sgy corp pres - august final - v2 · 7$5(7,1 &219(17,21$/ 2,/ 5(6(592,56 6xujh irfxvhv rq...

$: SGY Corp Pres - August FINAL - V2 · 7$5*(7,1* &219(17,21$/ 2,/ 5(6(592,56 6xujh irfxvhv rq kljk txdolw\ uhvhuyrluv dw wkh frqyhqwlrqdo hqg ri wkh shuphdelolw\ vshfwuxp 6rxufh 0rglilhg$
A COMPELLING VALUE

PROPOSITION

TSX: SGY

AUGUST, 2020

FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES2

REASONS TO OWN SURGE – TSX: SGYValue based with a strong focus on conventional reservoirs

Focus on high quality conventional, large OOIP(1), light/medium gravity crude oil reservoirs; A dominant position in the medium/light oil Sparky fairway – a premier conventional Canadian oil

play.

Maintains a stable production base with 86% oil & NGL’s and a low corporate decline rate of <19%;

Drilling inventory of over 800 net locations (>13 years of drilling)(2); and

Proved Developed Producing Sproule Net Asset Value(4) of $1.08 per basic share.

(1) See Reserves in the Oil and Gas Advisories section at the back of this presentation.

(2) See Drilling Locations in the Oil and Gas Advisories section at the back of this presentation.

(3) See the Additional Metrics section of the Oil and Gas Advisories at the back of this presentation.

(4) Net Asset Value calculation is detailed on slide 21 – Net Asset Value.

In response to the current volatility in global crude oil markets (i.e. COVID-19 &Saudi / Russia price war), Surge management and Board have suspended itspreviously announced 2020 guidance and capital program of $98.5 million.Furthermore, the Company has elected to suspend its dividend until such timeas there is a sustainable recovery in world crude oil pricing.


1H/2020 HIGHLIGHTSDisciplined, proactive, business strategy amid turbulent markets

In 1H/2020 Surge Management acted decisively to preserve stakeholder’s capital by:

Being the first public oil company in Canada to suspend its dividend;

Cutting capital expenditures quickly in Q1/20;

Being the first public oil company in Canada to shut-in meaningful loweroperating netback production (approximately 21 percent); and

Focusing on rigorous cost cutting measures.

Pursuant to the Company’s ongoing strategic hedging program, Surge realizedover $15 million in hedging gains in the second quarter of 2020, and $29 million inhedging gains during the first half of 2020;

Surge was able to reduce net debt in both Q2/2020 and 1H/2020, and now forecastsnet debt to drop meaningfully throughout 2H/2020 at current strip prices; and

Surge expects virtually all curtailed volumes to be back on by the end of August,2020 as oil prices having now rebounded >250% since the April low of US$11.57 WTIper bbl.


SIGNIFICANT HEDGE POSITION(1)

Robust 2020 hedging program provides balance sheet protection

Strategic hedging program yielded realized gains of over C$29 million during 1H 2020.

Edmonton Light and WCS oil differentials protected with differential hedging strategy and operational flexibility.

Attractive natural gas pricing hedged in 2020 through a combination of swaps and collars.

Note: All USD-denominated WTI hedges have been converted to CAD at a rate of $0.7407.

4

WTI OIL HEDGES

Qtr. 1 2020 Qtr. 2 2020 Qtr. 3 2020 Qtr. 4 2020

Avg. bbls/d Hedged 7,250 6,835 6,753 6,000

Avg. Floor Price $76.56 $69.07 $66.12 $53.79

(1) For further details on hedging please see the “Hedging Section” in the Appendix of this presentation.


OPERATIONS FOCUSED IN 4 CORE AREASLarge OOIP pools in established conventional reservoir trends

Valhalla:65% Oil & NGL’s

Sparky:93% Oil & NGL’s

Shaunavon:100% Oil & NGL’s

Average 86% Oil & NGL’s

Greater Sawn:93% Oil & NGL’s

Minors:50% Oil & NGL’s

FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES

NET OOIP OF >2.5 BILLION BARRELSLarge 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)

Sparky CoreSparky Formation +

Mannville Group>1,000

~500

(185)92% 8.2% 11.8%

Valhalla Doig / Montney >200>45

(35)82% 4.9% 10.2%

Greater Sawn Slave Point >700>150

(84)90% 5.0% 8.6%

ShaunavonShaunavon

(Upper & Lower)>400

>125

(92)100% 1.9% 4.7%

TOTALS(3)

: >2,500>800

(419)91% 5.8% 9.1%

6

>2.5 Billion barrels of net internally estimated OOIP under ownership; Current net recovery factor ~5.8%.

