TSX: TVE
CALGARY,
AB, Oct. 26, 2023 /CNW/ - Tamarack Valley
Energy Ltd. ("Tamarack" or the "Company") is pleased
to announce its financial and operating results for the three and
nine months ended September 30, 2023.
Selected financial and operating information is outlined below and
should be read with Tamarack's consolidated financial statements
and related management's discussion and analysis (MD&A) for the
three and nine months ended September 30,
2023, which will be available on SEDAR+ at www.sedarplus.ca
and on Tamarack's website at www.tamarackvalley.ca.
Q3 2023 Financial and Operating Highlights
- Record Corporate Production - Delivered on average
68,597 boe/d(2) during the third quarter resulting in
the highest quarterly production in Tamarack's history. This
represents a 58% year over year increase and 16% uplift to debt
adjusted per share production on a quarter over quarter basis;
- Reduced Production Expense - Net production
expense(1) improved by 17% year-over-year to
$8.47/boe reflecting the impact of
the Company's Wembley gas plant in
the Charlie Lake light oil play,
additional infrastructure development in the Clearwater area and higher production during
the quarter;
- Focused Capital Deployment - Capital
expenditures(1) of $122.8
million in the quarter included $85.7
million of development capital and $37.1 million of facility capital. Third quarter
activity included 41 (40.3 net) Clearwater heavy oil wells and 1 (1.0 net)
Charlie Lake light oil well. Year
to date the Company has drilled, completed and equipped 93 (91.6
net) Clearwater heavy oil wells
and 14 (13.8 net) Charlie Lake
light oil wells;
- Quarterly Adjusted Funds Flow(1) - Record
production and strong Canadian oil prices generated adjusted funds
flow(1) of $255.2 million
in Q3/23, which was 44% higher than the same quarter in 2022;
- Free Funds Flow(1) Generation - Free funds
flow(1) of $132.4 million
was $53 million, or 40%, higher on a
year over year basis. Year to date, the Company has generated
$181.0 million of free funds
flow(1);
- Debt Reduction – Net debt(1) decreased to
$1,128.0 million at September 30, 2023, reflecting the benefit of
free funds flow(1), non-core dispositions and assets
held for sale at the end of the quarter.
Brian Schmidt (Aakaikkitstaki), Tamarack's President and CEO
commented: "Tamarack's third quarter results reflect the successful
execution of ongoing drilling and field activity across our
portfolio of core development prospects. We remain focused on
disciplined capital deployment and strategic dispositions as net
debt continues to be reduced and our asset base is high graded.
Benefitting from infrastructure investment through the first half
of 2023, the Company has increased our ownership and control of
strategic facilities in our key plays resulting in enhanced market
access and driving our cost structure lower. Tamarack provides
investors with differentiated and focused exposure to two of
North America's most economic
plays. Exiting 2023, we expect 88% of our production to be derived
from our remaining core holdings in the Clearwater and Charlie Lake plays."
Financial & Operating Results
|
Three months
ended
|
Nine months
ended
|
September
30,
|
September
30,
|
|
2023
|
2022
|
%
change
|
2023
