SUSTAINABLE CONVENTIONAL RESOURCE COMPANY TSX: SGY JANUARY, 2019 - - PowerPoint PPT Presentation

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SUSTAINABLE CONVENTIONAL RESOURCE COMPANY TSX: SGY JANUARY, 2019 - - PowerPoint PPT Presentation

SUSTAINABLE CONVENTIONAL RESOURCE COMPANY TSX: SGY JANUARY, 2019 REASONS TO OWN SURGE TSX: SGY Value based with a strong focus on shareholder returns High quality conventional, large OOIP (1) , light/medium gravity crude oil asset base;


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SUSTAINABLE CONVENTIONAL RESOURCE COMPANY TSX: SGY JANUARY, 2019

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REASONS TO OWN SURGE – TSX: SGY

Value based with a strong focus on shareholder returns

▪ High quality conventional, large OOIP

(1), light/medium gravity crude oil asset

base; 84% of production is oil + liquids; low decline of 23%; excellent capital efficiencies

(2);

▪ Deep value proposition;

▪ >80% growth in production over the last 10 quarters; and ▪ 2017 year end 2P Sproule NAV of $6.06 per common share (1P NAV of $3.67 per common share)

(3).

▪ Over $900 million enterprise value; average daily trading volumes of 1.5 million shares – covered by 19 brokerage firms; ▪ Return capital to shareholders through a sustainable monthly dividend;

▪ Dividend of $0.10 per share annually (dividend yield >6%)(4) .

▪ Drilling inventory: over 800 net locations (>12 years of drilling)

(5); and

▪ ~$130 million available on credit facility

(6).

(1) See the reserves section of the forward looking statements at the back of this presentation. (2) See the Additional Metrics section at the back of this presentation for additional information. (3) Based on Surge’s 3rd party evaluated reserves as of December 31, 2017, and does not include acquisitions or divestures made by Surge in 2018. (4) Based on a $1.50 share price and a $0.10 annual dividend. (5) Drilling locations are comprised of both booked and un-booked locations and are defined in the Drilling Locations section at the back of this presentation. (6) Calculated as follows: $550 million credit facility less $420 million in estimated bank debt as of December 31, 2018.

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CONSISTENT PRODUCTION GROWTH

Surge management continues to deliver quarterly production growth Surge has delivered six upward revisions to production guidance since Q2 2016

  • twice organically, and four times through accretive core area acquisitions.

9,000 11,000 13,000 15,000 17,000 19,000 21,000 23,000

Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18 2019 Budget Avg

Production (boepd)

>80% Production Growth Since Q2 2016

Accretive light oil acquisition

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2019 CAPITAL BUDGET AND PRODUCTION GUIDANCE

Cost effective, sustainable, low decline production base Capital Category

2019 Total

Drilling and Completions $100 million Facilities, Equipment, and Pipelines $25 million Other (Land, Seismic, G&A) $10 million

Total Exploration and Development Capital $135 million

Production and Cost Guidance

2019e Average Production 22,000 boepd (84% liquids) 2019e Exit Production 22,000 boepd (84% liquids) 2019e Operating Costs $15.45 - $15.95 per boe 2019e Transportation Costs $1.50 - $1.75 per boe 2019e General & Administrative Costs $1.75 - $1.90 per boe 4

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2019 SUSTAINABILITY ANALYSIS

Commodity Sensitivity (1) WTI (USD) $55 $65 $75

FX (USD / CAD) $0.75 $0.75 $0.75 WTI (CAD$ / Bbl) $73.33 $86.67 $100.00 MSW-to-WTI Differential (US$ / Bbl)

  • $5.00
  • $5.00
  • $5.00

WCS-to-WTI Differential (US$ / Bbl)

  • $15.00
  • $15.00
  • $15.00

Capital Efficiency ($ / boepd) $25,500 $25,500 $25,500

2019e Cash Flow from Operating Activities(2) ($ MM) $171 $236 $291 Exploration and Development Capital ($ MM) $135 $135 $135 Dividend ($ MM) $31 $31 $31

Capital & Dividend ($ MM) $166 $166 $166

Cash Flow from Operating Activities in Excess of Capital & Dividend ($ MM) $5 $70 $125

All-in Payout Ratio(3) 97% 70% 57%

(1) Based on production of 22,000 Boepd (2) Assumes $NIL working capital. (3) This is a Non-GAAP financial measure which is defined in the Non-GAAP financial measures section of this document.

