CALGARY, March 3, 2020 /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 2019 as well as 2019 reserves results. The Company
delivered strong returns to shareholders, annual growth and
demonstrated continued financial resilience in this very
challenging energy cycle.
HIGHLIGHTS
- Tourmaline delivered full-year earnings of $319.7 million ($1.18/diluted share), again demonstrating the
profitability of its core EP business.
- Annual cash flow(1) of $1.2
billion ($4.43/diluted share)
and Q4 2019 cash flow of $335.9
million ($1.24/diluted share)
provide a platform for continued economic growth in 2020.
- Free cash flow(2) for 2019 of $144.9 million was a 27% increase over 2018. Q4
free cash flow of $67.1 million
represents an annualized free cash flow yield of approximately
8%.
- Tourmaline bought back 1,053,000 shares in 2019 at $12.23/share pursuant to its NCIB. Tourmaline
will continue to tactically pursue share buybacks funded by free
cash flow on hand if distressed valuations continue.
- The Company grew average annual liquids volumes by 16% and
total average production volumes by 10% in 2019, while containing
capital spending at $1.29 billion (up
only 6% from 2018).
- The Company posted record capital efficiency of $8,650/boepd (excluding acquisitions and
dispositions) – a 23% improvement over 2018.
- Tourmaline added 250.7 mmboe of proved plus probable reserves
("2P") after adding back annual production of 106.2 mmboe.
- 2P finding, development and acquisition costs (FD&A) in
2019 were $4.26/boe including changes
in future development capital ("FDC") ($5.13/boe excluding changes in FDC) based on
total capital expenditures of $1.29
billion, total proved ("TP") FD&A in 2019 were
$6.15/boe including change in FDC
($6.63/boe excluding change in FDC).
2019 proved, developed producing ("PDP") FD&A were $8.01/boe.
- Subsequent to the quarter, Tourmaline announced an update on
its NEBC consolidation activities. Through two corporate
transactions, Tourmaline has added 6,000 boepd of current
production, 2P reserves of 116.3 mmboe(3) and 160,000
acres of Montney lands for a
combined cash purchase price of $33.4
million.
2019 RESERVES
- Year-end 2019 PDP reserves of 527.4 mmboe were up 34% over
year-end 2018 when including 2019 annual production of 106.2
mmboe(4), TP reserves of 1.294 billion boe were up 16%
over 2018 when including 2019 annual production and 2P of 2.602
billion boe were up 10% when including 2019 annual production.
- Continued improvement in drill-and-complete capital costs
resulted in a significant reduction in FDC in the 2019 report.
- 2019 PDP finding and development ("F&D") costs were
$7.06/boe, including changes in FDC,
a record low, yielding a PDP reserve recycle ratio(5) of
1.6. Total proved F&D costs in 2019 were $4.94/boe including changes in FDC and 2P F&D
was $2.66/boe including changes in
FDC. 2P FD&A costs were $4.26/boe
including changes in FDC yielding a 2019 2P FD&A recycle ratio
of 2.7.
- Tourmaline replaced 236% of 2019's annual production of 106.2
mmboe in 2019 with a 2P addition of 251 mmboe before 2019
production.
- Tourmaline added the 251 mmboe of 2P reserves in 2019 even
though 66.8% of the 2019 drilling locations were converting
previously-booked locations. In 2019, the Company rig-released
198.9 (net) wells, down 7% from 2018 (213.1 wells) as the Company
moderated capital spending due to low commodity prices.
- Tourmaline's 2P reserve value equates to $55.69/share utilizing the lower 2019 engineering
price deck. TP reserve value is $32.42/share - PDP reserve value is $16.90/share.
- After 11 years of operation, Tourmaline now has 12.3 TCF of 2P
natural gas reserves and 553 million barrels of 2P oil, condensate,
and NGL reserves (January 1,
2020).
- For the seventh consecutive year, the Company enjoyed positive
2P technical revisions in its reserve report.
PRODUCTION UPDATE
- 2019 production averaged 290,865 boepd, Q4 2019 averaged
299,844 boepd. As announced on December 17,
2019, lengthy outages at the third-party Saturn deep-cut
facility in the Alberta Deep Basin and on the NEBC Enbridge system
reduced both quarterly liquid volumes and total production
levels.
- Current average production is 310,500 boepd excluding the
production impact of Polar Star Canadian Oil and Gas Inc. which
closed in February 2020. Tourmaline
has deferred a minimum of $25.0
million of first quarter capital expenditures from the
planned EP program into 2H 2020 due to lower commodity prices,
reducing 1H average production by approximately 2,500 boepd. The
Company is on track to meet full-year 2020 guidance of 315,000 –
320,000 boepd inclusive of this capital deferral and the effects of
weather-related freeze-offs in January. Closing of the
recently-announced acquisitions will be accretive to production
volumes, primarily in the second quarter.
