TSX:TVE
CALGARY, Feb. 27, 2019 /CNW/ - Tamarack Valley Energy Ltd.
("Tamarack" or the "Company") is pleased to announce
its financial and operating results for the three and twelve months
ended December 31, 2018 and the
results of its independent oil and gas reserves evaluation as of
December 31, 2018, prepared by GLJ
Petroleum Consultants Ltd. ("GLJ"). Selected financial,
operational and reserves information is outlined below and should
be read with Tamarack's audited consolidated financial statements
("Financial Statements"), management's discussion and analysis
("MD&A") as of December 31, 2018,
which are available on SEDAR at www.sedar.com and on Tamarack's
website at www.tamarackvalley.ca. The Company's annual information
form ("AIF") for the year ended December 31,
2018 will be filed on SEDAR and available on Tamarack's
website by close of business February 27,
2019.
2018 Financial and Operating Highlights
- Maintained stable production volumes of 24,780 boe/d in Q4/18
relative to 24,765 boe/d in Q3/18, while investing only
$25.8 million in capital
expenditures, a $52.3 million
reduction from the previous quarter.
- Total adjusted operating field netback (previously referred to
as "adjusted funds flow"; see "Non-IFRS Measures") increased 43% in
2018 to $226.5 million ($0.99 per share basic and $0.97 per share diluted), from $158.4 million in 2017 ($0.70 per share basic and diluted).
- In Q4/18, total adjusted operating field netback of
$38.3 million exceeded capital
spending of $21.0 million, net of
acquisitions and dispositions, by $17.3
million, resulting in excess total adjusted operating field
netback for the period, which was directed to debt repayment and
continued funding of the Company's active share repurchase
program.
- Year over year, achieved a 20% increase in production, and an
8% increase in the oil and natural gas liquids ("NGL") weighting
percentage, while spending $9 million
less capital, after acquisitions and dispositions, than the
mid-point of the Company's previous capital guidance.
- Full year 2018 net production and transportation expenses per
boe were 6% lower relative to 2017, stemming primarily from
increased production from the lower-cost Veteran area.
- Tamarack's continued increase in oil and liquids weighting
through 2018 largely contributed to 16% higher operating netbacks
(see "Non-IFRS Measures") compared to 2017, further supported by
improved pricing and lower transportation expenses per boe year
over year.
- Invested $219.2 million in total
capital expenditures net of dispositions during 2018, which
included drilling a total of 164 (158.2 net) wells, comprised of
129 (124.7 net) Viking oil wells, 19 (17.8 net) Cardium oil wells,
4 (4.0 net) Penny oil wells, 11 (10.7 net) Redwater oil wells, one exploratory vertical
stratigraphic well and one (1.0 net) water source well.
2018 Reserve Highlights
- Tamarack's strategy to enhance value through increased oil
weighting was evidenced by increases to the Company's crude oil
reserves which grew by 22% for total proved plus probable ("TPP"),
by 15% for total proved ("TP") and 10% for proved developed
producing ("PDP"), respectively, over 2017.
- Growth across all reserves categories on an absolute basis was
achieved in 2018; increased TPP reserves by 11% to 101.6 million
boe; increased TP reserves by 8% to 55.7 million boe; and increased
PDP reserves by 2% to 31.8 million boe.
- On a per share basis (basic), realized growth of 12% in TPP, 9%
in TP and 3% in PDP reserves, demonstrating Tamarack's continued
focus on enhancing per share metrics.
- Net asset value based on the net present values (discounted at
10%) of the TP and TPP reserves is $2.83 and $5.95 per
basic share, respectively. The net present value of reserves has
been adjusted for net debt of $179.9
million but assumes no value for undeveloped land or
infrastructure.
- Achieved attractive capital efficiencies through the 2018
development program, generating a TPP finding and development
("F&D") and finding, development and acquisition ("FD&A")
cost recycle ratio of 2.4x and 2.5x, respectively, and a TP F&D
and FD&A cost recycle ratio of 1.5x and 1.6x based on the 2018
average operating field netback of $30.05/boe.
- Crude oil weighting across reserves categories also increased
to 58%, 55% and 52% for TPP, TP and PDP, respectively, compared to
54%, 52% and 49% for the same categories in 2017, driving oil and
NGL weighting across all reserve categories to approximately 65%
compared to 62% in 2017.
- The Company replaced 144% of production on a TP basis and 214%
on a TPP basis.