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SURGE ASSET BASE HIGHLIGHTS

An operational platform to continue to execute a sustainable model

▪ Over 2.4 billion net barrels of conventional OOIP under management - with an estimated 6.9% recovery factor

(1) to date;

▪ Proven plus probable year end 2017 reserves of over 120 million boe (90% oil)

(2);

▪ 22,000 boepd light and medium gravity oil producer (84% oil and liquids weighted); ▪ Low corporate base production decline of 23%; ▪ Development drilling upside: >800 net locations; provides a drilling inventory of more than 12 years; and ▪ >14 year reserve life index (proved plus probable)

(3).

(1) See the Additional Metrics section at the back of this presentation for additional information. (2) Based on 3rd party evaluated reserves as of December 31, 2017, and includes acquisitions or divestures made by Surge in 2018. (3) Reserve Life Index (RLI) is calculated by dividing year end reserves by expected annual production.

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OPERATIONS FOCUSED IN 4 CORE AREAS

Large OOIP pools in established conventional reservoir trends

Valhalla:

Total: ~5,300 boe/d (65% Oil & NGL’s)

Sparky:

Total: ~7,500 boe/d (90% Oil & NGL’s)

Shaunavon:

Total: ~2,500 boe/d (100% Oil & NGL’s)

Surge 2019 Average Production Total: 22,000 boe/d (84% Oil & NGL’s)

Greater Sawn:

Total: ~5,700 boe/d (98% Oil & NGL’s)

Minors: Total: ~1,000 boe/d (50% Oil & NGL’s)

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TARGETING CONVENTIONAL RESERVOIRS

Surge focuses on reservoirs at the conventional end of the permeability spectrum

Source: Modified from US Department of Energy Study

0.0001 0.001 0.01 0.1 1 10 100 Extremely Tight Very Tight Tight Low Moderate High Permeability (mD) Unconventional Reservoirs Conventional Reservoirs Ultimate Oil Recovery PIR & IRR

Duvernay Montney Resource Viking-Cardium Halo Valhalla Doig Shaunavon Sparky

Recovery factors, internal rates of return (IRR)(1), decline rate, and profit to investment ratio (PIR)(1) increases, as reservoir quality improves.

Average Surge Permeability

Slave Point

(1) See the Additional Metrics section at the back of this presentation for additional information.

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NET OOIP OF >2.4 BILLION BARRELS

Large OOIP, with low recovery factors - focused in conventional reservoirs

Core Area Formations SGY Estimated Net OOIP (MMbbls) Total Net drilling Locations

  • Avg. WI

Net CTD(2) Oil Recovery Factor Total Booked Net Independent Recovery Factor P+P (Booked)(1) (% OOIP)(1)

Sparky Core Sparky Formation + Mannville Group >800 400 (97) 89% 10.4% 13.6% Valhalla Doig / Montney / Doe Creek / Charlie Lake >285 89 (50) 82% 8.6% 10.0% Greater Sawn Slave Point >690 119 (80) 89% 6.8% 11.5% Shaunavon Shaunavon (Upper & Lower) >470 177 (83) 98% 1.7% 5.4% TOTALS

(3):

>2,400 >800 (340) 88% 6.9% 10.6%

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>2.4B net barrels of internally estimated OOIP under ownership; Current net recovery factor ~6.9%.

(1) Based on 3rd party evaluated reserves as of December 31, 2017, and includes acquisitions or divestures made by Surge in 2018. Also see Drilling Locations section at the back of this presentation for additional information. (2) CTD means cumulative oil produced to date. (3) Totals do not add up as minor properties have been included in the totals but have not been subcategorized in the table.

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10 yrs 12 yrs 13 yrs 13 yrs

100 200 300 400 500 600 700 800 900 $55 WTI $1.75 AECO (0.75 FX) $65 WTI $1.75 AECO (0.76 FX) $75 WTI $1.75 AECO (0.78 FX) $85 WTI $1.75 AECO (0.80 FX)

SGY Economic Locations

SGY Economic Locations - >20% Risked IRR

*IRR: 68% *PIR10: 0.93 (1) *IRR: 85% *PIR10: 1.13 (1) *IRR: 114% *PIR10: 1.40 (1) *IRR: 118% *PIR10: 1.45 (1)

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SURGE’S ECONOMIC INVENTORY > 20% IRR

12 years of drilling @ US$65 WTI - Average Risked IRR: 85% & PIR10: 1.13

Years of Drilling Inventory (assumes 65 wells/yr.)

