CALGARY, July 29, 2019
/CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or
the "Company") (TSX, NYSE: VET) is pleased to report operating and
condensed financial results for the three and six months
ended June 30, 2019.
The unaudited financial statements and management discussion and
analysis for the three and six months ended June 30,
2019, will be available on the System for Electronic Document
Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at
www.sec.gov/edgar.shtml, and on Vermilion's website at
www.vermilionenergy.com.
Highlights
- Q2 2019 production averaged 103,003 boe/d, down slightly from
the prior quarter, as increases in the US and Australia were more than offset by lower
production in France due to a
refinery outage in the Paris
Basin.
- Fund flows from operations ("FFO") for Q2 2019 was $223 million ($1.44/basic share(1)), a decrease of
12% from the previous quarter due to the refinery outage, timing of
crude lifting in Australia, and
lower natural gas prices. Despite lower year-over-year commodity
prices, FFO for Q2 2019 was up 14% from the same quarter last year
due to increased production.
- In Germany, we finished
drilling and completing our first exploratory well, which was
tested subsequent to the end of the quarter. The well (46% working
interest) encountered 125 feet of net pay and tested at a rate of
8.8mmcf/d(2), with the test rate limited by weather
conditions.
- In CEE, we drilled three (2.3 net) exploration wells in
Hungary and one (1.0 net)
exploration well in Croatia during
Q2 2019. Subsequent to the end of the quarter, we drilled and
completed a fourth (1.0 net) exploration well in Hungary. Three of the Hungarian wells and the
Croatian well resulted in gas discoveries. The Hungarian wells
tested at rates of 1.7 mmcfe/d(3) (81% gas), 2.0
mmcf/d(4) and 3.4 mmcf/d(5) respectively. The
Croatian well tested at a rate of 15.0 mmcf/d(6).
- Subsequent to the end of the second quarter, we were awarded
two exploration licenses in Ukraine, subject to finalization of production
sharing agreements, in partnership with Ukrgazvydobuvannya ("UGV",
a Ukrainian state owned gas producer). The licenses cover
approximately 585,000 gross acres in the Dnieper-Donets Basin, one
of the most prolific natural gas regions in Europe.
- In the United States, Q2 2019
production averaged 4,414 boe/d, an increase of 21% from the prior
quarter, primarily driven by contributions from our first half 2019
Hilight drilling program. Production performance from the drilling
program is above our type curves.
- In Australia, production
averaged 6,689 bbl/d in Q2 2019, an increase of 14% from the
previous quarter, primarily due to contributions from the two (2.0
net) well drilling program completed at the end of January 2019.
- In France, Q2 2019 production
averaged 9,800 boe/d, a 15% decrease from the prior quarter. The
decrease resulted from curtailment of our production in the
Paris Basin as a result of an
unplanned outage at the Grandpuits refinery, where all of our
Paris Basin production is
processed. The refinery was returned to service in late July and
has now resumed accepting our oil deliveries. During the refinery
outage, we utilized trucks and barges to ship a portion of our oil
production to alternate delivery points in France and Germany.
- On June 12, 2019, Vermilion
entered into a series of cross currency interest rate swaps with a
syndicate of banks, financially swapping the remaining term of our
5.625% US$300 million senior
unsecured notes due March 15, 2025
into a €265 million obligation bearing interest at 3.275%. At
current foreign exchange rates, this swap is expected to reduce our
annual cash interest costs by approximately $9 million.
- Our Board of Directors has authorized an application to the TSX
to implement a normal course issuer bid ("NCIB") for a maximum
amount of 5% of the issued and outstanding shares of Vermilion,
which we plan to use as an additional means of returning capital to
shareholders under appropriate market conditions. The NCIB is
intended to augment our dividend, with excess free cash flow
allocated to a combination of debt reduction and share
buybacks.
- Vermilion was recently rated "AA" in MSCI's annual ESG rankings
for 2019, placing us in the top 19% of oil and gas companies
worldwide. This rating is an improvement from "A" in the previous
two years, and is driven by our determination to be the leader in
ESG in the energy industry.
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(1)
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Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section
of the accompanying Management's Discussion and
Analysis.
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(2)
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Burgmoor Z5 well (46%
working interest) tested at a final flow rate of 8.8 mmcf/d at a
flowing wellhead pressure of 431 psi, with the rate limited by
weather conditions during a 30 hour clean-up flow. The well
produced at a final rate of 480 bbls/d of drilling and completion
load fluid during clean-up operations, but is not expected to
produce meaningful amounts of formation water under long-term
producing conditions. The flowing wellhead pressure continued
to increase during the clean-up period and was 431 psi immediately
prior to being shut-in. The well encountered 125 feet of net
pay in the Permian Zechstein Carbonate from 11,014-11,276
feet. Test results are not necessarily indicative of
long-term performance or ultimate recovery.