(1) See the Drilling Locations in the Oil & Gas Advisories section at the back of the presentation.

(2) CTD means cumulative oil produced to date and is effective to December 31, 2019.

(3) Totals do not sum as minor properties have been included in the totals but have not been subcategorized in the table.

>325 locations have >20% IRR at $40 WTI (> 4 years of drilling)(1)

7

TARGETING CONVENTIONAL OIL RESERVOIRSSurge focuses on high quality 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

DuvernayMontney Resource

Viking-Cardium Halo

Valhalla Doig

Shaunavon

Sparky

Ult

ima

te O

il

Re

co

very PIR

&IRR

Recovery factors, internal rates of return (IRR), decline rate, and profit to investment ratio

(PIR)(1) improves as reservoir quality improves.

Average Surge Permeability

Slave Point


High Risk High Decline

Low Risk Low DeclineCAPITAL / BUSINESS / OPERATIONAL RISK

PermianBakken


SPARKY – A DOMINANT POSITIONLow PE’s, year-round accessibility = a premier Canadian medium/light oil growth play

8

Medium / Light Gravity Oil Window

>20° API

Sparky Formation Facts(1)

First Production May 1922

Original Oil in Place > 11 Bbbls

Cum Production > 1 Bbbls

Recovery Factor <10%

Producing Wells > 20,000Hz Wells / Multi-Stage Hz /

Surge Multi-Stage Hz >650 / >200 / >138

The Sparky is a large, well established, prolific oil producing formation in Western Canada.

Surge holds a dominant land position in the medium / light gravity oil window, and is applying modern horizontal multi-stage fracturing technology.

Key Sparky Value Drivers:• Shallow depth (700-900m).

• Low cost drilling (D,C&E at $1.2MM per well).

• Surge continues to improve costs and efficiencies with the implementation of pad drilling.

• Low geological risk due to 3D seismic and thousands of vertical penetrations.

• Focus on lighter oil gravity (23-31° API) = higher operating netbacks.

• Proven waterflood potential (Wainwright pool at >35% recovery factor(1)).

AB SK

(1) Data sourced from Canadian Discovery and GeoScout


2019-2020 SPARKY DRILLING RESULTSProduction results continue to outperform internal type curve expectations

43 horizontal Sparky wells drilled and on production in 2019/2020:• 24 wells brought on production in 2019

• 19 wells brough on production in Q1/20

• Normalized average production is well above Surge’s internal type curve

Surge is realizing top tier capital efficiencies of <$10,000 perboepd employing pad drilling (i.e. IP90(1) of 115 boepd with DCETcosts down to $1.05 million per well as compared to a budgeted$1.25MM per well).

Wainwright

Betty Lake

Sounding Lake Eyehill

Macklin

ProvostLakeview

>1.0 Bbbls Net OOIP

~500 Drilling Locations (>10 year inventory, 90% Oil)

>9,000 boepd currently

Silver

Eyehill SouthSounding Lk. East

Surge Operated Wells

2019/2020 Sparky Drills9



Net OOIP (MMbbl)

# of producing Hz's

# of Hz WtrInjectors

Production (boepd)

% OilCF/Yr @

US$60 WTI

TPPReserves

(Mboe)

TPPNPV10 ($MM)

YE 2015 70 15 1 500 80% $7.0 4,089 $49YE 2019 200 59 9 2,500 83% $33.7 15,029 $231

4 Yr Change +130 +44 +8 +2,000 +3% $26.7 +10,940 $182+186% +293% +400% +381% +268% +371%

10

EYEHILL – A CASE STUDYIncreased production and cashflow by +380% in 4 years

• Surge had only 15 horizontal wells producing 500 boepd (80% oil) at year end 2015.