* Risked weighted average

Realized WCS C$49 C$59 C$68 C$76 Realized EDMN C$67 C$77 C$87 C$96

(1) Profit to Investment ratio, discounted at 10% (PIR10) equals 0.0, when NPV10 equals the original investment capital (i.e. 0.0 = breakeven). See the Additional Metrics section at the back of this presentation for additional information (2) Drilling locations are comprised of both booked and un-booked locations. See the Drilling Locations section at the back of this presentation.

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SPARKY – A DOMINANT POSITION

Applying modern technology to a prolific Western Canadian formation

* Data sourced from Canadian Discovery and GeoScout

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Medium Gravity Oil Window >20° API

Sparky Formation Facts * First Production May 1922 Original Oil in Place > 11 Bbbls Cum Production > 1 Bbbls Recovery Factor <10% Producing Wells > 20,000

Hz Wells / Multi-Stage Hz / Surge Multi-Stage Hz

>650 / >200 / >90

▪ The Sparky is a well established prolific oil producing formation in Western Canada. ▪ Surge holds a dominant land position in the medium / light gravity oil window and is effectively applying modern horizontal multi-stage fracturing technology. Key Sparky Value Drivers:

  • Shallow depth (700-900m).
  • Low cost drilling (D,C&E at CAD$1.2MM per well).
  • Low geological risk due to 3D seismic and thousands of

vertical penetrations.

  • Lighter oil gravity (23-31° API) = higher netbacks.
  • Proven waterflood potential (Wainwright pool at >35%

recovery factor*).

AB SK

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SPARKY - A DIVERSIFIED LOW RISK ASSET BASE

Over 800 MMbbls of net OOIP and >400 drilling locations

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>800 MMbbls of net OOIP 400 net drilling locations (97 booked) >11 year drilling inventory

Betty Lake >80MMbbls OOIP Wainwright >160MMbbls OOIP Provost South >100MMbbls OOIP Macklin >40MMbbls OOIP Provost >50MMbbls OOIP Lakeview (Lloyd) >50MMbbls OOIP Eyehill >180MMbbls OOIP East Sounding Lake >40MMbbls OOIP Sounding Lake >60MMbbls OOIP Eyehill South >20MMbbls OOIP

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0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60

SE SK Frobisher/ Alida- Open-Hole Sparky / Eyehill SW SK Cantaur SE AB Sparky SW SK Viking SE SK Ratcliffe/ Midale- Open-Hole SW SK Shaunavon SE SK Midale- Frac'd Charlie Lake AB Viking Marten Hills Clearwater Heavy SE SK Bakken Provost Heavy Northwest Alberta Cardium Lloydminster/ Cold Lake Heavy PRA/ Seal Bluesky/ Gething Heavy Cold Lake Heavy – Vertical Northwest Alberta Dunvegan NW AB/NE BC Montney Kaybob Duvernay Volatile

  • S. Alberta Lower/ Mid Mannville

East Shale Basin Duvernay Greater Pembina Cardium SE SK Torquay Swan Hills Beaverhill Lake Profit to Investment Ratio (9%)

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Competing with the best light/medium oil plays in Western Canada

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As per Scotiabank’s Playbook As per internal estimates(1)

SPARKY – TOP QUARTILE ECONOMICS

Note: The Playbook defines profit investment ratio (PIR) as the present value of future cash flow, after tax, divided by the initial investment. Surge has assumed a baseline of zero meaning that any play with a PIR(9%) greater than zero represents an economic play. (1) Economics on Surge internal type curves were derived using the Playbook's "Base" commodity pricing assumptions.

** Source: Scotiabank The Playbook; "Ranking North Americas Oil & Gas Plays - 9th Edition"; Industry Report September 2018.

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SPARKY EYEHILL – SUSTAINABLE DEVELOPMENT

>165MMbbl net OOIP estimated with 1.5MMbbl’s produced to date

▪ Surge has now captured and controls over 85% of the total Eyehill pool. ▪ 11 Sparky horizontal wells drilled in 2018. ▪ Over 75 net low risk locations remain on Surge’s acreage. ▪ 200m well spacing is ideal for primary recovery and waterflood implementation. ▪ 7 wells have been converted to water injection.

Sparky Sands

Eyehill - Sparky Type Log 06-14-037-03W4

SGY Lands SGY Operated SGY Water Injectors 2018 Sparky Drills

06-14-37-3W4 Type Log

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GREATER SAWN - CONCENTRATED LIGHT OIL

>675 million barrels net OOIP in concentrated Slave Point reservoirs ▪ OOIP of >675 million bbls net of light oil (35-42° API). ▪ Development inventory of 119 net locations (80 net booked). ▪ Key Attributes:

  • Over 675 million barrels of net OOIP.
  • 6.8% recovery to date.
  • ~5,700 boepd – 98% light oil.
  • 23% base decline.
  • Production derived primarily from large multi-cycle

reef complexes (pay(1) thickness of up to 18 meters).

