TSX: TVE
CALGARY, AB, Jan. 31, 2022 /CNW/ - Tamarack Valley Energy
Ltd. ("Tamarack" or the "Company") is pleased to
announce certain unaudited financial and operating results for the
three months and year ended December 31,
2021 and the results of Tamarack's year end independent oil
and gas reserves evaluation as of December
31, 2021 (the "GLJ Report"), prepared by Tamarack's
independent qualified reserves evaluator, GLJ Ltd. ("GLJ").
Selected reserves information is outlined below. The Company
anticipates announcing its fourth quarter and audited year end 2021
financial results and filing an annual information form ("AIF") for
the year ended December 31, 2021, on
or near March 3, 2022.
Brian Schmidt, President and
Chief Executive Officer of Tamarack commented, "2021 was a
transformational year for Tamarack as we advanced our strategy of
driving long term sustainable free funds flow(1) growth
forward with the repositioning and further consolidation of the
Company in the Charlie Lake and
Clearwater oil plays. These plays
complement our highly economic waterflood assets. Operationally, we
exceeded our full year guidance and successfully integrated the
assets into our portfolio, which is demonstrated in our robust
reserves metrics including our low finding and development
("F&D") costs and strong recycle ratios."
Strong Fourth Quarter and Full Year 2021 Results
The following are unaudited highlights, and all numbers are
approximate. During the quarter and year ended December 31, 2021, Tamarack:
- Achieved fourth quarter average production of 40,384
boe/d(2), driving full year production of approximately
34,562 boe/d(3) which is above our full year guidance
range of 34,250 boe/d(4), despite the extreme cold
weather impacts that hampered December production across the
basin;
- Increased our oil and natural gas liquids ("NGL") weighting to
69% for both the fourth quarter and full year average 2021;
- Executed a capital program of $41.7
million for the fourth quarter and a total of $191.2 million for 2021, which was higher than
our forecast due to the continued consolidation of Clearwater and Charlie Lake land positions through land sales
during the quarter as well as the acceleration of approximately
$9 million of first quarter 2022
capital into fourth quarter 2021 to ensure access to services in a
timely and cost-efficient manner;
- Achieved adjusted funds flow(1) of $124 million for the quarter and $340 million for the year and generated
$82 million and $149 million of free funds flow(1),
excluding acquisitions, for the fourth quarter and full year 2021,
respectively;
- Achieved operating netbacks(1), excluding the
impacts of hedging, of $44.87/boe and
$36.51/boe for the fourth quarter and
full year 2021, respectively;
- Further consolidated our Charlie
Lake position through two tuck-in acquisitions during the
quarter; and
- Exited the quarter with $463.0
million in net debt(1).
2021 Reserve Highlights
Tamarack is pleased to provide select highlights of the
Company's proved developed producing ("PDP"), total proved ("TP")
and total proved plus probable ("TPP") reserves from the GLJ Report
below. Finding, development and acquisition ("FD&A")
costs and F&D costs contained within this press release
include changes in future development capital ("FDC"). In addition
to the summary information disclosed in this press release, more
detailed information regarding Tamarack oil and gas reserves will
be included in the AIF to be filed on SEDAR (www.sedar.com). The
Company's reserves as presented in the GLJ Report do not include
reserves associated with the previously announced planned
acquisition of Crestwynd Exploration Ltd. ("Crestwynd")
given such acquisition has yet to close. The ongoing positive
impact of Tamarack's drilling program combined with Clearwater and Charlie Lake asset acquisitions contributed
significantly to the reserves in 2021, further enhancing the
long-term resiliency and sustainability of free funds
flow(1) for the Company moving forward.
- Relative to year-end 2020, Tamarack increased PDP reserves 39%
to 56.3 MMboe, TP reserves 63% to 104.1 MMboe and TPP reserves 64%
to 181.9 MMboe in 2021.
- Replaced 225% of total 2021 production on a PDP basis, 419% on
a TP basis and 661% on a TPP basis. PDP reserves represent 54% and
31% of TP and TPP reserves, respectively.
- Achieved 2021 PDP F&D costs of $14.38/boe, including changes in FDC, TP F&D
costs of $14.66/boe and TPP F&D
costs of $8.74/boe. These F&D
metrics yielded reserve recycle ratios of 3.1x, 3.1x and 5.1x,
respectively based on a Q4/21 operating netback(1).
