TSX: TVE
CALGARY, May 9, 2019 /CNW/ - Tamarack Valley Energy
Ltd. ("Tamarack" or the "Company") is pleased to
announce its financial and operating results for the three months
ended March 31, 2019. 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 months
ended March 31, 2019 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.
Q1 2019 Financial and Operating Highlights
- Production averaged 23,149 boe/d (64% oil and NGL weighting),
reflecting the Company's compliance with the production curtailment
order imposed by the Government of Alberta that came into effect on January 1, 2019 ("Curtailment Order"). Tamarack
adjusted the timing of its capital investment and activity in order
to comply with the Curtailment Order and as a result, five wells
were brought on production late in the period and had minimal
contribution to average volumes in the quarter. The Company also
exited Q1/19 with 18 Viking oil wells and two Cardium oil wells
that were drilled awaiting completion. Based on field estimates,
current production is 24,000 boe/d in line with estimated annual
average production between 23,500 boe/d and 24,500 boe/d.
- Total adjusted operating field netback (see "Non-IFRS
Measures") of $57.5 million
($0.25/share basic and diluted) in
Q1/19 was 50% higher than the $38.3
million generated in Q4/18 ($0.17/share basic and diluted).
- Operating netback (see "Non-IFRS Measures") of $30.11/boe in Q1/19 was 58% higher than the Q4/18
netback of $19.03/boe and was equal
to Q1/18 primarily due to the continuation of strong realized
pricing supported by the Company's 64% oil and NGL weighting and a
reduction of operating and transportation expenses.
- Net production and transportation expenses in Q1/19 were 5%
lower at $10.20/boe compared to
$10.76/boe in Q1/18 primarily due to
increased production from the lower-cost Veteran area and a
reduction in transportation expenses as a result of the recently
commissioned pipeline in the Provost area of Alberta (the "Provost Pipeline").
- Invested $71.2 million in the
quarter, with 76% directed to drill, complete and equip 31 (30.2
net) Viking oil wells, 7 (6.1 net) Cardium oil wells and 2.0 net
Penny oil wells. In addition, 19 (18.5 net) Viking oil wells that
were drilled in late Q4/18 were completed and brought on
production. The Company also drilled 18 (17.7 net) Viking oil wells
and 2.0 net Cardium oil wells that will be brought on production in
Q2/19, resulting in the Company being able to increase production
in Q2/19.
- Completed four minor tuck-in acquisitions of assets in Q1/19
totaling $1.1 million and subsequent
to quarter end closed a Viking oil acquisition for $4.7 million in the Veteran/Consort area of
Alberta, adding 130 boe/d and 9.4
net sections of undeveloped Viking land. These lands are adjacent
to existing Tamarack lands.
Financial & Operating Results
|
Three months
ended
|
|
March 31,
|
|
|
2019
|
2018
3
|
%
change
|
($ thousands,
except per share)
|
|
|
|
Total
Revenue
|
95,047
|
98,736
|
(4)
|
Adjusted operating
field netback 1
|
57,503
|
58,545
|
(2)
|
Per share – basic
1
|
$
0.25
|
$ 0.26
|
(4)
|
Per share – diluted
1
|
$
0.25
|
$ 0.25
|
–
|
Net income
(loss)
|
(4,826)
|
3,294
|
(247)
|
Per share –
basic
|
$
(0.02)
|
$ 0.01
|
(300)
|
Per share –
diluted
|
$
(0.02)
|
$ 0.01
|
(300)
|
Net debt
1
|
(219,348)
|
(186,732)
|
17
|
Capital Expenditures
2
|
71,243
|
69,630
|
2
|
Weighted average
shares outstanding (thousands)
|
|
|
|
Basic
|
226,341
|
228,621
|
(1)
|
Diluted
|
226,341
|
231,713
|
(2)
|
Share
Trading (thousands, except share
price)
|
|
|
|
High
|
$
2.96
|
$ 3.09
|
(4)
|
Low
|
$
2.03
|
$ 2.31
|
(12)
|
Trading volume
(thousands)
|
64,864
|
30,945
|
110
|
Average daily
production
|
|
|
|
Light oil
(bbls/d)
|
12,689
|
13,239
|
(4)
|
Heavy oil
(bbls/d)
|
483
|
299
|
62
|
NGL
(bbls/d)
|
1,548
|
1,347
|
15
|
Natural gas
(mcf/d)
|
50,576
|
51,879
|
(3)
|
Total
(boe/d)
|
23,149
|
23,532
|
(2)
|
Average sale
prices
|
|
|
|
Light oil
($/bbl)
|
65.47
|
67.92
|
(4)
|
Heavy oil
($/bbl)
|
40.65
|
45.23
|
(10)
|
NGL ($/bbl)
|
40.85
|
45.14
|
(10)
|
Natural gas
($/mcf)
|
2.82
|
2.25
|
25
|
