CALGARY,
AB, Mar. 1, 2023 /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 2022, as well as 2022 reserves.
HIGHLIGHTS
- Full-year 2022 cash flow(1) ("CF") was a record
$4.9 billion ($14.26 per diluted share(2)) up 67%
over 2021. Fourth quarter 2022 CF was $1.4
billion ($4.08 per diluted
share).
- Tourmaline generated a record $3.2
billion of free cash flow(3) ("FCF") in 2022.
- Full-year 2022 after tax net earnings were $4.5 billion ($13.10 per diluted share).
- Tourmaline paid $7.90/share in
base and special dividends to shareholders in 2022, a 12% trailing
yield(4) based on an average 2022 share price of
$66.94.
- Tourmaline's proved plus probable ("2P") reserve value per
diluted share(5)(6) before tax is $143 ($109 after
tax) using the January 1, 2023
engineering price deck and a 10% discount rate. Total proved ("TP")
and proved, developed producing ("PDP") reserve values per diluted
share are $97 and $54 before tax, respectively ($75 and $44 after
tax, respectively) using the same pricing and discount rates.
- Full-year 2022 average production of 500,832 boepd was up 14%
over 2021 average production of 441,115 boepd.
- Current production is ranging between 520,000-530,000 boepd,
consistent with the expected first quarter average.
- At current strip pricing(7), the Company expects to
generate 2023 cash flow of $3.8
billion ($11.12 per diluted
share) and free cash flow of $2.0
billion ($5.72 per diluted
share) on unchanged EP capital expenditures(8) of
$1.675 billion (as per January 12, 2023 news release). Based on a
current share price of $60,
Tourmaline is trading at an approximate 10% free cash flow
yield(9).
- Exit 2022 net debt(10) was $494 million (0.1 times Q4 2022 annualized cash
flow) and well below the Company's long-term net debt target of
$1.0-1.2 billion.
- Year-end 2022 PDP reserves of 1.001 billion boe were up 25%, TP
reserves of 2.32 billion boe were up 14% and 2P reserves of 4.50
billion boe were up 10% over year-end 2021, after including 2022
annual production of 183 million boe.
- Tourmaline replaced 240% of its 2022 annual production of 183
million boe with 2P additions of 440 million boe including 2022
production, with 88% of the addition from the organic EP
program.
- After 14 years of operations, Tourmaline now has 20.7 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 January 2023, Tourmaline began
delivering gas to the US Gulf Coast, becoming the first Canadian EP
company participating in the LNG business with full exposure to JKM
(Japan Korea Marker) pricing.
PRODUCTION UPDATE
- Fourth quarter 2022 production averaged 511,590 boepd, up 5%
from Q4 2021; full-year 2022 average production of 500,832 boepd
was up 14% over 2021 average production of 441,115 boepd.
- Current production is ranging between 520,000-530,000 boepd
after a reduction in NGL volumes due to the Pembina Northern
pipeline system interruption. Commencing January 17, 2023, a force majeure event on the
Pembina Pipeline Corporation Northern line reduced daily Tourmaline
NGL production volumes by approximately 8,000 boepd. The pipeline
became operational again on February 25,
2023 and is currently flowing at reduced rates. First
quarter average production of 520,000-530,000 boepd is still
expected; full-year 2023 average production guidance ranging
between 520,000 and 540,000 boepd remains unchanged.
- 2022 average liquids production of 112,460 bpd (oil,
condensate, NGL) was up 16% over 2021. Tourmaline is the largest
NGL producer in Canada at
approximately 70,000 bpd and the second largest condensate producer
at 32,000 bpd. Condensate and NGL production are expected to grow
materially with the Company's Conroy North Montney development
project.
- On February 9, 2023, Tourmaline
produced its one billionth barrel of oil equivalent of production
since inception in 2008.
FINANCIAL HIGHLIGHTS
- Full-year 2022 cash flow was a record $4.9 billion ($14.26 per diluted share), up 67% over 2021 cash
flow of $2.9 billion.
- Fourth quarter 2022 cash flow was $1.4
billion ($4.08 per diluted
share), up 45% over fourth quarter 2021.
- Tourmaline generated a record $3.2
billion of free cash flow in 2022.
- Full-year 2022 after tax net earnings were $4.5 billion ($13.10 per diluted share) up 121% from 2021 after
tax net earnings of $2.0 billion
($6.40 per diluted share). Full year
after tax net earnings include $1.5
billion related to the fair value of the embedded derivative
associated with the Company's Gulf Coast LNG gas supply
agreement.
- The Company increased the quarterly base dividend three times
in 2022 to an annualized $1.00/share
from an annualized $0.72/share (39%
annual increase) and paid four special dividends totaling
$7.00/share in 2022. Tourmaline has
committed to returning the majority of annual FCF to shareholders
and is executing on that plan; the Company plans to return between
50-90% of FCF to shareholders in 2023.
- Tourmaline paid $7.90/share in
base and special dividends in 2022, a 12% trailing yield based on
an average share price of $66.94 in
2022.
- Tourmaline paid a special dividend of $2.00/share on February 1,
2023 and expects to declare and pay special dividends for
the remaining three quarters in 2023, fulfilling the commitment to
return 50-90% of free cash flow to investors. Strong base and
special dividends are anticipated in 2024 and in subsequent years
based on current strip pricing.
- Tourmaline maintains its Investment Grade credit rating of BBB
(high) validating the overall financial health of the Company as a
stable, low-risk senior North American oil and gas producer.
- Q4 2022 EP capital expenditures were $482.8 million and full-year 2022 EP capital
expenditures were $1.6 billion.
- In 2023, at current strip pricing, the Company expects to
generate cash flow of $3.8 billion
($11.12 per diluted share) and free
cash flow of $2.0 billion
($5.72 per diluted share) on
unchanged EP capital expenditures of $1.675
billion (as per January 12,
2023 news release). Based on a current share price of
$60, Tourmaline is trading at an
approximate 10% free cash flow yield in 2023 while growing
production 6% year over year, based on expected 2023 FCF.
- Tourmaline generated cash flow of $1.4
billion and free cash flow of $908.7
million in Q4 2022 on total capital expenditures (before
A&D) of $494.0 million.