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(3)
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Hajdubagos-01 well
(100% working interest) tested at a flow rate of 1.4 mmcf/d of
natural gas with 55 barrels per day of 60° API condensate with no
formation water during a 12 hour flow test on a 0.374 inch choke
with a stabilized flowing wellhead pressure of 590 psi. The
well encountered 15 feet of net pay in an Upper Miocene Pannonian
sandstone at depths from 6,517-6,550 feet. Test results are
not necessarily indicative of long-term performance or ultimate
recovery.
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(4)
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Mh-21 well (30%
working interest) tested at a flow rate of 2.0 mmcf/d with no
formation water during a six hour flow test with a stabilized
flowing wellhead pressure of 543 psi on a 0.43 inch choke.
The well encountered 26 feet of net pay in an Upper Miocene
Pannonian sandstone at depths from 2,901-2,930 feet.
Test results are not necessarily indicative of long-term
performance or ultimate recovery.
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(5)
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Battonya E-09 well
(100% working interest) tested at a flow rate of 3.4 mmcf/d with no
formation water during an eight hour flow test with a stabilized
flowing wellhead pressure of 739 psi on a 0.47 inch choke.
The well encountered 17 feet of net pay in an Upper Miocene
Pannonian sandstone from 2,448-2,476 feet. Test results are
not necessarily indicative of long-term performance or ultimate
recovery.
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(6)
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Ceric-01 well (100%
working interest) tested at a final flow rate of 15.0 mmcf/d at a
stabilized flowing wellhead pressure of 851 psi on a 0.86 inch
diameter choke during a one hour flow period following
perforating. An additional 18 hour flow test was later
conducted at reduced rates to limit flaring. During this
test, the well flowed at a rate of 6.2 mmcf/d at a stabilized
flowing pressure of 1,376 psi on a 0.37 inch choke. No
formation water was produced during the tests. The well
encountered 32 feet of net pay in two Upper Miocene Pannonian
sandstones from 3,346-3,353 and 3,828-3,861 feet. Only the
lower zone was tested. Test results are not necessarily
indicative of long-term performance or ultimate
recovery.
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($M except as
indicated)
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Q2
2019
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Q1
2019
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Q2
2018
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YTD
2019
|
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YTD
2018
|
Financial
|
|
|
|
|
|
|
|
|
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Petroleum and natural
gas sales
|
428,043
|
|
481,083
|
|
394,498
|
|
909,126
|
|
712,767
|
Fund flows from
operations
|
222,738
|
|
253,572
|
|
195,190
|
|
476,310
|
|
355,605
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Fund flows from operations ($/basic share)
(1)
|
1.44
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|
1.66
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|
1.45
|
|
3.10
|
|
2.77
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Fund flows from operations ($/diluted share)
(1)
|
1.42
|
|
1.64
|
|
1.43
|
|
3.07
|
|
2.73
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Net earnings
(loss)
|
2,004
|
|
39,547
|
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(61,364)
|
|
41,551
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(36,624)
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Net earnings (loss) ($/basic share)
|
0.01
|
|
0.26
|
|
(0.46)
|
|
0.27
|
|
(0.28)
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Capital
expenditures
|
92,607
|
|
202,053
|
|
79,984
|
|
294,660
|
|
208,449
|
Acquisitions
|
8,623
|
|
16,027
|
|
1,465,485
|
|
24,650
|
|
1,558,563
|
Asset retirement
obligations settled
|
4,907
|
|
3,597
|
|
2,626
|
|
8,504
|
|
6,217
|
Cash dividends
($/share)
|
0.690
|
|
0.690
|
|
0.690
|
|
1.380
|
|
1.335
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Dividends
declared
|
106,884
|
|
105,549
|
|
98,604
|
|
212,433
|
|
177,609
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%
of fund flows from operations
|
48%
|
|
42%
|
|
51%
|
|
45%
|
|
50%
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Net dividends
(1)
|
98,111
|
|
98,445
|
|
78,629
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|
196,556
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137,993
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%
of fund flows from operations
|
44%
|
|
39%
|
|
40%
|
|
41%
|
|
39%
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Payout
(1)
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195,625
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304,095
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161,239
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|
499,720
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|
352,659
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%
of fund flows from operations
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88%
|
|
120%
|
|
83%
|
|
105%
|
|
99%
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Net debt
|
1,950,509
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2,000,144
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1,796,807
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1,950,509
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1,796,807
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Ratio of net debt to
annualized fund flows from operations
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2.19
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|
1.97
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|
2.30
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|
2.05
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|
2.53
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Operational
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Production
|
|
|
|
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Crude oil and condensate (bbls/d)
|
48,964
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|
49,181
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34,574
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|
49,072
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|
30,812
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NGLs (bbls/d)
|
8,107
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|
7,897
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|
5,651
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|
8,002
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|
5,390
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Natural gas (mmcf/d)
|
275.60
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|
277.96
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|
242.40
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|
276.77
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|
235.34
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Total (boe/d)
|
103,003
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|
103,404
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|
80,625
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|
103,203