|
2022
|
%
change
|
($ thousands,
except per share)
|
|
|
|
|
|
|
Total oil, natural gas
revenue
|
506,365
|
327,910
|
54
|
1,284,066
|
1,033,135
|
24
|
Cash flow from
operating activities
|
199,756
|
229,927
|
(13)
|
415,645
|
577,488
|
(28)
|
Per
share – basic
|
$
0.36
|
$ 0.52
|
(31)
|
$
0.75
|
$ 1.34
|
(44)
|
Per
share – diluted
|
$
0.36
|
$ 0.52
|
(31)
|
$
0.74
|
$ 1.33
|
(44)
|
Adjusted funds flow
(1)
|
255,199
|
177,834
|
44
|
569,723
|
530,315
|
7
|
Per
share – basic (1)
|
$
0.46
|
$ 0.40
|
15
|
$
1.02
|
$ 1.23
|
(17)
|
Per
share – diluted (1)
|
$
0.46
|
$ 0.40
|
15
|
$
1.02
|
$ 1.22
|
(16)
|
Net income
|
8,634
|
124,793
|
(93)
|
36,874
|
294,757
|
(87)
|
Per
share – basic
|
$
0.02
|
$ 0.28
|
(93)
|
$
0.07
|
$ 0.68
|
(90)
|
Per
share – diluted
|
$
0.02
|
$ 0.28
|
(93)
|
$
0.07
|
$ 0.68
|
(90)
|
Net debt
(1)
|
(1,128,030)
|
(286,762)
|
293
|
(1,128,030)
|
(286,762)
|
293
|
Capital expenditures
(1)
|
122,759
|
98,451
|
25
|
388,752
|
333,301
|
17
|
Weighted average
shares outstanding (thousands)
|
|
|
|
|
|
|
Basic
|
556,708
|
440,388
|
26
|
556,399
|
431,672
|
29
|
Diluted
|
558,569
|
443,351
|
26
|
559,958
|
435,053
|
29
|
Share
Trading
|
|
|
|
|
|
|
High
|
$
4.12
|
$ 4.62
|
(11)
|
$
4.88
|
$ 6.48
|
(25)
|
Low
|
$
3.19
|
$ 3.28
|
(3)
|
$
2.99
|
$ 3.28
|
(9)
|
Average daily share
trading volume (thousands)
|
1,975
|
3,745
|
(47)
|
2,457
|
3,890
|
(37)
|
Average daily
production
|
|
|
|
|
|
|
Light oil
(bbls/d)
|
16,974
|
16,229
|
5
|
16,797
|
17,437
|
(4)
|
Heavy oil
(bbls/d)
|
35,900
|
13,183
|
172
|
35,229
|
10,524
|
235
|
NGL
(bbls/d)
|
3,623
|
3,659
|
(1)
|
3,795
|
3,769
|
1
|
Natural
gas (mcf/d)
|
72,597
|
62,428
|
16
|
71,633
|
66,839
|
7
|
Total
(boe/d)
|
68,597
|
43,476
|
58
|
67,760
|
42,870
|
58
|
Average sale
prices
|
|
|
|
|
|
|
Light oil
($/bbl)
|
107.83
|
111.80
|
(4)
|
98.30
|
119.53
|
(18)
|
Heavy oil,
net of blending expense(1) ($/bbl)
|
92.85
|
89.30
|
4
|
76.15
|
99.48
|
(23)
|
NGL
($/bbl)
|
41.46
|
49.18
|
(16)
|
41.51
|
56.23
|
(26)
|
Natural
gas ($/mcf)
|
2.60
|
6.27
|
(59)
|
2.84
|
6.59
|
(57)
|
Total
($/boe)
|
80.22
|
81.98
|
(2)
|
69.29
|
88.28
|
(22)
|
Operating netback
($/Boe)
|
|
|
|
|
|
|
Average
realized sales, net of blending expense (1)
|
80.22
|
81.98
|
(2)
|
69.29
|
88.28
|
(22)
|
Royalty
expenses
|
(13.38)
|
(14.06)
|
(5)
|
(12.70)
|
(16.49)
|
(23)
|
Net
production expenses (1)
|
(8.47)
|
(10.24)
|
(17)
|
(9.72)
|
(10.25)
|
(5)
|
Transportation expenses
|
(4.13)
|
(2.88)
|
43
|
(4.00)
|
(2.49)
|
61
|
Operating field
netback ($/Boe) (1)
|
54.24
|
54.80
|
(1)
|
42.87
|
59.05
|
(27)
|
Realized
commodity hedging loss
|
(2.52)
|
(2.90)
|
(13)
|
(1.89)
|
(5.46)
|
(65)
|
Operating netback
($/Boe) (1)
|
51.72
|
51.90
|
–
|
40.98
|
53.59
|
(24)
|
Adjusted funds flow
($/Boe) (1)
|
40.44
|
44.46
|
(9)
|
30.80
|
45.31
|
(32)
|
2023 Outlook & Guidance Update
The Company's exploration and development capital guidance range
remains unchanged at $425 million to
$475 million(3). Tamarack
continues to focus on maximizing free funds flow(1) for
debt repayment and enhancing shareholder returns as debt thresholds
are met. Fourth quarter 2023 free funds flow(1) is
expected to reflect increased oil weighting driving improved
netback(1) realizations through our infrastructure
initiatives.