  • 12.5 year RLI (proved plus probable).

▪ Active Slave Point Waterfloods:

  • Sawn
  • Red Earth
  • Evi/Otter
  • Nipisi

Nipisi & Nipisi South

OOIP: ~75 MMbbl net

Sawn

OOIP: >200 MMbbl net

Red Earth

OOIP: >250 MMbbl net

Evi / Otter

OOIP: >150 MMbbl net

(1) See the Additional Metrics section at the back of this presentation for additional information.

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SLAVE POINT HZ AVERAGE IP180’s (2011-2018)

Well results on Surge’s land base indicates higher quality reservoir

20 40 60 80 100 120 140 160 180 1 2 3 4 5 6 7

Producing Day IP 180 bopd 160 bopd Dolomite 2011-12 6 Wells 0/6 in Reef Facies Lone Pine 2012-14 Last 25 Wells 5/25 in Reef Facies Pinecrest 2012-13 Last 25 Wells 3/25 in Reef Facies Cdn Forest 2011 Last 25 Wells 5/25 in Reef Facies Harvest 2012-15 Last 25 Wells 16/25 in Reef Facies SGY Assets 2013-14 Last 25 Wells 17/25 in Reef Facies SGY Assets 2017-18 12 Wells 9/12 wells in Reef Facies 145 bopd 124 bopd 98 bopd 86 bopd 83 bopd 78 bopd

All Wells Single Leg Hz

**Data Source: GeoScout.

Surge Assets Yielding Best Results In Area

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VALHALLA – STACKED MULTI-ZONE POTENTIAL

Multiple large OOIP light oil reservoirs provide a sustainable drilling inventory and production base

▪ >250 MMbbls of net combined OOIP on Surge’s Valhalla lands. ▪ Doig wells continue to be among the most prolific oil producers in Western Canada. ▪ Multiple stacked light oil horizons creates additional opportunities. ▪ Drilling inventory includes 89 net locations in multiple horizons (50 net booked). ▪ Light oil gravity (~40° API) and extensive infrastructure in the area = attractive netbacks.

Formation Depth (m) Net OOIP (MMbbl) Capital ($MM/well) IP180 (boe/d) IP 180 Prod Eff ($/boepd) Doig 2050 150 $4.0 450 $8,900 Doe Creek 700 80 $1.6 135 $11,850 Charlie Lk. 1900 >20 $3.4 275 $12,360 Montney 2200 32 $4.0 430 $9,300 17

Doig Doe Creek Montney

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SHAUNAVON

>425 MMbbl net OOIP on Surge lands in the Upper and Lower Shaunavon

▪ Total Shaunavon production (Upper & Lower) is ~2,500 bopd. ▪ Upper Shaunavon net OOIP estimated to be >225 MMbbl.

  • >100 net locations – (48 net booked).
  • 9 horizontal wells converted to water injection.
  • Current recovery in the Upper Shaunavon is <1% -

analogues show recover factors >30%. ▪ Lower Shaunavon net OOIP estimated to be >200 MMbbl.

  • >65 net locations – (35 net booked).
  • Surge recently drilled and completed 5 Lower

Shaunavon wells using cemented liner, plug and perf methodology with 100% success rate.

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SGY Lands Upper Shaunavon Oil Fairway Water Injector SGY Upper Shaunavon Wells Upper Shaunavon Producing Well SGY Lower Shaunavon Wells Lower Shaunavon Producing Wells

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HIGH QUALITY CRUDE OIL ASSET BASE

Positioned for long term sustainability

▪ Low base production decline of 23%; high netbacks; excellent capital efficiencies; ▪ Dividend of $0.10 / share annually (dividend yield >6%) – Surge reported a low Dividend Payout Ratio of 14%

(1) for Q3/18;

▪ Solid balance sheet; ~$130 million available on credit facility; ▪ 4 core areas with operatorship, and working interests of >90%; ▪ Large OOIP conventional crude oil reservoirs – with a current combined recovery factor of 6.9%; >14 year RLI; and ▪ Over 800 net development drilling locations; provides >12 year drilling inventory.

(1) This is a capital management measure which is defined in the Capital Management Measures section at the back of this presentation.

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APPENDIX

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OIL HEDGING

All USD-denominated WTI hedges have been converted to CAD at a rate of $0.75 USD/CAD for the purposes of this graph.

