CALGARY, AB, March 12, 2021 /CNW/ - Spartan Delta
Corp. ("Spartan" or the "Company") (TSXV:
SDE); (TSXV: SDE.R) is pleased to announce its financial and
operating results for the fourth quarter and year ended
December 31, 2020, as well as its
independent oil and gas reserves evaluation as of December 31, 2020, prepared by McDaniel &
Associates Consultants Ltd. (the "McDaniel Report").
Corporate Milestones Achieved Since the
Recapitalization of Spartan Delta Corp. in December 2019
- Completed a transformational Spirit
River and Cardium asset acquisition in June 2020, which included ~25,000 boe/d of
production in west central Alberta, consisting of ~250 bbls/d of crude
oil, ~1,000 bbls/d of condensate, ~6,500 bbls/d of NGLs and ~103.5
MMcf/d of conventional natural gas.
- Maintained production at 26,141 boe/d on average during the
second half of 2020, consisting of ~330 bbls/d of crude oil, ~1,100
bbls/d of condensate, ~6,800 bbls/d of NGLs and ~107.5 MMcf/d of
conventional natural gas, through low-cost field optimization,
which more than offset normal corporate declines.
- Reduced operating costs by 18% in less than three quarters of
operating the properties acquired in June
2020.
- Established a $100 million
syndicated credit facility and successfully accessed capital
markets raising aggregate gross proceeds of $213 million from equity financings since the
inception in December 2019, inclusive
of a $124 million financing expected
to be completed in March 2021.
- Recently closed three small acquisitions and executed
definitive agreements for two additional acquisitions which are
collectively expected to add ~9,500 boe/d of run-rate production,
consisting of ~2,090 bbls/d of crude oil, ~475 bbls/d of
condensate, ~760 bbls/d of NGLs and ~37.05 MMcf/d of conventional
natural gas.
- Added a new core development and consolidation area with a
material entry into the Alberta Montney.
Selected Financial and Operational Information
Selected financial and operational information is set out below
and should be read in conjunction with Spartan's audited annual
consolidated financial statements and related management's
discussion and analysis ("MD&A") for the years ended
December 31, 2020 and 2019, which are
available on the Company's website at
www.spartandeltacorp.com and filed on SEDAR at
www.sedar.com.
|
Three months ended
December 31
|
Year ended December
31
|
(CA$ thousands,
except as otherwise indicated)
|
2020
|
2019
|
2020
|
2019
|
|
|
|
|
|
OPERATING
|
|
|
|
|
Average daily
production
|
|
|
|
|
Crude oil
(bbls/d)
|
332
|
25
|
196
|
26
|
Condensate (bbls/d)
(1)
|
1,131
|
-
|
656
|
-
|
NGLs (bbls/d)
(1)
|
6,728
|
20
|
3,965
|
15
|
Natural gas
(Mcf/d)
|
106,912
|
1,070
|
63,625
|
1,102
|
Combined
(boe/d)
|
26,010
|
223
|
15,421
|
225
|
Average realized
prices, before financial instruments
|
|
|
|
|
Crude oil
($/bbl)
|
47.95
|
54.14
|
46.03
|
61.76
|
Condensate ($/bbl)
(1)
|
54.46
|
-
|
51.39
|
-
|
NGLs ($/bbl)
(1)
|
18.35
|
53.39
|
16.74
|
54.13
|
Natural gas
($/Mcf)
|
2.72
|
2.20
|
2.42
|
1.51
|
Combined average
($/boe)
|
18.89
|
21.33
|
17.07
|
18.18
|
Operating and
Corporate Netbacks ($/boe) (2)
|
|
|
|
|
Oil and gas sales,
before financial instruments
|
18.89
|
21.33
|
17.07
|
18.18
|
Realized loss on
financial instruments
|
(0.90)
|
-
|
(0.17)
|
-
|
Oil and gas sales,
after financial instruments
|
17.99
|
21.33
|
16.90
|
18.18
|
Processing and other
revenue
|
0.66
|
1.78
|
0.60
|
1.66
|
Royalties
|
(2.01)
|
(0.15)
|
(1.57)
|
0.26
|
Operating
expenses
|
(5.68)
|
(30.91)
|
(6.11)
|
(24.58)
|
Transportation
expenses
|
(1.37)
|
-
|
(1.36)
|
-
|
Operating Netback
(2)
|
9.59
|
(7.95)
|
8.46
|
(4.48)
|
General and
administrative expenses
|
(1.48)
|
(27.19)
|
(1.64)
|
(17.13)
|
Interest expense, net
of interest income
|
(0.19)
|
-
|
(0.21)
|
-
|
Corporate Netback
(2)
|
7.92
|
(35.14)
|
6.61
|
(21.61)
|
FINANCIAL
|
|
|
|
|
Oil and gas
sales
|
45,206
|
437
|
96,324
|
1,491
|
Cash provided by
(used in) operating activities
|
16,064
|
(599)
|
32,209
|
(1,298)
|
Adjusted Funds from
Operations (2)
|
18,939
|
(723)
|
37,308
|
(1,772)
|
$ per share,
basic
|
0.33
|
(0.16)
|
0.83
|
(0.89)
|
$ per share,
diluted
|
0.28
|
(0.16)
|
0.67
|
(0.89)
|
Net income (loss) and
comprehensive income (loss)
|
12,358
|
(60)
|
47,663
|
(1,998)
|
$ per share,
basic
|
0.21
|
(0.01)
|
1.06
|
(1.00)
|
$ per share,
diluted
|
0.18
|
(0.01)
|
0.86
|
(1.00)
|
Capital expenditures,
net of dispositions
|
14,346
|
29
|
125,869
|
(231)
|
Total
assets
|
331,430
|
34,245
|
331,430
|
34,245
|
Net Debt (Surplus)
(2)
|
12,292
|
(23,538)
|
12,292
|
(23,538)
|
Shareholders'
equity
|
137,540
|
25,640
|
137,540
|
25,640
|
Common shares
outstanding (000s) (3)
|
|
|
|
|
Weighted average,
basic
|
58,220
|
4,638
|
44,848
|
1,996
|
Weighted average,
diluted
|
68,859
|
4,638
|
55,403
|
1,996
|
End of
period
|
58,226
|
26,106
|
58,226
|
26,106
|
(1)
|
Condensate is a
natural gas liquid as defined by NI 51-101. See "Reader
Advisories – Other Measurements".
