TSX: TVE
CALGARY, AB, Oct. 27, 2021 /CNW/ - Tamarack Valley Energy
Ltd. ("Tamarack" or the "Company") is pleased to announce its
financial and operating results for the three and nine months ended
September 30, 2021. Selected
financial and operational information is outlined below and should
be read in conjunction with Tamarack's unaudited condensed
consolidated interim financial statements for the three and nine
months ended September 30, 2021 and
related management's discussion and analysis ("MD&A") which are
available on SEDAR at www.sedar.com and on Tamarack's website at
www.tamarackvalley.ca.
Brian Schmidt, President and CEO
of Tamarack commented: "The third quarter was very strong
operationally and included the successful integration of the
Charlie Lake assets into our
portfolio. I am very proud and confident in our team's ability to
execute and drive outperformance in our assets, which is evident
through our production guidance increase for 2021. Tamarack is
pleased to announce its inaugural dividend and return of capital
framework. Our plan to initiate a sustainable base monthly dividend
commencing in January 2022, with the
framework working towards distributing up to 50% of our free funds
flow(1) as we reach our long-term debt target. The
successful repositioning of the Company into the Clearwater and Charlie Lake oil plays, coupled with our
strong portfolio of waterflood assets is expected to generate
sustainable long-term growth in free funds flow(1) and
return of capital to shareholders."
Q3 2021 Financial and Operating Highlights
- Achieved quarterly production volumes of 41,256
boe/d(2) in Q3 2021, representing a 92% increase
compared to the same period in 2020.
- Generated adjusted funds flow(1) of $102.5 million in Q3 2021 ($0.25 per share basic and diluted) compared to
$30.8 million in the same period in
2020 ($0.14 per share basic and
diluted) and $216.2 million for the
nine months ended September 30, 2021
($0.64 per share basic and
$0.63 per share diluted) compared to
$93.9 million in the same period in
2020 ($0.42 per share basic and
diluted).
- Generated free funds flow(1), excluding acquisition
expenditures, of $32.5 million and
net income of $20.0 million during
the quarter.
- Invested $70.0 million in
exploration and development ("E&D") capital expenditures,
excluding acquisitions, during the third quarter of 2021. This
contributed to the drilling of 8 (8.0 net) Clearwater oil wells, 7 (7.0 net) Charlie Lake oil wells and 3 (3.0 net) Viking
oil wells along with the investment in the Nipisi Clearwater gas
gathering project, which currently is conserving 2.0 mmcf/d of
natural gas, and other Clearwater
infrastructure initiatives.
- Exited the third quarter with $519.7
million of net debt(1) with a forecasted 2021
year-end net debt to Q4 annualized adjusted funds
flow(1) of less than 1.2x.
- Successfully executed $42.9
million of further tuck-in acquisitions in the Clearwater oil (previously announced
Southern Clearwater acquisition)
and Charlie Lake light oil plays
which included 53 net sections of land and 63 gross (59.7 net)
future drilling locations(3) in the Clearwater and added 20 gross (12.5 net)
sections in the Charlie Lake.
These acquisitions further our strategy of both adding to and
enhancing the resiliency of our drilling inventory and free funds
flow(1) profile.
2021 Guidance Increase & Preliminary 2022 Capital
Program
Given the strong operational outperformance, Tamarack is pleased
to provide updated production guidance for both the second half and
full year 2021.
- Production Guidance Increase – Second half 2021
production guidance is increased to 40,500 boe/d(4) with
full year production guidance of 34,250 boe/d(4) up from
33,000 boe/d.
- Preliminary 2022 Capital Program – Tamarack plans to
spend $200 to $225 million in 2022 and plans to announce its
comprehensive 2022 budget in January
2022.
Dividend Policy and Return of Capital Framework
Tamarack is pleased to announce the implementation of its
dividend policy and return of capital framework. The free funds
flow(1) return will be achieved through modest,
sustainable base dividend growth, special dividends and tactical
share buybacks.
- Sustainable Base Dividend – Providing shareholders with
a sustainable base monthly dividend which grows in conjunction with
earnings over time is a key focus for the Company. Tamarack will
initiate a base dividend of up to 25% of free funds
flow(1) predicated on the Tamarack five-year plan price
deck of US$55/bbl WTI and
$2.50/GJ AECO. The remainder of free
funds flow(1) will primarily be allocated to net
debt(1) reduction and strategic asset acquisitions in
existing core areas.
