CALGARY, AB, March 10, 2021 /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 2020 as well as 2020 reserves.
HIGHLIGHTS
- Achieved record production in Q4 2020, exiting 2020 producing
in excess of 400,000 boepd.
- Achieved a record 2P reserve addition of 826.0 mmboe in 2020
with finding, development and acquisition ("FD&A") costs of
$3.80/boe, including changes in
future development capital ("FDC").
- Fourth quarter 2020 cash flow(1) was $396.9 million ($1.44 per diluted share) and full-year 2020 cash
flow was $1,185.7 billion
($4.36 per diluted share). Fourth
quarter 2020 free cash flow(2) was $144.8 million.
- In 2021, at current strip pricing(3), the Company
expects to generate cash flow of $2.2
billion and free cash flow of $1.1
billion on EP capital spending of $1.075 billion.
- Increased the dividend in 2020 despite a difficult year for
Industry - the fourth increase since inception of the dividend in
2018. Given stronger than anticipated cash flow in future years,
the Company is increasing its dividend by 14% from $0.14 per share per quarter to $0.16 per share per quarter, commencing in
the first quarter of 2021.
- Completed four accretive corporate acquisitions in 2020 that
are estimated to have increased the five-year plan free cash flow
generation by over 20% or approximately $200
million per annum starting in 2022.
- Delivered full-year 2020 earnings of $618.3 million, underscoring the inherent
profitability of the Company's business model.
- Tourmaline received an 'A' rating in the MSCI Global ESG
Performance Ranking for its sustainability and environmental
initiatives.
PRODUCTION UPDATE
- Current production is averaging between 405,000-410,000 boepd,
at the higher end of the full-year guidance range of
390,000-410,000 boepd. Despite higher commodity prices, the Company
is maintaining previously disclosed production guidance for 2021.
The Company expects Q1 2021 average production of between 400,000
and 405,000 boepd.
- Q4 2020 average production was 336,325 boepd, and full-year
2020 average production was 310,598 boepd, both within
guidance.
- Natural gas production is forecast to average approximately
1.85-1.9 bcf/day in 2021 and combined oil, condensate, and NGL
production is expected to average approximately 85,000-90,000 bpd
in 2021. Tourmaline is Canada's
largest natural gas and NGL producer, and the second largest
condensate producer.
- All three operated EP complexes have achieved production
records during Q1 2021: the Alberta Deep Basin complex is currently
producing 252,000 boepd, NEBC is producing 135,000 boepd, and the
Peace River High complex is producing 23,000 boepd.
FINANCIAL HIGHLIGHTS
- Full-year 2020 after-tax earnings were $618.3 million ($2.27 per diluted share) as Tourmaline remained
profitable despite a challenging year for Industry.
- Fourth quarter 2020 cash flow was $396.9
million ($1.44 per diluted
share) and full-year 2020 cash flow was $1,185.7 billion ($4.36 per diluted share).
- Tourmaline generated $273.9
million in free cash flow in 2020.
- Despite a global pandemic and an oil price crash in 2020,
Tourmaline increased its dividend from 12
cents per share per quarter to 14
cents which was fully funded from free cash flow generated
in 2020.
- Tourmaline continued to effectively manage all-in cash costs in
2020 (operating, transportation, general and administrative, and
financing) which totaled $8.60/boe,
compared with $8.18/boe in 2019 with
a slight increase as a result of the corporate acquisitions which
carried higher cash costs. Operating costs on the acquired assets
are expected to trend down in 2021-2022.
- Achieved a public investment grade credit rating allowing the
Company to issue $250 million of debt
at a fixed rate of 2.077% for seven years.
- Topaz Energy Corp. ("Topaz") successfully completed its initial
public offering in 2020 with the market value of Tourmaline's 51.7%
equity ownership of Topaz at December 31,
2020 valued at $790.8 million
based on a December 31, 2020 closing
price for Topaz common shares of $13.60 per share.
2020/2021 BUDGET AND OUTLOOK
- 2020 Q4 EP capital spending was $243.6
million, full-year 2020 EP spending was $878.8 million.
- Tourmaline accelerated two large frac operations at
Spirit River, AB and Doe, NEBC
from January 2021 to December 2020 primarily for logistical reasons,
avoiding the anticipated post year-end industry frac activity
ramp-up. The Company also increased planned Q4 drilling activities
on the Jupiter and Modern assets post acquisition as well as at
Sundown and Birley-Laprise, B.C. Completing these field activities
earlier than originally planned also provided Tourmaline with
additional winter 2021 gas volumes, allowing the Company to further
benefit from the price spikes that occurred. As a result of these
accelerated expenditures into 2020, the 2021 EP capital budget has
been reduced by $25 million, from
$1.10 billion to $1.075 billion.
- Tourmaline generated cash flow of $396.9
million and free cash flow of $144.8
million in Q4 2020 on EP capital spending of $243.6 million.
- In 2021, at current strip pricing, the Company expects to
generate cash flow of $2.2 billion
and free cash flow of $1.1 billion on
EP capital spending of $1.075
billion. The free cash flow in 2021 will be designated for
debt reduction, potential dividend increases, selective
acquisitions, capital investment in emission reduction
technologies, and potential share buybacks.
- The $1.075 billion 2021 capital
budget consists of approximately $900
million of maintenance capital, required to keep production
flat at 400,000 boepd, and $175
million directed towards realizing the unchanged 3-5% annual
growth outlined in the five-year development plan. The Gundy, B.C. Phase 2 deep cut expansion remains
the only significant new project in the five-year plan.
$100 million of the $175 million in available incremental capital for
2021 is directed to the Phase 2 deep cut facility construction. The
new facility will commence production in Q2 2022 (200 mmcfpd,
15,000 bpd condensate and liquids) and is strategically tied to an
increase in gas transportation capacity to California commencing in 2022 and 2023.
