surge_corp_pres_-_feb_2015_final_for_website

Report
POSITIONED FOR LONG
TERM SUSTAINABILITY
TSX: SGY
FEBRUARY, 2015
RECENT DEVELOPMENTS
Strong 2014 Reserves, Record Production Levels and Debt Reduction
 2014 Year End Reserve Highlights
•
New NAV of $7.36 per share (December 31, 2014)
•
“All in” FD&A costs for 2014 of $19.55 per boe and recycle ratio of > 2.2 times
•
Increased YOY 2P reserves by 52% from 73.5MMboe to 112.0 MMboe
•
2P FDC (10%) is only 2.3 times 2014 forecast average funds flow
•
Maintained corporate PDP value year/year despite the plunge in crude pricing
•
>50% of Surge’s $2.0B total 2P NPV10 value resides in the PDP category
•
Initiated bank line review and expect to maintain $725MM bank line based on strong reserve
results, before the impact of the oil hedge reconfiguration and non-core property disposition
 Corporate Highlights:
•
Averaged 2014 production of 18,070 boe/d, an increase of 68% over 2013
•
Sold non-core assets for proceeds of $35.6MM
•
Monetized in the money crude oil swaps at a profit of >$35MM
•
Re-hedged approximately 45% of production by way of a “costless collar” with an avg floor of over
C$62/bbl(1) and a ceiling of over C$82/bbl(1) for the remainder of 2015
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
2
REASONS TO OWN SURGE
Well managed, operated, high quality, low decline asset base
 High quality light/medium crude oil asset base; low decline <22%
 >2.0 Billion barrels of OOIP under management; low RF~8%
 Low “all-in” sustainability ratio of 65% (US$58 WTI)
($0.30 annual dividend)
 High netbacks; top tier capital efficiencies
 Experienced management team with proven track records
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
3
FIRST HALF 2015 CAPITAL PROGRAM @ US$58 WTI
Protecting NAV and balance sheet through conservative capital spending
OPERATIONAL
Average Production (boe/d) for 1H 2015
>20,000 (83% Oil/NGLs)
Capital Spending for 1H 2015
Wells Drilled in 1H 2015
$22 million
5/3.8 gross/net wells
• 2 Shaunavon
• 1 Sparky
• 0.8 Midale
< 22%
Est Base Decline
FINANCIAL
(1)
1H 2015 Operational Netback
$31.65/boe
Basic Shares Outstanding
220 million
Annual Dividend Payable
$66 million ($0.30 per share per annum)
1H 2015 Basic Payout Ratio
41%
“All-in” 1H 2015 Sustainability Ratio
65%
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
4
ELITE ASSETS FOCUSED IN THREE CORE AREAS
Large OOIP pools located in established oil charged trends
Surge 2014 Exit Production:
Total: 21,350
(84% Oil & NGL’s)
Western Alberta Production:
Total: ~6,700
(67% Oil & NGL’s)
SE AB/SW SK Production:
Total: ~9,450
(88% Oil & NGL’s)
Williston Basin Production:
Total: ~5,200
(100% Oil & NGL’s)
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
5
CORE AREA DETAILS
>2 Billion bbl’s OOIP with potential to recover an additional ~261 Million bbl’s net to Surge
without the Viking
OOIP (MMbbls)
Drilling Locations
Gross/Net
Gross/Net
Avg. CTD Oil Total Booked Independent
Internally Estimated Ultimate
(1)
WI Recovery Recovery Factor P+P
Recovery Net (Waterflood
Factor
with Development Drilling)
(% OOIP)
Doig/Slave Point/
Bluesky/Montney/
Western Alberta
Banff/Doe Creek
/Wabamun
731/626
187/178
89%
5.7%
11.4%
23%
SE Alberta
Mannville Group
481/399
152/149
83%
16.7%
20.7%
25%
SW
Saskatchewan
Shaunavon
469/467
362/356
97%
0.9%
3.1%
13%
Williston Basin
Midale /
Frobisher-Alida /
Bakken-3 Forks
689/562
217/199
82%
12.6%
17.0%
23%
2,370/2,054
918/882
87%
8.3%
12.5%
21%
Core Area
Formations
TOTALS:
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
6
TOP TIER CAPITAL EFFICIENCIES AND REPLACEMENT METRICS