- Exit 2022 net debt was $494
million (0.1 times Q4 2022 annualized cash flow) and well
below the Company's long-term net debt target of $1.0-1.2 billion. Tourmaline is in a surplus
position when including the value of its 45.1 million shares in
Topaz Energy Corp. ("Topaz") (valued at $954
million using the closing price of the Topaz common shares
on December 31, 2022 of $21.13/share).
2022 RESERVES
- Year-end 2022 PDP reserves of 1.001 billion boe were up 25%
over year-end 2021 including 2022 annual production of 183 million
boe. TP reserves of 2.32 billion boe were up 14% including 2022
annual production. 2P reserves of 4.50 billion boe were up 10%
including 2022 annual production. The vast majority of the 2022
additions (88%) were from the ongoing organic EP growth
program.
- Tourmaline's 2P reserve value (before taxes) equates to
$143 per diluted share (after tax
reserve value is $109 per diluted
share) using the January 1, 2023,
engineering price deck and a 10% discount rate. TP reserve value
(before tax) is $97 per diluted share
and $75 per diluted share (after
tax). PDP reserve value is $54 per
diluted share (before tax) and $44
per diluted share (after tax) using the same pricing and discount
rates.
- Tourmaline's 2022 PDP finding, development and acquisition
("FD&A") costs were $8.74 per
boe(11), excluding changes in future development capital
("FDC"), yielding a PDP reserve recycle ratio(12)(13) of
3.06 (3.41 utilizing Q4 2022 cash flow per boe(14) of
$29.80).
- TP FD&A costs in 2022 were $10.74 per boe, including changes in FDC, and TP
FD&A costs were $6.52 per boe,
excluding changes in FDC. The TP FD&A recycle ratio (including
FDC) was 2.5 in 2022.
- 2P FD&A costs in 2022 were $10.59 per boe, including changes in FDC, and 2P
FD&A costs were $4.70 per boe,
excluding changes in FDC. The FDC account was significantly
increased in the 2022 year-end reserve report to better reflect
current inflationary pressures. The impact of this increase
resulted in a significant increase in 2022 2P FD&A costs, as
the full change in FDC is absorbed in the current year. The Company
does not believe this is representative of the FD&A costs that
relate purely to the Company's 2022 EP program. The 2P, three-year
average FD&A costs are $5.41/boe,
including the higher FDCs in 2022.
- Tourmaline replaced 240% of its 2022 annual production of 183
million boe with 2P additions of 440 million boe, including 2022
production.
- After 14 years of operations, Tourmaline now has 20.7 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 1.06 billion boe of 2P crude oil, condensate and NGL (natural
gas liquids) reserves (December 31,
2022), one of the largest conventional liquid reserve bases
in Canada.
- Tourmaline has only booked 3,359 (gross) locations of a total
drilling inventory of 23,077 gross locations (14.6% of the overall
inventory) to achieve year-end 2022 2P reserves of 4.50 billion
boe.
- The current FDCs associated with 2P reserves represent
approximately four years of prospective cash flow at strip pricing.
Although the Company has the execution capability to convert the
entire 4.5 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 continues to diversify its natural gas and liquids
marketing portfolio in order to realize the best pricing possible
for all of its hydrocarbon streams. That diversification played a
major role in enhancing Q4 2022 cash flow as well as full year 2023
expected cash flow.
- In 2021, the Company further diversified its gas marketing
portfolio by establishing a US Gulf Coast LNG long-term gas supply
agreement with Cheniere Energy. In January
2023, Tourmaline commenced delivery of 140 mmcfpd to the
Cheniere Sabine Pass LNG facility and became the first Canadian EP
company to participate in the LNG business with exposure to JKM
pricing, providing a material increase to anticipated 2023 cash
flow (based on the February 15, 2023
JKM strip pricing). The Company receives the JKM price, net of
liquification and shipping fees. The 2023 JKM strip is USD
$19.24/mcf. Tourmaline currently has
an average of 27 mmcfpd hedged at a weighted average fixed JKM
price of USD $34.196/mcf in 2023.
- During 2023, the Company will increase natural gas volumes
exported to western US markets from 345 mmcfpd to 495 mmcfpd, with
an average of 74% of the natural gas accessing the premium priced
PG&E California market over the calendar year.
- Average realized natural gas price in Q4 2022 was $6.89/mcf as the Company benefited primarily from
strong gas pricing in Western North
America. In Q4 2022, the Malin index averaged USD
$14.42/mcf, and the PG&E
California index averaged USD $15.87/mcf.
- Tourmaline has an average of 791 mmcfpd hedged for 2023 at a
weighted average fixed price of CAD $5.93/mcf, an average of 140 mmcfpd hedged at a
basis to Nymex of USD $0.42/mcf, and
an average of 698 mmcfpd of unhedged volumes exposed to export
markets in 2023, including Dawn, Iroquois, Great
Lakes, Empress, Chicago,
Ventura, Sumas, US Gulf Coast, JKM, Malin, and PG&E.
- Tourmaline is Canada's largest
NGL producer with anticipated average production levels of over
70,000 bpd in 2023.
EP UPDATE
- Tourmaline drilled a total of 240 net wells during 2022 for a
total of 1,285,407 metres (607,163 HZ metres), the most in the
WCSB. In 2022, the Company increased average lateral length by over
12.6%, the number of stages per well by 13% and average sand
tonnage by 19% over 2021.
- Tourmaline operated 13 to 14 drilling rigs and four to five
frac spreads across the three operated core EP complexes during
January and February of 2023, as originally planned.
- The Company expects to drill and complete a total of
approximately 300 wells (gross) during 2023.
- There are no material facility projects in the 2023 budget; as
such, the Company anticipates 2023 capital
efficiencies(15) of approximately $9,000/boepd.
- The Company continues to evolve the Conroy North Montney
development project. This minimum 100,000 boepd gas and liquids
project is currently planned for the 2025-2027 timeframe,
coinciding with the projected startup of LNG Canada and anticipated
related strong intra-Basin natural gas pricing. Facility
expenditures on this fully sanctioned project will commence in
2024. The agreement between the BRFN and the BC Government
announced on January 18, 2023,
provides a framework that facilitates the planning, permitting and
execution of this major project.
