May 2017 Free Cash Flow Generation - Cona Resources · PDF file1. Free cash flow yield...

May 2017 Free Cash Flow Generation

May 2017 | 1 Corporate Presentation

1. As at Mar 31, 2017. See slide 30 for full breakdown. 2. Based on May 1, 2017 closing price of $3.36/share. 3. As at Mar 31, 2017 and adjusted for subsequent repurchase of US$6.5 million of senior

unsecured notes .

4. As per 2017 guidance issued Dec 5, 2016. Total payout ratio based on 2017 guidance using forward strip commodity prices (WTI of US$50.25/bbl, WCS differential of US$13.47/bbl, CAD/US of 1.352).

5. Non-IFRS measure. See Advisory.

Corporate Profile

Common Shares TSX Ticker Symbol NBZ Outstanding Shares(1) 101 million Market Capitalization(2) $339 million

Net Debt(3) Cash on Balance Sheet $21 million Credit Facility $285 million (0% drawn)

Senior Unsecured Notes US$270 million (due 2022)

Dividend Annual Dividend $0.24/share Dividend Yield(2) 7.1% Total Payout Ratio(4,5) 77%

AB SK

• 17,100 boe/d(4) • 99% Oil • 100% Saskatchewan • 70% Waterflood/

Polymer Flood


• Free cash flow(1,2) generation – Low corporate decline – Low sustaining capital

• Sustainable dividend

– Low total payout ratio(2)

– Within funds from operations(2) to US$40/bbl WTI

• Enhanced Oil Recovery (“EOR”)

– Waterflood and polymer flood – Large low risk drilling inventory

1. Free cash flow is calculated as funds from operations less capital expenditures. 2. Non-IFRS measure. See Advisory.

Sustainable Yield Investment


12% 12% 13%

16% 18%

20% 21%

22% 23% 23% 23% 23% 23% 23% 23%

24% 24% 25% 25%

26% 27% 27% 27%

28% 30% 30% 30% 30% 30%

32% 33%

34% 34% 34% 35%

36% 37% 37%

39% 39% 40%

41%

0%

4%

8%

12%

16%

20%

24%

28%

32%

36%

40%

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Corporate Base Decline Rates(1)

1. NBZ base decline rate based on internal estimates. Peer group base decline rates based on Peters & Co. estimates as of May 1, 2017.

Low Base Decline Rate = Low Sustaining Capital

NBZ’s low 12% decline rate means sustaining capital required to replace production declines

is low, and therefore free cash flow is high.


17%

13%

9% 8% 8% 8% 8% 7% 7% 6% 6% 6% 6% 5% 5% 5% 5% 5% 4% 4% 4% 4% 4% 3% 3% 3% 2% 1% 1% 0%

-1% -1% -2% -3%

-4% -4% -5%

-8%

-11%

-15% -15% -17%

-20%

-16%

-12%

-8%

-4%

0%

4%

8%

12%

16%

N. B

LIZZA

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Free Cash Flow Yield (2017E)(1,2) – Forward Strip(3)

1. Free cash flow yield calculations assume a sustaining capital case and are consistent for all companies. Detailed calculations provided on slide 28. 2. NBZ free cash flow yield was calculated using internal estimates and a May 1, 2017 closing share price of $3.36/share. Free cash flow yield for industry peers was calculated using cash

flow estimates, production, corporate base declines, capital efficiencies and outstanding share data from Peters & Co. as of May 1, 2017. Detailed calculations provided on slide 28. 3. 2017 forward strip commodity prices: WTI of US$50.25/bbl, WCS differential of US$13.47/bbl, CAD/US of 1.352. 4. Free cash flow defined as funds from operations less sustaining capital expenditures. Non-IFRS measure. See Advisory.

Industry Leading Free Cash Flow Generation

NBZ’s free cash flow(4) generation drives its industry leading 17% free cash flow yield.

share priceAnnual FCF/share

FCF yield =


77% 89% 90% 95% 96% 97% 97%

104% 106% 112% 118% 123% 124% 132%

60%

80%

100%

120%

140%

N. B

LIZZA

RD

TORC

Bona

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Whit

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Bonte

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Surg

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Verm

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AVER

AGE

Cres

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Point

Card

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plus

Peyto

Birch

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ARC

2017 Total Payout(5,6,7) - Forward Strip(8)

7.1% 6.6% 6.3% 5.4% 5.4% 4.9%

4.1% 4.1% 4.0% 4.0% 3.9% 3.7% 3.5% 3.4% 3.4% 2.9% 2.7% 2.3% 1.9% 1.5% 1.4% 1.2%

0%

2%

4%

6%

8%

N. B

LIZZA

RD

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Dividend Yield (1)

1. Dividend yield based on last dividend (annualized) and May 1, 2017 share price. 2. Average yields for REITs, Utilities, Telcos, and Financials as per Bloomberg S&P TSX group indices on May 1, 2017. 3. Average yields for US AAA, BBB, and T-Bonds represent “Yield to Worst” values from Bloomberg Barclays bond indices at May 1, 2017. 4. “Energy Royaltycos” group includes PrairieSky and Freehold. 5. Total payout ratio defined as dividends plus capital expenditures divided by funds from operations, and is consistent with Peters & Co. calculation of “(E&D Capex + Div)/CF” as at May 1,

2017. 6. NBZ total payout ratio based 2017 guidance using forward strip commodity prices. Peer total payout ratios based on Peters & Co. “(E&D Capex + Div)/CF” estimates as of May 1, 2017. 7. Non-IFRS measure. See Advisory. 8. 2017 forward strip commodity prices: WTI of US$50.25/bbl, WCS differential of US$13.47/bbl, CAD/US of 1.352.

Dividend Protected by Low Total Payout Ratio

Energy Non-Energy Bonds

Compelling 7.1% dividend yield protected by best-in-class

77% total payout ratio.