Vast opportunity base allows for selective and efficient capital allocation
Areas/Formations
Core Area
Locations
SE
Alberta/
SW Sask
Valhalla
(1)
Drill/ Complete/
Equip (2)
180 day IP
Mboe/well
(on primary)
$55 WTI $58 WTI $65 WTI $75 WTI
(Gross / Net)
Western
Alberta
Rates of Return %
Capital
Efficiency
$14,100/boepd
57%
62%
77%
105%
$3.95 MM
280 boepd (69% oil)
420
Upper Shaunavon $11,800/boepd
76%
87%
122%
197%
$1.95 MM
165 boepd (100% oil)
150
$15,500/boepd
60%
64%
75%
95%
$1.70 MM
110 boepd (73% oil)
120
$20,000/boepd
53%
57%
66%
84%
$1.80 MM
90 boepd (100% oil)
100
$20,000/boepd
58%
62%
73%
92%
$1.80 MM
90 boepd (100% oil)
100
$15,600/boepd
43%
48%
60%
85%
$1.25 MM
80 boepd (100% oil)
75
$20,800/boepd
54%
58%
69%
90%
$1.35 MM
65 boepd (100% oil)
80
(39/31)
(175/174)
Sparky
(116/115)
Midale Crown
(24/17)
Midale SGY Fee
Williston
Basin
(93/84)
Mississippian –
Frobisher/Alida
(40/31)
Manson –
Bakken/Torquay
(37/33)
*Numbers in the above table are based on Surge’s internally generated type curves
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
7
QUALITY WATERFLOOD PROJECTS
Increasing reserves / flattening declines through waterflood implementation
Current Properties Under Full Commercial Waterflood
Area
Start Date
2014 Decline
Current RF
Booked RF
Expected RF
Lloyd/ Cummings
1996
18%
12.6%
35.7%
39.0%
Wainwright
Sparky
1962
8%
32.0%
35.5%
37.1%
Macklin
Sparky
2005
18%
10.4%
37.2%
38.0%
Valhalla
Doe Creek
1994
6%
12.5%
16.1%
38.5%
Silver
Formation
Current Waterflood Pilots
Formation
Start Date
# of
Injectors
Analog
Property
Slave Point
Q2 2013
4
Gift
Bakken
Q4 2013
7
Sinclair
Shaunavon
Lower
Shaunavon
Q4 2013
5
Shaunavon
Nevis
Wabamun
Q3 2010
2
N/A
Macoun
Midale
Q4 2013
1
Benson
Windfall
Bluesky
Q4 2012
1
N/A
Eyehill
Sparky
Q3 2014
1
Area
Nipisi
Manson
Comments
4th injector in Aug 2014; results to date encouraging; analog
pool is commercial
Initial results are encouraging; analog pool is commercial
Piloting 200 and 400 m spacing; 3 analog pilots showing
strong oil response.
2nd injector commenced in Q1 2014; increasing source water
supply to increase injection
1st Hz injector in the pool; analog pool is commercial
91,000 m3 injected; offset declines are flattening
Wainwright Q1/13 discovery; > 80 MM OOIP
2015 Waterflood Pilots
Provost
Sparky
Q4
1-2
Wainwright Q1/13 discovery; > 45 MM OOIP
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
8
SOUTHWEST SASKATCHEWAN - SHAUNAVON
>400MM barrels of Net OOIP in the Upper and Lower Shaunavon combined
 >400 MMbbls of Net OOIP in the Lower and
Upper Shaunavon formations (medium
gravity oil)
 Current recovery factor ~0.9%
 Rates of return in excess of 87%(1) for the
Upper Shaunavon
 362 gross/356 net drilling locations in the
Lower and Upper Shaunavon based on 8
wells/section
 Operated facilities, including: pipeline
connected battery, waterflood infrastructure,
a nearby rail transloading facility, and an
existing rail marketing arrangement
 Development of the Upper Shaunavon
discovery has begun with 9 wells on
production by year end 2014 and an
additional 2 wells to be on production in
Q1 2015
Surge Land
Surge Wells
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
9
UPPER SHAUNAVON
Large contiguous undeveloped land position in the Upper Shaunavon trend
R19W3
T10
R21W3
Instow
T8
Leitchville
Leon Lake
Area/Pool
Well Count Depth
OOIP
Cum Oil
Peak Rate Current Rate
Vt
Hz
(m)
(MMbbl)
(MMbbl)
(bbl/d)
(bbl/d)
Instow
118
2
1372
152.4
69.6
9420
2530
Leitchville
68
209
1371
98.9
14.5
6590
5080
Leon Lake
28
22
1371
74.7
4.2
1270
1270
Dollard
109
6
1402
179.3
103.5
14660
1680
Eastbrook
