upper shaunavon - Surge Energy Inc.

Transcription

SUSTAINABLE CONVENTIONAL
RESOURCE COMPANY
TSX: SGY
APRIL, 2016
REASONS TO OWN SURGE
100% operated, high quality, low decline asset base
 High quality light/medium crude oil asset base; low decline < 20%
 NAV of $4.79 per share (proforma Sunset sale) using Sproule and
Associates new lower pricing(1)
 Return capital to shareholders through dividend and share
buyback option
•
$0.075/share annual dividend
 High netbacks; top tier capital efficiencies
 Experienced management team with proven track records
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
2
SURGE ENERGY
Well positioned for growth and sustainable dividends
 Total Proved plus Probable Reserves of 80.7 mmboe(1)
 2016(e) Exit Production Rate 13,000 boepd (76% oil)
 Low Decline of < 20% (RLI >17 years)
 Year End 2015 Net Debt: $117 proforma Q1/16 asset & facility sales
 Bank line: $400 million; only ~30% drawn
 Location Inventory: 764/744 (gross/net); 235/217 (gross/net) booked(2)
 100% operated in three core areas
3
PROACTIVE MANAGEMENT
Positioned for a “lower for longer” crude oil price scenario
 Created over $759MM in liquidity since oil prices began to fall in 2014
•
•
•
•
$512MM in accretive asset/facility sales
$117MM in dividend reductions (annualized)
$90MM in Capex reductions
$40MM in hedge crystallizations
 Reduced OPEX by 20% and gross G&A by 36% year over year
 Drilled four of the top producing oil wells in Canada at Valhalla
 Further de-risked the Upper Shaunavon play drilling top tier oil wells in
Saskatchewan, while decreasing drilling costs by 30% per well
 Successfully lowered costs and drilled two monobore Sparky wells at
Eyehill which averaged over 110boe/d IP90
4
2016 CAPITAL PROGRAM
Protecting NAV and balance sheet through conservative capital spending
OPERATIONAL
2016(e) Exit Production (boe/d)
13,000 (76% Oil/NGLs)
Capital Spending for 2016
~$55 million
•
•
•
•
•
Wells Planned in 2016
Est Base Decline
DCET
Waterflood
Facilities
Workover
Land, Capitalized G&A, other
$32.4 million
$1.5 million
$6.2 million
$7.2 million
$7.7 million
17 net wells
• 10 Shaunavon
• 3 Valhalla Doig
• 4 Sparky
<20%
FINANCIAL
Basic Shares Outstanding
221.1 million
Annual Dividend Payable
$16.6 million
($0.075 per share per annum)
5
$55MM CAPEX – 2016(E) EXIT PRODUCTION OF 13,000 BOE/D
Maintaining production with full cycle production efficiencies of $18,500
Capital Allocation
Area
# of Drills
Capital / Well
($MM / DCET)
Total Capital
($MM)
IP365
Production Adds
(boe/d)
IP365 PE
($/boepd)
Valhalla
3
$3.6
$10.8
1,200
$9,000
Shaunavon
10
$1.6
$16.0
1,150
$13,900
Sparky
4
$1.4
$5.6
320
$17,500
$1.5
150
$10,000
$13.4
150
NA
Waterflood
Maintenance /
Facility Work
Land, G&A,
Other
Total
Full Cycle PE
($/boepd)
$7.7
17
$55
2970
$18,500

