TSX: TVE
CALGARY, AB, March 3, 2022 /CNW/ - Tamarack Valley Energy Ltd.
("Tamarack" or the "Company") (TSX: TVE) is pleased
to announce its audited financial and operating results for the
three months and year ended December 31,
2021. Selected financial and operating information is
outlined below and should be read with Tamarack's audited annual
consolidated financial statements and related management's
discussion and analysis for the three and twelve months ended
December 31, 2021, which are
available on SEDAR at www.sedar.com and on Tamarack's website at
www.tamarackvalley.ca. The Company's annual information form
("AIF") for the year ended December 31,
2021 will be filed on SEDAR today and will also be available
on Tamarack's website.
Brian Schmidt, President and CEO
of Tamarack commented: "2021 was a transformational year for
Tamarack with the successful repositioning and integration of
approximately $0.7 billion of
strategic acquisitions in the Clearwater and Charlie Lake oil plays, further enhancing
sustainable free funds flow(1) growth and return of
capital to shareholders. Operationally we exceeded our full year
guidance and maintained a strong balance sheet, exiting the year at
less than one times net debt to Q4/21 annualized adjusted funds
flow(1) while transitioning to a Sustainability Linked
borrowing structure on our credit facility further demonstrating
our commitment to responsible development."
2021 Financial and Operating Highlights
- Tamarack closed three separate acquisitions to further
consolidate the Company's position in the Clearwater oil play in 2021, along with the
acquisition of Crestwynd Exploration which closed February 15th, 2022, growing our land
position in excess of 445 net sections in Nipisi, West Marten Hills
and Southern Clearwater.
- Announced the transformational entrance into the Charlie Lake light oil play with the
acquisition of Anegada Oil Corp. which closed on June 1st, which in combination with
further tuck-ins across 2021, has established a significant
footprint with approximately 325 net sections at year end
2021.
- Achieved fourth quarter and annual production of 40,384
boe/d(2) and 34,562 boe/d(3) respectively,
representing an 83% and 57% increase compared to the same periods
in 2020.
- Generated adjusted funds flow(1) of $124.1 million in Q4/21 ($0.31 per share basic and $0.30 per share diluted) and $340.3 million for the year ($0.96 per share basic and $0.94 per share diluted) compared to $28.9 million ($0.13 per share basic and diluted) and
$122.7 million ($0.55 per share basic and diluted) for the same
period in 2020.
- Generated free funds flow(1), excluding acquisition
expenditures, of $82.4 million and
net income of $140.4 million during
the quarter and $149.1 million and
$390.5 million for free funds
flow(1) and net income on the year, respectively.
- Invested $41.7 million and
$191.2 million in exploration and
development expenditures ("E&D"), excluding acquisitions,
during Q4/21 and full year 2021, respectively, which contributed to
drilling 106 (101.8 net) wells, comprised of 43 (40.0 net)
Clearwater oil wells, 40 (40.0
net) Viking oil wells, 13 (13.0 net) Charlie Lake oil wells, two (0.8 net) Fahler
gas wells and eight (8.0 net) water source wells during the
year.
- Enhanced our financial strength through 2021, exiting the year
with net debt(1) of $463.3
million and a net debt to Q4/21 annualized adjusted funds
flow(1) ratio of 0.9x.
- Transitioned to a Sustainability Linked Loan on our
$600 million credit facility that
incorporates sustainability-linked incentive pricing terms related
to emissions, decommissioning management and Indigenous workforce
participation performance targets.