- In the updated five-year plan, Tourmaline expects to generate
$4.1 billion of free cash flow at
strip pricing over the five years.
- Strong natural gas prices, coupled with the Company's long
evolving market diversification strategy, will result in materially
stronger Q1 2021 cash flows than originally anticipated.
- Current full-year 2021 net debt(4) to cash flow is
now expected to be 0.4 times. Tourmaline expects to reduce debt to
its target total debt amount of $1.3
billion in 2H 2021, after which free cash flow allocation
will shift to potential dividend increases, accretive acquisitions,
capital investment in emission reduction technologies and potential
share buybacks.
2020 RESERVES
- Tourmaline increased 2P reserves to 3.31 billion boe in 2020 at
historically low FD&A costs.
- Year-end 2020 proved, developed producing ("PDP") reserves of
736.4 million boe were up 61.2 per cent over year-end 2019 when
including 2020 annual production of 113.7 million boe. Total proved
("TP") reserves of 1.7 billion boe were up 39.4 per cent when
including 2020 annual production. 2P reserves of 3.31 billion boe
were up 31.7 per cent including 2020 annual production.
- Tourmaline's 2020 PDP FD&A costs were $5.46 per boe including changes in FDC, a record
low, yielding a PDP reserve recycle ratio(5) of 1.91.
Total proved FD&A costs in 2020 were $4.86 per boe including changes in FDC, and 2P
FD&A was $3.80 per boe including
changes in FDC. The 2P FD&A recycle ratio was 2.7 in 2020.
- Tourmaline replaced 727% of its 2020 annual production of 113.7
million boe in 2020 with 2P additions of 826.0 million boe before
2020 production.
- Tourmaline's 2P reserve
value(6) equates to $57.95 per diluted share using the January 1, 2021 engineering price deck and a 10%
discount rate. TP reserve value is $35.03 per diluted share and PDP reserve value is
$20.17 per diluted share using the
same pricing and discount rates.
- After 12 years of operation, Tourmaline now has 15.5 trillion
cubic feet of 2P natural gas reserves, one of the largest,
lowest-development cost, lowest-emission natural gas reserve bases
in North America as well as 738
million barrels of 2P crude oil, condensate, and NGL (natural gas
liquids) reserves (January 1,
2021).
- Tourmaline has only booked 2,579 (gross) locations of a total
drilling inventory of 20,014 gross locations (13% per cent of the
overall inventory) to achieve year-end 2020 2P reserves of 3.31
billion boe.
- For the eighth consecutive year, the Company enjoyed positive
2P technical revisions in its reserve report.
MARKETING UPDATE
- Tourmaline has an average of 567 mmcfpd hedged for 2021 at a
weighted-average fixed price of CAD $2.64/mcf; an average of 129 mmcfpd hedged at a
basis to NYMEX of $(0.01) USD/mcf;
and an average of 502 mmcfpd incremental volume exposed to export
markets, including Dawn, Iroquois,
Empress, Chicago, Ventura, Sumas, Malin and PG&E.
- Natural gas fundamentals for 2021 and 2022 are steadily
improving. Approximately 61% of Tourmaline's natural gas volumes
are exposed to spot prices in markets on the Western half of the
continent (PG&E, Malin, Sumas, Station 2, AECO) where 2021
fundamentals continue to be most supportive.
- At PG&E, 95% of the total deliveries remain unhedged for
2021 at a market where forward prices continue to be strong.
- Tourmaline has sales diversification to the US and other hubs
of 584 mmcfpd for exit 2021, 705 mmcfpd for exit 2022 and 755
mmcfpd for exit 2023. The Company's diversified transportation
portfolio, with associated direct sale opportunities, allowed for
considerable realized price and cash flow benefits during the
February 2021 cold snap.
- The Company will continue to hedge volumes related to 2021 and
2022 over the next several months.
- Tourmaline had 4 bcf of natural gas in storage facilities at
Dawn, Ontario and PG&E,
San Francisco which was fully
withdrawn as the Company took advantage of the higher natural gas
prices.
EP UPDATE
- Tourmaline operated 12 drilling rigs and three to four frac
spreads across the three operated core EP complexes in January and
February - activity is now tapering into spring breakup.
- The Company expects to drill and complete a total of
approximately 225 (gross) wells during 2021.
- During 2020, the Company systematically drilled longer
horizontals in all three complexes. Average horizontal well
laterals were 16% longer, however, average drilling costs for these
longer wells in 2020 were down on average 6% across all three
complexes. Total completion costs for the longer horizontal wells
were down 14% over 2019 levels, on a completed lateral meter
basis.
- Tourmaline accelerated the completion and stimulation of the
Spirit River 6-10-78-8 W6 pad from January
2021 to December 2020. The
seven well Montney and Lower
Charlie Lake pad has significantly exceeded performance curve
expectations and is producing at a combined rate of 3,365 bpd of
light crude oil and 31.4 mmcfpd of natural gas after 68 days of
production. Five of the seven wells on the pad rank as the top five
oil wells in Alberta for
January 2021, based on calendar-day
production rates and were brought on-stream during a period of
increasing oil and natural gas prices.
- Tourmaline elected to complete the Phase 1 expansion of the
Sundown, B.C. Montney project
during the second half of 2020. During the past five years, the
Company has been steadily expanding the land position at Sundown,
steadily dropping drill/complete capital costs and dropping
operating expenses to less than $2.00/boe. The Company expanded the existing gas
processing facility at Sundown and drilled one five-well pad during
Q4 2020, bringing on an incremental 40 mmcfpd at a capital
efficiency of $4,500/boepd, including
facility costs. The Sundown facility is now producing at 120
mmcfpd; the next expansion phase will grow production to 250 mmcfpd
at similar capital efficiencies. This second expansion is not
currently in the five-year development plan. Current Sundown 2P
reserves are 1.0 TCF of natural gas, with 90 locations included in
the Company's reserve report and an estimated 857 locations
remaining in inventory.