- Achieved TPP F&D costs of $12.59/boe and TPP FD&A costs of $11.85/boe, both including the change in future
development capital ("FDC") contributing to reducing the realized
three-year average TPP F&D costs to $15.10/boe and TPP FD&A costs to $16.75/boe, both including the change in FDC.
- Based on 2018 average production of 24,237 boe/d, achieved a
TPP reserve life index of 11.5 years.
Financial & Operating Results
|
Three months
ended
|
Years
ended
|
December
31,
|
December
31,
|
|
2018
|
2017
|
%
change
|
2018
|
2017
|
%
change
|
($ thousands,
except per share)
|
|
|
|
|
|
|
Total
Revenue
|
73,075
|
90,160
|
(19)
|
398,804
|
283,672
|
41
|
Adjusted operating
field netback 1
|
38,346
|
57,583
|
(33)
|
226,475
|
158,383
|
43
|
Per share – basic
1
|
$
0.17
|
$ 0.25
|
(32)
|
$
0.99
|
$ 0.70
|
41
|
Per share – diluted
1
|
$
0.17
|
$ 0.25
|
(32)
|
$
0.97
|
$ 0.70
|
39
|
Net income
(loss)
|
18,952
|
(12,525)
|
251
|
38,310
|
(13,924)
|
375
|
Per share –
basic
|
$
0.08
|
$ (0.05)
|
260
|
$
0.17
|
$ (0.06)
|
383
|
Per share –
diluted
|
$
0.08
|
$ (0.05)
|
260
|
$
0.16
|
$ (0.06)
|
367
|
Net debt
1
|
(179,880)
|
(173,180)
|
4
|
(179,880)
|
(173,180)
|
4
|
Capital Expenditures
2
|
25,798
|
35,516
|
(27)
|
226,251
|
192,302
|
18
|
Weighted average
shares outstanding (thousands)
|
|
|
|
|
|
|
Basic
|
227,211
|
228,066
|
–
|
227,720
|
225,306
|
1
|
Diluted
|
232,066
|
228,066
|
2
|
233,561
|
225,306
|
4
|
Share Trading
(thousands, except share price)
|
|
|
|
|
|
|
High
|
$
5.20
|
$ 3.15
|
65
|
$
5.20
|
$ 3.59
|
45
|
Low
|
$
1.81
|
$ 2.49
|
(27)
|
$
1.81
|
$ 1.96
|
(8)
|
Trading volume
(thousands)
|
72,410
|
35,006
|
107
|
268,916
|
196,595
|
37
|
Average daily
production
|
|
|
|
|
|
|
Light oil
(bbls/d)
|
14,163
|
12,189
|
16
|
13,769
|
9,929
|
39
|
Heavy oil
(bbls/d)
|
755
|
500
|
51
|
552
|
511
|
8
|
NGL
(bbls/d)
|
1,485
|
1,459
|
2
|
1,398
|
1,547
|
(10)
|
Natural gas
(mcf/d)
|
50,262
|
51,956
|
(3)
|
51,108
|
48,893
|
5
|
Total
(boe/d)
|
24,780
|
22,807
|
9
|
24,237
|
20,136
|
20
|
Average sale
prices
|
|
|
|
|
|
|
Light oil
($/bbl)
|
36.78
|
65.08
|
(43)
|
64.17
|
59.42
|
8
|
Heavy oil
($/bbl)
|
49.33
|
48.97
|
1
|
59.13
|
46.01
|
29
|
NGL ($/bbl)
|
33.72
|
44.03
|
(23)
|
41.89
|
32.38
|
29
|
Natural gas
($/mcf)
|
3.70
|
1.89
|
96
|
2.30
|
2.32
|
(1)
|
Total
($/boe)
|
32.05
|
42.97
|
(25)
|
45.08
|
38.60
|
17
|
Operating netback
($/Boe) 1
|
|
|
|
|
|
|
Average realized
sales
|
32.05
|
42.97
|
(25)
|
45.08
|
38.60
|
17
|
Royalty
expenses
|
(2.59)
|
(4.03)
|
(36)
|
(4.51)
|
(3.96)
|
14
|
Production
expenses
|
(10.47)
|
(10.40)
|
1
|
(10.52)
|
(11.19)
|
(6)
|
Operating field
netback ($/Boe) 1
|
18.99
|
28.54
|
(33)
|
30.05
|
23.45
|
28
|
Realized commodity
hedging gain (loss)
|
0.04
|
1.53
|
(97)
|
(2.03)
|
0.77
|
(364)
|
Operating
netback
|
19.03
|
30.07
|
(37)
|
28.02
|
24.22
|
16
|
Adjusted operating
field netback ($/Boe)
1
|
16.82
|
27.44
|
(39)
|
25.60
|
21.55
|
19
|
|
|
Notes:
|
|
(1)
|
Net debt, operating
netback, operating field netback and adjusted 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 entities. See "Oil and Gas Metrics" and
"Non-IFRS Measures".
