TSX: TVE
CALGARY,
AB, Oct. 27, 2022 /CNW/ - Tamarack Valley
Energy Ltd. ("Tamarack" or the "Company") (TSX: TVE)
is pleased to announce its financial and operating results for the
three and nine months ended September 30,
2022. 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, 2022, which are
available on SEDAR at www.sedar.com and on Tamarack's website at
www.tamarackvalley.ca. The Company is also pleased to provide an
operational update, fourth quarter 2022 guidance incorporating the
acquisition of Deltastream Energy Corporation
("Deltastream") and confirmation of application to renew the
Normal Course Issuer Bid (NCIB) program.
Brian Schmidt, President and CEO
of Tamarack commented: "During the third quarter, we delivered
positive operating and financial results which were bolstered by
the resilient netbacks and full cycle profitability of the
Clearwater and Charlie Lake oil assets. Furthermore, the
acquisition of Deltastream further solidifies Tamarack as the
largest producer in the Clearwater
and builds on our core position and long-life inventory in what is
recognized as the most economic oil play in North America."
Q3 2022 Financial and Operating Highlights
- Generated Q3/22 adjusted funds flow(1) of
$177.8 million ($0.40/share basic and diluted).
- Achieved quarterly average production volumes of 43,476
boe/d(2) in Q3/22.
- Generated free funds flow(1), excluding acquisition
expenditures, of $79.4 million.
- Generated net income of $124.8
million ($0.28/share basic and
diluted) during the quarter.
- Declared dividends of $13.6
million ($0.01 per common
share per month) and, in conjunction with the Deltastream
acquisition, announced an increase to the base dividend of 25% to
$0.15 per common share annually
($0.0125 per month).
- Repurchased 3.1 million common shares under our NCIB for
$12.8 million during the quarter for
a total of 4.4 million shares and $18.6
million in consideration year to date.
- Invested $93.5 million in
exploration and development (E&D) capital expenditures and
$4.7 million on undeveloped land in
the Clearwater and Charlie Lake areas during Q3/22, which
contributed to the drilling of twenty-three (23.0 net) Clearwater oil wells and six (5.4 net)
Charlie Lake oil wells.
- Exited the quarter with $286.8
million of net debt(1), inclusive of current tax
payable, and net debt to Q3/22 annualized adjusted funds
flow(1) of 0.4x.
- Successfully closed the disposition of certain assets in the
Viking CGU for gross consideration of $70
million(3) ($59.5
million net).
- Announced the acquisition of Deltastream during the quarter for
total consideration of $1.425 billion
consisting of 80.0 million shares of Tamarack, $300.0 million of deferred acquisition notes and
$825.0 million in cash. The cash
consideration was financed, in part, through a $100.0 million add-on offering to the Company's
existing 7.25% senior unsecured sustainability linked Notes due
May 2027 and a $137.3 million net equity financing – both of
which closed in September 2022.
Financial & Operating Results
|
Three months
ended
|
Nine months
ended
|
September
30,
|
September
30,
|
|
2022
|
2021
|
%
change
|
2022
|
2021
|
%
change
|
($ thousands,
except per share)
|
|
|
|
|
|
|
Total oil, natural gas
and processing revenue