2.6x 2.6x

2.1x

1.8x

1.6x

1.0x

1.5x

2.0x

2.5x

3.0x

$0

$50

$100

$150

$200

$250

$300

$350

2017

E

2018

E

2019

E

2020

E

2021

E

Flat US$50 WTI, Net Debt Reduction Scenario(5)

Net D

ebt(3

) ($MM

)

Net D

ebt /

FFO

(3)

Flat Production/Capex Scenario

Guidance

$88 $99

$110 $111 $121

$132 $140

$40

$60

$80

$100

$120

$140

$40

$45

$50

STRI

P

$55

$60

$65

$mm

sdkf;

a

FFO(3) – 2017 Sensitivity(4)

WTI (US$/bbl)

$MM 2017 CAPEX + DIVIDEND: $85MM

2017 CAPEX: $60MM

Bank Credit Facility(1) • $21 million cash on balance sheet • $285 million credit facility (0% drawn) • Compliant with all covenants:

Senior Unsecured Notes(1) • US$270 million ($365 million) • No maintenance covenants • Due Feb 1, 2022 At US$50/bbl WTI, $25 million of excess free cash flow available annually for: • Debt repayment (near term focus) • Additional dividends • Growth capital • Share buy backs

1. As at Mar 31, 2017 and adjusted for subsequent repurchase of US$6.5 million of senior unsecured notes . 2. For this calculation, Senior Debt excludes the Senior Unsecured Notes. 3. Non-IFRS measure. See Advisory. 4. FFO sensitivity is provided based on 2017 guidance issued Dec 5, 2016 at the WTI prices indicated, WCS differential of US$13.47/bbl, and CAD/US of 1.352. Strip scenario is based on

WTI of US$50.25/bbl. 5. “Flat Production/Capex Scenario” assumes that production and capital spending for 2017 are held constant over the next 5 years, and free cash flow reduces net debt. Commodity

prices are held constant for all years presented (WTI of US$50.00/bbl, WCS differential of US$12.00/bbl, and CAD/US of 1.360).

Balance Sheet Protected by Excess Cash Flow

Bank Debt Covenants NBZ @

Mar 31, 2017

Senior Debt(2)/EBITDA (=< 3.0x) 0.0x

EBITDA/Int. Exp. (>= 2.5x) 5.5x

Current capex & dividend are

within cash flow to

US$40/bbl WTI

Free cash flow available to pay

down debt


$0

$20

$40

$60

$80

$40 $60WTI (US$/bbl)

2017 Corporate FFO Netback(3,4)

WCS Diff ($/bbl)

Royalties ($/boe)

Operating Costs ($/boe)

Blending & Trans. ($/bbl)

Corporate Costs ($/boe)

FFO Netback, After Hedging ($/boe)

• Large, low decline oil resource – ~1.9 billion bbl DOIIP(1) – only 12% recovered – Best-in-class decline rate of 10-12% – ~70% production under waterflood or polymer flood – Low viscosity oil ideal for EOR – > 1,000(2) low risk drilling locations

1. Discovered Oil Initially In Place; based on an independent reserve report effective Dec 31, 2016. 2. Inventory includes 347 Proved, 327 Probable and 51 Possible locations based on an independent reserve report effective Dec 31, 2016. 275 unbooked locations are an internal estimate, as at

Dec 31, 2016. None of the unbooked locations have been assigned either reserves or resources by our independent reserves evaluator. Unbooked locations were determined internally using geological mapping and seismic interpretation.

3. Funds from operations netback is based on the WTI prices as indicated, WCS differential of US$13.47/bbl and CAD/USD of 1.352. 4. Non-IFRS measure. See Advisory.

Concentrated EOR Asset Base

~80% of production from Cactus Lake, Winter,

and Court properties.

AB SK

+$14/boe netback at

US$40/bbl WTI.

352 262 261 234

48 60

>1,000

0

200

400

600

800

1,000

2011 2012 2013 2014 2015 2016 Inventory

Wells Drilled versus Inventory (Gross)

Unbooked Booked Actual

66 locations to be drilled in 2017


• Play characteristics – 100% WI operator – Low viscosity, floodable 14o API oil (200-300

centipoise) – 96% of field production is Bakken & Basal Mannville

• Exploitation strategy – Vertical down-spacing to 10 acres – Increasing recovery with waterflood followed by

polymer flood

1. Cactus Main only; based on an independent reserve report effective Dec 31, 2016. 2. Internal estimate as at Dec 31, 2016.

3. As at Dec 31, 2016. 4. See full breakdown on slide 11.

Cactus Lake – EOR Cash Flow Engine Highlights Est. 2017 production 9,000 boe/d DOIIP(1) 402 mmbbl 2P Reserves(1) 63 million boe Recovered to date(1) 13% Est. ultimate recovery(2) ~36% Wells drilled since 2010(3) 427

Drilling inventory(4) 331 locations

• Adding polymer increases viscosity and improves sweep efficiency


Base Declines by Production Vintage 2011 2012 2013 2014 2015 2016

On stream pre-2011 13% 14% 14% 14% 14% 14%

On stream 2011 50% -45% -20% -10% -10%

On stream 2012 40% -25% -10% -10%

On stream 2013 50% 8% -9%

On stream 2014 15% 0%

On stream 2015 15%

On stream 2016

Total Base Decline 13% 15% 12% 12% 8% -5%

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Jan-

2010

Jan-

2011

Jan-

2012

Jan-

2013

Jan-

2014

Jan-

2015

Jan-

2016

Jan-

2017

bbl/

d

Production by Vintage

Pre 2011 2011 2012 2013 2014 2015 2016

Cactus Lake – Decline Reversal

Successful EOR at Cactus Lake has

caused declines in old production vintages to

reverse and incline

From 2014 to 2016, base declines at Cactus Lake have improved from 12% to -5%


$0

$20

$40

$60

$80

$100

$120

$140

0

20

40

60

80

100

120

140

2011 2012 2013 2014 2015 2016 2017E

Capi

tal S

pend

ing

($M

M)

Wel

ls D

rille

d

Capital Spending Requirement Diminishing Development CapitalPolymer Facilities CapitalPolymer Powder CapitalWells Drilled

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2011 2012 2013 2014 2015 2016 2017E

Ope

ratin

g Co

sts (

$/bo

e)

Prod

uctio

n (b

oe/d

)

Production Growing While Operating Costs Fall Production (boe/d) Operating Costs ($/boe)

Polymer Injection

30

40

50

60

70

80

90

100

150

200

250

300

350

400

450

500

2012 2013 2014 2015 2016 2017+

DOIIP

(mm

boes

)

DOIIP & Reserves Increasing(1)

DOIIP 2P Reserves

2P R

eser

ves (

mm

boes

)

1. Cactus Main only; 2012 to 2016 based on an independent reserve report effective Dec 31, 2016. 2017+ an internal estimate, as at Dec 31, 2016.