|
(2)
|
Capital expenditures
include exploration and development expenditures, but exclude asset
acquisitions and dispositions.
|
2018 In Review
Through 2018, Tamarack delivered another year of exceptional
performance supplemented by an unwavering commitment to enhancing
per share and debt-adjusted per share value. In each quarter,
the Company met or exceeded expectations for production while
remaining focused on driving costs down and achieving strong
capital efficiencies. Tamarack grew annual production volumes
20% in 2018 over 2017, averaging 24,237 boe/d (65% oil and NGL),
compared to 20,136 boe/d (60% oil and NGL) following a successful
2018 drilling program combined with strong capital efficiencies.
The Company's 2018 average annual production was at the
mid-point of its 2018 average guidance range of 24,000 to
24,500 boe/d (66% oil and NGL). In Q4/18, Tamarack achieved
record production of 24,780 boe/d (66% oil and NGL) exceeding the
Company's lower end of its exit 2018 guidance range of 24,500 to
25,000 boe/d.
Consistent with historical practices during periods of
volatility in commodity prices, Tamarack remains disciplined in its
capital allocation and preservation of balance sheet strength.
This became critical during the final quarter of 2018 when an
unexpected and extreme widening of Canadian crude oil price
differentials severely reduced the Company's realized price for its
oil and NGL products. In response to this, Tamarack elected
to defer $7.4 million of the
$28.4 million in capital spending
that had previously been planned for acceleration from 2019 into
Q4/18. As such, the Company's Q4/18 capital spending totaled
$21.0 million net of acquisitions and
dispositions, bringing its total 2018 capital investment to
$226.3 million ($219.2 million including acquisitions, net of
dispositions). Tamarack remains focused on drilling wells
which are expected to payout in 1.5 years or less and estimates it
has more than nine years of development within its current
inventory.
During Q4/18, capital was directed to drill a total of 24 (23.2
net) Viking oil wells and one (1.0 net) water source well in the
Veteran area. Of these Viking oil wells, 19 (18.5 net) are
expected to be brought on production in Q1/19, while five (4.8 net)
of the drilled Viking oil wells were also completed, equipped and
tied-in during the period. Six of the Viking wells are future
Veteran waterflood injection wells, which will produce to recover
the capital costs until the commencement of the injection project
in the first half of 2019. In addition, Tamarack completed
and brought on production 18 (17.8 net) Viking oil wells and one
(1.0 net) Penny oil well that had been drilled in late
Q3/18.
Despite the weakness in realized oil prices during Q4/18,
Tamarack generated total adjusted operating field netback of
$38.3 million ($0.17 per share basic and diluted), exceeding its
capital spending, including acquisitions and net of dispositions,
by $17.3 million for the
quarter. The Company elected to direct excess total adjusted
operating field netback to debt repayment and continued funding of
Tamarack's active normal course issuer bid ("NCIB"). For the
full year 2018, adjusted operating field netback totaled
$226.5 million ($0.99 per basic share; $0.97 per diluted share), an increase of 43% over
$158.4 million ($0.70 per basic and diluted share) in 2017.
Based on the forward curve price deck, the Company
anticipates generating excess total adjusted operating field
netback in 2019 to again fully fund its capital program, achieve
3-5% debt-adjusted production per share growth in Q4/19 over Q4/18
and have incremental funds remaining. With this situation and
by maintaining financial flexibility, Tamarack retains optionality
to increase drilling activity, pursue tuck-in acquisitions, repay
debt or continue share buybacks under the NCIB depending on the
prevailing price environment. Year-end 2018 net debt totaled
$179.9 million, which represents a
net debt to Q4/18 annualized adjusted operating field netback ratio
of 1.2 times, compared to 0.8 times at December 31, 2017.