Based on a full year 2021 operating netback(1) the PDP,
TP and TPP recycle ratios were 2.5x, 2.5x and 4.2x
respectively.
- Achieved PDP FD&A costs of $32.68/boe including changes in FDC, TP FD&A
costs of $22.79/boe and TPP FD&A
costs of $15.10/boe. The TPP FD&A
recycle ratio was 2.4x based on a full year 2021 corporate
operating field netback(1).
- Before-tax net present value ("NPV") of reserves, discounted at
10% ("NPV10"), was $1.0 billion on a
PDP basis, $1.7 billion on a TP basis
and $3.0 billion on a TPP basis
evaluated using three independent reserve evaluators average
forecast pricing and foreign exchange rates as at January 2022.
2021 Independent Qualified Reserve Evaluation
The following tables highlight the findings of the GLJ Report,
which has been prepared in accordance with definitions, standards
and procedures contained in National Instrument 51-101 –
Standards of Disclosure for Oil and Gas Activities ("NI
51-101") and the most recent publication of the Canadian Oil and
Gas Evaluation Handbook ("COGEH"). All evaluations and summaries of
future net revenue are stated prior to the provision for interest,
debt service charges or general and administrative expenses and
after deduction of royalties, operating costs, estimated well
abandonment and reclamation costs and estimated future capital
expenditures. The information included in the "Net Present Values
of Future Net Revenue Before Income Taxes Discounted" table below
is based on an average of pricing assumptions prepared by the
following three independent external reserves evaluators: GLJ,
Sproule Associates Limited and McDaniel & Associates
Consultants Ltd (the "3-Consultant Average Forecast Pricing"). It
should not be assumed that the estimates of future net revenues
presented in the tables below represent the fair market value of
the reserves. All per share reserves metrics below are based on
basic shares outstanding as of December 31,
2021.
Reserves Snapshot by Category:
|
PDP
|
TP
|
TPP
|
Total Reserves
(mboe)(1)
|
56,290
|
104,133
|
181,932
|
Reserves
Added(2) (mboe)
|
28,398
|
52,908
|
83,375
|
Reserves
Replacement
|
225%
|
419%
|
661%
|
NPV10 Before Tax
($mm)
|
$1,009
|
$1,675
|
$2,953
|
Notes:
|
(1)
|
Total reserves are
Company Gross Reserves which exclude royalty volumes
|
(2)
|
Reserves Added takes
the difference in reserves year-over-year plus the production for
the year
|
Year-Over-Year Reserves Data (Forecast Prices and
Costs)
(mboe)
|
December
31,
2021
(1)
|
December
31,
2020
(1)
|
% Change
|
PDP
|
56,290
|
40,507
|
39%
|
TP
|
104,133
|
63,840
|
63%
|
TPP
|
181,932
|
111,172
|
64%
|
Note:
|
(1)
|
Total reserves are
Company Gross Reserves which exclude royalty volumes
|
FD&A Costs
|
PDP
|
TP
|
TPP
|
FD&A Cost per
boe(1)
|
32.68
|
22.79
|
15.10
|
F&D Cost per
boe(1)
|
14.38
|
14.66
|
8.74
|
Notes:
|
(1)
|
2021; including
changes in FDC
|
Company Reserves Data (Forecast Prices and Costs)
|
|
|
|
|
|
RESERVES
CATEGORY
|
LIGHT &
MEDIUM
CRUDE OIL(1)
|
HEAVY CRUDE
OIL
|
CONVENTIONAL
NATURAL GAS(2)
|
NATURAL GAS
LIQUIDS
|
