december 2012 1 - cequence...

December 2012 1

Forward-Looking Information and Definitions

Certain information included in this presentation constitutes forward-looking information under applicable securities legislation. This information relates to future events or future performance of the Company. Investors are cautioned that reliance on such information may not be appropriate for making investment decisions. Many factors could cause the Company’s actual results, performance or achievements to vary from those described herein. The forward-looking information contained in this presentation is expressly qualified by this and other cautionary statements set forth in the continuous disclosure record of the Company.

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 internally estimated, at a given date, to be contained in known accumulations, prior to production, plus those quantities in accumulations yet to be discovered.

Original Oil in Place (OOIP) is equivalent to Discovered Petroleum Initially-In-Place (DPIIP). DPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook (COGEH), 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 DPIIP includes production, reserves and contingent resources; the remainder is unrecoverable.

Original Gas in Place (OGIP) is equivalent to Discovered Petroleum Initially-In-Place (DPIIP). DPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook (COGEH), 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 DPIIP (ORGIP) includes production, reserves and contingent resources; the remainder is unrecoverable.

OOIP and OGIP estimates are internally estimated and prepared by a qualified reserves evaluator.

2

Cequence is focused in the Deep Basin of Alberta

3

USA CANADA

Peace River Arch/NE BC- 2012 Production Est: 1,800 boe/d

Deep Basin- 2012 Production Est: 7,100 boe/d

Deep Basin

SIMONETTE

Emphasis on building a high quality, operated asset base in a multi-zone, liquids-rich gas area

Target top quartile or better operating/cash costs

Control large contiguous land blocks to facilitate future development (170,000 net acres in the Deep Basin)

Maintain a strong balance sheet

Corporate Profile

4

Trading Symbol TSX: CQE

Current production 9,000 boepd

52-week trading range $0.88-$3.59

Shares outstanding 200 million

Insider ownership 12% FD

Market capitalization (1) $340 million

Forecast December 31, 2012 net debt(2) $43 million

Bank line $100 million

2012 Average Production Guidance 8,800 boepd

2012 Budgeted Net Capital Expenditures $75 million (1) Based on Cequence stock price of $1.70 (2) Net debt is calculated as net working capital less commodity contract asset and liabilities and demand credit facilities and

excluding other liabilities, and including expected net proceeds of $15 million from the November 2012 flow through financing.

Recent Highlights

5

Strong Balance Sheet and recent flow-through financing

$16 million flow-through financing closed on December 5th 2012 exit net debt expected to be $43 million (< 1 X forecast annualized Q4 FFO)

Excellent Simonette Montney Well Performance

Increased internal model 20% to reflect production performance

Recent Exploration Success continues at Simonette

Falher discovery at Simonette identifies a fourth formation to be exploited with horizontal drilling

Aux Sable Facility Agreement

Began production of raw gas to the Aux Sable Deep Cut Facility on June 1, 2012 resulting in increased netbacks at Simonette while avoiding $30-$35 MM in facilities capital

Financial Highlights

Q3 2012 Q2 2012 % Change

Average Daily Production (BOE/D) 8,895 8,660 3

Funds flow from operations ($M) (1) $10,803 $4,563 136

Per share, basic and diluted $0.06 $0.03 100

Operating costs per BOE $6.88 $8.32 (17)

G&A per BOE $2.19 $2.56 (14)

Capital expenditures, net ($M) $16,838 $6,929 143

Net debt and working capital (deficiency) ($M)(2) ($48,291) ($43,855) 10

Weighted average shares outstanding (basic and diluted) (M)

191,612 164,823 16

6

(1) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital

(2) Net debt and working capital (deficiency) is calculated as cash and net working capital less commodity contract assets and liabilities and demand credit facilities and excluding other liabilities

Cash Costs per Boe – Q3 2012

0.00

5.00

10.00

15.00

20.00

25.00

30.00

7

*Cash costs consist of operating expense, transportation costs, general and administrative expense and interest expense

$/b

oe

First Half 2013 Guidance

First Half 2013 Guidance

Production (boe/d)(1) 9,600

Capital expenditures $42 MM

Operating costs per boe $6.75

Royalties (% of revenue) 11

Crude oil – WTI (Cdn$/bbl) $91.00

Natural gas – AECO (Cdn$/GJ) $3.30

Funds flow from operations (2)(4) $25 MM

Annualized funds flow from operations (2)(4) $50 MM

June 30, 2013 net debt and working capital deficiency(3) $60 MM

Basic shares outstanding 200.3 MM

(1) Comprised of 49.8 mmcf/d of natural gas and 1,300 boe/d of oil and liquids

(2) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities

(3) Net debt and working capital (deficiency) is calculated as cash and net working capital less commodity contract assets and liabilities

(4) First half funds flow sensitivity: +/- $1 AECO is $6 million.