Tamarack's oil and NGL weighting continued to increase through
2018 and averaged 65%, compared to 60% in 2017, and largely
contributed to operating field netbacks of $30.05/boe, 28% higher than in 2017.
Tamarack's average per boe sales price increased 17% year-over-year
to $45.08/boe in 2018 from
$38.60/boe in 2017 while net
production and transportation expenses per boe declined by 6%.
The Company anticipates its oil and NGL weighting will range
between 64 to 66% of total 2019 production.
During 2018, Tamarack purchased and cancelled 3,025,000
outstanding common shares under the NCIB program, for a total
investment of $11.7 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 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 1,803,592 outstanding common shares in the open market
for $5.8 million, which are held in
trust and used to settle RSUs upon future exercise, further
supporting Tamarack's per share metrics.
2018 Year-End Reserves Summary
Tamarack continued to generate attractive capital efficiency
metrics in 2018, despite a very challenging Q4/18 crude oil price
environment which has had a severely negative impact on operating
netbacks for the period. The Company's full year 2018
operating field netback was more representative of the performance
through the year, averaging $30.05/boe, and reflecting the strategic capital
shift to projects with higher oil and NGL weighting. Using
the Company's full year operating field netback, Tamarack generated
a TPP F&D recycle ratio of 2.4x, 1.5x for TP, and 1.2x for PDP,
and FD&A recycle ratios of 2.5x for TPP, 1.6x for TP and 1.2x
for PDP. The Company maintained a consistent approach to
reserves booking, with TP reserves including only 140.6 net Veteran
and Consort horizontal Viking oil wells, 103.2 net Redwater and Saskatchewan horizontal Viking oil wells and
47.5 net undeveloped horizontal Cardium oil locations. Further, the
FDC for 2019, within GLJ's 2018 reserves evaluation, of
$126.8 million is materially lower
than Tamarack's 2019 capital expenditure guidance of $170 to $180
million. The total FDC on a TP basis was $381.6 million and on a TPP basis was
$700.2 million.
Consistent with Tamarack's core strategy, the Company continued
to take a long-term approach to the allocation of capital and
development of its asset base in 2018, including the Veteran
waterflood project. During the year, the Company invested
$30.3 million in waterflood capital,
including constructing pipelines for the planned injectors,
drilling a water source well, commencement of the water handling
upgrades to the Veteran oil battery, drilling nine wells as future
injectors in the Veteran unit and drilling six wells to be
converted into injectors in East Veteran in 2019. The results
of this capital investment have been conservatively recognized, as
GLJ assigned probable reserves of 4.9 million barrels of oil
associated with the waterflood, with no reserves yet reflected in
the PDP or TP categories. Excluding waterflood capital from
PDP and TP F&D costs (including FDC) results in $22.28/boe and $17.62/boe, respectively and generates recycle
ratios of 1.3x and 1.7x for the same respective categories.
In 2019, Tamarack plans to invest an additional $20 million to further the waterflood project,
which will benefit the Company in future years by improving oil
recoveries, reducing corporate decline rates and increasing
production rates over time, while utilizing existing Tamarack-owned
infrastructure.
The following tables highlight Tamarack's 2018 year-end
independent reserves assessment and evaluation prepared by GLJ with
an effective date of December 31,
2018 (the "GLJ Report"). The GLJ Report has been
prepared in accordance with definitions, standards and procedures
contained in National Instrument 51-101 – Standards of
Disclosure for Oil and Gas Activities ("NI 51-101") and the
Canadian Oil and Gas Evaluation Handbook. All evaluations and
summaries of future net revenue are stated prior to provision for
interest, debt service charges or general and administrative
expenses and after deduction of royalties, operating costs,
estimated well abandonment and reclamation costs and estimated
future capital expenditures. The information included in the "Net
Present Values of Future Net Revenue before Income Taxes" table
below is based on an average of pricing assumptions prepared by
three independent external reserves evaluators. It should not be
assumed that the estimates of future net revenues presented in the
tables below represent the fair market value of the reserves.
Given Tamarack's ongoing and extensive share buy-backs during 2018
under its NCIB and shares held in treasury to settle future
restricted share unit ("RSU") exercises, all per share reserves
metrics below are based on basic shares outstanding.