|
(2)
|
"Operating Netback",
"Corporate Netback", "Adjusted Funds from Operations" and "Net Debt
(Surplus)" do not have standardized meanings under IFRS. See
"Reader Advisories – Non-GAAP Measures".
|
(3)
|
See "Reader
Advisories – Share Capital".
|
Fourth Quarter 2020 Financial and Operational
Highlights
- Development Execution: Spartan drilled four and brought
on production two extended reach horizontal Spirit River wells at Ferrier, Alberta during the fourth quarter and
subsequently drilled and completed the remainder of the eight-well
winter program in the first quarter of 2021. The winter drilling
program was delivered ahead of schedule and below budget with six
wells having produced, on restricted production for operational
efficiencies and decline management purposes, at an average IP30 of
1,580 boe/d, consisting of 93 bbls/d condensate, 370 bbls/d NGLs
and 6.85 MMcf/d conventional natural gas. Two of these wells have
produced for more than two months at an average IP60 of 1,526
boe/d, consisting of 82 bbls/d condensate, 345 bbls/d NGLs and 6.53
MMcf/d conventional natural gas.
- Production Optimization: Maintained fourth quarter 2020
production volumes of 26,010 boe/d, in-line with third quarter 2020
volumes, primarily through production optimization as the Company's
first two new wells were brought onstream in mid-December. (See
"Selected Financial and Operational Information" for
breakdown by product type)
- Improved Operating Netback: Spartan's Operating Netback
increased by 15% and averaged $9.59/boe for the fourth quarter of 2020, up from
$8.32/boe in the third quarter of
2020. The improved operating netback reflects the decrease in per
unit operating costs in conjunction with stronger commodity prices,
partly offset by higher royalties. (See "Reader Advisories –
Non-GAAP Measures", below)
- Strong Cash Flows: The Company generated Adjusted Funds
from Operations of $18.9 million
($0.33 per share, basic and
$0.28 per share, diluted) during the
fourth quarter of 2020, resulting in a Corporate Netback of
$7.92/boe. Free Funds Flow was
$2.8 million after leases,
decommissioning and $14.0 million of
capital expenditures. (See "Reader Advisories – Non-GAAP
Measures", below)
- Operational Excellence: Spartan generated meaningful
cost savings and reduced its operating expenses each consecutive
quarter during 2020, highlighting the successful integration of the
acquired assets and impact of the Company's strategic initiatives.
Operating expenses averaged $5.68/boe
for the quarter ended December 31,
2020, down 7% from $6.10/boe
during the previous quarter and down 18% since the acquisition of
the Company's west central Alberta
assets in the second quarter of 2020.
- Balance Sheet Strength: Spartan exited the fourth
quarter with its credit facility undrawn and an authorized
borrowing amount of $100.0 million.
Spartan had Net Debt of $12.3 million
as at December 31, 2020. (See
"Reader Advisories – Non-GAAP Measures", below)
2020 Reserve Evaluation Highlights
Spartan is pleased to provide highlights of the Company's
December 31, 2020 reserves from the
McDaniel Report, below. The results of the McDaniel Report
are reflective of Spartan's significant acquisition in West Central
Alberta, making up a majority of the Company's reserves in 2020.
The West Central reserves were reconfigured in 2020 to capitalize
on extended reach horizontal drilling techniques ("ERH") and
to adjust booked locations to more accurately reflect the near-term
development plans of the Company post-acquisition.
- 72% of the 101 booked locations and 56% of the total inventory
are ERH.
- Reconfiguring to ERH has made booked locations more efficient,
economic and reduced the environmental impact of the
development:
-
- Approximately a 70% increase in IRR, while only increasing
capital cost by 25% when compared to conventional bookings of
one-mile horizontals; (See "Reader Advisories – Non-GAAP
Measures")
- Go-forward estimated undeveloped finding and development
("F&D") costs has been decreased considerably with
proved undeveloped F&D costs equal to $3.94 and proved plus probable undeveloped
F&D costs equal to $3.35;
and
- Go-forward proved undeveloped recycle ratio of 2.4x and proved
plus probable undeveloped recycle ratio of 2.9x.
- Future development capital ("FDC") totaled $266.5 million in the total proved category with
63 net locations and $417.3 million
in the total proved plus probable category with 101 net
locations.
- The Company has over 425 Spirit River and Cardium locations in
inventory (>75% unbooked).
- Before-tax net present value ("NPV") of reserves,
discounted at 10%, is $375.9 million
on a proved developed producing basis, $777.3 million on a total proved basis, and
$1.1 billion on a total proved plus
probable basis.
- Approximately 33% of the Company's reserves are in the proved
developed producing category and 65% of the reserves are in the
total proved category.
See "Reader Advisories – Oil and Gas Advisories".
2020 Independent Qualified Reserve Evaluation
The following tables highlight the findings of the McDaniel
Report, which has been prepared in accordance with the definitions,
standards and procedures contained in National Instrument 51-101 –
Standards of Disclosure for Oil and Gas Activities ("NI
51-101") and the most recent publication of the Canadian Oil
and Gas Evaluation Handbook. The McDaniel Report was based on the
average forecast pricing of McDaniel, GLJ Ltd. and Sproule
Associates Limited. See "Reader Advisories – Oil and Gas
Advisories" for more information. Additional reserves
information as required under NI 51-101 will be included in
Spartan's Annual Information Form, which will be filed on SEDAR on
or before March 30, 2021. The numbers
in the tables below may not add due to rounding.
