CALGARY, March 12, 2019 /CNW/ - Surge Energy Inc. ("Surge"
or the "Company") (TSX: SGY) is pleased to announce its operating
and financial results for the quarter ended December 31, 2018, and its year-end 2018
reserves, as evaluated by Sproule.
Surge's financial and operating results for the fourth
quarter of 2018 include only a partial quarter of the previously
announced Mount Bastion Oil & Gas Ltd. ("MBOG") light oil
acquisition, which closed during the fourth quarter of
2018.
MESSAGE TO THE SHAREHOLDERS
Overall, 2018 was a transformative year for the Company. Surge's
Q4 2018 production of 21,047 boepd (82% oil and NGLs) increased by
more than 34 percent (over 8 percent per share) as compared to Q4
2017 production volumes of 15,675 boepd (81% oil and NGLs). This
production growth was predominantly generated by the addition of
high-netback, light oil production. Additionally, Surge increased
its Proven plus Probable ("P+P") reserves by 29 percent, from 95.2
MMboe at year-end 2017, to 122.6 MMboe at year-end 2018.
Operationally, the Company's high quality, large original oil in
place1 ("OOIP"), conventional reservoirs continued to
deliver consistent results. The Company organically replaced 133%
of 2018 production, and has delivered three year FD&A costs of
$12.77 per boe on a P+P basis. This
drove a three year average recycle ratio of 2.5
times2.
During the fourth quarter of 2018 the price of oil dropped 44% -
from over US$76 WTI per barrel to as
low as US$42.50 WTI per barrel.
Furthermore, Western Canadian Select ("WCS") crude oil
differentials widened precipitously from US$19 per barrel to as high as US$50 per barrel, and Edmonton Light
differentials widened from US$4 per
barrel to more than US$30 per
barrel.
Surge management reacted quickly to these negative market
conditions by reducing capital expenditures and delaying well
completions into 2019. Accordingly, on January 14, 2019, Surge announced a 2019 capital
expenditure budget which focused on sustainability, generation of
free adjusted funds flow3 at lower commodity prices, and
payment of the Company's dividend.
The extremely negative factors that affected Q4 2018 financial
results have corrected quickly in Q1 2019. WTI crude oil
prices are up approximately 35% since December 2018, and both Edmonton light and WCS crude oil differentials
have quickly tightened to below historical averages.
Currently, Surge is receiving pricing on its WCS correlated
production that is 675% higher than in December 2018, at C$62 per barrel, and Edmonton light production is receiving 275%
higher pricing than December 2018, at
C$70 per barrel.
Surge remains well-positioned to execute its 2019 guidance,
focused on the continued development of its extensive portfolio of
large OOIP, light and medium gravity crude oil assets.
_____________________
|
1 See
Reserves Data in the Forward-Looking Statement section of this
document for further details
|
2 See
the Performance Measures section of this document for further
details
|
3 This is a non-GAAP financial
measure which is defined in the Non-GAAP Financial Measures section
of this document
|
FINANCIAL AND OPERATING HIGHLIGHTS
($000s except
per share amounts)
|
|
|
|
|
Three Months Ended
December 31,
|
|
Year Ended
December 31,
|
|
2018
|
2017
|
%
Change
|
|
2018
|
2017
|
%