$55 million capex with a 2016(e) exit production rate of 13,000 boe/d

Maintenance capital is minimized due to a confirmed lower corporate base decline of
<20% in 2016, top tier conventional assets, and industry leading PE’s / ROR’s
Surge’s low corporate decline of <20% is a direct reflection of Surge
having 11 of 16 reporting properties currently under waterflood, and
targeting development in large OOIP, conventional reservoirs.
6
ELITE ASSETS FOCUSED IN THREE CORE AREAS
Large OOIP pools in established conventional reservoirs
Surge 2016(e) Exit Production:
Total: >13,000 boe/d
(79% Oil & NGL’s)
(~57% on AB Crown)
Western Alberta Production:
Total: ~6,300 boe/d
(64% Oil & NGL’s)
SE AB Production:
Total: ~3,450 boe/d
(87% Oil & NGL’s)
Shaunavon Production:
Total: ~3,250 boe/d
(100% Oil & NGL’s)
7
CORE AREA DETAILS
>1.47 Billion bbl’s net OOIP with an additional ~187 Million net barrels of oil recoverable
Core Area
Formations
OOIP (MMbbls)
Drilling Locations
Gross/Net(2)
Gross/Net
(Booked)
Western Alberta
Doig/Slave Point/
Bluesky/ Banff/Doe
Creek /Wabamun
695/858
SE Alberta
Mannville Group
506/430
SW Saskatchewan
Shaunavon
469/459
TOTALS:
1,670/1,473
191/179
(95/85)
172/170
(56/55)
401/395
(84/77)
764/744
(235/217)
Internally Estimated Ultimate
Avg. CTD Oil Total Booked Independent
(1)
Recovery Net
Recovery
Factor
P+P
WI Recovery
(Waterflood with
(1)
Factor
Development Drilling)
(% OOIP)
84%
6.2%
10.4%
23%
85%
15.1%
19.1%
25%
98%
1.2%
3.8%
13%
88%
7.3%
10.9%
20%
~1.67B (~1.47B net) barrels of OOIP under management; RF~7.3%
8
TARGETING CONVENTIONAL RESERVOIRS
Large OOIP, high quality reservoirs tend to get larger over time