Cactus Lake – Consistent Performance

Production growth continues despite lower spending.

From 2012 to 2017, DOIIP at Cactus Lake has increased 61% to 450 mmbbls while 2P

reserves have increased 45% to 2016.

18% production CAGR from 2011 to 2016. 42% op cost reduction since 2014.


56

123 103 87

25 29

0

50

100

150

200

250

300

350

2011 2012 2013 2014 2015 2016 Inventory

Wells Drilled versus Inventory (Gross)


1. Inventory includes 165 Proved and 73 Probable locations based on an independent reserve report effective Dec 31, 2016. 93 unbooked locations are an internal estimate, as at Dec 31, 2016. None of the unbooked locations have been assigned either reserves or resources by our independent reserves evaluator. Unbooked locations were determined internally using geological mapping and seismic interpretation.

Cactus Lake – Repeatable, Low Risk Infill Drilling

~50% of Cactus Lake acreage down

spaced to 10 acres

331 low risk locations(1) identified to down

space remaining existing waterflood from 40 to 10 acres

40 Acre Waterflood

27 locations to be drilled in 2017

10 Acre Waterflood

3:1 Prod/Inj Ratio 1:1 Prod/Inj Ratio 1:1 Prod/Inj Ratio


Phase 1

Phase 2A

Phase 2B

Phase 6

Phase 4

Phase 3B

Phase 3A

Phase 8

Phase 5

Phase 7

1. Internal estimate as at Dec 31, 2016. 2. Based on an independent reserve report effective Dec 31, 2016.

Cactus Lake – Increasing Recovery Rates

Polymer Injectors (shaded areas under active polymer flood)

10

100

1,000

10,000

Jan-75 Jan-85 Jan-95 Jan-05 Jan-15 Jan-25 Jan-35 Jan-45 Jan-55

Oil

Rate

(Bbl

/d)

Cactus Lake – EOR Recovery Forecast

40 Acre Primary

40 AcreWaterflood

10 AcreWaterflood

10 AcrePolymerflood

28% RF 36% RF18% RF9% RF

60-70% of down spaced areas are

now under polymer flood

Injection Commencement Sparky HZ: Q1 2012 Phase 1: Q4/12, 2013 Phase 2A: 2014 Phase 2B: 2014 Phase 3A: 2015 Phase 3B: 2016 Phase 5: 2016

Polymer is expected to increase recovery rates at Cactus Lake

to ~36%(1) (from 12%(2) currently)

• Adding polymer increases viscosity and improves sweep efficiency


$0$10$20$30$40$50$60$70$80$90


2017 Operating Netback

WCS Diff ($/bbl)

Royalties ($/boe)



Operating Netback ($/boe)

Single Well Economics(1) DCET Capital $392K Facl. Capital $78K

Polymer cost per year $64K IP 365 22 Boe/d EUR 175 Mboe

Op. Costs $7.00/Boe Trans. & Other Costs $1.70/Boe Royalties & Burdens 11%

Realized Pricing 95% of WCS

22%

44%

70%

95%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

$40 $50 $60 $70

IRR

%

IRR (Midcycle, BTax)

10-Acre Polymer Infill

WTI Oil Price (US$/Bbl)

0

5

10

15

20

25

30

35

40

0 12 24 36 48 60 72 84 96

Prod

uctio

n (B

bl/d

)

Months on Production (Normalized)

Polymer 10-Acre Infill - Results vs. Type Curve

Type Curve (gross) 2014-2017 (142 wells) 2011-2013 (244 wells)

1. Economics are “Mid Cycle” and as such incorporate transportation costs, dry hole costs, and infrastructure to accommodate future water handling, oil treating, and major pipelines. Economics also incorporate (as a cost) the foregone NPV ($350K per well) for shut-in production due to injector conversions. Royalties and operating cost assumptions based on first five years of production.

2. IRR calculations based on WTI of US$40, $50, $60 and $70/bbl, WCS differential of US$13.00, $13.50, $14.00 and $14.50/bbl and CAD/USD of 1.320, 1.300, 1.280 and 1.260, respectively.

Cactus Lake – Robust Economics

• In 2017 will drill 27 net 10-acre down spacing wells in our Cactus Lake polymer flood project.

Single well economics at Cactus are robust due to flat decline profiles, low drilling costs, and strong netbacks

NPV10 ($50WTI): $783KIRR ($50WTI): 44%

Breakeven (NPV15): US$35 WTI

(2)


1. Cactus Lake free cash flow is calculated as operating income less capital expenditures. Non-IFRS measure. See Advisory. 2. “Flat Production/Capex Scenario” assumes that production and capital spending for 2017 are held constant over the next 5 years. Commodity prices are held constant for all years

presented (WTI of US$50.00/bbl, WCS differential of US$12.00/bbl, and CAD/US of 1.360).

