CALGARY,
AB, March 6, 2024 /CNW/ - Surge Energy Inc.
("Surge", "SGY", or the "Company") (TSX: SGY) is pleased to
announce its financial and operating results for the quarter and
year ended December 31, 2023; and its
year end 2023 reserves as independently evaluated by Sproule
Associates Limited ("Sproule").
Surge's disciplined operating strategy involves focusing growth
and development capital to high netback, low cost, light and
medium gravity crude oil reservoirs, that possess large original
oil in place ("OOIP")1 and low recovery factors.
In Q4/23 Surge achieved an average production rate of 25,050
boepd (86 percent liquids), exceeding the Company's 2023 public
guidance production exit rate of 25,000 boepd. Additionally, Surge
achieved record annual production in 2023 of 24,438 boe/d (86
percent liquids), an increase of 15 percent over 2022 average
production of 21,262 boepd.
FINANCIAL AND OPERATIONAL HIGHLIGHTS
Surge's Board and Management are pleased to report that the
Company organically generated free cash flow2 before dividends
("FCF") of $94 million in 2023,
representing 35 percent of 2023 cash flow from operating
activities.
Additional financial and operating highlights for the quarter
and year ended December 31, 2023
include:
- Generated cash flow from operating activities of $79.7 million in Q4/23;
- Reduced net debt2 by over $62
million in 2023 to $290.1
million, a decrease of 18 percent;
- Distributed cash dividends to shareholders in the amount of
$46.8 million in 2023;
- Reduced net operating expenses2 by $2.36 per boe over the course of 2023, from
$22.26 per boe in Q1/23 to
$19.90 per boe in Q4/23. This
represents an 11 percent decrease in net operating expenses over
the year;
- Repaid in full Surge's $47.9
million first lien term loan facility that was set to mature
in December 2024;
- Completed a new, oversubscribed, $48.3
million unsecured convertible debenture financing, with an
attractive 8.50% interest rate;
- Finalized the early redemption of $34.5
million of previously issued unsecured convertible
debentures that were set to mature on June
30, 2024 with no pre-payment penalty;
- Executed a successful 2023 drilling program of 70 gross (64.5
net) wells, strategically focused on light and medium gravity crude
oil in the Company's conventional SE
Saskatchewan and Sparky core areas; and
- Continued the Company's focus on ESG efforts, highlighted by
spending a total of $15.6 million on
abandonment activities during the year. This resulted in Surge
abandoning 132 gross wells during 2023, representing 1.9 wells
abandoned for each new gross well drilled in 2023.
___________________
|
1 See Oil
& Gas Advisories.
|
2 This is a
non-GAAP and other financial measure which is defined under
Non-GAAP and Other Financial Measures.
|
2023 YEAR END RESERVES HIGHLIGHTS
Surge is pleased to announce the results of the independent
reserves evaluation of the Company's crude oil and natural gas
assets, dated February 9, 2024 and
effective December 31, 2023, in
compliance with National Instrument 51-101 - Standards of
Disclosure for Oil and Gas Activities ("NI 51-101") and in
accordance with the Canadian Oil and Gas Evaluation Handbook (the
"Reserve Report").
Building off of the successful 2023 drilling program in the
Company's Sparky and SE
Saskatchewan core areas, Surge continued to delineate and
improve the Company's reserve base through pool extensions,
establishing new development fields, and new exploration/appraisal
drilling over the year.
Surge Management is pleased to report that, even after giving
effect to increases in industry wide inflationary cost estimates,
and a reduction in Sproule's crude oil price deck, the Company's
2023 Total Proved Net Asset Value1 ("TP NAV") is $11.27 per basic share. The Company's new TP NAV
includes 397 net booked locations of Surge's more than 1,000 net
internally identified drilling locations3. This
new TP NAV is approximately 65 percent higher than Surge's
current trading price of $6.92 per
share.