- Tourmaline had over 300 valid drilling permits in NEBC entering
2023 and has received an additional 55 permits during the first
quarter of 2023 thus far.
- The Company drilled 11 new pool/new zone discovery and
delineation wells in 2022 and has made two additional discoveries
in 2023 to date.
- One net rig will continue to drill new pool/new zone
exploration wells in 2023. The Company has completed, and tested, a
significant extension during the first quarter of 2023 for one of
the three material discoveries made to date through the program.
Significant incremental reserve increases are anticipated in
2023.
- It is expected that successful discoveries will be able to
access existing Tourmaline infrastructure.
___________________________________________
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|
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ENVIRONMENTAL PERFORMANCE IMPROVEMENT
- Tourmaline has had an engineering team in place for four 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 $30-50 million per year on environmental
performance improvement initiatives.
- The Company is displacing diesel with natural gas on all the
drilling rigs in the operated fleet, and currently has one rig
running directly on high line power. Since embarking on this
initiative over five years ago, the Company has displaced
approximately 91.3 million litres of diesel, yielding an emission
reduction of 57,888 tonnes and net cost savings of approximately
Cdn$86.0 million.
- In working with Trican Well Services Ltd., the first Canadian
Tier 4 fleet was deployed in October
2021 with continued successful deployment of Tier 4 fleets
operating for the Company during 2022 in Alberta and NEBC.
- Tourmaline is recognized as having the lowest freshwater
intensity for 2021 in Alberta at
an intensity of 0.11bbl/boe, 12 months after fracturing. The
Company continues to make significant investments to expand water
management/water recycling capability in all three operated
complexes.
- Also in 2022, Tourmaline expanded operations at the
Company-operated Emission Testing Center ("ETC"), the first of its
kind in the world, at the West Wolf gas plant. To date, 18 new
clean technologies have been tested at the ETC. The ETC is critical
in evolving new technology and methodologies in order 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
$0.25 per common share. The dividend
will be payable on March 31, 2023 to
shareholders of record at the close of business on March 15, 2023. This quarterly cash dividend is
designated as an "eligible dividend" for Canadian income tax
purposes.
_________________________________________
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(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", "cash flow per diluted
share", "free cash flow per diluted share", "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, 2022 (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)
|
Calculated as the
dividend per common share for the year divided by the average
common share price for the year.
|
(5)
|
2P, TP and PDP
reserve value per diluted share is calculated as the net present
value of the reserves (before or after tax, as the case may be) as
at December 31, 2022 discounted at 10%, divided by the number of
diluted weighted average common shares outstanding for the year
ended December 31, 2022.
|
(6)
|
Supplementary
financial measure. See "Non-GAAP and Other Financial Measures" in
this news release and in the Annual MD&A.
|
(7)
|
Based on oil and gas
commodity strip pricing at February 15, 2023.
|
(8)
|
"Capital
Expenditures" is a non-GAAP financial measure defined as cash flow
from investing activities adjusted for the change in non-cash
working capital (deficit), and corporate acquisitions. See
"Non-GAAP Financial Measures" in this news release and in the
Annual MD&A.
|
(9)
|
Calculated as
forecast 2023 FCF per diluted share (based on estimated diluted
Common Shares of 345 million) divided by the stated share price per
Common Share.
|
(10)
|
"Net debt" is a
capital management measure. 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.
|
(12)
|
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.
|
(13)
|
Non-GAAP financial
ratio. See "Non-GAAP and Other Financial Measures" in this news
release and in the Annual MD&A.
|
(14)
|
Non-GAAP financial
ratio. See "Non-GAAP and Other Financial Measures" in this news
release and in the Annual MD&A.
|
(15)
|
Capital efficiencies
are calculated as capital expenditures divided by estimated
production added over the period.
|
CORPORATE SUMMARY – DECEMBER 31,
2022
|
|
Three Months Ended
December 31,
|
|
Year Ended December
31,
|
|
|
2022
|
|
2021
|
Change
|
|
2022
|
|
2021
|
Change
|
OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(mcf/d)
|
|
2,376,463
|
|
2,269,290
|
5 %
|
|
2,330,234
|
|
2,063,455
|
13 %
|
Crude oil, condensate
and NGL
(bbl/d)
|
|
115,513
|
|
106,863
|
8 %
|
|
112,460
|
|
97,206
|
16 %
|
Oil equivalent
(boe/d)
|
|
511,590
|
|
485,078
|
5 %
|
|
500,832
|
|
441,115
|
14 %
|
Product
prices(1)
|
|
|
|
|
|
|
|
|
|
|
Natural gas
($/mcf)
|
$
|
6.89
|
$
|
4.66
|
48 %
|
$
|
5.87
|
$
|
3.94
|
49 %
|
Crude oil, condensate
and NGL
($/bbl)
|
$
|
63.01
|
$
|
56.66
|
11 %
|
$
|
66.97
|
$
|
47.89
|
40 %
|
Operating expenses
($/boe) (2)
|
$
|
4.38
|
$
|
3.95
|
11 %
|
$
|
4.30
|
$
|
3.77
|
14 %
|
Transportation costs
($/boe) (3)
|
$
|
5.08
|
$
|
4.45
|
14 %
|
$
|
4.92
|
$
|
4.25
|
16 %
|
Operating netback
($/boe) (4)
|
$
|
30.56
|
$
|
22.10
|
38 %
|
$
|
27.04
|
$
|
18.57
|
46 %
|
Cash general and
administrative
expenses ($/boe)(5)
|
$
|
0.56
|
$
|
0.49
|
14 %
|
$
|
0.57
|
$
|
0.54
|
6 %
|
FINANCIAL
($000, except share and per share)
|
|
|
|
|
|
|
|
|
|
|
Total revenue from
commodity sales
and realized gains
|
|
2,176,463
|
|
1,529,345
|
42 %
|
|
7,742,837
|
|
4,669,263
|
66 %
|
Royalties
|
|
292,784
|
|
168,168
|
74 %
|
|
1,115,549
|
|
387,914
|
188 %
|
Cash flow
|
|
1,402,647
|
|
968,236
|
45 %
|
|
4,883,949
|
|
2,929,126
|
67 %
|
Cash flow per share
(diluted)
|
$
|
4.08
|
$
|
2.88
|
42 %
|
$
|
14.26
|
$
|
9.25
|
54 %
|
Net earnings
|
|
(30,366)
|
|
996,248
|
(103) %
|
|
4,487,049
|
|
2,025,991
|
121 %
|
Net earnings per share
(diluted)
|
$
|
(0.09)
|
$
|
2.96
|
(103) %
|
$
|
13.10
|
$
|
6.40
|
105 %
|
Capital expenditures
(net of
dispositions)(6)
|
|
505,982
|
|
447,461
|
13 %
|
|
1,879,347
|
|
1,590,371
|
18 %
|
Weighted average shares
outstanding
(diluted)
|
|
|
|
|
|
|
342,533,099
|
|
316,788,967
|
8 %
|
Net debt
|
|
|
|
|
|
|
(494,442)
|
|
(972,979)
|
(49) %
|
PROVED +
PROBABLE RESERVES(7)
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(bcf)
|
|
|
|
|
|
|
20,663.8
|
|
19,487.1
|
6 %
|
Crude oil
(mbbls)
|
|
|
|
|
|
|
114,367
|
|
98,345
|
16 %
|
Natural gas liquids
(mbbls)
|
|
|
|
|
|
|
941,936
|
|
896,793
|
5 %
|
Mboe
|
|
|
|
|
|
|
4,500,272
|
|
4,242,981
|
6 %
|
|
|
|
|
|
|
|
|
|
|
|
Notes:
|
|
(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.
