CALGARY, AB, March 2, 2022 /CNW/ - Tourmaline Oil Corp.
(TSX:TOU) ("Tourmaline" or the "Company") is pleased to release
financial and operating results for the full year and fourth
quarter of 2021 as well as 2021 reserves.
HIGHLIGHTS
- Full-year average 2021 production of 441,115 boepd was up 42%
over 2020 average production of 310,598 boepd.
- Current production is ranging between 500,000-510,000 boepd,
with a Q1 2022 exit of 510,000-515,000 boepd anticipated.
- Full-year 2021 after tax net earnings were $2.03 billion ($6.40 per diluted share).
- Full-year 2021 cash flow(1) was a record
$2.93 billion ($9.25 per diluted share(2)) up 147%
over 2020.
- Tourmaline generated a record $1.49
billion of free cash flow(3) ("FCF") in
2021.
- Exit 2021 net debt(4) was $973 million (0.25 times 2021 net debt to Q4
annualized cash flow) and below the Company's long-term net debt
target of $1.0-1.2 billion.
- Year-end 2021 proved, developed producing ("PDP") reserves of
947.3 million boe were up 50%, total proved ("TP") reserves of 2.19
billion boe were up 39% and proved plus probable ("2P") reserves of
4.24 billion boe were up 33% over year-end 2020, including 2021
annual production of 161.0 million boe.
- Tourmaline replaced 677% of its 2021 annual production of 161.0
million boe with 2P additions of 1.090 billion boe including 2021
production.
- Tourmaline's 2P reserve value(5) equates to
$97.54 per diluted
share(6) using the January 1,
2022 engineering price deck and a 10% discount rate. TP and
PDP reserve value is $62.70 and
$33.77 per diluted
share(7), respectively, using the same pricing and
discount rates.
- After 13 years of operations, Tourmaline now has 19.5 TCF of 2P
natural gas reserves, the largest in Canada and one of the largest, lowest
development cost, lowest emission natural gas reserve bases in
North America.
- In 2021, the Company further diversified the gas marketing
portfolio by establishing a US Gulf Coast LNG pathway and entered
into a long-term arrangement with Cheniere Energy Inc. In 2023,
Tourmaline will become the first Canadian EP company participating
in the LNG business with full exposure to JKM (Japan Korea Marker)
pricing.
- The Company's exploration program has successfully tested six
new horizons spread across the three operated complexes thus
far.
- Tourmaline achieved its net 25% methane reduction target in
2021, three years earlier than targeted.
PRODUCTION UPDATE
- Fourth quarter 2021 production averaged 485,078 boepd, up 44%
from Q4 2020; full-year 2021 production of 441,115 boepd was up 42%
over 2020 average production of 310,598 boepd.
- 2021 average liquids production of 97,206 bpd (oil, condensate,
NGL) was up 50.7% over 2020.
- Current production is ranging between 500,000-510,000 boepd.
The Company expects to exit Q1 at 510,000-515,000 boepd. Full-year
2022 average production guidance of 500,000 boepd remains
unchanged.
- All three Company-operated EP complexes are currently producing
at or above full-year 2022 guidance levels. The Alberta Deep Basin
is currently producing 250,000 boepd, the BC Montney gas condensate complex is producing
230,000 boepd and the Peace River High complex is producing 25,000
boepd.
FINANCIAL HIGHLIGHTS
- Full-year 2021 after tax net earnings were $2.03 billion ($6.40 per diluted share).
- Fourth quarter 2021 cash flow was $968.2
million ($2.88 per diluted
share), and full-year 2021 cash flow was a record $2.93 billion ($9.25 per diluted share). Annual cash flow is up
147% on total revenue(8) of $4.67
billion for 2021, up 115% over 2020.
- Tourmaline generated a record $1.49
billion of free cash flow in 2021.
- The Company increased the base dividend three times in 2021 to
$0.72/share (29% annual increase) and
paid a special dividend of $0.75/share in October
2021. Tourmaline has committed to returning the majority of
annual FCF to shareholders and is executing on that plan.
- Subsequent to year-end 2021, Tourmaline increased the annual
base dividend to $0.80/share and paid
a second special dividend of $1.25/share in February
2022.
- Tourmaline's Investment Grade credit rating improved from BBB
to BBB (high) during 2021 in conjunction with its issuance of a
fixed term note and the acquisition of Black Swan. The public
investment grade rating upgrade validated the overall financial
health of Tourmaline as a stable, low-risk senior North American
oil and gas producer.
2021/2022 BUDGET AND OUTLOOK
- Q4 2021 EP capital expenditures were $410.9 million; full-year 2021 EP capital
expenditures were $1.39 billion.
- Tourmaline, as previously disclosed, accelerated the
construction of the Gundy Phase 2 deep cut and the Aitken 46-C
expansions into Q4 2021. Both projects were completed on budget and
are currently on-stream at full capacity. The Company also
accelerated the drilling of one BC pad at Gundy, and the fracing of two additional BC
pads from Q1 2022 into Q4 2021, primarily for operational
continuity and logistics reasons. These incremental EP operations
added approximately $80.0 million to
the Q4 2021 EP capital program.
- In 2022 at current strip(9) pricing, the Company
expects to generate cash flow of $4.05
billion ($11.97 per diluted
share) and free cash flow of $2.85
billion ($8.43 per diluted
share) on unchanged EP capital expenditures of $1.125 billion.
- Tourmaline builds 2.5% inflation per annum on both capital and
operating costs into the Company's five-year EP capital plan. The
$80.0 million of BC
drilling/completion capital accelerated into Q4 2021 will also
remain in the 2022 budget to provide for anticipated 2022
inflation. The Company's continuing material reductions of drill
times in all three EP complexes also provides a further offset to
inflationary pressures.
- Tourmaline generated cash flow of $968.2
million and free cash flow of $545.9
million in Q4 2021 on EP capital expenditures of
$410.9 million.
- Exit 2021 net debt was $973
million (0.25 times 2021 net debt to Q4 annualized cash
flow) and below the Company's long-term net debt target of
$1.0-1.2 billion. The majority of
Tourmaline's net debt is substantially offset by its investment in
Topaz, using a closing price of Topaz common shares at December 31, 2021 of $17.85 per share.
2021 RESERVES
- Year-end 2021 PDP reserves of 947.3 million boe were up 50%
over year-end 2020 including 2021 annual production of 161.0
million boe. TP reserves of 2.19 billion boe were up 39.0%
including 2021 annual production. 2P reserves of 4.24 billion boe
were up 33% including 2021 annual production.
- Tourmaline's 2021 PDP finding, development and acquisition
("FD&A") costs were $7.27 per
boe(10) including changes in future development capital
("FDC") yielding a PDP reserve recycle ratio(11)(12) of
2.5 (3.0 utilizing Q4 2021 cash flow per boe(13) of
$21.70 instead of full-year 2021 cash
flow per boe of $18.19). TP FD&A
costs in 2021 were $5.94 per boe
including changes in FDC and 2P FD&A was $4.54 per boe including changes in FDC. The 2P
FD&A recycle ratio was 4.0 in 2021.
- Tourmaline replaced 677% of its 2021 annual production of 161.0
million boe with 2P additions of 1.090 billion boe including 2021
production.
- Tourmaline's 2P reserve value (before taxes) equates to
$97.54 per diluted share using the
January 1, 2022 engineering price
deck and a 10% discount rate. TP reserve value is $62.70 per diluted share and PDP reserve value is
$33.77 per diluted share using the
same pricing and discount rates.
- After 13 years of operations, Tourmaline now has 19.5 TCF of 2P
natural gas reserves, the largest in Canada and one of the largest, lowest
development cost, lowest emission natural gas reserve bases in
North America. The Company also
has 995.1 million boe of 2P crude oil, condensate and NGL (natural
gas liquids) reserves (December 31,
2021) - one of the largest conventional liquid reserve bases
in Canada.
- Tourmaline has only booked 3,168 (gross) locations of a total
drilling inventory of 22,715 gross locations (14% of the overall
inventory) to achieve year-end 2021 2P reserves of 4.24 billion
boe.
- The current FDCs associated with 2P reserves represent
approximately three years of prospective cash flow at strip
pricing. Although the Company has the execution capability to
convert the entire 4.24 billion boe of 2P reserves to PDP in that
time frame, it does not believe that would be constructive for the
current encouraging supply/demand dynamics in the WCSB, or the
appropriate capital allocation decision.
MARKETING UPDATE
- Tourmaline continued to diversify its natural gas and liquids
marketing portfolio in order to realize the best pricing possible
for all of its hydrocarbon streams.
- In 2021, the Company further diversified the gas marketing
portfolio by establishing a US Gulf Coast LNG long-term netback
supply agreement with Cheniere Energy. In 2023, Tourmaline will
become the first Canadian EP company participating in the LNG
business with full exposure to JKM pricing, providing a material
increase to anticipated 2023 cash flow based on the February 15, 2022 JKM strip pricing.
- In November 2022, the Company
will increase gas volumes exported to western US markets from 345
to 445 mmcfpd, with approximately 67% of the gas accessing the
premium priced PG&E California market. In November 2023, western US market exposure will
increase by an incremental 50 mmcfpd.
- Average realized natural gas price in Q4 2021 was $4.66/mcf as the Company benefited from rising
commodity prices.