With Surge's December 31, 2023
Reserve Report, the Company delivered the following:
- 117 million boe of Total Proved & Probable ("TPP")
reserves;
- High oil weighting, with Proved Developed Producing ("PDP")
reserves comprised of 88% light and medium oil and natural gas
liquids, and TPP reserves comprised of 86% light and medium oil and
natural gas liquids;
- 543 gross (489 net) booked TPP drilling locations; 70% of these
locations are located in the Company's Sparky and SE Saskatchewan core areas3;
- Reported a TPP NAV of $17.63 per
basic share;
- Generated a TP NAV of $11.27 per
basic share;
- Confirmed a PDP NAV of $5.66 per
basic share;
- Delivered a TP Finding, Development & Acquisition
("FD&A") cost of $21.59/boe1;
- 1.8x Recycle Ratio1 on a 2023 operating netback of $39.07/boe (before realized losses on financial
contracts);
- Reported a strong reserve life index1 of 12.8 years on TPP
reserves, 9.3 years on TP reserves, and 4.7 years on PDP
reserves;
- Replaced 102% of production on a TP basis, and 80% of
production on a PDP basis; and
- Total Proved Undeveloped ("PUD") reserve net locations3
increased to 397 net, an increase of 31 locations over last year.
All additional PUD locations were added in the Sparky and
SE Saskatchewan core areas.
________________
|
3 See
Drilling Inventory.
|
FINANCIAL AND OPERATING HIGHLIGHTS
FINANCIAL AND
OPERATING HIGHLIGHTS
|
Three Months Ended
December 31,
|
Years Ended December
31,
|
($000s except per
share amounts)
|
2023
|
2022
|
%
Change
|
2023
|
2022
|
%
Change
|
Financial
highlights
|
|
|
|
|
|
|
Oil sales
|
160,755
|
152,465
|
5 %
|
640,389
|
672,862
|
(5) %
|
NGL sales
|
3,619
|
3,871
|
(7) %
|
13,052
|
16,783
|
(22) %
|
Natural gas
sales
|
4,079
|
9,472
|
(57) %
|
16,934
|
37,583
|
(55) %
|
Total oil, natural gas,
and NGL revenue
|
168,453
|
165,808
|
2 %
|
670,375
|
727,228
|
(8) %
|
Cash flow from
operating activities
|
79,712
|
78,975
|
1 %
|
266,141
|
276,125
|
(4) %
|
Per share - basic
($)
|
0.79
|
0.90
|
(12) %
|
2.69
|
3.26
|
(17) %
|
Per share - diluted
($)
|
0.78
|
0.88
|
(11) %
|
2.63
|
3.17
|
(17) %
|
Adjusted funds
flowa
|
77,001
|
71,807
|
7 %
|
291,846
|
293,555
|
(1) %
|
Per share - basic
($)a
|
0.77
|
0.82
|
(6) %
|
2.95
|
3.47
|
(15) %
|
Per share - diluted
($)
|
0.75
|
0.80
|
(6) %
|
2.89
|
3.37
|
(14) %
|
Net income (loss)
($)c
|
(29,676)
|
103,502
|
(129) %
|
15,751
|
231,718
|
(93) %
|
Per share - basic
($)
|
(0.30)
|
1.17
|
(126) %
|
0.16
|
2.74
|
(94) %
|
Per share - diluted
($)
|
(0.29)
|
1.15
|
(125) %
|
0.16
|
2.66
|
(94) %
|
Expenditures on
property, plant and equipment
|
61,305
|
47,728
|
28 %
|
181,572
|
169,944
|
7 %
|
Net acquisitions and
dispositions
|
3,813
|
200,302
|
(98) %
|
1,670
|
200,270
|
(99) %
|
Net capital
expenditures
|
65,118
|
248,030
|
(74) %
|
183,242
|
370,214
|
(51) %
|
Net
debta, end of
period
|
290,070
|
352,213
|
(18) %
|
290,070
|
352,213
|
(18) %
|
|
|
|
|
|
|
|
Operating
highlights
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
Oil (bbls per
day)
|
20,741
|
18,127
|
14 %
|
20,434
|
17,413
|
17 %
|
NGLs (bbls per
day)
|
808
|
695
|
16 %
|
704
|
708
|
(1) %
|
Natural gas (mcf per
day)
|
21,005
|
19,647
|
7 %
|
19,801
|
18,844
|
5 %
|
Total (boe per day)
(6:1)
|
25,050
|
22,097
|
13 %
|
24,438
|
21,262
|
15 %
|
Average realized price
(excluding hedges):
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
84.24
|
91.43
|
(8) %
|
85.86
|
105.87
|
(19) %
|
NGL ($ per
bbl)
|
48.68
|
60.51
|
(20) %
|
50.78
|
64.96
|
(22) %
|
Natural gas ($ per
mcf)
|
2.11
|
5.24