- 2019 average liquids production was 55,338 bpd (oil,
condensate, NGL), a 16% increase over 2018. Current 2020 liquids
production is 64,300 bpd. The Company is targeting full-year 2020
liquids production of approximately 68,000 bpd (a 22%
year-over-year increase).
FINANCIAL HIGHLIGHTS
- Full-year 2019 after-tax earnings were $319.7 million ($1.18/diluted share) as Tourmaline remained
profitable despite a challenging year for natural gas prices. The
Company has built one of the most stable, low-cost businesses in
the North American energy sector.
- Fourth quarter 2019 cash flow was $335.9
million ($1.24/diluted share)
and full-year 2019 cash flow was $1,205.5
million ($4.43/diluted
share).
- Tourmaline generated $67.1
million of free cash flow in Q4 2019. The first quarter 2020
dividend of $0.12/share will be paid
on March 31, 2020.
- The five-year EP development plan, released in mid-December,
remains unchanged. It is expected to generate approximately
$1.75 billion of free cash flow over
the five years at strip pricing(6). This cash is
expected to be deployed into dividend increases, debt reduction,
and share buybacks. The Company acquired 1,053,000 shares in 2019
through the NCIB at an average price of $12.23.
- Tourmaline continued to effectively manage all-in cash costs in
2019 (operating, transportation, general and administrative and
financing) which totalled $8.18/boe
compared to $7.87/boe in 2018.
MARKETING HIGHLIGHTS
- For 2019, the Company posted a realized gas price across the
portfolio of $2.59/mcf, a 46% premium
over the average AECO 5A price for the year.
- For calendar year 2020, Tourmaline has an average of 252 mmcf/d
hedged at a weighted-average fixed price of CAD $2.44/mcf, an average of 202 mmcf/d hedged at a
basis to NYMEX of $(0.31) USD/mcf, an
average of 410 mmcf/d incremental volume exposed to export markets,
including Dawn, Chicago, Ventura,
Sumas, Malin and PGE.
- In the first quarter of 2020, as part of the Company's gas
marketing diversification strategy, the Company signed a long-haul
transportation agreement for 25 mmcfpd delivering to the US Gulf
Coast which will commence on November 1,
2022.
- For 2H 2019, Tourmaline had in excess of 4,000 bbls/d of
propane exposed to Argus Far East Index (AFEI) and realized
wellhead prices in excess of CAD $23/bbl above Edmonton prices.
- For 2020, Tourmaline expects to have in excess of 5,000 bbls/d
of propane exposed to AFEI.
2019/2020 CAPITAL PROGRAMS
- Full-year EP capital spending in 2019 was $1,033.1 million. The Company reduced its
originally-planned program by approximately $270.0 million during the course of the year.
Continued per-well capital cost improvements allowed the Company to
largely achieve original EP targets on the reduced spending.
- The 2020 EP capital program remains at $925.0 million. Additionally, Tourmaline has the
flexibility to reduce activity to a maintenance capital budget
which is $100 million lower than the
current plan. Tourmaline will monitor commodity prices and the
natural gas supply/demand balance over the next few months; the
full-year program may be revised in conjunction with the Q1 2020
results release in May 2020. The
Company has already elected to defer a minimum of $25.0 million of originally-planned Q1 2020 EP
expenditures into 2H 2020.
- Less than 15% of 2020 capital expenditures are directed towards
facility expenditures, which will drive anticipated 2020 capital
efficiencies of $6,500 – $7,000/boepd.
- Tourmaline continues to target a net
debt(7)-to-cash flow range of 1.0 - 1.5
times. At December 31, 2019, net
debt-to-cash flow was at 1.5 times (net debt to annualized Q4 2019
cash flow was at 1.3 times). Current targeted exit 2020 net
debt-to-cash flow is 1.2 times.
EP HIGHLIGHTS
- 2019 capital efficiency was approximately $8,650/boepd (excluding acquisitions and
dispositions) - a record low for Tourmaline as the Company
continued to reduce capital costs and deliver strong well results.
The Company is forecasting a further improvement in capital
efficiency in 2020.
- Q4 2019 operating costs were $3.06/boe, significantly less than originally
forecast. NEBC full-year 2019 operating costs were a record low of
$2.40/boe.
- Tourmaline rig-released 198.9 net wells in 2019, down 7% from
2018 and still achieved full-year production growth of 10% in
2019.
- Tourmaline operated up to 11 drilling rigs during Q1 2020, with
10 rigs now operating. The Company currently plans to operate three
rigs through break-up in Q2 2020.