Reserves Snapshot by Category:
|
|
|
|
|
PDP
|
TP
|
TPP
|
Reserves
Added(1) (mboe)
|
9,319
|
12,737
|
18,957
|
Total Reserves
(mboe)(2)
|
31,788
|
55,651
|
101,572
|
Reserves
Replacement
|
105%
|
144%
|
214%
|
NPV10 BT
($mm)
|
$515.9
|
$820.8
|
$1,524.4
|
FD&A Cost per
boe(3)
|
$24.47
|
$18.83
|
$11.85
|
Recycle
Ratio(4)
|
1.2x
|
1.6x
|
2.5x
|
F&D Cost per boe
(3)
|
$25.74
|
$20.23
|
$12.59
|
Recycle
Ratio(4)
|
1.2x
|
1.5x
|
2.4x
|
|
|
Notes:
|
|
(1)
|
This number takes the
difference in reserves year over year plus the production for the
year.
|
(2)
|
Total reserves are
Company Gross Reserves which exclude royalty volumes.
|
(3)
|
Including changes in
FDC.
|
(4)
|
Based on 2018
operating field netback of $30.05 per boe.
|
Reserves Data (Forecast Prices and Costs) – Company
Gross
|
|
|
|
|
|
|
|
RESERVES
CATEGORY
|
|
CRUDE
OIL(1)
|
|
CONVENTIONAL
NATURAL
GAS(2)
|
|
NATURAL
GAS
LIQUIDS
|
|
TOTAL
OIL
EQUIVALENT
|
|
Gross
(Mbbls)
|
|
Net
(Mbbls)
|
|
Gross
(Mmcf)
|
|
Net
(Mmcf)
|
|
Gross
(Mbbls)
|
|
Net
(Mbbls)
|
|
Gross
(Mboe)
|
|
Net
(Mboe)
|
PROVED:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
Producing
|
|
16,484
|
|
14,629
|
|
75,954
|
|
70,112
|
|
2,645
|
|
2,111
|
|
31,788
|
|
28,426
|
Developed
Non-Producing
|
|
1,081
|
|
962
|
|
8,928
|
|
7,902
|
|
61
|
|
54
|
|
2,630
|
|
2,333
|
Undeveloped
|
|
12,976
|
|
11,698
|
|
40,281
|
|
37,585
|
|
1,543
|
|
1,399
|
|
21,233
|
|
19,361
|
TOTAL
PROVED
|
|
30,542
|
|
27,290
|
|
125,163
|
|
115,600
|
|
4,249
|
|
3,564
|
|
55,651
|
|
50,120
|
PROBABLE
|
|
28,609
|
|
23,857
|
|
86,930
|
|
79,982
|
|
2,824
|
|
2,399
|
|
45,921
|
|
39,585
|
TOTAL PROVED PLUS
PROBABLE
|
|
59,151
|
|
51,146
|
|
212,093
|
|
195,581
|
|
7,073
|
|
5,962
|
|
101,572
|
|
89,706
|
|
|
Notes:
|
|
(1)
|
Heavy oil and tight
oil included in the crude oil product type represents less than
3.1% of any reserves category and as such is immaterial.
|
(2)
|
Conventional natural
gas amounts include coal bed methane, in amounts less than
0.1%.
|
(3)
|
Columns may not add
due to rounding.
|
Net Present Values of Future Net Revenue before Income Taxes
Discounted at (% per year)
RESERVES
CATEGORY
|
0%
($000s)
|
|
5%
($000s)
|
|
10%
($000s)
|
|
15%
($000s)
|
|
20%
($000s)
|
|
Unit
Value
Before
Income
Tax
Discounted
at
10%
Per
Year(1)
($/Boe)
|
PROVED:
|
|
|
|
|
|
|
|
|
|
|
|
Developed
Producing
|
681,815
|
|
590,082
|
|
515,863
|
|
459,947
|
|
416,912
|
|
18.15
|
Developed
Non-Producing
|
55,510
|
|
44,239
|
|
37,438
|
|
32,842
|
|
29,474
|
|
16.05
|
Undeveloped
|
452,997
|
|
345,872
|
|
267,459
|
|
210,646
|
|
168,666
|
|
13.81
|
TOTAL
PROVED
|
1,190,322
|
|
980,193
|
|
820,760
|
|
703,435
|
|
615,052
|
|
16.38
|
PROBABLE
|
1,407,444
|
|
962,460
|
|
703,627
|
|
540,753
|
|
431,402
|
|
17.77
|
TOTAL PROVED PLUS
PROBABLE
|
2,597,765
|
|
1,942,653
|
|
1,524,387
|
|
1,244,188
|
|
1,046,454
|
|
16.99
|
|
|
Notes:
|
|
(1)
|
Unit values based on
Company net interest reserves.