|
(60) %
|
2.34
|
5.46
|
(57) %
|
|
|
|
|
|
|
|
Netback ($ per
boe)
|
|
|
|
|
|
|
Petroleum and natural
gas revenue
|
73.09
|
81.56
|
(10) %
|
75.15
|
93.71
|
(20) %
|
Realized gain (loss) on
commodity and FX contracts
|
1.02
|
(4.71)
|
nmb
|
(0.35)
|
(12.65)
|
(97) %
|
Royalties
|
(13.55)
|
(13.50)
|
— %
|
(13.40)
|
(16.44)
|
(18) %
|
Net operating
expensesa
|
(19.90)
|
(20.98)
|
(5) %
|
(21.13)
|
(19.70)
|
7 %
|
Transportation
expenses
|
(1.48)
|
(1.40)
|
6 %
|
(1.54)
|
(1.45)
|
6 %
|
Operating
netbacka
|
39.18
|
40.97
|
(4) %
|
38.73
|
43.47
|
(11) %
|
G&A
expense
|
(2.19)
|
(2.06)
|
6 %
|
(2.15)
|
(2.14)
|
— %
|
Interest
expense
|
(3.58)
|
(3.59)
|
— %
|
(3.86)
|
(3.50)
|
10 %
|
Adjusted funds
flowa
|
33.41
|
35.32
|
(5) %
|
32.72
|
37.83
|
(14) %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares
outstanding, end of period
|
100,314
|
96,477
|
4 %
|
100,314
|
96,477
|
4 %
|
Weighted average basic
shares outstanding
|
100,314
|
88,094
|
14 %
|
98,790
|
84,619
|
17 %
|
Stock-based
compensation dilution
|
1,808
|
2,097
|
(14) %
|
2,227
|
2,404
|
(7) %
|
Weighted average
diluted shares outstanding
|
102,122
|
90,191
|
13 %
|
101,017
|
87,023
|
16 %
|
|
|
|
|
|
|
|
a This is a
non-GAAP and other financial measure which is defined in the
Non-GAAP and Other Financial Measures section of this
document.
|
b
The Company views this change calculation
as not meaningful, or "nm".
|
c
The three and twelve months ended
December 31, 2023 include a non-cash impairment charge of $59.2
million.
|
OPERATIONS UPDATE
During 2023, Surge successfully drilled a total of 70 gross
(64.5 net) wells spending a total of $181.6
million including expenditures on land, facilities, and
equipment. The Company focused drilling operations primarily on its
light and medium gravity crude oil assets in the Sparky and
SE Saskatchewan core areas.
The 2023 drilling program consisted of 35 gross (35.0 net) wells
in the Sparky core area and 35 gross (29.5 net) wells in SE
Saskatchewan. Included in the Sparky drilling program were 3
gross (3.0 net) multi-lateral wells in Betty Lake, Hope Valley and Provost. The SE Saskatchewan drilling program was focused
in the Frobisher formation - with
31 gross (26.5 net) wells. Ninety percent of the wells
targeting the Frobisher formation
(28 gross wells) were stacked multi-lateral wells.
In Q4/23 Surge achieved an average production rate of 25,050
boepd (86 percent liquids), exceeding the Company's 2023 public
guidance production exit rate of 25,000 boepd. Additionally, Surge
achieved record annual production in 2023 of 24,438 boe/d (86
percent liquids), an increase of 15 percent over 2022 average
production of 21,262 boepd.
The Company achieved record annual production volumes in both
its Sparky and SE Saskatchewan
core operating areas in 2023. Sparky annual volumes grew 23 percent
to average 2023 production of more than 10,900 boepd, and
SE Saskatchewan annual volumes
increased 45 percent to an average 2023 production level of 7,750
boepd.
During 2023, Surge safely executed 8 operated gas plant and oil
battery turnarounds at Valhalla, Provost, Betty Lake,
Lakeview and Steelman. In addition, the Company experienced 4
additional turnarounds at facilities operated by third parties
(including the Sexsmith, Keyera, Steel Reef and TCPL gas plant
turnarounds). Although several of these turnarounds were
budgeted for by the Company, the impact of the unscheduled
turnarounds, in addition to non-core dispositions, reduced
production for 2023 by approximately 450 boepd.