TOTAL OIL
EQUIVALENT
|
Gross
(Mbbls)
|
Net
(Mbbls)
|
Gross
(Mbbls)
|
Net
(Mbbls)
|
Gross
(Mmcf)
|
Net
(Mmcf)
|
Gross
(Mbbls)
|
Net
(Mbbls)
|
Gross
(Mboe)
|
Net
(Mboe)
|
PROVED:
|
|
|
|
|
|
|
|
|
|
Developed
Producing
|
26,322
|
21,496
|
4,093
|
3,487
|
114,981
|
104,619
|
6,712
|
5,551
|
56,290
|
47,971
|
Developed
Non-Producing
|
1,242
|
1,089
|
0
|
0
|
5,053
|
4,567
|
255
|
200
|
2,339
|
2,051
|
Undeveloped
|
25,690
|
21,568
|
4,188
|
3,765
|
69,461
|
63,461
|
4,049
|
3,385
|
45,504
|
39,295
|
TOTAL
PROVED
|
53,253
|
44,153
|
8,281
|
7,252
|
189,495
|
172,647
|
11,016
|
9,136
|
104,133
|
89,316
|
PROBABLE
|
40,856
|
32,806
|
7,819
|
6,644
|
128,681
|
117,187
|
7,677
|
6,232
|
77,799
|
65,214
|
TOTAL PROVED PLUS
PROBABLE
|
94,110
|
76,960
|
16,100
|
13,896
|
318,177
|
289,833
|
18,692
|
15,369
|
181,932
|
154,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes:
|
(1)
|
Tight oil included in
the light & medium crude oil product type represents less than
5.0% of any reserves category
|
(2)
|
Conventional natural
gas amounts include coal bed methane, in amounts less than 0.3% of
any reserves category
|
(3)
|
Columns may not add
due to rounding
|
Net Present Values of Future Net Revenue before Income Taxes
Discounted at (% per year)
RESERVES
CATEGORY
|
0%
($000s)
|
5%
($000s)
|
10%
($000s)
|
15%
($000s)
|
20%
($000s)
|
Unit Value
Before Income
Tax Discounted
at 10% Per
Year(1)
($/Boe)
|
PROVED:
|
|
|
|
|
|
|
Developed
Producing
|
1,261,988
|
1,121,358
|
1,008,539
|
919,330
|
847,794
|
21.02
|
Developed
Non-Producing
|
58,418
|
48,404
|
40,960
|
35,369
|
31,072
|
19.97
|
Undeveloped
|
1,045,941
|
799,826
|
625,970
|
500,594
|
407,702
|
15.93
|
TOTAL
PROVED
|
2,366,347
|
1,969,587
|
1,675,469
|
1,455,293
|
1,286,568
|
18.76
|
PROBABLE
|
2,344,259
|
1,677,816
|
1,278,008
|
1,019,532
|
841,347
|
19.60
|
TOTAL PROVED PLUS
PROBABLE
|
4,710,606
|
3,647,403
|
2,953,476
|
2,474,825
|
2,127,915
|
19.11
|
Notes:
|
(1)
|
Unit values based on
Company net interest reserves
|
(2)
|
The prices used to
estimate net present values are based on the 3-Consultant Average
Forecast Pricing
|
(3)
|
Columns may not add
due to rounding
|
Reconciliation of Company Gross Reserves Based on Forecast
Prices and Costs
|
MBOE
|
FACTORS
|
TP
|
Probable
|
TPP
|
December 31,
2020
|
63,840
|
47,332
|
111,172
|
Extensions and
Improved Recovery(1)
|
13,969
|
11,440
|
25,409
|
Technical
Revisions
|
(3,638)
|
(11,467)
|
(15,105)
|
Acquisitions
|
40,747
|
30,323
|
71,070
|
Dispositions
|
(550)
|
(217)
|
(767)
|
Economic
Factors
|
2,380
|
389
|
2,768
|
Production
|
(12,615)
|
0
|
(12,615)
|
December 31,
2021
|
104,133
|
77,799
|
181,932
|
Notes:
|
(1)
|
Reserves additions
under Infill Drilling, Improved Recovery and Extensions are
combined and reported as "Extensions and Improved
Recovery"
|
(2)
|
Columns may not add
due to rounding
|
(3)
|
Company Gross
Reserves exclude royalty volumes
|
Future Development Capital Costs
The following is a summary of GLJ's estimated FDC required to
bring TP and TPP undeveloped reserves on production.