- Tourmaline has an average of 845 mmcfpd hedged for 2022 at a
weighted average fixed price of CAD $3.44/mcf, an average of 151 mmcfpd hedged at a
basis to Nymex of USD $(0.05)/mcf,
and an average of 609 mmcfpd of unhedged volumes exposed to export
markets in 2022, including Dawn, Iroquois, Empress/McNeil, Chicago, Ventura, Sumas, US Gulf Coast, Malin,
and PG&E.
- The 2022 volumes include approximately 145 mmcfpd of
lower-priced deals inherited in the Black Swan and Modern corporate
transactions, the majority of which will expire during 2022.
- NGL price realizations in Q4 2021 were up 24% over Q3 2021.
Tourmaline is Canada's largest NGL
producer with anticipated average production levels of over 70,000
bpd in 2022.
EP UPDATE
- Tourmaline drilled a total of 280 net wells during 2021 for a
total of 1.289 million metres. The Company has systematically
increased lateral length by over 30% since 2018 while reducing
actual drill/complete costs per lateral foot by an additional 30%
in that time period.
- Tourmaline operated 13 drilling rigs and four to five frac
spreads across the three operated core EP complexes during January
and February of 2022 as originally planned.
- The Company expects to drill and complete a total of
approximately 265 (gross) wells during 2022.
- The Company continues to operate five drilling rigs in NEBC
with new multiple high-performance pads at Sundown, Gundy, Aitken, and Laprise.
- Facility expansions at Gundy
and Aitken were accelerated into 2H 2021 and completed on budget.
The Aitken 46-C expansion/deep cut was executed in 120 days for
$96.5 million; the previous owner had
estimated 270 days for $116 million.
There are no material facility projects in the 2022 budget; as
such, the Company anticipates record 2022 capital
efficiencies(14) in the $6,000/boepd range.
- The Company continues to evolve the Conroy/N. Montney development project. This minimum
100,000 boepd gas and liquids project is currently planned in the
2025-26 timeframe, coinciding with the projected startup of LNG
Canada and anticipated related strong intra-Basin natural gas
pricing. The production, cash flow, and capital for this project
are not reflected in the current corporate five-year EP plan. Once
sanctioned, the Company believes it can execute this project in
approximately 18 months.
- The three-well 1-15 Upper Charlie Lake pad has averaged at a
combined rate of 2,500 bopd and 2.8 mmcfpd over the first two weeks
of production. The Company has two additional pads to bring
on-stream in the complex, prior to spring break-up.
- The 4-23 two well Wilrich pad at Smoky tested at combined rate
of 65 mmcfpd over three days of testing in February 2022. The pad has since been turned over
to production.
EXPLORATION PROGRAM
- The Company embarked upon a modest exploration program over two
years ago as a subset of the annual EP program. The Company has
successfully tested six new horizons spread across the three
operated complexes to date. The December 31,
2021 reserve report includes 845.1 bcfe of 2P reserves from
these discoveries thus far. Further delineation drilling is planned
in all three complexes over the next 12 months; the Company will
disclose further details in upcoming quarters as appropriate.
- Successful discoveries to date are accessing existing
Tourmaline infrastructure.
- This 'Back to the Future' initiative provides shareholders with
an additional, unique, long-term growth and value accretion
opportunity.
ACQUISITION UPDATE
- Tourmaline completed a highly successful consolidation strategy
in the 2020 and 1H 2021 time period. In July
2021, the Company indicated that the larger acquisition
program was being paused. The Company made the decision to focus on
integration of the assets acquired in the completed deals and
realization of the identified capital and operating synergies.
- The Company has indicated that $200-300 million of annual FCF could be allocated
to further smaller, complementary asset acquisitions within
existing complexes.
- During Q4 2021 and thus far in Q1 2022, the Company has
completed a number of these small acquisitions that in aggregate
are meaningful. To that end, Tourmaline has acquired 2,400 boepd of
production, an estimated 43 mmboe of reserves (based on internal
estimates), 295 gross sections of land (including land sales), and
238 gross drilling locations for total cash proceeds of
$63.8 million over the two
quarters.
SUSTAINABILITY AND ENVIRONMENTAL PERFORMANCE
IMPROVEMENT
- Tourmaline has had an engineering team in place for three years
developing and implementing new proprietary emission reduction
technologies, executing expanded water management initiatives,
managing third party environmental related research, evolving a
methane testing centre, and managing an emerging carbon offset
business. Tourmaline intends to invest $20-40 million per year on environmental
performance improvement initiatives.
- The Company now has displaced diesel with natural gas on all
the drilling rigs in the operated fleet, and currently has one rig
running directly on high line power.
- In 2021, the Company entered into a joint venture with Trican
to utilize the first Tier 4 natural gas frac unit in Canada, displacing the majority of the diesel
consumed during frac operations with Company-sourced natural gas.
This unit is currently being utilized on a full-time basis in the
Gundy BC complex.
- During 2021, Tourmaline continued its Basin leading initiative
to reduce freshwater usage in EP well stimulation operations. The
Company now has seven water management/water recycling complexes
across all three operated complexes.
- Tourmaline achieved its net 25% methane reduction target in
2021, three years earlier than targeted.
- In 2021, the Company's Emission Testing Center ("ETC"), the
first of its kind in the world, at the West Wolf gas plant, became
fully operational. The ETC is critical in evolving new technology
and methodologies to continue materially reducing methane and other
emissions over the entire EP business.
DIVIDEND
- The Company is pleased to announce that its Board of Directors
has declared a quarterly cash dividend on its common shares of
$0.20 per common share. The dividend
will be payable on March 31, 2022 to
shareholders of record at the close of business on March 15, 2022. This quarterly cash dividend is
designated as an "eligible dividend" for Canadian income tax
purposes.
___________
|
(1)
|
This news release
contains certain specified financial measures consisting of
non-GAAP financial measures, non-GAAP ratios, capital management
measures and supplementary financial measures. See
"Non-GAAP and Other Financial Measures" in this news release for
information regarding the following non-GAAP financial measures,
non-GAAP ratios, capital management measures and
supplementary financial measures used in this news release: "cash
flow", "capital expenditures", "free cash flow", "operating
netback", "operating netback per boe", "cash flow per boe",
"adjusted working capital" and "net debt". Since these specified
financial measures do not have standardized meanings under
International Financial Reporting Standards ("GAAP"), securities
regulations require that, among other things, they be identified,
defined, qualified and, where required, reconciled with their
nearest GAAP measure and compared to the prior period. See
"Non-GAAP and Other Financial Measures" in this news release and in
the Company's Management's Discussion and Analysis for the year
ended December 31, 2021 (the "Annual MD&A"),which information
is incorporated by reference into this news release, for further
information on the composition of and, where required,
reconciliation of these measures.
|
(2)
|
"Cash flow per
diluted share" is a non-GAAP financial ratio. Cash flow, a
non-GAAP financial measure, is used as a component of the non-GAAP
financial ratio. See "Non-GAAP and Other Financial Measures"
in this news release and in the Annual MD&A.
|
(3)
|
"Free cash flow" is
a non-GAAP financial measure defined as cash flow less capital
expenditures, excluding acquisitions and
dispositions. Free cash flow is prior to dividend
payments. See "Non-GAAP and Other Financial Measures" in this news
release.
|
(4)
|
"Net debt" is a
capital management measure. See "Non-GAAP and Other Financial
Measures" in this news release and in the Annual
MD&A.
|
(5)
|
2P, TP and PDP
reserve value per share is calculated as the before tax net
present value of the reserves at December 31, 2021 discounted at
10% divided by total diluted shares outstanding at December 31,
2021.
|
(6)
|
Supplementary
financial measure. See "Non-GAAP and Other Financial Measures" in
this news release and in the Annual MD&A.
|
(7)
|
Supplementary
financial measure. See "Non-GAAP and Other Financial Measures" in
this news release and in the Annual MD&A.
|
(8)
|
Total revenue from
commodity sales and premium (loss) on risk management activities
and realized gain (loss) on financial instruments.
|
(9)
|
Based on oil and gas
commodity strip pricing at February 15, 2022.
|
(10)
|
Non-GAAP financial
ratio. See "Non-GAAP and Other Financial Measures" in this news
release and in the Annual MD&A.
|
(11)
|
Non-GAAP financial
ratio. See "Non-GAAP and Other Financial Measures" in this news
release and in the Annual MD&A. The recycle ratio is calculated
by dividing the cash flow per boe by the appropriate F&D or
FD&A costs related to the reserve additions for that
year.
|
(12)
|
Non-GAAP financial
ratio. See "Non-GAAP and Other Financial Measures" in this news
release and in the Annual MD&A.
|
(13)
|
Non-GAAP financial
ratio. See "Non-GAAP and Other Financial Measures" in this news
release and in the Annual MD&A.
|
(14)
|
Capital efficiencies
are calculated as capital expenditures divided by estimated
production added over the period.