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|
75,425
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Average realized
prices
|
|
|
|
|
|
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Crude oil and condensate ($/bbl)
|
79.46
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|
73.45
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|
87.50
|
|
76.36
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|
84.32
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NGLs ($/bbl)
|
11.25
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|
22.49
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|
26.06
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|
16.76
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|
25.73
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Natural gas ($/mcf)
|
3.09
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|
5.10
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|
4.77
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|
4.09
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|
5.27
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Production mix (% of
production)
|
|
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%
priced with reference to WTI
|
38%
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37%
|
|
29%
|
|
37%
|
|
25%
|
%
priced with reference to Dated Brent
|
18%
|
|
18%
|
|
21%
|
|
19%
|
|
23%
|
%
priced with reference to AECO
|
26%
|
|
26%
|
|
26%
|
|
26%
|
|
26%
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%
priced with reference to TTF and NBP
|
18%
|
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19%
|
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24%
|
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18%
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26%
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Netbacks
($/boe)
|
|
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Operating netback (1)
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29.62
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31.50
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|
33.03
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|
30.57
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|
32.22
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Fund flows from operations netback
|
24.15
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|
26.76
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|
26.58
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|
25.46
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|
26.20
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Operating expenses
|
11.04
|
|
12.92
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|
10.75
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|
11.99
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|
10.82
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General and administration expenses
|
1.70
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|
1.38
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|
1.93
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|
1.54
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|
1.91
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Average reference
prices
|
|
|
|
|
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WTI (US $/bbl)
|
59.81
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|
54.90
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|
67.88
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|
57.36
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|
65.37
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Edmonton Sweet index (US $/bbl)
|
55.19
|
|
50.05
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|
62.43
|
|
52.62
|
|
59.70
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Saskatchewan LSB index (US $/bbl)
|
55.54
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|
50.84
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|
61.84
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|
53.19
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|
59.23
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Dated Brent (US $/bbl)
|
68.82
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|
63.20
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|
74.35
|
|
66.01
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|
70.55
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AECO ($/mcf)
|
1.03
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|
2.62
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|
1.18
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|
1.83
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|
1.63
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NBP ($/mcf)
|
5.44
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|
8.33
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|
9.42
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|
6.89
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|
9.69
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TTF ($/mcf)
|
5.75
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|
8.14
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|
9.50
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|
6.94
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|
9.54
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Average foreign
currency exchange rates
|
|
|
|
|
|
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CDN $/US $
|
1.34
|
|
1.33
|
|
1.29
|
|
1.33
|
|
1.28
|
CDN $/Euro
|
1.50
|
|
1.51
|
|
1.54
|
|
1.51
|
|
1.55
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Share information
('000s)
|
Shares outstanding -
basic
|
155,032
|
|
153,213
|
|
152,363
|
|
155,032
|
|
152,363
|
Shares outstanding -
diluted (1)
|
158,633
|
|
156,650
|
|
155,355
|
|
158,633
|
|
155,355
|
Weighted average
shares outstanding - basic
|
154,795
|
|
152,904
|
|
134,603
|
|
153,855
|
|
128,531
|
Weighted average
shares outstanding - diluted (1)
|
156,844
|
|
154,550
|
|
136,559
|
|
155,335
|
|
130,224
|
(1) The above table includes
non-GAAP financial measures which may not be comparable to other
companies. Please see the "Non-GAAP Financial Measures"
section of the accompanying Management's Discussion and
Analysis.
|
Message to Shareholders
During the second quarter, we conducted our most active
exploration drilling program in Europe in the history of the company.
Over the past four months, we have drilled one exploration well in
Germany and five exploration wells
in our Central and Eastern European ("CEE") business unit, with
successes on all but one well in Hungary. This drilling
campaign was preceded by several years of careful implementation of
our new country entry strategy. We entered Germany in 2014 and initially focused on
expanding our land position through various acquisitions, farm-ins
and government concessions, and we now have approximately 1.2
million net acres of land, comprising about one-quarter of the
prolific North German Basin. The first few years were focused
on building our team and executing on low risk development
opportunities on the existing producing assets while evaluating
future exploration and development prospects. Following the
successful completion of our first operated drilling in
Germany this summer, we now plan
to drill at least one exploration well in Germany each year over the next several years,
targeting other sizable gas prospects in the basin.