- The Company continues to realize the anticipated 30-40% capital
cost reduction for drilling and completion activities on the
acquired Jupiter and Modern assets in the Alberta Deep Basin
complex.
SUSTAINABILITY AND ENVIRONMENTAL PERFORMANCE
IMPROVEMENT
- Tourmaline won independent awards in 2020 for ongoing
successful efforts to reduce emissions through diesel displacement
and for water management activities that ultimately eliminate
freshwater usage in frac operations. The Company achieved an
Industry 'A' rating in the most recent MSCI Global ESG Performance
ranking.
- Tourmaline has had an engineering team in place for over 18
months developing and implementing new proprietary emission
reduction technologies, executing expanded water management
initiatives, managing third-party environmental related research,
and more recently managing an emerging carbon offset business.
- Tourmaline is operating a methane testing and research
facility, the only one in Canada,
at one of the Company's Ansell-Edson gas processing facilities.
This site will evolve technology that more accurately measures
fugitive, flare and storage emissions as well as drives towards
zero methane emission well sites.
- Tourmaline has invested $8.0
million to date building proprietary units for the Company's
broad diesel displacement initiatives. The long-term goal is to
transition all drilling and frac operations to much lower emission
emitting natural gas, or where possible, highline
power/electricity. The Company's rig in the Peace River High area
is fully electric, operating solely off highline power. The cost
savings realized from reduced diesel in drilling operations this
January alone were $1.8 million. To
date, the Company has displaced 34.6 million litres of diesel with
a net savings of $28.0 million
including the cost of the replacement natural gas. On an energy
equivalent basis, natural gas emits 30% less CO2, 90% less carbon
monoxide, 95% less nitrogen dioxide, 90% less particulate matter,
and 99% less sulfur dioxide than diesel. The go-forward,
longer-term costs savings, are expected to be well over
$75 million from this initiative
which also provides a major contribution towards the corporate goal
of reducing CO2 emission intensity by over 25% in the next five
years.
SOCIAL
- Tourmaline was the most active operator in the WCSB in 2020
during the pandemic, employing as many people as possible in the
service sector and in the rural communities of Alberta and British
Columbia while continuing to safely, effectively and
efficiently manage operations.
- During the global pandemic in 2020, Tourmaline made multiple
foodbank, United Way, and youth development charitable donations
totaling over $1 million assisting
people in need in Calgary,
Edson, Hinton, Grande
Prairie, Spirit River, and
Fort St. John.
- Tourmaline was one of the few senior Canadian producers that
did not reduce its dividend, recognizing the broad shareholder base
and many individuals who rely on the dividend for necessary income,
accentuated during the COVID-19 crisis.
DIVIDEND
- The Company is pleased to announce that its Board of Directors
has declared a quarterly cash dividend on its common shares of
C$0.16 per common share. The dividend
will be payable March 31, 2021 to
shareholders of record at the close of business on March 18, 2021. This quarterly cash dividend is
designated as an "eligible dividend" for Canadian income tax
purposes.
(1)
|
"Cash flow" is
defined as cash provided by operations before changes in non-cash
operating working capital. See "Non-GAAP Financial Measures"
in this news release and in the Company's 2020 Management's
Discussion and Analysis.
|
|
|
(2)
|
"Free cash flow"
is defined as cash flow less total net capital expenditures.
Total net capital expenditures is defined as total capital spending
before acquisitions, net of non-core dispositions. Free cash
flow is prior to dividend payments. See "Non-GAAP Financial
Measures" in this news release and the Company's 2020 Management's
Discussion and Analysis.
|
|
|
(3)
|
Based on oil and
gas commodity strip pricing at March 1, 2021.
|
|
|
(4)
|
See "Non-GAAP
Financial Measures" in this news release and in the
Company's Management's Discussion and Analysis for the year ended
December 31, 2020.
|
|
|
(5)
|
The recycle ratio
is calculated by dividing the cash flow per boe by the appropriate
F&D or FD&A costs related to the reserve additions for that
year.
|
|
|
(6)
|
2P reserve
value per share is calculated as the before tax net present value
of the reserves at December 31, 2020 discounted at 10% divided by
total diluted shares outstanding at December 31,
2020.