Tamarack has updated its 2023 production guidance to reflect the
west central non-core Cardium asset disposition previously
announced on October 19, 2023 (the
"Disposition). Updated full year 2023 production is expected to be
in the range of 65,500 to 69,500 boe/d(4) with fourth
quarter volumes of 65,000 to 66,000 boe/d(5). Production
guidance reflects the strong performance of our Clearwater and Charlie Lake drilling programs and impact of
the Disposition of ~4,500 boe/d(6) for the fourth
quarter. Tamarack expects to provide the 2024 budget and guidance
on December 6, 2023.
|
|
Prior Guidance
2023
|
Current Guidance
2023
|
|
|
as presented May 10,
2023
|
|
Capital Budget
($MM)(3)
|
|
$425 – $475
|
$425 – $475
|
Annual Average
Production (boe/d)(4)
|
|
67,000 –
71,000
|
65,500 –
69,500
|
Average Oil & NGL
Weighting
|
|
81% – 83%
|
82% – 84%
|
|
|
|
|
Expenses:
|
|
|
|
Royalty Rate
(%)
|
|
19% – 21%
|
19% – 21%
|
Operating
($/boe)
|
|
$9.00 –
$9.50
|
$9.00 –
$9.50
|
Transportation
($/boe)
|
|
$3.50 –
$4.00
|
$3.50 –
$4.00
|
General and
Administrative ($/boe)(7)
|
|
$1.25 –
$1.35
|
$1.25 –
$1.35
|
Interest
($/boe)
|
|
$3.80 –
$4.00
|
$3.80 –
$4.00
|
Taxes
($/boe)(8)
|
|
$3.75 –
$4.10
|
$3.75 –
$4.50
|
Leasing Expenditures
($MM)
|
|
$3.5 – $4.5
|
$3.5 – $4.5
|
Operations Update
Infrastructure
Tamarack's owned and operated Wembley gas plant continues to provide
consistent and reliable processing capacity within the Company's
operational control. Since commissioning in mid-June, approximately
40% of the Company's Charlie Lake
production is processed through the facility and Tamarack has
materially reduced its exposure to third party downtime at
Wembley to approximately 1.2%
(June 2023 to October 2023). This compares to average
third-party downtime of approximately 12.0% from January 2022 to May
2023 resulting from infrastructure outages where Tamarack
was delivering Wembley Charlie Lake volumes to non-operated
facilities.
At West Marten Hills, Tamarack is expanding capacity at its
Marten Creek plant to increase gas
conservation and reduce emissions intensity as our Clearwater development moves forward. This
facility offers the potential to become a regional conservation hub
and is expected to initially conserve 6 MMcf/d of natural gas
commencing in Q1/24. Expansion of this facility is underway and is
expected to support long term regional Clearwater development.
Tamarack continues to advance strategic initiatives to enhance
pricing and reduce costs, including the Nipisi terminal and
pipeline project which has been commissioned, with linefill
delivered in October. On the heels of this start up, Tamarack was
able to secure the sale of initial batches of its Clearwater Heavy
Oil barrels in October, for November delivery, which attracted
premium pricing relative to the CHV (Conventional Heavy Oil)
benchmark.
Clearwater
Clearwater production averaged
37,600 boe/d(9) in the third quarter, representing 55%
of corporate production. During the quarter, the Company drilled
and brought onstream 41 (40.3 net) Clearwater wells. Tamarack currently has five
rigs running on its Clearwater
assets (three at West Marten Hills, one at Nipisi and one at Marten
Hills).
West Marten Hills continues to see strong well results as
Tamarack recently brought 13 new B sand wells onstream, which
included eight wells at the 02-22-76-5W5 pad (with average IP30 oil
rates exceeding 250 bopd per well) and five wells at the
12-22-76-5W5 pad (with average IP30 oil rates of approximately 225
bopd per well). Demonstrating the stacked potential in this area,
the Company has brought two new C sand wells onstream from the 2-22
and 12-22 pads with per well average IP30 of 245 bopd and 314 bopd
respectively. Tamarack plans to waterflood the B and C sands from
these pads, leveraging interconnected infrastructure to improve the
economics for both zones.
Primary development at Marten Hills focused on multi-well pads
with longer lateral lengths to drive improved capital efficiencies
through reduced drilling and infrastructure costs. During the
quarter, Tamarack drilled its first 11 leg, three bench wells,
resulting in a 15% reduction in drilling cost per meter compared to
its conventional drilling design. These wells are currently
cleaning up and an update will be provided with the budget in
December.