Total
($/boe)
|
45.62
|
46.62
|
(2)
|
Operating netback
($/Boe) 1
|
|
|
|
Average realized
sales
|
45.62
|
46.62
|
(2)
|
Royalty
expenses
|
(4.86)
|
(5.16)
|
(6)
|
Production
expenses
|
(10.20)
|
(10.76)
|
(5)
|
Operating field
netback ($/Boe) 1
|
30.56
|
30.70
|
-
|
Realized commodity
hedging loss
|
(0.45)
|
(0.59)
|
(24)
|
Operating
netback
|
30.11
|
30.11
|
-
|
Adjusted operating
field netback ($/Boe) 1
|
27.60
|
27.64
|
-
|
|
Notes:
|
(1)
|
Adjusted operating
field netback, net debt, operating field netback and operating
netback do not have any standardized meaning prescribed by IFRS and
therefore may not be comparable with the calculation of similar
measures for other issuers. See "Oil and Gas Metrics" and
"Non-IFRS Measures".
|
(2)
|
Capital expenditures
include exploration and development expenditures, but exclude asset
acquisitions and dispositions.
|
(3)
|
IFRS 16 was adopted
January 1, 2019 using the modified retrospective approach;
therefore, comparative information has not been
restated.
|
First Quarter Review
Tamarack's Q1/19 production of 23,149 boe/d (64% oil and NGL
weighting) was impacted by its required compliance with the
Curtailment Order, which muted the Company's previous growth
trajectory as the timing of capital spending and activity were
adjusted. As a result, three Cardium and two Viking wells were
drilled in the first quarter and subsequently brought on production
late in the quarter resulting in minimal contribution to average
Q1/19 volumes. Based on field estimates, current production is
24,000 boe/d in line with estimated annual average production
between 23,500 boe/d and 24,500 boe/d.
The Company was ahead of internal forecasts for production
during January, but extreme cold weather in February impacted
volumes such that they could not be sufficiently offset by new
wells coming on in late March. The prolonged winter
conditions allowed the Company to accelerate the drilling of second
quarter wells into the first quarter. The Company exited Q1/19 with
18 Viking oil and two Cardium oil wells drilled and awaiting
completion. All 20 wells drilled in the period were
subsequently brought on production in the second quarter, which are
expected to contribute to a ramp up in average production volumes
assisting the Company in achieving its first half average
production rate forecast of between 23,500 boe/d and 23,750 boe/d.
This activity and spending will be assessed regularly in light of
the Curtailment Order and prevailing commodity prices.
Tamarack's oil and NGL weighting remained strong at 64% compared
to 63% in Q1/18 and contributed to an average realized sales price
of $45.62/boe in Q1/19. The 5%
reduction in net production and transportation expenses in Q1/19
which averaged $10.20/boe from
$10.76/boe in Q1/18, was attributable
to higher volumes from Tamarack's lower-cost Veteran area combined
with lower transportation expenses associated with the December
start-up of the Provost Pipeline and the effect of the new lease
accounting standard, IFRS 16, "Leases". These cost reductions
drove an operating netback of $30.11/boe in Q1/19, on par with Q1/18. Even
with the production impacts, Tamarack recorded strong Q1/19 total
adjusted operating field netbacks (see "Non-IFRS Measures") of
$57.5 million ($0.25/share basic and diluted), which was 50%
higher than the previous quarter due to improved oil prices and
narrower differentials coupled with continued cost reductions.
Successful Execution of Strategy
The Company continued to invest in its long-term future with
ongoing expansion of the Veteran waterflood. In 2018, reserves
bookings attributable to waterflood only accounted for 4.9 million
bbls of total proved plus probable reserves, which Tamarack
estimates represents only 5% of the potential risked total
waterflood upside in the area. During the quarter, the Company had
ten active injector wells which increased waterflood injection
volumes from 2,000 bbls/d to 12,000 bbls/d. Another water source
well is expected to be drilled in Q2/19 along with completion of
the remainder of the planned well conversions to injectors.
