TSX: TVE
CALGARY, Nov. 7, 2018 /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, 2018. Selected
financial and operational information is outlined below and should
be read in conjunction with Tamarack's unaudited condensed
consolidated interim financial statements ("Financial Statements")
for the three and nine months ended September 30, 2018 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.
Tamarack posted another strong quarter in Q3/18 marked by record
production, strong capital efficiencies and an increase in free
cash flow generation. The Company remains on track to meet
2018 forecast annual production guidance of 24,000 to 24,500 boe/d
(64 to 66% oil and natural gas liquids ("NGL")) with Q4/18 exit
production guidance of 24,500 to 25,000 boe/d (65 to 67% oil and
NGL). Recently, Canadian oil price differentials have increased
causing significantly lower realized prices across the Western
Canadian Sedimentary Basin than many had anticipated.
Although the current wide Canadian oil differential is anticipated
to be temporary, Tamarack will remain committed to long-term value
creation and balance sheet preservation, and as such, may elect to
defer bringing new production on stream through the end of the year
and into Q1/19 if pricing remains deeply discounted. Tamarack
will delay formalizing its 2019 capital budget until January of
2019, leaving previously communicated preliminary guidance
unchanged.
Q3 2018 Financial and Operating Highlights
- Achieved record corporate production in Q3/18 of 24,765 boe/d,
an increase of 4% over Q2/18 volumes of 23,853 boe/d and an
increase of 21% from Q3/17 volumes of 20,541 boe/d.
- Oil and NGL weighting was 66% in Q3/18 compared to 63% in Q2/18
and 59% in Q3/17. The 12% increase from Q3/17 positively
contributed to the Company's stronger netbacks year-over-year.
- Total adjusted operating field netbacks (previously referred to
as "adjusted funds flow"; see "Non-IFRS Measures") increased 97% to
$68.6 million in Q3/18 ($0.30 per share basic and $0.29 per share diluted), from $34.8 million in Q3/17 ($0.15 per share basic and diluted).
- Operating netbacks (excluding the effects of hedging) increased
by 94% to $36.61/boe in Q3/18 from
$18.84/boe in Q3/17 primarily due to
the 47% increase in the combined average realized prices for oil
and NGL, the 12% increase in oil and NGL weighting and the 8%
decrease in net production and transportation expenses.
- Net production and transportation expenses were 8% lower in
Q3/18 at $10.38/boe compared to
$11.26/boe in Q3/17.
- Maintained financial flexibility with net debt to annualized
Q3/18 adjusted operating field netback ratio of 0.7 times at the
end of Q3/18, compared to 1.4 times at the end of Q3/17, with a
draw of $169 million on the Company's
$290 million revolving credit
facility (the "Facility").
- Invested $78.1 million in Q3/18
capital expenditures directed to drilling 43 (42.4 net) Viking oil
wells, three (1.8 net) Cardium oil wells, three (3.0 net) Penny oil
wells and four (4.0 net) Redwater
oil wells plus one vertical stratigraphic exploratory well.
- Reduced share dilution by purchasing and cancelling 2.1 million
outstanding common shares at a total cost of $9.4 million under the Company's normal course
issuer bid (the "NCIB"), helping to offset the impact of option
issuances on share capital. In addition, Tamarack spent
$4.0 million to purchase 970,000
outstanding common shares in order to settle future restricted
share unit ("RSU") exercises.