We followed a similar approach when we entered Central and
Eastern Europe later in
2014. We acquired land in the Pannonian Basin in Hungary, Croatia and Slovakia through various government
concessions and deals with industry partners. Our initial
focus was on building our knowledge of the basin and operating
environment, while acquiring and evaluating seismic to identify
future drilling prospects. This summer's drilling program has
yielded four conventional discoveries in Hungary and Croatia in five exploratory attempts. We
look forward to executing the remainder of our Croatian program and
to initiating our Slovakian program later this year.
Subsequent to the second quarter, we further expanded our CEE
presence as we were awarded two exploration licenses in
Ukraine in partnership with
Ukrgazvydobuvannya ("UGV", a Ukrainian state owned gas producer) in
the prolific Dnieper-Donets Basin. These two licenses are in
close proximity to several multi-TCF gas fields with most of the
basin (and awarded license areas) still not covered by 3D
seismic. Entering Ukraine aligns with our strategy to
capitalize on opportunities in under-exploited basins by using
modern technologies to improve success rates and recovery.
In addition to our Germany and
CEE exploration drilling programs, we are also currently preparing
to drill the first well (0.5 net) of our two (1.0 net) well 2019
program in the Netherlands after
having received permits for these wells in the second
quarter. Netherlands
continues to be a strong free cash flow generating business and we
look forward to resuming drilling there after a two-year
hiatus.
Our second quarter results were negatively impacted by a
third-party refinery outage in France which reduced production and forced us
to find alternate transportation methods and delivery points for
our oil in the Paris Basin, which
is the larger of our two producing regions in the country.
Our French team did an exceptional job of contracting for alternate
delivery points for most of our production, and conducting the
required long-haul trucking and barging in a safe manner.
Despite the refinery outage, which impacted quarterly production
volumes by approximately 1,300 boe/d and FFO by approximately
$11 million, we recorded corporate
production of approximately 103,000 boe/d, little changed from the
previous quarter.
We recorded FFO of $223 million in
Q2 2019, down 12% from the prior quarter. In addition to the
France refinery impact, the
primary drivers for this lower FFO were the timing of crude lifting
in Australia, which resulted in an
inventory build and lower sales volumes ($8
million impact), and weaker natural gas prices in
Europe and North America ($33
million impact).
We were able to mitigate a portion of this pricing variance
through our hedging program, particularly in European gas,
realizing a $14 million pre-tax gain
during the quarter. European gas prices weakened this summer
due to increased LNG deliveries. However, we have locked in
pricing on approximately 70% of our summer European gas at
significantly higher prices than the spot price. The forward
price for European gas remains in strong contango compared to the
front month price, with the calendar 2020 strip for NBP at
approximately $8.50/mmbtu, and
calendar year strips for the next three years are currently trading
within approximately 1% of where they were one year ago.
While our fundamental view on European gas is that the forward
market realistically reflects supply and demand drivers, we are
willing to lock in this curve and attendant strong levels of free
cash flow and expected project economics. Accordingly, we
have already hedged 65% of our expected 2020 European gas
production, with hedges continuing at lower percentages on into
2022.
Since 2003, Vermilion has had a track record of returning
capital to shareholders through our monthly dividend (previously a
cash distribution during the trust era). This distribution
and dividend stream has been increased four times and has never
been reduced. We also recognize that other forms of returning
capital to shareholders, such as share buybacks, may be appropriate
to complement our dividend in certain market conditions. With
this in mind, our Board of Directors has authorized an application
to the TSX to implement a normal course issuer bid ("NCIB") for a
maximum amount of 5% of the issued and outstanding shares of
Vermilion. We intend to use the NCIB to return capital to our
shareholders, augmenting our current return of cash through
dividends. We will also continue to allocate a portion of
excess free cash flow to debt reduction.
Q2 2019 Operations Review
Europe
In France, Q2 2019 production
averaged 9,800 boe/d, a decrease of 15% from the prior
quarter. Our production in the Paris Basin was temporarily curtailed as a
result of a third party refinery outage due to a failure on the
refinery's main feedstock line. The Grandpuits refinery, where
all of our Paris Basin production
is processed, returned to service in late July, and has resumed
processing Vermilion deliveries. During the refinery outage,
we made arrangements to ship most of our oil to alternate delivery
points in France and Germany utilizing trucks and barges. The
net impact from the refinery outage reduced our Q2 2019 production
volumes by approximately 1,300 boe/d and after-tax FFO by
approximately $11 million
($0.07/share) from reduced sales and
higher transportation expense. In addition, approximately
$2 million in capital investment was
required to put truck and barge loading equipment in place.