28
22
1420
n/a
8.4
3760
3430
Rapdan
103
10
1410
143.2
31.5
4490
1050
0
11*
1430
200+
0.2
TBD
>1200
SGY - Eastend
* SGY well count includes 2 January 2015 drills scheduled for completion February 2015
Data from public sources
Dollard
 Surge Upper Shaunavon
•
T6
Eastend
•
Eastbrook
•
•
T4
•
Rapdan
9 wells drilled and completed in 2014 (Currently >1200 bopd)
5 wells drilled and completed in Q4 2014 with 30 day IP rates
over 200 bopd
5th well was a step-out and validated a large additional Upper
Shaunavon trend
2 Upper Shaunavon wells drilled in Q1 2015 with completions
scheduled for Feb 2015
Discovery >200MMbbls OOIP; over 100 locations
SGY Lands
Upper Shaunavon Wells
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
10
UPPER SHAUNAVON ACTIVITY
>150MMbbl OOIP on Surge lands in the Upper Shaunavon B Sand
R20W3
R19W3
R18W3
T7
CPG U. Shvn Hz
191/13-20-006-19W3
On Prd Mar 2011
IP(90) = 109 BOPD
Cum(YTD) = 24.5 mbbl
T6
Upper Shaunavon A Sand
SGY Q4 ‘14 U. Shvn Hz
191/01-25-005-20W3
On Prd Dec 2014
Avg. 125 bbl/d (67 days)
Cum(YTD) = 9.6 mbbl
Upper Shaunavon B Sand
Upper Shaunavon C Sand
Lower Shaunavon
SGY Q3 ‘14 U. Shvn Hz
192/13-31-005-19W3
On Prd Sept 2014
IP(90) = 240 BOPD
Cum(YTD) = 28.8 mbbl
SGY Q1 ‘14 Upper Shvn Hz
191/16-36-005-20W3
IP(90) = 250 BOPD
Cum(YTD) = 68.5 mbbl
T5
SGY Q4 ‘14 U Shvn Hz
192/03-25-005-20W3
On Prd Dec 2014
Avg. 297 bbl/d (66 days)
Cum(YTD) = 21.1 mbbl
SGY Q4 ‘14 U.Shvn Hz
191/04-34-005-19W3
On Prd Dec 2014
Avg. 164 bbl/d (48 days)
Cum(YTD) = 9.1 mbbl
SGY Lands
T4
Upper Shaunavon Depositional Trend
CPG U. Shvn Hz
191/14-13-005-20W3
On Prd Jan 2014
IP(90) = 248 BOPD
Cum(YTD) = 44.2 mbbl
Upper Shaunavon Seismically Identified “Sweet Spots”
CPG U. Shvn Hz
191/02-36-004-20W3
On Prd Jan 2013
IP(90) = 287 BOPD
Cum = 99 mbbl
SGY 2014 Upper Shaunavon Drills
SGY Licensed Locations
Upper Shaunavon Wells
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
11
UPPER SHAUNAVON PERFORMANCE
Surge results in the Upper Shaunavon exceeding expectations
Upper Shaunavon - SGY Results vs Type Curve
Production Rate (bopd), Cumulative Oil Production (mbbls)
300
SGY Wells Normalized
Rate (bopd)
250
SGY Wells Avg. Cum
(mbbls)
200
McDaniel YE2014 Type
Curve Rate (bopd)
McDaniel YE2014 Type
Curve Cum (mbbls)
150
McDaniel YE2013 Type
Curve Rate (bopd)
100
McDaniel YE2013 Type
Curve Cum (mbbls)
50
0
0
5
10
15
20
25
Month
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
12
SOUTHEAST SASKATCHEWAN - WILLISTON BASIN
Midale, Macoun and Pinto Areas – Large Fee and Crown position in Midale Carbonate trend
Weyburn
 211 MMbbls of Net OOIP
(35-37 degree API)
 Current recovery factor ~5% of OOIP
 Rates of return >57% (1)
 38,400 acres (60 sections) of
Surge Fee land
 142 gross/123 net drilling locations
Midale
Macoun
•
•
•
Pinto
93/84 (gross/net) FEE Locations
24/17 (gross/net) Crown Locations
25/22 (gross/net) Freehold Locations
Surge Land
Surge Fee Land
Surge Wells
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
13
SOUTHEAST ALBERTA
Provost / Eyehill / Wainwright Area’s – Oil saturated Cretaceous Sands
Wainwright
 >400 MMbbls of Net OOIP (23-31 degree API oil)
 Current recovery factor of ~14%
 Eyehill Sparky waterflood started in Q4 2014 and
Provost waterflood pilot expected to start in 2015
 Control of key infrastructure
 Rates of return in excess of 64% (1)
 152 gross/149 net drilling locations
Silver
Macklin
Provost
Eyehill
Surge Land
Surge Wells
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
14
WESTERN ALBERTA
>195MMbbls OOIP in Oil rich Doig and Doe Creek Formations
Valhalla Doig
Doe Creek
Oil Pool
Valhalla