Financial & Operating Results
|
|
Three months
ended
|
Nine months
ended
|
September
30,
|
September
30,
|
|
2018
|
2017
|
%
change
|
2018
|
2017
|
%
change
|
($ thousands,
except per share)
|
|
|
|
|
|
|
Total
Revenue
|
119,304
|
64,483
|
85
|
325,961
|
194,208
|
68
|
Adjusted operating
field netback 1
|
68,579
|
34,774
|
97
|
188,129
|
100,800
|
87
|
Per share – basic
1
|
$
0.30
|
$ 0.15
|
100
|
$
0.83
|
$ 0.45
|
84
|
Per share – diluted
1
|
$
0.29
|
$ 0.15
|
93
|
$
0.81
|
$ 0.45
|
80
|
Net income
(loss)
|
13,004
|
(6,742)
|
(293)
|
19,358
|
(1,399)
|
(1,484)
|
Per share –
basic
|
$
0.06
|
$ (0.03)
|
(300)
|
$
0.08
|
$ (0.01)
|
(900)
|
Per share –
diluted
|
$
0.06
|
$ (0.03)
|
(300)
|
$
0.08
|
$ (0.01)
|
(900)
|
Net debt
1
|
(192,184)
|
(194,917)
|
(1)
|
(192,184)
|
(194,917)
|
(1)
|
Capital Expenditures
2
|
78,149
|
74,063
|
6
|
200,453
|
156,786
|
28
|
Weighted average
shares outstanding (thousands)
|
|
|
|
|
|
|
Basic
|
227,031
|
227,691
|
–
|
227,891
|
224,376
|
2
|
Diluted
|
233,203
|
227,691
|
2
|
233,215
|
224,376
|
4
|
Share Trading
(thousands, except share price)
|
|
|
|
|
|
|
High
|
$
5.16
|
$ 2.88
|
79
|
$
5.16
|
$ 3.59
|
44
|
Low
|
$
4.34
|
$ 1.98
|
119
|
$
2.31
|
$ 1.96
|
18
|
Trading volume
(thousands)
|
77,479
|
25,281
|
206
|
196,506
|
161,588
|
22
|
Average daily
production
|
|
|
|
|
|
|
Light oil
(bbl/d)
|
14,417
|
10,108
|
43
|
13,636
|
9,168
|
49
|
Heavy oil
(bbl/d)
|
621
|
603
|
3
|
484
|
514
|
(6)
|
NGL (bbl/d)
|
1,403
|
1,499
|
(6)
|
1,369
|
1,576
|
(13)
|
Natural gas
(mcf/d)
|
49,943
|
49,987
|
–
|
51,393
|
47,860
|
7
|
Total
(boe/d)
|
24,765
|
20,541
|
21
|
24,055
|
19,235
|
25
|
Average sale
prices
|
|
|
|
|
|
|
Light oil
($/bbl)
|
76.98
|
53.43
|
44
|
73.76
|
56.89
|
30
|
Heavy oil
($/bbl)
|
69.33
|
46.26
|
50
|
64.29
|
45.03
|
43
|
NGL ($/bbl)
|
43.64
|
30.76
|
42
|
44.88
|
28.74
|
56
|
Natural gas
($/mcf)
|
1.63
|
1.62
|
1
|
1.84
|
2.48
|
(26)
|
Total
($/boe)
|
52.29
|
33.83
|
55
|
49.60
|
36.85
|
35
|
Operating netback
($/Boe) 1
|
|
|
|
|
|
|
Average realized
sales
|
52.29
|
33.83
|
55
|
49.60
|
36.85
|
35
|
Royalty
expenses
|
(5.30)
|
(3.73)
|
42
|
(5.18)
|
(3.94)
|
31
|
Production
expenses
|
(10.38)
|
(11.26)
|
(8)
|
(10.53)
|
(11.51)
|
(9)
|
Operating field
netback ($/Boe) 1
|
36.61
|
18.84
|
94
|
33.89
|
21.40
|
58
|
Realized
commodity hedging gain (loss)
|
(4.16)
|
2.11
|
(297)
|
(2.75)
|
0.46
|
(698)
|
Operating
netback
|
32.45
|
20.95
|
55
|
31.14
|
21.86
|
42
|
Adjusted operating
field netback ($/Boe) 1
|
30.10
|
18.39
|
64
|
28.65
|
19.19
|
49
|
|
|
|
|
|
|
|
Notes:
|
|
(1)
|
Adjusted operating
field netback, net debt, operating netback and operating field
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 excludes
asset acquisitions and dispositions.