Financial & Operating Results
|
|
|
|
Three months
ended
|
Twelve months
ended
|
December
31,
|
December
31,
|
|
2021
|
2020
|
%
change
|
2021
|
2020
|
%
change
|
($ thousands,
except per share)
|
|
|
|
|
|
|
Total oil, natural
gas and processing revenue
|
243,184
|
64,873
|
275
|
701,051
|
222,073
|
216
|
Cash flow from
operating activities
|
118,647
|
23,859
|
397
|
297,894
|
125,290
|
138
|
Per share –
basic
|
$
0.29
|
$ 0.11
|
164
|
$
0.84
|
$ 0.56
|
50
|
Per share –
diluted
|
$
0.29
|
$ 0.11
|
164
|
$
0.83
|
$ 0.56
|
48
|
Adjusted funds
flow(1)
|
124,080
|
28,894
|
329
|
340,259
|
122,748
|
177
|
Per share –
basic(1)
|
$
0.31
|
$ 0.13
|
138
|
$
0.96
|
$ 0.55
|
75
|
Per share –
diluted(1)
|
$
0.30
|
$ 0.13
|
131
|
$
0.94
|
$ 0.55
|
71
|
Net income
(loss)
|
140,448
|
(18,220)
|
871
|
390,508
|
(311,384)
|
225
|
Per share –
basic
|
$
0.35
|
$ (0.08)
|
538
|
$
1.10
|
$ (1.40)
|
179
|
Per share –
diluted
|
$
0.34
|
$ (0.08)
|
525
|
$
1.08
|
$ (1.40)
|
177
|
Net
debt(1)
|
(463,284)
|
(219,311)
|
111
|
(463,284)
|
(219,311)
|
111
|
Capital
expenditures(4)
|
41,672
|
13,088
|
218
|
191,159
|
103,543
|
85
|
Weighted average
shares
outstanding(thousands)
|
|
|
|
|
|
|
Basic
|
406,061
|
226,213
|
80
|
353,642
|
222,781
|
59
|
Diluted
|
413,944
|
226,213
|
83
|
360,779
|
222,781
|
62
|
Share Trading
(thousands, except
share price)
|
|
|
|
|
|
|
High
|
$
3.95
|
$ 1.41
|
180
|
$
3.95
|
$ 2.27
|
74
|
Low
|
$
3.08
|
$ 0.69
|
346
|
$
1.25
|
$ 0.39
|
221
|
Trading volume
(thousands)
|
207,256
|
78,236
|
165
|
724,784
|
259,895
|
179
|
Average daily
production
|
|
|
|
|
|
|
Light oil
(bbls/d)
|
18,487
|
10,353
|
79
|
15,670
|
11,155
|
40
|
Heavy oil
(bbls/d)
|
5,616
|
319
|
1,661
|
4,613
|
204
|
2,161
|
NGL
(bbls/d)
|
3,899
|
2,421
|
61
|
3,408
|
1,930
|
77
|
Natural gas
(mcf/d)
|
74,291
|
53,738
|
38
|
65,226
|
52,426
|
24
|
Total
(boe/d)
|
40,384
|
22,049
|
83
|
34,562
|
22,027
|
57
|
Average sale
prices
|
|
|
|
|
|
|
Light oil
($/bbl)
|
88.59
|
47.63
|
86
|
78.64
|
41.46
|
90
|
Heavy oil
($/bbl)
|
71.69
|
43.12
|
66
|
64.56
|
38.36
|
68
|
NGL ($/bbl)
|
55.09
|
24.40
|
126
|
41.77
|
20.90
|
100
|
Natural gas
($/mcf)
|
5.09
|
2.46
|
107
|
3.70
|
1.77
|
109
|
Total
($/boe)
|
65.21
|
31.67
|
106
|
55.38
|
27.40
|
102
|
Operating netback
($/Boe)(1)
|
|
|
|
|
|
|
Average realized
sales
|
65.21
|
31.67
|
106
|
55.38
|
27.40
|
102
|
Royalty
expenses
|
(9.50)
|
(3.31)
|
187
|
(8.10)
|
(3.04)
|
166
|
Net production and
transportation expenses
|
(10.84)
|
(11.71)
|
(7)
|
(10.77)
|
(10.59)
|
2
|
Operating field
netback ($/Boe)(1)
|
44.87
|
16.65
|
169
|
36.51
|
13.77
|
165
|
Realized commodity
hedging gain (loss)
|
(8.25)
|
0.52
|
(1,687)
|
(6.40)
|
4.09
|
(256)
|
Operating
netback
|
36.62
|
17.17
|
113
|
30.11
|
17.86
|
69
|
Adjusted funds
flow ($/Boe)(1)
|
33.40
|
14.24
|
135
|
26.97
|
15.23
|
77
|
Risk Management
The Company continues to manage commodity price risk and
volatility through a prudent hedging management program, with
approximately 50% of gross oil production hedged against WTI on
average for the remainder of 2022, through instruments including
puts and enhanced collars. Tamarack also has WTI-MSW and WCS
differential hedges in place on approximately 46% of our production
in 2022. For 2023, we have entered into WTI put floors and enhanced
collars as we systematically roll our risk management program
forward on approximately 10% of our first quarter production. Our
strategy provides protection to the downside exposure while
maximizing upside. Additional details of the current hedges in
place can be found in the corporate presentation on the Company
website (www.tamarackvalley.ca).
