TSX: TVE
CALGARY, AB, July 27, 2021 /CNW/ - Tamarack Valley Energy
Ltd. ("Tamarack" or the "Company") is pleased to announce its
financial and operating results for the three and six months ended
June 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 six months ended
June 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: "We are proud to report another very strong
quarter driven by the successful integration of Anegada Oil Corp.
("Anegada") along with the continued execution of our Clearwater and Waterflood operations. The
Anegada acquisition complements our balanced asset portfolio and
provides further upside and resiliency to our free adjusted funds
flow(1) and potential return of capital profile. In
addition, we remain focused on advancing the 2021 initiatives and
targets set within our robust environmental, social and governance
("ESG") reporting."
Q2 2021 Financial and Operating Highlights
- Successfully closed the acquisition of Anegada on June 1, 2021, providing the Company an entrance
into the Charlie Lake light oil
play ("Charlie Lake"), one of the most profitable oil plays in
North America.
- The Company's syndicate of lenders increased the Company's
credit facilities to $600 million and
extended the revolving period to May 31,
2022.
- Achieved quarterly production volumes of 32,416
boe/d(2) in Q2/21, representing a 54% increase compared
to the same period in 2020.
- Generated adjusted funds flow(1) of $71.7 million in Q2/21 ($0.21 per share basic and diluted) compared to
$21.0 million in the same period in
2020 ($0.09 per share basic and
diluted).
- Generated free adjusted funds flow(1), excluding
acquisition expenditures, of $40.9
million and net income of $230.2
million during the quarter.
- Invested $30.8 million in
exploration and development capital expenditures, excluding
acquisitions, during the second quarter of 2021, which contributed
to the drilling of 20 (20.0 net) wells, comprised of 10 (10.0 net)
Viking oil wells, 8 (8.0 net) Clearwater oil wells and 2 (2.0 net)
Charlie Lake oil wells.
- Exited the second quarter with $506
million of net debt; with a forecasted year end 2021 net
debt to Q4 annualized adjusted funds flow(1) of less
than 1.2x.
Charlie Lake Update
Tamarack brought on its first two operated Charlie Lake light oil wells in June
(12-16-071-08W6 and 02/16-22-073-07W6) with IP30 rates of
approximately 1,367 boe/d(3) (1,157 bopd) and 1,048
boe/d(4) (650 bopd), respectively. This compares to the
internal TVE Tier 8 development type curve of 482 bbls/d.
Production for June and July was impacted by third party plant
outages due to the extreme temperatures that plagued the province.
However, the Company remains on track with its planned production
range of 12,000-13,000 boe/d(5) for the asset going
forward, with current production of approximately 13,000
boe/d(5). Tamarack currently has three rigs running with
the third and fourth wells in the program rig released.
Clearwater Update
In the quarter Tamarack drilled 8 gross (8.0 net) Clearwater wells in the Nipisi area bringing
the yearly total to 23.5 net wells for the year in Nipisi and
Jarvie. All the wells in the
second quarter were drilled with 8 legs, and Tamarack plans to
continue with this strategy throughout the remainder of
2021. Average well production from the second quarter program
is 210bbls/d(6) (8-leg laterals) after cleanup versus
the 160 bbls/d(6) winter program 6-leg average in the
core Nipsi development area with well costs for the eight leg
laterals averaging an incremental $105
thousand per well, driving significant capital efficiency
gains. Total Clearwater production averaged
4,550bbls/d(7) for the quarter with June averaging
approximately 5,000bbls/d(7).
Tamarack plans to drill another 13-14 net wells in Nipisi
keeping one rig working throughout the year with a second rig
planned to start up in December. Additionally, Tamarack plans
to participate in 3-4 net (6-8 gross) wells in the Jarvie area. Gas conservation work is slated
to begin at Nipisi in July with commissioning and start up in late
September. In addition to this, technical work continues on a
waterflood pilot and high graded areas for a trial have been
selected. Tamarack anticipates drilling the pilot in early Q4
with injection slated to start in late Q4 2021 or early Q1
2022.
Executive Changes
Tamarack wishes to congratulate Mr. Floyd Price, Chairman of the Board, on his
retirement effective July 27, 2021.
Mr. Price has served on the Board of Directors since inception and
successfully guided the company through several key acquisitions
and market events. His imprint on strategy and guidance has been
key to Tamarack's success.
Tamarack also congratulates Mr. Dave
Christensen, Vice President, Engineering on his retirement
effective August 31st,
2021. Mr. Christensen has been an officer of the Company since
2014. We would like to thank him for his many contributions to the
company over the years.
As a result of the strategic organizational changes and
retirements, Tamarack has made the following executive
appointments:
- Mr. John Rooney, a director of
the Company, has been elected to be Chair of the Board of
Directors. Mr. Rooney has run several oil and gas companies most
recently CEO of Northern Blizzard and Tusk Energy. He currently
serves as Chairman of Kara Technologies and is on the Board of
Western Energy Services.