|
Record Q3/18 Production & Improved Netbacks
Tamarack posted stronger revenue quarter-over-quarter, primarily
due to improved production volumes, oil and NGL weighting and
wellhead pricing for crude oil and NGL. WTI oil prices
averaged US$69.54/bbl in Q3/18 and
were 2% higher than the US$67.88/bbl
average in Q2/18. Although WTI prices improved and the
Canadian dollar remained weak through the summer, the Q3/18
Edmonton Par index averaged $77.26/bbl, 2% lower than the Q2/18 average of
$78.90/bbl. Continued issues
related to market oversupply and restrictions on Canadian
infrastructure caused the WTI/Edmonton Par light oil differential
to widen during Q3/18, averaging US$6.82/bbl compared to US$5.46/bbl in Q2/18. Even with the
decrease in the Edmonton Par index, Tamarack's Q3/18 realized light
oil price increased 2% to $76.98/bbl
from $75.29/bbl in the previous
quarter, due to the increased proportion of production represented
by high-quality Viking light oil and the positive impact of the
physical WTI/Edmonton Par differential hedge. For the
remainder of 2018, Tamarack has a light oil WTI/Edmonton Par
physical hedge of 1,500 bbl/d fixed at US$5.50/bbl.
Tamarack achieved record production volumes in Q3/18 of 24,765
boe/d, exceeding the upper end of the Company's annual average 2018
guidance range of 24,000 to 24,500 boe/d, with an oil and NGL
production weighting of 66% also at the upper end of the 64 to 66%
guidance range.
Revenue for Q3/18 was 86% higher than in Q3/17 and 10% higher
than Q2/18, primarily due to higher production volumes and liquids
content combined with stronger realized oil and NGL prices.
Tamarack's Q3/18 operating netback, excluding hedging, was 94%
higher than Q3/17 at $36.61/boe,
attributable to increased production volumes and higher oil and NGL
weighting year-over-year, as well as lower costs for production and
transportation. The higher production volumes in Q3/18 contributed
to reduced production and transportation expenses, which averaged
$10.38/boe (1% lower than Q2/18 and
8% lower than Q3/17). The Company expects production and
transportation expenses to average between $10.30/boe and $10.40/boe in Q4/18 and remains committed to
improving operational efficiencies and cost savings.
Continued Operational Execution Drives Record
Quarter
The third quarter of 2018 represents another period of
exceptional operational execution and financial performance for
Tamarack. With its high-quality, light oil-weighted asset
base and strong capital efficiencies, the Company strives to
deliver free cash flow and growth.
Building on the momentum from a short spring breakup, Tamarack
successfully executed its summer 2018 capital program through
Q3/18. A total of $78.1 million was
allocated to drill, complete and tie-in activities during Q3/18,
funded partially by the $68.6 million
of adjusted operating field netback generated during the period and
the remaining $9.6 million from an
increase in net debt and stock option proceeds. To date in
2018, Tamarack has demonstrated exceptional operational efficiency.
This has led the Company to accelerate capital for the last
two quarters in order to benefit from the economies of scale
offered by executing a larger program. As previously announced,
approximately $28 million of 2019
capital will be accelerated into Q4/18, as the Company is ahead of
its original drilling schedule. Approximately half of the
accelerated capital will be directed to the planned Veteran
waterflood projects, with the other half directed to initiate the
Company's Q1/19 drilling program in Q4/18, which includes
de-risking lands to the west, east and south of Veteran that were
originally targeted for delineation in early 2019. Several of these
wells will validate the extension of the resource base in three
directions from the existing Veteran Unit potentially adding years
of production growth both with primary and waterflood recovery.
Tamarack has invested a total of $200.5
million ($198.2 million
including acquisitions, net of dispositions) year-to-date in 2018
and remains on track to spend $230 to
$235 million, in line with the
originally planned $195 to
$205 million capital budget in
addition to the $28 million of
accelerated capital.