|
CORPORATE SUMMARY – DECEMBER 31,
2020
|
Three Months Ended
December 31,
|
Twelve Months Ended
December 31,
|
|
2020
|
2019
|
Change
|
2020
|
2019
|
Change
|
OPERATIONS
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
Natural gas
(mcf/d)
|
1,592,010
|
1,439,746
|
11%
|
1,476,613
|
1,413,160
|
4%
|
Crude oil, condensate
and NGL (bbl/d)
|
70,990
|
59,886
|
19%
|
64,496
|
55,338
|
17%
|
Oil equivalent
(boe/d)
|
336,325
|
299,844
|
12%
|
310,598
|
290,865
|
7%
|
Product
prices(1)
|
|
|
|
|
|
|
Natural gas
($/mcf)
|
$
|
3.19
|
$
|
2.77
|
15%
|
$
|
2.68
|
$
|
2.59
|
3%
|
Crude oil, condensate
and NGL ($/bbl)
|
$
|
33.85
|
$
|
38.59
|
(12)%
|
$
|
30.87
|
$
|
39.29
|
(21)%
|
Operating expenses
($/boe)
|
$
|
3.25
|
$
|
3.06
|
6%
|
$
|
3.14
|
$
|
3.28
|
(4)%
|
Transportation costs
($/boe)
|
$
|
4.42
|
$
|
4.13
|
7%
|
$
|
4.48
|
$
|
3.86
|
16%
|
Operating
netback(3) ($/boe)
|
$
|
13.65
|
$
|
13.00
|
5%
|
$
|
10.93
|
$
|
12.12
|
(10)%
|
Cash general and
administrative
expenses ($/boe)(2)
|
$
|
0.50
|
$
|
0.52
|
(4)%
|
$
|
0.56
|
$
|
0.49
|
14%
|
FINANCIAL
($000, except share and per share)
|
|
|
|
|
|
|
Total revenue from
commodity sales and realized gains
|
688,374
|
579,588
|
19%
|
2,174,903
|
2,127,337
|
2%
|
Royalties
|
28,623
|
22,559
|
27%
|
65,523
|
83,030
|
(21)%
|
Cash
flow(4)
|
396,869
|
335,856
|
18%
|
1,185,687
|
1,205,540
|
(2)%
|
Cash flow per share
(diluted)(4)
|
$
|
1.44
|
$
|
1.24
|
16%
|
$
|
4.36
|
$
|
4.43
|
(2)%
|
Net
earnings
|
629,191
|
61,340
|
926%
|
618,311
|
319,740
|
93%
|
Net earnings per
share (diluted)
|
$
|
2.28
|
$
|
0.23
|
891%
|
$
|
2.27
|
$
|
1.18
|
92%
|
Capital expenditures
(net of dispositions)
|
271,284
|
320,389
|
(15)%
|
1,083,625
|
1,287,259
|
(16)%
|
Weighted average
shares outstanding (diluted)
|
|
|
|
272,079,590
|
271,878,824
|
-%
|
Net
debt(4)
|
|
|
|
(1,784,920)
|
(1,755,684)
|
2%
|
PROVED +
PROBABLE RESERVES(3)
|
|
|
|
|
|
|
Natural gas
(bcf)
|
|
|
|
15,459.2
|
12,294.6
|
26%
|
Crude oil
(mbbls)
|
|
|
|
102,843
|
96,984
|
6%
|
Natural gas liquids
(mbbls)
|
|
|
|
634,890
|
455,851
|
39%
|
Mboe
|
|
|
|
3,314,264
|
2,601,928
|
27%
|
|
|
(1)
|
Product prices
include realized gains and losses on risk management activities and
financial instrument contracts.
|
(2)
|
Excluding interest
and financing charges.
|
(3)
|
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.
|
(4)
|
See "Non-GAAP
Financial Measures" in this news release and in the Company's
Management's Discussion and Analysis for the year ended December
31, 2020.
|
2020 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.
Tourmaline's Reserves and Net Present Values of Future Net
Revenue disclosed in this news release include the full impact of
the sale of certain assets to Topaz Energy Corp. ("Topaz")
notwithstanding Tourmaline's 51.7% ownership interest in
Topaz. The Net Present Values of Future Net Revenue on a
Total Proved Plus Probable basis (discounted at a rate of 10%)
would increase by approximately 6.5% had the Topaz transaction not
occurred. On a Proved Producing and Total Proved basis, the Net
Present Values of Future Net Revenue (discounted at a rate of 10%)
would increase by approximately 8.5% and 7.6%, respectively.
Refer to the General Development of the Business section in
the Company's recently filed Annual Information Form for further
details.
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, 2020
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
|
|
14,638
|
|
12,807
|
|
2,187,332
|
|
1,990,250
|
|
1,262,996
|
|
1,100,036
|
|
146,755
|
|
127,125
|
|
736,448
|
|
654,979
|
Proved Developed
Non-Producing
|
|
1,791
|
|
1,430
|
|
86,881
|
|
79,270
|
|
174,689
|
|
154,455
|
|
10,365
|
|
9,203
|
|
55,750
|
|
49,587
|
Proved
Undeveloped
|
|
35,721
|
|
30,124
|
|
2,327,817
|
|
2,139,471
|
|
1,921,668
|
|
1,700,155
|
|
154,889
|
|
140,095
|
|
898,857
|
|
810,156
|
Total
Proved
|
|
52,150
|
|
44,361
|
|
4,602,031
|
|
4,208,992
|
|
3,359,353
|
|
2,954,646
|
|
312,008
|
|
276,422
|
|
1,691,056
|
|
1,514,723
|
Total
Probable
|
|
50,693
|
|
42,936