Change
|
Financial
highlights
|
|
|
|
|
|
|
|
Oil sales
|
51,424
|
64,221
|
(20)%
|
|
285,378
|
217,194
|
31 %
|
NGL sales
|
2,477
|
2,751
|
(10)%
|
|
11,022
|
9,431
|
17 %
|
Natural gas
sales
|
4,226
|
2,288
|
85 %
|
|
8,147
|
14,283
|
(43)%
|
Total oil, natural
gas, and NGL revenue
|
58,127
|
69,260
|
(16)%
|
|
304,547
|
240,908
|
26 %
|
Cash flow from
operating activities
|
26,770
|
28,640
|
(7)%
|
|
121,907
|
93,682
|
30 %
|
Per share - basic
($)
|
0.09
|
0.12
|
(25)%
|
|
0.50
|
0.41
|
22 %
|
Adjusted funds
flow1
|
6,249
|
32,173
|
(81)%
|
|
113,651
|
103,816
|
9 %
|
Per share - basic
($)1
|
0.02
|
0.14
|
(86)%
|
|
0.46
|
0.45
|
2 %
|
Total exploration and
development expenditures
|
33,598
|
22,709
|
48 %
|
|
120,552
|
98,466
|
22 %
|
Total acquisition and
dispositions
|
299,032
|
368
|
nm2
|
|
327,765
|
72,465
|
nm
|
Total capital
expenditures
|
332,630
|
23,077
|
nm
|
|
448,317
|
170,931
|
162 %
|
Net debt1,
end of period
|
461,187
|
239,718
|
92 %
|
|
461,187
|
239,718
|
92 %
|
|
|
|
|
|
|
|
|
Operating
highlights
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
Oil (bbls per
day)
|
16,578
|
12,169
|
36 %
|
|
13,992
|
11,347
|
23 %
|
NGLs (bbls per
day)
|
703
|
571
|
23 %
|
|
623
|
639
|
(3)%
|
Natural gas (mcf per
day)
|
22,598
|
17,607
|
28 %
|
|
20,658
|
17,615
|
17 %
|
Total (boe per day)
(6:1)
|
21,047
|
15,675
|
34 %
|
|
18,058
|
14,922
|
21 %
|
Average realized
price (excluding hedges):
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
33.72
|
57.36
|
(41)%
|
|
55.88
|
52.44
|
7 %
|
NGL ($ per
bbl)
|
38.28
|
52.41
|
(27)%
|
|
48.51
|
40.41
|
20 %
|
Natural gas ($ per
mcf)
|
2.03
|
1.41
|
44 %
|
|
1.08
|
2.22
|
(51)%
|
|
|
|
|
|
|
|
|
Netback ($ per
boe)
|
|
|
|
|
|
|
|
Petroleum and natural
gas revenue
|
30.02
|
48.03
|
(37)%
|
|
46.21
|
44.23
|
4 %
|
Realized loss on
financial contracts
|
(1.25)
|
(0.81)
|
54 %
|
|
(1.67)
|
(0.74)
|
126 %
|
Royalties
|
(3.86)
|
(5.62)
|
(31)%
|
|
(6.55)
|
(5.53)
|
18 %
|
Net operating
expenses1
|
(15.70)
|
(13.85)
|
13 %
|
|
(14.76)
|
(13.62)
|
8 %
|
Transportation
expenses
|
(1.53)
|
(1.21)
|
26 %
|
|
(1.50)
|
(1.41)
|
6 %
|
Operating
netback1
|
7.68
|
26.54
|
(71)%
|
|
21.73
|
22.93
|
(5)%
|
G&A
expense
|
(1.83)
|
(1.95)
|
(6)%
|
|
(2.01)
|
(1.94)
|
4 %
|
Interest
expense
|
(2.60)
|
(2.28)
|
14 %
|
|
(2.47)
|
(1.94)
|
27 %
|
Adjusted funds
flow1
|
3.25
|
22.31
|
(85)%
|
|
17.25
|
19.05
|
(9)%
|
|
|
|
|
|
|
|
|
Common shares
outstanding, end of period
|
309,286
|
232,989
|
33 %
|
|
309,286
|
232,989
|
33 %
|
Weighted average
basic shares outstanding
|
288,744
|
232,929
|
24 %
|
|
246,252
|
228,212
|
8 %
|
Stock option
dilution
|
—
|
—
|
—%
|
|
—
|
—
|
—%
|
Weighted average
diluted shares outstanding
|
288,744
|
232,929
|
24 %
|
|
246,252
|
228,212
|
8 %
|
1 This is a non-GAAP
financial measure which is defined in the Non-GAAP Financial
Measures section of this document.
|
2 The Company views
this change calculation as not meaningful, or "nm".
|
In accordance with industry practice, the Company uses adjusted
funds flow to analyze the cash flow generated from its ongoing
principal business activities. On this basis, both adjusted funds
flow and cash flow from operating activities are provided for
comparative purposes. Please see the Non-GAAP Financial
Measures section of this release for further details.