- Mr. Kevin Screen has been
promoted to Chief Operating Officer. Mr. Screen has served as Vice
President, Production & Operations since he joined the Company
in 2011 and has been instrumental in the strategic development and
effective operational execution that have driven Tamarack's success
to date.
- Mr. Martin Malek has been
appointed as successor to Mr. Christensen as Vice President,
Engineering. Mr. Malek has served in various roles across the
organization since joining in 2014. He most recently served as Vice
President, Business Development and has been a pivotal driver in
Tamarack's acquisition activity over the past year.
Tamarack is also pleased to announce the appointment of Ms.
Christine Ezinga as Vice President,
Corporate Planning and Business Development, and Mr. Scott Shimek as Vice President, Production and
Operations. Ms. Ezinga brings more than 20 years of industry
experience in finance, investor relations and business development,
including mergers and acquisitions. Most recently, she held the
role of Vice President, Strategy & Planning at Black Swan
Energy. Mr. Shimek brings more than 15 years of engineering and
operations experience, most recently serving as Vice President,
Resource Development at Bonavista Energy Corp. The Company is
excited to add the skills and perspectives of these bright young
leaders to the strong existing team.
"On behalf of the Board of Directors, executive management team
and all of our staff, I would like to extend sincere appreciation
to Floyd and Dave for their many contributions which are imprinted
in our success. They have been instrumental in building the Company
into what it is today" said Brian
Schmidt, President and Chief Executive Officer. "We wish
them well in retirement. I would also like to congratulate both
Kevin and Martin on their new roles and welcome Christine and Scott
to Tamarack. We are excited to be able to bring in this exceptional
talent to complement our executive team".
Financial & Operating Results
|
Three months
ended
|
Six months
ended
|
June 30,
|
June 30,
|
|
2021
|
2020
|
%
change
|
2021
|
2020
|
%
change
|
($ thousands,
except per share)
|
|
|
|
|
|
|
Total oil, natural
gas and processing revenue
|
152,168
|
33,127
|
359
|
245,602
|
99,410
|
147
|
Cash flow from
operating activities
|
40,253
|
28,107
|
43
|
78,689
|
74,466
|
6
|
Per share –
basic
|
$
0.12
|
$ 0.13
|
(8)
|
$
0.26
|
$ 0.34
|
(24)
|
Per share –
diluted
|
$
0.12
|
$ 0.13
|
(8)
|
$
0.26
|
$ 0.34
|
(24)
|
Adjusted funds flow
(1)
|
71,741
|
20,972
|
242
|
113,693
|
63,017
|
80
|
Per share – basic
(1)
|
$
0.21
|
$ 0.09
|
133
|
$
0.38
|
$ 0.28
|
36
|
Per share – diluted
(1)
|
$
0.21
|
$ 0.09
|
133
|
$
0.37
|
$ 0.28
|
32
|
Net income
(loss)
|
230,194
|
(36,067)
|
738
|
230,028
|
(287,388)
|
180
|
Per share –
basic
|
$
0.69
|
$ (0.16)
|
531
|
$
0.77
|
$ (1.30)
|
159
|
Per share –
diluted
|
$
0.67
|
$ (0.16)
|
519
|
$
0.75
|
$ (1.30)
|
158
|
Net debt
(1)
|
(505,992)
|
(213,066)
|
137
|
(505,992)
|
(213,066)
|
137
|
Capital expenditures
(8)
|
30,805
|
6,218
|
395
|
79,509
|
80,091
|
(1)
|
Weighted average
shares outstanding
(thousands)
|
|
|
|
|
|
|
Basic
|
333,908
|
221,142
|
51
|
300,013
|
221,612
|
35
|
Diluted
|
341,935
|
221,142
|
55
|
307,608
|
221,612
|
39
|
Share Trading
(thousands, except share
price)
|
|
|
|
|
|
|
High
|
$
2.90
|
$ 1.09
|
166
|
$
2.90
|
$ 2.27
|
28
|
Low
|
$
2.16
|
$ 0.43
|
402
|
$
1.25
|
$ 0.39
|
221
|
Trading volume
(thousands)
|
155,905
|
66,702
|
134
|
337,037
|
125,647
|
168
|
Average daily
production
|
|
|
|
|
|
|
Light oil
(bbls/d)
|
14,535
|
11,107
|
31
|
12,340
|
11,988
|
3
|
Heavy oil
(bbls/d)
|
4,701
|
156
|
2,913
|
3,683
|
168
|
2,092
|
NGL
(bbls/d)
|
3,032
|
1,466
|
107
|
2,728
|
1,565
|
74
|
Natural gas
(mcf/d)
|
60,887
|
49,610
|
23
|
56,699
|
51,261
|
11
|
Total
(boe/d)
|
32,416
|
20,997
|
54
|
28,201
|
22,265
|
27
|
Average sale
prices
|
|
|
|
|
|
|
Light oil
($/bbl)
|
75.30
|
24.92
|
202
|
70.69
|
36.46
|
94
|
Heavy oil
($/bbl)
|
61.20
|
15.47
|
296
|
56.47
|
33.81
|
67
|
NGL ($/bbl)
|
39.57
|
12.73
|
211
|
38.51
|
16.30
|
136
|
Natural gas
($/mcf)
|
2.77
|
1.37
|
102
|
2.94
|
1.50
|
96
|
Total
($/boe)
|
51.55
|
17.42
|
196
|
47.95
|
24.47
|
96
|
Operating netback
($/Boe) (1)
|
|
|
|
|
|
|
Average realized
sales
|
51.55
|
17.42
|
196
|
47.95
|
24.47
|
96
|
Royalty
expenses
|
(7.20)
|
(2.12)
|
240
|
(6.43)
|
(3.00)
|
114
|
Net production and
transportation expenses (1)
|
(10.74)
|
(10.01)
|
7
|
(10.91)
|
(9.99)
|
9
|
Operating field
netback ($/Boe) (1)
|
33.61
|
5.29
|
535
|
30.61
|
11.48
|
167
|
Realized commodity
hedging gain (loss)
|
(6.20)