8

Simonette Infrastructure

9

• Control 220 gross operated sections (avg. 75% W.I) with excellent land tenure

• Cequence operates its facilities at Simonette and delivers raw gas to the Alliance Pipeline for processing at the Aux Sable Deep Cut plant in Chicago

• Aux Sable agreement provides access to deep cut processing and avoids the potential $30-$35 million of capital for the initial 40 mmcfd gas plant while enhancing operating netbacks

• Phase 4 facility expansion expected completion - Q1 2013

Capital cost $5.5 million Capacity increased to 75

mmcfd

Cequence Alliance Meter Station Capacity 120 mmcf/d Trilogy Plant

CQE W.I. = 25% Capacity 10 mmcf/d

9-10 Field Compressor

13-11 Compressor Station

To Aux Sable Deep Cut Plant Chicago, Illinois

Keyera Processing Facility Capacity 153 mmcf/d

6 miles

PHASE 4 FACILITY EXPANSION • COMPRESSION AND

CONDENSATE STABILIZATION • NEW FACILITY CAPABILITY 75

MMCFD • CAPITAL COST $5.5 MM (INCL

PIPELINES) - 2013

10 KM LOOPING

3D Seismic Coverage

Stacked Zones Contain Significant Resources

10

5-10 BCF

5-24 BCF each

5-25 BCF

30-60 BCF

Dunvegan

Falher

Wilrich

Gething

Upper Montney

Zone Total Resource Potential/Sec (1)

2,400m

2,950m

3,100m

2,700m

2,500m

2,800m

(1) See Forward-Looking Information and Definitions for definition of total resource

6 miles

Gas/Condensate trend- CQE wells outperforming expectations

• Significant industry activity offsetting Cequence

• 50 net sections mapped on existing trend at an average 40 bcf of total resource per section (1)

• Approximately 200 potential horizontal locations assuming 4 wells per section

• Liquids yield (C3+) ranges from 20-60 bbls/mmcf (70% condensate)

• Average net 30 bbls/mm C3+

• Minimum three firm wells currently planned for winter program.

Oil Prone trend developing in North Simonette

• Three HZ CQE wells completed with average stabilized rates of 135 boepd (52% oil/condensate) after 3 months

• Competitor drilling currently de-risking Cequence land

• 20 net sections in potential oil trend with average internally estimated OOIP of 15 mmbbls(1) per section

11

6 miles

(1) See Forward-Looking Information and Definitions for definition of OOIP and total resource

10-16 IP rate- 2 mmcfd despite mechanical restrictions

8-21 Completion before yearend

1-18 -Drilling

Simonette Montney Liquids-Rich Resource Play

Montney Gas/Condensate CQE Working Model vs. 7

CQE gas wells to date

12

RESERVES

UPDATED MODEL

5.0 BCF raw natural gas 100 MBbl Condensate

50 MBbl Propane/Butane

PRODUCTION

IP YEAR 1 AVERAGE

5.5 mmcfd 110 bpd C5+ 55 bpd C3/C4 1,100 boepd

2.9 mmcfd 63 bpd C5+

30 bpd C3/C4 550 boepd

0

5

10

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

2012 DRILLING PROGRAM

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

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

Pro

du

cin

g D

aily

Gas

Rat

e (

mcf

/d)

Months on Production

Average Well Production

CQE Simonette Model

Montney Drilling Costs

13

bo

e/d

* Includes liner cost ** Longer wells have 2,400+ m laterals

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

$ /

me

ter

- M

eas

ure

d D

ep

th

Dri

ll &

Cas

e C

ost

s $

M

Drill & Case Cost*

$/m MD

2011 2010 2012

• 2012 drilling costs declining while wellbore length increasing

• Recent wells are 5,500 meters measured depth with 2,500 meter lateral

• Padsites reduce access and tie-in costs

• Improving bit design, drilling fluids, and well path planning

Montney Completion Costs

14

Dri

ll &

Co

mp

lete

Co

sts

$M

M

15 16 16 19 16 22 16 15 24 18 15 25

$258

$173 $179

$227

$199 $210

$318

$185

$143

$151

$323

$127

$50

$100

$150

$200

$250

$300

$350

0

1,000

2,000

3,000

4,000

5,000

6,000

Dri

ll &

Co

mp

lete

Co

sts

$M

Completion Cost

Frac cost per stage

# of Stages Completed

2011 2010 2012

$M

pe

r Fr

ac S

tage

Foam Frac Mechanical Problems

• Cost per frac showing steady improvement

• Improved fluid handling in the field- tanks/flow-lines

• Testing in-line

• Two wells out of the range due to mechanical issues and high cost fluid

• Cequence believes longer laterals with more frac stages will increase rate and recoverable reserves