2018 FOURTH QUARTER AND YEAR-END RESERVES HIGHLIGHTS
- During the fourth quarter, Surge announced the closing of the
Company's accretive MBOG light oil acquisition, and the creation of
the Greater Sawn core area;
- Surge's Q4/18 quarterly average production of 21,047 boepd
increased by more than 34% as compared to Q4/17 production of
15,675 boepd;
- The Company's Q4/18 quarterly average production of 21,047
boepd increased by 17% as compared to Q3/18 production of 18,029
boepd;
- The Company's revolving credit facility increased by 57 percent
to $550 million, up from $350 million previously. The Company had over
$140 million in undrawn
capacity4 at December 31,
2018;
- Independently engineered Proved Developed Producing reserves
(as of December 31, 2018) of 43.4
MMboe, increased 31% from year-end 2017;
- Total Proved Plus Probable reserves of 122.6 MMboe, increased
29% from year-end 2017;
- Organically added 8.0 MMboe of Proved Plus Probable Reserves,
replacing 133% of 2018 production5;
- Organically added 6.2 MMboe of Proved Developed Reserves,
replacing 102% of 2018 production5;
- Total Proved Plus Probable FD&A7 cost of
$20.97/boe including changes in
future development capital;
- Delivered three year average Total Proved Plus Probable
FD&A cost of $12.77/boe7, including changes in
future development capital;
- Reported a three year average recycle ratio of 2.5
times on a Total Proved Plus Probable basis;
- Total Proved Plus Probable Reserve life index6 of 16
years;
- Estimated Total Proved Plus Probable Net Asset Value of
$5.58 per common share7, a
1% increase from year-end 2017; and
- Estimated Total Proven Net Asset Value of $3.20 per common share7.
- Subsequent to Q4/18, Surge has executed a definitive purchase
and sale agreement regarding the disposition of certain non-core
assets for cash proceeds of $28.65 million, subject to
standard closing adjustments.
________________________
|
4 Calculated as $550 million, less
reported bank debt of $408.6 million as per the December 31, 2018
Financial Statements of the Company
|
5
Production Replacement is calculated as the total organic reserves
additions (ie. excluding acquisitions and dispositions) divided by
annual production (excluding acquisitions and
dispositions)
|
6 Reserve Life Index is calculated as
total Company share reserves divided by the annualized fourth
quarter actual production
|
7 See the
Performance Measures section of this document for further
details
|
2018 OPERATIONAL HIGHLIGHTS
Surge's disciplined operating strategy and high quality
conventional, large OOIP assets continued to provide strong
operational results in 2018. When combined with the MBOG light oil
acquisition, this resulted in Surge achieving record production of
21,047 boepd in the fourth quarter of 2018. The Company has now
increased production by 73% from Q2 2016 through Q4 2018.
In total, the Company spent $120.6
million of exploration and development capital in 2018,
drilling 46 gross (45.6 net) wells, along with waterflood injector
conversions, associated infrastructure, land and seismic. Through
step-out delineation drilling and minor land acquisitions, the
Company was able to increase the drilling inventory to over
8008 net internally estimated locations, representing an
increase of over 20% from 2017.