Tamarack remains committed to enhancing its sustainability and
anticipates positive impacts on decline rates and reserve bookings
will be realized commencing in 2020.
With Q1/19 development capital spending of $71.2 million, the Company drilled, completed and
equipped a total of 31 (30.2 net) Viking oil wells, 7 (6.1
net) Cardium oil wells and 2.0 net Penny oil wells. A further 19
(18.5 net) Viking oil wells that were drilled in late Q4/18 were
completed and brought on production. The Company also drilled 18
(17.7 net) Viking oil wells and 2.0 net Cardium oil wells that will
be brought on production in Q2/19, bringing the total drilling for
the quarter to 49 (47.9 net) Viking oil wells, 9 (8.1 net) net
Cardium oil wells and 2.0 net Penny oil wells. Tamarack
continued to focus on improvements in capital program efficiencies
and drilled the first of its two 3-mile long lateral wells in the
Cardium. In moving to a 3-mile lateral, the Company expects to
capture rate of return increases that are comparable to those
realized when Tamarack increased lateral lengths from 1-mile to
2-miles. In addition to the positive impact of longer
laterals, recently implemented modified well designs in the Cardium
are also expected to improve capital efficiencies.
Further enhancing its existing asset base, Tamarack completed
four minor tuck-in acquisitions in Q1/19 for $1.1 million, and subsequent to quarter end,
closed an additional Viking oil tuck-in acquisition in the
Veteran/Consort area for $4.7
million, adding 130 boe/d and 9.4 net sections of
undeveloped Viking land. These lands are adjacent to existing
Tamarack lands.
During the first four months of 2019, the Company purchased and
cancelled 434,900 outstanding common shares under its normal course
issuer bid (the "NCIB") program, for a total investment of
$1.1 million. The NCIB provides
management a tool that can be employed when there is a perceived
misalignment between the Company's prevailing share price and the
underlying current and future potential value of its assets. In
addition, it helps to offset the dilutive impact that may be
associated with the exercise and settlement of options, restricted
share units and performance share units issued under Tamarack's
stock-based compensation programs. In April
2019, Tamarack received approval from the Toronto Stock
Exchange to renew its NCIB under the same terms.
2019 Outlook
Tamarack's first quarter production and modification to the
timing of bringing wells on production reflects the Company's
compliance with the Curtailment Order. Based on the timing and
allocation of capital through the first half of 2019, Tamarack
anticipates that approximately 65% of its drilling program will
occur in the second half of 2019 with a meaningful ramp-up in
production volumes anticipated during the fourth quarter, subject
to the Curtailment Order being lifted.
Based on current strip prices, the 2019 capital program is
forecast to generate approximately $40
million to $50 million of
adjusted operating field netback (see "Non-IFRS Measures") over and
above budgeted capital expenditures, which can be directed to
further asset enhancements through acquisition or incremental share
buy-backs under its active NCIB program. The Company will
re-evaluate its capital allocation strategy in the second half of
2019 to determine whether changes are required to its original
capital budget of $170 to
$180 million based on the status of
the Curtailment Order and the commodity price outlook. Supported by
success in accumulating an inventory of Viking and Cardium
locations that payout in 1.5 years or less at current commodity
prices, the Company estimates it will achieve a 3% to 5% increase
in debt-adjusted production per share(1) growth (see
"Non-IFRS Measures") in Q4/19 compared to Q4/18.
Tamarack's 2019 budget anticipates drilling 125 net wells,
including Viking wells in Alberta
and Saskatchewan, Cardium oil
wells in Wilson Creek and oil
wells in Penny. In addition, the Company intends to continue
directing capital to activities related to the Veteran waterflood
with $20 million budgeted for 15 well
conversions in the first half of 2019 and the drilling and
conversion of six additional injection wells in Veteran. While
the impact of the waterflood on overall corporate decline rates is
expected to be realized in 2020, programs such as the Veteran
waterflood are key initiatives that serve to enhance Tamarack's
long-term sustainability.
The Company's capital allocation strategy over the past several
years has remained consistent with the objective of achieving
sustainability at low oil prices, while generating debt-adjusted
per share growth. With approximately 30% of its 2019 production
protected with hedges including a US$60.00/bbl WTI put option and another
approximately 3% protected by fixed price contracts at US$64.60/bbl, Tamarack remains well positioned to
withstand further crude oil price volatility.