Montney Economic Sensitivity to Gas Price and Net Liquids Yield

15

0

5,000

10,000

15,000

20,000

25,000

2.00 3.00 4.00 5.00 6.00 7.00

NP

V 1

0 (

$M

)

AECO Gas price ($/mmbtu)

20 Bbl/MMcf NGL Yield 30 Bbl/MMcf NGL Yield 45 Bbl/MMcf NGL Yield

IP: 5.5 MMcf/d ORGIP: 5.0 BCF (1)

NGL Yield: 20 to 60 Bbl/MMcf C3 + (70% Condensate) Capital: $7.5 MM

(1) See Forward-Looking Information and Definitions for definition of ORGIP

Simonette Dunvegan Oil, and Gas/Condensate Play

• 16-2 well will earn additional land which is highly prospective for Dunvegan gas/condensate production

• Resthaven pool is highly productive in the Dunvegan formation

• Cequence has mapped 22 potential locations on 11 net existing sections

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Simonette oil pool

42º API

Resthaven gas/condensate pool

6 miles

Oil prone

16-2 Drilling

Falher Trends – New Discovery

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KAKWA Falher C Channel Pressure: 3950 psi (27216 kpa) Depth: 2400 m (7891 ft) Gradient: 0.5 - 0.55 psi/ft OGIP: 12 Bcf/Section(1) (20 max) H 12m Ø Avg 6.5%

RESTHAVEN/SIMONETTE Falher F Channel Pressure: 5000 psi (34450 kpa) Depth: 2900 m (9514 ft) Gradient: 0.53 psi/ft OGIP: 9 Bcf/Section (20 max)(1)

H 10m Ø Avg 5.0%

16-18 HZTL

IP 30 (restricted) 1,300 boepd (7.3 MMcf/d and 113 bbls cond/d)

• Discovery well at 16-18 had an average first month rate of 1,300 boepd

• Cequence has mapped 28 potential locations on 14 net existing sections

• Stepout well at 4-6 located 3 miles south of recent discovery at 16-18. Planned spud January 2013.

• Falher F Pool similar

reservoir distribution and quality to nearby Musreau/Kakwa Falher C Pools

• Analog pool produces 60 mmcfd from 21 existing producers

• Internal model 6 mmcfd IP and 5 bcf recoverable per well

4-6 Option Well-planned for Q1

6 miles

Production Model: 6 MMCF/D for 5 BCF, 20-40 BBL/MM

(1) See Forward-Looking Information and Definitions for definition of ORGIP

Simonette Wilrich

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Wilrich Play

• 20 net sections currently mapped with 2 wells per section spacing

• Deeper Montney drilling confirms existing trend to the south

Ansell/Minehead area

• Acquired 27 sections of prospective land on a new over-pressured Spirit River prospect (100% WI)

• Competitor drilling currently de-risking CQE land

• Nearby wells tested at more than 20 mmcfd

• Initial well planned in 2013

RESTHAVEN

Deeper Montney exploitation drilling confirms Wilrich pay extension to south

WILRICH POOL

Simonette Model Economics

IP Rate (mmcf/d)

Liquids (bbls/mmcf)

ORGIP (BCF)(6)

Dev. Capital Cost/Well (2)

(MM)

ROR

NPV (MM)

Model Payout

(months)

Breakeven Gas Price (/mmbtu)

Dunvegan Gas

4.5 50-75 4.0 $6.5 80%+

>$9.0

<16 <$2.00

Falher (4) 6.5 20 5.0 $7.0 60% $5.0 18 $2.00

Wilrich 4.5 20 4.0 $5.5 70% $4.7 17 $2.25

Montney 5.5 30(5) 5.0 $7.5 70% $8.0 18 <$2.00

CQE Working Development Models @ $4.00/mmbtu and $90/bbl WTI (1)(3)

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(1) Economics calculated post Aux Sable tie-in (2) Drill, complete, tie-in, slick water (3) Without GORR (4) Falher production performance based on Kakwa analog (5) 21 bbls/mm condensate (6) See Forward-Looking Information and Definitions for definition of ORGIP

Independent Gas Play Ranking- 4 CQE plays rank in the top 13 in North America

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Simonette/Resthaven Horizontal Wells

• Multiple zones with significant horizontal drilling success

• Major companies active in Simonette/Resthaven

• Exxon • Encana • Conoco

• CQE land is well-

positioned

• Stacked potential of up to 100 bcf per section of total resource (1) on Cequence lands