|
CORPORATE SUMMARY – DECEMBER 31,
2021
|
Three Months Ended
December 31,
|
|
Twelve Months Ended
December 31,
|
|
2021
|
2020
|
Change
|
|
2021
|
2020
|
Change
|
OPERATIONS
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
Natural gas
(mcf/d)
|
2,269,290
|
1,592,010
|
43%
|
|
2,063,455
|
1,476,613
|
40%
|
Crude oil, condensate
and NGL (bbl/d)
|
106,863
|
70,990
|
51%
|
|
97,206
|
64,496
|
51%
|
Oil equivalent
(boe/d)
|
485,078
|
336,325
|
44%
|
|
441,115
|
310,598
|
42%
|
Product
prices(1)
|
|
|
|
|
|
|
|
Natural gas
($/mcf)
|
$
|
4.66
|
$
|
3.19
|
46%
|
|
$
|
3.94
|
$
|
2.68
|
47%
|
Crude oil, condensate
and NGL ($/bbl)
|
$
|
56.66
|
$
|
33.85
|
67%
|
|
$
|
47.89
|
$
|
30.87
|
55%
|
Operating expenses
($/boe) (2)
|
$
|
3.95
|
$
|
3.25
|
22%
|
|
$
|
3.77
|
$
|
3.14
|
20%
|
Transportation costs
($/boe) (3)
|
$
|
4.45
|
$
|
4.42
|
1%
|
|
$
|
4.25
|
$
|
4.48
|
(5)%
|
Operating netback
($/boe) (4)
|
$
|
22.10
|
$
|
13.65
|
62%
|
|
$
|
18.57
|
$
|
10.93
|
70%
|
Cash general and
administrative
expenses ($/boe)(5)
|
$
|
0.49
|
$
|
0.50
|
(2)%
|
|
$
|
0.54
|
$
|
0.56
|
(4)%
|
FINANCIAL
($000, except share and per share)
|
|
|
|
|
|
|
|
Total revenue from
commodity sales and realized gains
|
1,529,345
|
688,374
|
122%
|
|
4,669,263
|
2,174,903
|
115%
|
Royalties
|
168,168
|
28,623
|
488%
|
|
387,914
|
65,523
|
492%
|
Cash flow
|
968,236
|
396,869
|
144%
|
|
2,929,126
|
1,185,687
|
147%
|
Cash flow per share
(diluted)
|
$
|
2.88
|
$
|
1.44
|
100%
|
|
$
|
9.25
|
$
|
4.36
|
112%
|
Net earnings
|
996,248
|
629,191
|
58%
|
|
2,025,991
|
618,311
|
228%
|
Net earnings per share
(diluted)
|
$
|
2.96
|
$
|
2.28
|
30%
|
|
$
|
6.40
|
$
|
2.27
|
182%
|
Capital expenditures
(net of dispositions)(6)
|
447,461
|
271,284
|
65%
|
|
1,590,371
|
1,083,625
|
47%
|
Weighted average shares
outstanding (diluted)
|
|
|
|
|
316,788,967
|
272,079,590
|
16%
|
Net debt
|
|
|
|
|
(972,979)
|
(1,784,920)
|
(45)%
|
PROVED +
PROBABLE RESERVES(7)
|
|
|
|
|
|
|
|
Natural gas
(bcf)
|
|
|
|
|
19,487.1
|
15,459.2
|
26%
|
Crude oil
(mbbls)
|
|
|
|
|
98,345
|
102,843
|
(4)%
|
Natural gas liquids
(mbbls)
|
|
|
|
|
896,793
|
634,890
|
41%
|
Mboe
|
|
|
|
|
4,242,981
|
3,314,264
|
28%
|
|
|
(1)
|
Product prices
include realized gains and losses on risk management activities and
financial instrument contracts.
|
(2)
|
Supplementary
financial measure. See "Non-GAAP and Other Financial Measures" in
this news release and in the Annual MD&A.
|
(3)
|
Supplementary
financial measure. See "Non-GAAP and Other Financial Measures" in
this news release and in the Annual MD&A.
|
(4)
|
Excluding interest
and financing charges. Non-GAAP financial measure and non-GAAP
ratio. See "Non-GAAP and Other Financial Measures" in this news
release and in the Annual MD&A.
|
(5)
|
Non-GAAP financial
measure and non-GAAP ratio. See "Non-GAAP and Other Financial
Measures" in this news release and in the Annual
MD&A.
|
(6)
|
Non-GAAP financial
measure. See "Non-GAAP and Other Financial Measures" in this news
release and in the Annual MD&A.
|
(7)
|
Reserves are
"Company gross reserves", which are defined as the working interest
share of reserves prior to the deduction of interest owned by
others (burdens). Royalty interest reserves are not included in
Company gross reserves.
|
2021 RESERVE SUMMARY
The following tables summarize the Company's gross reserves
defined as the working interest share of reserves prior to the
deduction of interest owned by others (burdens). Royalty
interest reserves are not included in Company gross reserves.
Company net reserves are defined as the working net carried and
royalty interest reserves after deduction of all applicable
burdens.
Reserves and Future Net Revenue Data (Forecast Prices and
Costs)
Summary of Crude Oil, Natural Gas and Natural
Gas Liquids Reserves and
Net Present Values of Future Net Revenue
as of December 31, 2021
Forecast Prices and Costs(1)
|
|
Light & Medium
Crude
Oil
|
|
Conventional
Natural
Gas
|
|
Shale Natural
Gas(2)
|
|
Natural Gas
Liquids
|
|
Total Oil
Equivalent
|
Reserves
Category
|
|
Company
Gross
(Mbbls)
|
|
Company
Net
(Mbbls)
|
|
Company
Gross
(MMcf)
|
|
Company
Net
(MMcf)
|
|
Company
Gross
(MMcf)
|
|
Company
Net
(MMcf)
|
|
Company
Gross
(Mbbls)
|
|
Company
Net
(Mbbls)
|
|
Company Gross
(Mboe)
|
|
Company
Net
(Mboe)
|
Proved
Producing
|
|
13,666
|
|
11,294
|
|
2,316,261
|
|
2,081,062
|
|
2,151,299
|
|
1,759,736
|
|
189,034
|
|
156,708
|
|
947,293
|
|
808,135
|
Proved Developed
Non-Producing
|
|
1,695
|
|
1,263
|
|
56,830
|
|
51,128
|
|
291,228
|
|
243,333
|
|
17,399
|
|
14,473
|
|
77,104
|
|
64,812
|
Proved
Undeveloped
|
|
35,322
|
|
28,459
|
|
2,290,336
|
|
2,071,498
|
|
3,089,713
|
|
2,554,843
|
|
231,476
|
|
196,134
|
|
1,163,473
|
|
995,650
|
Total Proved
|
|
50,682
|
|
41,016
|
|
4,663,427
|
|
4,203,689
|
|
5,532,239
|
|
4,557,912
|
|
437,910
|
|
367,315
|
|
2,187,870
|
|
1,868,597
|
Total
Probable
|
|
47,662
|
|
38,626
|
|
3,098,317
|
|
2,773,983
|
|
6,193,076
|
|
5,006,345
|
|
458,883
|
|
373,721
|
|
2,055,111
|
|
1,709,069
|
Total Proved Plus
Probable
|
|
98,345
|
|
79,642
|
|
7,761,744
|
|
6,977,672
|
|
11,725,316
|
|
9,564,257
|
|
896,793
|
|
741,036
|
|
4,242,981
|
|
3,577,666
|
|
|
Net Present Values
of Future Net Revenue ($000s)
|
|
|
Before Income Taxes
Discounted at (2) (%/year)
|
|
After Income Taxes
Discounted at (2) (3)
(%/year)
|
|
Unit Value
Before
Income Tax
Discounted
at 10%/year
|
Reserves
Category
|
|
0
|
|
5
|
|
8
|
|
10
|
|
15
|
|
20
|
|
0
|
|
5
|
|
8
|
|
10
|
|
15
|
|
20
|
|
($/Boe)
|
|
($/Mcfe)
|
Proved
Producing
|
|
15,895,760
|
|
13,323,539
|
|
12,106,290
|
|
11,411,616
|
|
9,996,380
|
|
8,984,527
|
|
13,793,015
|
|
11,724,576
|
|
10,726,715
|
|
10,153,628
|
|
8,978,499
|
|
8,079,741
|
|
14.12
|
|
2.35
|
Proved Developed
Non-Producing
|
|
1,862,980
|
|
1,352,921
|
|
1,156,872
|
|
1,054,529
|
|
864,456
|
|
735,753
|
|
1,435,838
|
|
1,027,731
|
|
874,366
|
|
795,234
|
|
650,130
|
|
552,567
|
|
16.27
|
|
2.71
|
Proved
Undeveloped
|
|
20,460,819
|
|
12,839,140
|
|
10,095,313
|
|
8,717,048
|
|
6,278,640
|
|
4,863,857
|
|
15,379,706
|
|
9,540,902
|
|
7,435,008
|
|
6,377,707
|
|
4,510,673
|
|
3,327,238
|
|
8.76
|
|
1.46
|
Total Proved
|
|
38,219,559
|
|
27,515,600
|
|
23,358,475
|
|
21,183,193
|
|
17,139,476
|
|
14,584,136
|
|
30,608,559
|
|
22,293,210
|
|
19,036,089
|
|
17,326,568
|
|
14,139,302
|
|
11,959,545
|
|
11.34
|
|
1.89
|
Total
Probable
|
|
39,372,998
|
|
19,788,766
|
|
14,264,392
|
|
11,773,086
|
|
7,807,442
|
|
5,744,160
|
|
29,287,702
|
|
14,637,854
|
|
10,499,401
|
|
8,634,477
|
|
5,671,909
|
|
4,005,961
|
|
6.89
|
|
1.15
|
Total Proved Plus
Probable
|
|
77,592,557
|
|
47,304,365
|
|
37,622,867
|
|
32,956,279
|
|
24,946,918
|
|
20,328,297
|
|
59,896,260
|
|
36,931,063
|
|
29,535,490
|
|
25,961,045
|
|
19,811,211
|
|
15,965,506
|
|
9.21
|
|
1.54
|
Notes:
|
(1)
|
Numbers may not add due
to rounding.
|
(2)
|
Shale Natural Gas is
required to be presented separately from Conventional Natural Gas
as its own product type pursuant to National Instrument 51-101 –
Standards of Disclosure for Oil and Gas Activities ("NI 51-101").