Summary of Oil and Natural Gas Reserves as at December 31, 2020
|
Crude Oil Lt.
& Med.
|
Conventional
Natural Gas
|
Coal Bed
Methane
|
Natural Gas
Liquids
|
Total
|
Reserves
Categories
|
Gross
(Mbbl)
|
Net
(Mbbl)
|
Gross
(MMcf)
|
Net
(MMcf)
|
Gross
(MMcf)
|
Gross
(MMcf)
|
Gross
(Mbbl)
|
Net
(Mbbl)
|
Gross
(Mboe)
|
Net
(Mboe)
|
Proved:
|
|
|
|
|
|
|
|
|
|
|
Developed Producing
|
878
|
806
|
276,731
|
242,510
|
559
|
473
|
20,196
|
16,205
|
67,289
|
57,508
|
Developed Non-Producing
|
1
|
1
|
177
|
144
|
-
|
-
|
7
|
4
|
37
|
29
|
Undeveloped
|
1,719
|
1,440
|
279,507
|
259,265
|
-
|
-
|
19,348
|
16,354
|
67,651
|
61,005
|
Total
Proved
|
2,598
|
2,247
|
556,414
|
501,919
|
559
|
473
|
39,551
|
32,563
|
134,977
|
118,542
|
Probable
|
2,451
|
1,965
|
290,631
|
264,176
|
151
|
128
|
21,051
|
17,416
|
71,965
|
63,432
|
Total Proved plus
Probable
|
5,048
|
4,212
|
847,045
|
766,095
|
710
|
601
|
60,601
|
49,979
|
206,942
|
181,974
|
|
|
|
|
|
|
|
|
|
|
|
|
%
Change
|
2020
|
2019
|
2018
|
Reserves
(Mboe)
|
|
|
|
|
Proved Developed
Producing ("PDP")
|
>1,000%
|
67,289
|
507
|
604
|
Total Proved
("1P")
|
>1,000%
|
134,977
|
1,671
|
1,112
|
Total Proved plus
Probable ("2P")
|
>1,000%
|
206,942
|
3,314
|
2,353
|
PDP as % of
2P
|
120%
|
33%
|
15%
|
26%
|
1P as % of
2P
|
30%
|
65%
|
50%
|
47%
|
Reserve Life Index
(1) (years)
|
|
|
|
|
PDP
|
15%
|
7.1
|
6.2
|
7.2
|
1P
|
(31%)
|
14.2
|
20.5
|
13.3
|
2P
|
(46%)
|
21.8
|
40.7
|
28.2
|
(1)
|
RLI is calculated as
total Company share reserves divided by the annualized fourth
quarter actual production of 26,010 boe/d. See "Reader
Advisories – Oil and Gas Advisories".
|
Net Present Value of Future Net Revenue as at December 31, 2020 (Before Income Tax)
Reserves
Category
|
0%
($M)
|
5%
($M)
|
10%
($M)
|
15%
($M)
|
20%
($M)
|
Unit
Value(1) Before Tax
Discounted at
10%/Year
($/boe)
|
Unit Value
(1) Before Tax
Discounted
at 10%/Year
($/Mcfe)
|
Proved:
|
|
|
|
|
|
|
|
Developed Producing
|
440,816
|
440,426
|
375,938
|
324,359
|
286,270
|
6.54
|
1.09
|
Developed Non-Producing
|
112
|
96
|
83
|
73
|
64
|
2.88
|
0.48
|
Undeveloped
|
835,220
|
558,130
|
401,286
|
303,493
|
237,920
|
6.58
|
1.10
|
Total
Proved
|
1,276,147
|
998,652
|
777,307
|
627,926
|
524,254
|
6.56
|
1.09
|
Probable
|
1,001,067
|
512,426
|
300,803
|
194,061
|
133,645
|
4.74
|
0.79
|
Total Proved plus
Probable
|
2,277,214
|
1,511,078
|
1,078,110
|
821,986
|
657,899
|
5.92
|
0.99
|
(1)
|
Unit values are based
on net reserves. Net reserves means the Corporation's working
interest reserves after deduction of royalties, plus its royalty
interests in reserves.
|
Forecast Prices Used in Estimates
The forecast cost and price assumptions assume increases in
wellhead selling prices and take into account inflation with
respect to future operating and capital costs. Crude oil and
natural gas benchmark reference pricing, inflation and exchange
rates utilized in the McDaniel Report were McDaniel's forecasts, as
at December 31, 2020, as follows:
Year
|
Crude Oil
WTI
Cushing
Oklahoma
(US$/bbl)
|
Edmonton
Light
Crude Oil
(C$/bbl)
|
Western
Canadian
Select
(C$/bbl)
|
Edmonton
Ethane
(C$/bbl)
|
Edmonton
Propane
(C$/bbl)
|
Edmonton
Butane
(C$/bbl)
|
Edmonton
Cond. &
Natural
gasoline
(C$/bbl)
|
Alberta
AECO Spot
Price
(C$/MMBtu)
|
Inflation
Rate
(%/Year)
|
Exchange
Rate
(US$/C$)
|
2021
|
47.17
|
55.76
|
44.63
|
8.91
|
18.18
|
26.36
|
59.24
|
2.78
|
0.00
|
0.7680
|
2022
|
50.17
|
59.89
|
48.18
|
8.65
|
21.91
|
32.85
|
63.19
|
2.70
|
1.30
|
0.7650
|
2023
|
53.17
|
63.48
|
52.10
|
8.35
|
24.57
|
39.20
|
67.34
|
2.61
|
2.00
|
0.7630
|
2024
|
54.97
|
65.76
|
54.10
|
8.46
|
25.47
|
40.65
|
69.77
|
2.65
|
2.00
|
0.7630
|
2025
|
56.07
|
67.13
|
55.19
|
8.63
|
26.00
|
41.50
|
71.18
|
2.70
|
2.00
|
0.7630
|
Reserves Reconciliation
The following sets out the reconciliation of Spartan's gross
reserves (1) based on forecast prices and costs by
principal product type as at December 31,
2020.