During Q3/18, the Company drilled, completed and equipped 25
(24.6 net) Viking oil wells, three (1.8 net) Cardium oil wells, two
(2.0 net) Penny oil wells and four (4.0 net) Redwater oil wells plus one vertical
stratigraphic exploratory well. In addition, Tamarack
completed and brought on production 18 (17.8 net) Viking oil wells,
six (6.0 net) Cardium oil wells, and one (1.0 net) Penny oil well
that were drilled in late Q2/18. During Q3/18, the Company
also drilled 18 (17.8 net) Viking oil wells and one (1.0 net) Penny
oil well that will be brought on production in the fourth quarter
of 2018, resulting in total drilling for the quarter of 43 (42.4
net) Viking oil wells, three (1.8 net) Cardium oil wells, three
(3.0 net) Penny oil wells and four (4.0 net) Redwater oil wells plus one vertical
stratigraphic exploratory well.
Tamarack continued to direct capital to the ongoing development
of its waterflood program at Veteran. Of the 43 Viking oil
wells drilled in the quarter, nine wells were drilled as future
injection wells, which will produce to recover capital costs until
the commencement of the injection project in the first half of
2019. The Company also invested in the pipeline and facility
infrastructure that will be required to operate the waterflood,
with installation expected to continue through the end of 2018 and
into early 2019. The waterflood project is designed to improve oil
recoveries, reduce corporate decline rates and increase production
rates while utilizing existing Tamarack-owned infrastructure.
These supplementary projects are subject to the same rate of
return thresholds as those used for development drilling when
competing for capital.
Preserving Per Share Value
Tamarack continues to remain focused on creating per share value
for all shareholders, including through its active NCIB program.
Year-to-date, the Company has spent $9.4
million to purchase and cancel 2.1 million common
shares. 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 potential for dilutive impact that may be associated
with the exercise and settlement of options issued under Tamarack's
stock-based compensation program.
In addition to the NCIB, the Company purchased 970,000
outstanding common shares in the open market for a total cost of
$4.0 million in the first nine months
of 2018. These shares are held by Tamarack's trustee.
As needed, the Company can 'draw down' from the remaining balance
of purchased common shares to settle future RSU exercises and
further control dilution by eliminating the need to issue new
shares for the settlement of RSUs. At September 30, 2018, the Company had a remaining
balance of 445,516 such common shares.
Outlook
With continued commodity price volatility impacting the Canadian
oil and gas industry, Tamarack's strategy remains focused on
disciplined capital allocation and preserving balance sheet
strength. This approach enables the Company to take advantage
of potential accretive opportunities that may arise within its core
areas.
Through the first nine months of 2018, the Company has
clearly demonstrated the strength of its strategy and the value in
focusing on drilling opportunities that offer a pay back in 1.5
years or less. Tamarack has continued to outperform through
Q3/18, driven by strong drilling results, higher than expected
production volumes, lower operating costs and stronger oil prices.
For the balance of 2018, Tamarack anticipates spending
approximately $30-35 million of its
remaining capital budget to complete the 18 Viking wells drilled
late in Q3/18, continue installation of the pipeline to handle
water injection for the Veteran waterflood in early 2019 and to
drill 16 Viking wells in Veteran that are expected to be completed
in Q1/19. Average annual production for 2018 remains on
target to meet previous guidance of 24,000 to 24,500 boe/d (64 to
66% oil and NGL) with forecast Q4/18 exit production on track to
deliver 24,500 to 25,000 boe/d (65 to 67% oil and NGL).
Since the end of Q3/18, the WTI/Edmonton Par light oil
differential has severely widened due to ongoing market oversupply
and Canadian infrastructure restrictions. Recently, continued
pricing pressures led to Canadian light oil differentials reaching
unprecedented levels that have exceeded US$30/bbl, driving further underperformance of
the Edmonton Par price relative to WTI. While the duration
and magnitude of these extreme price conditions are difficult to
predict, Tamarack is committed to conservatively planning around
future oil prices and continues to explore ways to mitigate and
manage market risk. As a result of the Company's ongoing
commitment to maintaining a strong balance sheet with significant
financial flexibility, Tamarack is well positioned to endure oil
price and differential volatility. However, should the
current pricing environment continue through the balance of Q4/18
and Q1/19, adjusted operating field netbacks will be negatively
impacted.
The Company has historically demonstrated prudence in capital
allocation decisions during volatile commodity price environments
and will continue to closely monitor current and future commodity
prices and price differentials. Given the current lack of
visibility on timing for differentials to improve, Tamarack
anticipates formalizing its 2019 capital expenditure budget in
early 2019 and in order to preserve value, may elect to defer some
Q1/19 projects, including bringing new production on-stream, until
the current wide differentials have abated.