- Capital cost reduction/improvements continue to be achieved
through monobore trials in the Alberta Deep Basin, application of
rotary steerable technology and novel pad equipping approaches,
amongst other technology-driven opportunities. NEBC Montney
horizontal completed well costs are now averaging $2.9 million (drill, 35 stage-completions,
equip.).
ENVIRONMENTAL IMPROVEMENT INITIATIVES
As outlined in the Company's Sustainability Report, published in
February 2020, Tourmaline has made
major strides in reducing emissions and continually improving
overall environmental performance.
Major Environmental Performance Achievements
- 46% reduction in CO2 emissions intensity
since 2013.
- Near elimination of all fresh water, in well stimulation
operations, in British
Columbia.
- Initiation of methane-reduction retrofit compliance plan
resulting in over 3,400 high-bleed devices being replaced in
2019.
- An approximate 50% reduction in the surface area per producing
well in the Company's operating areas due to multi-pad well
development.
- Broad replacement of diesel in Tourmaline's drilling and
completion operations with natural gas. Tourmaline now operates 15
natural gas fuel substitution units allowing for the displacement
of 9.8 million litres of diesel per year.
Environmental Performance Targets
- Continued emphasis on reducing corporate emissions intensity by
maintaining the Company's top-decile performance relative to the
Company's peer group while targeting a 25% reduction in total
methane emissions from 2018 levels by 2023.
- Reduce corporate emissions intensity by 25% by 2027 (scope 1)
using 2018 as a baseline, by continuing to focus on overall
efficiencies with the application of new, innovative technologies
including the electrification of assets, when feasible.
- Continually improve the Company's peer-leading performance on
water usage in completion activities by reducing and eventually
eliminating the usage of fresh water throughout its core gas
operations.
The environmental performance improvements achieved thus far,
and the myriad of future-planned initiatives, require significant
capital investment. The vast majority of these initiatives,
however, ultimately reduce Tourmaline's capital and operating cost
structure. Shareholders receive a double win – a cleaner
environment via Tourmaline's net-cleanest hydrocarbon molecule and
enhanced returns via the Company's improved efficiencies.
Our strong results and intense focus on sustainability is why
the world needs Canadian natural gas now and in the future.
DIVIDEND
The Company is pleased to announce that its Board of Directors
has declared a quarterly cash dividend on its common shares of
C$0.12 per common share. The dividend
will be payable March 31, 2020 to
shareholders of record at the close of business on March 16, 2020. 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 2019 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 2019 Management's Discussion
and Analysis.
|
(3)
|
Reserves have been
evaluated by independent reserve evaluators as at December 31, 2018
as follows: Polar Star 2P reserves of 80.7 mmboe by Sproule and
Chinook 2P reserves of 35.6 mmboe by McDaniel for a combined 2P