• Surge has drilled an average of 14 wells per year (12 per year excluding acquisitions), increasing production by 400% – inclusive of lost production associated with water injector conversions.

• To date 9 of the 72 wells drilled have been converted to water injection, providing pressure support and lowering the pool decline (i.e. Divco model).

YE 2015

• Of the 72 operated horizontal wells at Eyehill, Surge drilled 60 and acquired 12.

• Peak production of 2,950 boepd was reached in May 2017.

Maintain Flat Production as per Divco Model

R3W4

Source: GeoScout

Surge Eyehill:

>200MMbbls net OOIP >65 net locations remain

(45 net booked)

11

GREATER SAWN - CONCENTRATED LIGHT OIL>600MMbbls net OOIP in concentrated Slave Point reservoirs

OOIP of >700 MMbbls net of light oil (35-42° API).

Development inventory of 150 net locations (84 net booked).

Key Slave Point Attributes:• 6% recovery to date.

• 18% base decline; waterflooded.

• Production derived primarily from large multi-cycle reef complexes (pay(1) thickness of up to 18 meters).

Active Slave Point Waterfloods:• Sawn

• Red Earth

• Evi/Otter

• Nipisi

Nipisi & Nipisi SouthOOIP: ~100 MMbbl net

SawnOOIP: >200 MMbbl net

Red EarthOOIP: >250 MMbbl net

Evi / OtterOOIP: >150 MMbbl net

(1) ) See the Additional Metrics section of the Oil and Gas Advisories at the back of this presentation.


VALHALLA – STACKED MULTI-ZONE POTENTIALMultiple large OOIP light oil reservoirs provide a sustainable drilling inventory and production base

>200MMbbls of net combined OOIP.

Doig wells continue to be among the most prolific oil producers in Western Canada.

Recently drilled a horizontal well into the Company’s large OOIP Montney (turbidite) light oil pool, with initial production rates exceeding 1,400 bopd.

Drilling inventory includes >45 net locations in multiple horizons (35 net booked).

Light oil gravity (~40° API) and extensive infrastructure in the area = attractive operating netbacks.

FormationDepth

(m)Net OOIP (MMbbl)

Capital ($MM/well)

IP180(boe/d)

IP 180 Prod Eff($/boepd)

Doig 2050 >150 $4.0 450 $8,900

Montney 2200 >40 $4.0 370 $10,800

12

Doig

Montney


SHAUNAVON>400 MMbbl net OOIP on Surge lands in the Upper and Lower Shaunavon formations

Shaunavon produces 100% high operating netbacks, low decline oil.

Upper Shaunavon net OOIP is estimated to be >200MMbbl.

• >65 net locations – (35 net booked).

• 10 horizontal wells converted to water injection.

• Current recovery in the Upper Shaunavon is ~1%.

Lower Shaunavon net OOIP is estimated to be >200MMbbl.

• >70 net locations – (57 net booked).

• Surge recently drilled and completed 6 Lower Shaunavon wells using cemented liner, plug and perf methodology with 100% success rate.

• Current recovery in the Lower Shaunavon is ~3%.

13


CORPORATE SUSTAINABILITYSurge is taking a proactive approach to Environmental, Social, and Governance initiatives

Surge is committed to diversity in the workplace and on its Board of Directors. Surge increased the gender

diversity on the Board of Directors to 33% from 22% in 2019.

Surge’s Board independence increased to 78% from 71% in 2019.

The average age of Surge Board members is currently 59 years.

GovernanceSocial

Surge employs a pro-active safety culture and is proud to be over 4 years without a lost-time incident.

Surge is proud to be a Gold Level sponsor of the La Glace regional recreation centre –providing a new community centre and ice rink to the town of La Glace, Alberta.

Environmental

Surge abandoned 149 wells in 2019 which is over 4X the number of wells Surge drilled.

Surge has joined the Alberta Energy Regulators Area Based Closure Program, allowing Surge to focus on abandoning and reclaiming entire areas versus single wells, greatly increasing the capital efficiencies of these projects.