While the Tourmaline Montney reserves do not strictly fit the
definition of "shale gas" as defined in NI 51-101 because the
natural gas is not "primarily adsorbed" as stated within the
definition, the Montney reserves have been included as shale gas
for purposes of this disclosure.
|
(3)
|
The after-tax net
present value of the Company's oil and gas properties reflects the
tax burden on the properties on a stand-alone basis. It does
not consider the Company's tax situation, or tax planning. It
does not provide an estimate of the value at the Company level
which may be significantly different. The Company's financial
statements and management's discussion and analysis should be
consulted for information at the Company level.
|
Total Future Net Revenue ($000s)
(Undiscounted)
as of December 31, 2021
Forecast Prices and Costs(1)
Reserves
Category
|
|
Revenue
|
|
Royalties
|
|
Operating
Costs
|
|
Capital
Development
Costs
|
|
Abandonment
and
Reclamation
Costs(2)
|
|
Future Net
Revenue
Before
Income Tax
|
|
Income
Tax
|
|
Future Net
Revenue
After
Income
Tax(3)
|
Proved
Producing
|
|
25,765,001
|
|
2,433,456
|
|
6,626,387
|
|
970
|
|
808,427
|
|
15,895,760
|
|
2,102,746
|
|
13,793,015
|
Proved Developed
Non-Producing
|
|
2,643,209
|
|
210,932
|
|
438,012
|
|
104,091
|
|
27,195
|
|
1,862,980
|
|
427,141
|
|
1,435,838
|
Proved
Undeveloped
|
|
35,978,182
|
|
3,195,226
|
|
6,318,605
|
|
5,691,019
|
|
312,513
|
|
20,460,819
|
|
5,081,114
|
|
15,379,706
|
Total Proved
|
|
64,386,393
|
|
5,839,614
|
|
13,383,004
|
|
5,796,080
|
|
1,148,135
|
|
38,219,559
|
|
7,611,001
|
|
30,608,559
|
Total
Probable
|
|
66,737,385
|
|
7,554,755
|
|
14,085,762
|
|
5,232,675
|
|
491,196
|
|
39,372,998
|
|
10,085,296
|
|
29,287,702
|
Total Proved Plus
Probable
|
|
131,123,778
|
|
13,394,369
|
|
27,468,766
|
|
11,028,755
|
|
1,639,331
|
|
77,592,557
|
|
17,696,296
|
|
59,896,260
|
Notes:
|
(1)
|
Numbers may not add due
to rounding.
|
(2)
|
Abandonment and
Reclamation Costs includes all active and inactive assets, with or
without associated reserves, inclusive of all wells (existing and
undrilled), facilities and pipelines.
|
(3)
|
The after-tax net
present value of the Company's oil and gas properties reflects the
tax burden on the properties on a stand-alone basis. It does
not consider the Company's tax situation, or tax planning. It
does not provide an estimate of the value at the Company level,
which may be significantly different. The Company's financial
statements and management's discussion and analysis should be
consulted for information at the Company level.
|
Summary of Pricing and Inflation Rate
Assumptions
Forecast Prices and Costs (1)
|
|
Crude Oil and Natural
Gas Liquids Pricing
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX WTI Near
Month Futures Contract
Crude Oil at Cushing,
Oklahoma
|
|
MSW, Light
Crude Oil
(40 API,
0.3%S) at
Edmonton
Then
Current
$Cdn/Bbl
|
Alberta Natural Gas
Liquids
(Then Current Dollars)
|
Year
|
|
Inflation(2)
%
|
|
CAD/USD
Exchange
Rate
$US/$Cdn(3)
|
|
Constant
2022
$US/Bbl
|
|
Then
Current
$US/
Bbl
|
|
|
Spec
Ethane
$Cdn/Bbl
|
|
Edmonton
Propane
$Cdn/Bbl
|
|
Edmonton
Butane
$Cdn/Bbl
|
|
Edmonton
C5+
Stream
Quality
$Cdn/Bbl
|
|
2022
|
|
0.0
|
|
0.7967
|
|
72.83
|
|
72.83
|
|
86.82
|
|
11.48
|
|
43.39
|
|
57.49
|
|
91.85
|
|
2023
|
|
2.3
|
|
0.7967
|
|
67.21
|
|
68.78
|
|
80.73
|
|
10.33
|
|
35.92
|
|
50.17
|
|
85.53
|
|
2024
|
|
2.0
|
|
0.7967
|
|
63.96
|
|
66.76
|
|
78.01
|
|
9.81
|
|
34.62
|
|
48.53
|
|
82.98
|
|
2025
|
|
2.0
|
|
0.7967
|
|
63.95
|
|
68.09
|
|
79.57
|
|
10.01
|
|
35.31
|
|
49.50
|
|
84.63
|
|
2026
|
|
2.0
|
|
0.7967
|
|
63.96
|
|
69.45
|
|
81.16
|
|
10.22
|
|
36.02
|
|
50.49
|
|
86.33
|
|
2027
|
|
2.0
|
|
0.7967
|
|
63.95
|
|
70.84
|
|
82.78
|
|
10.42
|
|
36.74
|
|
51.50
|
|
88.05
|
|
2028
|
|
2.0
|
|
0.7967
|
|
63.96
|
|
72.26
|
|
84.44
|
|
10.64
|
|
37.47
|
|
52.53
|
|
89.82
|
|
2029
|
|
2.0
|
|
0.7967
|
|
63.95
|
|
73.70
|
|
86.13
|
|
10.86
|
|
38.22
|
|
53.58
|
|
91.61
|
|
2030
|
|
2.0
|
|
0.7967
|
|
63.95
|
|
75.18
|
|
87.85
|
|
11.08
|
|
38.99
|
|
54.65
|
|
93.44
|
|
2031
|
|
2.0
|
|
0.7967
|
|
63.95
|
|
76.68
|
|
89.60
|
|
11.31
|
|
39.77
|
|
55.74
|
|
95.32
|
|
2032
|
|
2.0
|
|
0.7967
|
|
63.95
|
|
78.21
|
|
91.40
|
|
11.53
|
|
40.56
|
|
56.86
|
|
97.22
|
|
2033
|
|
2.0
|
|
0.7967
|
|
63.96
|
|
79.78
|
|
93.23
|
|
11.77
|
|
41.37
|
|
58.00
|
|
99.17
|
|
2034
|
|
2.0
|
|
0.7967
|
|
63.96
|
|
81.38
|
|
95.09
|
|
12.00
|
|
42.20
|
|
59.15
|
|
101.15
|
|
2035
|
|
2.0
|
|
0.7967
|
|
63.96
|
|
83.00
|
|
96.99
|
|
12.24
|
|
43.04
|
|
60.34
|
|
103.17
|
|
2036
|
|
2.0
|
|
0.7967
|
|
63.96
|
|
84.66
|
|
98.93
|
|
12.49
|
|
43.91
|
|
61.54
|
|
105.24
|
|
2037
|
|
2.0
|
|
0.7967
|
|
63.96
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
|
Natural Gas and Sulphur
Pricing
|
|
|
|
|
|
|
|
|
|
Alberta Plant
Gate
|
|
|
|
British
Columbia
|
|
NYMEX Henry Hub
Near Month Contract
|
|
Midwest
Price @
Chicago
Then Current
$US/
MMbtu
|
|
AECO/NIT
Spot Then Current
$Cdn/
MMbtu
|
|
Dawn Price
@ Ontario Then
Current
$US/MMbtu
|
|
Spot
|
|
|
|
|
|
|
|
Year
|
|
Constant
2022
$US/
MMbtu
|
|
Then Current
$US/MMbtu
|
|
|
|
|
Constant 2021
$Cdn/
MMbtu
|
|
Then Current
$Cdn/
MMbtu
|
|
ARP $Cdn/
MMbtu
|
|
Sumas Spot
$US/
MMbtu
|
|
Westcoast
Station 2
$Cdn/
MMbtu
|
|
Spot Plant
Gate
$Cdn/
MMbtu
|
2022
|
|
3.85
|
|
3.85
|
|
3.71
|
|
3.56
|
|
3.78
|
|
3.31
|
|
3.31
|
|
3.29
|
|
3.66
|
|
3.48
|
|
3.23
|
2023
|
|
3.36
|
|
3.44
|
|
3.30
|
|
3.20
|
|
3.37
|
|
2.89
|
|
2.96
|
|
2.93
|
|
3.28
|
|
3.14
|
|
2.89
|
2024
|
|
3.04
|
|
3.17
|
|
3.03
|
|
3.05
|
|
3.10
|
|
2.68
|
|
2.80
|
|
2.77
|
|
3.01
|
|
2.98
|
|
2.73
|
2025
|
|
3.04
|
|
3.24
|
|
3.09
|
|
3.10
|
|
3.16
|
|
2.68
|
|
2.86
|
|
2.83
|
|
3.07
|
|
3.04
|
|
2.79
|
2026
|
|
3.04
|
|
3.30
|
|
3.16
|
|
3.17
|
|
3.23
|
|
2.69
|
|
2.92
|
|
2.89
|
|
3.14
|
|
3.10
|
|
2.85
|
2027
|
|
3.04
|
|
3.37
|
|
3.22
|
|
3.23
|
|
3.29
|
|
2.69
|
|
2.98
|
|
2.95
|
|
3.20
|
|
3.16
|
|
2.91
|
2028
|
|
3.04
|
|
3.44
|
|
3.29
|
|
3.30
|
|
3.36
|
|
2.69
|
|
3.04
|
|
3.01