Subject to the Curtailment Order being lifted by the end of Q3
2019, the Company's 2019 guidance and assumptions are reaffirmed
below.
- Annual average production between 23,500 boe/d and 24,500 boe/d
(64% to 66% oil and NGL), with 2019 exit production estimated
between 25,500 boe/d and 26,500 boe/d (64% and 66% oil and
NGL).
- Capital expenditures between $170
million and $180 million to
comply with the Curtailment Order.
- Estimated year end 2019 net debt to Q4 annualized adjusted
operating field netback ratio (see "Non-IFRS Measures") of
approximately 1.0 times with an estimated $100 million of liquidity on existing credit
facilities.
- Average 2019 commodity price assumptions of WTI US$50.00/bbl, Edmonton Par C$52.33/bbl, WTI / Edmonton Par differential of
US$10.75/bbl, AECO $1.31/GJ and a Canadian/US dollar exchange rate
of $0.75.
__________________________________
|
(1)
|
Debt-adjusted
production per share is a measure of changes in production on a per
share basis, with the number of shares adjusted based on changes to
net debt outstanding for the periods being compared. Debt adjusted
share count is calculated as total shares outstanding plus
incremental shares issued using $2.30 per share to eliminate the
change in net debt or in the case where net debt decreases the
reduction in shares using the same $2.30 per share.
|
Tamarack's strategy remains focused on preserving balance sheet
strength and remaining flexible with capital spending in the face
of continued commodity price and crude oil price differential
volatility.
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company
committed to long-term growth and the identification, evaluation
and operation of resource plays in the Western Canadian Sedimentary
Basin. Tamarack's strategic direction is focused on two key
principles: (i) targeting repeatable and relatively predictable
plays that provide long-life reserves; and (ii) using a rigorous,
proven modeling process to carefully manage risk and identify
opportunities. The Company has an extensive inventory of low-risk,
oil development drilling locations focused primarily in the Cardium
and Viking fairways 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
bbls
|
barrels
|
bbls/d
|
barrels per
day
|
boe
|
barrels of oil
equivalent
|
boe/d
|
barrels of oil
equivalent per day
|
Mboe
|
thousands barrels of
oil equivalent
|
mcf
|
thousand cubic
feet
|
GJ
|
gigajoule
|
MMcf
|
million cubic
feet
|
Mbbls
|
thousand
barrels
|
mcf/d
|
thousand cubic feet
per day
|
WTI
|
West Texas
Intermediate, the reference price paid in U.S. dollars at Cushing,
Oklahoma for the crude oil standard grade
|
AECO
|
the natural gas
storage facility located at Suffield, Alberta connected to
TransCanada's Alberta System
|
IFRS
|
International
Financial Reporting Standards as issued by the International
Accounting Standards Board
|
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 National Instrument 51-101 –
Standards of Disclosure for Oil and Gas Activities. Boe may
be misleading, particularly if used in isolation.
Reserves Disclosure. All reserve references in this
press release are "Company interest reserves". Company interest
reserves are the Company's total working interest reserves before
the deduction of any royalties and including any royalty interests
payable the Company. It should not be assumed that the present
worth of estimated future cash flow presented herein represents the
fair market value of the reserves. There is no assurance that the
forecast prices and costs assumptions will be attained and
variances could be material. The recovery and reserve estimates of
Tamarack's 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.
Oil and Gas Metrics. This press release contains
metrics commonly used in the oil and natural gas industry, such as
operating field netback, operating netback, development capital,
F&D costs, FD&A costs, recycle ratio, reserve life index
and net asset value.
"Operating field netback"
equals total petroleum and natural gas sales less royalties and
operating costs calculated on a boe basis.
"Operating netback" is the
operating field netback with realized gains and losses on commodity
and foreign exchange derivative contracts.
"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 and also includes the cost of acquisitions and
capital associated with acquisitions where reserve additions are
attributed to the acquisitions.