APPENDIX

15


OIL HEDGING

(1) All USD-denominated WTI hedges have been converted to CAD at a rate of $0.7407 USD/CAD in the above table and graph.(2) WTI 3-way hedges consist of a sold put, a bought put and a sold call. Using Q1 2021 as an example ($44/$52/$60), Surge

receives WTI+$8/bbl when WTI is at or below $44/bbl; Surge receives $52/bbl when WTI is between $44/bbl and $52/bbl; Surge receives WTI when WTI is between $52/bbl and $60/bbl; and Surge receives $60/bbl when WTI is above $60/bbl.

16

Qtr. 2 2020 Qtr. 3 2020 Qtr. 4 2020 Qtr.1 2021 Qtr. 2 2021 Qtr. 3 2021

Avg. bbls./d Hedged 6,835 6,753 6,000 3,500 1500 250

Avg. Floor Price(1)(2) $ 69.07 $ 66.12 $ 53.79 $ 50.20 $ 47.08 $ 58.05


RISK MANAGEMENT / HEDGING STRATEGYThe Company has an on-going, risk management / hedging program. Below is a list of Surge’s current WTI hedges:

17

WTI Hedges – 3 Ways

WTI Hedges - Collars

Quarter Volume Bought Put (USD) Sold Call (USD) Sold Put (USD)

Qtr. 2 2020 0 $ - $ - $ -

Qtr. 3 2020 4,500 $ 54.83 $ 64.92 $ 46.61

Qtr. 4 2020 4,000 $ 43.06 $ 49.58 $ 33.81

Qtr. 1 2021 2,000 $ 40.75 $ 47.90 $ 31.75

Qtr. 2 2021 500 $ 39.00 $ 51.00 $ 31.00

Qtr. 3 2021 250 $ 43.00 $ 51.00 $ 35.00

Quarter Volume Bought Put (USD) Sold Call (USD)

Qtr. 2 2020 4,000 $ 55.41 $ 65.34

WTI Hedges - SwapsQuarter Volume Swap (USD)

Qtr. 2 2020 2,835 $ 45.18

Qtr. 3 2020 2,253 $ 37.27

Qtr. 4 2020 2,000 $ 33.42

Qtr. 1 2021 2,000 $ 33.62

Qtr. 2 2021 1,000 $ 32.81


RISK MANAGEMENT / HEDGING STRATEGY

Natural Gas Hedges

18

WCS Oil Differential Hedges

The Company has an on-going, risk management / hedging program. Below is a list of Surge’s current WTI hedges:

Date Total Swap Collar Swaps Ceiling Floor

Qtr. 3 2020 5,500 3,000 2,500 - $ 16.78 - $ 15.14 - $ 19.98

Qtr. 4 2020 4,000 1,500 2,500 - $ 16.35 - $ 15.14 - $ 19.98

Qtr. 1 2021 1,500 1,500 - - $ 14.75 - -

Qtr. 2 2021 1500 1,500 - - $ 14.75 - -

Qtr. 3 2021 500 500 - - $ 15.40 - $ 15.40 -

Qtr. 4 2021 500 500 - -$ 15.40 - $ 15.40 -

Type Currency Type Term Volume Floor Ceiling

AECO CAD Swap Nov 19 – Dec 20 3,000 GJ/D $1.98 -

AECO CAD Swap Jan 20 – Dec 20 4,000 GJ/D $1.45 -

AECO CAD Swap Nov 20 – Mar 21 2,000 GJ/D $2.31 -

AECO CAD Swap Jan 20 – Dec 20 2,000 GJ/D $2.12 -

Chicago USD Swap Apr 20 – Oct 20 3,000 MMBTU/D $2.05 -

Chicago USD Collar Nov 19 – Oct 20 3,000 MMBTU/D $2.25 $2.90

Chicago USD Swap Nov 20 – Oct 21 3,000 MMBTU/D $2.52 -

Chicago USD Collar Nov 20 - Oct 21 3,000 MMBTU/D $2.15 $2.90

Date Total Swap Collar Swaps Ceiling Floor

Qtr. 3 2020 3,500 3,500 - - $ 4.94 - -

Qtr. 4 2020 - - - - - -

Qtr. 1 2021 500 500 - - $ 5.80 - -

Qtr. 2 2021 500 500 - - $ 5.80 - -

MSW Oil Differential Hedges


INTEREST RATE AND FX HEDGING

19

INTEREST RATE HEDGE

Type TermNotional Amount

(CAN$)Surge

ReceivesSurge Pays

Fixed Rate Surge Pays

Fixed-to-Floating Rate Swap

Feb 2018 to Feb 2023

$100,000,000Floating

RateFixed Rate

Semi-Annual Step Up• Beginning at

1.786% • Ending at 2.714%• Averaging 2.479%

Fixed-to-Floating Rate Swap

July 2019 – June 2024

$50,000,000Floating

RateFixed Rate 1.785%

(1) Based on projected borrowing spread as of June 30, 2020

FOREIGN EXCHANGE RATE HEDGE

Type TermNotional Amount

(USD)Rate

FX average Rate Fund Q2 2020 – Q4 2020 $1,000,000 per month Swap at $1.3245


2019 Year End Reserves(1)(2)

Reserve CategoryOil & NGLs

(Mbbl)(3)Gas

(MMcf)(4)Total

(Mboe)NPVBT10 ($MM)(5)

Proved Producing 34,505 31,104 39,689 $603

Proved Non-Producing 253 217 289 $4

Proved Undeveloped 31,589 35,146 37,446 $416

Total Proved (1P) 66,346 66,467 77,424 $1,023

Probable 34,082 32,006 39,417 $621

Total Proved + Probable (2P) 100,428 98,474 116,841 $1,644

20

2019 YEAR END RESERVES

Increased Total Proved reserves per debt adjusted share by 4% in 2019;

Added 21.6 MMboe of Total Proved + Probable reserves over the last three years, replacing 109% of production; and

Maintained a 2P reserve life index of 15 years.

>$1.6 Billion of Total Proved plus Probable Reserves Value (NPVBT10)

20

(1) See the Reserves section of the Oil and Gas Advisories at the back of this presentation. (2) Amounts may not add due to rounding.(3) Includes light, medium, heavy and natural gas liquids.(4) Includes conventional natural gas, solution gas and coal bed methane.(5) Total ADR (Abandonment, Decommissioning, Reclamation) is included in the reserves report, as it is best practice stated in the COGE Handbook.

2019 Reserves (MMboe) 2019 Reserves Value(NPVBT10 $MM)


NET ASSET VALUEHigh quality conventional reservoirs continue to deliver value to shareholders

21

2019 NAV per Share(1)

PDP TP TPP

Reserve Value NPV10 BT ($MM) $603 $1,023 $1,644

Undeveloped Land and Seismic ($MM)(2) $131 $131 $131

Net Debt ($MM)(3) $(382) $(382) $(382)

Total Net Assets ($MM) $352 $772 $1,393

Basic Shares Outstanding (MM) 326 326 326

Estimated NAV per Basic Share ($/share) $1.08/ sh. $2.37/ sh. $4.27/ sh.

(1) 2019 NAV per share are as of December 31, 2019.(2) Internally estimated and includes $95 million for non-reserve assigned lands and $36 million for seismic(3) See the Net Debt section of the Non-GAAP Financial Measures section at the back of this presentation.

22

ANALYST COVERAGEFinancial Institution Analyst Email Address

Acumen Capital Partners Trevor Reynolds [email protected]

BMO Capital Markets Ray Kwan [email protected]

Canaccord Genuity Anthony Petrucci [email protected]

CIBC Dave Popowich [email protected]

Clarus Securities Inc. Robert Pare [email protected]

Cormark Securities Inc. Garett Ursu [email protected]

Eight Capital Adam Gill [email protected]

GMP FirstEnergy Robert Fitzmartyn [email protected]

Industrial Alliance Securities Michael Charlton [email protected]

Laurentian Bank Securities Todd Kepler [email protected]

National Bank Financial Dan Payne [email protected]

Peters & Co. Limited Cindy Mah [email protected]

Raymond James Jeremy McCrea [email protected]