reserves total of 116.3 mmboe. Reserves are working interest gross
reserves before deduction of royalties payable to others and
without including any royalty interests.
|
(4)
|
See "Supplemental
Information Regarding Product Types" in this news
release.
|
(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)
|
Based on oil and
gas commodity strip pricing at December 11, 2019.
|
(7)
|
See "Non-GAAP
Financial Measures in this new release and in the Company's 2019
Management's Discussion and Analysis.
|
CORPORATE SUMMARY – DECEMBER 31,
2019
|
Three Months Ended
December 31,
|
Twelve Months Ended
December 31,
|
|
2019
|
2018
|
Change
|
2019
|
2018
|
Change
|
OPERATIONS
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
Natural gas
(mcf/d)
|
1,439,746
|
1,347,778
|
7%
|
1,413,160
|
1,305,025
|
8%
|
Crude oil, condensate
and NGL
|
|
|
|
|
|
|
(bbl/d)
|
59,886
|
51,938
|
15%
|
55,338
|
47,540
|
16%
|
Oil equivalent
(boe/d)
|
299,844
|
276,568
|
8%
|
290,865
|
265,044
|
10%
|
Product
prices(1)
|
|
|
|
|
|
|
Natural gas
($/mcf)
|
$
|
2.77
|
$
|
3.13
|
(12)%
|
$
|
2.59
|
$
|
2.73
|
(5)%
|
Crude oil, condensate
and NGL
|
|
|
|
|
|
|
($/bbl)
|
$
|
38.59
|
$
|
43.40
|
(11)%
|
$
|
39.29
|
$
|
46.47
|
(15)%
|
Operating expenses
($/boe)
|
$
|
3.06
|
$
|
3.35
|
(9)%
|
$
|
3.28
|
$
|
3.33
|
(2)%
|
Transportation costs
($/boe)
|
$
|
4.13
|
$
|
3.63
|
14%
|
$
|
3.86
|
$
|
3.52
|
10%
|
Operating
netback(3) ($/boe)
|
$
|
13.00
|
$
|
15.82
|
(18)%
|
$
|
12.12
|
$
|
14.12
|
(14)%
|
Cash general and
administrative
expenses ($/boe)(2)
|
$
|
0.52
|
$
|
0.42
|
24%
|
$
|
0.49
|
$
|
0.49
|
-%
|
|
|
|
|
|
|
|
FINANCIAL
|
|
|
|
|
|
|
($000, except
share and per share)
|
|
|
|
|
|
|
Total revenue from
commodity sales
and realized gains
|
579,588
|
595,487
|
(3)%
|
2,127,337
|
2,106,209
|
1%
|
Royalties
|
22,559
|
15,380
|
47%
|
83,030
|
77,369
|
7%
|
Cash
flow(4)
|
335,856
|
391,532
|
(14)%
|
1,205,540
|
1,303,462
|
(8)%
|
Cash flow per share
(diluted)(4)
|
$
|
1.24
|
$
|
1.44
|
(14)%
|
$
|
4.43
|
$
|
4.80
|
(8)%
|
Net
earnings
|
61,340
|
190,895
|
(68)%
|
319,740
|
401,418
|
(20)%
|
Net earnings per
share (diluted)
|
$
|
0.23
|
$
|
0.70
|
(67)%
|
$
|
1.18
|
$
|
1.48
|
(20)%
|
Capital expenditures
(net of
dispositions)
|
320,389
|
395,194
|
(19)%
|
1,287,259
|
1,214,437
|
6%
|
Weighted average
shares outstanding
(diluted)
|
|
|
|
271,878,824
|
271,702,910
|
-%
|
Net
debt(4)
|
|
|
|
(1,755,684)
|
(1,720,009)
|
2%
|
PROVED
+
|
|
|
|
|
|
|
PROBABLE
RESERVES(3)
|
|
|
|
|
|
|
Natural gas
(bcf)
|
|
|
|
12,294.6
|
11,712.7
|
5%
|
Crude oil
(mbbls)
|
|
|
|
96,984
|
82,046
|
18%
|
Natural gas liquids
(mbbls)
|
|
|
|
455,851
|
423,198
|
8%
|
Mboe
|
|
|
|
2,601,928
|
2,457,358
|
6%
|
|
|
(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, 2019.
|
2019 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 74% 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 7% 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 9% and 8%, 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 Oil and
Gas Reserves and
|
Net Present Values
of Future Net Revenue
|
as of December 31,
2019
|
Forecast Prices
and Costs(1)
|
|
|
Light & Medium
Crude
Oil
|
|
Conventional
Natural
Gas
|
|
Shale Natural
Gas(2)
|
|
Natural Gas
Liquids
|
|
Total Oil
Equivalent
|
|
|
Company