- Enhanced Return to Shareholders – Once the Company
reaches its long term $250 to
$300 million net debt(1)
target, Tamarack plans to return up to 50% of the previous
quarter's free funds flow(1) inclusive of base
dividends, taking into consideration market conditions, to its
shareholders through tactical share buybacks and/or special
dividends. The long-term debt target is predicated on a forecasted
year-end net debt to trailing annual adjusted funds
flow(1) of 1.0x at US$45/bbl WTI. The remaining 50% of free funds
flow(1) will be allocated to further debt repayment and
future acquisitions.
Given the continued success of our development program and
strong free funds flow(1) generation, Tamarack
expects the inaugural monthly cash dividend of $0.0083 per share to be payable on February 15, 2022, to holders of common shares
("Common Shares") of the Company of record at the close of business
on January 31, 2022. The base
dividend is modelled to be sustainable down to less than
US$35/bbl WTI and at US$70/bbl WTI would only represent 7% of 2022
adjusted funds flow(1), highlighting the resiliency of
the dividend level. On current strip pricing, the Company looks to
achieve its long-term debt target of $250 to $300
million in the second half of 2022. The base dividend will
be designated as an "eligible dividend" for Canadian federal and
provincial income tax purposes. Dividends paid to shareholders who
are non-residents of Canada will
be subject to Canadian non-resident withholding taxes.
Strategic and opportunistic M&A remains a key focus for
Tamarack in enhancing and growing the sustainable free funds
flow(1) for the Company and shareholders. The Company
will continue to execute potential M&A in a disciplined manner
with a focus on free funds flow breakeven(1) levels and
debt adjusted free funds flow(1) per share accretion
within our five-year plan.
NCIB Application
Tamarack has applied to the TSX for approval of a normal course
issuer bid ("NCIB"). If approved, the NCIB would allow Tamarack to
purchase up to approximately 20,354,360 common shares
(representing approximately 5% of the 407,087,206 outstanding
Common Shares as of October 25, 2021)
over a period of twelve months. The actual number of Common Shares
which may be purchased pursuant to the NCIB would be determined by
management of the Company. Any Common Shares that are purchased
under the NCIB would be cancelled upon their purchase by
Tamarack.
The NCIB would provide an additional tool for the reinvestment
of excess free funds flow(1) to increase long-term total
shareholder returns. Tamarack believes that, at times, the
prevailing share price does not reflect the underlying value of the
Common Shares and the repurchase of Common Shares represents an
opportunity to improve per share metrics. As with all expenditures,
if the NCIB is approved, Tamarack will remain vigilant in ensuring
it retains flexibility and liquidity on its balance sheet.
Operations & Sustainability Update
Tamarack has one rig active in the Charlie Lake with 2 (2.0 net) wells planned to
be drilled during the fourth quarter and has two rigs active in the
Clearwater play (one operated and
one non-operated) with plans for 8 (7.0 net) wells to be drilled.
The Company continues to achieve production rates ahead of our
internal type curves in both the Charlie
Lake and Clearwater oil
plays. Tamarack remains on track with its planned production range
of 12,000-13,000 boe/d(5) for the Charlie Lake asset going forward, with current
production in excess of 13,000 boe/d(5). Total
Clearwater production averaged
5,450 boe/d(6) for the third quarter with current
production of approximately 5,750 boe/d(6). The Company
is also pleased to announce the completion of its Nipisi Clearwater
gas gathering project during the third quarter which is currently
conserving approximately 2.0 mmcf/d of natural gas. In addition,
technical work continues to progress on an initial Clearwater waterflood pilot which is expected
to be initiated in the first quarter of 2022 in West Nipisi.
Tamarack's commitment to progressing our environment, social and
governance ("ESG") initiatives continued during the third quarter
with the commissioning of our Nipisi Clearwater gas conservation
project in addition to furthering our community engagement and
Indigenous partnerships. Tamarack plans to release our 2021
Sustainability Report in November of this year.