Cactus Lake – Strong Free Cash Flow at US$50/bbl WTI

$95.12 $94.21

$97.96

$93.00

$48.80

$43.32

$50.00 $50.00 $50.00 $50.00 $50.00

$3MM

-$44MM

$13MM $44MM $42MM $43MM

$86MM $81MM $76MM $76MM $76MM

$167MM

$242MM

$318MM

$394MM

($200)

($150)

($100)

($50)

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

$40.00

$50.00

$60.00

$70.00

$80.00

$90.00

$100.00

$110.00

2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E 2021E

Free

Cas

h Fl

ow ($

MM

)

WTI

(US$

/bbl

)

Free Cash Flow(1) Profile (Flat US$50WTI / Flat Production Scenario(2))

Cumulative FCF (less capex) Annual FCF (less capex) WTI

Guidance

Flat Production/Capex Scenario(2)

Actual Historical

Demonstrable FCF during weak oil

prices

Strong cumulative FCF with flat production in flat US$50/bbl

WTI price environment


• Play characteristics – CNRL and NBZ dominate the channel – ~12o API oil (3,000 - 4,000 centipoise) – Mannville Cummings/Dina channel

production with aquifer support • Exploitation strategy

– Unstimulated horizontal infill drilling – Increase recovery via down spacing to ~25

meter inter-well distances

1. Based on an independent reserve report effective Dec 31, 2016. 2. Internal estimate as at Dec 31, 2016.

3. Gross, producing horizontal wells as at Dec 31, 2016. 4. See full breakdown on slide 16.

Winter – Low Risk Conventional Drilling

Est. 2017 production 2,700 boe/d DOIIP(1) (gross) 599 million bbl 2P Reserves(1) 19 million boe Recovered to date(1) ~8% Est. ultimate recovery(2) ~12% Hz wells drilled since 2010(3) 198

Drilling inventory(4) 490 locations

Highlights


• Consistent performance – 198(1) horizontal wells drilled on ~25 meter spacing since

2010 • Large, repeatable inventory

– 490(2) locations identified on ~25 meter spacing – Only 314 locations booked by reserves evaluator

• Down spacing upside – Have successfully down spaced to 19 meters – Potential to unlock +400 additional locations through

increased down spacing. • Long lateral economic upside

– Drilling 750m laterals (vs ~400m) and getting +200% IRRs

1. Gross, producing horizontal wells as at Dec 31, 2016. 2. Inventory includes 152 Proved and 162 Probable locations based on an independent reserve report effective Dec 31, 2016. 176 unbooked locations are an internal estimate, as at Dec 31,

2016. None of the unbooked locations have been assigned either reserves or resources by our independent reserves evaluator. Unbooked locations were determined internally using geological mapping and seismic interpretation.

Winter – Repeatable Horizontal Infill Drilling

23

46 60 42 11 16

0

100

200

300

400

500

Wells Drilled versus Inventory


27 producers to be drilled in 2017


97%

149%

209%

278%

35%

63%

93%

124%

0%

25%

50%

75%

100%

125%

150%

175%

200%

225%

250%

275%

300%

$45 $50 $55 $60

IRR

%

WTI (US$/bbl)

IRR (Midcycle, BTax)

Long Lateral (750m)Short Lateral (~400m)

0

10

20

30

40

50

60

70

80

90

100

0 12 24 36 48 60 72

Prod

uctio

n (b

oe/d

)

Months on Production (Normalized)

Winter HZ Infill Wells - Type Curves

Long (750m) Horizontals

Short (~400m) Horizontals

1. Economics are “Mid Cycle” and as such incorporate transportation costs, dry hole costs, and infrastructure for water handling, oil treating, and major pipelines. 2017 economics avoid facility costs by shutting-in high watercut legacy wells – as such, production and reserves provided are NET of shut-in production (equal to approximately $14K NPV10 at US$50/bbl). Operating costs are for the first four years of production.

2. IRR calculations based on WTI of US$45, $50, $55 and $60/bbl, WCS differential of US$13.25, $13.50 , $13.75 and $14.00/bbl and CAD/USD of 1.310, 1.300, 1.290 and 1.280, respectively.

Winter – Strong Economics; Long Lateral Upside

• In 2017 will drill at Winter 27 (20 net) horizontal infill wells.

Long laterals have shown compelling economics for

a 7% increase in capital Results across the pool expected in this band

~400m Infill 750m InfillNPV10 ($50WTI) $368K $765K

IRR ($50WTI) 63% 149%

$0$10$20$30$40$50$60$70$80$90


2017 Operating Netback

WCS Diff ($/bbl)

Royalties ($/boe)



Operating Netback ($/boe)

Short vs Long Lateral Economics(1) ~400m Infill 750m Infill

DCET Capital $592K $630K IP 365 38 Boe/d 56 Boe/d EUR 47 Mboe 67 Mboe

Op. Costs $8.00/Boe $7.50/Boe Trans. & Other Costs $3.00/Boe $3.00/Boe Royalties & Burdens 6.4% 7.6%

Realized Pricing 91% of WCS


• Large oil in place • Technology-driven recovery • Long life assets

• Huge upside potential • Significant advantages from existing

infrastructure

AB SK

Plover Lake SAGD

1. Based on an independent reserve report effective Dec 31, 2016.

DOIIP(1) – 143 mmbbl

R27 R26 R28

T36

T35

Plover Lake SAGD


Plover Lake SAGD – Value to be Unlocked

Existing Well Pairs

New Well Pairs

New Well Pairs

Side Track

Investigating the following possible solutions: 1) PH treatment to

remediate wellbore scaling

2) Sidetrack existing wells

3) Drill 2 new well pairs

0

3,000

6,000

9,000

0

500

1,000

1,500

2,000

2,500

3,000

Jun-14 Sep-14 Dec-14 Mar-15 Jun-15 Sep-15 Dec-15 Mar-16 Jun-16 Sep-16 Dec-16 Mar-17

Stea

m, T

otal

Flu

id, b

bl/d

Oil

Rate

, bbl

/d

Plover Lake SAGD Total Rates

Oil Steam

Under-injection of steam led to well bore damage and suboptimal production


3.9x 4.3x 4.6x 4.7x 4.8x 4.8x 4.9x 5.0x 5.2x 5.8x 6.1x 6.1x 6.3x 6.4x 6.5x 6.5x 6.6x 6.7x 6.7x 6.7x 6.9x 6.9x 7.0x 7.0x 7.1x 7.1x 7.1x 7.4x 7.4x 7.5x 7.7x 7.9x 8.0x 8.1x 8.3x 8.4x 8.6x 9.2x 10.5x 10.8x

11.5x

25.9x

0.0x

2.0x

4.0x

6.0x

8.0x

10.0x

12.0x

14.0x

16.0x

18.0x

20.0x

22.0x

24.0x

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EV/DACF (2017E)(1,2) – Forward Strip(3)

1. Northern Blizzard EV/DACF calculation based on 2017 guidance using forward strip commodity prices and May 1, 2017 closing price of $3.36/share. Peer group EV/DACF based on Peters & Co. estimates as of May 1, 2017.