|
329,304
|
212,265
|
55
|
1,035,394
|
457,867
|
126
|
Cash flow from
operating activities
|
229,927
|
100,558
|
129
|
577,488
|
179,247
|
222
|
Per share –
basic
|
$
0.52
|
$ 0.25
|
108
|
$
1.34
|
$ 0.53
|
153
|
Per share –
diluted
|
$
0.52
|
$ 0.24
|
117
|
$
1.33
|
$ 0.52
|
156
|
Adjusted funds flow
(1)
|
177,834
|
102,486
|
74
|
530,315
|
216,179
|
145
|
Per share –
basic
|
$
0.40
|
$ 0.25
|
60
|
$
1.23
|
$ 0.64
|
92
|
Per share –
diluted
|
$
0.40
|
$ 0.25
|
60
|
$
1.22
|
$ 0.63
|
94
|
Net income
|
124,793
|
20,032
|
523
|
294,757
|
250,060
|
18
|
Per share –
basic
|
$
0.28
|
$ 0.05
|
460
|
$
0.68
|
$ 0.74
|
(8)
|
Per share –
diluted
|
$
0.28
|
$ 0.05
|
460
|
$
0.68
|
$ 0.73
|
(7)
|
Net debt
(1)
|
(286,762)
|
(519,708)
|
(45)
|
(286,762)
|
(519,708)
|
(45)
|
Capital expenditures
(4)
|
98,451
|
69,978
|
41
|
333,301
|
149,487
|
123
|
Weighted average
shares outstanding (thousands)
|
|
|
|
|
|
|
Basic
|
440,388
|
406,152
|
8
|
431,672
|
335,913
|
29
|
Diluted
|
443,351
|
414,342
|
7
|
435,053
|
344,072
|
26
|
Share Trading
(thousands, except share price)
|
|
|
|
|
|
|
High
|
$
4.62
|
$ 3.31
|
40
|
$
6.48
|
$ 3.31
|
96
|
Low
|
$
3.28
|
$ 2.05
|
60
|
$
3.28
|
$ 1.25
|
162
|
Average daily share
trading volume (thousands)
|
3,745
|
2,865
|
31
|
3,890
|
2,753
|
41
|
Average daily
production
|
|
|
|
|
|
|
Light
oil (bbls/d)
|
16,229
|
19,405
|
(16)
|
17,437
|
14,720
|
18
|
Heavy
oil (bbls/d)
|
13,183
|
5,438
|
142
|
10,524
|
4,275
|
146
|
NGL
(bbls/d)
|
3,659
|
4,257
|
(14)
|
3,769
|
3,243
|
16
|
Natural
gas (mcf/d)
|
62,428
|
72,935
|
(14)
|
66,839
|
62,171
|
8
|
Total
(boe/d)
|
43,476
|
41,256
|
5
|
42,870
|
32,600
|
32
|
Average sale
prices
|
|
|
|
|
|
|
Light
oil ($/bbl)
|
111.80
|
79.12
|
41
|
119.53
|
74.43
|
61
|
Heavy
oil ($/bbl)
|
89.30
|
67.97
|
31
|
99.48
|
61.40
|
62
|
NGL
($/bbl)
|
49.18
|
33.67
|
46
|
56.23
|
36.37
|
55
|
Natural
gas ($/mcf)
|
6.27
|
3.44
|
82
|
6.59
|
3.14
|
110
|
Total
($/boe)
|
81.98
|
55.73
|
47
|
88.28
|
51.27
|
72
|
Operating netback
($/Boe)
|
|
|
|
|
|
|
Average
realized sales
|
81.98
|
55.73
|
47
|
88.28
|
51.27
|
72
|
Royalty
expenses
|
(14.06)
|
(8.97)
|
57
|
(16.49)
|
(7.51)
|
120
|
Net
production and transportation expenses
|
(13.12)
|
(10.53)
|
25
|
(12.74)
|
(10.75)
|
19
|
Operating field
netback ($/Boe) (1)
|
54.80
|
36.23
|
51
|
59.05
|
33.01
|
79
|
Realized
commodity hedging loss
|
(2.90)
|
(6.21)
|
(53)
|
(5.46)
|
(5.62)
|
(3)
|
Operating netback
($/Boe) (1)
|
51.90
|
30.02
|
73
|
53.59
|
27.39
|
96
|
Adjusted funds flow
($/Boe) (1)
|
44.46
|
27.00
|
65
|
45.31
|
24.29
|
87
|
|
|
|
|
|
|
|
Operations Update
Deltastream Clearwater Assets
Deltastream Assets – Deltastream rig released 56 (56.0
net) wells year-to-date through the end of Q3 2023: 25 (25.0 net)
in Nipisi; 21 (21.0 net) in Marten Hills; and 10 (10.0 net) in
Canal. Tamarack will continue to operate three rigs on the
Deltastream lands through the end of 2022, focused entirely on the
Marten Hills and Nipisi assets. The Company expects to drill an
additional 22 gross (22.0 net) wells prior to year end. Total
capital of $50.0 million has been
allocated to the Deltastream assets for the fourth quarter, which
will include costs associated with ongoing pipeline, facility and
surface construction projects.