Investor Webcast
Tamarack will host a webcast at 9:00 AM
MT (11:00 AM ET) on
October 28, 2021 to discuss the third
quarter financial results and provide an investor 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.
Financial & Operating Results
|
Three months
ended
|
Nine months
ended
|
September
30,
|
September
30,
|
|
2021
|
2020
|
%
change
|
2021
|
2020
|
%
change
|
($ thousands,
except per share)
|
|
|
|
|
|
|
Total oil, NGL,
natural gas and processing revenue
|
212,265
|
57,790
|
267
|
457,867
|
157,200
|
191
|
Cash flow from
operating activities
|
100,558
|
26,965
|
273
|
179,247
|
101,431
|
77
|
Per share –
basic
|
$
0.25
|
$ 0.12
|
108
|
$
0.53
|
$ 0.46
|
15
|
Per share –
diluted
|
$
0.24
|
$ 0.12
|
100
|
$
0.52
|
$ 0.46
|
13
|
Adjusted funds flow
(1)
|
102,486
|
30,837
|
232
|
216,179
|
93,854
|
130
|
Per share – basic
(1)
|
$
0.25
|
$ 0.14
|
79
|
$
0.64
|
$ 0.42
|
52
|
Per share – diluted
(1)
|
$
0.25
|
$ 0.14
|
79
|
$
0.63
|
$ 0.42
|
50
|
Net income
(loss)
|
20,032
|
(5,776)
|
447
|
250,060
|
(293,164)
|
185
|
Per share –
basic
|
$
0.05
|
$ (0.03)
|
267
|
$
0.74
|
$ (1.32)
|
156
|
Per share –
diluted
|
$
0.05
|
$ (0.03)
|
267
|
$
0.73
|
$ (1.32)
|
155
|
Net debt
(1)
|
(519,708)
|
(199,561)
|
160
|
(519,708)
|
(199,561)
|
160
|
Capital expenditures
(7)
|
69,978
|
10,364
|
575
|
149,487
|
90,455
|
65
|
Weighted average
shares outstanding (thousands)
|
|
|
|
|
|
|
Basic
|
406,152
|
221,611
|
83
|
335,913
|
221,610
|
52
|
Diluted
|
414,342
|
221,611
|
87
|
344,072
|
221,610
|
55
|
Share Trading
(thousands, except share price)
|
|
|
|
|
|
|
High
|
$
3.31
|
$ 1.09
|
204
|
$
3.31
|
$ 2.27
|
46
|
Low
|
$
2.05
|
$ 0.70
|
193
|
$
2.05
|
$ 0.39
|
426
|
Trading volume
(thousands)
|
180,490
|
56,013
|
222
|
346,720
|
181,659
|
91
|
Average daily
production
|
|
|
|
|
|
|
Light oil
(bbls/d)
|
19,405
|
10,309
|
88
|
14,720
|
11,424
|
29
|
Heavy oil
(bbls/d)
|
5,438
|
159
|
3,320
|
4,275
|
165
|
2,491
|
NGL
(bbls/d)
|
4,257
|
2,162
|
97
|
3,243
|
1,766
|
84
|
Natural gas
(mcf/d)
|
72,935
|
53,420
|
37
|
62,171
|
51,986
|
20
|
Total
(boe/d)
|
41,256
|
21,533
|
92
|
32,600
|
22,019
|
48
|
Average sale
prices
|
|
|
|
|
|
|
Light oil
($/bbl)
|
79.12
|
46.77
|
69
|
74.43
|
39.58
|
88
|
Heavy oil
($/bbl)
|
67.97
|
38.31
|
77
|
61.40
|
35.27
|
74
|
NGL ($/bbl)
|
33.67
|
23.57
|
43
|
36.37
|
19.29
|
89
|
Natural gas
($/mcf)
|
3.44
|
1.61
|
114
|
3.14
|
1.53
|
105
|
Total
($/boe)
|
55.73
|
29.02
|
92
|
51.27
|
25.97
|
97
|
Operating netback
($/Boe) (1)
|
|
|
|
|
|
|
Average realized
sales
|
55.73
|
29.02
|
92
|
51.27
|
25.97
|
97
|
Royalty
expenses
|
(8.97)
|
(2.87)
|
213
|
(7.51)
|
(2.95)
|
155
|
Net production and
transportation expenses (1)
|
(10.53)
|
(10.64)
|
(1)
|
(10.75)
|
(10.21)
|
5
|
Operating field
netback ($/Boe) (1)
|
36.23
|
15.51
|
134
|
33.01
|
12.81
|
158
|
Realized commodity
hedging gain (loss)
|
(6.21)
|
2.42
|
(357)
|
(5.62)
|
5.28
|
(206)
|
Operating
netback
|
30.02
|
17.93
|
67
|
27.39
|
18.09
|
51
|
Adjusted funds
flow ($/Boe) (1)
|
27.00
|
15.57
|
73
|
24.29
|
15.56
|
56
|
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company
committed to free funds flow generation and financial stability
through the identification, evaluation and operation of resource
plays in the Western Canadian Sedimentary Basin. Tamarack's
strategic direction is focused on three key principles: (i)
targeting repeatable and relatively predictable plays that provide
long-life reserves; (ii) using a rigorous, proven modeling process
to carefully manage risk and identify opportunities; and (iii)
operating as a responsible corporate citizen with a focus on
environmental, social and governance (ESG) commitments and goals.