|
2022 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, 2022
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
|
|
15,761
|
|
12,385
|
|
2,283,478
|
|
2,009,384
|
|
2,406,984
|
|
1,854,524
|
|
203,670
|
|
166,320
|
|
1,001,175
|
|
822,689
|
Proved Developed
Non-
Producing
|
|
1,320
|
|
967
|
|
95,709
|
|
82,882
|
|
216,512
|
|
174,341
|
|
14,484
|
|
12,101
|
|
67,841
|
|
55,939
|
Proved
Undeveloped
|
|
43,645
|
|
33,359
|
|
2,403,189
|
|
2,099,405
|
|
3,400,823
|
|
2,712,735
|
|
241,962
|
|
200,937
|
|
1,252,943
|
|
1,036,320
|
Total Proved
|
|
60,726
|
|
46,711
|
|
4,782,376
|
|
4,191,671
|
|
6,024,319
|
|
4,741,600
|
|
460,116
|
|
379,358
|
|
2,321,959
|
|
1,914,948
|
Total
Probable
|
|
53,640
|
|
41,417
|
|
3,183,615
|
|
2,711,649
|
|
6,673,506
|
|
5,108,451
|
|
481,819
|
|
390,154
|
|
2,178,313
|
|
1,734,921
|
Total Proved Plus
Probable
|
|
114,367
|
|
88,129
|
|
7,965,991
|
|
6,903,320
|
|
12,697,825
|
|
9,850,051
|
|
941,936
|
|
769,512
|
|
4,500,272
|
|
3,649,869
|
Reserves
Category
|
|
Net Present Values
of Future Net Revenue ($000s)
|
|
Before Income Taxes
Discounted at (2)
(%/year)
|
|
After Income Taxes
Discounted at (2) (3)
(%/year)
|
|
Unit Value
Before Income
Tax Discounted
at 10%/year
|
|
0
|
|
5
|
|
8
|
|
10
|
|
15
|
|
20
|
|
0
|
|
5
|
|
8
|
|
10
|
|
15
|
|
20
|
|
($/Boe)
|
|
($/Mcfe)
|
|
Proved
Producing
|
|
27,256,608
|
|
22,048,650
|
|
19,815,550
|
|
18,594,008
|
|
16,202,116
|
|
14,452,939
|
|
21,685,281
|
|
17,643,107
|
|
15,880,983
|
|
14,913,475
|
|
13,014,064
|
|
11,621,938
|
|
22.60
|
|
3.77
|
|
Proved Developed
Non-
Producing
|
|
1,547,216
|
|
1,185,761
|
|
1,045,007
|
|
970,579
|
|
829,370
|
|
729,452
|
|
1,151,010
|
|
881,261
|
|
775,795
|
|
719,940
|
|
613,796
|
|
538,537
|
|
17.35
|
|
2.89
|
|
Proved
Undeveloped
|
|
31,743,036
|
|
20,066,138
|
|
15,818,145
|
|
13,668,368
|
|
9,832,017
|
|
7,367,494
|
|
23,731,897
|
|
14,875,960
|
|
11,646,742
|
|
10,012,402
|
|
7,098,117
|
|
5,230,277
|
|
13.19
|
|
2.20
|
|
Total Proved
|
|
60,546,860
|
|
43,300,549
|
|
36,678,702
|
|
33,232,955
|
|
26,863,503
|
|
22,549,885
|
|
46,568,188
|
|
33,400,328
|
|
28,303,520
|
|
25,645,816
|
|
20,725,977
|
|
17,390,752
|
|
17.35
|
|
2.89
|
|
Total
Probable
|
|
54,739,447
|
|
26,882,473
|
|
19,218,845
|
|
15,791,766
|
|
10,376,611
|
|
7,344,119
|
|
40,697,268
|
|
19,870,844
|
|
14,132,259
|
|
11,567,762
|
|
7,523,462
|
|
5,268,589
|
|
9.10
|
|
1.52
|
|
Total Proved Plus
Probable
|
|
115,286,307
|
|
70,183,022
|
|
55,897,547
|
|
49,024,720
|
|
37,240,114
|
|
29,894,004
|
|
87,265,456
|
|
53,271,172
|
|
42,435,779
|
|
37,213,578
|
|
28,249,439
|
|
22,659,340
|
|
13.43
|
|
2.24
|
|
|
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, 2022
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
|
|
42,824,434
|
|
5,775,434
|
|
8,703,218
|
|
1,125
|
|
1,088,049
|
|
27,256,608
|
|
5,571,327
|
|
21,685,281
|
Proved Developed
Non-
Producing
|
|
2,434,472
|
|
301,383
|
|
467,582
|
|
94,982
|
|
23,309
|
|
1,547,216
|
|
396,207
|
|
1,151,010
|
Proved
Undeveloped
|
|
54,968,413
|
|
7,322,603
|
|
8,482,475
|
|
7,037,299
|
|
382,999
|
|
31,743,036
|
|
8,011,139
|
|
23,731,897
|
Total
Proved
|
|
100,227,318
|
|
13,399,419
|
|
17,653,275