Expansion of the West Nipisi and Marten Hills waterflood program
is ongoing with Tamarack currently injecting ~2,000 bbl/d of water
at West Nipisi and observing early signs of response from multiple
waterflood patterns implemented in 2023. The Company plans to drill
four additional injectors by 2023 year-end to ramp water injection
rates to 4,000 bbl/d.
At Marten Hills, Tamarack increased water injection at
15-02-075-25W4 beginning in April
2023 and observed a material subsequent oil response at this
location of ~150 bopd higher than pre-ramp rates. This well has now
produced over 420 mbbls of oil on a cumulative basis, representing
the highest recovery of any Clearwater multi-lateral drilled in the
history of the play. Building on these successful results, Tamarack
plans to convert the offsetting wells to waterflood in Q4/23. In
May 2023, Tamarack converted its
first "W" waterflood pattern to injection at 01-11-074-24W5,
observing recent water injectivity rates over 1,100 bbl/d. Given
the strong positive correlation between injectivity and oil
response across the Clearwater
fairway, the Company sees this as a very promising result as the
program continues to advance.
In the South Clearwater
fairway, the Company has drilled four wells year-to-date utilizing
the fan well design. Two of the four wells have been producing for
over 30 days and the average IP30 is 244 bopd per well. The fan
design drives efficiency through:
- Reduced surface locations and infrastructure requirements,
minimizing the operational footprint and lowering lease
construction costs;
- Improved drilling design with increased efficiency by reducing
turns and required sliding, resulting in lower drilling costs on a
$/metre basis; and
- Improved recovery efficiency with a 25% reduction in wells
required to access the same reserves achieved by previous
conventional design across a four-section land block of land.
Charlie Lake
With the new Wembley gas plant
onstream, Tamarack's Charlie Lake
assets achieved a new record production rate of 16,200
boe/d(10) during the third quarter. The Company was able
to leverage wells drilled in the first half of 2023 to ramp up
plant capacity exiting Q2/23, requiring the drilling of only one
well in Q3/23 while still achieving record quarterly production.
Reflecting continued field development success, the five wells
drilled ahead of commissioning in the Wembley area achieved IP90 rates that averaged
900 boe/d(11) per well. The strongest of these was the
00/12-36-073-08W6/00 well which delivered an IP90 rate of 1,185
boe/d(12). With two rigs currently active, drilling for
the fourth quarter includes a modest four (3.5 net) well program
and is expected to sustain production in the 16,000 – 17,000
boe/d(13) range exiting the year.
Return of Capital
The Company remains committed to balancing long-term sustainable
free funds flow(1) growth with returning capital to
shareholders. The base dividend is currently $0.15/share annually which represents a 3.8%
yield at the current share price. Debt repayment remains the
immediate focus to achieve our enhanced return of capital
thresholds whereby the Company will return from 25% up to 75% of
excess funds flow on a quarterly basis. Tamarack expects to reach
the first enhanced return threshold of the return of capital
framework during the fourth quarter of 2023, reflecting the
positive impact of recent dispositions, strong production and
improved commodity prices. Given current valuations the Company
views share buybacks as the preferred mechanism to enhance overall
shareholder returns at this time.
Risk Management
The Company takes a systematic approach to manage commodity
price risk and volatility to ensure sustaining capital, debt
servicing requirements and the base dividend are protected through
a prudent risk management program. For the remainder of 2023,
approximately 54% of net after royalty oil production is hedged
against WTI with an average floor price of greater than
US$67.50/bbl. For Q1/24,
approximately 53% of net after royalty oil production is hedged
against WTI with an average floor price of greater than
US$68.40/bbl. Our strategy
focuses on downside protection while maintaining upside
opportunity. Tamarack will continue to utilize financial
instruments, including base commodity, associated differentials and
foreign exchange. Additional details of the current hedges in place
can be found in the corporate presentation on the Company website
(www.tamarackvalley.ca) or Tamarack's consolidated financial
statements and related MD&A for the three and nine months ended
September 30, 2023, which will be
available on SEDAR+ (www.sedarplus.ca).
Investor Call
Information October 26, 2023
9:30 AM MDT (11:30
AM EDT)
|
Tamarack will host a
webcast at 9:30 AM MDT (11:30 AM EDT) on Thursday, October 26, 2023
to discuss the
third quarter financial results and an operational update.