The Company has an extensive inventory of low-risk, oil development
drilling locations focused primarily on Charlie Lake, Clearwater and EOR plays in Alberta that are economic over a range of oil
and natural gas prices. With this type of portfolio and an
experienced and committed management team, Tamarack intends to
continue delivering on its strategy to maximize shareholder returns
while managing its balance sheet.
Abbreviations
AECO
|
the natural gas
storage facility located at Suffield, Alberta connected to TC
Energy's Alberta System
|
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 and free funds flow breakeven were
previously referred to as free adjusted funds flow and free
adjusted funds flow breakeven, respectively
|
(2)
|
Comprised of 19,405
bbl/d light and medium oil, 5,438 bbl/d heavy oil, 4,257 bbl/d NGL
and 72,935 mcf/d natural gas
|
(3)
|
See "Disclosure of
Oil and Gas Information – Drilling Locations"
|
(4)
|
Comprised of
17,500-18,0000 bbl/d light and medium oil, 6,500-7,000 bbl/d heavy
oil, 4,000-4,200 bbl/d NGL and 69,500-70,500 mcf/d natural gas for
second half and 15,250-15,750 bbl/d light and medium oil,
4,800-5,000 bbl/d heavy oil, 3,300-3,500 bbl/d NGL and
64,000-65,000 mcf/d natural gas for full year
|
(5)
|
Comprised of
6,550-7,200 bbl/d light and medium oil, 1,950-2,000 bbl/d NGL and
21,000-22,800 mcf/d natural gas
|
(6)
|
Comprised of 5,450
bbl/d heavy oil for the third quarter with 5,475-5,525 bbl/d heavy
oil and 15-20 bbl/d NGL and 1,200-1,500 mcf/d natural gas for
current production
|
(7)
|
Capital expenditures
include exploration and development expenditures but exclude asset
acquisitions and dispositions
|
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.
Type Curves. Certain type curves disclosure presented
herein represents estimates of the production decline and ultimate
volumes expected to be recovered from wells over the life of the
well. The type curves represent what management thinks an average
well will achieve, based on methodology that is analogous to wells
with similar geological features. Individual wells may be higher or
lower but over a larger number of wells, management expects the
average to come out to the type curve. Over time type curves can
and will change based on achieving more production history on older
wells or more recent completion information on newer wells.
Additional details on well performance and management's type curves
are available in the presentation on Tamarack's website at
www.tamarackvalley.ca.
Drilling Locations. This press release discloses drilling
locations in three categories: (i) proved locations; (ii) probable
locations; and (iii) unbooked locations. Proved locations and
probable locations are derived from the Company's internal reserves
evaluation as prepared by a member of management who is a qualified
reserves evaluator in accordance with NI 51-101 and the most recent
publication of the most recent publication of the Canadian Oil and
Gas Evaluations Handbook effective October 1, 2021 and account for drilling
locations that have associated proved and/or probable reserves, as
applicable. Unbooked locations are internal estimates based on the
Company's assumptions as to the number of wells that can be drilled
per section based on industry practice and internal review.