Conventional reservoirs tend to outperform over time:
•
•
•
•

Year over year recovery factor reserve additions
Long life, low decline production
Higher ultimate recoveries
Enhanced oil recovery by applying proven technology
Characteristics of conventional reservoirs:
•
•
•
•
•
High porosity - large oil storage; large OOIP
High permeability - better fluid flow as porosity is highly interconnected
Greater confidence in achieving recovery factors (vs unconventional/tight)
Lower risk drilling and enhanced recovery with application of technology
Higher probability of successful waterflood implementation increasing oil
recovery factors
9
CONVENTIONAL VS. UNCONVENTIONAL RESERVOIRS
Capital expenditures decrease,
while recovery factors and
rates of return increase, as
reservoir quality improves.
ROR
Ultimate Oil
Recovery
Surge targets reservoirs on the conventional end of the permeability spectrum
Unconventional
Reservoirs
Extremely
Tight
Very Tight
Tight
Low
Moderate
High
Valhalla Doig
Shaunavon
Montney
Resource
Duvernay
0.0001
Conventional Reservoirs
0.001
*Modified from US Department of Energy Study
Viking-Cardium
Halo
0.01
Sparky
0.1
Permeability (mD)
1
10
100
Average Surge Permeability
10
THREE CORE CONVENTIONAL RESERVOIRS
Applying proven technology to conventional reservoirs helps provide top tier performance and
higher recovery factors
U. Shaunavon
Valhalla Doig
Sparky
Depth
1450m
Depth
2000m
Depth
725m
Net Pay
4 - 10m
Net Pay
15 - 35m
Net Pay
8 - 12m
Porosity
12-18%
Porosity
6-10%
Porosity
18-29%
Permeability
Up to 500mD
Permeability
Up to 100mD
Permeability
Up to 500mD
Sw (%)
30-40%
Sw (%)
20%
Sw (%)
40-50%
°API
21-23°
°API
41°
°API
28°
OOIP/Sec
(Average)
4–9
MMBbls
OOIP/Sec
(Average)
7 – 14
MMBbls
OOIP/Sec
(Average)
8 – 16
MMBbls
Net OOIP
>250 MMbbls
Net OOIP
>140 MMbbls
Net OOIP
>350 MMbbls
Surge is focusing capital to three core conventional plays; all of which have
excellent reservoir characteristics which in turn lead to top tier PE’s, ROR’s
and higher recovery factors.
11
TOP TIER CAPITAL EFFICIENCIES AND REPLACEMENT METRICS
Large inventory with excellent economics using April 2016 strip pricing
Areas/Formations
Locations
Core Area
Gross / Net
(Booked)
Capital
Efficiency
Upper Shaunavon
214/212
$11,200/boepd
(62/59)
Valhalla (Doig)
Western
47/41
$6,500/boepd
Alberta
(30/25)
Sparky
136/135
$12,700/boepd
SE Alberta
(45/44)
SW Sask
Rates of
Return (1)
Drill/ Complete/
Equip
180 day IP
Mboe/well
(on primary)
38%
$1.6 MM
145 boepd (100% oil)
150
97%
$3.6 MM
550 boepd (68% oil)
420
28%
$1.4 MM
110 boepd (73% oil)
140
(April 2016 Strip Pricing)
*Numbers in the above table are based on Surge’s internally generated type curves and realized 2015 DCET capital reductions of ~20-30%.
12
QUALITY WATERFLOOD PROJECTS
Waterflood - increasing reserves & flattening declines
Current Properties Under Commercial Waterflood
Area
Formation
Start Date
2015 Decline
Current RF
Booked RF
Expected RF
Silver
Lloyd/ Cummings
1996
10%
12.6%
35.7%
39.0%
Wainwright
Sparky
1962
8%
32.0%
35.5%
37.1%
Macklin
Sparky
2005
8%
10.4%
37.2%
38.0%
Valhalla
Doe Creek
1994
6%
12.5%
16.1%
38.5%
Chip Lake
Rock Creek
2008
1%
7.2%
11.8%
15.0%
Westerose
Banff
2002
8%
6.1%
7.3%
10.0%
Nipisi
Slave Point
2013
8%
3.3%
8.8%
20%
Nevis
Wabamun
2010
15%
3.1%
5.4%
20%
Windfall
Bluesky
2012
10%
2.1%
4.5%
15%
Eyehill
Sparky
2014
18%
0.2%
3.0%
20%
Current Waterflood Pilots
Area
Formation
Start Date
# of
Injectors
Shaunavon
Upper
Shaunavon
Q3 2015
2
Analog
Property
Comments
Initiated flood in Q3 2015; 2 injectors implemented; numerous
Shaunavon successful analogues in the Upper Shaunavon trend; initial data
is showing positive response
Future Waterflood Pilots
Provost
Sparky
2016e
1-2
Wainwright
Q1/13 discovery; ~65 MM OOIP
13
SOUTHWEST SASKATCHEWAN - SHAUNAVON
>450MM barrels of net OOIP in the Upper and Lower Shaunavon combined
 >450 MMbbls of net OOIP in the Lower and
Upper Shaunavon formations (medium
gravity oil)
 Current combined recovery factor ~1.2%
 Rates of return in excess of 38%(1) for the
Upper Shaunavon
 401/395 (gross/net) drilling locations in the
Lower and Upper Shaunavon:
84/77 (gross/net) booked
 Operated facilities, including: pipeline
connected battery, waterflood infrastructure,
and a nearby rail transloading facility
 Fully unbooked waterflood upside from a
conventional sandstone reservoir, in a trend
with proven waterflood implementation
Surge Land
Surge Upper Shaunavon Wells
Surge Lower Shaunavon Wells
14
UPPER SHAUNAVON
Large contiguous undeveloped land position in the greater Upper Shaunavon trend
R19W3
T10
R21W3
Instow
Area/Pool
Well Count Depth
Cum Oil
Peak Rate Current Rate
Vt
Hz
(m)
(MMbbl)
(MMbbl)
(bbl/d)
(bbl/d)
Instow
118
2
1,370
152
71
9,420
2,600
Dollard
109
5
1,400
179
104
14,660
1,450
Eastbrook*
28
92
1,420
266
10
3,760
1,950
Rapdan
103
29
1,410
150
33
3,600
1,500
0
20
1,430
250
0.62
TBD
>1,500
SGY – Eastend*
T8
OOIP
Data from public sources