|
|
3.26
|
|
3.22
|
|
2.97
|
2029
|
|
3.04
|
|
3.51
|
|
3.36
|
|
3.36
|
|
3.43
|
|
2.70
|
|
3.11
|
|
3.08
|
|
3.33
|
|
3.29
|
|
3.04
|
2030
|
|
3.04
|
|
3.57
|
|
3.43
|
|
3.43
|
|
3.49
|
|
2.69
|
|
3.17
|
|
3.14
|
|
3.40
|
|
3.35
|
|
3.10
|
2031
|
|
3.04
|
|
3.65
|
|
3.50
|
|
3.50
|
|
3.57
|
|
2.70
|
|
3.24
|
|
3.21
|
|
3.47
|
|
3.42
|
|
3.17
|
2032
|
|
3.04
|
|
3.72
|
|
3.57
|
|
3.57
|
|
3.64
|
|
2.70
|
|
3.30
|
|
3.28
|
|
3.54
|
|
3.49
|
|
3.23
|
2033
|
|
3.04
|
|
3.79
|
|
3.64
|
|
3.64
|
|
3.71
|
|
2.70
|
|
3.37
|
|
3.34
|
|
3.61
|
|
3.56
|
|
3.29
|
2034
|
|
3.04
|
|
3.87
|
|
3.71
|
|
3.71
|
|
3.78
|
|
2.70
|
|
3.44
|
|
3.41
|
|
3.68
|
|
3.63
|
|
3.36
|
2035
|
|
3.04
|
|
3.95
|
|
3.79
|
|
3.79
|
|
3.86
|
|
2.70
|
|
3.51
|
|
3.48
|
|
3.76
|
|
3.70
|
|
3.43
|
2036
|
|
3.04
|
|
4.03
|
|
3.87
|
|
3.86
|
|
3.94
|
|
2.70
|
|
3.58
|
|
3.55
|
|
3.83
|
|
3.78
|
|
3.49
|
2037
|
|
3.04
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
2.70
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes:
|
(1)
|
Crude oil and natural
gas benchmark reference pricing, inflation and exchange rates
utilized by GLJ in the GLJ Reserve Report and Deloitte in the
Deloitte Reserve Report, were an average of forecast prices and
costs published by Sproule Associates Ltd. as at December 31, 2021
and GLJ and McDaniel & Associates Consultants Ltd. as at
January 1, 2022 (each of which is available on their respective
websites at www.sproule.com, www.gljpc.com, and www.mcdan.com). GLJ
assigns a value to the Company's existing physical diversification
contracts for natural gas for consuming markets at Dawn, Chicago,
Ventura, Malin, PG&E, Iroquois, Kingsgate, US Gulf Coast and
JKM based on forecasted differentials to NYMEX Henry Hub as per the
aforementioned consultant average price forecast, contracted
volumes and transportation costs. No incremental value is assigned
to potential future contracts which were not in place as of
December 31, 2021.
|
(2)
|
Inflation rates used
for forecasting prices and costs.
|
(3)
|
Exchange rates used to
generate the benchmark reference prices in this table.
|
RESERVES PERFORMANCE RATIOS
The following tables highlight Tourmaline's reserves, F&D
and FD&A costs as well as the associated recycle ratios.
Reserves, Capital Expenditures and Cash
Flow(1)
As at
December 31,
|
2021
|
2020
|
2019
|
Reserves
(Mboe)
|
|
|
|
Proved
Producing
|
947,293
|
736,448
|
527,361
|
Total Proved
|
2,187,870
|
1,691,056
|
1,294,439
|
Proved Plus
Probable
|
4,242,981
|
3,314,264
|
2,601,928
|
Capital
Expenditures ($ millions)
|
|
|
|
Exploration and
Development(2)
|
1,437
|
912
|
1,069
|
Net Property
Acquisitions (Dispositions)(3)
|
196
|
172
|
219
|
Net Corporate
Acquisitions (Dispositions)(3)
|
1,232
|
794
|
-
|
Less: Topaz Property
Acquisitions(4)
|
(161)
|
(119)
|
-
|
Total(5)
|
2,704
|
1,759
|
1,287
|
Cash Flow
($/boe)
|
|
|
|
Cash Flow
|
18.19
|
10.43
|
11.36
|
Cash Flow - Three Year
Average
|
13.97
|
11.67
|
12.75
|
Notes:
|
(1)
|
Cash flow is defined
as cash provided by operations before changes in non-cash operating
working capital. See "Non-GAAP and Other Financial Measures" below
and in the Annual MD&A for further discussion.
|
(2)
|
Includes capitalized
G&A of $38 million, $32 million and $30 million for 2021, 2020
and 2019 respectively.
|
(3)
|
Includes purchase
price (cash and/or common shares) plus net debt, if
applicable.
|
(4)
|
Includes property
acquisitions incurred by Topaz from non-related parties, prior to
June 8, 2021, when it was a controlled subsidiary of
Tourmaline.
|
(5)
|
Represents the
capital expenditures used for purposes of F&D and FD&A
calculations.
|
Finding and Development Costs
Finding and
Development Costs, Excluding FDC
|
2021
|
2020
|
2019
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Reserve Additions
(MMboe)
|
257.6
|
185.4
|
160.7
|
|
F&D Costs
($/boe)
|
5.58
|
4.92
|
6.65
|
5.66
|
F&D Recycle
Ratio(1)
|
3.3
|
2.1
|
1.7
|
2.5
|
Total Proved Plus
Probable
|
|
|
|
|
Reserve Additions
(MMboe)
|
232.2
|
210.5
|
180.4
|
|
F&D Costs
($/boe)
|
6.19
|
4.33
|
5.92
|
5.48
|
F&D Recycle
Ratio(1)
|
2.9
|
2.4
|
1.9
|
2.5
|
|
|
|
|
|
Finding and
Development Costs, Including FDC
|
2021
|
2020
|
2019
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Change in FDC ($
millions)
|
197.2
|
(286.0)
|
(275.2)
|
|
Reserve Additions
(MMboe)
|
257.6
|
185.4
|
160.7
|
|
F&D Costs
($/boe)
|
6.34
|
3.38
|
4.94
|
5.06
|
F&D Recycle
Ratio(1)
|
2.9
|
3.1
|
2.3
|
2.8
|
Total Proved Plus
Probable
|
|
|
|
|
Change in FDC ($
millions)
|
41.6
|
(566.3)
|
(589.4)
|
|
Reserve Additions
(MMboe)
|
232.2
|
210.5
|
180.4
|
|
F&D Costs
($/boe)
|
6.37
|
1.64
|
2.66
|
3.70
|
F&D Recycle
Ratio(1)
|
2.9
|
6.4
|
4.3
|
3.8
|
Finding, Development and Acquisition Costs
Finding, Development
and Acquisition Costs,
Excluding FDC
|
2021
|
2020
|
2019
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Reserve Additions
(MMboe)
|
657.8
|
510.3
|
194.2
|
|
FD&A Costs
($/boe)
|
4.11
|
3.45
|
6.63
|
4.22
|
FD&A Recycle
Ratio(1)
|
4.4
|
3.0
|
1.7
|
3.3
|
Total Proved Plus
Probable
|
|
|
|
|
Reserve Additions
(MMboe)
|
1,089.7
|
826.0
|
250.7
|
|
FD&A Costs
($/boe)
|
2.48
|
2.13
|
5.13
|
2.65
|
FD&A Recycle
Ratio(1)
|
7.3
|
4.9
|
2.2
|
5.3
|
|
|
|
|
|
Finding, Development
and Acquisition Costs,
Including FDC
|
2021
|
2020
|
2019
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Change in FDC ($
millions)
|
1,201.1
|
723.3
|
(93.4)
|
|
Reserve Additions
(MMboe)
|
657.8
|
510.3
|
194.2
|
|
FD&A Costs
($/boe)
|
5.94
|
4.86
|
6.15
|
5.57
|
FD&A Recycle
Ratio(1)
|
3.1
|
2.1
|
1.8
|
2.5
|
Total Proved Plus
Probable
|
|
|
|
|
Change in FDC ($
millions)
|
2,241.2
|
1,383.5
|
(218.0)
|
|
Reserve Additions
(MMboe)
|
1,089.7
|
826.0
|
250.7
|
|
FD&A Costs
($/boe)
|
4.54
|
3.80
|
4.26
|
4.23
|
FD&A Recycle
Ratio(1)
|
4.0
|
2.7
|
2.7
|
3.3
|
Note:
|
(1)
|
The recycle ratio is
calculated by dividing the cash flow per boe by the appropriate
F&D or FD&A costs related to the reserve additions for that
year.
|
Conference Call Tomorrow at 9:00 a.m.