In the Netherlands, Q2 2019
production averaged 8,917 boe/d, an increase of 3% from the prior
quarter. The increase is primarily due to the successful
completion of our first half 2019 workover and facility maintenance
program, which was partially offset by minor downtime. During
the second quarter we received the draft drilling permit for the
Waalwijk South well (0.5 net), the second well in our planned 2019
drilling program. We recently began site construction for the
first well of our 2019 program, the Weststellingwerf well (0.5
net), which is expected to commence drilling in August 2019.
Drilling of the Waalwijk South well is expected to begin in Q4
2019.
In Ireland, production averaged
49 mmcf/d (8,201 boe/d) in Q2 2019, a decrease of 4.8% from the
prior quarter. The decrease was due to natural decline and
minor unplanned downtime at the Corrib natural gas processing
facility. Since we took over as operator of the Corrib
Project late in 2018, operating costs have decreased 14% over the
comparative six-month period. At present, our efforts are
focused on evaluating future facility and drilling projects, and
optimizing our maintenance activities, including a scheduled plant
turnaround in Q3 2019.
In Germany, production in Q2
2019 averaged 3,474 boe/d, a decrease of 8% from the prior
quarter. The decrease is primarily due to unplanned downtime
on several operated and non-operated assets, which was partially
offset by a full quarter contribution from various well workovers
performed on our operated oil assets earlier this year.
During the quarter, we completed drilling our first
exploratory well in Germany, the
Burgmoor Z5 well (46% working interest). The well reached a
measured depth of 11,480 feet and encountered 125 feet of net pay
in the Zechstein carbonate. The well was tested at the end of
July at a final flow rate of 8.8 mmcf/d(2) limited by
weather conditions. The Burgmoor Z5 well has been turned over
to ExxonMobil as operator during the testing and production
phases. We also completed and brought on production a
non-operated coil tubing sidetrack (0.25 net) during the
quarter.
In Central and Eastern Europe,
we drilled four (3.3 net) exploration wells during Q2 2019, and one
(1.0 net) subsequent to the end of the quarter. Four of these
wells resulted in new gas discoveries. In Hungary, we drilled four (3.3 net) exploration
wells, the first (1.0 net) of which was dry. The second well
(1.0 net) of our 2019 Hungary drilling program encountered 15 feet
of net gas pay and tested at a rate of 1.4 mmcf/d and 55
bbls/d(3) of condensate. The third well (0.3 net)
encountered 26 feet of net gas pay, and tested at a rate of 2.0
mmcf/d(4) in July. The fourth Hungarian well (1.0
net) was drilled and tested in July, encountering 17 feet of net
gas pay and testing at 3.4 mmcf/d(5). In
Croatia, we drilled our first
natural gas exploration well (1.0 net) in the country which
encountered 32 feet of net gas pay in two zones. Subsequent
to the end of the quarter, it tested 15.0 mmcf/d(6) from
the lower zone.
Subsequent to the end of the second quarter, we were awarded two
exploration licenses in Ukraine,
subject to a final production sharing agreement, in a 50/50
partnership with Ukrgazvydobuvannya ("UGV", a Ukrainian state owned
gas producer). The licenses cover approximately 585,000 gross
acres situated in one of Europe's
most prolific natural gas regions (Dnieper-Donets Basin). The
new licenses are in close proximity to several multi-TCF gas fields
with most of the basin (and awarded license areas) still uncovered
by 3D seismic. The terms of the licenses include a modest
capital commitment, back-loaded over a five-year time frame.
North America
In Canada, production averaged
61,507 boe/d in Q2 2019, up slightly from the prior quarter.
The increase was primarily due to the contribution from our first
quarter drilling program in Saskatchewan and Alberta, partially offset by unplanned
facility downtime and less drilling activity in the second quarter
due to spring breakup. We drilled or participated in 28 (22.9
net) wells in the second quarter of 2019, including 27 (22.4 net)
wells in Saskatchewan and one (0.5
net) Mannville well in
Alberta. We brought six (6.0 net) wells on production in
Saskatchewan and one (1.0 net)
well in Alberta during the
quarter. During the second half of the year, we plan to drill
73 (62.7 net) wells in Saskatchewan and six (4.2 net) wells in
Alberta, in addition to completing
several plant turnarounds in Alberta in Q3 2019. We are currently
operating four drilling rigs in Saskatchewan, but have been delayed in
resuming Alberta activity due to
wet weather conditions.