20 Upper Shaunavon horizontal wells drilled and
on production

Q3 2015 Waterflood Pilot; 2 horizontal injector
conversions completed in early Q3

Upper Shaunavon currently estimated to have
>250MMbbls net OOIP; >200 net locations on
Surge owned acreage
Dollard
T6
Eastend
T4
Eastbrook
SGY Lands
Rapdan
Upper Shaunavon Wells
Surge Upper Shaunavon Wells
15
UPPER SHAUNAVON ACTIVITY
>250MMbbl OOIP on Surge lands in the Upper Shaunavon
R20W3
R19W3
Upper Shaunavon A Sand
T7
R21W3
Upper Shaunavon B Sand
Upper Shaunavon C Sand
T6
Lower Shaunavon
T5
SGY Q3 Waterflood Pilot
36-005-20W3
SGY Q1 ‘15 U. Shvn Hz
191/13-18-005-19W3
On Prd March 2015
IP (90) = 219 BOPD
Progression of Upper Shaunavon Development
191/13-05-005-19W3
On Prd Aug 2015
IP(90) = 151 BOPD
SGY Lands
Upper Shaunavon Oil Fairway
T4
SGY Upper Shaunavon Drills
Q1 2016 Upper Shaunavon Wells
191/04-32-004-19W3
On Prd Aug 2015
IP(90) = 300 BOPD
Upper Shaunavon Producing Well
Upper Shaunavon Water Injector
16
UPPER SHAUNAVON PERFORMANCE
Surge horizontal results in the Upper Shaunavon outperforming area average
Upper Shaunavon Monthly Production vs Area Average
400
350
Rate (bopd), Cum Oil (mbbl)
300
250
200
150
Primary EUR
150Mbbl
100
50
0
0
12
Month
24
17
NORTHWEST ALBERTA
Large OOIP >695MMbbls in concentrated high quality light oil assets
 Large OOIP of >695 (585 net) MMbbls
of high quality light oil (32-40° API)
 Large development inventory of
191/179 (gross/net) locations:
Valhalla
OOIP: 228 mmbbl
(195 mmbbl net)
Nipisi
OOIP: 155 mmbbl
(150 mmbbl net)
 Successful waterfloods implemented at:
Windfall
OOIP: 40 mmbbl
(40 mmbbl net)
Westerose
OOIP: 84 mmbbl
(57 mmbbl net)
Nevis
OOIP: 160 mmbbl
(117 mmbbl net)
•
Valhalla: Doe Creek
•
Nipisi: Slave Point
•
Windfall: Bluesky
•
Nevis: Wabamun
•
Westerose: Banff
•
Chip Lake: Rock Creek
18
NORTHWEST ALBERTA - VALHALLA
Firm service agreements for Alliance and TCPL pipelines mitigates production restrictions
Valhalla Doig
Doe Creek Oil
Pool >60MMbbl
Valhalla
Sexsmith
04-08-075-7W6
Gas Plant
TCPL & Alliance
Connected
Surge 08-30-075-9W6
CNQ 01-29-075-9W6
Gas Plants
TCPL & Alliance
Connected

~140 MMbbls of net combined OOIP on Surge’s
Valhalla and Wembley Lands (40° API light oil)

Rates of return of 97% (1)

Current recovery factor ~3.2%

47/41 (gross/net) drilling locations at Valhalla and
Wembley: 30/25 (gross/net) booked

Continued delineation of large pool extension to
the North (Next well expected to Spud April 2016)