|
Lt & Med Crude
Oil
|
Heavy Crude
Oil
|
Total Crude
Oil
|
|
Proved
(MBbl)
|
Probable
(MBbl)
|
Proved
and
Probable
(MBbl)
|
Proved
(MBbl)
|
Probable
(MBbl)
|
Proved
and
Probable
(MBbl)
|
Proved
(MBbl)
|
Probable
(MBbl)
|
Proved
and
Probable
(MBbl)
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
656
|
801
|
1,457
|
-
|
-
|
-
|
656
|
801
|
1,457
|
Extensions &
Improved Recovery
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Technical
Revisions (2)
|
(592)
|
166
|
(426)
|
-
|
-
|
-
|
(592)
|
166
|
(426)
|
Acquisitions
|
2,605
|
1,483
|
4,088
|
-
|
-
|
-
|
2,605
|
1,483
|
4,088
|
Dispositions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Economic
Factors
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Production
|
(72)
|
-
|
(72)
|
-
|
-
|
-
|
(72)
|
-
|
(72)
|
December 31,
2020
|
2,597
|
2,450
|
5,048
|
-
|
-
|
-
|
2,597
|
2,450
|
5,048
|
|
|
|
|
|
|
|
|
|
|
|
NGL
|
Conventional
Natural Gas
|
Total
|
|
Proved
(Mbbl)
|
Probable
(Mbbl)
|
Proved +
Probable
(MBbl)
|
Proved
(MMcf)
|
Probable
(MMcf)
|
Proved +
Probable
(MMcf)
|
Proved
(Mboe)
|
Probable
(Mboe)
|
Proved +
Probable
(Mboe)
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
76
|
61
|
137
|
5,631
|
4,689
|
10,320
|
1,670
|
1,644
|
3,314
|
Extensions &
Improved Recovery
|
1,354
|
339
|
1,693
|
12,859
|
3,216
|
16,075
|
3,497
|
875
|
4,372
|
Technical
Revisions (2)
|
77
|
44
|
121
|
(2,575)
|
1,637
|
(938)
|
(944)
|
483
|
(461)
|
Acquisitions
|
39,735
|
20,606
|
60,342
|
564,345
|
281,239
|
845,584
|
136,398
|
68,963
|
205,361
|
Dispositions
|
|
-
|
|
|
-
|
-
|
-
|
-
|
|
Economic
Factors
|
|
-
|
|
|
-
|
-
|
-
|
-
|
|
Production
|
(1,691)
|
-
|
(1,691)
|
(23,287)
|
-
|
(23,287)
|
(5,644)
|
-
|
(5,644)
|
December 31,
2020
|
39,551
|
21,050
|
60,601
|
556,973
|
290,781
|
847,754
|
134,977
|
71,965
|
206,942
|
(1)
|
Gross Reserves means
the Corporation's working interest reserves before calculation of
royalties and before consideration of the Corporation's royalty
interests.
|
(2)
|
Technical Revisions
also include changes in reserves associated with changes in
operating costs, capital costs and commodity price
offsets.
|
Future Development Capital Costs
The following table is McDaniel estimated future development
capital required to bring total proved and total proved plus
probable reserves on production.
Year
|
Total Proved
Reserves ($M)
|
Total Proved Plus
Probable Reserves ($M)
|
2021
|
44,921
|
44,892
|
2022
|
44,519
|
44,519
|
2023
|
47,335
|
47,335
|
2024
|
68,581
|
68,581
|
2025
|
61,122
|
61,122
|
Thereafter
|
-
|
150,856
|
Total
|
266,478
|
417,305
|
10%
Discounted
|
209,496
|
296,124
|
Performance Measures (Including FDC)
The following table highlights our 1P/2P Future Undeveloped
F&D costs and associated recycle ratios, including FDC, based
on the evaluation of our petroleum and natural gas reserves
prepared by McDaniel.
Future Undeveloped
F&D Costs
|
|
|
|
|
|
Proved
Undeveloped
|
|
|
Future Development
Capital
|
$M
|
266,478
|
Undeveloped
Reserves
|
Mboe
|
67,651
|
1P F&D
(1)
|
$/boe
|
3.94
|
Recycle Ratio
(2)
|
|
2.4x
|
|
|
|
Proved plus
Probable Undeveloped
|
|
|
Future Development
Capital
|
$M
|
417,305
|
Undeveloped
Reserves
|
Mboe
|
124,400
|
2P F&D
(1)
|
$/boe
|
3.35
|
Recycle Ratio
(2)
|
|
2.9x
|
(1)
|
Undeveloped F&D
costs are calculated as the sum of FDC divided by undeveloped
reserves. See "Reader Advisories – Oil and Gas
Advisories".
|
(2)
|
Recycle ratio is
calculated as the fourth quarter 2020 operating netback of
$9.59/boe divided by 1P or 2P F&D costs, as applicable. See the
selected financial and operational information table, above, for
the assumptions used to calculate Q4 2020 operating netback and
"Reader Advisories – Non-GAAP Measures" for more
information.
|
Outlook and Guidance
On February 16, 2021, Spartan
announced that the Company entered into definitive agreements with
respect to three strategic acquisitions (the
"Acquisitions"), the completion of which will create a new
core development and consolidation area for the Company and a
material entry in the Alberta Montney. The Acquisitions include:
(a) assets in the Alberta Montney fairway, including the corporate
acquisition of Inception Exploration Ltd. (the "Inception
Acquisition") and the purchase of assets located primarily in
the Simonette area of northwest Alberta (the "Simonette Acquisition");
and (b) the acquisition of a tuck-in asset in the Company's West
Central core area, which closed on March 5,
2021 (the "Willesden Green Acquisition"). The
Inception Acquisition and Simonette Acquisition are expected to
close on or about March 18, 2021.