In the United States, Q2 2019
production averaged 4,414 boe/d, representing an increase of 21%
from the prior quarter. The increase was primarily driven by
production contributions from our first half 2019 Hilight drilling
campaign, in which four (4.0 net) wells were completed and brought
on production during the quarter. The first two wells were
equipped with rod pumps and brought on production in
mid-April. These wells have performed ahead of our
expectations, producing in excess of our rod-pump type curve
through the end of the quarter, and achieving an average peak IP30
rate of approximately 325 boe/d to date, with production still on a
modest incline in one of the wells. The two subsequent wells
were equipped with electric submersible pumps ("ESP") and were
brought on production in mid-May. These two wells have also
performed ahead of our expectations by approximately 150 bbls/d on
average, while achieving an average peak IP30 rate of approximately
635 boe/d per well. We recently mobilized a rig that we had
been using on our Canadian operations to Wyoming for our remaining (4.0 net) Hilight
wells planned for this year. The fifth well of the program
was spud toward the end of Q2 2019 and was drilled in less than 12
days, representing a 28% improvement over the fastest H1 2019
well. Since taking over operatorship last year, we have
achieved a 15% reduction in DCET costs, and expect another 10%
improvement in the remaining wells this year.
Australia
In Australia, production
averaged 6,689 bbl/d in Q2 2019, an increase of 14% from the
previous quarter primarily due to contributions from the two (2.0
net) well drilling program completed at the end of January
2019. We continue to manage our Australian production to our
annual production target of 6,000 bbl/d.
Cross Currency Interest Rate Swaps
On June 12, 2019, Vermilion
entered into a series of cross currency interest rate swaps with a
syndicate of banks, financially swapping the remaining term of our
5.625% US$300 million senior
unsecured notes due March 2025 into a
€265 million obligation bearing interest at 3.275%. At
current foreign exchange rates, this swap is expected to reduce our
annual cash interest costs by approximately $9 million.
Credit Rating
On July 26, 2019, Fitch Ratings
initiated a credit rating for Vermilion. The corporate
first-time Long-Term Issuer Default Rating was initiated at a BB-
with a stable outlook and the BB- rating was assigned to the issued
and outstanding senior unsecured notes due March 2025.
Normal Course Issuer Bid
Our Board of Directors has authorized an application to the TSX
to implement a normal course issuer bid ("NCIB") for a maximum
amount of 5% of the issued and outstanding shares of Vermilion,
which we plan to use as an additional means of returning capital to
shareholders under appropriate market conditions. The NCIB is
intended to augment our ongoing return of capital via
dividends. We plan to allocate excess free cash flow beyond
our dividend stream to both debt reduction and buybacks.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and
increase the stability of our cash flows, providing additional
certainty with regard to the execution of our dividend and capital
programs. In aggregate, as of July 25,
2019, we currently have 40% of our expected net-of-royalty
production hedged for Q3 2019. More than half of our Q3 2019
corporate hedge position consists of two-way collars and three-way
structures, which allow participation in price increases up to
contract ceilings. For 2020, approximately 70% of our hedge
position is in participating structures.
We have currently hedged 71% of anticipated European natural gas
volumes for Q3 2019. We have also hedged 69% and 65% of our
anticipated full-year 2019 and 2020 European natural gas volumes,
respectively, at prices which are expected to provide for strong
project economics and free cash flows. At present, 33% of
both our expected Q3 2019 and Q4 2019 oil production is
hedged. For Q3 2019, 45% of our North American natural gas
production is priced away from AECO, due to diversification hedges
to financially sell at the SoCal Border and at Henry Hub for a
portion of our Alberta natural gas
production, and because 15% of our North American gas production is
located in Saskatchewan and
Wyoming.
Sustainability
Vermilion was recently rated "AA" in MSCI's annual ESG rankings
for 2019, placing us in the top 19% of oil and gas companies
worldwide. This rating is an improvement from "A" in the
previous two years. MSCI ESG Research LLC is the world's
largest provider of ESG ratings and research, rating over 13,000
equity and income issuers. Its research is used globally to
help investors understand how ESG factors can impact the long-term
risk and return profile of their investments. Our increased
rating is the result of improving company ESG performance and
enhanced disclosure on topics relevant to MSCI's detailed
assessment process.
Organizational Update
Mr. Kyle Preston, previously our
Director of Investor Relations, has been promoted to the position
of Vice President of Investor Relations. He joined Vermilion
in 2016 and has over 20 years of experience in oil and gas finance,
including 13 years as an equity research analyst. Mr. Preston
has played a key role in developing and executing our
differentiated capital markets strategy. He holds the
Chartered Financial Analyst® and Certified Management Accountant
designations and earned a Bachelor of Commerce degree from the
University of Manitoba.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
July 25, 2019
(1)
|
Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section
of the accompanying Management's Discussion and
Analysis.