|
(2)
|
The prices used to
estimate net present values are the average of those used by the
largest independent industry reserve evaluators.
|
(3)
|
Columns may not add
due to rounding.
|
Reconciliation of Company Gross Reserves Based on Forecast
Prices and Costs
|
MBOE
|
FACTORS
|
Proved
|
Probable
|
Proved
+
Probable
|
December 31,
2017
|
51,761
|
39,701
|
91,462
|
Extensions and
Improved Recovery(1)
|
10,907
|
8,777
|
19,684
|
Technical
Revisions
|
1,060
|
(2,875)
|
(1,816)
|
Acquisitions
|
1,128
|
527
|
1,655
|
Dispositions
|
0
|
0
|
0
|
Economic
Factors
|
(358)
|
(210)
|
(567)
|
Production
|
(8,847)
|
0
|
(8,847)
|
December 31,
2018
|
55,651
|
45,921
|
101,572
|
Notes:
|
|
(1)
|
Reserves additions
under Infill Drilling, Improved Recovery and Extensions are
combined and reported as "Extensions and Improved
Recovery".
|
(2)
|
Columns may not add
due to rounding.
|
(3)
|
Company Gross
Reserves exclude royalty volumes.
|
Future Development Capital Costs
The following is a summary of GLJ's estimated future development
capital required to bring proved and probable undeveloped reserves
on production.
Future Development
Capital(1)
|
|
|
(amounts in
$000s)
|
Total
Proved
|
Total Proved +
Probable
|
2019
|
91,721
|
126,768
|
2020
|
162,651
|
193,817
|
2021
|
87,219
|
156,685
|
2022 and
Subsequent
|
39,978
|
222,902
|
Total Undiscounted
FDC
|
381,570
|
700,174
|
Total Discounted FDC
at 10% per year
|
323,279
|
563,488
|
|
|
Note:
|
|
(1)
|
FDC as per GLJ
independent reserve evaluation effective December 31, 2018 based on
GLJ forecast pricing.
|
FD&A
Costs
|
2018
|
Three Year
Average
|
|
|
|
|
|
(amounts in $000s
except as noted)
|
TP
|
TPP
|
TP
|
TPP
|
FD&A costs,
including FDC(1)(2)
|
|
|
|
|
Exploration and
development capital expenditures (3)(4)
|
216,584
|
216,584
|
155,144
|
155,144
|
Acquisitions, net of
dispositions(5)
|
2,627
|
2,627
|
160,913
|
160,913
|
Total change in
FDC
|
20,572
|
5,414
|
62,160
|
111,433
|
Total FD&A
capital, including change in FDC
|
239,783
|
224,625
|
378,217
|
427,490
|
|
|
|
|
|
Reserve additions,
including revisions – Mboe
|
11,609
|
17,302
|
8,364
|
12,010
|
Acquisitions, net of
dispositions(5) – Mboe
|
1,128
|
1,655
|
8,505
|
13,509
|
Total FD&A
Reserves
|
12,737
|
18,956
|
16,869
|
25,519
|
|
|
|
|
|
F&D costs,
including FDC - $/boe
|
20.23
|
12.59
|
19.90
|
15.10
|
Acquisition costs,
net of dispositions - $/boe
|
4.33
|
4.12
|
24.90
|
18.22
|
FD&A costs,
including FDC - $/boe
|
18.83
|
11.85
|
22.42
|
16.75
|
|
|
Notes:
|
|
(1)
|
While Nl 51-101
requires that the effects of acquisitions and dispositions be
excluded from the calculation of finding and development costs,
FD&A costs have been presented because acquisitions and
dispositions can have a significant impact on the Company's ongoing
reserve replacement costs and excluding these amounts could result
in an inaccurate portrayal of the Company's cost structure. Finding
and development costs both including and excluding acquisitions and
dispositions have been presented above.
|
(2)
|
The calculation of
FD&A costs incorporates the change in FDC required to bring
proved undeveloped and developed reserves into production. In all
cases, the FD&A number is calculated by dividing the identified
capital expenditures by the applicable reserves additions after
changes in FDC costs.
|
(3)
|
The aggregate of the
exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future
development costs generally will not reflect total finding and
development costs related to reserves additions for that
year.