>130 MMbbls of Net combined OOIP at Valhalla and
Wembley (40 degree API light oil)

Rates of return of 62% (1)

Current recovery factor ~2.8%

39 gross/31 net drilling locations at both Valhalla and
Wembley

Continued delineation of large pool extension to the North

Potential future waterflood candidate
Valhalla Doe Creek Oil Pool
Doig
Wembley

>60MMbbls of OOIP (37° API oil)

Current recovery factor 13%

Low historical declines of 8-10%/year

100% WI and operated

Currently under waterflood with optimization opportunities

Acquired working interest in a gas plant capable of
processing associated gas volumes from Surge’s Valhalla
Doig oil pool
Surge Land
Surge Wells
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
15
RISK MANAGEMENT / HEDGING STRATEGY
Oil Hedges
$85.00
6,500
$80.00
5,500
4,500
$70.00
 Surge has 5,500 barrels per day of WTI
hedged (~ 41% 1H net oil + NGL’s)
with a costless collar structure, as
follows:
Avg Price
Period
bbl/d
CAD$ per bbl
$75.00
 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.
3,500
$65.00
2,500
$60.00
$55.00
1,500
$50.00
500
Mar-15 Apr-15 May-15
Jun-15
Jul-15
Aug-15 Sep-15
Oct-15 Nov-15 Dec-15
bbl/d Hedged
Average C$ WTI Oil Hedge Floor Price
Average C$ WTI Oil Hedge Ceiling Price
Strip - C$ WTI
Currency bbls/d
(Floor /
Ceiling)
Mar – Dec
2015
CAD
3,000 $61.67 / $83
Mar – Dec
2015
USD
2,500 $50 / $65.40
 Surge has 7,586 mcf per day of
AECO hedged (~50% net natural
gas) at CAD$4.14 for 2015.
WCS Differential
Hedges
bbls/d
hedged
WTI-less
USD$/bbl
2015
3,000
$22.10
2016
1,000
$21.75
EDM Light Differential
Hedges
bbls/d
hedged
WTI-less
USD$/bbl
Q1 2015
2,000
$8.34
Q2 2015
1,000
$8.19
USD$ WTI hedges converted to CAD, based on Feb-9-2015 strip rate for illustrative purposes.
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
16
2014 YEAR END RESERVES
~$2.0 Billion of Total Proved plus Probable Reserves Value (NPVBT10)
2014 Year End Reserves
Reserve Category
Oil& NGLs
(Mbbl)
Gas
(MMcf)
Total
(Mboe)
NPVBT10 ($MM) (1)
Proved Producing
36,834
51,587
45,431
$1,038
Proved Non-Producing
733
2,424
1,137
$25
Proved Undeveloped
16,647
30,628
21,752
$261
Total Proved (1P)
54,214
84,639
68,320
$1,324
Probable
36,017
46,156
43,710
$661
Total Proved + Probable (2P)
90,230
130,795
112,030
$1,984
*Numbers in the above table may not add exactly due to rounding
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
17
POSITIONED FOR LONG TERM SUSTAINABILITY
 Low base decline <22%, high netbacks, excellent capital
efficiencies
 Very low “all-in” sustainability ratio of 65%; NO DRIP!
 Ongoing risk management/hedging program protects cash flow
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
18
HIGH QUALITY CRUDE OIL ASSET BASE
 Focused, high quality, crude oil asset and opportunity base;
core properties are 100% operated with working interests of
~90%
 Elite, large OOIP crude oil reservoirs – with low recovery
factors; >15 year RLI (only ~2 years of FDC/cash flow)
 Over 900 gross low risk development drilling locations provide
>12 year inventory; Of these >400 are grade “A” development
locations - providing >35,000 boepd of low risk upside
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
19
ANALYST COVERAGE
Financial Institution
Analyst
Email Address
BMO Capital Markets
Jim Byrne
[email protected]
Canaccord Genuity
Anthony Petrucci
[email protected]
CIBC World Markets Inc.
Jeremy Kaliel
[email protected]
Cormark Securities Inc.
Garett Ursu
[email protected]
Dundee Securities Corporation
Chad Ellison
[email protected]