Surge has continued the Company's operational momentum into
early 2024, with 4 drilling rigs active in its Sparky and
SE Saskatchewan core areas. Surge
plans to drill 70 gross (70.0 net) wells in 2024, comprised of 37
gross (37.0 net) Sparky wells and 33 gross (33.0 net) SE Saskatchewan wells, with total capital
expenditures budgeted at $190
million.
In the Sparky core area, Surge's 2024 capital program will
consist of 25 gross (25.0 net) net single-leg frac'ed Sparky
horizontal wells, 8 gross (8.0 net) net multi-leg Sparky wells, and
4 gross (4.0 net) horizontal wells in the Lloydminster formation. In 2024, Management is
focused on the continued growth of Surge's multi-lateral well
footprint in the Mannville stack,
with approximately 30 percent of drilling capital directed to
multi-lateral development.
The Company commenced Surge's winter drilling program in
December of 2023, and has now completed the drilling of 14 gross
(14.0 net) Sparky locations and 15 gross (14.5 net) wells in
SE Saskatchewan. All wells from
both the Q1/24 Sparky and SE
Saskatchewan drilling programs are anticipated to be
completed and on production prior to March
31, 2024.
2023 YEAR-END RESERVES
The Company's reserves were independently evaluated by Sproule
in accordance with National Instrument 51-101 – Standards of
Disclosure for Oil and Gas Activities ("NI 51-101") effective
December 31, 2023. Surge's Annual
Information Form (the "AIF") for the year ended December 31, 2023 contains Surge's reserves data
and other oil and natural gas information as mandated by NI
51-101.
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
reserves report. The evaluation is based on Sproule's forecast
pricing and exchange rates at December 31,
2023 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.
RESERVES SUMMARY AND NET PRESENT VALUE
Gross
Reserves(a)
|
Crude Oil
and NGLs
(Mbbl)(b)
|
Natural
Gas
(MMcf)(c)
|
Oil Equivalent
Total Reserves
(Mboe)
|
Before Tax NPV of
Future Net
Revenue(d) Discounted at
|
5%
($MM)
|
10%
($MM)
|
15%
($MM)
|
Proved:
|
|
|
|
|
|
|
|
Proved
Producing
|
37,864
|
29,696
|
42,814
|
966
|
858
|
766
|
|
Proved
Non-Producing
|
1,667
|
1,639
|
1,940
|
53
|
44
|
38
|
|
Proved
Undeveloped
|
33,959
|
37,262
|
40,170
|
705
|
519
|
390
|
Total
Proved
|
73,491
|
68,597
|
84,924
|
1,724
|
1,421
|
1,193
|
|
Probable
|
27,025
|
28,405
|
31,760
|
859
|
638
|
498
|
Total Proved Plus
Probable
|
100,516
|
97,002
|
116,683
|
2,583
|
2,059
|
1,691
|
a)
|
Amounts may not add due
to rounding.
|
b)
|
Includes light, medium,
heavy and natural gas liquids.
|
c)
|
Includes non-associated
and natural gas, solution gas and coal bed methane.
|
d)
|
Total ADR (Abandonment,
Decommissioning, Reclamation) is included in the reserves report,
as it is best practice as stated in the COGE Handbook.