|
|
3,181,653
|
|
2,914,958
|
|
4,316,151
|
|
3,689,427
|
|
322,881
|
|
280,309
|
|
1,623,208
|
|
1,423,976
|
Total Proved Plus
Probable
|
|
102,843
|
|
87,296
|
|
7,783,684
|
|
7,123,950
|
|
7,675,505
|
|
6,644,073
|
|
634,890
|
|
556,731
|
|
3,314,264
|
|
2,938,698
|
|
|
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
|
|
8,659,201
|
|
7,102,128
|
|
6,390,964
|
|
5,993,613
|
|
5,203,745
|
|
4,621,172
|
|
8,659,201
|
|
7,102,128
|
|
6,390,964
|
|
5,993,613
|
|
5,203,745
|
|
4,621,172
|
|
9.15
|
|
1.53
|
Proved Developed
Non-Producing
|
|
763,691
|
|
592,722
|
|
523,565
|
|
486,385
|
|
414,782
|
|
363,460
|
|
606,060
|
|
512,097
|
|
468,528
|
|
443,379
|
|
390,975
|
|
349,840
|
|
9.81
|
|
1.63
|
Proved
Undeveloped
|
|
8,898,335
|
|
5,746,758
|
|
4,549,177
|
|
3,931,094
|
|
2,804,494
|
|
2,060,860
|
|
6,942,509
|
|
4,463,850
|
|
3,523,500
|
|
3,038,714
|
|
2,155,890
|
|
1,573,309
|
|
4.85
|
|
0.81
|
Total
Proved
|
|
18,321,228
|
|
13,441,608
|
|
11,463,706
|
|
10,411,091
|
|
8,423,021
|
|
7,045,492
|
|
16,207,770
|
|
12,078,075
|
|
10,382,992
|
|
9,475,706
|
|
7,750,610
|
|
6,544,320
|
|
6.87
|
|
1.15
|
Total
Probable
|
|
21,803,472
|
|
11,347,402
|
|
8,240,697
|
|
6,812,064
|
|
4,502,129
|
|
3,180,028
|
|
16,789,742
|
|
8,677,720
|
|
6,271,191
|
|
5,167,025
|
|
3,388,007
|
|
2,375,947
|
|
4.78
|
|
0.80
|
Total Proved Plus
Probable
|
|
40,124,699
|
|
24,789,010
|
|
19,704,403
|
|
17,223,156
|
|
12,925,150
|
|
10,225,520
|
|
32,997,511
|
|
20,755,796
|
|
16,654,183
|
|
14,642,731
|
|
11,138,617
|
|
8,920,267
|
|
5.86
|
|
0.98
|
|
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, 2020
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
|
15,239,772
|
|
1,197,826
|
|
4,557,871
|
|
3,771
|
|
821,102
|
|
8,659,201
|
|
-
|
|
8,659,201
|
Proved Developed
Non-Producing
|
1,194,349
|
|
109,414
|
|
261,539
|
|
41,756
|
|
17,948
|
|
763,691
|
|
157,632
|
|
606,060
|
Proved
Undeveloped
|
19,529,608
|
|
1,478,749
|
|
4,378,741
|
|
4,549,430
|
|
224,353
|
|
8,898,335
|
|
1,955,826
|
|
6,942,509
|
Total
Proved
|
35,963,729
|
|
2,785,989
|
|
9,198,151
|
|
4,594,957
|
|
1,063,404
|
|
18,321,228
|
|
2,113,458
|
|
16,207,770
|
Total
Probable
|
40,565,147
|
|
4,222,391
|
|
9,997,501
|
|
4,192,615
|
|
349,169
|
|
21,803,472
|
|
5,013,730
|
|
16,789,742
|
Total Proved Plus
Probable
|
76,528,876
|
|
7,008,379
|
|
19,195,653
|
|
8,787,572
|
|
1,412,573
|
|
40,124,699
|
|
7,127,188
|
|
32,997,511
|
|
|
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
|
|
|
|
Alberta Natural Gas
Liquids
(Then Current Dollars)
|
Year
|
|
Inflation(2)
%
|
|
CAD/USD
Exchange
Rate
$US/$Cdn(3)
|
|
Constant
2021
$US/Bbl
|
|
Then
Current
$US/
Bbl
|
|
MSW, Light
Crude Oil
(40 API,
0.3%S) at
Edmonton
Then
Current
$Cdn/Bbl
|
|
Spec
Ethane
$Cdn/Bbl
|
|
Edmonton
Propane
$Cdn/Bbl
|
|
Edmonton
Butane
$Cdn/Bbl
|
|
Edmonton
C5+
Stream
Quality
$Cdn/Bbl
|
2021
|
|
0.0
|
|
0.7683
|
|
47.17
|
|
47.17
|
|
55.76
|
|
8.91
|
|
18.18
|
|
26.36
|
|
59.24
|
2022
|
|
1.3
|
|
0.7650
|
|
49.51
|
|
50.17
|
|
59.89
|
|
8.65
|
|
21.91
|
|
32.85
|
|
63.19
|
2023
|
|
2.0
|
|
0.7633
|
|
51.44
|
|
53.17
|
|
63.48
|
|
8.35
|
|
24.57
|
|
39.20
|
|
67.34
|
2024
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
54.97
|
|
65.76
|
|
8.46
|
|
25.47
|
|
40.65
|
|
69.77
|
2025
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
56.07
|
|
67.13
|
|
8.63
|
|
26.00
|
|
41.50
|
|
71.18
|
2026
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
57.19
|
|
68.53
|
|
8.81
|
|
26.54
|
|
42.36
|
|
72.61
|
2027
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
58.34
|
|
69.95
|
|
8.99
|
|
27.09
|
|
43.24
|
|
74.07
|
2028
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
59.50
|
|
71.40
|
|
9.17
|
|
27.65
|
|
44.14
|
|
75.56
|
2029
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
60.69
|
|
72.88
|
|
9.36
|
|
28.23
|
|
45.06
|
|
77.08
|
2030
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
61.91
|
|
74.34
|
|
9.55
|
|
28.79
|
|
45.96
|
|
78.62
|
2031
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
63.15
|
|