Return of Capital
In accordance with the Company's dividend program, monthly
dividends of $0.0083/share were
declared in January and February
2022. At current strip prices, Tamarack anticipates reaching
the debt target of $325-375 million
mid-year 2022, enabling the declaration of an enhanced dividend
and/or share buybacks.
Operations Update
Clearwater
Peavine Metis Settlement Strategic Land Agreement –
Tamarack has entered into a strategic partnership with the Peavine
Metis Settlement in the High
Prairie area that covers 29.5 sections of land, which are
prospective for the Clearwater
formation. These lands offset competitor appraisal wells that have
illustrated the potential of the play in the area. Tamarack is
committed to building and maintaining strong partnerships with the
Metis community, and we look forward to creating opportunity for
economic participation and inclusion through the development of the
resource with the Peavine Metis Settlement. Tamarack plans to begin
its appraisal program in 2022.
West Marten Hills Exploration – The West Marten Hills
02/8-33-075-3W5 well was drilled with eight one-mile laterals in
the Clearwater F sand. On its initial 15 days of production, post
load recovery, it has averaged approximately 175 bbl/d of 19-degree
API heavy oil. This well, alongside competitor activity, de-risks a
significant portion of the Company's West Marten Hills lands. The
Company plans to drill an additional eight wells at West Marten
Hills in 2022.
West Nipisi – Tamarack has brought on two wells in
West Nipisi as part of the waterflood program, each producing
approximately 320 bbl/d of 19-degree API heavy oil over the last 30
days. Tamarack is drilling three injectors (injection to commence
Q2/22), with an additional twelve wells planned under its 2022
Clearwater waterflood configuration.
Southern
Clearwater – Tamarack is active in the Jarvie, Perryvale and Meanook areas of the
Southern Clearwater with four rigs
currently running. Six well have been rig released to date, with
eight wells expected to be on-stream by the end of the first
quarter. The Company plans to drill forty-seven wells in the area
in 2022.
Charlie Lake
Tamarack continues to delineate lands in the Pipestone area, bringing on four net wells
since December 2021 with results
exceeding expectations. The 13-12-073-10W6 well initiated
production with a light oil rate of approximately 1,400 bbl/d
(~1,700 boe/d(5)). Development drilling at Wembley continues to deliver rates exceeding
internal budget type curves with the most recent 5-30-073-07W6 well
averaging 918 bbl/d of light oil (1,428 boe/d(6)) in the
first eighteen days of production. Tamarack is also drilling its
first Upper Charlie Lake well in the Saddle Hills area, with
production expected in the second quarter.
Waterflood
Tamarack has drilled twenty-one net wells through its winter
program targeting the Viking (14.0 net) and Sparky (7.0 net) at its
Veteran and Eyehill properties. Current waterflood production
continues to perform as expected, averaging ~ 5,000 bopd.
Environmental, Social and Governance
Phase one of the Nipisi gas conservation project was brought
on-line in October of 2021, capturing approximately 2 mmcf/d of
natural gas. Phase two of the project, which is anticipated to
conserve an additional 1 mmcf/d of natural gas is scheduled to be
operational by the end of the second quarter.
2022 Outlook(7)
Our 2022 guidance remains unchanged as Tamarack targets
production of 45,000 to 46,000 boe/d(8) capital
expenditures of $250 to $270 million(8), with the exception of
interest expense which has changed slightly as a result of the
sustainability linked notes issued in February 2022. Based on the forward strip, the
Company expects to generate over $480
million of before tax free funds flow(1) in 2022
($410 million after tax).