The Marten Hills development program has produced average well
rates in-line with expectations, with ongoing waterflood injection
in the area proceeding in-line with forecasts to date.
Infrastructure improvement and expansion is ongoing with additional
compression capacity being added. In addition, a significant
expansion to the in-field pipeline infrastructure has resulted in
approximately 60% of Marten Hills oil production connected to the
main 11-04 facility, including 5 mmcf/d of conserved natural
gas
In Nipisi, the 14-18-076-06W5, 02-19-076-06W5 and 09-19-076-06W5
pads drilled in H1 2022 are currently producing over 4,000 bopd, on
a combined basis, from 3.25 sections of land. Performance from this
area is ahead of forecast with all 22 wells having been onstream
for more than five months and still averaging ~180 bopd per well.
These results provide confidence that Tamarack's Nipisi waterflood
fairway can be expanded to the east onto the acquired Deltastream
lands. In addition, significant road construction was completed
during Q3 to provide access to approximately 11 sections of high
graded Nipisi inventory for future drilling.
Total production from the Deltastream assets averaged 20,400
boe/d(5) (19,300 bopd) through the first three weeks of
October, with 13,300 boe/d(5) and 5,300
boe/d(5) coming from the Marten Hills and Nipisi areas
respectively. Nipisi has experienced substantial growth in 2022,
from a 2021 exit rate of 240 bopd to over 5,000 bopd oil in early
Q3, reflecting a very active and successful H1 2022 drilling
program.
Clearwater
Peavine/Seal – Tamarack has licensed its first eight leg
multi-lateral well in Peavine. Surface construction is ongoing,
with an estimated spud date in mid-November. At Seal, we are on
track to spud our first three well pad in early December testing
three separate Clearwater
sands.
West Marten Hills Exploration – Tamarack has rig released
four West Marten Hills wells, including a step out well in the
Clearwater A sand. Two of the four wells are on production, with
the Clearwater A sand results exceeding Company expectations at
over 200 bopd, despite being facility constrained while awaiting
completion of construction on the permanent oil facility in this
area which is anticipated to be completed in early November.
Additionally, Tamarack has spud its first of three extended reach
multi-laterals from the 14-07-076-04W5 pad.
West Nipisi – Tamarack's strategy at West Nipisi is
focused on optimizing waterflood development moving forward. The
Company has rig released 15 of 17 wells planned from four different
pad sites, all of which are being developed under Tamarack's Nipisi
Clearwater waterflood configuration. Currently, 14 of the 15 rig
released wells are on production and average initial rates are
exceeding expectations with the new 13-23-076-08W5 six well pad
producing over 2,000 bopd. Injection commenced on three wells
at Tamarack's waterflood pilot in early May, which is currently
producing at 400 bopd, up from initial rates of 300 bopd. Tamarack
has increased its H2 2022 injector drilling program from five wells
to eight, including a trial three leg multi-lateral injector, given
the positive response exhibited to date from the pilot. Currently
three injectors from the 03-23-076-08W5 pad have been rig
released.
Southern
Clearwater – Tamarack continues to actively develop
its Southern Clearwater assets
with two rigs currently operating. Through area consolidation and
development, Southern Clearwater
production has increased from less than 500 bopd in Q4/21 to
current rates of greater than 7,200 bopd. Development has been
highlighted at West Perryvale, where production results have
outperformed the area type curve and further inventory has been
added through continued pool delineation. To date in 2022, 39 wells
have been rig released, with 36 of those wells currently onstream.
The wells currently producing have averaged peak oil rates of
greater than 150 bopd. The Company plans to drill 45 gross (45.0
net) wells in the area in 2022 and execute on operational synergies
on recently acquired production.
Charlie Lake
In the Charlie Lake, Tamarack
has brought 15 of 18 planned wells onstream in 2022 and has
achieved increased well performance by extending the average well
length. During the quarter, the 100/15-24-071-09W6 well achieved an
IP30 of 790 bopd (1,330 boe/d(6)).