Participants can access the live webcast via this link
or
through links provided on the Company's website. A recorded archive
of the webcast will be available on the
Company's website following the live webcast.
|
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company
committed to creating long-term value for its shareholders through
sustainable free funds flow generation, financial stability and the
return of capital. The Company has an extensive inventory of
low-risk, oil development drilling locations focused primarily on
Charlie Lake and Clearwater plays in Alberta while also pursuing EOR upside in
these core areas. Operating as a responsible corporate citizen is a
key focus to ensure we deliver on our environmental, social and
governance (ESG) commitments and goals. For more information,
please visit the Company's website at www.tamarackvalley.ca.
Abbreviations
AECO
|
the natural gas storage
facility located at Suffield, Alberta connected to TC
Energy's Alberta System
|
ARO
|
asset retirement
obligation; may also be referred to as decommissioning
obligation
|
bbls
|
barrels
|
bbl/d
|
barrel per
day
|
boe
|
barrel of oil
equivalent
|
boe/d
|
barrel of oil
equivalent per day
|
bopd
|
barrel of oil per
day
|
GJ
|
gigajoule
|
IFRS
|
International Financial
Reporting Standards as issued by the International
Accounting Standards Board
|
IP30
|
average production for
the first 30 days that a well is onstream
|
IP90
|
average production for
the first 90 days that a well is onstream
|
mcf
|
thousand cubic
feet
|
mcf/d
|
thousand cubic feet per
day
|
MM
|
Million
|
mmcf/d
|
million cubic feet per
day
|
MSW
|
Mixed sweet blend, the
benchmark for conventionally produced light sweet
crude oil in Western Canada
|
NGL
|
Natural gas
liquids
|
WCS
|
Western Canadian
select, the benchmark for conventional and oil sands
heavy production at Hardisty in Western Canada
|
WTI
|
West Texas
Intermediate, the reference price paid in U.S. dollars at
Cushing,
Oklahoma for the crude oil standard grade
|
Reader Advisories
Notes to Press
Release
|
|
1)
|
See "Specified
Financial Measures"
|
2)
|
Q3 2023 production of
68,597 boe/d comprised of 16,974 bbl/d light and medium oil, 35,900
bbl/d heavy oil, 3,623 bbl/d NGL and 72,597 mcf/d natural
gas.
|
3)
|
Capital expenditures
include exploration and development capital, ESG initiatives,
facilities land and seismic but exclude asset acquisitions and
dispositions as well as ARO. Capital budget includes
exploration and development capital, ARO, ESG initiatives,
facilities land and seismic but excludes asset acquisitions and
dispositions. The key difference between these two metrics is the
inclusion (capital budget) or exclusion (capital expenditures) of
ARO.
|
4)
|
Prior guidance Annual
Average Production is comprised of 16,500-17,500 bbl/d light and
medium oil, 34,750-36,500 bbl/d heavy oil, 3,500-4,500 bbl/d NGL
and 71,000-75,000 mcf/d natural gas. Current guidance Annual
Average Production 16,400-16,900 bbl/d light and medium oil,
34,700-36,500 bbl/d heavy oil, 3,230-4,260 bbl/d NGL and
67,000-71,000 mcf/d natural gas.
|
5)
|
Fourth quarter
estimated volumes comprised of 14,000-14,300 bbl/d light and medium
oil, 38,000-38,900 bbl/d heavy oil, 3,000-3,200 bbl/d NGL and
57,000-57,600 mcf/d natural gas.
|
6)
|
Production impacts of
approximately 4,500 boe/d comprised of 1,098 bbl/d light and medium
oil, 922 bbl/d NGL and 14,880 mcf/d natural gas.
|
7)
|
G&A noted excludes
the effect of cash settled stock-based compensation.
|
8)
|
Tax numbers in the
annual guidance numbers are based on 2023 average pricing
assumptions of: US$80.00/bbl WTI; US$22.00/bbl WCS; US$3.00/bbl
MSW; $4.00/GJ AECO; and $1.3200 CAD/USD.
|
9)
|
Q3 2023 Clearwater
production of 37,600 boe/d is comprised of approximately 35,700
bbl/d heavy oil, 186 bbl/d NGL and 10,375 mcf/d natural
gas.