|
|
Company
|
|
Company
|
|
Company
|
|
Company
|
|
Company
|
|
Company
|
|
Company
|
|
Company
|
|
Company
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Reserves
Category
|
|
(Mbbls)
|
|
(Mbbls)
|
|
(MMcf)
|
|
(MMcf)
|
|
(MMcf)
|
|
(MMcf)
|
|
(Mbbls)
|
|
(Mbbls)
|
|
(Mboe)
|
|
(Mboe)
|
Proved
Producing
|
|
13,948
|
|
11,422
|
|
1,676,894
|
|
1,505,877
|
|
910,873
|
|
844,148
|
|
82,118
|
|
68,535
|
|
527,361
|
|
471,628
|
Proved Developed
Non-Producing
|
|
1,935
|
|
1,504
|
|
95,010
|
|
85,260
|
|
208,272
|
|
196,007
|
|
12,432
|
|
10,958
|
|
64,914
|
|
59,340
|
Proved
Undeveloped
|
|
32,189
|
|
26,203
|
|
1,929,133
|
|
1,751,774
|
|
1,408,310
|
|
1,308,908
|
|
113,735
|
|
102,419
|
|
702,164
|
|
638,736
|
Total
Proved
|
|
48,072
|
|
39,130
|
|
3,701,036
|
|
3,342,911
|
|
2,527,455
|
|
2,349,063
|
|
208,285
|
|
181,912
|
|
1,294,439
|
|
1,169,704
|
Total
Probable
|
|
48,912
|
|
39,478
|
|
2,412,245
|
|
2,173,075
|
|
3,653,824
|
|
3,279,086
|
|
247,566
|
|
210,547
|
|
1,307,490
|
|
1,158,719
|
Total Proved Plus
Probable
|
|
96,984
|
|
78,608
|
|
6,113,281
|
|
5,515,987
|
|
6,181,279
|
|
5,628,148
|
|
455,851
|
|
392,458
|
|
2,601,928
|
|
2,328,422
|
|
|
Net Present Values
of Future Net Revenue ($000s)
|
|
|
Before Income
Taxes Discounted at
(%/year)
|
|
After Income Taxes
Discounted at(3) (%/year)
|
|
Unit Value
Before Income
Tax Discounted
at 10%/year
|
Reserves
Category
|
|
0
|
|
5
|
|
10
|
|
15
|
|
20
|
|
0
|
|
5
|
|
10
|
|
15
|
|
20
|
|
($/Boe)
|
|
($/Mcfe)
|
Proved
Producing
|
|
6,776,073
|
|
5,475,633
|
|
4,579,234
|
|
3,953,261
|
|
3,496,236
|
|
6,513,916
|
|
5,329,729
|
|
4,494,030
|
|
3,901,446
|
|
3,463,622
|
|
9.71
|
|
1.62
|
Proved Developed
Non-Producing
|
|
951,690
|
|
723,446
|
|
581,989
|
|
487,603
|
|
420,666
|
|
703,333
|
|
555,992
|
|
464,566
|
|
402,764
|
|
357,903
|
|
9.81
|
|
1.63
|
Proved
Undeveloped
|
|
8,114,346
|
|
5,258,108
|
|
3,623,511
|
|
2,611,296
|
|
1,943,173
|
|
5,988,919
|
|
3,824,651
|
|
2,584,398
|
|
1,819,464
|
|
1,317,883
|
|
5.67
|
|
0.95
|
Total
Proved
|
|
15,842,109
|
|
11,457,187
|
|
8,784,733
|
|
7,052,160
|
|
5,860,075
|
|
13,206,167
|
|
9,710,371
|
|
7,542,994
|
|
6,123,674
|
|
5,139,408
|
|
7.51
|
|
1.25
|
Total
Probable
|
|
20,521,808
|
|
10,555,460
|
|
6,308,597
|
|
4,165,195
|
|
2,945,016
|
|
15,169,537
|
|
7,746,820
|
|
4,579,558
|
|
2,987,161
|
|
2,086,554
|
|
5.44
|
|
0.91
|
Total Proved Plus
Probable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,363,916
|
|
22,012,647
|
|
15,093,330
|
|
11,217,355
|
|
8,805,091
|
|
28,375,704
|
|
17,457,191
|
|
12,122,552
|
|
9,110,834
|
|
7,225,961
|
|
6.48
|
|
1.08
|
|
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,
2019
|
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
|
|
12,077,042
|
|
1,248,887
|
|
3,611,456
|
|
50
|
|
440,576
|
|
6,776,073
|
|
262,157
|
|
6,513,916
|
Proved Developed
Non-
Producing
|
|
1,573,143
|
|
164,268
|
|
368,213
|
|
66,242
|
|
22,730
|
|
951,690
|
|
248,357
|
|
703,333
|
Proved
Undeveloped
|
|
17,308,773
|
|
1,640,354
|
|
3,550,448
|
|
3,805,349
|
|
198,275
|
|
8,114,346
|
|
2,125,427
|
|
5,988,919
|
Total
Proved
|
|
30,958,957
|
|
3,053,509
|
|
7,530,117
|
|
3,871,642
|
|
661,581
|
|
15,842,109
|
|
2,635,941
|
|
13,206,167
|
Total