|
FUTURE DEVELOPMENT CAPITAL ("FDC")
|
|
Total
Proved
|
Total Proved
Plus Probable
|
|
|
($MM)
|
($MM)
|
2024
|
|
130
|
138
|
2025
|
|
207
|
233
|
2026
|
|
208
|
237
|
2027
|
|
163
|
209
|
2028
|
|
117
|
171
|
Remaining
|
|
35
|
51
|
Total
(Undiscounted)
|
|
860
|
1,039
|
Total (Discounted at
10%)
|
|
679
|
806
|
F&D AND FD&A COSTS
|
2023
|
3-Year
Average
|
F&D Costs,
including total change in FDC (a)
Proved Developed
Producing
|
$24.78
|
$17.93
|
Total Proved
|
$22.30
|
$21.43
|
Total Proved +
Probable
|
$51.13
|
$25.58
|
FD&A Costs,
including total change in FDC (b)
Proved Developed
Producing
|
$23.75
|
$20.31
|
Total Proved
|
$21.59
|
$23.12
|
Total Proved +
Probable
|
$50.00
|
$23.94
|
a)
|
2023 FDC costs
calculated using capital of $182 million plus changes in FDC of $26
million (TP) and -$14 million (TPP)
|
b)
|
2023 FDC costs
calculated using capital of $182 million plus changes in FDC of $14
million (TP) and -$36 million (TPP)
|
NET ASSET VALUE
|
PDP
|
TP
|
TPP
|
|
Reserve Value NPV10 BT
($mm)
|
858
|
1,421
|
2,059
|
|
Net Debt
($mm)
|
(290)
|
(290)
|
(290)
|
|
Total Net Assets
($mm)
|
568
|
1,131
|
1,769
|
|
Basic Shares
Outstanding (mm)
|
100.3
|
100.3
|
100.3
|
|
Estimated NAV per Basic
Share ($/share)
|
5.66
|
11.27
|
17.63
|
|
|
|
|
|
|
|
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
As at December 31,
2023
|
|
Canadian
Light
|
Western
Canada
|
Natural
Gas
|
|
|
WTI
|
Sweet
Crude
|
Select (WCS)
Crude
|
AECO-C
|
Exchange
Rate
|
Sproule
|
Cushing,
Oklahoma
|
40°
API
|
20.5
API
|
Spot
|
Forecast(a)
|
($US/bbl)
|
($Cdn/bbl)
|
($Cdn/bbl)
|
($Cdn/mmbtu)
|
($US/$Cdn)
|
Year
|
2023
|
2022
|
2023
|
2022
|
2023
|
2022
|
2023
|
2022
|
2023
|
2022
|
Forecast
|
|
|
|
|
|
|
|
|
|
|
2024
|
$76.00
|
$84.00
|
$97.33
|
$101.25
|
$81.33
|
$89.38
|
$2.33
|
$4.34
|
0.750
|
0.800
|
2025
|
$76.00
|
$80.00
|
$97.25
|
$96.18
|
$84.67
|
$84.06
|
$3.64
|
$4.00
|
0.750
|
0.800
|
2026
|
$76.00
|
$81.60
|
$97.17
|
$98.10
|
$84.33
|
$85.74
|
$3.95
|
$4.08
|
0.750
|
0.800
|
2027
|
$77.52
|
$83.23
|
$99.12
|
$100.06
|
$86.02
|
$87.46
|
$4.03
|
$4.16
|
0.750
|
0.800
|
2028
|
$79.07
|
$84.90
|
$101.10
|
$102.06
|
$87.74
|
$89.21
|
$4.11
|
$4.24
|
0.750
|
0.800
|
2029
|
$80.65
|
$86.59
|
$103.12
|
$104.10
|
$89.50
|
$90.99
|
$4.19
|
$4.33
|
0.750
|
0.800
|
2030
|
$82.26
|
$88.33
|
$105.18
|
$106.18
|
$91.29
|
$92.81
|
$4.27
|
$4.42
|
0.750
|
0.800
|
2031
|
$83.91
|
$90.09
|
$107.29
|
$108.31
|
$93.11
|
$94.67
|
$4.36
|
$4.50
|
0.750
|
0.800
|
2032
|
$85.59
|
$91.89
|
$109.43
|
$110.47
|
$94.97
|
$96.56
|
$4.44
|
$4.59
|
0.750
|
0.800
|
2033
|
$87.30
|
$93.73
|
$111.62
|
$112.68
|
$96.87
|
$98.49
|
$4.53
|
$4.68
|
0.750
|
0.800
|
a) Prices
escalate at two percent after 2033, with the exception of foreign
exchange which stays flat.
|
OUTLOOK: PREMIUM ASSET QUALITY DRIVES SUPERIOR
RETURNS
Surge is a publicly traded intermediate oil company focused on
enhancing shareholder returns through free cash flow generation.
The Company's defined operating strategy is based on owning and
developing high quality, large OOIP, conventional light and medium
gravity crude oil reservoirs, and using proven technology to
enhance ultimate oil recoveries.
Surge has now assembled dominant operational positions in two of
the top four crude oil plays in Canada in its Sparky (>11,500 boepd; 85%
medium gravity oil) and SE
Saskatchewan (~8,000 boepd; 90% light oil) core areas, as
independently evaluated by a leading brokerage firm4.
Over 80 percent of the Company's current production and TPP
NAV now comes from these two core areas.