FDC(1)
|
|
|
(amounts in
$000s)
|
TP
|
TPP
|
2022
|
161,379
|
190,710
|
2023
|
169,751
|
219,325
|
2024
|
178,018
|
241,292
|
2025 and
Subsequent
|
114,366
|
314,299
|
Total Undiscounted
FDC
|
623,515
|
965,626
|
Total Discounted FDC
at 10% per year
|
518,215
|
773,442
|
Note:
|
(1)
|
FDC as per GLJ Report
based on the 3-Consultant Average Forecast Pricing
|
FD&A
Costs
|
2021
|
Three-Year
Average
|
|
|
|
|
|
(amounts in $000s
except as noted)
|
TP
|
TPP
|
TP
|
TPP
|
FD&A costs,
including FDC(1)(2)
|
|
|
|
|
Exploration and
development capital expenditures (3)(4)
|
191,159
|
191,519
|
157,889
|
157,889
|
Acquisitions, net of
dispositions(5)
|
739,205
|
739,205
|
277,478
|
277,478
|
Total change in
FDC
|
275,464
|
328,268
|
80,643
|
88,475
|
Total FD&A
capital, including change in FDC
|
1,205,828
|
1,258,632
|
516,010
|
523,842
|
|
|
|
|
|
Reserve additions,
including revisions – Mboe
|
12,711
|
13,074
|
8,128
|
5,999
|
Acquisitions, net of
dispositions(5) – Mboe
|
40,197
|
70,302
|
17,854
|
30,609
|
Total FD&A
Reserves
|
52,908
|
83,376
|
25,982
|
36,608
|
|
|
|
|
|
F&D costs,
including FDC - $/boe
|
14.66
|
8.74
|
16.33
|
14.71
|
Acquisition costs,
net of dispositions - $/boe
|
25.36
|
16.28
|
21.47
|
14.23
|
FD&A costs,
including FDC - $/boe
|
22.79
|
15.10
|
19.86
|
14.31
|
Notes:
|
(1)
|
While Nl 51-101
requires that the effects of acquisitions and dispositions be
excluded from the calculation of finding and development costs,
FD&A costs have been presented because acquisitions and
dispositions can have a significant impact on the Company's ongoing
reserve replacement costs and excluding these amounts could result
in an inaccurate portrayal of the Company's cost structure. Finding
and development costs both including and excluding acquisitions and
dispositions have been presented above.
|
(2)
|
The calculation of
FD&A costs incorporates the change in FDC required to bring
proved undeveloped and developed reserves into production. In all
cases, the FD&A number is calculated by dividing the identified
capital expenditures by the applicable reserves additions after
changes in FDC costs.
|
(3)
|
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.
|
(4)
|
The capital
expenditures also exclude capitalized administration
costs.
|
(5)
|
Includes capital
spent in 2021 to develop the assets acquired during
2021.
|
(6)
|
Columns may not add
due to rounding
|
(7)
|
Calculations use
Company Gross Reserves which exclude royalty volumes.
|
Crestwynd Acquisition Update
Further to the Company's previous announcement, Tamarack expects
the previously announced acquisition of Crestwynd to close on or
around February 15, 2022, subject to
certain customary conditions. Tamarack has internally estimated the
effect of the Crestwynd reserves, and has highlighted the following
pro forma reserves and future values for the combined entities as
at December 31, 2021.
Reserves Snapshot Pro Forma the Crestwynd
Acquisition:
|
PDP
|
TP
|
TPP
|
Total Tamarack
Reserves (mboe)(1)
|
56,290
|
104,133
|
181,932
|
Total Crestwynd
Reserves (mboe)(1)(2)
|
1,902
|
6,320
|
9,650
|
Total Pro Forma
Reserves (mboe)(1)(2)
|
58,192
|
110,453
|
191,582
|
Tamarack NPV10 Before
Tax ($mm)
|
$1,009
|
$1,675
|
$2,953
|
Crestwynd NPV10
Before Tax ($mm)(2)
|
$67
|
$149
|
$218
|
Proforma NPV10
Before Tax ($mm)(2)
|
$1,076
|
$1,824
|
$3,171
|
Notes:
|
(1)
|
Total reserves are
Company Gross Reserves which exclude royalty volumes.
|
(2)
|
PDP reserves, TP
reserves, TPP reserves and NPV10 Before Tax in respect of the
Crestwynd assets have been internally estimated by the Company's
internal Qualified Reserve Evaluators ("QRE") and prepared in
accordance with NI 51-101 and COGEH effective as of December 31,
2021, using the 3-Consultant Average Pricing to estimate net
present values. "Internally estimated" means an estimate that is
derived by the Company's internal QRE and prepared in accordance
with NI 51-101 and COGEH.