During the quarter, the Company experienced downtime associated
with scheduled third-party turnarounds which were included in our
previous H2 2022 guidance, which resulted in a production impact of
approximately 1,500 boe/d(7) for the quarter. Further to
this, turnaround activity extended into early October at one
third-party facility. Production from the area is currently in-line
with the corporate forecast.
Tamarack is continuing to advance plans to construct a new owned
and operated gas plant in the Grande
Prairie area, with engineering, planning and design work
currently underway. Phase 1 of the plant will add approximately
15-20 MMcf/d of gas processing capacity and is forecasted to be
commissioned in the second quarter of 2023.
Veteran/Eyehill Waterfloods
Tamarack has drilled 13 wells in 2022 targeting the Viking (6.0
net) and Sparky (7.0 net) formations at the Veteran and Eyehill
properties, all of which were onstream prior to the end of Q1.
Field-wide production from the Eyehill Sparky assets continued to
grow throughout Q3, demonstrating waterflood response from water
injection which commenced in 2021. September oil production of
~2,300 bopd is tracking ahead of expectations.
Non-Core Viking
Disposition
Tamarack closed the disposition of approximately 2,000
boe/d(8) (~44 % liquids) of non-core Viking production
for total gross proceeds of $70
million(3) in Q3/22. This disposition
is consistent with the Company's portfolio rationalization strategy
which is focused on growing our core areas and long-term
sustainable free funds flow(1) growth.
Updated Deltastream Pro Forma
Q4/2022 Guidance
To reflect the Deltastream acquisition that closed on
October 13, 2022, Tamarack is
providing updated pro forma Q4/22 corporate guidance. The Company
remains focused on capital discipline and sustainable free funds
flow(1) growth. Tamarack expects to release its 2023
full year budget and guidance in early December 2022.
|
Q4 2022
Guidance
|
E&D Capital
Budget(9) ($millions)
|
$125-$135
|
Q4 Average
Production(10) (boe/d)
|
62,000-64,000
|
Expenses:
|
|
Royalty Rate
(%)
|
20–22%
|
Operating
($/boe)
|
$9.50–$10.00
|
Transportation
($/boe)
|
$2.50–$3.00
|
General and
Administrative ($/boe)(11)
|
$1.25–$1.35
|
Return of Capital
Framework
The Company remains committed to balancing long-term sustainable
free funds flow(1) growth with returning capital to
shareholders. As previously disclosed with the Deltastream
acquisition, the Company further refined its return of capital
framework to balance debt repayment, enable future strategic
acquisitions that bolster long-term inventory resiliency and
increase clarity around delivering enhanced returns to shareholders
through opportunistic share buybacks and/or enhanced dividends.
The return of capital framework includes a base dividend, which
is a structural component of the financial framework and is set at
a level equivalent to approximately 25% of corporate free funds
flow(1) at our long-term 5-year plan price deck of
US$55/bbl WTI and $2.50/GJ AECO. The base dividend can be
sustainably covered at bottom cycle pricing of less than
US$40/bbl WTI. In addition to the
base dividend, the Company will direct up to a given percentage of
excess quarterly funds flow(1) to enhanced return as
certain debt thresholds are met, as outlined below.
Base Dividend
As previously announced, the Company will increase the base
dividend by 25% to $0.15/share
annually for the November dividend declaration payable in December.
In total, Tamarack has increased its annual base dividend by 50%
year to date, from $0.10/share to
$0.15/share. The increase in the base
dividend year to date is driven by the enhanced sustainable free
funds flow(1) achieved in conjunction with the success
of the Company's 2022 capital program and strategic Clearwater acquisitions which are accretive to
the 5-year plan at flat pricing of US$55/bbl WTI and $2.50/GJ AECO.
Updated Enhanced Return Framework
In conjunction with the acquisition of Deltastream, Tamarack's
balance sheet will remain a priority. The enhanced return framework
corresponds with specific debt range targets as outlined below:
- Net debt of less than $1.1
billion but greater than $900
million, the Company will target to deliver up to 25% of
excess funds flow from the prior quarter to shareholders through
enhanced dividends and/or tactical share buybacks.