|
|
7,133,407
|
|
1,494,357
|
|
60,546,860
|
|
13,978,672
|
|
46,568,188
|
Total
Probable
|
|
93,842,747
|
|
14,329,453
|
|
17,685,183
|
|
6,488,314
|
|
600,351
|
|
54,739,447
|
|
14,042,179
|
|
40,697,268
|
Total Proved Plus
Probable
|
|
194,070,065
|
|
27,728,872
|
|
35,338,459
|
|
13,621,720
|
|
2,094,708
|
|
115,286,307
|
|
28,020,851
|
|
87,265,456
|
|
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
|
Year
|
|
Inflation(2)
%
|
|
|
|
CAD/USD
Exchange
Rate
$US/$Cdn(3)
|
|
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)
|
|
Constant
2023
$US/Bbl
|
|
Then
Current
$US/
Bbl
|
|
Spec
Ethane
$Cdn/Bbl
|
|
Edmonton
Propane
$Cdn/Bbl
|
Edmonton
Butane
$Cdn/Bbl
|
|
Edmonton
C5+
Stream
Quality
$Cdn/Bbl
|
|
2023
|
|
0.0
|
|
0.7450
|
|
80.33
|
|
80.33
|
|
103.77
|
|
13.75
|
|
39.80
|
53.88
|
|
106.22
|
|
2024
|
|
2.3
|
|
0.7650
|
|
76.71
|
|
78.50
|
|
97.74
|
|
14.33
|
|
39.13
|
52.67
|
|
101.35
|
|
2025
|
|
2.0
|
|
0.7683
|
|
73.72
|
|
76.95
|
|
95.27
|
|
13.77
|
|
39.74
|
51.42
|
|
98.94
|
|
2026
|
|
2.0
|
|
0.7717
|
|
72.89
|
|
77.61
|
|
95.58
|
|
13.98
|
|
39.86
|
51.61
|
|
100.19
|
|
2027
|
|
2.0
|
|
0.7750
|
|
72.89
|
|
79.16
|
|
97.07
|
|
14.20
|
|
40.47
|
52.39
|
|
101.74
|
|
2028
|
|
2.0
|
|
0.7750
|
|
72.90
|
|
80.75
|
|
99.01
|
|
14.49
|
|
41.28
|
53.44
|
|
103.78
|
|
2029
|
|
2.0
|
|
0.7750
|
|
72.90
|
|
82.36
|
|
100.99
|
|
14.79
|
|
42.11
|
54.51
|
|
105.85
|
|
2030
|
|
2.0
|
|
0.7750
|
|
72.89
|
|
84.01
|
|
103.01
|
|
15.09
|
|
42.95
|
55.60
|
|
107.97
|
|
2031
|
|
2.0
|
|
0.7750
|
|
72.89
|
|
85.69
|
|
105.07
|
|
15.39
|
|
43.81
|
56.71
|
|
110.13
|
|
2032
|
|
2.0
|
|
0.7750
|
|
72.90
|
|
87.40
|
|
106.69
|
|
15.71
|
|
44.47
|
57.56
|
|
112.33
|
|
2033
|
|
2.0
|
|
0.7750
|
|
72.89
|
|
89.15
|
|
108.83
|
|
16.02
|
|
45.35
|
58.71
|
|
114.58
|
|
2034
|
|
2.0
|
|
0.7750
|
|
72.90
|
|
90.93
|
|
111.00
|
|
16.34
|
|
46.26
|
59.88
|
|
116.87
|
|
2035
|
|
2.0
|
|
0.7750
|
|
72.89
|
|
92.75
|
|
113.22
|
|
16.67
|
|
47.19
|
61.08
|
|
119.21
|
|
2036
|
|
2.0
|
|
0.7750
|
|
72.89
|
|
94.60
|
|
115.49
|
|
17.00
|
|
48.13
|
62.30
|
|
121.59
|
|
2037
|
|
2.0
|
|
0.7750
|
|
72.89
|
|
96.50
|
|
117.80
|
|
17.34
|
|
49.09
|
63.55
|
|
124.03
|
|
2038
|
|
2.0
|
|
0.7750
|
|
72.89
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
+2.0%/yr
|
|
+2.0%/yr
|
|
Year
|
|
Natural Gas and Sulphur
Pricing
|
NYMEX Henry Hub
Near Month Contract
|
|
Midwest
Price @
Chicago
Then Current
$US/
MMbtu
|
|
AECO/NIT
Spot
Then Current
$Cdn/
MMbtu
|
|
|
|
Alberta Plant
Gate
|
|
Sumas Spot
$US/
MMbtu
|
|
British
Columbia
|
|
JKM
$US/
MMbtu
|
|
|
Spot
|
|
ARP $Cdn/
MMbtu
|
|
Westcoast
Station 2
$Cdn/
MMbtu
|
|
Spot Plant
Gate
$Cdn/
MMbtu
|
|
Constant
2023
$US/
MMbtu
|
|
Then Current
$US/MMbtu
|
|
Dawn Price
@ Ontario Then
Current
$US/MMbtu
|
|
Constant
2023
$Cdn/
MMbtu
|
|
Then Current
$Cdn/
MMbtu
|
|
2023
|
|
4.74
|
|
4.74
|
|
4.50
|
|
4.23
|
|
4.67
|
|
3.92
|
|
3.92
|
|
3.92
|
|
5.03
|
|
4.08
|
|
3.73
|
|
29.83
|
2024
|
|
4.40
|
|
4.50
|
|
4.29
|
|
4.40
|
|
4.43
|
|
3.99
|
|
4.09
|
|
4.09
|
|
4.61
|
|
4.28
|
|
3.92
|
|
26.38
|
2025
|
|
4.13
|
|
4.31
|
|
4.10
|
|
4.21
|
|
4.24
|
|
3.73
|
|
3.90
|
|
3.90
|
|
4.43
|
|
4.10
|
|
3.75
|
|
20.50
|
2026
|
|