|
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
|
bbls
|
barrels
|
bbls/d
|
barrels per
day
|
boe
|
barrels of oil
equivalent
|
boe/d
|
barrels of oil
equivalent per day
|
GJ
|
gigajoule
|
IFRS
|
International
Financial Reporting Standards as issued by the International
Accounting Standards Board
|
mcf
|
thousand cubic
feet
|
mcf/d
|
thousand cubic feet
per day
|
mmcf/d
|
million cubic feet
per day
|
MSW
|
Mixed sweet blend,
the benchmark for conventionally produced light sweet crude oil 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 "Non-IFRS
Measures"; free funds flow was previously referred to as free
adjusted funds flow
|
(2)
|
Comprised of 18,487
bbl/d light and medium crude oil, 5,616 bbl/d heavy crude oil,
3,899 bbl/d NGL and 74,297 mcf/d conventional natural
gas.
|
(3)
|
Comprised of 15,670
bbl/d light and medium crude oil, 4,613 bbl/d heavy crude oil,
3,408 bbl/d NGL and 65,226 mcf/d conventional natural
gas.
|
(4)
|
Comprised of
15,250-15,750 bbl/d light and medium crude oil, 4,800-5,000 bbl/d
heavy crude oil, 3,300-3,500 bbl/d NGL and 64,000-65,000 mcf/d
conventional natural gas.
|
Unaudited Financial Information
Certain financial and operating results included in this press
release, including adjusted funds flow, free funds flow, operating
netbacks, capital expenditures and production information, are
based on unaudited estimated results. These estimated results are
subject to change upon completion of the Company's audited
financial statements for the year ended December 31, 2021, and changes could be material.
Tamarack anticipates filing its audited financial statements and
related management's discussion and analysis for the year ended
December 31, 2021 on or near
March 3, 2022.
Disclosure of Oil and Gas Information
AIF. Tamarack's Statement of Reserves Data and Other
Oil and Gas Information on Form 51-101F1 dated effective as at
December 31, 2021, which will include
further disclosure of Tamarack's oil and gas reserves and other oil
and gas information (excluding in respect of the assets to be
acquired pursuant to Tamarack's previously announced acquisition of
Crestwynd) in accordance with NI 51-101 and COGEH forming the
basis of this press release, will be included in the AIF which will
be available on SEDAR at www.sedar.com on or near March 3, 2022.
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 NI 51-101. Boe may be misleading,
particularly if used in isolation.
Reserves and Future Net Revenue Disclosure. All
reserves values, future net revenue and ancillary information
contained in this press release are derived from the GLJ Report
unless otherwise noted. All reserve references in this press
release are "Company gross reserves". Company gross reserves are
the Company's total working interest reserves before the deduction
of any royalties payable by the Company. Estimates of reserves and
future net revenue for individual properties may not reflect the
same level of confidence as estimates of reserves and future net
revenue for all properties, due to the effect of aggregation. There
is no assurance that the forecast price and cost assumptions
applied by GLJ in evaluating Tamarack's reserves or by the QRE in
evaluating Crestwynd's reserves will be attained and variances
could be material. All reserves assigned in the GLJ Report are
located in the Provinces of Alberta and Saskatchewan and presented on a consolidated
basis.
All evaluations and summaries of future net revenue are stated
prior to the provision for interest, debt service charges or
general and administrative expenses and after deduction of
royalties, operating costs, estimated well abandonment and
reclamation costs and estimated future capital expenditures. It
should not be assumed that the estimates of future net revenues
presented in the tables below represent the fair market value of
the reserves. The recovery and reserve estimates of Tamarack's and
Crestwynd's, as applicable, crude oil, natural gas liquids and
natural gas reserves provided herein are estimates only and there
is no guarantee that the estimated reserves will be recovered.
Actual crude oil, natural gas and natural gas liquids reserves may
be greater than or less than the estimates provided herein. There
are numerous uncertainties inherent in estimating quantities of
crude oil, reserves and the future cash flows attributed to such
reserves. The reserve and associated cash flow information set
forth herein are estimates only.