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Kakwa / Chime

Encana / Tourmaline

Spirit River

Karr

7 Generations

Montney Oil Pool

Kakwa /

Musreau

Paramount

Spirit River

Resthaven

Paramount/Encana/

Conoco

Dunvegan

Resthaven

Encana

Spirit River

Leland

Encana

Spirit River

North Simonette

Apache-AOSC

Montney Oil Pool

Simonette

COP

Dunvegan

6 miles

Simonette

Montney Gas Pool Celtic

Montney

Celtic

Montney

Conoco

Exxon

Montney

(1) See Forward-Looking Information and Definitions for definition of total resource

Conclusions

Strong balance sheet 2012 exit debt <1 X annualized forecast Q4 FFO

Montney results outperforming type curve

Infrastructure in place- positioned to accelerate drilling activity

and grow production as gas prices strengthen

Large multi-zone drilling inventory in four leading North American natural gas plays

Highly experienced Deep Basin management team and Board of Directors

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23

Appendix

20.30

19.37

17.38 16.76

14.99

14.08 14.21

12.84 12.58

13.88

11.87

10

15

20

25

0

2,000

4,000

6,000

8,000

10,000

12,000

Natural Gas Oil & NGL Opex, Transportation, G&A and Interest

8,895

Corporate Production and Cash Costs

24

$/b

oe

bo

e/d

9,464 8,879

9,833

9,125

8,185 7,485

4,619

3,197

2,444

8,660

Hedging- approximately 40% of 2013 production hedged at an average

$3.62 per mcf

Contract

Type Volume

GJ/d CAD Price Basis

July 1, 2012 to December 31, 2012 Gas Swap 2,000 $3.14 AECO

August 1, 2012 to December 31, 2012 Gas Swap 2,500 $2.50 AECO

January 1, 2013 to December 31, 2013 Gas Swap 2,000 $2.84 AECO





January 1, 2013 to December 31, 2013 Sold Oil Call 200 bbls/d $100.00 usd WTI


January 1, 2014 to September 30, 2014 Gas Swap 2,500 $3.51 AECO

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Reserves

Independent Reserves Evaluation (1) – Dec 31, 2011

2011 2010

Proved Developed Producing (mboe) 14,675 13,018

($M)(4) 202,850 181,163

Proved (mboe) 35,077 27,332

($M)(4) 389,446 307,465

FD&A ($/BOE) 19.26 18.25

FDC ($MM) 236.4 141.7

RLI (years) 10.7(2) 10.0(3)

Proved + Probable (mboe) 67,443 48,863

($M)(4) 715,750 525,635

FD&A ($/BOE) 13.42 12.67

FDC ($MM) 426.5 250.8

RLI (years) 20.5(2) 17.9(3)

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(1) Independent reserves evaluator is GLJ Petroleum Consultants (“GLJ”) (2) RLI based on 2011 annual production of 9,010 boe/d

(3) RLI based on Q4, 2010 production of 7,485 boe/d

(4) Discounted at 10%

Land & Net Asset Value (NAV)

December 31, 2011 GLJ Report Escalated Strip Pricing(1)

$M $M

Proved + Probable, NPV 10% - December 31, 2011

715,750 450,887

Land (2) 50,880 50,880

Dec 31, 2012 Estimated Net Debt(3) (43,000) (43,000)

NAV 723,630 458,767

Shares Outstanding (M)(4) 200,300 200,300

NAV/Share ($/share) 3.61 2.29

27

(2) 254,400 acres @ $200/acre

(1) Based on the net present value of the future net revenue from the Company’s proved plus probable reserves (discounted at 10%) with benchmark future pricing used in the Company’s reserve report at December 31, 2011 adjusted to March 5, 2012 escalated strip prices

(4) Common voting shares outstanding at September 30, 2012 and including common shares issued in November 2012 financing

(3) Estimated net debt based on Cequence’s 2012 guidance is calculated as cash and net working capital less commodity contract asset and demand credit facilities and excluding other liabilities and include proceeds of November 2012 financing.

Simonette Deep Basin Stack

28

Dunvegan

Falher Bluesky / Gething

Montney Wilrich

3075

3050

3025

3000

2950

2975

Upper

Middle

Lower

CURRENT HORIZONAL

TARGET ZONE

Contacts: Paul Wanklyn President & CEO [email protected] David Gillis

Vice President, Finance & CFO [email protected]

www.cequence-energy.com

3100, 525 - 8th Avenue SW Calgary AB T2P 1G1

Phone: 403-229-3050 Fax: 403-229-0603

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december 2012 1 - cequence...

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