Sparky Core
Area
In the Sparky core area, Surge drilled 25
gross (24.6 net) wells in four separate fields during the year. In
addition to continued drilling at Eyehill and Provost, the Company
drilled four additional wells and constructed a battery at Betty
Lake. Peak production from the Betty Lake field was over 600 boepd,
and three additional wells have now been drilled into the pool in
Q1 2019. With over 50 net remaining internally estimated
locations, this large OOIP Sparky asset is very well-positioned for
long term, sustainable growth.
In the Sounding Lake field, the Company drilled its first Sparky
horizontal infill well in Q4 2018. This well continues to produce
at over 150 boepd. An additional two wells have been drilled in the
Sounding Lake area in Q1 2019.
With drill, complete and equip costs of under $1.3 million, year-round access, well-developed
infrastructure, proven waterflood performance and over
400 internally identified net locations, the Sparky core area
is a cornerstone asset of Surge's business.
Valhalla Core Area
At Valhalla, Surge successfully drilled and
completed 5 gross (5 net) wells in 2018. Four of these wells were
drilled into the Doig formation and had an average 30 day initial
production oil rate of over 1,100 bopd. Two Doig wells have been
drilled in Q1 2019.
The Company also drilled its first well into the Charlie Lake formation with a 30 day IP oil
rate over 200 bopd. Throughout 2018, Surge continued to expand its
drilling inventory in this multi-zone area and now has over 85 net
locations in the Doig, Montney,
Doe Creek and Charlie Lake
formations.
Shaunavon Core Area
Surge successfully drilled
14 gross (14 net) wells at its Shaunavon core area in the past year,
targeting both the Upper and Lower Shaunavon formations. Production
from the field was maintained throughout the year at approximately
2,500 boepd.
Strategically positioned in Southwest
Saskatchewan, Shaunavon
receives Fosteron grade crude oil pricing, which has historically
traded at a premium to WCS. Accordingly, Shaunavon has one of the highest operating
netbacks in the Company and generates free adjusted funds
flow9 that can be deployed across Surge's asset
base.
________________________
|
8 See
the drilling locations section of this document for further
details.
|
Greater Sawn Core
Area
With the closing of the MBOG acquisition in
Q4 2018, Surge created a fourth core operating area at Greater
Sawn. The light oil, large OOIP, carbonate reef pools with
waterflood potential complement Surge's existing asset base and
business model. Shortly after closing the acquisition in 2018, the
Company drilled 2 gross (2 net) wells at Sawn. An additional two
net wells have been drilled in Q1 2019 and all four wells have now
been placed on production.
In the Sawn pool, five horizontal wells have already been
converted to water injection by the previous operator, and plans
are underway to further expand the waterflood and convert another
one to two wells to water injection in 2019. A comprehensive
reservoir simulation is also being completed on the Sawn pool to
optimize future infill drilling and waterflood development.
2018 YEAR-END RESERVES
The Company's reserves were evaluated by Sproule in accordance
with National Instrument 51-101 – Standards of Disclosure for Oil
and Gas Activities ("NI 51-101") effective December 31, 2018. Surge's annual information
form for the year ended December 31,
2018 (the "AIF") will contain Surge's reserves data and
other oil and natural gas information as mandated by NI 51-101.
Surge expects to file the Company's AIF on SEDAR on or before
March 31, 2019.
The following tables summarize Surge's working interest oil,
natural gas liquids and natural gas reserves and the net present
values ("NPV") of future net revenue for these reserves (before
taxes) using forecast prices and costs as evaluated in the Sproule
Report. The evaluation is based on Sproule's forecast
pricing and exchange rates at December 31,
2018 which is available on their website www.sproule.com.
All references to reserves in this release are to gross Company
reserves, meaning Surge's working interest reserves before
deductions of royalties and before consideration of the Company's
royalty interests. The amounts in the tables may not add due to
rounding.