Probable
|
|
37,823,111
|
|
4,827,222
|
|
8,615,423
|
|
3,532,409
|
|
326,248
|
|
20,521,808
|
|
5,352,271
|
|
15,169,537
|
Total Proved Plus
Probable
|
|
68,782,068
|
|
7,880,731
|
|
16,145,540
|
|
7,404,051
|
|
987,829
|
|
36,363,916
|
|
7,988,212
|
|
28,375,704
|
|
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
2020
$
$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
|
2020
|
|
0.0
|
|
0.7600
|
|
61.00
|
|
61.00
|
|
72.64
|
|
6.42
|
|
26.36
|
|
42.09
|
|
76.83
|
2021
|
|
1.7
|
|
0.7700
|
|
62.70
|
|
63.75
|
|
76.06
|
|
7.41
|
|
29.80
|
|
47.03
|
|
79.82
|
2022
|
|
2.0
|
|
0.7850
|
|
63.82
|
|
66.18
|
|
78.35
|
|
8.33
|
|
32.94
|
|
50.66
|
|
82.30
|
2023
|
|
2.0
|
|
0.7850
|
|
64.20
|
|
67.91
|
|
80.71
|
|
8.65
|
|
34.00
|
|
52.21
|
|
84.72
|
2024
|
|
2.0
|
|
0.7850
|
|
64.40
|
|
69.48
|
|
82.64
|
|
8.98
|
|
34.89
|
|
53.48
|
|
86.71
|
2025
|
|
2.0
|
|
0.7850
|
|
64.58
|
|
71.07
|
|
84.60
|
|
9.24
|
|
35.78
|
|
54.77
|
|
88.73
|
2026
|
|
2.0
|
|
0.7850
|
|
64.75
|
|
72.68
|
|
86.57
|
|
9.46
|
|
36.69
|
|
56.07
|
|
90.77
|
2027
|
|
2.0
|
|
0.7850
|
|
64.84
|
|
74.24
|
|
88.49
|
|
9.67
|
|
37.57
|
|
57.32
|
|
92.76
|
2028
|
|
2.0
|
|
0.7850
|
|
64.84
|
|
75.73
|
|
90.31
|
|
9.89
|
|
38.41
|
|
58.50
|
|
94.65
|
2029
|
|
2.0
|
|
0.7850
|
|
64.85
|
|
77.24
|
|
92.17
|
|
10.12
|
|
39.26
|
|
59.71
|
|
96.57
|
2030
|
|
2.0
|
|
0.7850
|
|
64.85
|
|
78.79
|
|
94.01
|
|
10.35
|
|
40.11
|
|
60.90
|
|
98.53
|
2031
|
|
2.0
|
|
0.7850
|
|
64.85
|
|
80.36
|
|
95.89
|
|
10.56
|
|
40.91
|
|
62.12
|
|
100.50
|
2032
|
|
2.0
|
|
0.7850
|
|
64.84
|
|
81.97
|
|
97.81
|
|
10.77
|
|
41.73
|
|
63.36
|
|
102.51
|
2033
|
|
2.0
|
|
0.7850
|
|
64.84
|
|
83.61
|
|
99.76
|
|
10.98
|
|
42.56
|
|
64.63
|
|
104.56
|
2034
|
|
2.0
|
|
0.7850
|
|
64.85
|
|
85.28
|
|
101.76
|
|
11.20
|
|
43.42
|
|
65.92
|
|
106.65
|
2035
|
|
2.0
|
|
0.7850
|
|
64.85
|
|
+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
2020 $
$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
2020 $
$Cdn/
MMbtu
|
|
Then Current
$Cdn/
MMbtu
|
|
ARP $Cdn/
MMbtu
|
|
Sumas Spot
$US/
MMbtu
|
|
Westcoast
Station 2
$Cdn/
MMbtu
|
|
Spot Plant
Gate
$Cdn/
MMbtu
|
2020
|
|
2.62
|
|
2.62
|
|
2.53
|
|
2.04
|
|
2.58
|
|
1.82
|
|
1.82
|
|
1.83
|
|
2.16
|
|
1.66
|
|
1.41
|
2021
|
|
2.82
|
|
2.87
|
|
2.78
|
|
2.32
|
|
2.82
|
|
2.07
|
|
2.10
|
|
2.11
|
|
2.44
|
|
1.99
|
|
1.74
|
2022
|
|
2.95
|
|
3.06
|
|
2.96
|
|
2.62
|
|
3.01
|
|
2.30
|
|
2.39
|
|
2.40
|
|
2.72
|
|
2.31
|
|
2.07
|
2023
|
|
2.99
|
|
3.17
|
|
3.07
|
|
2.71
|
|
3.12
|
|
2.35
|
|
2.48
|
|
2.50
|
|
2.83
|
|
2.46
|
|
2.21
|
2024
|
|
3.01
|
|
3.24
|
|
3.15
|
|
2.81
|
|
3.20
|
|
2.39
|
|
2.58
|
|
2.59
|
|
2.90
|
|
2.56
|
|
2.31
|
2025
|
|
3.02
|
|
3.32
|
|
3.23
|
|
2.89
|
|
3.27
|
|
2.41
|
|
2.66
|
|
2.67
|
|
2.98
|
|
2.66
|
|
2.42
|
2026
|
|
3.02
|
|
3.39
|
|
3.30
|
|
2.96
|
|
3.34
|
|
2.42
|
|
2.72
|
|
2.74
|
|
3.05
|
|
2.73
|
|
2.48
|
2027
|
|
3.02
|
|
3.46
|
|
3.36
|
|
3.03
|
|
3.41
|
|
2.43
|
|
2.78
|
|
2.80
|
|
3.12
|
|
2.80
|
|
2.54
|
2028
|
|
3.02
|
|
3.52
|
|
3.43
|
|
3.10
|
|
3.48
|
|
2.44
|
|
2.85
|
|
2.87
|
|
3.18
|
|
2.87
|
|
2.61
|
2029
|
|
3.02
|
|
3.60
|
|
3.50
|
|
3.17
|
|
3.55
|
|
2.45
|
|
2.92
|
|
2.94
|
|
3.26
|
|
2.93
|
|
2.68
|
2030
|
|
3.02
|
|
3.67
|
|
3.58
|
|
3.24