|
|
Capital Budget
(including ARO)(9) ($mm)
|
$250–$270
|
Annual Average
Production(8) (boe/d)
|
45,000–46,000
|
Expenses:
|
|
Royalty Rate
(%)
|
16%–17%
|
Operating
($/boe)
|
$8.50–$8.70
|
Transportation
($/boe)
|
$2.00–$2.10
|
General and
Administrative ($/boe)
|
$1.30–$1.35
|
Interest(10) ($/boe)
|
$1.60–$1.65
|
Taxes
($/boe)
|
$1.60–$1.70
|
Leasing Expenditures
($mm)
|
$3.7
|
Asset Retirement
Obligations ($mm)
|
$7.5
|
Revenue:
|
|
Average Oil &
Natural Gas Liquids Weighting
|
74%
|
Light Oil Wellhead
Differential
|
$3.00-$3.50
|
Heavy Oil Wellhead
Differential
|
$4.50-$5.00
|
Sustaining FFF
Breakeven(1) (WTI US$/bbl)
|
~$35.00
|
2022 Adjusted
Funds Flow(1) Sensitivities
|
|
Increase in
Adjusted Funds Flow(1) ($mm)
|
Increase of $1.00 WTI
($US/bbl)
|
$11
|
Decrease of $1.00 MSW
($US/bbl)
|
$4
|
Decrease of $1.00 WCS
($US/bbl)
|
$4
|
Increase of $0.25
AECO ($CAD/GJ)
|
$3
|
Investor Webcast
Tamarack will host a webcast at 9:00 AM
MT (11:00 AM ET) on
March 4, 2022 to discuss the fourth
quarter and year end 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.
We would like to thank our employees, shareholders and other
stakeholders for all of their support over the past year and look
forward to continuing to develop our high-quality assets to create
shareholder value in a sustainable and responsible way.
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 "Specified
Financial Measures"; free funds flow (FFF) and free funds flow
breakeven were previously referred to as free adjusted funds flow
and free adjusted funds flow breakeven, respectively
|
(2)
|
Comprised of 18,487
bbl/d light and medium oil, 5,616 bbl/d heavy oil, 3,899 NGL and
74,291 mcf/d natural gas
|
(3)
|
Comprised of 15,670
bbl/d light and medium oil, 4,613 bbl/d heavy oil, 3,408 NGL and
65,226 mcf/d natural gas
|
(4)
|
Capital expenditures
include exploration and development capital, ARO, ESG initiatives,
facilities land and seismic but excludes asset acquisitions and
dispositions
|
(5)
|
Comprised of 1,400
bbl/d light and medium oil, 30 bbl/d NGL and 1,620 mcf/d natural
gas
|
(6)
|
Comprised of
approximately 918 bbl/d light medium oil, 50 bbl/d NGL and 2,760
mcf/d natural gas
|
(7)
|
Pro forma the closing
of the Acquisition of Crestwynd on February 15, 2022, with pricing
assumptions of: 88.74 USD/bbl WTI; 4.18 CAD/GJ AECO; 1.266 CAD/USD;
2.67 USD/bbl MSW; and 12.40 USD/bbl WCS.
|
(8)
|
Comprised of
16,750-17,250 bbl/d light and medium oil, 13,000-13,250 bbl/d heavy
oil, 3,750-4,000 bbl/d NGL and 69,000-71,000 mcf/d natural
gas
|
(9)
|
Capital budget
includes exploration and development capital, ARO, ESG initiatives,
facilities land and seismic but excludes asset acquisitions and
dispositions
|
(10)
|
Includes the impact
of the $200 million in sustainability linked notes issued February
10, 2022
|
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 and
organic growth; future intentions with respect to return of
capital; oil and natural gas production levels, 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; the Company's
capital program, guidance and budget for 2022 and 2022 capital
program; 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; Tamarack's commitment to ESG
principles and sustainability; and the source of funding for the
Company's activities including development costs.
The forward-looking statements contained in this document are
based on certain key expectations and assumptions made by Tamarack,
including 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; 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 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; 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 AIF 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, 2022 capital budget and expenditures, balance
sheet strength, adjusted funds flow, free funds flow, free funds
flow breakeven, 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 initial 15 days of
production 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 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 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. 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 (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.
"Free funds flow breakeven
(non-IFRS financial measure)" (previously referred to as "free
adjusted funds flow breakeven") is determined by calculating the
minimum WTI price in US/bbl required to generate free funds
flow equal to zero sustaining current production levels and all
other variables held constant. Management believes that free funds
flow breakeven provides a useful measure to establish corporate
financial sustainability.
"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. 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. 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.
"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 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
netback per boe to the most directly comparable measure calculated
and presented in accordance with IFRS.
"Net debt (capital management
measure)" is calculated as bank debt plus working capital
surplus or deficit, plus other liability, including the fair value
of cross-currency swaps and excluding the fair value of financial
instruments and lease liabilities.
"Year-end Net Debt to
Annualized Adjusted Funds Flow (capital management measure)" is
calculated as estimated year-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