9 This is a non-GAAP financial
measure which is defined in the Non-GAAP Financial Measures section
of this document
|
RESERVES SUMMARY AND NET PRESENT VALUE
Gross
Reserves(1)
|
Crude Oil
and NGLs
(Mbbl)(2)
|
Natural
Gas
(MMcf)(3)
|
Oil
Equivalent
Total
Reserves
(Mboe)
|
Before Tax NPV of
Future Net
Revenue(4) Discounted at
|
5%
($MM)
|
10%
($MM)
|
15%
($MM)
|
Proved:
|
|
|
|
|
|
|
|
Proved
Producing
|
37,511
|
35,369
|
43,406
|
815
|
741
|
656
|
|
Proved
Non-Producing
|
1,631
|
989
|
1,796
|
49
|
39
|
33
|
|
Proved
Undeveloped
|
29,336
|
36,173
|
35,365
|
738
|
538
|
404
|
Total
Proved
|
68,478
|
72,531
|
80,566
|
1,602
|
1,318
|
1,093
|
|
Probable
|
36,392
|
34,111
|
42,077
|
1,060
|
736
|
548
|
Total Proved Plus
Probable
|
104,869
|
106,643
|
122,643
|
2,662
|
2,054
|
1,641
|
(1)
|
Amounts may not add
due to rounding.
|
(2)
|
Includes light,
medium, heavy and tight oil and natural gas liquids.
|
(3)
|
Includes conventional
natural gas, solution gas and coal bed methane.
|
(4)
|
Total ADR
(Abandonment, Decommissioning, Reclamation) is included in the
reserves report, as it is best practice stated in the COGE
Handbook.
|
FUTURE CAPITAL COSTS
|
Total
Proved
|
Total Proved
Plus Probable
|
|
($MM)
|
($MM)
|
2019
|
113
|
127
|
2020
|
155
|
202
|
2021
|
166
|
192
|
2022
|
109
|
165
|
2023
|
64
|
107
|
Remaining
|
37
|
61
|
Total
(Undiscounted)
|
644
|
854
|
Total (Discounted at
10%)
|
509
|
660
|
|
|
(1)
|
In addition to Future
Development Costs, Future Capital Costs include an additional $103
million of
|
|
|
|
undiscounted
maintenance capital ($54 MM discounted at 10%).
|
PERFORMANCE MEASURES
|
2018
|
Three Year
Average
|
|
TP
|
TPP
|
TP
|
TPP
|
F&D ($/boe)
(1)
|
$22.39
|
$22.99
|
$15.71
|
$19.84
|
|
|
|
|
|
FD&A ($/boe)
(2)
|
$25.34
|
$20.97
|
$17.77
|
$12.77
|
|
|
|
|
|
FD&A Recycle
Ratio (3)
|
0.92
|
1.12
|
1.28
|
2.49
|
|
|
|
|
|
Production
Replacement (%) (4)
|
128%
|
133%
|
134%
|
131%
|
|
|
|
|
|
RLI (Years)
(5)
|
10.5
|
16.0
|
10.8
|
16.9
|
(1)
|
2018 Finding and
Development costs calculated using capital of $115 million plus
changes in FDC of $69 million.
|
(2)
|
2018 Finding,
Development and Acquisition costs calculated using capital of $448
million, plus total change in FDC of $265 million.
|
(3)
|
Recycle Ratio is
calculated using the 2018 operating netback excluding realized gain
(loss) on financial contracts10 of $23.40/boe
divided by F&D. The Company's 2018 operating netback includes
only 2 months of contribution from the MBOG acquisition.
|
(4)
|
Production
Replacement is calculated as the total organic reserves additions
(ie. excluding acquisitions and dispositions) divided by annual
production (excluding acquisitions and dispositions).
|
(5)
|
Reserve Life Index is
calculated as total Company share reserves divided by the
annualized fourth quarter actual production.