4.13
|
|
4.40
|
|
4.19
|
|
4.27
|
|
4.32
|
|
3.72
|
|
3.96
|
|
3.96
|
|
4.52
|
|
4.16
|
|
3.81
|
|
17.80
|
2027
|
|
4.13
|
|
4.49
|
|
4.26
|
|
4.34
|
|
4.41
|
|
3.70
|
|
4.02
|
|
4.02
|
|
4.61
|
|
4.23
|
|
3.87
|
|
17.62
|
2028
|
|
4.13
|
|
4.58
|
|
4.35
|
|
4.43
|
|
4.50
|
|
3.71
|
|
4.11
|
|
4.11
|
|
4.70
|
|
4.32
|
|
3.95
|
|
17.95
|
2029
|
|
4.13
|
|
4.67
|
|
4.44
|
|
4.51
|
|
4.59
|
|
3.71
|
|
4.20
|
|
4.20
|
|
4.80
|
|
4.40
|
|
4.03
|
|
18.30
|
2030
|
|
4.13
|
|
4.76
|
|
4.54
|
|
4.60
|
|
4.68
|
|
3.72
|
|
4.29
|
|
4.29
|
|
4.90
|
|
4.49
|
|
4.13
|
|
18.65
|
2031
|
|
4.13
|
|
4.86
|
|
4.61
|
|
4.69
|
|
4.77
|
|
3.72
|
|
4.37
|
|
4.37
|
|
4.99
|
|
4.58
|
|
4.21
|
|
19.02
|
2032
|
|
4.13
|
|
4.95
|
|
4.71
|
|
4.79
|
|
4.87
|
|
3.72
|
|
4.46
|
|
4.46
|
|
5.10
|
|
4.67
|
|
4.30
|
|
19.40
|
2033
|
|
4.13
|
|
5.05
|
|
4.81
|
|
4.89
|
|
4.97
|
|
3.72
|
|
4.55
|
|
4.55
|
|
5.20
|
|
4.76
|
|
4.39
|
|
19.76
|
2034
|
|
4.13
|
|
5.15
|
|
4.91
|
|
4.98
|
|
5.07
|
|
3.72
|
|
4.64
|
|
4.64
|
|
5.30
|
|
4.86
|
|
4.47
|
|
20.13
|
2035
|
|
4.13
|
|
5.26
|
|
5.01
|
|
5.08
|
|
5.17
|
|
3.73
|
|
4.74
|
|
4.74
|
|
5.41
|
|
4.96
|
|
4.57
|
|
20.51
|
2036
|
|
4.13
|
|
5.36
|
|
5.11
|
|
5.18
|
|
5.28
|
|
3.73
|
|
4.84
|
|
4.84
|
|
5.52
|
|
5.06
|
|
4.65
|
|
20.90
|
2037
|
|
4.13
|
|
5.47
|
|
5.21
|
|
5.29
|
|
5.38
|
|
3.73
|
|
4.93
|
|
4.93
|
|
5.63
|
|
5.16
|
|
4.75
|
|
21.31
|
2038
|
|
4.13
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
3.73
|
|
+2.0%/yr
|
|
+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, 2022
and GLJ and McDaniel & Associates Consultants Ltd. as at
January 1, 2023 (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 and US Gulf Coast
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, 2022.
|
(2)
|
Inflation rates used
for forecasting prices and costs, with the exception of capital
expenditures, which have been forecasted to have nil inflation
until 2026, at which time the inflation profile is as published in
these tables.
|
(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, and for the
Year ended December 31,
|
2022
|
2021
|
2020
|
Reserves
(Mboe)
|
|
|
|
Proved
Producing
|
1,001,175
|
947,293
|
736,448
|
Total Proved
|
2,321,959
|
2,187,870
|
1,691,056
|
Proved Plus
Probable
|
4,500,272
|
4,242,981
|
3,314,264
|
Capital
Expenditures ($ millions)
|
|
|
|
Exploration and
Development(2)
|
1,677
|
1,437
|
912
|
Net Property
Acquisitions (Dispositions)(3)
|
202
|
196
|
172
|
Net Corporate
Acquisitions (Dispositions)(3)
|
188
|
1,232
|
794
|
Less: Topaz Property
Acquisitions(4)
|
–
|
(161)
|
(119)
|
Total(5)
|
2,067
|
2,704
|
1,759
|
Cash Flow
($/boe)
|
|
|
|
Cash Flow
|
26.72
|
18.19
|
10.43
|
Cash Flow - Three Year
Average
|
19.67
|
13.97
|
11.67
|
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 $47 million, $38 million and $32 million for 2022, 2021,
and 2020 respectively.
|
(3)
|
Includes purchase
price (cash and/or common shares) plus net debt, if
applicable.
|
(4)
|
Includes property
acquisitions incurred by Topaz from non-related parties, prior to
June 8, 2021, when it was a controlled subsidiary of
Tourmaline.
|
(5)
|
Represents the
capital expenditures used for purposes of F&D and FD&A
calculations.