As part of the Company's press release dated February 16, 2021, Spartan also announced
intentions to complete an $80.0
million equity financing and provided revised corporate
guidance for 2021 which reflected the Company's preliminary
operating and financial forecast after giving effect to the
proposed Acquisitions and financing. The initial equity financing
was comprised of a $50.0 million
non-brokered private placement and a $30.0
million bought deal prospectus offering. Subsequent to the
initial announcement, the equity financings were upsized by 55% to
aggregate gross proceeds of $124.0
million, comprised of a $79.0
million non-brokered private placement and a $45.0 million bought deal prospectus offering
(together, the "2021 Financings"). The 2021 Financings are
expected to be completed concurrently with, and are conditional
upon, the successful completion of the Inception Acquisition.
Based on the recent rise in crude oil and NGL prices, additional
proceeds from the upsized 2021 Financings and minor revisions to
the expected timing and allocation of budgeted capital
expenditures, the Company has further revised its operating and
financial guidance for 2021. The revised guidance outlined below
was approved by the Company's board of directors on March 11, 2021.
Spartan's 2021 capital expenditures are estimated to be
approximately $101.0 million
(unchanged from previous guidance). Leveraging Spartan's strategic
infrastructure position including the infrastructure to be acquired
with the Acquisitions, the capital expenditure program will be
focused on the execution and acceleration of drill-ready
development across the Company's core properties targeting the
Montney, Spirit River, and Cardium formations.
Spartan expects 2021 production to average between 35,500 to
37,500 boe/d (previous guidance 35,000 to 37,000 BOE per day, see
notes to below table for a breakdown by product type). The
Company's organic development program, supplemented with production
from the Acquisitions, is expected to deliver approximately 40%
production growth in 2021 compared to average production of 26,010
boe/d during the fourth quarter of 2020 (see table under
"Selected Financial and Operational Information", above, for
a breakdown by product type).
The Company expects to generate approximately $139.0 million of Adjusted Funds Flow in 2021, up
from previous guidance of $122.0
million (see "Reader Advisories - Non-GAAP
Measures"). The increase in forecasted Adjusted Funds Flow is
primarily driven by the increase in forecast oil prices to
US$55.00 per barrel for WTI
(previously US$50.00 per barrel) as
well as the corresponding impact on NGL pricing. Spartan's forecast
of $2.75 per GJ for AECO natural gas
is unchanged. Reallocation of capital within the budget as well as
minor changes in expected "on-stream" dates also contributed to the
increase in forecasted Adjusted Funds Flow.
Spartan is now forecasting its Net Surplus to be approximately
$115.0 million at the end of 2021
compared to previous guidance of $54.0
million. The increase in forecasted Net Surplus reflects the
$17.0 million increase in forecast
Adjusted Funds Flow and $44.0 million
of additional proceeds from the upsized 2021 Financings. Spartan
expects to use its cash surplus to continue executing on the
Company's targeted acquisition and consolidation strategy. (See
"Reader Advisories - Non-GAAP Measures")
The table below outlines Spartan's revised 2021 guidance
compared to previous guidance published in the Company's press
release dated February 16, 2021:
2021
GUIDANCE
|
Revised
Guidance
|
Previous
Guidance
|
%
Change
|
Average Production
(BOE/d) (1)(3)
|
35,500 –
37,500
|
35,000 –
37,000
|
1
|
% Oil and
NGLs
|
31%
|
31%
|
-
|
Forecast Average
Commodity Prices
|
|
|
|
WTI oil price
(US$/bbl)
|
55.00
|
50.00
|
10
|
Edmonton condensate
($/bbl)
|
67.93
|
60.96
|
11
|
Conway propane
(US$/gal)
|
0.71
|
0.65
|
9
|
AECO 5A natural gas
price ($/GJ)
|
2.75
|
2.75
|
-
|
Average exchange rate
(CA$/US$)
|
1.26
|
1.27
|
(1)
|
Operating Netback
($/BOE) (1)(2)(3)(4)
|
12.74
|
11.59
|
10
|
Adjusted Funds Flow
($MM) (1)(2)(3)(4)
|
139
|
122
|
14
|
Capital expenditures,
excluding A&D ($MM) (5)
|
101
|
101
|
-
|
Free Funds Flow ($MM)
(4)
|
38
|
20
|
90
|
Net Debt (Surplus),
end of year ($MM) (4)(6)
|
(115)
|
(54)
|
113
|
Common shares
outstanding, end of 2021 (MM) (7)
|
114
|
104
|
10
|
(1)
|
Production guidance
is post-completion of the Acquisitions and consists of
approximately 4% crude oil, 4% condensate, 23% NGLs and 69% natural
gas (product weighting is unchanged from previous
guidance). The forecasted financial guidance and percentage
change is based on the midpoint of revised production guidance of
36,500 boe/d (previously 36,000 boe/d).
|
(2)
|
In addition to the
forecast of benchmark commodity prices outlined above, the guidance
includes the following significant assumptions for 2021: royalties
are expected to average 11% of oil and gas sales; budgeted
operating and transportation expenses are expected to average
$6.09/boe and $1.53/boe, respectively; G&A is budgeted to
average $1.35/boe; and cash interest expense is budgeted to average
$0.07/boe (unchanged from previous guidance in all material
respects, minor differences in per unit estimates due to higher
volumes).
|
(3)
|
Assumes the Inception
Acquisition and Simonette Acquisition close on March 18,
2021.
|
(4)
|
Operating Netback,
Adjusted Funds Flow, Free Funds Flow and Net Debt (Surplus) do not
have a prescribed meaning under IFRS. Refer to "Reader
Advisories - Non-GAAP Measures".
|
(5)
|
The forecast of
capital expenditures excludes acquisitions. The aggregate
amount of cash consideration related to acquisitions completed
to-date and expected to be completed in 2021 is estimated to be
approximately $26.3 million, net of closing adjustments and working
capital.