|
NET ASSET VALUE
|
TP
|
TPP
|
Reserve Value NPV10
BT ($MM) (1)
|
1,318
|
2,054
|
Undeveloped Land and
Seismic ($MM) (2)
|
134
|
134
|
Net Debt
($MM)
|
(461)
|
(461)
|
Total Net Assets
($MM)
|
990
|
1,726
|
Basic Shares
Outstanding (MM)
|
309.3
|
309.3
|
Fully Diluted Shares
Outstanding (MM)
|
318.5
|
318.5
|
Estimated NAV per
Basic Share ($/share)
|
$3.20/sh
|
$5.58/sh
|
(1)
|
Includes $148 MM (TP)
and $165 MM (TPP) of costs for changes due to the COGE Handbook to
include operating expenditures for non-producing properties and
abandonment liabilities.
|
(2)
|
Internally estimated
as $101 MM for non-reserve assigned land and $33 MM for seismic
data.
|
OUTLOOK
Management's stated goal is to be the best positioned, top
performing, light/medium gravity crude oil growth and dividend
paying public company in our peer group in Canada.
________________________
|
10 This is
a non-GAAP financial measure which is defined in the Non-GAAP
Financial Measures section of this document.
|
Overall, 2018 was a transformative year for the Company. Surge's
Q4 2018 production of 21,047 boepd (82% oil and NGLs) increased by
more than 34 percent (over 8 percent per share) over Q4 2017
production volumes of 15,675 boepd (81% oil and NGLs). This
significant production growth was predominantly generated by the
addition of high-netback, light oil production. Additionally, Surge
increased its Proven plus Probable ("P+P") reserves by 29 percent,
from 95.2 MMboe at year-end 2017, to 122.6 MMboe at year-end
2018.
On January 14, 2019 Surge
announced a 2019 capital budget of $135
million. This budget provides substantial flexibility to
react to changing commodity prices, while allowing the Company to
continue to deliver its sustainable dividend to shareholders.
The Company's 2019 capital budget is focused on the continued
development of its extensive portfolio of low risk, large OOIP,
light and medium gravity crude oil assets. Surge will execute this
plan while maintaining the Company's low 23 percent corporate
decline rate, and Surge's $140
million of credit availability11.
Over the last ten financial quarters, Surge has continued to
build and maintain the Company's track record, delivering:
- consistent successful drilling and waterflood results;
- timely and accretive core area acquisitions;
- increased production by more than 73 percent; and
- increased Surge's dividend three times by a cumulative 33
percent.
FORWARD LOOKING STATEMENTS:
This press release 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 press release contains statements
concerning: Management's expectations and plans with respect to the
development of its assets and the timing thereof; Surge's declared
focus and primary goals; Surge's annual exploration and development
capital expenditure program and budget and its flexibility to make
adjustments thereto; commodity prices and management's ability to
react to changes thereto; maintenance of Surge's decline rate;
production curtailments; export pipelines; availability of undrawn
capacity with respect to Surge's credit facility; Surge's dividend
policy and sustainability thereof and anticipated timing of filing
the Company's AIF.
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 ability of Surge to
increase its dividend post-closing; the availability and costs of
capital, labour and services; and the creditworthiness of industry
partners.
________________________
|
11
Calculated as $550 million, less reported bank debt of $408.6
million as per the December 31, 2018 Financial Statements of the
Company.
|
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 December 31,
2018, both of which have been filed on SEDAR and can be
accessed at www.sedar.com.
The forward-looking statements contained in this press release
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.
Reserves Data
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.
Original Oil in Place ("OOIP") means Discovered Petroleum
Initially In Place ("DPIIP"). 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). OOIP/DPIIP and potential
recovery rate estimates are based on current recovery technologies.
There is significant uncertainty as to the ultimate recoverability
and commercial viability of any of the resource associated with
OOIP/DPIIP, and as such a recovery project cannot be defined for a
volume of OOIP/DPIIP at this time.
Drilling Locations
This press release discloses drilling locations in two
categories: (i) booked locations; and (ii) unbooked locations.