Schachter Asset Management Josef I. Schachter [email protected]

Scotia Capital Inc. Cameron Bean [email protected]

TD Securities Juan Jarrah [email protected]


2100, 635 – 8th Ave. SW, Calgary Alberta T2P 3M3T: 403.930.1010 F: 403.930.1011

www.surgeenergy.ca

Advisors

Bankers Syndicate:

National Bank of CanadaBank of Nova ScotiaBank of Montreal ATB FinancialCanadian Imperial Bank of CommerceToronto-Dominion BankHSBC Bank CanadaBDC CapitalGoldman Sachs

Auditor: KPMG LLP

Legal Counsel: McCarthy Tétrault

Evaluation Engineers: Sproule

Registrar & Transfer Agent: Computershare Canada

Investor Contacts:Paul Colborne, President & CEOJared Ducs, CFO

CORPORATE PARTNERS

23


FORWARD-LOOKING STATEMENTSFORWARD-LOOKING STATEMENTS

More particularly, this presentation contains statements concerning: the ability of management to protect stakeholder's capital; projected decrease in the Company's net debt in 2H/20; potential worldwide decline in oil production; 2020 forward strip oil prices; management's expectations and plans with respect to the development of its assets and the timing thereof; Surge's assets and performance, the characteristics thereof, and the potential for shareholders to benefit from such assets; drilling inventory of Surge; possession by Surge of certain key operational indicia of highly successful oil companies; Surge's operational and financial flexibility for the balance of 2020; the ability of Surge to maximize corporate cash flows; Surge's declared focus and primary goals; the impacts of COVID-19 on our business and measures taken in response thereto; the societal, economic and governmental response to COVID-19; the continued participation and exploration by Surge in all applicable Government assistance programs relating to COVID-19, and additional funding expected to be received by Surge as a result of such programs; Surge's continued commitment to ESG initiatives; Surge's capital expenditure program and its flexibility to make adjustments thereto; Surge's current and potential production curtailments and its ability to restart such production; Surge's cost reduction efforts and the anticipated results and benefits therefrom; commodity prices and management's ability to react to changes thereto; Surge's risk management program; Surge's hedging program and the characteristics thereof; the ability of Surge to continue to execute attractive hedges for 2020/2021; the select working-over of wells by Surge; and the suspension of Surge’s dividend and the timing for reimplementation.

The forward-looking statements are based on certain key expectations and assumptions made by Surge, including expectations and assumptions 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 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 condition of the global economy, including trade, public health (including the impact of COVID-19) and other geopolitical risks; 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; and failure to obtain the continued support of the lenders under Surge's bank line as a result of fluctuating commodity prices and reserve determinations by the lenders or otherwise.

Certain of these risks are set out in more detail in Surge's AIF dated March 9, 2020 and in Surge's MD&A for the period ended June 30, 2020, 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.


OIL AND GAS ADVISORIESThe term “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 cubicfeet 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. Given that the value ratio based onthe 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. Boe/dand boepd means barrel of oil equivalent per day. Bbl means barrel of oil. NGLs means natural gas liquids.

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) MMboemeans million barrels of oil equivalent and (xii) boe/d means barrels of oil equivalent per day.

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 andaccount for associated proved and/or probable reserves, as applicable. Reserves referenced in this presentation reflect the bookings that existed as of December 31, 2019 and do not account for Surge’sAcquisitions and Divestiture activity to date.

For the purpose of this presentation, Original Oil in Place (“OOIP”) means Discovered Petroleum Initially In Place (“DPIIP”) as at December 31st, 2019. DPIIP is derived by Surge’s internal Qualified ReserveEvaluators (“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 petroleumthat 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 December 31st, 2019 and are based on current recovery technologies and have been prepared by Surge’s internal QRE. There issignificant 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 thisvolume of OOIP/DPIIP at this time.

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 forindividual 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.

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 partyexternal evaluation done by Sproule using standard practices as prescribed in the COGEH and account for drilling locations that have associated proved and/or probable reserves, as applicable.