2. Non-IFRS measure. See Advisory. 3. 2017 forward strip commodity prices: WTI of US$50.25/bbl, WCS differential of US$13.47/bbl, CAD/US of 1.352.

Compelling Relative Valuation


Reasons for Discount What We’re Doing About It

1. Commodity price collapse & magnified impact on heavy oil margins.

Protected downside through hedging & strengthened margins through cost control.

2. Uncertainty over PE exit strategy.

Previous PE partners replaced with long term partner, Waterous Energy.

3. Dilution from stock dividend program.

Eliminated SDP program and reversed dilution through 22.5MM share buy back.

4. Low trading liquidity. Increase trading volumes through income-orientated marketing strategy.

5. SAGD operational challenges.

Identified issue. Working on remediation plans.

6. Higher than average D/CF ratio.

Near term focus on debt repayment with excess free cash flow.


1. 7.1% dividend yield protected by best-in-class 77% total payout.

2. Capex & dividend within cash flow to US$40/bbl WTI.

3. Best-in-class 10-12% base decline rate.

4. Best-in-class 17% free cash flow yield.

5. Low operational risk & repeatability of core inventory.

6. Low financial risk due to structure of debt and ability to reduce debt with excess cash flow.

7. Compelling valuation.

Why to Own Northern Blizzard


Appendix


1. As per 2017 guidance issued Dec 5, 2016. 2. Non-IFRS measure. See Advisory.

2017 Guidance & Sensitivities

$88 $99

$110 $111 $121

$132 $140

$40

$60

$80

$100

$120

$140

$40

$45

$50

STRI

P

$55

$60

$65

$mm

sdkf;

a

FFO(2) – 2017 Sensitivity

WTI (US$/bbl)

$MM 2017 CAPEX + DIVIDEND: $85MM

2017 CAPEX: $60MM

97% 86%

77% 77% 71%

65% 61%

30%40%50%60%70%80%90%

100%110%120%130%

$40

$45

$50

STRI

P

$55

$60

$65

Free Cash Flow Yield (2016E) Total Payout Ratio – 2017 Sensitivity

WTI (US$/bbl)

Within Cash Flow

2017 Guidance(1) WTI Sensitivity

Current Forward

Strip WTI Sensitivity WTI (US$/bbl) 55.00 40.00 45.00 50.00 50.25 55.00 60.00 65.00 WCS Differential (US$/bbl) (15.00) (13.47) (13.47) (13.47) (13.47) (13.47) (13.47) (13.47) FX (CAD/USD) 1.300 1.352 1.352 1.352 1.352 1.352 1.352 1.352

Average Production (boe/d) 17,100 17,100 17,100 17,100 17,100 17,100 17,100 17,100

Funds from Operations (FFO)(2) ($ million) 110 88 99 110 111 121 132 140 Capital Expenditures ($ million) 60 60 60 60 60 60 60 60 Dividends ($ million) 25 25 25 25 25 25 25 25 Free Cash Flow(2), after Dividends ($ million) 25 3 14 25 26 36 47 55

Total Payout Ratio(2) (%) 78 97 86 77 77 71 65 61

Year End Net Debt(2) ($ million) 294 330 319 308 308 297 286 278 Year End Net Debt / FFO (x) 2.7 3.8 3.2 2.8 2.8 2.5 2.2 2.0


Base Declines by Production Vintage(1)

2011 2012 2013 2014 2015 2016 2017

On stream pre-2011 15% 14% 18% 20% 18% 5% 5%

On stream 2011 60% 13% 13% 13% 13% 13%

On stream 2012 30% -7% 0% 0% 0%

On stream 2013 15% 22% 5% 5%

On stream 2014 30% 20% 20%

On stream 2015 30% 25%

On stream 2016 30%

Total Base Decline 15% 34% 22% 18% 21% 12% 12%

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Jan-

2010

Jan-

2011

Jan-

2012

Jan-

2013

Jan-

2014

Jan-

2015

Jan-

2016

Jan-

2017

bbl/

d

Production by Vintage Pre 2011 2011 2012 2013 2014 2015 2016

1. Production by vintage excludes Coleville and Smiley (which were disposed in Q4 2016).

Corporate Decline Rate – YOY Profile

EOR has caused declines in old

production vintages to flatten.

Base declines have improved to 10-12% from 18%

due to EOR success and the

sale of high decline assets.


2016 2017E

Capital Expenditures(1) ($000)

Corporate 51,445 59,590

Polymer powder – capitalized (9,531) (11,562)

Capex, excl polymer 41,914 48,028

Production Additions (boe/d)

Q4 production, prior year (boe/d) 19,065 17,000(3)

Decline rate (%) 12% 12%

Base production declines (boe/d) 2,288 2,040

Q4 production, prior year (boe/d) 19,065 17,000(3)

Less base production declines (boe/d) (2,288) (2,040)

Prior year Q4 prod. after declines 16,777 14,960

Q4 production, current year (boe/d) 18,620(2) 17,250

Less prior year Q4 prod. after dispositions (16,777) (14,960)

Production additions (boe/d) 1,843 2,290

Capital efficiency ($/boepd) $27,914 $26,022

Capital efficiency, excl. polymer ($/boepd) $22,742 $20,793

1. Excludes acquisitions and decommissioning costs. 2. Estimated Q4 2016 production before the impact of dispositions in Q4 2016. 3. Estimated 2016 exit production after Q4 2016 dispositions. The disposed properties produced ~1,425 boe/d in Nov 2016.

Corporate Capital Efficiency – YOY Profile

$0

$200

$400

$600

$800

$1,000

Winter Cactus Lake

2014 2015 2016

Well Costs - DCET ($000)

26%Savings

24%Savings

$21.04

$16.72 $15.91 $15.40

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

2014 2015 2016 2017E


27% improvement


1. Corporate free cash flow is calculated as funds from operations less capital expenditures. For the scenario shown above, free cash flow also excludes hedging gains or losses. Non-IFRS measure. See Advisory.