|
10)
|
Q3 2023 Charlie Lake
production of 16,200 boe/d is comprised of approximately 9,270
bbl/d light and medium oil, 1,970 bbl/d NGL and 30,000 mcf/d
natural gas.
|
11)
|
Average of five recent
Charlie Lake wells of 900 boe/d is comprised of approximately 713
bbl/d light and medium oil, 129 bbl/d NGL and 2,075 mcf/d natural
gas.
|
12)
|
12-36-073-08W6 well
IP90 rate of 1,185 boe/d comprised of 710 bbl/d light and medium
oil, 130 bbl/d NGL and 2,075 mcf/d natural gas.
|
13)
|
Charlie Lake rates of
16,000 – 17,000 boe/d for the balance of 2023 comprised of
approximately 9,735 bbl/d light and medium oil, 2,145 bbl/d NGL and
27,720 mcf/d natural gas.
|
Disclosure of Oil and Gas Information
Unit Cost Calculation. For the purpose of calculating
unit costs, natural gas volumes have been converted to a boe using
six thousand cubic feet equal to one barrel unless otherwise
stated. A boe conversion ratio of 6:1 is based upon an energy
equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead.
This conversion conforms with Canadian Securities Administrators'
National Instrument 51 101 - Standards of Disclosure for Oil and
Gas Activities ("NI 51-101"). Boe may be misleading, particularly
if used in isolation.
References in this press release to "crude oil" or "oil" refers
to light, medium and heavy crude oil product types as defined by NI
51-101. References to "NGL" throughout this press release comprise
pentane, butane, propane, and ethane, being all NGL as defined by
NI 51-101. References to "natural gas" throughout this press
release refers to conventional natural gas as defined by NI
51-101.
Forward Looking Information
This press release contains certain forward-looking information
(collectively referred to herein as "forward-looking statements")
within the meaning of applicable Canadian securities laws.
Forward-looking statements are often, but not always, identified by
the use of words such as "guidance", "outlook", "anticipate",
"target", "plan", "continue", "intend", "consider", "estimate",
"expect", "may", "will", "should", "could" or similar words
suggesting future outcomes. More particularly, this press release
contains statements concerning: Tamarack's business strategy,
objectives, strength and focus; the completion of the Disposition;
the anticipated benefits of the Disposition; future consolidation
and disposition activity, organic growth and development and
portfolio rationalization; future intentions with respect to debt
repayment and reduction and return of capital, including enhanced
dividends and share buybacks; oil and natural gas production
levels, adjusted funds flow and free funds flow; anticipated
operational results for the remainder of 2023 including, but not
limited to, estimated or anticipated production levels, capital
expenditures, drilling plans and infrastructure initiatives; the
anticipated benefits of the Company's major infrastructure projects
and the costs and timing thereof, including the Wembley gas plant and gas conservation
investments; the Company's capital program, guidance and budget for
2023 and flexibility with respect thereto; the timing of 2024
guidance; expectations regarding commodity prices; the performance
characteristics of the Company's oil and natural gas properties;
decline rates and enhanced recovery, including waterflood
initiatives; exploration activities; continued integration of the
recently acquired assets; the ability of the Company to achieve
drilling success consistent with management's expectations; risk
management activities, including the Company's hedging management
program; Tamarack's commitment to ESG principles and
sustainability; and the source of funding for the Company's
activities including development costs. Future dividend payments
and share buybacks, if any, and the level thereof, are uncertain,
as the Company's return of capital framework and the funds
available for such activities from time to time is dependent upon,
among other things, free funds 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 Tamarack to
pay dividends and buyback shares 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.
The forward-looking statements contained in this document are
based on certain key expectations and assumptions made by Tamarack,
including those relating to: the business plan of Tamarack; the
satisfaction of all conditions to the completion of the
Disposition; the timing of and success of future drilling,
development and completion activities; the geological
characteristics of Tamarack's properties; the characteristics of
recently acquired assets; the continued integration of recently
acquired assets into Tamarack's operations; prevailing commodity
prices, price volatility, price differentials and the actual prices
received for the Company's products (including expectations
concerning narrowing WCS differentials); the availability and
performance of drilling rigs, facilities, pipelines and other
oilfield services; the timing of past operations and activities in
the planned areas of focus; the drilling, completion and tie-in of
wells being completed as planned; the performance of new and
existing wells; the application of existing drilling and fracturing
techniques; prevailing weather and break-up conditions; royalty
regimes and exchange rates; impact of inflation on costs; the
application of regulatory and licensing requirements; the continued
availability of capital and skilled personnel; the ability to
maintain or grow the banking facilities; the accuracy of Tamarack's
geological interpretation of its drilling and land opportunities,
including the ability of seismic activity to enhance such
interpretation; and Tamarack's ability to execute its plans and
strategies.