|
(6)
|
Net Debt (Surplus)
does not include a $50.0 million unsecured non-interest bearing
convertible promissory note (the "Convertible Note") to be
issued in connection with the Inception Acquisition. The
Convertible Note will mature five years from the closing of the
Inception Acquisition, and will be convertible in whole or in part
beginning on the day that is two years following the closing of the
Inception Acquisition, at the Company's election, for such number
of common shares calculated based on the greater of: (i) the volume
weighted average trading price of the common shares for the 10
trading days immediately preceding the delivery by the Company of a
notice of conversion to the Inception Shareholder; and (ii) $7.67,
being two times the deemed issuance price of the common shares
under the Inception Acquisition. The Convertible Note will be
"in-the-money" during all periods in which Spartan's share price is
less than $7.67. Spartan intends to settle the Convertible Note in
the future by exercising the Company's conversion option and the
maximum number of Spartan common shares issuable on conversion is
6,518,905 common shares.
|
(7)
|
The forecast number
of common shares outstanding assumes the Acquisitions and 2021
Financings close and does not include common shares potentially
issuable in respect of dilutive securities (see "Reader
Advisories – Share Capital").
|
Spartan's guidance is contingent upon the successful completion
of the Inception Acquisition, Simonette Acquisition and the 2021
Financings (see "Reader Advisories – Forward-Looking
Statements"). In addition, changes in forecast commodity
prices, differences in the timing of capital expenditures, and
variances in average production estimates can have a significant
impact on the key performance measures included in the budget. The
Company's actual results may differ materially from these
estimates. Holding all other assumptions constant for 2021: if the
forecast for AECO natural gas increased (decreased) by $0.25/GJ, the Adjusted Funds Flow forecast for
2021 would increase (decrease) by approximately $7.0 million; or, if the WTI crude oil reference
price forecast increased (decreased) by US$5.00/bbl, the Adjusted Funds Flow forecast for
2021 would increase (decrease) by approximately $9.0 million. Assuming capital expenditures are
unchanged, the impact on Free Funds Flow and resulting Net Debt
(Surplus) would be equivalent to the increase or decrease in
Adjusted Funds Flow.
Share Award Grants
On August 19, 2020, the Board of
Directors of the Company approved a Share Award Incentive Plan (the
"Plan"). The Plan is intended to assist in retaining and
engaging the directors, officers and any future employees of the
Company and to provide additional incentive to these individuals
for their efforts on behalf of the Company. The Plan allows
the Company to issue restricted share awards ("RSAs") and
performance share awards ("PSAs"), provided that the
aggregate number of common shares that may be issuable pursuant to
the Plan does not exceed 2,900,000. The Plan is subject to the
approval of the TSX Venture Exchange and the formal approval of the
Plan by the shareholders of the Company at the next annual general
meeting.
Effective March 11, 2021, the
Company has issued a total of 984,100 options under its existing
stock option plan and 1,180,800 RSAs under the Plan to officers and
directors of the Company. The options each have an exercise price
of $4.08 per share, are exercisable
for a period of 5 years and vest in one third increments on the
first, second and third anniversaries from the date of grant. The
RSAs each vest in one third increments on the first, second and
third anniversaries from the date of grant. Each RSA was valued at
$4.08 per share. The grant of the
RSAs is subject to final regulatory and shareholder approval of the
Plan.
Promotions
In recognition of their continued strong contributions to
operations in their respective disciplines, Spartan is pleased to
announce the promotion of Brendan
Paton, from Manager, Engineering to Vice President,
Engineering and Ashley Hohm, from
Manager, Finance and Controller to Vice President, Finance and
Controller.
Updated Corporate Presentation
An updated corporate presentation has been posted on the
Company's website along with this morning's fourth quarter results
release.
About Spartan Delta Corp.
Spartan is a differentiated energy company whose ESG-focused
culture is centered on generating sustainable free funds flow
through oil and gas exploration and development. Building on
its existing high-quality, low-decline operated production in the
heart of the Alberta Deep Basin and Alberta Montney, Spartan
intends to continue acquiring undervalued, diversified assets that
can be restructured, optimized and rebranded, financially or
operationally, yielding accretion to shareholder value. With excess
infrastructure capacity, the Company is well positioned to continue
pursuing immediate production optimization and responsible future
growth. Further detail is available in Spartan's March corporate
presentation, which can be accessed on its website at
www.spartandeltacorp.com.
READER ADVISORIES
Share Capital
Spartan's common shares trade on the TSX Venture exchange
("TSXV") under the symbol "SDE". The volume weighted average
trading price of the Company's common shares on the TSXV for the
three and twelve month periods ended December 31, 2020 was $2.95 and $2.91,
respectively.
The Company uses the treasury stock method to determine the
impact of dilutive securities in accordance with International
Financial Reporting Standards ("IFRS"). Under this method,
only "in-the-money" dilutive instruments impact the calculation of
the diluted shares outstanding. The treasury stock method assumes
that the proceeds received from the exercise of all potentially
dilutive instruments are used to repurchase common shares at the
average market price during the period. In computing diluted net
income per share and Adjusted Funds from Operations per share for
the fourth quarter and year ended December
31, 2020, the effect of stock options was excluded because
they were not in-the-money based on the volume weighted average
trading price of the Company's common shares during the
periods.
As of the date hereof, the Company has 60.2 million common
shares outstanding, 16.1 million common share purchase warrants
outstanding with an exercise price of $1.00 per share, and 3.4 million stock options
outstanding with an average exercise price of $3.00 per share.
Non-GAAP Measures
This release contains certain financial measures, as described
below, which do not have standardized meanings prescribed by IFRS
or Generally Accepted Accounting Principles ("GAAP"). As
these non-GAAP financial measures are commonly used in the oil and
gas industry, the Company believes that their inclusion is useful
to investors. The reader is cautioned that these amounts may not be
directly comparable to measures for other companies where similar
terminology is used. The non-GAAP measures used in this release,
represented by the capitalized and defined terms outlined below,
are used by Spartan as key measures of financial performance and
are not intended to represent operating profits nor should they be
viewed as an alternative to cash provided by operating activities,
net income or other measures of financial performance calculated in
accordance with IFRS. For a reconciliation of Adjusted Funds Flow,
Free Funds Flow, Adjusted Funds from Operations, Operating Income,
Operating Netback, Corporate Netback and Net Debt (Surplus), see
the MD&A, which is available under the Company's SEDAR profile
at www.sedar.com.