75.83
|
|
9.74
|
|
29.37
|
|
46.88
|
|
80.19
|
2032
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
64.41
|
|
77.34
|
|
9.93
|
|
29.96
|
|
47.82
|
|
81.80
|
2033
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
65.70
|
|
78.89
|
|
10.13
|
|
30.55
|
|
48.78
|
|
83.43
|
2034
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
67.01
|
|
80.47
|
|
10.33
|
|
31.16
|
|
49.75
|
|
85.10
|
2035
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
68.35
|
|
82.08
|
|
10.54
|
|
31.79
|
|
50.75
|
|
86.80
|
2036
|
|
2.0
|
|
0.7633
|
|
52.14
|
|
+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
|
|
|
|
|
|
|
|
Spot
|
|
|
|
|
|
|
|
|
Year
|
|
Constant
2021
$US/
MMbtu
|
|
Then Current
$US/MMbtu
|
|
Midwest
Price @
Chicago
Then Current
$US/
MMbtu
|
|
AECO/NIT
Spot
Then Current
$Cdn/
MMbtu
|
|
Dawn Price
@ Ontario 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
2.83
|
|
2.83
|
|
2.69
|
|
2.78
|
|
2.73
|
|
2.55
|
|
2.55
|
|
2.56
|
|
2.76
|
|
2.71
|
|
2.48
|
2022
|
|
2.83
|
|
2.87
|
|
2.73
|
|
2.70
|
|
2.80
|
|
2.44
|
|
2.47
|
|
2.49
|
|
2.75
|
|
2.62
|
|
2.38
|
2023
|
|
2.81
|
|
2.90
|
|
2.76
|
|
2.61
|
|
2.83
|
|
2.31
|
|
2.38
|
|
2.40
|
|
2.77
|
|
2.53
|
|
2.30
|
2024
|
|
2.81
|
|
2.96
|
|
2.82
|
|
2.65
|
|
2.89
|
|
2.30
|
|
2.42
|
|
2.43
|
|
2.82
|
|
2.56
|
|
2.33
|
2025
|
|
2.81
|
|
3.02
|
|
2.88
|
|
2.70
|
|
2.94
|
|
2.30
|
|
2.47
|
|
2.48
|
|
2.88
|
|
2.61
|
|
2.38
|
2026
|
|
2.80
|
|
3.08
|
|
2.94
|
|
2.76
|
|
3.00
|
|
2.30
|
|
2.52
|
|
2.53
|
|
2.94
|
|
2.67
|
|
2.43
|
2027
|
|
2.81
|
|
3.14
|
|
3.00
|
|
2.81
|
|
3.06
|
|
2.30
|
|
2.57
|
|
2.59
|
|
3.00
|
|
2.72
|
|
2.48
|
2028
|
|
2.80
|
|
3.20
|
|
3.06
|
|
2.86
|
|
3.12
|
|
2.30
|
|
2.62
|
|
2.64
|
|
3.06
|
|
2.77
|
|
2.53
|
2029
|
|
2.80
|
|
3.26
|
|
3.12
|
|
2.92
|
|
3.18
|
|
2.30
|
|
2.68
|
|
2.70
|
|
3.12
|
|
2.83
|
|
2.59
|
2030
|
|
2.80
|
|
3.33
|
|
3.18
|
|
2.98
|
|
3.25
|
|
2.30
|
|
2.74
|
|
2.75
|
|
3.18
|
|
2.88
|
|
2.64
|
2031
|
|
2.80
|
|
3.39
|
|
3.25
|
|
3.04
|
|
3.32
|
|
2.30
|
|
2.79
|
|
2.81
|
|
3.24
|
|
2.94
|
|
2.69
|
2032
|
|
2.80
|
|
3.46
|
|
3.32
|
|
3.10
|
|
3.38
|
|
2.30
|
|
2.85
|
|
2.86
|
|
3.31
|
|
3.00
|
|
2.74
|
2033
|
|
2.80
|
|
3.53
|
|
3.38
|
|
3.16
|
|
3.45
|
|
2.30
|
|
2.90
|
|
2.92
|
|
3.38
|
|
3.06
|
|
2.80
|
2034
|
|
2.80
|
|
3.60
|
|
3.45
|
|
3.23
|
|
3.52
|
|
2.31
|
|
2.96
|
|
2.98
|
|
3.45
|
|
3.12
|
|
2.85
|
2035
|
|
2.80
|
|
3.67
|
|
3.52
|
|
3.29
|
|
3.59
|
|
2.30
|
|
3.02
|
|
3.04
|
|
3.52
|
|
3.18
|
|
2.91
|
2036
|
|
2.80
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
2.30
|
|
+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, 2020
and GLJ and McDaniel & Associates Consultants Ltd. as at
January 1, 2021 (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, and
Kingsgate 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, 2020.
|
(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,
|
2020
|
2019
|
2018
|
Reserves
(Mboe)
|
|
|
|
Proved
Producing
|
736,448
|
527,361
|
473,269
|
Total
Proved
|
1,691,056
|
1,294,439
|
1,206,381
|
Proved Plus
Probable
|
3,314,264
|
2,601,928
|
2,457,358
|
Capital
Expenditures ($ millions)
|
|
|
|
Exploration and
Development(2)
|
912
|
1,069
|
1,261
|
Net Property
Acquisitions (Dispositions)
|
172
|
219
|
(47)
|
Net Corporate
Acquisitions (Dispositions)(3)
|
794
|
-
|
-
|
Less: Topaz Property
Acquisitions(4)
|
(119)
|
-
|
-
|
Total(5)
|
1,759
|
1,287
|
1,214
|
Cash
Flow ($/boe)
|
|
|
|
Cash Flow
|
10.43
|
11.36
|
13.47
|
Cash Flow - Three
Year Average
|
11.67
|
12.75
|
12.80
|
Notes:
|
(1)
|
Cash flow is
defined as cash provided by operations before changes in non-cash
operating working capital. See "Non-GAAP Financial Measures" below
and in the Company's most recently filed Management's Discussion
and Analysis for further discussion.
|
(2)
|
Includes
capitalized G&A of $31 million, $33 million and $30 million for
2020, 2019 and 2018 respectively.
|
(3)
|
Includes purchase
price (cash and/or common shares) plus net debt.
|
(4)
|
Includes property
acquisitions incurred by Topaz from non-related
parties.