|
|
|
(2)
|
Burgmoor Z5 well (46%
working interest) tested at a final flow rate of 8.8 mmcf/d at a
flowing wellhead pressure of 431 psi, with the rate limited by
weather conditions during a 30 hour clean-up flow. The well
produced at a final rate of 480 bbls/d of drilling and completion
load fluid during clean-up operations, but is not expected to
produce meaningful amounts of formation water under long-term
producing conditions. The flowing wellhead pressure continued
to increase during the clean-up period and was 431 psi immediately
prior to being shut-in. The well encountered 125 feet of net
pay in the Permian Zechstein Carbonate from 11,014-11,276
feet. Test results are not necessarily indicative of
long-term performance or ultimate recovery.
|
|
|
(3)
|
Hajdubagos-01 well
(100% working interest) tested at a flow rate of 1.4 mmcf/d of
natural gas with 55 barrels per day of 60° API condensate with no
formation water during a 12 hour flow test on a 0.374 inch choke
with a stabilized flowing wellhead pressure of 590 psi. The
well encountered 15 feet of net pay in an Upper Miocene Pannonian
sandstone at depths from 6,517-6,550 feet. Test results are
not necessarily indicative of long-term performance or ultimate
recovery.
|
|
|
(4)
|
Mh-21 well (30%
working interest) tested at a flow rate of 2.0 mmcf/d with no
formation water during a six hour flow test with a stabilized
flowing wellhead pressure of 543 psi on a 0.43 inch choke.
The well encountered 26 feet of net pay in an Upper Miocene
Pannonian sandstone at depths from 2,901-2,930 feet.
Test results are not necessarily indicative of long-term
performance or ultimate recovery.
|
|
|
(5)
|
Battonya E-09 well
(100% working interest) tested at a flow rate of 3.4 mmcf/d with no
formation water during an eight hour flow test with a stabilized
flowing wellhead pressure of 739 psi on a 0.47 inch choke.
The well encountered 17 feet of net pay in an Upper Miocene
Pannonian sandstone from 2,448-2,476 feet. Test results are
not necessarily indicative of long-term performance or ultimate
recovery.
|
|
|
(6)
|
Ceric-01 well (100%
working interest) tested at a final flow rate of 15.0 mmcf/d at a
stabilized flowing wellhead pressure of 851 psi on a 0.86 inch
diameter choke during a one hour flow period following
perforating. An additional 18 hour flow test was later
conducted at reduced rates to limit flaring. During this
test, the well flowed at a rate of 6.2 mmcf/d at a stabilized
flowing pressure of 1,376 psi on a 0.37 inch choke. No
formation water was produced during the tests. The well
encountered 32 feet of net pay in two Upper Miocene Pannonian
sandstones from 3,346-3,353 and 3,828-3,861 feet. Only the
lower zone was tested. Test results are not necessarily
indicative of long-term performance or ultimate
recovery.
|
Guidance
On October 25, 2018, we released
our 2019 capital budget and related guidance. On February 27, 2019, we deferred some activity to
later in the year and reallocated capital between business units,
although the 2019 total budget and production guidance remained
unchanged.
The following table summarizes our guidance:
|
|
|
|
|
|
|
Date
|
|
Capital
Expenditures ($MM)
|
|
Production
(boe/d)
|
2019
Guidance
|
|
|
|
|
|
2019
Guidance
|
October 25,
2018
|
|
530
|
|
101,000 to
106,000
|
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call and
webcast presentation on Monday, July 29,
2019 at 9:00 AM MST
(11:00 AM EST). To participate,
call 1-888-231-8191 (Canada and US
Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the
conference call will be available for replay by calling
1-855-859-2056 and using the conference ID 4454959 from
July 29, 2019 at 12:00 MST to August 12,
2019 at 21:59 MST.
You may also access the webcast
at https://event.on24.com/wcc/r/2034202/D763FFCE3D2CBFC02220C1DD1B0A63FB.
The webcast link, along with conference call slides, can be found
on Vermilion's website at
http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm
under Upcoming Events prior to the conference call.
About Vermilion
Vermilion is an international energy producer that seeks to
create value through the acquisition, exploration, development and
optimization of producing properties in North America, Europe and Australia. Our business model
emphasizes organic production growth augmented with value-adding
acquisitions, along with providing reliable and increasing
dividends to investors. Vermilion is targeting growth in
production primarily through the exploitation of light oil and
liquids-rich natural gas conventional resource plays in
Canada and the United States, the exploration and
development of high impact natural gas opportunities in
the Netherlands and Germany, and through oil drilling and workover
programs in France and
Australia. Vermilion holds a 20% working interest in the
Corrib gas field in Ireland. Vermilion pays a monthly
dividend of Canadian $0.23 per share,
which provides a current yield of approximately 11.5%.