|
|
3.62
|
|
2.46
|
|
2.99
|
|
3.00
|
|
3.33
|
|
3.00
|
|
2.74
|
2031
|
|
3.02
|
|
3.74
|
|
3.65
|
|
3.30
|
|
3.69
|
|
2.46
|
|
3.05
|
|
3.07
|
|
3.39
|
|
3.06
|
|
2.80
|
2032
|
|
3.02
|
|
3.81
|
|
3.72
|
|
3.37
|
|
3.77
|
|
2.46
|
|
3.11
|
|
3.13
|
|
3.46
|
|
3.12
|
|
2.85
|
2033
|
|
3.02
|
|
3.89
|
|
3.80
|
|
3.43
|
|
3.84
|
|
2.46
|
|
3.17
|
|
3.19
|
|
3.54
|
|
3.19
|
|
2.91
|
2034
|
|
3.02
|
|
3.97
|
|
3.87
|
|
3.50
|
|
3.92
|
|
2.46
|
|
3.23
|
|
3.25
|
|
3.61
|
|
3.25
|
|
2.97
|
2035
|
|
3.02
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
+2.0%/yr
|
|
2.46
|
|
+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, 2019
and GLJ and McDaniel & Associates Consultants Ltd. as at
January 1, 2020 (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 and PG&E 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, 2019.
|
(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,
|
2019
|
2018
|
2017
|
Reserves
(Mboe)
|
|
|
|
Proved
Producing
|
527,361
|
473,269
|
436,208
|
Total
Proved
|
1,294,439
|
1,206,381
|
1,055,702
|
Proved Plus
Probable
|
2,601,928
|
2,457,358
|
2,216,206
|
Capital
Expenditures ($ millions)
|
|
|
|
Exploration and
Development(2)
|
1,069
|
1,261
|
1,364
|
Net Acquisitions
(Dispositions)
|
219
|
(47)
|
58
|
Total Capital
Expenditures
|
1,287
|
1,214
|
1,422
|
Cash
Flow ($/boe)
|
|
|
|
Cash Flow
|
11.36
|
13.47
|
13.63
|
Cash Flow - Three
Year Average
|
12.75
|
12.80
|
13.11
|
|
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 $33 million, $30 million and $27 million for
2019, 2018 and 2017 respectively.
|
Finding and Development Costs
Finding and
Development Costs, Excluding FDC
|
2019
|
2018
|
2017
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Reserve Additions
(MMboe)
|
160.7
|
241.0
|
272.8
|
|
F&D Costs
($/boe)
|
6.65
|
5.24
|
5.00
|
5.48
|
F&D Recycle
Ratio(1)
|
1.7
|
2.6
|
2.7
|
2.3
|
Total Proved
Plus Probable
|
|
|
|
|
Reserve Additions
(MMboe)
|
180.4
|
326.6
|
537.5
|
|
F&D Costs
($/boe)
|
5.92
|
3.86
|
2.54
|
3.54
|
F&D Recycle
Ratio(1)
|
1.9
|
3.5
|
5.4
|
3.6
|
|
|
|
|
|
Finding and
Development Costs, Including FDC
|
2019
|
2018
|
2017
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Change in FDC ($
millions)
|
(275.2)
|
441.7
|
481.1
|
|
Reserve Additions
(MMboe)
|
160.7
|
241.0
|
272.8
|
|
F&D Costs
($/boe)
|
4.94
|
7.07
|
6.76
|
6.44
|
F&D Recycle
Ratio(1)
|
2.3
|
1.9
|
2.0
|
2.0
|
Total Proved
Plus Probable
|
|
|
|
|
Change in FDC ($
millions)
|
(589.4)
|
486.3
|
612.1
|
|
Reserve Additions
(MMboe)
|
180.4
|
326.6
|
537.5
|
|
F&D Costs
($/boe)
|
2.66
|
5.35
|
3.68
|
4.02
|
F&D Recycle
Ratio(1)
|
4.3
|
2.5
|
3.7
|
3.2
|
Finding, Development and Acquisition Costs
Finding,
Development and Acquisition Costs,
Excluding FDC
|
2019
|
2018
|
2017
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Reserve Additions
(MMboe)
|
194.2
|
247.4
|
285.2
|
|
FD&A Costs
($/boe)
|
6.63
|
4.91
|
4.98
|
5.40
|
FD&A Recycle
Ratio(1)
|
1.7
|
2.7
|
2.7
|
2.4
|
Total Proved
Plus Probable
|
|
|
|
|
Reserve Additions
(MMboe)
|
250.7
|
337.9
|
557.8
|
|
FD&A Costs
($/boe)
|
5.13
|
3.59
|
2.55
|
3.42
|
FD&A Recycle
Ratio(1)
|
2.2
|
3.7
|
5.3
|
3.7
|
|
|
|
|
|
Finding,
Development and Acquisition Costs,
Including FDC
|
2019
|
2018
|
2017
|
3-Year
Avg.