|
Finding and Development Costs
Finding and
Development Costs, Excluding FDC
|
2022
|
2021
|
2020
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Reserve Additions
(MMboe)
|
284.6
|
257.6
|
185.4
|
|
F&D Costs
($/boe)
|
5.89
|
5.58
|
4.92
|
5.53
|
F&D Recycle
Ratio(1)
|
4.5
|
3.3
|
2.1
|
3.6
|
Total Proved Plus
Probable
|
|
|
|
|
Reserve Additions
(MMboe)
|
387
|
232.2
|
210.5
|
|
F&D Costs
($/boe)
|
4.33
|
6.19
|
4.33
|
4.85
|
F&D Recycle
Ratio(1)
|
6.2
|
2.9
|
2.4
|
4.1
|
|
|
|
|
|
Finding and
Development Costs, Including FDC
|
2022
|
2021
|
2020
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Change in FDC ($
millions)
|
1,202
|
197.2
|
(286.0)
|
|
Reserve Additions
(MMboe)
|
284.6
|
257.6
|
185.4
|
|
F&D Costs
($/boe)
|
10.12
|
6.34
|
3.38
|
7.06
|
F&D Recycle
Ratio(1)
|
2.6
|
2.9
|
3.1
|
2.8
|
Total Proved Plus
Probable
|
|
|
|
|
Change in FDC ($
millions)
|
2,380.7
|
41.6
|
(566.3)
|
|
Reserve Additions
(MMboe)
|
387
|
232.2
|
210.5
|
|
F&D Costs
($/boe)
|
10.49
|
6.37
|
1.64
|
7.09
|
F&D Recycle
Ratio(1)
|
2.5
|
2.9
|
6.4
|
2.8
|
Finding, Development and Acquisition Costs
Finding, Development
and Acquisition Costs,
Excluding FDC
|
2022
|
2021
|
2020
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Reserve Additions
(MMboe)
|
316.9
|
657.8
|
510.3
|
|
FD&A Costs
($/boe)
|
6.52
|
4.11
|
3.45
|
4.40
|
FD&A Recycle
Ratio(1)
|
4.1
|
4.4
|
3.0
|
4.5
|
Total Proved Plus
Probable
|
|
|
|
|
Reserve Additions
(MMboe)
|
440.1
|
1,089.7
|
826.0
|
|
FD&A Costs
($/boe)
|
4.70
|
2.48
|
2.13
|
2.77
|
FD&A Recycle
Ratio(1)
|
5.7
|
7.3
|
4.9
|
7.1
|
|
|
|
|
|
Finding, Development
and Acquisition Costs,
Including FDC
|
2022
|
2021
|
2020
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Change in FDC ($
millions)
|
1,337.3
|
1,201.1
|
723.3
|
|
Reserve Additions
(MMboe)
|
316.9
|
657.8
|
510.3
|
|
FD&A Costs
($/boe)
|
10.74
|
5.94
|
4.86
|
6.59
|
FD&A Recycle
Ratio(1)
|
2.5
|
3.1
|
2.1
|
3.0
|
Total Proved Plus
Probable
|
|
|
|
|
Change in FDC ($
millions)
|
2,593.0
|
2,241.2
|
1,383.5
|
|
Reserve Additions
(MMboe)
|
440.1
|
1,089.7
|
826.0
|
|
FD&A Costs
($/boe)
|
10.59
|
4.54
|
3.80
|
5.41
|
FD&A Recycle
Ratio(1)
|
2.5
|
4.0
|
2.7
|
3.6
|
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 2, 2023 starting at 9:00 a.m. MT (11:00 a.m.
ET).
To participate without operator assistance, you may register and
enter your phone number at https://bit.ly/3ROiPpp to receive an
instant automated call back.
To participate using an operator, please dial 1-888-664-6383
(toll-free in North America), or
1-416-764-8650 (international dial-in), a few minutes prior to the
conference call.
Conference ID is 03091736.
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, business opportunities and shareholder return plan,
including the following: the future declaration and payment of base
and special dividends and the timing and amount thereof which
assumes, among other things, the availability of free cash flow to
fund such dividends; the Company's plan to return between 50-90% of
free cash flow to shareholders; anticipated 2023 cash flow and free
cash flow and long-term net debt targets; anticipated petroleum and
natural gas production and production growth for various periods
including estimated production levels for the first quarter of 2023
and full-year 2023 and condensate and NGL production growth
anticipated from the Company's Conroy North Montney development
project; expected full-year 2023 EP capital spending levels and
anticipated capital efficiencies; the number of wells expected to
be drilled in 2023; the anticipated restart of the Pembina Pipeline
Corporation Northern pipeline system; anticipated natural gas
prices; anticipated increase in natural gas volumes to western US
markets; anticipated inflationary contingencies; anticipated strong
intra-Basin natural gas pricing from the startup of LNG Canada;
anticipated reserve increases resulting from exploration
activities, and the anticipated ability of successful exploration
discoveries to access existing Tourmaline infrastructure; the
timing for facility expansions and facility start-up dates;
sustainability and environmental improvement initiatives; 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 rates; the degree to which
Tourmaline's operations and production may be disrupted or by
circumstances attributable to supply chain disruptions; applicable
royalty rates and tax laws; interest rates; inflation rates; future
well production rates and reserve volumes; operating costs, receipt
of regulatory approvals and the timing thereof; 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 benefits to be derived from acquisitions;
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 natural
gas liquids 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 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; supply chain
disruptions; 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; changes in rates of
inflation; 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;
uncertainties associated with counterparty credit risk; failure to
obtain required regulatory and other approvals including drilling
permits and the impact of not receiving such approvals on the
Company's long-term planning; and changes in legislation, including
but not limited to tax laws, royalties and environmental
regulations. 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 which 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, 2022, 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 forecast prices published by Sproule Associates Ltd.
as at December 31, 2022 and GLJ and
McDaniel & Associates Consultants Ltd. as at January 1, 2023 (each of which is available on
their respective websites at www.sproule.com, www.gljpc.com, and
www.mcdan.com), and will be contained in the Company's Annual
Information Form for the year ended December
31, 2022, which will be filed on SEDAR (accessible at
www.sedar.com) on or before March 31, 2023.
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, 2022, which will be filed on SEDAR
(accessible at www.sedar.com) on or before March 31, 2023.