|
(4)
|
The capital
expenditures also exclude capitalized administration
costs.
|
(5)
|
Includes capital
spent in 2018 to develop the assets acquired during
2018.
|
(6)
|
Columns may not add
due to rounding.
|
(7)
|
Calculations using
Company Gross Reserves which exclude royalty volumes.
|
2019 Guidance
Our 2019 guidance remains unchanged with plans to invest between
$170 and $180
million, funded entirely through adjusted operating field
netback. This capital program is expected to result in
production of 23,500 – 24,500 boe/d (64-66% oil and NGL). In
the context of continued volatility in oil prices and
supported by the Company's exceptional operational execution,
Tamarack remains committed to investing in longer-term projects,
including the Veteran waterflood, which the Company expects will
reduce the overall corporate decline rate in 2020 and enhance
Tamarack's sustainability.
Effective January 1, 2019 the
Government of Alberta imposed
production curtailments which, when combined with active production
management and engagement from the producer community, have
resulted in a significant narrowing of the differential into the
early part of 2019. The Company remains well positioned to
withstand further crude oil price volatility given approximately
30% of its 2019 production is protected with hedges that include a
US$60.00/bbl WTI put option and
another approximately 3% is protected with fixed price contracts at
US$64.60/bbl. Regardless, the Company
will continue to closely monitor current and future commodity
prices and price differentials. While the Company's 2019
capital guidance assumes activity levels will be weighted evenly
between H1 and H2 of 2019, the program timing for H1 has been
designed to comply with the required production cuts.
Following expected stable production levels in H1/19 due to the
mandatory volume curtailments, Tamarack anticipates realizing a
meaningful ramp-up in production volumes during the second half of
2019, assuming no additional government intervention.
The Company's 2019 guidance and assumptions are outlined
below:
- Annual average production between 23,500 – 24,500 boe/d (64-66%
oil and NGL), with 2019 exit production estimated between 25,500 –
26,500 boe/d (64-66% oil and NGL);
- Capital expenditures between $170
to $180 million to maintain the
Alberta government's mandatory
production curtailments during Q1 of 2019;
- Estimated year end 2019 net debt to Q4 annualized adjusted
operating field netback ratio of approximately 1.0 times with an
estimated $100 million of liquidity
on existing credit facilities; and
- 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.
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 NI 51-101. 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.
"Finding and development
costs" are calculated as the sum of field capital plus the
change in FDC for the period divided by the change in reserves that
are characterized as development for the period and "finding,
development and acquisition costs" are calculated as the sum of
field capital plus acquisition capital plus the change in FDC for
the period divided by the change in total reserves, other than from
production, for the period. Both finding and development
costs and finding development and acquisition costs take into
account reserves revisions during the year on a per boe basis. The
aggregate of the exploration and development costs incurred in the
financial year and changes during that year in estimated future
development costs generally will not reflect total finding and
development costs related to reserves additions for that year.
Finding and development costs both including and excluding
acquisitions and dispositions have been presented in this press
release because acquisitions and dispositions can have a
significant impact on Tamarack's ongoing reserves replacements
costs and excluding these amounts could result in an inaccurate
portrayal of the Company's cost structure.
"Recycle ratio" is measured
by dividing the operating netback for the applicable period by
F&D cost per boe for the year. The recycle ratio compares
netback from existing reserves to the cost of finding new reserves
and may not accurately indicate the investment success unless the
replacement reserves are of equivalent quality as the produced
reserves.
"Reserve life index" is
calculated as total Company interest reserves divided by annual
production.
"Net asset value" is based
on present value of future net revenues discounted at 10% before
tax on reserves, net of estimated net debt at year end divided by
the basic shares outstanding at year end.
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; risk management activities, including
hedging and fixed price contracts; drilling plans including the
timing of drilling; investments in pipeline and facility
infrastructure; 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 and the impact of oil curtailment thereon;
decline rates; 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; the weighting
of activity levels between the first and second halves of 2019;
Tamarack's intent to direct excess total adjusted operating field
netback to debt repayment and continued funding share buy-backs for
cancellation under the NCIB and RSU settlements; liquidity on
existing credit facilities; shareholder returns; and enhanced per
share metrics. 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.
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 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 AIF for the
year ended December 31, 2018 which
will be filed on SEDAR by close of business February 27, 2019.
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 asset value, 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 adjusted for risk management contracts.
"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