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3,167 bbl/d 2,750 bbl/d 2,500 bbl/d 2,500 bbl/d $50.00 $55.00 $60.00 $65.00 $70.00 $75.00 $80.00 500 1000 1500 2000 2500 3000 3500

  • Qtr. 1 2019
  • Qtr. 2 2019
  • Qtr. 3 2019
  • Qtr. 4 2019

Weighted AVerage Floor Price per Bbl (C$ WTI) bbl/d of WTI Hedged

  • Avg. Bbl / d hedged

Avg floor Price - C$ WTI / Bbl

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RISK MANAGEMENT / HEDGING STRATEGY

WTI Oil Hedges

The Company has an on-going, risk management / hedging program designed to lock in future cash flows to protect the Company’s capital program and fund dividends. Below is a list of Surge’s current hedging programs:

Type Term bbl/d Currency Put Sold Put Acquired Call Sold Call Acquired Swap Price (per bbl) (per bbl) (per bbl) (per bbl) (per bbl)

WTI 2H 2018 - Q1 2019 500 USD $50.00 $60.00 $71.50

  • WTI

2H 2018 - Q1 2019 500 USD $50.00 $57.50 $78.10

  • WTI

Q2 2019 500 USD $50.00 $57.50 $72.50

  • WTI

1H 2019 500 USD $47.50 $57.50 $75.50

  • WTI

1H 2019 500 CAD $50.00 $60.00 $73.34

  • WTI

1H 2019 500 USD $53.00 $60.00 $80.50

  • WTI

1H 2019 500 USD $53.00 $60.00 $82.00

  • WTI

2H 2019 2,000 USD $53.00 $60.00 $82.79

  • WTI

2H 2019 250 USD

  • $50.00

$63.40

  • WTI

2019 250 USD

  • $53.90

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RISK MANAGEMENT / HEDGING STRATEGY

The Company has an on-going, risk management / hedging program designed to lock in future cash flows to protect the Company’s capital program and fund dividends. Below is a list of Surge’s current hedging programs:

Natural Gas Hedges

Type Term Volume Currency Floor Ceiling Chicago Collar Nov 2018 through Mar 2019 4,000 mmbtu/d USD $2.65 per mmbtu $3.30 per mmbtu Chicago Swap Nov 2018 through Mar 2019 4,000 mmbtu/d USD $3.49 per mmbtu $3.49 per mmbtu

CAD/USD FX Hedges

Type Term Monthly Notional Amount (US$) Total Notional Amount (US$) Swap Rate (CAD per USD) Avg Rate Forward 2019 $1,000,000 $12,000,000 1.2726 Avg Rate Forward 2H 2018 through 1H 2019 $3,000,000 $36,000,000 1.2850

Oil Differential Hedges

Type Term bbl/d Currency Floor (per bbl) Ceiling (per bbl) WCS (Physical) 2019 1,500 USD US$WTI less $16.45 US$WTI less $22.00 WCS Jan 2019 through Oct 2019 500 USD US$WTI less $19.25

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INTEREST RATE HEDGING & CONVERTIBLE DEBENTURE

Type Term Notional Amount (CAD$) Surge Receives Surge Pays Effective Fixed Rate SGY Pays

Fixed-to-Floating Rate Swap Feb 2018 to Feb 2023 $100,000,000 Floating Rate Fixed Rate Effective All in Rate 5.0%(1) Convertible Debenture Issuance Nov 2017 to Dec 2022 $44,500,000 Floating Rate Fixed Rate Effective All in Rate 5.75%

Total $144,500,000 Weighted Average All in Rate of 5.23%

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INTEREST RATE HEDGE

Type Term Notional Amount (CAD$) Surge Receives Surge Pays Fixed Rate SGY Pays Fixed-to-Floating Rate Swap Feb 2018 to Feb 2023 $100,000,000 Floating Rate Fixed Rate Semi-Annual Step Up