In the first half of 2024, Surge continues to execute an active
drilling program in both the Sparky and SE Saskatchewan core areas, with 29.7 net
wells budgeted to be drilled.
Surge is well positioned to continue delivering attractive
shareholder returns in 2024 and beyond, based on the following key
corporate fundamentals:
___________________________
|
4 Source:
Peters & Co. Limited (January 16, 2024 North American Oil and
Natural Gas Plays)
|
- Ownership of more than 3.1 billion of net (internally
estimated) OOIP; with an estimated 7.7 percent recovery
factor;
- Estimated 2024 average production 0f 25,000 boepd (87 percent
liquids);
- Estimated 24 percent annual corporate decline1;
- Estimated 2024 cash flow from operating activities of
$295 million5;
- $48 million annual cash dividend
($0.48 per share annual dividend,
paid monthly);
- More than 1,000 (net) internally estimated drilling locations
providing a 13-year drilling inventory3;
- $1.2 billion in tax pools
(approximate 4 year tax horizon at US$75 WTI pricing); and
- Total Proved plus Probable net asset value ("NAV") of
$17.63 per share and Total Proved NAV
of $11.27 per share1.
With cash flow strategically allocated between high rate of
return capital expenditures, debt repayment, and cash dividends
paid to shareholders, Management currently forecasts that the
Company will achieve its previously announced Phase 2 return of
capital net debt target in 2H/24, based on current crude oil
pricing.
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: Surge's declared focus and primary goals; Surge's
reserves, reserve life index, drilling inventory and locations and
decline rates; the Company's commitment to abandonment and
reclamation work; Surge's planned 2024 drilling program and focus;
management's belief that Surge is well positioned to deliver
attractive shareholder returns; the Company's tax horizon; and
management's expectations regarding the timing of the Company
achieving Phase 2 of its return of capital net debt target.
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. Certain of these risks are set out in more
detail in Surge's AIF dated March 6,
2024 and in Surge's MD&A for the period ended
December 31, 2023, both of which have
been filed on SEDAR+ and can be accessed at www.sedarplus.ca.
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.
____________________________
|
5 Pricing
Assumptions: US$75 WTI, US$16 WCS differential, US$3.50 EDM
differential, $0.725 CAD/USD FX and $2.95 AECO.
|
Oil and Gas Advisories
The 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 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" mean barrel of oil equivalent per day. Bbl
means barrel of oil and "bopd" means barrels of oil per day.
NGLs means natural gas liquids.
This press release contains certain oil and gas metrics and
defined terms which do not have standardized meanings or standard
methods of calculation and therefore such measures may not be
comparable to similar metrics/terms presented by other issuers and
may differ by definition and application. All oil and gas
metrics/terms used in this document are defined below:
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. "Internally estimated" means an
estimate that is derived by Surge's internal QRE's and prepared in
accordance with National Instrument 51-101 - Standards of
Disclosure for Oil and Gas Activities. All internal estimates
contained in this news release have been prepared effective as of
January 1, 2024.
Net Asset Value is calculated as reserve value discounted at 10%
on a BTax basis, less Surge's net debt at December 31, 2023 of $290.1 million and is divided by 100.3 million
basic shares.
PDP F&D (Finding & Development) is calculated on the
Capital spent for 2023 development of all properties (other than
those Acquired or Disposed of in 2023), divided by the sum of all
reserve additions other than those from Acquisitions &
Dispositions.
Recycle Ratio is equal to F&D divided by netback.
Finding, Development and Acquisition (FD&A) is the sum of
the Capital spent for 2023 development including Acquisition &
Divestiture properties, plus 2023 total Acquisition &
Disposition capital, plus the delta on Future Development Costs
(from 2022YE vs 2023YE), divided by the sum of all reserve
additions including those from Acquisitions & Dispositions.
Reserve Life Index is calculated as total Company share
reserves divided by Surge's estimated 2024 production (25,000
boe/d).
Sproule's 2023YE reserves have a PDP decline of 29 percent and a
P+PDP decline of 26 percent.
Drilling Inventory
This press release discloses drilling locations in two
categories: (i) booked locations; and (ii) unbooked locations.
Booked locations are proved locations and probable locations
derived from an internal evaluation using standard practices as
prescribed in the Canadian Oil and Gas Evaluations Handbook and
account for drilling locations that have associated proved and/or
probable reserves, as applicable.