Potential future waterflood candidate
Facility Options
Conoco Wembley
06-19-073-8W6
Gas Plant
TCPL & Alliance
Connected
Doig Oil Pools
~130MMbbl’s

Surge anticipates minimal production interruptions
at Valhalla due to firm service agreements

Surge is currently producing Valhalla gas through
the 01-29 gas plant, Sexsmith, and Wembley gas
plants all of which are dual connected with access
to Alliance and TCPL

Construction of the pipeline connecting North
Valhalla to 01-29-075-9W6 and 08-30-075-9W6 is
complete, sales began mid December 2015

Compressor installation to reduce field line pressure
is complete with 10-12mmcf/d of sweet gas now
being sent North to the 01-29 facility
Surge Land
Surge Wells
Pipeline Options
Wembley
19
VALHALLA DOIG PERFORMANCE
2015 drilling in Valhalla yielded 3 of the top oil wells in Canada
North Valhalla Doig
02/15-06-075-8W6 Hz

Recent drilling results outperforming type curve and
exceeding expectations

Optimization of drilling and completion techniques
are improving results and lowering capex

200m infill spacing is optimal for proper exploitation
the 25+m thick Doig reservoir
03/05-07-075-8W6 Hz
Valhalla Doig - 2015/2016 Performance
350,000
03/05-07
04-06
300,000
02/15-06
00/03-06-075-8W6 Hz
(Q1 2016)
Cum (boe)
00/04-06-075-8W6 Hz
SGY Avg Normalized Cum
250,000
AVG PUD
03-06
200,000
150,000
100,000
50,000
Surge Land
Doig Penetrations
Surge Doig Locations
0
0
12
Months
24
20
SOUTHEAST ALBERTA - SPARKY
Provost / Eyehill / Wainwright area’s – Oil saturated Cretaceous sands
Wainwright
 >430 MMbbls of net OOIP (23-31° API oil)
 Current recovery factor of ~15%
 Eyehill Sparky waterflood implemented in Q4 2014
 Control of key infrastructure
 Rates of return in excess of 28% (1)
Silver
Macklin
 172/170 (gross/net) drilling locations:
Provost
Eye Hill
Surge Land
Surge Wells
21
POSITIONED FOR LONG TERM SUSTAINABILITY
 Low base decline <20%, high netbacks, excellent capital
efficiencies
 $0.075 annual dividend; NO DRIP! ; Share buyback in place
 Excellent balance sheet – one of the best in the peer group
22
HIGH QUALITY CRUDE OIL ASSET BASE
 Focused, high quality, crude oil asset and opportunity base;
3 core areas are 100% operated, with working interests of ~90%
 Large OOIP crude oil reservoirs – with low recovery factors;
>17 year RLI
 Over 700 net low risk development drilling locations provide >12
year drilling inventory
23
RISK MANAGEMENT / HEDGING STRATEGY
The Company has an orderly, on-going, risk management / hedging program designed to lock in future cash flows to protect the
Company’s capex program and fund dividends. Below is a list of Surge’s current hedging programs:
Natural Gas Hedges
Oil Hedges
Term
bbl/d
Currency
Floor
(per bbl)
Ceiling
(per bbl)
Swap Price
(per bbl)
WTI
2H 2016
2,000
CAD
$45.00
$64.77
-
WTI
2H 2016 1H 2017
1,000
CAD
$45.00
$70.18
-
WTI
1H 2017
1,500
CAD
$50.00
$70.00
-
WCS Swap
2016
2,500
USD
-
-
US$WTI less
$16.11
WCS Swap
2017
500
USD
-
-
US$WTI less
$22.00
MSW (EDM)
Swap
2016
2,000
USD
-
-
US$WTI less
$3.55
Type
Term
mcf/d
Currency
Swap Price
(per mcf)
Chicago Swap (1)
2016
10,000
CAD
$3.50
Jan 2017 –
Oct 2017
10,000
CAD
$3.65
NYMEX Swap
CAD/USD FX Hedges
Power Hedges
Term
Monthly Notional
Amount
Swap
Rate
Floor
Ceiling
Conditional
Ceiling (2)
Avg Rate
Variable
Collar
2016
USD$4,000,000
-
1.30625
1.3800
1.3273
Avg Rate
Forward
2017
USD$4,000,000
1.3229
-
-
-
Type
Type
Term
Volume
(MW/h)
Total Volume
(MWh’s)
Swap Price
(per MWh)
Swap
2016
4MW/h
35,136
$41.00
Swap
2017
2MW/h
17,520
$41.77
Type
24
2015 YEAR END RESERVES
~$1.1 Billion of Total Proved plus Probable Reserves Value (NPVBT10)
2015 Year End Reserves Proforma Sunset Asset Sale
Reserve Category
Oil& NGLs
(Mbbl)
Gas
(MMcf)
Total
(Mboe)
NPVBT10 ($MM) (1)
Proved Producing
21,413
33,642
27,020
$442
Proved Non-Producing
1,114
3,288
1,662
$25
Proved Undeveloped
14,723
34,645
20,497
$198
Total Proved (1P)
37,205
71,573
49,178
$665
Probable
25,271