FirstEnergy Capital Corp.
Cody R. Kwong
[email protected]
GMP Securities L.P.
Grant Daunheimer
[email protected]
Macquarie Securities Group
Ray Kwan
[email protected]
National Bank Financial
Dan Payne
[email protected]
Paradigm Capital
Ken Lin
[email protected]
Peters & Co. Limited
Dale Lewko
[email protected]
RBC Capital Markets
Shailender Randhawa
[email protected]
Scotia Capital Inc.
Cameron Bean
[email protected]
TD Securities
Juan Jarrah
[email protected]
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
20
CORPORATE PARTNERS
Advisors
Bankers:
National Bank of Canada
Bank of Nova Scotia
Canadian Imperial Bank of Commerce
Toronto-Dominion Bank
Bank of Montreal
JPMorgan Chase Bank, N.A.
ATB Financial
HSBC Bank Canada
Auditor:
KPMG LLP
Legal Counsel:
McCarthy Tétrault
Evaluation Engineers:
Sproule Associates Ltd.
McDaniel & Associates Consultants Ltd.
Registrar & Transfer Agent:
Computershare Canada
Investor Contacts:
Paul Colborne, President & CEO
Max Lof, CFO
2100, 635 – 8th Ave. SW, Calgary Alberta T2P 3M3
T: 403.930.1010 F: 403.930.1011
www.surgeenergy.ca
21
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.
22
ENDNOTES
Slide 2:
(1) USD$ WTI hedges have been converted to $CAD, based on Feb-9-2015 strip rate.
Slide 4:
(1) Based on 2015 WTI oil pricing of US$58/bbl; AECO gas $3.50/gj and a CAD/USD exchange rate of $0.83.
Slide 6:
(1) December 31, 2013 reserves.
Slide 7:
(1) Assumes CAD/USD exchange rate of $0.83 for 2015 and Sproule January 2015 price forecast for 2016 and after.
(2) Assumes 10% capital savings due to reduction in service costs
Slide 9:
(1) WTI oil pricing of US$58/bbl; AECO gas $3.50/gj; CAD/USD exchange rate of $0.83 was assumed for 2015.
Sproule January 2015 price forecast was used for 2016 and after.
Slide 13 - 15:
(1) WTI oil pricing of US$58/bbl; AECO gas $3.50/gj; CAD/USD exchange rate of $0.83 was assumed for 2015.
Sproule January 2015 price forecast was used for 2016 and after.
Slide 18:
(1) Based on Sproule's December 31, 2014 Revised Price Forecast
23
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.
Contingent resources are those quantities of oil estimated, as of a given date, to be potentially recoverable from known accumulations using
established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or
more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of
markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in
the early evaluation stage. All contingent resources represented in this document are considered Economic Contingent Resources based on the
McDaniel & Associates Consultants Ltd. January 1 Price Forecast and an economic hurdle rate of the before tax net present value at a discount
rate of 10% being greater than 0 (i.e. ROR >= 10%). The primary contingency which prevents the classification of Surge's contingent resources
as reserves is capital budgeting restraints that allow the resources to be developed within a reasonable time frame. This time frame can be
defined as 3 – 4 years. As additional drilling and/or development takes place, it is expected that some or all of the contingent resources will be
booked as reserves.
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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, legal settlement
expenses, decommissioning expenditures, cash settled stock-based compensation, transaction costs and current tax on disposition.
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.
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