As previously announced, Tamarack was added to the TSX Composite
Index and its sub-indices as of September
24, 2018. Tamarack was the only energy company added
to the index during this most recent rebalancing period,
demonstrating the Company's growth and successful execution over
the past several years. Tamarack anticipates the inclusion
may bring positive benefits such as attracting new incremental
buyers and attracting future capital for the Company.
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 – targeting repeatable and relatively predictable plays
that provide long-life reserves, and 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
bbl
|
barrels
|
bbl/d
|
barrels per
day
|
boe
|
barrels of oil
equivalent
|
boe/d
|
barrels of oil
equivalent per day
|
mcf
|
thousand cubic
feet
|
GJ
|
gigajoule
|
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
|
Oil and Gas Advisories
Unit Cost Calculation. For the purpose of
calculating unit costs, natural gas volumes have been converted to
a barrel of oil equivalent 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. Boe may be
misleading, particularly if used in isolation.
Oil and Gas Metrics. This press release contains metrics
commonly used in the oil and natural gas industry, such as
operating field netback and operating netback.
"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
derivative contracts on a boe basis.
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",
"target", "plan", "continue", "intend", "ongoing", "estimate",
"expect", "may", "should", "will" or similar words suggesting
future outcomes. More particularly, this press release
contains statements concerning: Tamarack's business strategy,
objectives, strength and focus; market conditions impacting
realized prices; the ability of the Company to achieve drilling
success consistent with management's expectations; drilling
plans including the timing of drilling; share buy-backs for
cancellation under the NCIB and RSU settlements; debt repayment;
continuing to support operating netbacks by mitigating exposure to
weaker gas prices and focusing on drilling opportunities where the
oil and NGL weighting is higher; Tamarack's intent to generate free
cash flow and growth; forecast 2018 annual production range and
liquid weighting percentage; the preliminary 2019 budget; release
of the formal 2019 budget and the timing thereof; oil and natural
gas production levels; the availability and use of the Facility;
timing and level of 2018 and 2019 capital expenditures and
accelerations thereto; 2018 annual and exit production guidance;
2018 waterflood projects, drilling program and pipeline
installation; the inclusion on the TSX Composite Index and the
impact thereof; and shareholder returns. The forward-looking
statements contained in this document are based on certain key
expectations and assumptions made by Tamarack relating to
prevailing commodity prices, price volatility, price differentials
and the actual prices received for the Company's products, the
availability of drilling rigs and other oilfield services, the cost
of such 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, 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. Although management
considers these assumptions to be reasonable based on information
currently available to it, 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 (e.g. operational
risks in development, exploration and production; 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 Tamarack's annual
information form for the year ended December
31, 2017 (the "AIF") and the MD&A for additional risk
factors relating to Tamarack. The AIF and the MD&A can be
accessed either on Tamarack's website at www.tamarackvalley.ca
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,
production, net debt, cash flow, net debt to adjusted operating
field netback ratio, adjusted operating field netback, operating
netbacks, operating costs, capital expenditures and components
thereof, all of which are subject to the same assumptions, risk
factors, limitations and qualifications as set forth in the above
paragraphs and the assumption outlined in the Non-IFRS Measures
section below. FOFI contained in this press release was made as of
the date of this press release and was provided for the purpose of
providing further information about Tamarack's anticipated future
business operations. Tamarack disclaims any intention or obligation
to update or revise any FOFI contained in this press release,
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 press release 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, net debt to annualized adjusted operating field
netback, cash flow, adjusted operating field netbacks and net debt
to 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 adjusted for
risk management contracts.
"Total adjusted operating field
netback" is calculated as net income or loss before taxes and
adding back items including: transaction costs; and deducting
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.
"Cash flow" is determined as gross
oil, natural gas and natural gas liquids revenues including
realized gains on commodity risk management contracts, less the
following: royalties, operating costs, transportation costs,
general and administrative costs and interest expense.
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