Proved reserves are those reserves that can be estimated with a
high degree of certainty to be recoverable. It is likely that the
actual remaining quantities recovered will exceed the estimated
proved reserves. Probable reserves are those additional reserves
that are less certain to be recovered than proved reserves. It is
equally likely that the actual remaining quantities recovered will
be greater or less than the sum of the estimated proved plus
probable reserves. Proved developed producing reserves are those
reserves that are expected to be recovered from completion
intervals open at the time of the estimate. These reserves may be
currently producing or, if shut-in, they must have previously been
on production, and the date of resumption of production must be
known with reasonable certainty. Undeveloped reserves are those
reserves expected to be recovered from known accumulations where a
significant expenditure (e.g., when compared to the cost of
drilling a well) is required to render them capable of production.
They must fully meet the requirements of the reserves category
(proved, probable, possible) to which they are assigned. Certain
terms used in this press release but not defined are defined in NI
51-101, CSA Staff Notice 51-324 – Revised Glossary to NI 51-101,
Revised Glossary to NI 51-101, Standards of Disclosure
for Oil and Gas Activities ("CSA Staff Notice 51-324")
and/or the COGEH and, unless the context otherwise requires, shall
have the same meanings herein as in NI 51-101, CSA Staff Notice
51-324 and the COGEH, as the case may be.
Oil and Gas Metrics. This press release contains
metrics commonly used in the oil and natural gas industry, such as
development capital, F&D costs, FD&A costs, recycle ratio,
operating netback and reserves replacement.
"Development capital" means
the aggregate exploration and development costs incurred in the
financial year on reserves that are categorized as development.
Development capital presented herein excludes land and capitalized
administration costs but includes the cost of acquisitions and
capital associated with acquisitions where reserve additions are
attributed to the acquisitions.
"Finding and development
costs" or "F&D costs" are calculated as the sum of
field capital plus the change in FDC for the period divided by the
change in reserves that are characterized as development for the
period and "finding, development and acquisition costs" are
calculated as the sum of field capital plus acquisition capital
plus the change in FDC for the period divided by the change in
total reserves, other than from production, for the period. Both
finding and development costs and finding development and
acquisition costs take into account reserves revisions during the
year on a per boe basis. The aggregate of the exploration and
development costs incurred in the financial year and changes during
that year in estimated future development costs generally will not
reflect total finding and development costs related to reserves
additions for that year. Finding and development costs both
including and excluding acquisitions and dispositions have been
presented in this press release because acquisitions and
dispositions can have a significant impact on Tamarack's ongoing
reserves replacements costs and excluding these amounts could
result in an inaccurate portrayal of the Company's cost
structure.
"Finding, development and
acquisition costs" or "FD&A costs" incorporate the
change in FDC required to bring proved undeveloped and developed
reserves into production. In all cases, the FD&A number is
calculated by dividing the identified capital expenditures by the
applicable reserves additions after changes in FDC costs.
"Recycle ratio" is measured
by dividing the operating netback for the applicable period by
F&D cost per boe for the year. The recycle ratio compares
netback from existing reserves to the cost of finding new reserves
and may not accurately indicate the investment success unless the
replacement reserves are of equivalent quality as the produced
reserves.
"Operating Netback" is
calculated as total petroleum and natural gas sales, including
realized gains and losses on commodity, interest rate and foreign
exchange derivative contracts, less royalties and net production
and transportation costs.
"Reserves replacement" is
calculated as reserves in the referenced category divided by
estimated referenced production.
These terms have been calculated by management and do not have a
standardized meaning and may not be comparable to similar measures
presented by other companies, and therefore should not be used to
make such comparisons. Management uses these oil and gas metrics
for its own performance measurements and to provide shareholders
with measures to compare Tamarack's operations over time. Readers
are cautioned that the information provided by these metrics, or
that can be derived from the metrics presented in this press
release, should not be relied upon for investment or other
purposes.
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 acquisition of Crestwynd (the
"Acquisition") and the timing thereof; future consolidation
activity and organic growth; future intentions with respect to
return of capital; oil and natural gas production levels, decline
rates, adjusted funds flow, free funds flow; anticipated
operational results for 2022 including, but not limited to,
estimated or anticipated production levels, capital expenditures
and drilling plans; expectations regarding commodity prices; the
performance characteristics of the Company's oil and natural gas
properties; the ability of the Company to achieve drilling success
consistent with management's expectations; the source of funding
for the Company's activities including development costs.