Booked locations are proved locations and probable locations
evaluated by Sproule. Unbooked locations are generated internally
by Qualified Reserve Evaluators using standard practices as
prescribed in the Canadian Oil and Gas Evaluations Handbook.
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
certified Engineers and Geologists (who are also 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 December 31, 2018
reference date as noted per the Sproule Reserves report, Surge has
over 800 net drilling locations identified herein, of which over
400 are unbooked locations and 404 net are booked locations. Of the
404 net booked locations identified herein, 305 net are Proved
locations and 99 net are Probable locations. The Company's Sparky
core area has 133 net booked locations, of which 99 net are Proved
locations and 34 net are Probable locations. Betty Lake locations
identified herein has 12 net booked Proved locations and 3 net
booked Probable locations. Valhalla locations identified herein has 46
net Proved locations and 16 net Probable locations.
Non-GAAP Financial Measures
Certain secondary financial measures in this press release –
namely, "adjusted funds flow", "adjusted funds flow per
share", "free adjusted funds flow", "net debt", "net operating
expenses", "operating netback", "operating netback excluding
realized gain (loss) on financial contracts" and "adjusted funds
flow per boe" are not prescribed by GAAP. These non-GAAP financial
measures 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 the
Company's reported financial performance or position. The non-GAAP
measures do not have a standardized meaning prescribed by IFRS and
therefore are 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 & Adjusted Funds Flow per
Share
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.
Adjusted funds flow per share is calculated using the same
weighted average basic and diluted shares used in calculating
income per share.
The following table reconciles cash flow from operating
activities to adjusted funds flow and adjusted funds flow per share
for the three months and year ended December
31, 2018:
|
Three Months
Ended
|
Years
Ended
|
($000s except per
share)
|
Dec 31,
2018
|
|
Dec 31,
2017
|
Dec 31,
2018
|
|
Dec 31,
2017
|
Cash flow from
operating activities
|
$
|
26,770
|
|
$
|
28,640
|
$
|
121,907
|
|
$
|
93,682
|
Change in non-cash
working capital
|
(25,464)
|
|
2,276
|
(24,338)
|
|
4,644
|
Decommissioning
expenditures
|
1,439
|
|
829
|
6,348
|
|
2,457
|
Transaction and other
costs
|
3,504
|
|
-
|
5,288
|
|
1,155
|
Cash settled
stock-based compensation
|
-
|
|
428
|
4,447
|
|
1,878
|
Adjusted funds
flow
|
$
|
6,249
|
|
$
|
32,173
|
$
|
113,651
|
|
$
|
103,816
|
Per share –
basic
|
$
|
0.02
|
|
$
|
0.14
|
$
|
0.46
|
|
$
|
0.45
|
Free Adjusted Funds Flow
Free adjusted funds flow is calculated as adjusted funds flow
less the sum of total exploration and development capital and
dividends and represents, in dollars, the excess of adjusted funds
flows above exploration and development capital and dividends.
Management uses this measure to assess whether adjusted funds flow
is sufficient to fund the ongoing capital requirements of the
Company whilst servicing the dividend.
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
and other long term liabilities. 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.
($000s)
|
As at December
31,
2018
|
|
As at December
31,
2017
|
Bank debt
|
$
(408,593)
|
|
$
(209,231)
|
Accounts
receivable
|
21,084
|
|
36,291
|
Prepaid expenses and
deposits
|
9,222
|
|
2,889
|
Accounts payable and
accrued liabilities
|
(42,350)
|
|
(31,107)
|
Dividends
payable
|
(2,577)
|
|
(1,845)
|
Convertible
debentures
|
(37,973)
|
|
(36,715)
|
Total
|
$
(461,187)
|
|
$
(239,718)
|
Net Operating Expenses
Net operating expenses are determined by deducting processing
and other revenue primarily generated by processing third party
volumes at processing facilities where the Company has an ownership
interest. It is common in the industry to earn third party
processing revenue on facilities where the entity has a working
interest in the infrastructure asset. Under IFRS this source of
funds is required to be reported as revenue. However, the Company's
principal business is not that of a midstream entity whose
activities are dedicated to earning processing and other
infrastructure payments. Where the Company has excess capacity at
one of its facilities, it will look to process third party volumes
as a means to reduce the cost of operating/owning the facility. As
such, third party processing revenue is netted against operating
costs in the MD&A.