Operating Income (Loss) and Operating Netback
"Operating Income (Loss)" is calculated by deducting
operating and transportation expenses from total revenue, after
realized gains or losses on commodity price derivative financial
instruments. Total revenue is comprised of oil and gas sales, net
of royalties, plus processing and other revenue. The Company refers
to Operating Income (Loss) expressed per unit of production as an
"Operating Netback".
Adjusted Funds from Operations and Corporate Netback
"Adjusted Funds from Operations" is calculated as cash
provided by (used in) operating activities before changes in
non-cash working capital, transaction costs on acquisitions and
settlements of decommissioning obligations. Adjusted Funds from
Operations can also be calculated by deducting general and
administrative and interest expenses (net of interest income) from
Operating Income (Loss). Spartan's "Corporate Netback" is
equal to Adjusted Funds from Operations expressed per unit of
production.
"Adjusted Funds from Operations per share" is calculated
on a consistent basis with net income (loss) per share, using basic
and diluted weighted average common shares as determined in
accordance with IFRS (refer to additional information under
"Reader Advisories – Share Capital").
Adjusted Funds Flow and Free Funds Flow
"Adjusted Funds Flow" is calculated by deducting
settlements of decommissioning obligations and lease payments from
Adjusted Funds from Operations. The Company believes Adjusted Funds
Flow is an appropriate metric to compare relative to Net Debt
because it reflects the net cash flow generated from routine
business operations and because Spartan does not include lease
liabilities in its definition of Net Debt (Surplus).
"Free Funds Flow" is calculated as Adjusted Funds Flow
less total net capital expenditures, excluding acquisitions.
Spartan believes Free Funds Flow provides an indication to
investors and Spartan shareholders of the amount of funds the
Company has available for future capital allocation decisions.
Net Debt (Surplus)
"Net Debt (Surplus)" includes bank debt, net of Adjusted
Working Capital. "Adjusted Working Capital" is calculated as
current assets less current liabilities, excluding derivative
financial instrument assets and liabilities and lease liabilities.
As at December 31, 2020 and 2019, the
Adjusted Working Capital deficit (surplus) includes cash and cash
equivalents, accounts receivable, prepaid expenses and deposits,
accounts payable and accrued liabilities and the current portion of
decommissioning obligations. Spartan uses Net Debt (Surplus) as a
measure of the Company's financial position and liquidity, however
it is not intended to be viewed as an alternative to other measures
calculated in accordance with IFRS.
IRR
"Internal rate of return" of "IRR" is a rate of
return measure used to compare the profitability of an investment
and represents the discount rate at which the net present value of
costs equals the net present value of the benefits. The higher a
project's IRR, the more desirable the project.
Forward-Looking and Cautionary Statements
Certain statements contained within this press release
constitute forward-looking statements within the meaning of
applicable Canadian securities legislation. All statements other
than statements of historical fact may be forward-looking
statements. Forward-looking statements are often, but not always,
identified by the use of words such as "anticipate", "budget",
"plan", "endeavor", "continue", "estimate", "evaluate", "expect",
"forecast", "monitor", "may", "will", "can", "able", "potential",
"target", "intend", "consider", "focus", "identify", "use",
"utilize", "manage", "maintain", "remain", "result", "cultivate",
"could", "should", "believe" and similar expressions. The Company
believes that the expectations reflected in such forward-looking
statements are reasonable, but no assurance can be given that such
expectations will prove to be correct and such forward-looking
statements should not be unduly relied upon. Without limitation,
this press release contains forward-looking statements pertaining
to: the intentions of management and the Company with respect to
its growth strategy and business plan; the closing of the
Acquisitions and the concurrent financings, and the timing thereof;
the use of the proceeds from the concurrent financings; anticipated
synergies created from the Acquisitions and Spartan's ability to
capitalizing thereon; the implementation of the Company's
consolidation strategy; Spartan's expectations regarding its 2021
drilling program; Spartan's expectations regarding Net Debt
(Surplus) levels; Spartan plans to deliver strong operational
performance and to generate free funds flow; Spartan's production
forecasts; Spartan's cost-cutting measures and the results thereof;
and Spartan's 2021 budget and financial/operational guidance.
The forward-looking statements and information are based on
certain key expectations and assumptions made by Spartan, including
expectations and assumptions concerning the business plan of the
Company, expected production, market conditions, receipt of
regulatory and other approvals for the Acquisitions and the
concurrent financings and benefits and synergies arising from the
Acquisitions. Although Spartan believes that the expectations and
assumptions on which such forward-looking statements and
information are based are reasonable, undue reliance should not be
placed on the forward-looking statements and information because
Spartan can give no assurance that they will prove to be correct.
By its nature, such forward-looking information is subject to
various risks and uncertainties, which could cause the actual
results and expectations to differ materially from the anticipated
results or expectations expressed. These risks and uncertainties
include, but are not limited to, fluctuations in commodity prices,
changes in industry regulations and political landscape both
domestically and abroad, foreign exchange or interest rates, stock
market volatility, impacts of the current COVID-19 pandemic and the
retention of key management and employees. Please refer to the
Company's most recent Annual Information Form and MD&A for
additional risk factors relating to Spartan, which can be accessed
either on Spartan's website at www.spartandeltacorp.com or
under the Company's profile on www.sedar.com. Readers are cautioned
not to place undue reliance on this forward-looking information,
which is given as of the date hereof, and to not use such
forward-looking information for anything other than its intended
purpose. Spartan undertakes no obligation to update publicly or
revise any forward-looking information, whether as a result of new
information, future events or otherwise, except as required by
law.