37,834
31,578
$406
Total Proved + Probable (2P)
62,522
109,408
80,756
$1,071
*Numbers in the above table may not add exactly due to rounding
25
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
Clarus Securities Inc.
Josie Ho
jho@clarussecurities.com
Cormark Securities Inc.
Garett Ursu
gursu@cormark.com
Dundee Securities Corporation
Chad Ellison
cellison@dundeesecurities.com
FirstEnergy Capital Corp.
Cody R. Kwong
crkwong@firstenergy.com
GMP Securities L.P.
Grant Daunheimer
gdaunheimer@gmpsecurities.com
Mackie Research Capital Corp.
David Ricciardi
dricciardi@mackieresearch.com
Macquarie Securities Group
Brian Bagnell
brian.bagnell@macquarie.com
National Bank Financial
Dan Payne
dan.payne@nbc.ca
Paradigm Capital
Ken Lin
klin@paradigmcap.com
Peters & Co. Limited
Dale Lewko
dlewko@petersco.com
RBC Capital Markets
Shailender Randhawa
shailender.randhawa@rbccm.com
Schachter Asset Management Inc.
Josef I. Schachter
josef@e-sami.com
Scotia Capital Inc.
Cameron Bean
cameron.bean@scotiacapital.com
TD Securities
Juan Jarrah
Juan.Jarrah@tdsecurities.com
26
CORPORATE PARTNERS
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
Auditor:
KPMG LLP
Legal Counsel:
McCarthy Tétrault
Evaluation Engineers:
Sproule Associates Ltd.
Registrar & Transfer Agent:
Computershare Canada
Investor Contacts:
Paul Colborne, President & CEO
Paul Ferguson, CFO
2100, 635 – 8th Ave. SW, Calgary Alberta T2P 3M3
T: 403.930.1010 F: 403.930.1011
www.surgeenergy.ca
27
FORWARD-LOOKING STATEMENTS
FORWARD-LOOKING STATEMENTS
This presentation contains forward-looking statements. More particularly, this presentation contains statements concerning anticipated: business strategies, plans and objectives;
potential development opportunities and drilling locations, expectations and assumptions concerning the success of future drilling and development activities, the performance of
existing wells, the performance of new wells, decline rates, recovery factors, the successful application of technology and the geological characteristics of our properties; cash
flow; timing and amount of future dividend payments; oil & natural gas production growth and mix; reserves; debt and bank facilities; amounts and timing of capital expenditures;
hedging results; primary and secondary recovery potentials and implementation thereof; and drilling, completion and operating costs.
Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the
reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less
than the estimates provided in this presentation.
Cash dividends on our common shares are paid at the discretion of our Board of Directors and can fluctuate. In establishing the level of cash dividends, the Board of Directors
considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and
capital expenditures and our prevailing financial circumstances at the time.
The forward-looking statements are based on certain key expectations and assumptions made by Surge, including expectations and assumptions concerning the performance of
existing wells and success obtained in drilling new wells, anticipated expenses, cash flow and capital expenditures and the application of regulatory and royalty regimes. 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 forwardlooking 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 uncertainties resulting from potential delays or changes in
plans with respect to exploration or development projects or capital expenditures. Certain of these risks are set out in more detail in Surge’s Annual Information Form which has
been filed on SEDAR and can be accessed at www.sedar.com.
Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of
such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to
differ materially from those contained in any forward-looking statements. The above summary of assumptions and risks related to forward-looking statements in this presentation