2. “Flat Production/Capex Scenario” assumes that production and capital spending for 2017 are held constant over the next 5 years. The impact of hedging has been excluded. Commodity prices are held constant for all years presented (WTI of US$50.00/bbl, WCS differential of US$12.00/bbl, and CAD/US of 1.360).

Corporate Free Cash Flow – YOY Profile

$95.12 $94.21 $97.96

$93.00

$48.80

$43.32

$50.00 $50.00 $50.00 $50.00 $50.00

-$68MM -$84MM

-$52MM

-$3MM $28MM

-$10MM

$67MM $62MM $57MM $57MM $57MM

$129MM

$186MM

$243MM

$300MM

($200)

($150)

($100)

($50)

$0

$50

$100

$150

$200

$250

$300

$350

$400

$40.00

$50.00

$60.00

$70.00

$80.00

$90.00

$100.00

2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E 2021E

Free Cash Flow(1) Profile (Flat US$50WTI / Flat Production Scenario(2))

Cumulative FCF (less capex & excl. hedging) Annual FCF WTI price

WTI

(US$

/bbl

)

Guidance

Flat Production/Capex Scenario(2)

Actual Historical

Free

Cas

h Fl

ow ($

MM

)

Successful transition to FCF

generation despite drop in oil prices

Strong cumulative FCF with flat production in flat US$50/bbl WTI

price environment

High initial investment in drilling & EOR facilities and negative FCF

during period of high oil prices


• Management of decline rates and capital efficiency underpin free cash flow generation for oil & gas companies.

• “Free Cash Flow Yield” places FCF in the context of share price; companies with both high excess free cash flow per share and low valuations have the highest FCF yields.

• Northern Blizzard stands out amongst its peers with a sector leading 17% FCF yield.

1. Free cash flow calculations assume a sustaining capital case and are consistent for all companies.

2. NBZ calculations based on internal estimates and a May 1st, 2017 closing price of $3.36/share.

3. Industry peer calculations use cash flow estimates, production, corporate base declines, capital efficiencies, outstanding share count, and share price data from Peters & Co. as of May 1, 2017.

4. 2017 forward strip commodity prices: WTI of US$50.25/bbl, WCS differential of US$13.47/bbl, CAD/US of 1.352.

5. Non-IFRS measure. See Advisory.

Free Cash Flow Yield vs. Peers SUSTAINABILITY ANALYSIS (1,2,3) - FORWARD STRIP COMMODITY PRICES(4)

Production Declines Capital Efficiency Free Cash Flow (5) Analysis ($MM) Free Cash Flow Yield

Production Base Replacement Cost to Replace CapEx Sustaining FREE CASH Share Free Cash Free Cash

(Current) Decline (to stay flat) Production Cash Flow Required Capex for Payout or Price per Share Flow Yield (boe/d) Rate (boe/d) ($/boe/d) ($MM) (2017E) (to stay flat) as % CF Reinvestment ($/share) ($/share) (%) A B C = A*B D E = (C*D) F G=E H=G/F I=F-G J K L=K/J Advantage 39,000 30.0% 11,700 $11,000 $128.7 $204.0 $128.7 63% $75.3 $8.54 $0.41 5% ARC 114,300 24.0% 27,432 $15,400 $422.5 $731.0 $422.5 58% $308.5 $17.81 $0.87 5% Baytex 68,200 35.0% 23,870 $18,100 $432.0 $288.0 $432.0 150% ($144.0) $4.00 ($0.62) -15% Bellatrix 33,100 30.0% 9,930 $10,200 $101.3 $81.0 $101.3 125% ($20.3) $1.02 ($0.08) -8% Birchcliff 62,400 25.0% 15,600 $14,400 $224.6 $344.0 $224.6 65% $119.4 $6.80 $0.45 7% Bonavista 70,300 25.0% 17,575 $13,300 $233.7 $333.0 $233.7 70% $99.3 $2.79 $0.35 13% Bonterra 13,100 23.0% 3,013 $20,800 $62.7 $115.0 $62.7 54% $52.3 $19.11 $1.57 8% Cardinal 15,200 13.0% 1,976 $20,000 $39.5 $83.0 $39.5 48% $43.5 $6.32 $0.56 9% Cequence 8,900 30.0% 2,670 $12,000 $32.0 $25.0 $32.0 128% ($7.0) $0.25 ($0.03) -11% Chinook 3,600 34.0% 1,224 $9,000 $11.0 $9.0 $11.0 122% ($2.0) $0.35 ($0.01) -3% Crescent Point 172,200 30.0% 51,660 $27,000 $1,394.8 $1,691.0 $1,394.8 82% $296.2 $13.14 $0.54 4% Crew 23,400 28.0% 6,552 $13,300 $87.1 $124.0 $87.1 70% $36.9 $4.16 $0.25 6% Delphi 8,000 39.0% 3,120 $14,400 $44.9 $45.0 $44.9 100% $0.1 $1.32 $0.00 0% Enerplus 77,000 23.0% 17,710 $16,000 $283.4 $385.0 $283.4 74% $101.6 $9.79 $0.42 4% Gear 6,000 27.0% 1,620 $23,300 $37.7 $42.0 $37.7 90% $4.3 $0.83 $0.02 3% Gran Tierra 30,200 23.0% 6,946 $19,300 $134.1 $205.0 $134.1 65% $70.9 $3.43 $0.18 5% Journey 8,600 20.0% 1,720 $24,200 $41.6 $40.0 $41.6 104% ($1.6) $2.60 ($0.03) -1% Kelt 19,800 30.0% 5,940 $12,800 $76.0 $117.0 $76.0 65% $41.0 $6.67 $0.23 3% Marquee 2,500 22.0% 550 $30,900 $17.0 $11.0 $17.0 155% ($6.0) $0.09 ($0.01) -15% Northern Blizzard (2) 17,100 12.0% 2,050 $26,500 $54.3 $110.6 $54.3 49% $56.2 $3.36 $0.56 17% Nuvista 26,100 36.0% 9,396 $14,500 $136.2 $168.0 $136.2 81% $31.8 $6.20 $0.18 3% Paramount 15,900 41.0% 6,519 $18,300 $119.3 $109.0 $119.3 109% ($10.3) $17.24 ($0.10) -1% Parex 32,600 23.0% 7,498 $17,000 $127.5 $248.0 $127.5 51% $120.5 $16.64 $0.79 5% Pengrowth 42,600 16.0% 6,816 $37,000 $252.2 $130.0 $252.2 194% ($122.2) $1.29 ($0.22) -17% Penn West 34,000 23.0% 7,820 $28,600 $223.7 $186.0 $223.7 120% ($37.7) $2.01 ($0.07) -4% Peyto 101,000 37.0% 37,370 $12,300 $459.7 $622.0 $459.7 74% $162.3 $24.49 $0.99 4% Perpetual 8,300 32.0% 2,656 $13,000 $34.5 $31.0 $34.5 111% ($3.5) $1.60 ($0.06) -4% Pine Cliff 21,300 12.0% 2,556 $13,000 $33.2 $52.0 $33.2 64% $18.8 $0.75 $0.06 8% Prairie Sky 24,100 21.0% 5,061 $0 $0.0 $265.0 $0.0 0% $265.0 $29.63 $1.12 4% Raging River 22,500 39.0% 8,775 $30,600 $268.5 $295.0 $268.5 91% $26.5 $7.88 $0.11 1% RMP 3,200 37.0% 1,184 $18,400 $21.8 $19.0 $21.8 115% ($2.8) $0.83 ($0.02) -2% Seven Generations 150,000 40.0% 60,000 $16,000 $960.0 $1,152.0 $960.0 83% $192.0 $24.33 $0.53 2% Spartan 21,400 26.0% 5,564 $21,300 $118.5 $203.0 $118.5 58% $84.5 $2.21 $0.15 7% Storm 16,800 33.0% 5,544 $8,400 $46.6 $70.0 $46.6 67% $23.4 $3.85 $0.19 5% Surge 14,500 24.0% 3,480 $22,800 $79.3 $111.0 $79.3 71% $31.7 $2.46 $0.14 6% Tamarack 18,500 34.0% 6,290 $20,600 $129.6 $134.0 $129.6 97% $4.4 $2.56 $0.02 1% TORC 19,800 23.0% 4,554 $23,400 $106.6 $197.0 $106.6 54% $90.4 $5.82 $0.49 8% Tourmaline 230,900 34.0% 78,506 $11,300 $887.1 $1,333.0 $887.1 67% $445.9 $27.13 $1.66 6% Trilogy 23,800 27.0% 6,426 $23,900 $153.6 $126.0 $153.6 122% ($27.6) $4.59 ($0.22) -5% Vermilion 64,500 18.0% 11,610 $14,800 $171.8 $622.0 $171.8 28% $450.2 $48.21 $3.78 8% Whitecap 55,600 23.0% 12,788 $20,000 $255.8 $479.0 $255.8 53% $223.2 $9.63 $0.61 6% TOTAL/AVERAGE 1,740,300 27.4% 503,271 $17,978 $8,445 $8,445 84% $3,091 2%