MT (11:00 a.m. ET)
Tourmaline will host a conference call tomorrow, March 3, 2022 starting at 9:00 a.m. MT (11:00 a.m.
ET). To participate, please dial 1-888-664-6383
(toll-free in North America), or
international dial-in 1-416-764-8650, a few minutes prior to the
conference call.
Conference ID is 68524395.
Reader Advisories
CURRENCY
All amounts in this news release are stated in Canadian dollars
unless otherwise specified.
FORWARD-LOOKING INFORMATION
This news release contains forward-looking information and
statements (collectively, "forward-looking information") within the
meaning of applicable securities laws. The use of any of the words
"forecast", "expect", "anticipate", "continue", "estimate",
"objective", "ongoing", "on track", "may", "will", "project",
"should", "believe", "plans", "intends" and similar expressions are
intended to identify forward-looking information. More particularly
and without limitation, this news release contains forward-looking
information concerning Tourmaline's plans and other aspects of its
anticipated future operations, management focus, objectives,
strategies, financial, operating and production results and
business opportunities, including the following: anticipated
petroleum and natural gas production and production growth for
various periods including estimated production levels for 2022 and
beyond; expected free cash flow and cash flow levels for 2022 and
beyond; targeted 2022 exit net debt to cash flow ratio; the future
declaration and payment of dividends and the timing and amount
thereof including any future increase; cash flow and free cash flow
levels; production levels supported by certain of the Company's
reserves and drilling inventory; capital expenditures over various
periods; cost reduction initiatives; improvements in capital
efficiency; projected operating and drilling costs; the timing for
facility expansions and facility start-up dates; sustainability and
environmental improvement initiatives; anticipated future commodity
prices including the expectation for future increases above current
levels; the ability to generate, and the amount of, anticipated
cash flow and free cash flow including in 2022 and over the five
year development plan; expectations that in 2023 Tourmaline will
become the first Canadian EP company participating in the LNG
business with full exposure to JKM pricing; the anticipated amount
to be invested per year on environmental performance improvement
initiatives; as well as Tourmaline's future drilling prospects and
plans, business strategy, future development and growth
opportunities, prospects and asset base. The forward-looking
information is based on certain key expectations and assumptions
made by Tourmaline, including expectations and assumptions
concerning the following: prevailing and future commodity prices
and currency exchange and interest rates; applicable royalty rates
and tax laws; future well production rates and reserve volumes;
operating costs, the timing of receipt of regulatory approvals; the
performance of existing wells; the success obtained in drilling new
wells; anticipated timing and results of capital expenditures; the
sufficiency of budgeted capital expenditures in carrying out
planned activities; the timing, location and extent of future
drilling operations; the successful completion of acquisitions and
dispositions and the benefits to be derived therefrom; the state of
the economy and the exploration and production business; the
availability and cost of financing, labour and services; ability to
maintain its investment grade credit rating; and ability to market
crude oil, natural gas and NGL successfully. Without limitation of
the foregoing, future dividend payments, if any, and the level
thereof is uncertain, as the Company's dividend policy and the
funds available for the payment of dividends from time to time is
dependent upon, among other things, free cash flow, financial
requirements for the Company's operations and the execution
of its growth strategy, fluctuations in working capital and the
timing and amount of capital expenditures, debt service
requirements and other factors beyond the Company's control.
Further, the ability of Tourmaline to pay dividends will be subject
to applicable laws (including the satisfaction of the solvency test
contained in applicable corporate legislation) and contractual
restrictions contained in the instruments governing its
indebtedness, including its credit facility.
Statements relating to "reserves" are also deemed to be forward
looking information, as they involve the implied assessment, based
on certain estimates and assumptions, that the reserves described
exist in the quantities predicted or estimated and that the
reserves can be profitably produced in the future.
Although Tourmaline believes that the expectations and
assumptions on which such forward-looking information is based are
reasonable, undue reliance should not be placed on the
forward-looking information because Tourmaline can give no
assurances that it will prove to be correct. Since forward-looking
information addresses future events and conditions, by its very
nature it involves 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:
the risks associated with the oil and natural gas industry in
general such as 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
estimates and projections relating to reserves, production,
revenues, costs and expenses; health, safety and environmental
risks; commodity price and exchange rate fluctuations; interest
rate fluctuations; marketing and transportation; loss of markets;
environmental risks; competition; incorrect assessment of the value
of acquisitions; failure to complete or realize the anticipated
benefits of acquisitions or dispositions; ability to access
sufficient capital from internal and external sources; failure to
obtain required regulatory and other approvals; climate change
risks; inflation; supply chain risks and changes in legislation,
including but not limited to tax laws, royalties and environmental
regulations.
In addition, wars (including Russia's military actions in Ukraine), hostilities, civil insurrections,
pandemics, epidemics or outbreaks of an infectious disease in
Canada or worldwide, including
COVID-19 or other illnesses could have an adverse impact on the
Company's results, business, financial condition or liquidity.
Ongoing military actions between Russia and Ukraine have the potential to threaten the
supply of oil and gas from the region. The long-term impacts of the
actions between these nations remains uncertain. If the
pandemic is further prolonged, including through subsequent waves,
or if additional variants of COVID-19 emerge which are more
transmissible or cause more severe disease, or if other diseases
emerge with similar effects, the adverse impact on the economy
could worsen. It remains uncertain how the macroeconomic
environment, and societal and business norms will be impacted
following the COVID-19 pandemic.
Readers are cautioned that the foregoing list of factors is not
exhaustive.
Additional information on these and other factors that could
affect Tourmaline, or its operations or financial results, are
included in the Company's most recently filed Management's
Discussion and Analysis (See "Forward-Looking Statements" therein),
Annual Information Form (See "Risk Factors" and "Forward-Looking
Statements" therein) and other reports on file with applicable
securities regulatory authorities and may be accessed through the
SEDAR website (www.sedar.com) or Tourmaline's website
(www.tourmalineoil.com).
The forward-looking information contained in this news release
is made as of the date hereof and Tourmaline undertakes no
obligation to update publicly or revise any forward-looking
information, whether as a result of new information, future events
or otherwise, unless expressly required by applicable securities
laws.
RESERVES DATA
The reserves data set forth above is based upon the reports of
GLJ Ltd. ("GLJ") and Deloitte LLP, each dated effective
December 31, 2021, which have been
consolidated into one report by GLJ and adjusted to apply certain
of GLJ's assumptions and methodologies and pricing and cost
assumptions. The price forecast used in the reserve
evaluations is an average of the January 1,
2022 price forecasts for GLJ, Sproule Associates Ltd. and
McDaniel & Associates Consultants Ltd., each of which is
available on their respective websites, www.gljpc.com,
www.sproule.com and www.mcdan.com, and will be contained in the
Company's Annual Information Form for the year ended December 31, 2021, which will be filed on SEDAR
(accessible at www.sedar.com) on or before March 31, 2022.
There are numerous uncertainties inherent in estimating
quantities of crude oil, natural gas and NGL reserves and the
future cash flows attributed to such reserves. The reserve
and associated cash flow information set forth above are estimates
only. In general, estimates of economically recoverable crude oil,
natural gas and NGL reserves and the future net cash flows
therefrom are based upon a number of variable factors and
assumptions, such as historical production from the properties,
production rates, ultimate reserve recovery, timing and amount of
capital expenditures, marketability of oil and natural gas, royalty
rates, the assumed effects of regulation by governmental agencies
and future operating costs, all of which may vary materially.
For those reasons, estimates of the economically recoverable crude
oil, NGL and natural gas reserves attributable to any particular
group of properties, classification of such reserves based on risk
of recovery and estimates of future net revenues associated with
reserves prepared by different engineers, or by the same engineers
at different times, may vary. The Company's actual
production, revenues, taxes and development and operating
expenditures with respect to its reserves will vary from estimates
thereof and such variations could be material.
All evaluations and reviews of future net revenue are stated
prior to any provisions for interest costs or general and
administrative costs and after the deduction of estimated future
capital expenditures for wells to which reserves have been
assigned. The after-tax net present value of the Company's
oil and gas properties reflects the tax burden on the properties on
a stand-alone basis and utilizes the Company's tax pools. It
does not consider the corporate tax situation, or tax
planning. It does not provide an estimate of the after-tax
value of the Company, which may be significantly different.
The Company's financial statements and the management's discussion
and analysis should be consulted for information at the level of
the Company.
The estimates of reserves and future net revenue for individual
properties may not reflect the same confidence level as estimates
of reserves and future net revenue for all properties, due to
effects of aggregations. The estimated values of future net
revenue disclosed in this news release do not represent fair market
value. There is no assurance that the forecast prices and
cost assumptions used in the reserve evaluations will be attained
and variances could be material.
The reserve data provided in this news release presents only a
portion of the disclosure required under National Instrument
51-101. All of the required information will be contained in
the Company's Annual Information Form for the year ended
December 31, 2021, which will be
filed on SEDAR (accessible at www.sedar.com) on or before
March 31, 2022.