has been provided in order to provide potential investors with a more complete perspective of our current and future operations and as such information may be not appropriate
for other purposes. 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.
28
ENDNOTES
Slide 2:
(1) Based on Sproule's December 31, 2015 Price Forecast
Slides 3 & 8:
(1) December 31, 2015 reserves.
(2) This presentation discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations.
Proved locations and probable locations, which are sometimes collectively referred to as “booked locations”, are derived from the Company’s
most recent independent reserves evaluation as of December 31, 2015 and account for drilling locations that have associated proved or
probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s prospective acreage and an
assumption 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. Of the 744 net drilling locations identified herein, 145 net are proved locations, 72 net are
probable locations and 527 are unbooked locations. Unbooked locations have specifically been identified by management as an estimation of
our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves data on
prospective acreage and geologic formations. The drilling locations on which we actually drill wells will ultimately depend upon the availability
of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.
Slides 12, 14,
19, 21:
Apr 11, 2016 strip price forecast (2016 WTI: US$39.72/bbl; Henry Hub: US$2.19/mmbtu); a 1.5% per year inflation rate was applied from end
of strip forecast (2024) to 2064. An inflating CAD/USD exchange rate of $0.77 (to $0.90 by 2061) was assumed.
Slide 24:
(1) Surge entered into a Chicago-priced swap as the Company’s firm transport contracts settle against the Chicago index.
(2) If the USD/CAD average monthly rate settles above the ceiling rate, the settlement amount is based on the conditional ceiling.
Slide 25:
(1) Based on Sproule's December 31, 2015 Price Forecast
29
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.
30
NON-GAAP MEASURES
NON-GAAP MEASURES
This presentation includes non-GAAP measures as further described herein. These non-GAAP measures do not have a standardized meaning
prescribed by International Financial Reporting Standards (“IFRS or, alternatively, “GAAP”) and, therefore, may not be comparable with the
calculation of similar measures for other entities.
“Basic payout ratio” is calculated as cash dividends declared divided by funds from operations.
“Cash dividends per share” represents cash dividends declared per share by Surge.
“Funds from operations” represents cash flow from operating activities adjusted for changes in non-cash working capital, decommissioning
expenditures, cash settled stock-based compensation and transaction costs. Management believes that funds from operations is a useful
supplemental measure that provides an indication of the results generated by the Company's principal business activities before the
consideration of how those activities are financed or how the results are taxed.
“Netbacks” is used by the Company to help evaluate its performance as well as to evaluate acquisitions. The Company considers netbacks as a
key measure as it demonstrates its profitability relative to current commodity prices. “Operating netbacks” are calculated by taking total
revenues (excluding derivative gains and losses) and subtracting royalties, operating expenses and transportations costs on a per boe basis.
“Net debt” is calculated as outstanding bank debt plus or minus working capital, however, excluding the fair value of financial contracts and
other current obligations. Net debt is used by management to analyze the financial position and leverage of Surge.
“Total Payout Ratio” is calculated as development capital plus cash dividends declared divided by funds from operations.
31

upper shaunavon - Surge Energy Inc.

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