• Hedging program supports predictable cash flows – 2017 – 10,000 bbl/d (58%) at US$49.54/bbl WTI and 8,000 bbl/d (47%) at US$13.52/bbl WCS

differential – 2018 – 6,000 bbl/d (35%) at US$46.18/bbl WTI

1. Contracts denominated in CAD have been converted to USD at CAD/USD of 1.352.

Hedging Summary

58%

35%

$49.54 $46.18

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

55.00

60.00

65.00

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2017E 2018E

Aver

age

WTI

Pric

e (U

S$/b

bl)

% G

ross

Pro

duct

ion

Hedg

ed

Hedging Profile


• On April 10, 2017, Waterous Energy Fund and its affiliates announced an agreement to acquire the 67.7 million shares owned by affiliates of NGP and Riverstone. The transaction closed May 11, 2017.

1. As at Mar 31, 2017. 2. As at March 31, 2017, per SEDI.

Shareholder Breakdown

Common Shares Outstanding, Basic(1) 101.0 million shares Public Float 28.1 million shares / 28% Management & Directors(2) 5.2 million shares / 5% Waterous Energy Fund 67.7 million shares / 67%

Waterous Energy Fund

(67%)

Public Float (28%)

Mgmt (5%)


Non-IFRS Measures This presentation makes reference to certain terms that do not have any standardized meaning prescribed by IFRS, referred to as non-IFRS measures. The reader is cautioned that these amounts should not be used to make comparisons to measures for other companies where similar terminology is used. “Enterprise value” or “EV” is calculated as market capitalization plus net debt. “Debt adjusted cash flow” or “DACF” is calculated as funds from operations excluding cash finance costs. “Free cash flow” or “FCF” is calculated as funds from operations less capital expenditures. At the field level, free cash flow is calculated as operating income less capital expenditures. Free cash flow is used by Northern Blizzard to assess the performance of its assets in addition to its ability to finance dividends. “Free cash flow yield” or “FCF yield” is calculated as free cash flow per basic share divided by share price. For the purposes of this calculation free cash flow is defined as FFO less sustaining capex (i.e. capital spending required to maintain production flat). “Funds from operations” or “FFO” is calculated as cash flow from operating activities (as determined in accordance with IFRS) before shares purchased and held for the Northern Blizzard’s incentive plan, cash settlement of Incentive Plan Awards, decommissioning costs incurred, onerous provision costs incurred and changes in non-cash operating working capital. Funds from operations is used by Northern Blizzard to analyze operating performance and its ability to fund capital investments. Management considers funds from operations to be a key measure of the results generated by its principal business activities before the consideration of how those activities are financed or how the results are taxed and before decommissioning expenditures. “Funds from operations netback” is calculated as funds from operations divided by oil equivalent sales volumes for the period. “Market capitalization” is calculated by applying the period end closing share price to the number of shares outstanding. “Net debt” is calculated as the principal amount drawn on bank loans, the long-term debt and the onerous contract provision plus current liabilities less current assets (excluding the fair value of financial derivative contracts and the share-based compensation liability), and is used by the Northern Blizzard to assess liquidity and general financial strength. “Operating income” is calculated as oil and natural gas sales (net of blending expenses) less royalties, production and operating expenses and transportation expenses. Operating income is used as an indicator of operating performance and profitability. “Operating netback” is calculated as operating income divided by barrels of oil equivalent sales volume for the period. Operating netback is used as an indicator of operating performance and profitability relative to current commodity prices, calculated on a per barrel of oil equivalent basis. “Total payout ratio” is calculated as dividends paid plus capital expenditures divided by funds from operations. This calculation is consistent with Peters & Co’s “(E&D Capex + Div)/CF” calculation as at May 1, 2017. Presentation of Financial Information Unless otherwise noted, all financial information for Northern Blizzard has been prepared in accordance with IFRS, as issued by the International Accounting Standards Board.