BOE EQUIVALENCY
In this news release, production and reserves information may be
presented on a "barrel of oil equivalent" or "BOE" basis. BOEs may
be misleading, particularly if used in isolation. A BOE
conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. In
addition, as the value ratio between natural gas and crude oil
based on the current prices of natural gas and crude oil is
significantly different from the energy equivalency of 6:1,
utilizing a conversion on a 6:1 basis may be misleading as an
indication of value.
INDUSTRY METRICS
This news release contains metrics commonly used in the oil and
natural gas industry. Each of these metrics is determined by
the Company as set out below or elsewhere in this news release.
These metrics are "reserve replacement", "F&D" costs,
"FD&A" costs, "recycle ratio", "F&D recycle ratio", and
"FD&A recycle ratio". These metrics are considered
"non-GAAP ratios" and do not have standardized meanings and may not
be comparable to similar measures presented by other companies. As
such, they should not be used to make comparisons. See "Non-GAAP
and Other Financial Measures" in this news release and in the
Annual MD&A. The non-GAAP financial measures used as a
component of these non-GAAP ratios are capital expenditures and
cash flow.
Management uses these oil and gas metrics for its own
performance measurements and to provide shareholders with measures
to compare the Company's performance over time, however, such
measures are not reliable indicators of the Company's future
performance and future performance may not compare to the
performance in previous periods.
"F&D" costs are calculated by dividing the sum of the total
capital expenditures for the year (in dollars) by the change in
reserves within the applicable reserves category (in boe).
F&D costs, including FDC, includes all capital
expenditures in the year as well as the change in FDC required to
bring the reserves within the specified reserves category on
production.
"FD&A" costs are calculated by dividing the sum of the total
capital expenditures for the year inclusive of the net acquisition
costs and disposition proceeds (in dollars) by the change in
reserves within the applicable reserves category inclusive of
changes due to acquisitions and dispositions (in boe).
FD&A costs, including FDC, includes all capital
expenditures in the year inclusive of the net acquisition costs and
disposition proceeds as well as the change in FDC required to bring
the reserves within the specified reserves category on
production.
The "recycle ratio" is calculated by dividing the cash flow per
boe by the appropriate F&D or FD&A costs related to the
reserve additions for that year.
The Company uses F&D and FD&A as a measure of the
efficiency of its overall capital program including the effect of
acquisitions and dispositions. The aggregate of the
exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future
development costs generally will not reflect total finding and
development costs related to reserves additions for that year.
FINANCIAL OUTLOOKS
Also included in this news release are estimates of Tourmaline's
2022 cash flow and free cash flow, which are based on, among other
things, the various assumptions as to production levels, capital
expenditures, annual cash flows and other assumptions disclosed in
this news release and including Tourmaline's estimated average 2022
production of 500,000 boepd, 2022 commodity price assumptions for
natural gas (NYMEX (US) - $4.49/mcf;
AECO - $4.20/mcf) crude oil (WTI (US)
- $83.95/bbl) and an exchange rate
assumption of $0.79 (US/CAD). To the
extent such estimates constitute financial outlooks, they were
approved by management and the Board of Directors of Tourmaline on
March 2, 2022 and are included to
provide readers with an understanding of Tourmaline's anticipated
cash flow and free cash flow based on the capital expenditure,
production and other assumptions described herein and readers are
cautioned that the information may not be appropriate for other
purposes.
NON-GAAP AND OTHER FINANCIAL MEASURES
This news release contains the terms cash flow, capital
expenditures, free cash flow, and operating netback which are
considered "non-GAAP financial measures" and cash flow per diluted
share, operating netback per boe, cash flow per boe, finding and
development costs, finding, development and acquisition costs and
recycle ratio, which are considered "non-GAAP ratios". These terms
do not have a standardized meaning prescribed by GAAP. In addition,
this news release contains the terms adjusted working capital and
net debt, which are considered "capital management measures" and do
not have standardized meanings prescribed by GAAP. This
news release also contains the terms reserve value per diluted
share, operating expenses ($/boe), and transportation costs
($/boe), which are considered "supplementary financial measures"
and do not have standardized meanings prescribed by GAAP.
Accordingly, the Company's use of these terms may not be comparable
to similarly defined measures presented by other companies.
Investors are cautioned that these measures should not be construed
as an alternative to net income determined in accordance with GAAP
and these measures should not be considered to be more meaningful
than GAAP measures in evaluating the Company's
performance.
Non-GAAP Financial Measures
Cash Flow
Management uses the term "cash flow" for its own performance
measure and to provide shareholders and potential investors with a
measurement of the Company's efficiency and its ability to generate
the cash necessary to fund its future growth expenditures, to repay
debt or to pay dividends. The most directly comparable GAAP
measure for cash flow is cash flow from operating activities.
A summary of the reconciliation of cash flow from operating
activities to cash flow, is set forth below:
|
Three Months
Ended
December 31,
|
Years Ended
December 31,
|
(000s)
|
2021
|
2020
|
2021
|
2020
|
Cash flow from
operating activities (per GAAP)
|
$
|
1,058,460
|
$
|
326,526
|
$
|
2,847,117
|
$
|
1,125,136
|
Change in non-cash
working capital (deficit)
|
(90,224)
|
70,343
|
82,009
|
60,551
|
Cash flow
|
$
|
968,236
|
$
|
396,869
|
$
|
2,929,126
|
$
|
1,185,687
|
Capital Expenditures
Management uses the term "capital expenditures" as a measure of
capital investment in exploration and production activity, as well
as property acquisitions and divestitures, and such spending is
compared to the Company's annual budgeted capital
expenditures. The most directly comparable GAAP measure for
capital expenditures is cash flow used in investing
activities. A summary of the reconciliation of cash flow used
in investing activities to capital expenditures, is set forth
below:
|
Three Months
Ended
December 31,
|
Years Ended
December 31,
|
(000s)
|
2021
|
2020
|
2021
|
2020
|
Cash flow used in
investing activities (per GAAP)
|
$
|
468,384
|
$
|
326,526
|
$
|
1,380,111
|
$
|
1,162,271
|
Corporate
acquisitions
|
-
|
(73,750)
|
-
|
(100,822)
|
Proceeds from sale of
investments
|
-
|
-
|
103,824
|
-
|
Change in non-cash
working capital (deficit)
|
(20,923)
|
794
|
106,436
|
22,176
|
Capital
expenditures
|
$
|
447,461
|
$
|
271,284
|
$
|
1,590,371
|
$
|
1,083,625
|
Free Cash Flow
Management uses the term "free cash flow" for its own
performance measure and to provide shareholders and potential
investors with a measurement of the Company's efficiency and its
ability to generate the cash necessary to fund its future growth
expenditures, to repay debt and provide shareholder returns.
Free cash flow is defined as cash flow less capital expenditures,
excluding acquisitions and dispositions. Free cash flow is
prior to dividend payment. The most directly comparable GAAP
measure for cash flow is cash flow from operating activities.
See "Non-GAAP Financial Measures – Cash Flow" and " Non-GAAP
Financial Measures – Capital Expenditures" above.
Operating Netback
Management uses the term "operating netback" as a key
performance indicator and one that is commonly presented by other
oil and natural gas producers. Operating netback is defined
as the sum of commodity sales from production, premium (loss) on
risk management activities and realized gains (loss) on financial
instruments less the sum of royalties, transportation costs and
operating expenses. A summary of the reconciliation of
operating netback from commodity sales from production, which is a
GAAP measure, is set forth below:
|
Three Months
Ended
December 31,
|
Years Ended
December 31,
|
($/boe)
|
2021
|
2020
|
2021
|
2020
|
Commodity sales from
production
|
$
|
1,709,063
|
$
|
688,269
|
$
|
5,053,611
|
$
|
2,200,911
|
Premium (loss) on risk
management activities
|
21,579
|
(10,913)
|
13,943
|
(106,001)
|
Realized gain (loss) on
financial instruments
|
(201,297)
|
11,018
|
(398,291)
|
79,993
|
Royalties
|
(168,168)
|
(28,623)
|
(387,914)
|
(65,523)
|
Transportation
costs
|
(198,537)
|
(136,875)
|
(683,737)
|
(509,520)
|
Operating
expenses
|
(176,360)
|
(100,590)
|
(607,292)
|
(356,674)
|
Operating
netback
|
$
|
986,280
|
$
|
422,286
|
$
|
2,990,320
|
$
|
1,243,186
|
Non-GAAP Financial Ratios
Operating Netback per-boe
Management calculates "operating netback per-boe" as operating
netback divided by total production for the period. Netback
per-boe is a key performance indicator and measure of operational
efficiency and one that is commonly presented by other oil and
natural gas producers. A summary of the calculation of
operating netback per boe, is set forth below:
|
Three Months
Ended
December 31,
|
Years Ended
December 31,
|
($/boe)
|
2021
|
2020
|
2021
|
2020
|
Revenue, excluding
processing income
|
$
|
34.27
|
$
|
22.25
|
$
|
29.00
|
$
|
19.13
|
Royalties
|
(3.77)
|
(0.93)
|
(2.41)
|
(0.58)
|
Transportation
costs
|
(4.45)
|
(4.42)
|
(4.25)
|
(4.48)
|
Operating
expenses
|
(3.95)
|
(3.25)
|
(3.77)
|
(3.14)
|
Operating
netback
|
$
|
22.10
|
$
|
13.65
|
$
|
18.57
|
$
|
10.93
|
Cash Flow per-boe
Management uses cash flow per boe to highlight how much cash
flow is generated by each boe produced. The ratio is
calculated by dividing cash flow by total production for the
period. See "Non-GAAP Financial Measures – Cash Flow".