|
(5)
|
Represents the
capital expenditures used for purposes of F&D and FD&A
calculations.
|
Finding and Development Costs
Finding and
Development Costs, Excluding FDC
|
2020
|
2019
|
2018
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Reserve Additions
(MMboe)
|
185.4
|
160.7
|
241.0
|
|
F&D Costs
($/boe)
|
4.92
|
6.65
|
5.24
|
5.52
|
F&D Recycle
Ratio(1)
|
2.1
|
1.7
|
2.6
|
2.1
|
Total Proved
Plus Probable
|
|
|
|
|
Reserve Additions
(MMboe)
|
210.5
|
180.4
|
326.6
|
|
F&D Costs
($/boe)
|
4.33
|
5.92
|
3.86
|
4.52
|
F&D Recycle
Ratio(1)
|
2.4
|
1.9
|
3.5
|
2.6
|
|
|
|
|
|
Finding and
Development Costs, Including FDC
|
2020
|
2019
|
2018
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Change in FDC ($
millions)
|
(286.0)
|
(275.2)
|
441.7
|
|
Reserve Additions
(MMboe)
|
185.4
|
160.7
|
241.0
|
|
F&D Costs
($/boe)
|
3.38
|
4.94
|
7.07
|
5.32
|
F&D Recycle
Ratio(1)
|
3.1
|
2.3
|
1.9
|
2.2
|
Total Proved
Plus Probable
|
|
|
|
|
Change in FDC ($
millions)
|
(566.3)
|
(589.4)
|
486.3
|
|
Reserve Additions
(MMboe)
|
210.5
|
180.4
|
326.6
|
|
F&D Costs
($/boe)
|
1.64
|
2.66
|
5.35
|
3.59
|
F&D Recycle
Ratio(1)
|
6.4
|
4.3
|
2.5
|
3.3
|
Finding, Development and Acquisition Costs
Finding,
Development and Acquisition Costs, Excluding FDC
|
2020
|
2019
|
2018
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Reserve Additions
(MMboe)
|
510.3
|
194.2
|
247.4
|
|
FD&A Costs
($/boe)
|
3.45
|
6.63
|
4.91
|
4.48
|
FD&A Recycle
Ratio(1)
|
3.0
|
1.7
|
2.7
|
2.6
|
Total Proved
Plus Probable
|
|
|
|
|
Reserve Additions
(MMboe)
|
826.0
|
250.7
|
337.9
|
|
FD&A Costs
($/boe)
|
2.13
|
5.13
|
3.59
|
3.01
|
FD&A Recycle
Ratio(1)
|
4.9
|
2.2
|
3.7
|
3.9
|
|
|
|
|
|
Finding,
Development and Acquisition Costs, Including FDC
|
2020
|
2019
|
2018
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Change in FDC ($
millions)
|
723.3
|
(93.4)
|
465.3
|
|
Reserve Additions
(MMboe)
|
510.3
|
194.2
|
247.4
|
|
FD&A Costs
($/boe)
|
4.86
|
6.15
|
6.79
|
5.63
|
FD&A Recycle
Ratio(1)
|
2.1
|
1.8
|
2.0
|
2.1
|
Total Proved
Plus Probable
|
|
|
|
|
Change in FDC ($
millions)
|
1,383.5
|
(218.0)
|
526.8
|
|
Reserve Additions
(MMboe)
|
826.0
|
250.7
|
337.9
|
|
FD&A Costs
($/boe)
|
3.80
|
4.26
|
5.15
|
4.21
|
FD&A Recycle
Ratio(1)
|
2.7
|
2.7
|
2.6
|
2.8
|
|
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 11, 2021 starting at 9:00 a.m. MT (11:00 a.m.
ET). To participate, please dial 1-888-231-8191
(toll-free in North America), or
international dial-in 647-427-7450, a few minutes prior to the
conference call.
Conference ID is 1689407.
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 2021 and
beyond; expected free cash flow and cash flow levels for 2021 and
beyond; potential for share buybacks; targeted 2021 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
spending 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 2021 and over the five year development plan; 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 rates; prevailing
and future commodity prices and currency exchange rates; applicable
royalty rates and tax laws; interest rates; 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; 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; and changes in
legislation, including but not limited to tax laws, royalties and
environmental regulations.
In addition, pandemics, epidemics or outbreaks of an infectious
disease in Canada or worldwide,
including COVID-19or other illnesses could have an adverse impact
on the Company's results, business, financial condition or
liquidity. 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 this COVID-19 pandemic. Unexpected developments
in financial markets, regulatory environments, or consumer
behaviour may also have adverse impacts on the Company's results,
business, financial condition or liquidity, for a substantial
period of time. The Company's business, financial condition,
results of operations, cash flows, reputation, access to capital,
cost of borrowing, access to liquidity, and/or business plans may,
in particular, and without limitation, be adversely impacted as a
result of the pandemic and/or decline in commodity prices as a
result of: the shut-down of facilities or the delay or
suspension of work on major capital projects due to workforce
disruption or labour shortages caused by workers becoming infected
with COVID-19, or government or health authority mandated
restrictions on travel by workers or closure of facilities or
worksites; suppliers and third-party vendors experiencing
similar workforce disruption or being ordered to cease
operations; reduced cash flows resulting in less funds from
operations being available to fund capital expenditure
budgets; reduced commodity prices resulting in a reduction in
the volumes and value of reserves; crude oil storage
constraints resulting in the curtailment or shutting in of
production; counterparties being unable to fulfill their
contractual obligations on a timely basis or at all; the
inability to deliver products to customers or otherwise get
products to market caused by border restrictions, road or port
closures or pipeline shut-ins, including as a result of pipeline
companies suffering workforce disruptions or otherwise being unable
to continue to operate; and the ability to obtain additional
capital including, but not limited to, debt and equity financing
being adversely impacted as a result of unpredictable financial
markets, commodity prices and/or a change in market fundamentals.