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
2023 cash flow and free cash flow, which are based on, among other
things, the various assumptions as to production levels, capital
expenditures and other assumptions disclosed in this news release
and including Tourmaline's estimated 2023 average production of
530,000 boepd, 2023 commodity price assumptions for natural gas
($3.20/mcf NYMEX US, $2.80/mcf AECO, $18.12/mcf JKM US), crude oil ($77.85/bbl WTI US) and an exchange rate
assumption of $0.75 (US/CAD). To the
extent such estimates constitute a financial outlook, it was
approved by management and the Board of Directors of Tourmaline on
March 1, 2023 and is included to provide readers with an
understanding of Tourmaline's anticipated cash flow and free cash
flow based on the capital expenditure, production, pricing,
exchange rate 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 the terms "cash flow
per diluted share", "free 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 standardized meanings prescribed by GAAP. In addition, this
news release contains the terms "adjusted working capital" and "net
debt", which are considered "capital management measures" and also
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 or more meaningful than the most directly comparable
GAAP measures in evaluating the Company's performance. See
"Non-GAAP and Other Financial Measures" in the most recent
Management's Discussion and Analysis for more information on the
definition and description of these terms.
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)
|
2022
|
|
2021
|
2022
|
2021
|
Cash flow from
operating activities (per GAAP)
|
$
1,115,399
|
$
|
1,058,460
|
$
4,692,731
|
$ 2,847,117
|
Current Income
Taxes
|
(7,599)
|
|
-
|
(11,934)
|
-
|
Change in non-cash
working capital (deficit)
|
294,847
|
|
(90,224)
|
203,152
|
82,009
|
Cash flow
|
$
1,402,647
|
$
|
968,236
|
$
4,883,949
|
$ 2,929,126
|
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)
|
2022
|
2021
|
2022
|
2021
|
Cash flow used in
investing activities (per GAAP)
|
$
548,471
|
$
468,384
|
$
1,971,129
|
$ 1,380,111
|
Corporate
acquisitions
|
-
|
-
|
(67,770)
|
-
|
Proceeds from sale of
investments
|
-
|
-
|
-
|
103,824
|
Change in non-cash
working capital (deficit)
|
(42,489)
|
(20,923)
|
(24,012)
|
106,436
|
Capital
expenditures
|
$
505,982
|
$
447,461
|
$
1,879,347
|
$ 1,590,371
|
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.
|
|
Three Months Ended
December 31,
|
Years Ended
December 31,
|
(000s)
|
|
2022
|
2021
|
2022
|
2021
|
Cash flow
|
$
|
1,402,647
|
$
968,236
|
$
4,883,949
|
$ 2,929,126
|
Capital
expenditures
|
|
(505,982)
|
(447,461)
|
(1,879,347)
|
(1,590,371)
|
Property
acquisitions
|
|
12,126
|
26,721
|
273,843
|
545,861
|
Proceeds from
divestitures
|
|
(109)
|
(1,560)
|
(71,489)
|
(392,556)
|
Free Cash
Flow
|
$
|
908,682
|
$
545,936
|
$
3,206,956
|
$ 1,492,060
|
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 to commodity sales from production, which is a GAAP
measure, is set forth below:
|
Three Months Ended
December 31,
|
Years Ended
December 31,
|
(000s)
|
2022
|
|
2021
|
2022
|
2021
|
Commodity sales from
production
|
$
1,932,515
|
$
|
1,709,063
|
$
8,110,837
|
$ 5,053,611
|
Premium on risk
management activities
|
409,241
|
|
21,579
|
517,109
|
13,943
|
Realized loss on
financial instruments
|
(165,293)
|
|
(201,297)
|
(885,109)
|
(398,291)
|
Royalties
|
(292,784)
|
|
(168,168)
|
(1,115,549)
|
(387,914)
|
Transportation
costs
|
(238,937)
|
|
(198,537)
|
(898,871)
|
(683,737)
|
Operating
expenses
|
(206,344)
|
|
(176,360)
|
(785,611)
|
(607,292)
|
Operating
netback
|
$
1,438,398
|
$
|
986,280
|
$
4,942,806
|
$ 2,990,320
|
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)
|
2022
|
2021
|
2022
|
2021
|
Revenue, excluding
processing income
|
$
46.24
|
$
34.27
|
$
42.36
|
$
29.00
|
Royalties
|
(6.22)
|
(3.77)
|
(6.10)
|
(2.41)
|
Transportation
costs
|
(5.08)
|
(4.45)
|
(4.92)
|
(4.25)
|
Operating
expenses
|
(4.38)
|
(3.95)
|
(4.30)
|
(3.77)
|
Operating
netback
|
$
30.56
|
$
22.10
|
$
27.04
|
$
18.57
|
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 "Reserves
Performance Ratios" section for information on annual cash flow per
boe and comparative period data used.
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.
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)
|
2022
|
2021
|
Working capital
(deficit)
|
$
809,449
|
$
(361,034)
|
Fair value of financial
instruments – short-term (asset) liability
|
(709,286)
|
240,970
|
Lease liabilities –
short-term
|
3,109
|
2,997
|
Decommissioning
obligations – short-term
|
30,000
|
20,103
|
Unrealized foreign
exchange in working capital – (asset)
|
(8,605)
|
(6,441)
|
Adjusted working
capital (deficit)
|
$
124,667
|
$
(103,405)
|
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)
|
2022
|
2021
|
Bank debt
|
$
(170,767)
|
$
(421,539)
|
Senior unsecured
notes
|
(448,342)
|
(448,035)
|
Adjusted working
capital (deficit)
|
124,667
|
(103,405)
|
Net debt
|
$
(494,442)
|
$
(972,979)
|
Supplementary Financial Measures
The following measures are supplementary financial measures:
cash flow per diluted share, reserve value per diluted share,
operating expenses ($/boe), cash general and administrative
expenses ($/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.
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 current production,
full-year 2022 production, Q4 2022 production and full-year 2023
expected 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)
|
Current
Production
|
|
45,000
|
|
1,335,000
|
|
1,125,000
|
|
70,000
|
|
525,000
|
2022
Production
|
|
42,923
|
|
1,284,879
|
|
1,045,355
|
|
69,537
|
|
500,832
|
Q4 2022
Production
|
|
43,549
|
|
1,310,520
|
|
1,065,943
|
|
71,964
|
|
511,590
|
2023 Expected
Average
Daily Production
|
|
48,300
|
|
1,336,100
|
|
1,118,500
|
|
72,600
|
|
530,000
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
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
|
JKM
|
Japan Korea
Marker
|
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
|
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.