Unbooked locations do not have attributed reserves or resources. Of
the total 63 (59.7 net) drilling locations identified herein,
21 (21.0 net) are proved locations, 11 (11.0 net) are
probable locations and 31 (27.7 net) are unbooked locations.
Unbooked locations have been identified by management as an
estimation of Company's multi-year drilling activities based on
evaluation of applicable geologic, seismic, engineering, production
and reserves information. There is no certainty that the Company
will drill all unbooked drilling locations and if drilled there is
no certainty that such locations will result in additional oil and
gas reserves, resources or production. The drilling locations
considered for future development will ultimately depend upon the
availability of capital, regulatory approvals, seasonal
restrictions, oil and natural gas prices, costs, actual drilling
results, additional reservoir information that is obtained and
other factors. While certain of the unbooked drilling locations
have been derisked by the drilling of existing wells in relative
close proximity to such unbooked drilling locations, other unbooked
drilling locations are farther away from existing wells where
management has less information about the characteristics of the
reservoir and therefore there is more uncertainty whether wells
will be drilled in such locations and if drilled there is more
uncertainty that such wells will result in additional oil and gas
reserves, resources or production.
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, including the Company's five year
plan and the anticipated benefits thereof; future consolidation
activity and organic growth; future intentions with respect to
return of capital including dividends and share buybacks; net debt
reduction and debt targets; Tamarack's intention to return free
funds flow to shareholders; the timing and implementation of the
dividend policy; the granting of any special dividends or the
implementation of any share buyback program or other supplements to
the base dividend; statements regarding plans or expectations for
the declaration of future dividends and the amount thereof; oil and
natural gas production levels, decline rates, adjusted funds flow,
free funds flow and net debt to Q4 annualized adjusted funds flow;
anticipated operational results for 2021 including, but not limited
to, estimated or anticipated production levels, capital
expenditures and drilling plans; the Company's revised capital
program, guidance and budget for 2021 and preliminary 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; the source of funding for the Company's activities
including development costs; Without limitation of the foregoing,
future dividend payments, if any, and the level thereof, is
uncertain, as the Company's dividend policy and the funds available
for the payment of dividends from time to time is dependent upon,
among other things, free 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 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 relating to: 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
Tamarack is unable to implement the dividend policy, or that
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; 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 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 Tamarack's five year plan, including generating
sustainable long-term growth in free funds flow, dividends and
share buybacks, prospective results of operations and production,
weightings, operating costs, capital budget and expenditures,
decline rates, profit, operating field netbacks, balance sheet
strength, adjusted funds flow, free funds flow, free funds flow
breakeven, net debt, net debt to Q4 annualized adjusted funds flow,
year-end net debt to trailing annual adjusted funds flow, debt
targets, total returns and components thereof, 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
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", "free funds flow breakeven", "net production and
transportation expenses", "operating field netback", "operating
netback", "net debt", "net debt to Q4 annualized adjusted funds
flow" and "year-end net debt to trailing annualized adjusted funds
flow", 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" 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 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.
"Free funds flow breakeven" (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.
"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.
"Net production and transportation expenses" Net
production expenses are determined by deducting processing income
primarily generated by processing third party volumes at processing
facilities where the Company has an ownership interest. Under IFRS
this source of funds is required to be reported as revenue. Where
the Company has excess capacity at one of its facilities, it will
process third party volumes as a means to reduce the cost of
operating/owning the facility, and as such third-party processing
revenue is netted against production expenses. Transportation
expense are an IFRS measure but are included with net production
expenses for simplicity of presentation. Full details of these
expenses are outlined in the Company's MD&A.
"Operating Field Netback" equals total petroleum and
natural gas sales, less royalties and net production and
transportation expenses.
"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.
"Net Debt to Q4 Annualized Adjusted Funds Flow" is
calculated as net debt divided by the annualized adjusted funds
flow for the most recently completed, or referenced, quarter.
"Year-end Net Debt to Trailing Annual Adjusted Funds
Flow" is calculated as estimated year-end net debt divided by
the estimated adjusted funds flow for the four preceding quarters
at year-end.
Please refer to the MD&A for additional information relating
to Non-IFRS 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