  • Beginning at 1.786%
  • Ending at 2.714%
  • Averaging 2.479%

FIXING INTEREST COSTS IN A RISING RATE ENVIRONMENT

(1) Based on projected borrowing spread as of October 1, 2018

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ANALYST COVERAGE

Financial Institution Analyst Email Address

Acumen Capital Partners Trevor Reynolds treynolds@acumencapital.com BMO Capital Markets Ray Kwan ray.kwan@bmo.com Canaccord Genuity Anthony Petrucci apetrucci@canaccordgenuity.com CIBC Dave Popowich dave.popowich@cibc.com Clarus Securities Inc. Robert Pare rpare@clarussecurities.com Cormark Securities Inc. Garett Ursu gursu@cormark.com Eight Capital Adam Gill agill@viiicapital.com GMP FirstEnergy Robert Fitzmartyn rjfitzmartyn@gmpfirstenergy.com Industrial Alliance Securities Michael Charlton mcharlton@iagto.ca Laurentian Bank Securities Todd Kepler KeplerT@lb-securities.ca Macquarie Securities Group Brian Kristjansen brian.kristjansen@macquarie.com Paradigm Capital Ken Lin klin@paradigmcap.com National Bank Financial Dan Payne Dan.payne@nbc.ca Peters & Co. Limited Cindy Mah cmah@petersco.com Raymond James Jeremy McCrea Jeremy.McCrea@raymondjames.ca RBC Capital Markets Shailender Randhawa shailender.randhawa@rbccm.com Schachter Asset Management Josef I. Schachter josef@e-sami.com Scotia Capital Inc. Cameron Bean cameron.bean@scotiacapital.com TD Securities Juan Jarrah Juan.Jarrah@tdsecurities.com

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2100, 635 – 8th Ave. SW, Calgary Alberta T2P 3M3 T: 403.930.1010 F: 403.930.1011 www.surgeenergy.ca

Advisors Bankers Syndicate: National Bank of Canada Bank of Nova Scotia Canadian Imperial Bank of Commerce Toronto-Dominion Bank Bank of Montreal ATB Financial HSBC Bank Canada Wells Fargo Goldman Sachs BDC Capital Auditor: KPMG LLP Legal Counsel: McCarthy Tétrault Evaluation Engineers: Sproule Registrar & Transfer Agent: Computershare Canada Investor Contacts: Paul Colborne, President & CEO Jared Ducs, Vice President Finance

CORPORATE PARTNERS

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FORWARD-LOOKING STATEMENTS

FORWARD-LOOKING STATEMENTS

This presentation contains forward-looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. More particularly, this presentation contains statements concerning: Surge and its results and development plans; the assets owned or acquired by Surge and the characteristics thereof; Surge’s operational and financial platform; the sustainability of Surge and Surge’s growth plus income model; recycle ratios; reduction of capital costs; production efficiencies; internal rates of return; profit to investment ratio; recovery factors; estimated future drilling locations and lowering of corporate decline rate; reserve life index; management’s expectations with respect to the development of certain Surge assets; Surge’s estimated total net debt; availability of funds under Surge’s credit facility; Surge’s hedging strategy and the associated benefits; projected borrowing spread of Surge; Surge’s declared focus and primary goals; Surge’s annual exploration and development capital expenditure program; expectations of Surge’s management with respect to Surge’s waterflood program and results therefrom; and Surge’s dividend policy. The guidance for 2019 set forth in this presentation may be considered to be future-oriented financial information or a financial outlook for the purposes of applicable Canadian securities laws. Financial

  • utlook and future-oriented financial information and projected operational information contained in this presentation are based on assumptions about future events based on management's assessment of

the relevant information currently available. In particular, this presentation contains projected financial information for 2019, including 2019 adjusted funds and funds on a per basic share basis, exploration and development capital expenditures, 2019 dividend, 2019 free adjusted funds flow, 2019 all-in payout ratio and Q4 2019 net debt to annualized adjusted funds flow. This presentation also contains certain projected operational information, including 2018 exit production, average 2019 production and % oil and NGLs weighting. The future-oriented financial information and financial outlooks and projected

  • perational information contained in this presentation have been approved by management as of the date of this presentation. Readers are cautioned that any such future-oriented financial information,

financial outlooks and projected operational information contained herein should not be used for purposes other than those for which it is disclosed herein. The forward-looking statements are based on certain key expectations and assumptions made by Surge, including the ability of Surge to execute and realize on the anticipated benefits of certain acquisitions; the performance of existing wells and success obtained in drilling new wells; anticipated expenses, cash flow and capital expenditures; the application of regulatory and royalty regimes; prevailing commodity prices and economic conditions; development and completion activities; the performance of new wells; the successful implementation of waterflood programs; the availability of and performance of facilities and pipelines; the geological characteristics of Surge’s properties; the successful application of drilling, completion and seismic technology; the determination of decommissioning liabilities; prevailing weather conditions; exchange rates; licensing requirements; the impact of completed facilities on operating costs; the ability of Surge to increase or maintain its dividend; the availability and costs of capital, labour and services; and the creditworthiness of industry partners. Although Surge believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Surge can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and

  • uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in

general (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and constraint in the availability of services, adverse weather or break-up conditions, uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures or failure to obtain the continued support of the lenders under Surge’s bank line. Certain of these risks are set out in more detail in Surge’s Annual Information Form dated March 14, 2018 and in Surge’s MD&A for the period ended Sept 30, 2018, both of which have been filed on SEDAR and can be accessed at www.sedar.com. The forward-looking statements contained in this presentation are made as of the date hereof and Surge undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

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FORWARD-LOOKING STATEMENTS

Reserves

Reserves disclosed in this presentation are derived from a third party external evaluation done by Sproule using standard practices as prescribed in the Canadian Oil and Gas Evaluations Handbook and account for associated proved and/or probable reserves, as applicable. Reserves referenced in this presentation account for all of Surge’s Acquisitions and Divestiture activity to date, reflecting the bookings that existed (from the respective 3rd party evaluator), as of January 1, 2018 (the “Surge Report”). Boe means barrel of oil equivalent on the basis of 1 boe to 6,000 cubic feet of natural gas. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe for 6,000 cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boe/d and boepd means barrel of oil equivalent per day. Bbl means barrel of oil. NGLs means natural gas liquids. For the purpose of this presentation, Original Oil in Place (“OOIP”) means Discovered Petroleum Initially In Place (“DPIIP”) as at Oct 31st, 2018. DPIIP is derived by Surge’s internal Qualified Reserve Evaluators (“QRE”) and prepared in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluations Handbook (“COGEH”). DPIIP, as defined in 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 Resources Other Than Reserves (ROTR). The OOIP/DPIIP and potential recovery rate estimates are as at Oct 31st, 2018 and are based on current recovery technologies and have been prepared by Surge’s internal Qualified Reserve

  • Evaluators. There is significant uncertainty as to the ultimate recoverability and commercial viability of any of the resource associated with the OOIP/DPIIP estimates, and as such a recovery project cannot

be defined for this volume of OOIP/DPIIP at this time.

Drilling Locations

This presentation discloses drilling locations in two categories: (i) booked locations; and (ii) unbooked locations. Booked locations are proved locations and probable locations derived from a third party external evaluation done by Sproule using standard practices as prescribed in the Canadian Oil and Gas Evaluations Handbook and account for drilling locations that have associated proved and/or probable reserves, as applicable. Drilling locations referenced in this presentation account for all of Surge’s Acquisitions and Divestiture to date, reflecting the bookings that existed (from the respective 3rd party evaluator), as of January 1, 2018. Unbooked locations are internal estimates based on prospective acreage and assumptions as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by Surge’s internal Qualified Reserve Evaluators as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Assuming the January 1, 2018 reference date outlined above, the company discussed in this presentation will have over >800 gross (>800 net) drilling locations identified herein, of these >500 gross (>500 net) are unbooked locations. Of the 340 net booked locations identified herein 258 net are Proved locations and 82 net are Probable locations. Type curve economics referenced on “Surge’s Economic Inventory > 20% IRR” slide, were constructed using a representative, factual and balanced analog data set, as of Oct 31, 2018. All locations were risked appropriately, and EUR’s were measured against OOIP estimates to ensure a reasonable recovery factor was being achieved based on the respective spacing assumption. Over 95% of the locations used in the economic inventory slide were represented by type curves developed by Surge’s Qualified Reserve Evaluators, the remaining locations were represented using Sproule’s 2017YE type curves. Other assumptions, such as capital, operating expenses, wellhead offsets, land encumbrances, working interests and NGL yields were all reviewed and accounted for on a well by well basis by Surge’s Qualifies Reserve Evaluators. All type curves fully comply with Part 5.8 of the Companion Policy 51 – 101CP.

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CAPITAL MANAGEMENT MEASURES

Capital Management Measures

Dividend Payout Ratio Dividend payout ratio is calculated as the dividends paid for the respective period divided by adjusted funds flow. This capital management measure is used by management to analyze the level of dividends currently being paid on the stock in comparison to the cash being generated by the principal business activities.

(1) This is a non-GAAP financial measure which is defined in the Non-GAAP Financial Measures section of this document.