- Net debt of between $500 million
and $900 million, the Company will
target delivery of up to 50% of excess funds flow from the prior
quarter to shareholders.
- Net debt reaches the long-term debt floor of $500 million, representing approximately 1.0x net
debt to quarterly annualized funds flow at US$45/bbl WTI and $2.50/GJ AECO, the Company will target to return
up to 75% of excess funds flow to shareholders.
Any enhanced dividend will be paid to shareholders on a
quarterly basis, one month following the declaration date. Tamarack
looks forward to continuing to deliver on shareholder returns in
2022 with further incremental returns in 2023 based on the current
commodity price outlook.
Tamarack in in the process of applying to the TSX to renew the
NCIB for November 2022 through
October 2023. The Company expects to
receive confirmation and approval of program renewal in early
November 2022.
Risk Management
Consistent with the strategy of protecting the balance sheet,
sustaining capital and base dividend, the Company manages commodity
price risk and volatility through a prudent and systematic hedging
program. Tamarack has approximately 60% of gross oil production
hedged against WTI for the remainder of 2022, through instruments
including swaps, puts and enhanced collars. Tamarack also has
WTI-MSW and WCS differential hedges in place on approximately half
of remaining 2022 production. For 2023, the Company has a
combination of WTI swaps, put floors and enhanced collars on
approximately 50% of first half production. Additional details of
the current hedges in place can be found in the corporate
presentation on the Company website (www.tamarackvalley.ca).
Sustainability
On September 30, 2022, Tamarack
released a report on sustainability performance target progress,
detailing the progress that was made in 2021 on the key performance
indicators outlined in the Company's sustainability linked debt
instruments. A copy of the report can be found on Tamarack's
website. The Company looks forward to sharing more information on
the overall sustainability program in the annual sustainability
report that will be published in early December 2022.
Investor Call
Tomorrow
9:00 AM MDT (11:00
AM EDT)
Tamarack will host a
webcast at 9:00 AM MDT (11:00 AM EDT) on Friday, October 28, 2022
to discuss the third quarter results and operations 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, Clearwater and EOR plays in Alberta. 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
|
bbls/d
|
barrels per
day
|
boe
|
barrels of oil
equivalent
|
boe/d
|
barrels of oil
equivalent per day
|
Bopd
|
barrels of oil per
day
|
CGU
|
cash generating
unit
|
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
|
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
|
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)
|
Comprised of 16,229
bbl/d light and medium oil, 13,183 bbl/d heavy oil, 3,659 bbl/d NGL
and 62,428 mcf/d natural gas
|
(3)
|
Total gross proceeds
are comprised of $50.0 million cash and a $ 20.0 million promissory
note. Net proceeds for the transaction of $59.9 million represent
the $70.0 million total gross proceeds less transaction costs and
net income adjustments back to the effective date of April 1,
2022.
|
(4)
|
Capital expenditures
include exploration and development capital, ARO, ESG initiatives,
facilities, land and seismic but excludes asset acquisitions and
dispositions.
|
(5)
|
Comprised of
approximately: 19,300 bbl/d heavy oil, 75 bbl/d NGL and 6,150 mcf/d
natural gas (total production); 12,400 bbl/d heavy oil, 70 bbl/d
NGL and 5,000 mcf/d natural gas (Marten Hills production); 5,100
bbl/d heavy oil, 10 bbl/d NGL and 1,150 mcf/d natural gas (total
production);
|
(6)
|
Comprised of
approximately 790 bbl/d light and medium oil, 290 bbl/d NGL and
1,500 mcf/d natural gas
|
(7)
|
Comprised of
approximately 850 bbl/d light and medium oil, 350 bbl/d NGL and
1,800 mcf/d natural gas
|
(8)
|
Comprised of
approximately 640 bbl/d light and medium oil, 240 bbl/d NGL and
6,720 mcf/d natural gas
|
(9)
|
Capital E&D budget
includes exploration and development capital, ESG initiatives, and
facilities but excludes asset acquisitions and dispositions, ARO,
land and seismic.
|
(10)
|
Comprised of
17,500-18,000 bbl/d light and medium oil, 30,000-31,000 bbl/d heavy
oil, 3,400-3,600 bbl/d NGL and 67,000-69,000 mcf/d natural
gas
|
(11)
|
Excludes the impact of
transaction costs to G&A in the fourth quarter
|
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.