Although management considers these assumptions to be reasonable
based on information currently available, undue reliance should not
be placed on the forward-looking statements because Tamarack can
give no assurances that they may prove to be correct. By their very
nature, forward-looking statements are subject to certain risks and
uncertainties (both general and specific) that could cause actual
events or outcomes to differ materially from those anticipated or
implied by such forward-looking statements. These risks and
uncertainties include, but are not limited to: risks with respect
to unplanned third party pipeline outages and risks relating to
inclement and severe weather events and natural disasters, such as
fire, drought and flooding, including in respect of safety, asset
integrity and shutting-in production, maintaining 2023 guidance and
resumption of operations; risks with respect to unplanned
third-party pipeline outages; the risk that future dividend
payments thereunder are reduced, suspended or cancelled; unforeseen
difficulties in integrating of recently acquired assets into
Tamarack's operations,; incorrect assessments of the value of
benefits to be obtained from acquisitions and exploration and
development programs; risks associated with the oil and gas
industry in general (e.g. operational risks in development,
exploration and production; and delays or changes in plans with
respect to exploration or development projects or capital
expenditures); commodity prices; the uncertainty of estimates and
projections relating to production, cash generation, costs and
expenses, including increased operating and capital costs due to
inflationary pressures; volatility in the stock market and
financial system; health, safety, litigation and environmental
risks; access to capital; pandemics; Russia's military actions in Ukraine; and the Israel-Palestinian conflict.
Due to the nature of the oil and natural gas industry, drilling
plans and operational activities may be delayed or modified to
respond to market conditions, results of past operations,
regulatory approvals or availability of services causing results to
be delayed. Please refer to the Company's AIF for the period ended
December 31, 2022 and the MD&A
for the period ended September 30,
2023 for additional risk factors relating to Tamarack, which
can be accessed either on Tamarack's website at
www.tamarackvalley.ca or under the Company's profile on
www.sedarplus.ca.The forward-looking statements contained in this
press release are made as of the date hereof and the Company does
not undertake any obligation to update publicly or to revise any of
the included forward-looking statements, except as required by
applicable law. The forward-looking statements contained herein are
expressly qualified by this cautionary statement.
This press release contains future-oriented financial
information and financial outlook information (collectively,
"FOFI") about generating sustainable long-term growth in
free funds flow, dividends and share buybacks, prospective results
of operations and production, weightings, operating costs, 2023
capital budget and expenditures, decline rates, balance sheet
strength, realized pricing, adjusted funds flow and free funds
flow, net debt, material debt reduction (including achieving the
first net debt threshold of its enhanced return of capital
framework), total returns and components thereof, including pro
forma the completion of the Disposition, all of which are subject
to the same assumptions, risk factors, limitations and
qualifications as set forth in the above paragraphs. FOFI contained
in this document was approved by management as of the date of this
document and was provided for the purpose of providing further
information about Tamarack's future business operations. Tamarack
and its management believe that FOFI has been prepared on a
reasonable basis, reflecting management's best estimates and
judgments, and represent, to the best of management's knowledge and
opinion, the Company's expected course of action. However, because
this information is highly subjective, it should not be relied on
as necessarily indicative of future results. Tamarack disclaims any
intention or obligation to update or revise any FOFI contained in
this document, whether as a result of new information, future
events or otherwise, unless required pursuant to applicable law.
Readers are cautioned that the FOFI contained in this document
should not be used for purposes other than for which it is
disclosed herein. Changes in forecast commodity prices, differences
in the timing of capital expenditures, and variances in average
production estimates can have a significant impact on the key
performance measures included in Tamarack's guidance. The Company's
actual results may differ materially from these estimates.