The COVID-19 pandemic has also created additional operational risks
for the Company, including the need to provide enhanced safety
measures for its employees and customers; comply with rapidly
changing regulatory guidance; address the risk of, attempted
fraudulent activity and cybersecurity threat behaviour; and protect
the integrity and functionality of the Company's systems, networks,
and data as a larger number of employees work remotely. The Company
is also exposed to human capital risks due to issues related to
health and safety matters, and other environmental stressors as a
result of measures implemented in response to the COVID-19
pandemic, as well as the potential for a significant proportion of
the Company's employees, including key executives, to be unable to
work effectively, because of illness, quarantines,
sheltering-in-place arrangements, government actions or other
restrictions in connection with the pandemic. The extent to which
the COVID-19 pandemic continues to impact the Company's results,
business, financial condition or liquidity will depend on future
developments in Canada, the U.S.
and globally, including the development and widespread availability
of efficient and accurate testing options, and effective treatment
options or vaccines. Despite the approval of certain vaccines by
the regulatory bodies in Canada
and the U.S., the ongoing evolution of the development and
distribution of an effective vaccine also continues to raise
uncertainty.
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, 2020, 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,
2021 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, 2020, which will be filed on SEDAR
(accessible at www.sedar.com) on or before March 31, 2021.
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, 2020, which will be
filed on SEDAR (accessible at www.sedar.com) on or before
March 31, 2021.
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",
"FD&A recycle ratio" and "NPV per share". These metrics
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.
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 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
2021 exit net debt-to-cash flow ratio as well as 2021 – 2025 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
production of 390,000 – 410,000 boepd for 2021 and 426,000,
448,000, 465,000 and 482,000 boepd for 2022 - 2025, respectively.
Commodity price assumptions for natural gas (NYMEX (US) -
$2.85/mcf, $2.65/mcf, $2.51/mcf, $2.52/mcf and $2.54/mcf for 2021 – 2025, respectively; AECO -
$2.96/mcf, $2.51/mcf, $2.29/mcf, $2.30/mcf and $2.40/mcf for 2021 – 2025, respectively), and
crude oil (WTI (US) - $58.52/bbl,
$54.44/bbl, $51.80/bbl, $50.35/bbl and $49.68/bbl for 2021 – 2025, respectively) and an
exchange rate assumption of $0.79
(US/CAD) for 2021 – 2023 and $0.78
for 2024 – 2025. Further, in the case of years subsequent to 2021,
readers are cautioned that such estimates are provided for
illustration only and are based on budgets and forecasts that have
not been finalized and are subject to a variety of additional
factors and contingencies including prior years' results. To the
extent such estimates constitute financial outlooks, they were
approved by management and the Board of Directors of Tourmaline on
March 10, 2021 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 FINANCIAL MEASURES
This news release includes references to "free cash flow", "cash
flow", and "net debt" which are financial measures commonly used in
the oil and gas industry and do not have a standardized meaning
prescribed by International Financial Reporting Standards ("GAAP").
Accordingly, the Company's use of these terms may not be comparable
to similarly defined measures presented by other companies.
Management uses the term "free cash flow", "cash flow", and "net
debt" for its own performance measures 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 a
portion of its future growth expenditures, to pay dividends or to
repay debt. Investors are cautioned that these non-GAAP measures
should not be construed as an alternative to net income or cash
from operating activities determined in accordance with GAAP as an
indication of the Company's performance. Free cash flow is
calculated as cash flow less total net capital expenditures and is
prior to dividend payments. Net capital expenditures is defined as
the sum of E&P capital program and other corporate
expenditures, net of non-core dispositions. See "Non-GAAP
Financial Measures" in the December 31,
2019 Management's Discussion and Analysis for the definition
and description of these terms.
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 2020 annual production,
2020 average daily production, Q4 2020 average daily production,
current average daily production, Q1 2021 average daily production
and 2021 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)
|
2020 Annual
Production
|
10,266,666
|
|
339,302,682
|
|
201,137,676
|
|
13,338,870
|
|
113,678,929
|
2020 Average Daily
Production
|
28,051
|
|
927,057
|
|
549,556
|
|
36,445
|
|
310,598
|
Q4 2020 Average Daily
Production
|
29,113
|
|
993,899
|
|
598,111
|
|
41,877
|
|
336,325
|
Current Average Daily
Production
|
32,957
|
|
1,267,517
|
|
643,263
|
|
56,079
|
|
407,500
|
Q1 2021 Average Daily
Production
|
32,553
|
|
1,251,965
|
|
635,371
|
|
55,391
|
|
402,500
|
2021 Average Daily
Production
|
33,060
|
|
1,198,601
|
|
667,955
|
|
55,848
|
|
400,000
|
|
|
(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.
|
General
See also "Forward-Looking Statements", and "Non-GAAP Financial
Measures" in the most recently filed Management's Discussion and
Analysis.
Certain Definitions:
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
|
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, 2020 and 2019, please refer to SEDAR
(www.sedar.com) or Tourmaline's website at
www.tourmalineoil.com.
About Tourmaline Oil Corp.
Tourmaline is an investment grade Canadian senior crude oil and
natural gas exploration and production company focused on providing
strong and predictable long-term growth and a steady return to
shareholders through an aggressive exploration, development,
production and acquisition program in the Western Canadian
Sedimentary Basin by building its extensive asset base in its three
core exploration and production areas and exploiting and developing
these areas to increase reserves, production and cash flows at an
attractive return on invested capital.
SOURCE Tourmaline Oil Corp.