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. Unbookedlocations do not have attributed reserves or resources. Unbooked locations have been identified by Surge’s internal QREs as an estimation of our multi-year drilling activities based on evaluation ofapplicable 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 suchlocations 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, regulatoryapprovals, 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 havebeen 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 managementhas 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 willresult in additional oil and gas reserves, resources or production.

Assuming a Jan 1, 2020 reference date, the company will have over >800 gross (>800 net) drilling locations identified herein, of these >400 gross (>400 net) are unbooked locations. Of the 418 net booked locations identified herein 325 net are Proved locations and 94 net are Probable locations based on Sproule’s 2019YE reserves.

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 August 31, 2019, and a reference date of Jan 1, 2020. 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. 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 QRE’s. Over 95% of the locations used in the economic inventory slide were represented by type curves developed by Surge’s QRE’s, the remaining locations were represented using Sproule’s 2018YE type curves. All type curves fully comply with Part 5.8 of the Companion Policy 51 – 101CP. Type Curve economics were run at US$50/bbl, US$60/bbl, US$70/bbl and US$80/bbl WTI, with differential assumptions of US$16/bbl WCS and US$5/bbl EDMN, and a 0.75 USD/CAD FX.

Following the collapse of oil prices, Surge has subsequently tested their economic inventory at $40 WTI, and estimate over 250 locations still have an IRR > 20%.


NON-GAAP FINANCIAL MEASURESCertain secondary financial measures in this presentation – namely, "net debt", and “operating netback“ are not prescribed by GAAP. These non-GAAP financialmeasures are 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. None of these measures are used to enhance theCompany's reported financial performance or position. The non-GAAP measures do not have a standardized meaning prescribed by IFRS and therefore are unlikely tobe comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and application. Allsecondary measures in this document are defined below:

Operating Netback

In this presentation, “operating netback” is calculated by deducting royalties paid and production costs, including transportation costs, from prices received, excluding the effects of hedging. Management believes that in addition to net income, operating netbacks are a useful supplemental measure as it assists in the determination of the Company’s operating performance. Readers should be cautioned, however, that this measure should not be construed as an alternative to both net income and net cash from (used in) operating activities, which are determined in accordance with IFRS, as indicators of the Company’s performance.

Net Debt

There is no comparable measure in accordance with IFRS for net debt. Net debt is calculated as bank debt plus the liability component of the convertible debentures plus or minus working capital, however, excluding the fair value of financial contracts, decommissioning obligations and lease and other obligations. This metric is used by management to analyze the level of debt in the Company including the impact of working capital, which varies with timing of settlement of these balances.


ADDITIONAL METRICSAdditional 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:

• Net Present Value (NPV) is the present value of cash inflows less present value of cash outflows. NPV10 assumes a discount rate of 10%.

• Free cash flow from operating activities yield is calculated by taking cash flow from operating activities and subtracting exploration and development capital, dividends, and payments on lease obligations divided by common shares outstanding.

• Production Replacement is calculated as the total organic reserves additions (i.e., excluding acquisitions and dispositions) divided by annual production (also excluding acquisitions and dispositions).

• Capital efficiencies is calculated as total exploration and development expenditures during the period, divided by an initial production rate for a specified number of days (i.e., $98.5 MM / (21,000 BOEPD multiplied by 23% corporate decline). Management uses Capital efficiency to understand the amount of development and exploration capital expenditures are required to add an additional boe of production per day.

• Internal rate of return (IRR) is the discount rate that makes the NPV of all cash flows from a given project equal to zero.

• Profit to investment ratio (PIR) is calculated as the NPV from a project divided by the capital investment ascribed to that project.

• Recovery factor 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 QRE. 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.

• References to initial production (IP) rates found in this presentation are useful for determining the presence of hydrocarbons. There is no assurance as to the length of time that wells will produce at such rates, and consideration must be given to natural declines thereafter. As such, readers are cautioned when using these production rates to aggregate Surge’s production.

sgy corp pres - august final - v2 · 7$5*(7,1* &219(17,21$/ 2,/ 5(6(592,56 6xujh irfxvhv rq...

Documents

sgy corp pres - august final - v2 · 7$5(7,1 &219(17,21$/ 2,/ 5(6(592,56 6xujh irfxvhv rq...