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 a January 1, 2024
reference date, the Company will have over >1,150 gross
(>1,050 net) drilling locations identified herein; of these
>615 gross (>575 net) are unbooked locations. Of the 489 net
booked locations identified herein, 397 net are Proved locations
and 92 net are Probable locations based on Sproule's 2023YE
reserves. Assuming an average number of wells drilled per year of
80, Surge's >1,050 net locations provide 13 years of
drilling.
Assuming a January 1, 2024
reference date, the Company will have over >475 gross (>470
net) Sparky Core area drilling
locations identified herein; of these >285 gross (>285 net)
are unbooked locations. Of the 186 net booked locations identified
herein, 140 net are Proved locations and 46 net are Probable
locations based on Sproule's 2023YE reserves. Assuming an average
number of wells drilled per year of 40, Surge's >470 net
locations provide >11 years of drilling.
Assuming a January 1, 2024
reference date, the Company will have over >340 gross (>290
net) SE Sask drilling locations identified herein; of these >160
gross (>140 net) are unbooked locations. Of the 153 net booked
locations identified herein, 122 net are Proved locations and 31
net are Probable locations based on Sproule's 2023YE reserves.
Assuming an average number of wells drilled per year of 40,
Surge's >290 net locations provide >7 years of drilling.
Surge's internally used type curves were constructed using a
representative, factual and balanced analog data set, as of
January 1, 2023. 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,
updated and accounted for on a well-by-well basis by Surge's
Qualifies Reserve Evaluators. All type curves fully comply
with Part 5.8 of the Companion Policy 51 – 101CP.
Non-GAAP and Other Financial Measures
This press release includes references to non-GAAP and other
financial measures used by the Company to evaluate its financial
performance, financial position or cash flow. These specified
financial measures include non-GAAP financial measures and non-GAAP
ratios, are not defined by IFRS and therefore are referred to as
non-GAAP and other financial measures. Certain secondary financial
measures in this press release – namely, "adjusted funds flow",
"adjusted funds flow per share", "adjusted funds flow per boe",
"free cash flow", "net debt", "net operating expenses", "net
operating expenses per boe", "operating netback", and "operating
netback per boe" are not prescribed by GAAP. These non-GAAP and
other 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 and other financial 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 and other financial
measures used in this document are defined below, and as
applicable, reconciliations to the most directly comparable GAAP
measure for the year ended December 31,
2023, have been provided to demonstrate the calculation of
these measures:
Adjusted Funds Flow & Adjusted Funds Flow Per
Share
Adjusted funds flow is a non-GAAP financial measure. The Company
adjusts cash flow from operating activities in calculating adjusted
funds flow for changes in non-cash working capital, decommissioning
expenditures, and cash settled transaction and other costs.
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
property acquisitions and dispositions, debt restructuring and
employee severance costs, which management believes do not reflect
the ongoing cash flows of the business, and as such reduces
comparability. 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 a non-GAAP ratio, calculated
using the same weighted average basic and diluted shares used in
calculating income per share.
|
Three Months Ended
December 31,
|
Years Ended December
31,
|
($000s except per
share amounts)
|
2023
|
2022
|
2023
|
2022
|
Cash flow from
operating activities
|
79,712
|
78,975
|
266,141
|
276,125
|
Change in non-cash
working capital
|
(11,261)
|
(14,152)
|
9,350
|
4,271
|
Decommissioning
expenditures
|
8,255
|
2,367
|
15,560
|
7,895
|
Cash settled
transaction and other costs
|
295
|
4,617
|
795
|
5,264
|
Adjusted funds
flow
|
77,001
|
71,807
|
291,846
|
293,555
|
Per share -
basic
|
$0.77
|
$0.82
|
$2.95
|
$3.47
|
The following table reconciles cash flow from operating
activities to adjusted funds flow and adjusted funds flow per
share:
Free Cash Flow
Free cash flow is a non-GAAP financial measure, calculated as
cash flow from operating activities, before changes in non-cash
working capital, less expenditures on property, plant and equipment
and dividends paid. Management uses free cash flow to determine the
amount of funds available to the Company for future capital
allocation decisions.