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; operational execution and
the ability of the Company to achieve drilling success consistent
with management's expectations; commodity prices; market conditions
impacting realized prices; the Company's ability to withstand
commodity price volatility; drilling plans including the timing of
drilling; 2019 waterflood projects and the impact thereon on oil
recoveries, corporate decline rates and production rates; the
payout of wells and the timing thereof; expectations regarding
timing of development of current inventory; oil and natural gas
production levels, including annual average production and exit
production in 2019; changes in decline rates and reserve bookings
and the timing realization thereof; oil and liquids weighting and
changes thereto; the 2019 drilling program, capital budget and
guidance, including the Company's expectations to be
self-sustaining in 2019; Tamarack's intent to use excess total
adjusted operating field netback to purchase and cancel shares
under the NCIB or to close additional accretive tuck-in
acquisitions; liquidity on existing credit facilities; shareholder
returns; enhanced per share metrics; the duration and impact of the
Curtailment Order; the Company's compliance with the Curtailment
Order; the Company's expectation that Viking and Cardium oil wells
will be brought on production in Q2/19 and its impact on production
in 2019; estimate of adjusted operating field netback generated
from Tamarack's 2019 capital program; estimates for debt adjusted
production per share in 2019; and the re-evaluation of Tamarack's
capital allocation strategy. 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.
Tamarack remains committed to enhancing its sustainability and
anticipates positive impacts on decline rates and reserve booking
will be realized commencing in 2020.
The forward-looking statements contained in this document are
based on certain key expectations and assumptions made by Tamarack,
including relating to: 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 lifting of the Curtailment Order and the timing
thereof; accumulating an inventory of Viking and Cardium locations
that payout in 1.5 years or less at current commodity prices; 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; and the accuracy of
Tamarack's geological interpretation of its drilling and land
opportunities, including the ability of seismic activity to enhance
such interpretation.
Although management considers these assumptions to be reasonable
based on information currently available, undue reliance should not
be placed on the forward-looking statements because Tamarack can
give no assurances that they may prove to be
correct. By their very nature, forward-looking
statements are subject to certain risks and uncertainties (both
general and specific) that could cause actual events or outcomes to
differ materially from those anticipated or implied by such
forward-looking statements. These risks and uncertainties include,
but are not limited to: risks 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; and
access to capital. 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 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 and the Company's annual
information form ("AIF") for the year ended December 31, 2018.
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,
production, net debt, debt-adjusted production per share, estimated
year end 2019 net debt to Q4 annualized adjusted operating field
netback ratio 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 made 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 financial measures referred to in this press release,
such as net debt, debt-adjusted production per share, adjusted
operating field netbacks and net debt to annualized adjusted
operating field netback ratio, are not prescribed by IFRS. Tamarack
uses these measures to help evaluate its financial and operating
performance as well as its liquidity and leverage. These non-IFRS
financial measures do not have any standardized meaning prescribed
by IFRS and therefore may not be comparable to similar measures
presented by other issuers.
"Net debt" is
calculated as long-term debt plus working capital surplus or
deficit excluding the fair value of financial instruments.
"Debt adjusted production per
share" is a measure of changes in production on a per
share basis, with the number of shares adjusted based on changes to
net debt outstanding for the periods being compared. Debt-adjusted
share count is calculated as total shares outstanding plus
incremental shares issued at a current market price to eliminate
the change in net debt or in the case where debt decreases the
reduction in shares. Management of Tamarack believes that debt
adjusted production per share is useful in determining the
production growth on a per share basis as if changes to debt was
extinguished by the issuance or redemption of shares. The
presentation of production growth on a per share basis is skewed
for oil and gas companies that have more debt on their balance
sheet and in their capital structure. Such companies will show
better results because more of their growth is financed through
debt than equity (as opposed to generating growth through realizing
a rate of return on capital employed). The debt adjusted production
per share measure provides a means of putting oil and gas companies
on an equal, enterprise-based footing with respect to debt when
calculating per share numbers. This measure is relevant to
investors to appreciate the impact the debt on a company's balance
sheet has on per share growth disclosure and the strength of one
company's balance sheet relative to an over-leveraged peer,
particularly in volatile commodity price environments where a
company's indebtedness may increase as a result of lower cash flows
and higher debt financing costs.
"Adjusted operating field
netback" is calculated by taking net income or loss
before taxes and adding back items, including transaction costs,
and certain non-cash items including stock-based compensation;
accretion expense on decommissioning obligations; depletion,
depreciation and amortization; impairment; unrealized gain or loss
on financial instruments; and gain or loss on dispositions.
"Net debt to annualized
adjusted operating field netback ratio" is calculated as
net debt divided by annualized adjusted operating field netback for
the most recent quarter.
"Operating field
netback" is calculated as total petroleum and natural gas
sales, less royalties and net production and transportation
costs.
"Operating netback" is
calculated as total petroleum and natural gas sales, including
realized gains and losses on commodity and foreign exchange
derivative contracts, less royalties and net production and
transportation costs.
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