|
8.46
|
(173)
|
(5.19)
|
6.68
|
(178)
|
Operating netback
(1)
|
27.41
|
13.75
|
99
|
25.42
|
18.16
|
40
|
Adjusted funds
flow ($/Boe) (1)
|
24.32
|
10.98
|
121
|
22.27
|
15.55
|
43
|
Investor Webcast
Tamarack will host a webcast at 9:00 AM
MT (11:00 AM ET) on
July 28, 2021 to discuss the second
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.
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 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 in
the Charlie Lake, Cardium,
Clearwater 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
AECO
|
the natural gas
storage facility located at Suffield, Alberta connected to TC
Energy's Alberta System
|
bbls/d
|
barrels per
day
|
boe
|
barrels of oil
equivalent
|
boe/d
|
barrels of oil
equivalent per day
|
Bopd
|
barrels of oil 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
|
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"
|
(2)
|
Comprised of 14.535
bbl/d light and medium oil, 4.701 bbl/d heavy oil, 3,032 bbl/d NGL
and 60,887 mcf/d natural gas
|
(3)
|
Comprised of 1,157
bbl/d light and medium oil, 38 bbl/d NGL and 1,030 mcf/d natural
gas
|
(4)
|
Comprised of 650
bbl/d light and medium oil, 74 bbl/d NGL and 1,942 mcf/d natural
gas
|
(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 210
bbl/d of heavy oil and 160 bbl/d of heavy oil,
respectively
|
(7)
|
Comprised of 4,550
bbl/d of heavy oil for Q2 2021 and 5,000 bbl/d of heavy oil for
June 2021
|
(8)
|
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. 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.
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 with respect to
Charlie Lake; expectations with
respect to reserves, oil and natural gas production levels,
operating field netbacks, decline rates, adjusted funds flow, free
adjusted funds flow and net debt to Q4 annualized adjusted funds
flow relating Tamarack, including pro forma the acquisition of
Anegada; development and drilling plans for Anegada's assets,
including the drilling locations associated therewith and timing of
results therefrom; anticipated operational results for 2021
including, but not limited to, estimated or anticipated production
levels, capital expenditures and drilling plans; the Company's
capital program, guidance and budget for 2021; expectations
regarding commodity prices in 2021; deployment of the Company's
2021 capital program; the expected allocation of the Company's 2021
capital expenditure budget; 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; development costs, operating costs, general and
administrative costs, costs of services and other costs and
expenses; and projections of commodity prices and costs, and
exchange rates.
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
Anegada's assets; the successful integration of Anegada's 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: unforeseen
difficulties in integrating Anegada's assets into Tamarack's
operations; incorrect assessments of the value of benefits to be
obtained from acquisitions and exploration and development programs
(including with respect to Anegada); 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 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 adjusted funds
flow, free adjusted funds flow breakeven, net debt, net debt to Q4
annualized adjusted funds flow, 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.
References in this press release to IP30 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.
Non-IFRS Measures
Certain measures commonly used in the oil and natural gas
industry referred to herein, including, "adjusted funds flow",
"free adjusted funds flow", "free adjusted funds flow breakeven",
"net production and transportation expenses", "operating field
netback", "operating netback", "net debt" and "net debt to
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 adjusted funds
flow" is calculated by taking adjusted funds flow
and subtracting capital expenditures, excluding acquisitions and
dispositions, Management believes that free adjusted 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 adjusted funds flow
breakeven" is determined by calculating the minimum WTI price
in US/bbl required to generate Free Adjusted Funds Flow equal to
zero with no production growth and all other variables held
constant. Management believes that Free Adjusted 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 Annualized
Adjusted Funds Flow" is calculated as net debt divided by
the annualized adjusted funds flow for the most recently completed
quarter.
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