Advisory


Presentation of Oil and Gas Information All oil and gas information in this presentation has been prepared and presented in accordance with NI 51-101 adopted by the Canadian securities regulatory authorities. Unless otherwise specified, in this presentation, all production is reported on the basis of Northern Blizzard’s working interest (“WI”) (operating and non-operating) before the deduction of royalties payable. Unless otherwise indicated, all numbers of wells and acreage information are presented on a gross basis. Unless otherwise indicated, reserves and resources information in this presentation is given as of December 31, 2016. For complete NI 51-101 reserves disclosures, refer to the Annual Information Form dated March 10, 2017. Discovered Petroleum Initially-in-Place or Discovered Oil Initially-in-Place (“DOIIP”), is defined in the Canadian Oil and Gas Evaluation Handbook as the quantity of oil that is estimated to be in place within a known accumulation prior to production. DOIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion consisting of production, reserves and contingent resources. There is no certainty that it will be economically viable or technically feasible to produce any portion of the DOIIP except for those portions already produced or identified in the independent reserves report. At December 31, 2016, all DOIIP that has not already been produced or classified as reserves would be classified as contingent resources or unrecoverable DOIIP . There are no contingent resources identified in this presentation. A portion of the quantities currently classified as unrecoverable DOIIP may become recoverable and reclassified as contingent resources or reserves in the future as additional technical studies are performed, commercial circumstances change or technological developments occur. The remaining portion may never be recovered due to the physical or chemical constraints represented by subsurface interaction of fluids and reservoir rocks. The discounted and undiscounted net present value of future net revenues attributable to reserves and resources do not represent the fair market value of such reserves and resources. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of crude oil, natural gas and NGL reserves and resources provided in this presentation are estimates only and there is no guarantee that the estimated reserves or resources will be recovered. Actual crude oil, natural gas and NGL reserves and resources may be greater or less than the estimates provided in this presentation. The estimates of reserves and future net revenue for individual properties in this presentation may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Northern Blizzard has adopted the standard of 6 Mcf:1 bbl when converting natural gas to oil equivalent. Boe conversions may be misleading particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Advisory (continued)


Forward-Looking Information This presentation contains certain forward-looking statements and forward-looking information within the meaning of applicable securities legislation (collectively, “forward-looking information”), which reflects management’s expectations about Northern Blizzard’s future growth, results of operations (including future production and capital expenditures), performance (both operational and financial) and business prospects. All information and statements other than statements of historical fact is forward-looking information. The information contained in this presentation does not purport to be all-inclusive or to contain all information that potential investors may require. In this presentation there is forward-looking information in respect of Northern Blizzard’s business; anticipated business activities and development plans; projected growth and execution of corporate plans and strategies; timing and success of development and exploitation activities; timing and development of Northern Blizzard’s capital projects; estimates of 2017 free cash flow and free cash flow yield for Northern Blizzard and its peers; expectations regarding Northern Blizzard’s ability to add production and reserves through exploration, development, exploitation and acquisitions; future oil and gas production levels; planned capital and operating expenditures; future operating costs; expected rate of return; hedging and other risk management plans and strategies; and future commodity prices. In addition, statements relating to “reserves” and “resources” are deemed to be forward-looking information 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. Although the forward-looking information in this presentation reflects management’s current beliefs about Northern Blizzard’s prospects, based on information currently available to management and on what management believes to be reasonable assumptions, there is no certainty that the actual results achieved will be consistent with such forward-looking information. Forward-looking information is not a guarantee of future performance and necessarily involves significant known and unknown risks, assumptions and uncertainties, some that are similar to other oil and gas companies and some that are unique to Northern Blizzard, which may cause Northern Blizzard’s actual results, performance, prospects and opportunities in future periods to differ materially from those expressed or implied by the forward-looking information provided in this presentation. Any changes to the assumptions on which such forward-looking information is based could cause actual results, performance or achievements to differ materially from the anticipated results expressed or implied in the forward-looking information of Northern Blizzard set out in this presentation. A large number of factors could affect the assumptions on which statements about forward-looking information are made in this presentation or the underlying assumptions many of which are beyond Northern Blizzard’s control, including: general economic, market and business conditions; competition; fluctuations in oil and natural gas prices; and changes in laws or royalty regimes. Forward-looking information is expressly qualified by the foregoing cautionary statements, is stated as of the date of preparation of this presentation and, except as required under applicable laws, Northern Blizzard assumes no obligation to update or revise such information to reflect new events or circumstances. The 2017 guidance provided in this is presentation is based on a number of material assumptions and factors as set out above and in Northern Blizzard’s most recent management’s discussion and analysis. This financial outlook is included to provide readers with an understanding of Northern Blizzard’s operations for 2017. Readers are cautioned that the information may not be appropriate for other purposes. The actual results of Northern Blizzard’s operations for the corresponding period will vary form the financial outlook and such variations may be material. See “Forward-Looking Statements” in Northern Blizzard’s most recent management’s discussion and analysis for a discussion of the risks that could cause actual results to vary. This guidance has been approved by management as of the date of this presentation.

Advisory (continued)


1900, 421 – 7 Avenue SW, Calgary, AB T2P 4K9 (403) 930-3000

www.northernblizzard.com

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