Net Debt
Net debt is a non-GAAP financial measure, calculated as bank
debt, term debt, plus the liability component of the convertible
debentures plus current assets, less current liabilities, however,
excluding the fair value of financial contracts, decommissioning
obligations, and lease and other obligations. There is no
comparable measure in accordance with IFRS for net debt. This
metric is used by management to analyze the level of debt in the
Company including the impact of working capital, which varies with
the timing of settlement of these balances.
($000s)
|
As at Dec 31,
2023
|
As at Sep 30,
2023
|
As at Dec 31,
2022
|
Accounts
receivable
|
53,354
|
74,624
|
60,623
|
Prepaid expenses and
deposits
|
5,355
|
3,050
|
3,032
|
Accounts payable and
accrued liabilities
|
(85,390)
|
(83,978)
|
(93,373)
|
Dividends
payable
|
(4,013)
|
(4,013)
|
(3,375)
|
Bank debt
|
(42,797)
|
(11,900)
|
(30,597)
|
Term debt
|
(178,731)
|
(230,624)
|
(256,032)
|
Convertible
debentures
|
(37,848)
|
(33,454)
|
(32,491)
|
Net Debt
|
(290,070)
|
(286,295)
|
(352,213)
|
Net Operating Expenses & Net Operating Expenses per
boe
Net operating expenses is a non-GAAP financial measure,
determined by deducting processing income, 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 when analyzed by management.
Net operating expenses per boe is a non-GAAP ratio, calculated
as net operating expenses divided by total barrels of oil
equivalent produced during a specific period of time.
|
Three Months Ended
December 31,
|
Years Ended December
31,
|
($000s)
|
2023
|
2022
|
2023
|
2022
|
Operating
expenses
|
47,602
|
44,570
|
196,256
|
160,133
|
Less: processing
income
|
(1,734)
|
(1,926)
|
(7,780)
|
(7,242)
|
Net operating
expenses
|
45,868
|
42,644
|
188,476
|
152,891
|
Net operating expenses
($ per boe)
|
19.90
|
20.98
|
21.13
|
19.70
|
Operating Netback, Operating Netback per boe, and Adjusted
Funds Flow per boe
Operating netback is a non-GAAP financial measure, calculated as
petroleum and natural gas revenue and processing and other income,
less royalties, realized gain (loss) on commodity and FX contracts,
operating expenses, and transportation expenses. Operating netback
per boe is a non-GAAP ratio, calculated as operating netback
divided by total barrels of oil equivalent produced during a
specific period of time. There is no comparable measure in
accordance with IFRS. This metric is used by management to evaluate
the Company's ability to generate cash margin on a unit of
production basis.
Adjusted funds flow per boe is a non-GAAP ratio, calculated as
adjusted funds flow divided by total barrels of oil equivalent
produced during a specific period of time.
Operating Netback & Adjusted Funds Flow are Calculated on a
per unit basis as follows:
|
Three Months Ended
December 31,
|
Years Ended December
31,
|
($000s)
|
2023
|
2022
|
2023
|
2022
|
Petroleum and natural
gas revenue
|
168,453
|
165,808
|
670,375
|
727,228
|
Processing and other
income
|
1,734
|
1,926
|
7,780
|
7,242
|
Royalties
|
(31,235)
|
(27,449)
|
(119,513)
|
(127,548)
|
Realized gain (loss) on
commodity and FX contracts
|
2,351
|
(9,580)
|
(3,164)
|
(98,145)
|
Operating
expenses
|
(47,602)
|
(44,570)
|
(196,256)
|
(160,133)
|
Transportation
expenses
|
(3,411)
|
(2,846)
|
(13,755)
|
(11,272)
|
Operating
netback
|
90,290
|
83,289
|
345,467
|
337,372
|
G&A
expense
|
(5,041)
|
(4,190)
|
(19,158)
|
(16,626)
|
Interest
expense
|
(8,248)
|
(7,292)
|
(34,463)
|
(27,191)
|
Adjusted funds
flow
|
77,001
|
71,807
|
291,846
|
293,555
|
Barrels of oil
equivalent (boe)
|
2,304,615
|
2,032,892
|
8,920,018
|
7,760,455
|
Operating netback ($
per boe)
|
$39.18
|
$40.97
|
$38.73
|
$43.47
|
Adjusted funds flow ($
per boe)
|
$33.41
|
$35.15
|
$32.72
|
$37.83
|
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.