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; future consolidation activity,
organic growth and development and portfolio rationalization;
future intentions with respect to 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 Q3 2022 including, but not
limited to, estimated or anticipated production levels, capital
expenditures and drilling plans; the Company's capital program,
guidance and budget for Q4 2022 and Q4 2022 capital program; use of
proceeds from the Non-Core Viking disposition; expectations
regarding commodity prices; the performance characteristics of the
Company's oil and natural gas properties; successful integration of
the Deltastream assets; the ability of the Company to achieve
drilling success consistent with management's expectations; risk
management activities, 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
timing of and success of future drilling, development and
completion activities; the geological characteristics of Tamarack's
properties; the characteristics of recently acquired assets,
including the Deltastream assets; the successful 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; 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: 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; health, safety, litigation and
environmental risks; access to capital; the COVID-19 pandemic; and
Russia's military actions in
Ukraine. 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 annual information form for the year ended
December 31, 2021 and the MD&A
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.sedar.com.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, prospective results of operations and production, weightings,
operating costs, Q4 2022 capital budget and expenditures, balance
sheet strength, adjusted funds flow and free funds flow, including
pro forma the acquisition of Deltastream and the Non-Core Viking
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, test rates, IP30
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. The Company cautions that test rates should
be considered to be preliminary. 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 "NGLs"
throughout this press release comprise pentane, butane, propane,
and ethane, being all NGLs 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.
Specified Financial
Measures
This press release includes various specified financial
measures, including non-IFRS financial measures, non-IFRS financial
ratios and capital management 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
measure)" is calculated by taking cash-flow from operating
activities, on a periodic basis, deducting current income taxes and
adding back changes in non-cash working capital, expenditures on
decommissioning obligations and transaction costs since Tamarack
believes the timing of collection, payment or incurrence of these
items is variable. While current income taxes will not be paid
until Q1/23, management believes adjusting for estimated current
income taxes in the period incurred 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 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.
"Free funds flow (capital management
measure)" (previously referred to as "free adjusted
funds flow") is calculated by taking adjusted funds flow and
subtracting capital expenditures, excluding acquisitions and
dispositions. 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.
"Operating field netback (non-IFRS
financial measure or ratio)" is calculated as 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 field netback an
important measure to evaluate Tamarack's operational performance,
as it demonstrates field level profitability relative to current
commodity prices. See the MD&A for a detailed calculation and
reconciliation of operating field netback per boe to the most
directly comparable measure calculated and presented in accordance
with IFRS.
"Operating netback (non-IFRS financial
measure or ratio)" is calculated as total petroleum and natural
gas sales, including realized gains and losses on commodity and
foreign exchange derivative contracts, less royalties, net
production expenses and transportation expense (non-IFRS financial
measure). This metrics can also be calculated on a per boe basis
(non-IFRS financial ratio). Management considers operating netback
an important measure to evaluate Tamarack's operational
performance, as it demonstrates field level profitability relative
to current commodity prices. See the MD&A for a detailed
calculation and reconciliation of operating netback per boe to the
most directly comparable measure calculated and presented in
accordance with IFRS.
"Net debt (capital management
measure)" is calculated as credit facilities plus senior
unsecured notes, plus working capital surplus or deficit, plus
other liability, including the fair value of cross-currency swaps
plus government loans, less notes receivable and excluding the fair
value of financial instruments, decommissioning obligations, lease
liabilities and the cash award incentive plan liability.
"Net debt to annualized adjusted funds flow
(capital management measure)" is calculated as estimated period
end net debt divided by the annualized adjusted funds flow for the
preceding quarter (multiplied by 4 for annualization).
Please refer to the MD&A for additional information relating
to specified financial measures including non-IFRS financial
measures, non-IFRS financial ratios and capital management
measures. The MD&A can be accessed either on Tamarack's website
at www.tamarackvalley.ca or under the Company's profile on
www.sedar.com.
SOURCE Tamarack Valley Energy