($000s) Q3/18 Q3/17 Dividends paid $ 5,788 $ 5,386 Adjusted funds flow (1) $ 40,638 $ 22,985 Dividend payout ratio (dividends paid as a % of adjusted funds flow) 14% 23%

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NON-GAAP FINANCIAL MEASURES

Non-GAAP Financial Measure

Certain secondary financial measures in this presentation– namely, "adjusted funds flow“ are not prescribed by GAAP. This non-GAAP financial measure is included because management uses the information to analyze business performance, cash flow generated from the business, leverage and liquidity, resulting from the Company’s principal business activities and it may be useful to investors on the same basis. This measure is not used to enhance the Company’s reported financial performance or position. This non-GAAP measure does not have a standardized meaning prescribed by IFRS and therefore is unlikely to be comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and

  • application. All non-GAAP financial measures used in this document are defined below:

Adjusted Funds Flow The Company adjusts cash flow from operating activities in calculating adjusted funds flow for changes in non-cash working capital, decommissioning expenditures, transaction and other costs, and cash settled stock-based compensation plans, particularly cash used to settle withholding obligations on stock-based compensation arrangements that are settled in shares. Management believes the timing of collection, payment or incurrence of these items involves a high degree of discretion and as such may not be useful for evaluating Surge’s cash flows. Changes in non-cash working capital are a result of the timing of cash flows related to accounts receivable and accounts payable, which management believes reduces comparability between

  • periods. Management views decommissioning expenditures predominately as a discretionary allocation of capital, with flexibility to determine the size and timing of decommissioning programs to

achieve greater capital efficiencies and as such, costs may vary between periods. Transaction and other costs represent expenditures associated with acquisitions, which management believes do not reflect the ongoing cash flows of the business, and as such reduces comparability. Subsequent to the third quarter of 2018, all of the Company’s stock-based compensation plans are equity classified as the Company has the intention of settling all awards with shares. Cash settled stock-based compensation currently represents the statutory tax withholdings required on stock- based compensation awards and is a discretionary allocation of capital. The Company has the option to either require the holder to sell shares earned in the stock-based compensation plan to satisfy tax withholdings, or the Company can issue less shares to the individual and remit a cash payment to satisfy tax withholding requirements. Each of these expenditures, due to their nature, are not considered principal business activities and vary between periods, which management believes reduces comparability. The following table reconciles cash flow from operating activities to adjusted funds flow:

($000s) Q3/18 Q3/17 Cash flow from operating activities $ 37,197 $ 24,589 Change in non-cash working capital (2,269) (2,954) Decommissioning expenditures 1,329 686 Transaction and other costs 1,016 138 Cash settled stock-based compensation 3,365 526 Adjusted funds flow $ 40,638 $ 22,985

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ADDITIONAL METRICS

Additional Metrics

This presentation contains additional metrics commonly used in the oil and natural gas industry. These terms have been calculated by Management and do not have a standardized

  • meaning. Management uses these oil and gas metrics to further analyze the performance of the Company over time and to compare the results of the Company with others in the industry.

Additional metrics used in this presentation are as follows:

  • Capital efficiency is the amount of development and exploration capital expenditures required to add an additional boe of production per day.
  • Internal rate of return is a discount rate that makes the net present value (NPV) of all cash flows from a particular project equal to zero.
  • Profit to investment ratio is calculated as the net present value (NPV) from a project divided by the capital investment required to realize such cashflows.
  • Recovery factors is defined as the percentage of hydrocarbons currently recovered or potentially recoverable from a known accumulation of such hydrocarbons.
  • Pay for the purpose of this presentation is defined as hydrocarbons located in the subsurface as determined by Surge’s internal qualified reserve evaluators. The overall interval in which

pay sections occur is the gross pay; the smaller portions of the gross pay that meet local criteria for pay (such as minimum porosity, permeability and hydrocarbon saturation) are net pay.

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OIL AND GAS ADVISORY

"In this presentation, "Boe" means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6mcf: 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. In addition, 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 of 6: 1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. In this presentation: (i) mcf means thousand cubic feet; (ii) mcf/d means thousand cubic feet per day (iii) MMcf means million cubic feet; (iv) mmcf/d means million cubic feet per day; (v) bbls means barrels; (vi) mbbls means thousand barrels; (vii) MMbbls means million barrels; (viii) bbls/d means barrels per day; (ix) bcf means billion cubic feet; (x) mboe means thousand barrels of oil equivalent; (xi) mmboe means million barrels of oil equivalent and (xii) boe/d means barrels of oil equivalent per day. The estimated values of the future net reserves of the reserves disclosed in this presentation do not represent the market value of such reserves. The estimates of reserves and future net reserve for individual properties may not reflect the same confidence level as estimates of reserves and future net reserve for all properties due to the effects of aggregation. Original Oil in Place (OOIP) is the equivalent to Discovered Petroleum Initially In Place (DPIIP) for the purposes of this presentation. DPIIP is defined as quantity of hydrocarbons that are estimated to be in place within a known accumulation. There is no certainty that it will be commercially viable to produce any portion of the resources. A recovery project cannot be defined for this volume of DPIIP at this time, and as such it cannot be further sub-categorized.