Future Oriented Financial Information
Any financial outlook or future oriented financial information
in this press release, as defined by applicable Canadian securities
legislation, has been approved by management of Spartan. Readers
are cautioned that any such future-oriented financial information
contained herein, including (but not limited to) references to Net
Debt (Surplus) levels, Adjusted Funds Flow and the Company's
"Outlook and Guidance" for 2021, should not be used for purposes
other than those for which it is disclosed herein. The Company and
its management believe that the prospective financial information
has been prepared on a reasonable basis, reflecting management's
best estimates and judgments, and represent, to the best of
management's knowledge and opinion, the Company's expected course
of action. However, because this information is highly subjective,
it should not be relied on as necessarily indicative of future
activities or results.
Oil and Gas Advisories
All reserve references in this press release are "Company share
reserves". Company share reserves are the applicable company's
total working interest reserves before the deduction of any
royalties and including any royalty interests payable to the
company.
It should not be assumed that the present worth of estimated
future amounts presented in the tables above represents the fair
market value of the reserves. There is no assurance that the
forecast prices and costs assumptions will be attained, and
variances could be material. The recovery and reserve estimates of
the crude oil, natural gas liquids and natural gas reserves
provided herein are estimates only and there is no guarantee that
the estimated reserves will be recovered. Actual crude oil, natural
gas and natural gas liquids reserves may be greater than or less
than the estimates provided herein. All evaluations and summaries
of future net revenue are stated prior to the provision for
interest, debt service charges or general and administrative
expenses and after deduction of royalties, operating costs,
estimated well abandonment and reclamation costs and estimate
future capital expenditures.
This press release contains metrics commonly used in the oil and
natural gas industry which have been prepared by management, such
as "development capital", "F&D costs", "operating netback",
"recycle ratio" and "reserve life index". These terms do not have a
standardized meaning and may not be comparable to similar measures
presented by other companies, and therefore should not be used to
make such comparisons.
"Development capital" means the aggregate exploration and
development costs incurred in the financial year on reserves that
are categorized as development. Development capital excludes
capitalized administration costs.
"Undeveloped F&D costs" are calculated as the
sum of development capital, divided by the undeveloped reserves at
the proved undeveloped and proved plus probable undeveloped
levels.
"Operating netback" see "Reader Advisories – Non-GAAP
Measures".
"Recycle ratio" is measured by dividing operating netback
by F&D cost per boe for the year.
"Reserve life index" or "RLI" is calculated as
total Company share reserves divided by annualized fourth quarter
actual production.
Management uses these oil and gas metrics for its own
performance measurements and to provide shareholders with measures
to compare our operations over time. Readers are cautioned that the
information provided by these metrics, or that can be derived from
the metrics presented in this press release, should not be relied
upon for investment or other purposes.
Drilling Locations
This press release discloses drilling inventory in three
categories: (i) proved locations; (ii) probable locations; and
(iii) unbooked locations. Proved locations and probable locations
are derived from the McDaniel Report and account for drilling
locations that have associated proved and/or probable reserves, as
applicable. Unbooked locations are internal estimates based on our
prospective acreage and an assumption as to the number of wells
that can be drilled per section based on industry practice and
internal review. Unbooked locations do not have attributed reserves
or resources.
- Of the 864 (590 net) total drilling locations identified
herein, 75 (63 net) are proved locations, 43 (38 net) are probable
locations and 746 (489 net) are unbooked locations.
- Of the 118 (101 net) FDC drilling locations identified herein,
75 (63 net) are proved locations, and 43 (38 net) are probable
locations.
Unbooked locations have been identified by management 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 we 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
we drill 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, 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.
Other Measurements
All dollar figures included herein are presented in Canadian
dollars, unless otherwise noted.
This press release contains various references to the
abbreviation "boe" which means barrels of oil equivalent. Where
amounts are expressed on a boe basis, natural gas volumes have been
converted to oil equivalence at six thousand cubic feet per barrel.
A boe conversion ratio of six thousand cubic feet per barrel is
based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead and is significantly different than the
value ratio based on the current price of crude oil and natural
gas. This conversion factor is an industry accepted norm and is not
based on either energy content or current prices. Such abbreviation
may be misleading, particularly if used in isolation.
Throughout this press release, "crude oil" or "oil" refers to
light and medium crude oil product types as defined by NI 51-101.
Condensate is a natural gas liquid as defined by NI 51-101.
References to "natural gas liquids" or "NGLs" throughout this press
release comprise pentane, butane, propane, and ethane, being all
NGLs as defined by NI 51-101 other than condensate, which is
disclosed separately because the value equivalency of condensate is
more closely aligned with crude oil. References to "natural gas" or
"gas" relates to conventional natural gas.
Other Abbreviations
AECO
|
Alberta Energy
Company "C" Meter Station of the NOVA Pipeline System, the Canadian
benchmark price for natural gas
|
bbl
|
barrel
|
bbls/d
|
barrels per
day
|
boe
|
barrels of oil
equivalent
|
boe/d
|
barrels of oil
equivalent per day
|
CA$
|
Canadian
dollars
|
GJ
|
gigajoule
|
IP30
|
initial 30-day
production
|
IP60
|
initial 60-day
production
|
$M
|
thousands of
dollars
|
Mbbls
|
one million
barrels
|
Mboe
|
one million barrels
of oil equivalent
|
Mcf
|
one thousand cubic
feet
|
Mcf/d
|
one thousand cubic
feet per day
|
MMbtu
|
one million British
thermal units
|
MMcf
|
one million cubic
feet
|
NGL
|
natural gas
liquids
|
US$
|
United States
dollar
|
WA
|
weighted
average
|
WTI
|
West Texas
Intermediate, price paid in US$ at Cushing, Oklahoma, for crude oil
of standard grade
|
Neither the TSXV nor its Regulation Services Provider (as
that term is defined in the policies of the TSXV) accepts
responsibility for the adequacy or accuracy of this press
release.
SOURCE Spartan Delta Corp.