See "Reserve Performance Ratios" section for information on annual
cash flow per boe and comparative period data used.
Capital Management Measures
Adjusted Working Capital
Management uses the term "adjusted working capital" for its own
performance measures and to provide shareholders and potential
investors with a measurement of the Company's liquidity. A
summary of the composition of adjusted working capital (deficit),
is set forth below:
|
As at December
31,
|
(000s)
|
2021
|
2020
|
Working capital
(deficit)
|
$
|
(361,034)
|
$
|
111,744
|
Fair value of financial
instruments – short-term liability
|
240,970
|
36,115
|
Lease liabilities –
short-term
|
2,997
|
3,412
|
Decommissioning
obligations – short-term
|
20,103
|
4,618
|
Unrealized foreign
exchange in working capital – (asset) liability
|
(6,441)
|
1,450
|
Adjusted working
capital (deficit)
|
$
|
(103,405)
|
$
|
157,339
|
Net Debt
Management uses the term "net debt", as a key measure for
evaluating its capital structure and to provide shareholders and
potential investors with a measurement of the Company's total
indebtedness. A summary of the composition of net debt, is
set forth below:
|
As at December
31,
|
(000s)
|
2021
|
2020
|
Bank debt
|
$
|
(421,539)
|
$
|
(1,942,259)
|
Senior unsecured
notes
|
(448,035)
|
-
|
Adjusted working
capital (deficit)
|
(103,405)
|
157,339
|
Net debt
|
$
|
(972,979)
|
$
|
(1,784,920)
|
Supplementary Financial Measures
The following measures are supplementary financial measures:
reserve value per diluted share, operating expenses ($/boe), and
transportation costs ($/boe). These measures are calculated by
dividing the numerator by a diluted share count or by total
production for the period, depending on the financial measure
discussed.
Finding and Development Costs, Finding, Development and
Acquisition Costs and Recycle Ratio
See "Reserves Performance Ratios" and "Industry Metrics" for
information on the composition of, the non-GAAP financial measures
used as a component of and comparative period data for finding and
development costs, finding, development and acquisition costs and
recycle ratio.
OIL AND GAS METRICS
This news release contains certain oil and gas metrics which do
not have standardized meanings or standard methods of calculation
and therefore such measures may not be comparable to similar
measures used by other companies and should not be used to make
comparisons. Such metrics have been included in this document to
provide readers with additional measures to evaluate the Company's
performance; however, such measures are not reliable indicators of
the Company's future performance and future performance may not
compare to the Company's performance in previous periods and
therefore such metrics should not be unduly relied upon.
ESTIMATES OF DRILLING LOCATIONS
Unbooked drilling locations are the internal estimates of
Tourmaline based on Tourmaline's prospective acreage and an
assumption as to the number of wells that can be drilled per
section based on industry practice and internal review. Unbooked
locations do not have attributed reserves or resources (including
contingent and prospective). Unbooked locations have been
identified by Tourmaline's management as an estimation of
Tourmaline's multi-year drilling activities based on evaluation of
applicable geologic, seismic, engineering, production and reserves
information. There is no certainty that Tourmaline will drill
all unbooked drilling locations and if drilled there is no
certainty that such locations will result in additional oil and
natural gas reserves, resources or production. The drilling
locations on which Tourmaline will actually drill wells, including
the number and timing thereof is ultimately dependent upon the
availability of funding, regulatory approvals, seasonal
restrictions, oil and natural gas prices, costs, actual drilling
results, additional reservoir information that is obtained and
other factors. While a certain number of the unbooked drilling
locations have been de-risked by Tourmaline 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 of Tourmaline 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.
SUPPLEMENTAL INFORMATION REGARDING PRODUCT TYPES
This news release includes references to 2021 average daily
production, Q4 2021 average daily production, current average daily
production, Q1 2022 average daily production and 2022 average daily
production. The following table is intended to provide supplemental
information about the product type composition for each of the
production figures that are provided in this news release:
|
|
Light and Medium
Crude Oil(1)
|
|
Conventional
Natural Gas
|
|
Shale Natural
Gas
|
|
Natural Gas
Liquids(1)
|
|
Oil Equivalent
Total
|
|
|
Company Gross
(Bbls)
|
|
Company Gross
(Mcf)
|
|
Company Gross
(Mcf)
|
|
Company Gross
(Bbls)
|
|
Company Gross
(Boe)
|
2021 Annual
Production
|
|
13,725,460
|
|
462,324,351
|
|
290,836,724
|
|
21,754,730
|
|
161,007,036
|
2021 Average Daily
Production
|
|
37,604
|
|
1,266,642
|
|
796,813
|
|
59,602
|
|
441,115
|
Q4 2021 Average Daily
Production
|
|
40,880
|
|
1,299,980
|
|
969,310
|
|
65,983
|
|
485,078
|
Current Average Daily
Production
|
|
42,000
|
|
1,280,000
|
|
1,060,000
|
|
73,000
|
|
505,000
|
2022 Average Daily
Production
|
|
42,600
|
|
1,225,000
|
|
1,084,000
|
|
72,600
|
|
500,000
|
(1)
|
For the purposes of
this disclosure, condensate has been combined with Light and Medium
Crude Oil as the associated revenues and certain costs of
condensate are similar to Light and Medium Crude Oil.
Accordingly, NGLs in this disclosure exclude
condensate.
|
INITIAL PRODUCTION RATES
Any references in this news release to initial production rates
are useful in confirming the presence of hydrocarbons; however,
such rates are not determinative of the rates at which such wells
will continue production and decline thereafter and are not
necessarily indicative of long-term performance or ultimate
recovery. While encouraging, readers are cautioned not to place
reliance on such rates in calculating the aggregate production for
the Company. Such rates are based on field estimates and may be
based on limited data available at this time.
CREDIT RATINGS
Credit ratings are intended to provide investors with an
independent measure of credit quality of an issue of securities.
Credit ratings are not recommendations to purchase, hold or sell
securities and do not address the market price or suitability of a
specific security for a particular investor. There is no assurance
that any rating will remain in effect for any given period of time
or that any rating will not be revised or withdrawn entirely by a
rating agency in the future if, in its judgment, circumstances so
warrant.
GENERAL
See also "Forward-Looking Statements", and "Non-GAAP and Other
Financial Measures" in the most recently filed Management's
Discussion and Analysis.
Certain
Definitions:
|
|
1H
|
first half
|
2H
|
second half
|
bbl
|
barrel
|
bbls/day
|
barrels per
day
|
bbl/mmcf
|
barrels per million
cubic feet
|
bcf
|
billion cubic
feet
|
bcfe
|
billion cubic feet
equivalent
|
bpd or
bbl/d
|
barrels per
day
|
boe
|
barrel of oil
equivalent
|
boepd or
boe/d
|
barrel of oil
equivalent per day
|
bopd or
bbl/d
|
barrel of oil,
condensate or liquids per day
|
DUC
|
drilled but uncompleted
wells
|
EP
|
exploration and
production
|
gj
|
gigajoule
|
gjs/d
|
gigajoules per
day
|
mbbls
|
thousand
barrels
|
mmbbls
|
million
barrels
|
mboe
|
thousand barrels of oil
equivalent
|
mboepd
|
thousand barrels of oil
equivalent per day
|
mcf
|
thousand cubic
feet
|
mcfpd or
mcf/d
|
thousand cubic feet per
day
|
mcfe
|
thousand cubic feet
equivalent
|
mmboe
|
million barrels of oil
equivalent
|
mmbtu
|
million British thermal
units
|
mmbtu/d
|
million British thermal
units per day
|
mmcf
|
million cubic
feet
|
mmcfpd or
mmcf/d
|
million cubic feet per
day
|
MPa
|
megapascal
|
mstb
|
thousand stock tank
barrels
|
natural
gas
|
conventional natural
gas and shale gas
|
NCIB
|
normal course issuer
bid
|
NGL or
NGLs
|
natural gas
liquids
|
tcf
|
trillion cubic
feet
|
MANAGEMENT'S DISCUSSION AND ANALYSIS AND CONSOLIDATED
FINANCIAL STATEMENTS
To view Tourmaline's Management's Discussion and Analysis and
Consolidated Financial Statements for the years ended December 31, 2021 and 2020, please refer to SEDAR
(www.sedar.com) or Tourmaline's website at
www.tourmalineoil.com.
ABOUT TOURMALINE OIL CORP.
Tourmaline is Canada's largest
and most active natural gas producer dedicated to producing the
lowest-emission and lowest-cost natural gas in North America. We are an investment grade
exploration and production company providing strong and predictable
operating and financial performance through the development of our
three core areas in the Western Canadian Sedimentary Basin. With
our existing large reserve base, decades-long drilling inventory,
relentless focus on execution and cost management, and
industry-leading environmental performance, we are excited to
provide shareholders an excellent return on capital, and an
attractive source of income through our base dividend and surplus
free cash flow distribution strategies.
SOURCE Tourmaline Oil Corp.