|
Total
Proved
|
|
|
|
|
Change in FDC ($
millions)
|
(93.4)
|
465.3
|
515.7
|
|
Reserve Additions
(MMboe)
|
194.2
|
247.4
|
285.2
|
|
FD&A Costs
($/boe)
|
6.15
|
6.79
|
6.79
|
6.62
|
FD&A Recycle
Ratio(1)
|
1.8
|
2.0
|
2.0
|
1.9
|
Total Proved
Plus Probable
|
|
|
|
|
Change in FDC ($
millions)
|
(218.0)
|
526.8
|
678.3
|
|
Reserve Additions
(MMboe)
|
250.7
|
337.9
|
557.8
|
|
FD&A Costs
($/boe)
|
4.26
|
5.15
|
3.76
|
4.28
|
FD&A Recycle
Ratio(1)
|
2.7
|
2.6
|
3.6
|
3.0
|
|
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 4, 2020 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 3587405.
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 2020 and
beyond; expected free cash flow and cash flow levels; potential for
share buybacks; targeted 2020 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;
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
free cash flow including in 2020 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. 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 Petroleum Consultants Ltd. ("GLJ") and Deloitte LLP, each dated
effective December 31, 2019, 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, 2020
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, 2019, which will be filed on SEDAR (accessible at
www.sedar.com) on or before March 30,
2020.
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, 2019, which will be filed on SEDAR
(accessible at www.sedar.com) on or before March 30, 2020.
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
2020 exit net debt-to-cash flow ratio as well as 2020 – 2024 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 315,000 –
320,000 boepd for 2020 and 333,000, 353,000, 372,000 and 391,000
boepd for 2021 - 2024, respectively. Commodity price assumptions
for natural gas (NYMEX (US) - $2.29/mcf, $2.46/mcf, $2.46/mcf, $2.49/mcf and $2.54/mcf for 2020 – 2024, respectively; AECO -
$1.92/mcf, $2.08/mcf, $2.10/mcf, $2.13/mcf and $2.27/mcf for 2020 – 2024, respectively), and
crude oil (WTI (US) - $57.30/bbl,
$53.51/bbl, $51.81/bbl, $51.20/bbl and $51.19/bbl for 2020 – 2024, respectively) and an
exchange rate assumption of $0.76
(US/CAD) for 2020 and 2021 and $0.75
for 2022 - 2024. Further, in the case of years subsequent to 2020,
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 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 3,
2020 and are included to provide readers with an
understanding of Tourmaline's anticipated 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. In particular, readers are
cautioned that estimates for 2021 and beyond are provided for
illustration only as budgets and forecasts beyond 2021 have not
been finalized and are subject to a variety of factors including
prior year's results.
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 2019 annual production,
2019 average daily production, Q4 average daily production, current
average daily production and 2020 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)
|
2019 Annual
Production
|
9,102,058
|
|
348,019,492
|
|
167,783,775
|
|
11,096,311
|
|
106,165,580
|
2019 Average
Daily
Production
|
24,937
|
|
953,478
|
|
459,682
|
|
30,401
|
|
290,865
|
Q4 2019 Average
Daily
Production
|
27,832
|
|
925,580
|
|
514,166
|
|
32,054
|
|
299,844
|
Current Average
Daily
Production
|
27,571
|
|
960,312
|
|
516,337
|
|
36,821
|
|
310,500
|
2020 Average
Daily
Production
|
31,179
|
|
896,058
|
|
600,466
|
|
36,900
|
|
317,500
|
|
|
(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
|
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, 2019 and 2018, please refer to SEDAR
(www.sedar.com) or Tourmaline's website at
www.tourmalineoil.com.
ABOUT TOURMALINE OIL CORP.
Tourmaline is a Canadian senior crude oil and natural gas
exploration and production company focused on long-term growth
through an aggressive exploration, development, production and
acquisition program in the Western Canadian Sedimentary Basin.
SOURCE Tourmaline Oil Corp.