References in this press release to peak rates, initial
production rates, IP30, IP90 and other short-term production rates
are useful in confirming the presence of hydrocarbons, however such
rates are not determinative of the rates at which such wells will
commence production and decline thereafter and are not indicative
of long-term performance or of ultimate recovery. While
encouraging, readers are cautioned not to place reliance on such
rates in calculating the aggregate production of Tamarack.
Specified Financial Measures
This press release includes various specified financial
measures, including non-IFRS financial measures, non-IFRS financial
ratios, capital management measures and supplemental financial
measures as further described herein. These measures do not have a
standardized meaning prescribed by International Financial
Reporting Standards ("IFRS") and, therefore, may not be comparable
with the calculation of similar measures by other companies.
"Adjusted Funds Flow (Capital Management
Measures)" is calculated by taking cash-flow from
operating activities, on a periodic basis, deducting current income
tax expense and interest expense (excluding fees) and adding back
income tax paid, interest paid, changes in non-cash working
capital, expenditures on decommissioning obligations and
transaction costs settled during the applicable period. since
Tamarack believes the timing of collection, payment or incurrence
of these items is variable. Management believes adjusting for
estimated current income taxes and interest in the period expensed
is a better indication of the adjusted funds generated by the
Company. Expenditures on decommissioning obligations may vary from
period to period depending on capital programs and the maturity of
the Company's operating areas. Expenditures on decommissioning
obligations are managed through the capital budgeting process which
considers available adjusted funds flow. Tamarack uses adjusted
funds flow as a key measure to demonstrate the Company's ability to
generate funds to repay debt, pay dividends and fund future capital
investment. Adjusted funds flow per share is calculated using the
same weighted average basic and diluted shares that are used in
calculating income per share, which results in the measure being
considered a supplemental financial measure. Adjusted funds flow
can also be calculated on a per boe basis, which results in the
measure being considered a supplemental financial measure.
"Free Funds Flow and Capital Expenditures
(Capital Management Measures)" is calculated by taking
adjusted funds flow and subtracting capital expenditures, excluding
acquisitions and dispositions. Capital expenditures is calculated
as property, plant and equipment additions (net of government
assistance) plus exploration and evaluation additions. Management
believes that free funds flow provides a useful measure to
determine Tamarack's ability to improve returns and to manage the
long-term value of the business.
Net Production Expenses, Revenue, net of
blending expense, Operating Netback and Operating Field Netback
(Non-IFRS Financial Measures, and Non-IFRS Financial Ratios if
calculated on a per boe basis) - Management uses certain
industry benchmarks, such as net production expenses, revenue, net
of blending expense, operating netback and operating field netback,
to analyze financial and operating performance. Net production
expenses are determined by deducting processing income primarily
generated by processing third party volumes at processing
facilities where the Company has an ownership interest. Under
IFRS this source of funds is required to be reported as income.
Where the Company has excess capacity at one of its facilities, it
will process third party volumes as a means to reduce the cost of
operating/owning the facility, and as such third-party processing
revenue is netted against production expenses in the MD&A.
Blending expense includes the cost of blending diluent purchased to
reduce the viscosity of our heavy oil transported through pipelines
to meet pipeline specifications. The blending expense represents
the difference between the cost of purchasing and transporting the
diluent and the realized price of the blended product sold. In this
MD&A, blending expense is recognized as a reduction to heavy
oil revenues, whereas blending expense is reported as an expense in
the financial statements. Operating netback equals total petroleum
and natural gas sales (net of blending), including realized gains
and losses on commodity and foreign exchange derivative contracts,
less royalties, net production expenses and transportation expense.
Operating field netback equals total petroleum and natural gas
sales, less royalties, net production expenses and transportation
expense. These metrics can also be calculated on a per boe basis,
which results in them being considered a non-IFRS financial ratio.
Management considers operating netback and operating field netback
important measures to evaluate Tamarack's operational performance,
as it demonstrates field level profitability relative to current
commodity prices.
"Net Debt (Capital Management Measures)"
is calculated as credit facilities plus senior unsecured notes,
plus deferred acquisition payment notes, plus working capital
surplus or deficiency, plus other liability, including the fair
value of cross-currency swaps, plus government loans, plus
facilities acquisition payments, less notes receivable and
excluding the current portion of fair value of financial
instruments, decommissioning obligations, lease liabilities and the
cash award incentive plan liability.
SOURCE Tamarack Valley Energy Ltd.