Statements relating to "reserves" are also deemed to be
forward-looking statements, 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.
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,
Crestwynd and the assets to be acquired pursuant to the
Acquisition; the receipt of all approvals and satisfaction of all
conditions to the completion of the Acquisition; 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 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; 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 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 (including the Acquisition); 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; health, safety, litigation and environmental
risks; access to capital; and the COVID-19 pandemic. Due to the
nature of the oil and natural gas industry, drilling plans and
operational activities may be delayed or modified to react 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, 2020, the management's
discussion and analysis for the period ended September 30, 2021 (the "MD&A") and
other continuous disclosure documents 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 Tamarack's prospective results of operations and
funds from operations, 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.
Non-IFRS Measures
Certain measures commonly used in the oil and natural gas
industry referred to herein, including, "adjusted funds flow",
"free funds flow", "operating netback" and "net debt", do not have
a standardized meaning prescribed by IFRS and therefore may not be
comparable with the calculation of similar measures by other
companies. These non-IFRS measures are further described and
defined below. Such non-IFRS measures are not intended to represent
operating profits nor should they be viewed as an alternative to
cash flow provided by operating activities, net earnings or other
measures of financial performance calculated in accordance with
IFRS.
"Adjusted funds
flow" is calculated by taking cash-flow from operating
activities and adding back changes in non-cash working capital and
expenditures on decommissioning obligations and corporate
transaction costs since Tamarack believes the timing of collection,
payment or incurrence of these items is variable. 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 loss per
share.
"Free funds flow"
(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.
A reconciliation of adjusted funds
flow to the most directly comparable measure calculated and
presented in accordance with IFRS and a subsequent reconciliation
of such adjusted funds flow to free funds flow is as follows:
(C$ thousands,
unless otherwise noted)
|
Three months
ended
December 31, 2021
(unaudited)
|
Twelve months
ended
December 31, 2021
(unaudited)
|
Cash flow from
operating activities
|
118,647
|
297,894
|
Abandonment
expenditures
|
1,574
|
4,466
|
Transaction
costs
|
-
|
8,110
|
Changes in non-cash
working capital
|
3,859
|
29,789
|
Adjusted funds
flow
|
124,080
|
340,259
|
Less: capital
expenditures
|
41,672
|
191,159
|
Free Funds
Flow
|
82,408
|
149,100
|
"Operating Netback" is calculated as total petroleum
and natural gas sales, including realized gains and losses on
commodity, interest rate and foreign exchange derivative contracts,
less royalties and net production and transportation costs.
"Operating Field Netback" is calculated as total petroleum
and natural gas sales, including interest rate and foreign exchange
derivative contracts, less royalties and net production and
transportation costs. A reconciliation of operating netback and
operating field netback per boe to the most directly comparable
measure calculated and presented in accordance with IFRS is as
follows:
|
Three months
ended
December 31, 2021
|
Three months
ended
December 31, 2021
|
($/boe)
|
|
|
Average realized
sales
|
65.21
|
55.38
|
Royalty
expenses
|
(9.50)
|
(8.10)
|
Net production
expenses
|
(9.16)
|
(9.15)
|
Transportation
expense
|
(1.68)
|
(1.62)
|
Operating field
netback
|
44.87
|
36.51
|
Realized commodity
hedging gain (loss)
|
(8.25)
|
(6.40)
|
Operating
netback
|
36.62
|
30.11
|
"Net debt" is calculated as bank debt plus working
capital surplus or deficit, including the fair value of
cross-currency swaps and excluding the fair value of financial
instruments and lease liabilities. The following outlines the
Company's calculation of net debt:
(C$ thousands, unless
otherwise noted)
|
Three months
ended
December 31, 2021
(unaudited)
|
Accounts payable and
accrued liabilities
|
72,188
|
Cross currency swap
liability
|
292
|
Accounts
receivable
|
(78,804)
|
Prepaid expenses and
deposits
|
(7,829)
|
Working capital
deficiency (surplus)
|
(14,153)
|
Bank debt
|
477,437
|
Net
debt
|
463,284
|
SOURCE Tamarack Valley Energy