Operating Netback, Operating Netback Excluding Realized
Gain (Loss) on Financial Contracts, & Adjusted Funds Flow
Netback
Operating netback, operating netback excluding realized gain
(loss) on financial contracts & adjusted funds flow per boe for
the three and twelve months ended December
31, 2018 are calculated on a per unit basis as follows:
|
Three Months
Ended
|
Years
Ended
|
($000s except per
share)
|
Dec 31,
2018
|
|
Dec 31,
2017
|
Dec 31,
2018
|
|
Dec 31,
2017
|
|
Dec 31,
2016
|
Petroleum and natural
gas revenue*
|
$
|
58,127
|
|
$
|
69,260
|
$
|
304,547
|
|
$
|
240,908
|
|
$
|
165,568
|
Processing and other
income*
|
576
|
|
502
|
2,818
|
|
2,502
|
|
1,993
|
Royalties*
|
(7,478)
|
|
(8,106)
|
(43,203)
|
|
(30,099)
|
|
(19,197)
|
Operating
expenses*
|
(30,985)
|
|
(20,476)
|
(100,108)
|
|
(76,697)
|
|
(59,623)
|
Transportation
expenses*
|
(2,971)
|
|
(1,740)
|
(9,878)
|
|
(7,670)
|
|
(7,302)
|
Operating netback
excluding realized gain (loss) on financial contracts
|
$
|
17,269
|
|
$
|
39,440
|
$
|
154,176
|
|
$
|
128,944
|
|
$
|
81,439
|
Realized gain (loss)
on financial contracts*
|
(2,430)
|
|
(1,163)
|
(11,007)
|
|
(4,013)
|
|
3,963
|
Operating
netback
|
$
|
14,839
|
|
$
|
38,277
|
$
|
143,169
|
|
$
|
124,931
|
|
$
|
85,402
|
G&A
expense*
|
(3,551)
|
|
(2,813)
|
(13,228)
|
|
(10,575)
|
|
(8,708)
|
Interest
expense*
|
(5,039)
|
|
(3,291)
|
(16,289)
|
|
(10,540)
|
|
(6,468)
|
Adjusted funds
flow
|
$
|
6,249
|
|
$
|
32,173
|
$
|
113,651
|
|
$
|
103,816
|
|
$
|
70,226
|
Barrels of oil
equivalent (boe)
|
1,936,352
|
|
1,441,982
|
6,591,007
|
|
5,446,777
|
|
4,717,008
|
Operating netback
excluding realized gain (loss) on financial contracts ($ per
boe)
|
$
|
8.93
|
|
$
|
27.35
|
$
|
23.40
|
|
$
|
23.67
|
|
$
|
17.26
|
Operating netback
($ per boe)
|
$
|
7.68
|
|
$
|
26.54
|
$
|
21.73
|
|
$
|
22.93
|
|
$
|
18.10
|
Adjusted funds
flow ($ per boe)
|
$
|
3.25
|
|
$
|
22.31
|
$
|
17.25
|
|
$
|
19.05
|
|
$
|
14.88
|
* Taken directly from
the financial statements.
|
|
|
|
|
|
|
|
|
Additional information relating to non-GAAP measures can be
found in the Company's most recent management's discussion and
analysis MD&A, which may be accessed through the SEDAR website
(www.sedar.com).
Neither the TSX nor its Regulation Services Provider (as that
term is defined in the policies of the TSX) accepts responsibility
for the adequacy or accuracy of this release.
SOURCE Surge Energy Inc.