Vermilion's priorities are health and safety, the environment,
and profitability, in that order. Nothing is more important
to us than the safety of the public and those who work with us, and
the protection of our natural surroundings. We have been
recognized as a top decile performer amongst Canadian publicly
listed companies in governance practices, as a Climate Leadership
level (A-) performer by the CDP, and a Best Workplace in the Great
Place to Work® Institute's annual rankings in Canada, the
Netherlands and Germany. In addition, Vermilion
emphasizes strategic community investment in each of our operating
areas.
Employees and directors hold approximately 5% of our fully
diluted shares, are committed to consistently delivering superior
rewards for all stakeholders, and have delivered over 20 years of
market outperformance. Vermilion trades on the Toronto Stock
Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this
document may constitute forward looking statements or financial
outlooks under applicable securities legislation. Such
forward looking statements or information typically contain
statements with words such as "anticipate", "believe", "expect",
"plan", "intend", "estimate", "propose", or similar words
suggesting future outcomes or statements regarding an
outlook. Forward looking statements or information in this
document may include, but are not limited to: capital expenditures;
business strategies and objectives; operational and financial
performance; estimated reserve quantities and the discounted net
present value of future net revenue from such reserves; petroleum
and natural gas sales; future production levels (including the
timing thereof) and rates of average annual production growth;
exploration and development plans; acquisition and disposition
plans and the timing thereof; operating and other expenses,
including the payment and amount of future dividends; royalty and
income tax rates; and the timing of regulatory proceedings and
approvals.
Such forward looking statements or information are based on a
number of assumptions, all or any of which may prove to be
incorrect. In addition to any other assumptions identified in
this document, assumptions have been made regarding, among other
things: the ability of Vermilion to obtain equipment, services and
supplies in a timely manner to carry out its activities in
Canada and internationally; the
ability of Vermilion to market crude oil, natural gas liquids, and
natural gas successfully to current and new customers; the timing
and costs of pipeline and storage facility construction and
expansion and the ability to secure adequate product
transportation; the timely receipt of required regulatory
approvals; the ability of Vermilion to obtain financing on
acceptable terms; foreign currency exchange rates and interest
rates; future crude oil, natural gas liquids, and natural gas
prices; and management's expectations relating to the timing and
results of exploration and development activities.
Although Vermilion believes that the expectations reflected in
such forward looking statements or information are reasonable,
undue reliance should not be placed on forward looking statements
because Vermilion can give no assurance that such expectations will
prove to be correct. Financial outlooks are provided for the
purpose of understanding Vermilion's financial position and
business objectives, and the information may not be appropriate for
other purposes. Forward looking statements or information are
based on current expectations, estimates, and projections that
involve a number of risks and uncertainties which could cause
actual results to differ materially from those anticipated by
Vermilion and described in the forward looking statements or
information. These risks and uncertainties include, but are
not limited to: the ability of management to execute its business
plan; the risks of the oil and gas industry, both domestically and
internationally, such as operational risks in exploring for,
developing and producing crude oil, natural gas liquids, and
natural gas; risks and uncertainties involving geology of crude
oil, natural gas liquids, and natural gas deposits; risks inherent
in Vermilion's marketing operations, including credit risk; the
uncertainty of reserves estimates and reserves life and estimates
of resources and associated expenditures; the uncertainty of
estimates and projections relating to production and associated
expenditures; potential delays or changes in plans with respect to
exploration or development projects; Vermilion's ability to enter
into or renew leases on acceptable terms; fluctuations in crude
oil, natural gas liquids, and natural gas prices, foreign currency
exchange rates and interest rates; health, safety, and
environmental risks; uncertainties as to the availability and cost
of financing; the ability of Vermilion to add production and
reserves through exploration and development activities; the
possibility that government policies or laws may change or
governmental approvals may be delayed or withheld; uncertainty in
amounts and timing of royalty payments; risks associated with
existing and potential future law suits and regulatory actions
against Vermilion; and other risks and uncertainties described
elsewhere in this document or in Vermilion's other filings with
Canadian securities regulatory authorities.
The forward looking statements or information contained in this
document are made as of the date hereof and Vermilion undertakes no
obligation to update publicly or revise any forward looking
statements or information, whether as a result of new information,
future events, or otherwise, unless required by applicable
securities laws.
This document contains metrics commonly used in the oil and gas
industry. These oil and gas metrics do not have any
standardized meaning or standard methods of calculation and
therefore may not be comparable to similar measures presented by
other companies where similar terminology is used and should
therefore not be used to make comparisons. Natural gas
volumes have been converted on the basis of six thousand cubic feet
of natural gas to one barrel of oil equivalent. Barrels of
oil equivalent (boe) may be misleading, particularly if used in
isolation. A boe conversion ratio of six thousand cubic feet
to one barrel of oil is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
Financial data contained within this document are reported in
Canadian dollars, unless otherwise stated.
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SOURCE Vermilion Energy Inc.