CALGARY, Oct. 31, 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 nine months ended September 30, 2019.
The unaudited financial statements and management discussion and
analysis for the three and nine months
ended September 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
- Q3 2019 production averaged 97,239 boe/d, a decrease of 6% from
the prior quarter. The lower production level resulted from a
number of plant turnarounds, unplanned downtime, and weather
delays. Higher production in the US and France was more than offset by lower
production in Canada, Netherlands, Ireland and Australia.
- We have reduced our 2019 capital investment guidance by
$10 million to $520 million. With nine months of results in
place, we are revising our 2019 annual production guidance range to
100,000 to 101,000 boe/d to account for the unplanned downtime and
lower capital investment. We expect to deliver annual production at
the mid-point of this revised guidance range, reflecting strong
year-over-year production per share growth of 5%.
- Fund flows from operations ("FFO") for Q3 2019 was $216 million ($1.39/basic share(1)), a decrease of
3% from the previous quarter, primarily due to lower production
volumes and weaker commodity prices. FFO for Q3 2019 decreased 17%
from the same quarter last year as increased production was more
than offset by weaker global commodity pricing.
- In the United States, Q3 2019
production averaged 4,925 boe/d, an increase of 12% from the prior
quarter, primarily driven by contributions from our 2019 drilling
program, which continues to perform above our expectations. New
well results were partially offset by a longer-than-expected
turnaround at a third-party operated gas plant.
- In Central and Eastern Europe,
we drilled one (1.0 net) exploration well in Croatia during Q3 2019, which resulted in a
second consecutive gas discovery. The well tested at a rate of 17.2
mmcf/d(2). We were also provisionally awarded the SA-07
license in Croatia, adding
approximately 500,000 net acres to our portfolio, which will bring
our total licensed acreage to approximately 2.4 million net acres
in the country.
- In France, Q3 2019 production
averaged 10,347 boe/d, an increase of 6% from the prior quarter.
Production volumes in the Paris
Basin were no longer restricted after restart of the Grandpuits
refinery in mid-August.
- In Canada, Q3 2019 production
averaged 58,504 boe/d, a decrease of 5% from the prior quarter. The
decrease was primarily due to planned turnarounds and project
delays caused by abnormally wet weather.
- In the Netherlands, Q3 2019
production averaged 7,429 boe/d, a decrease of 17% from the prior
quarter, primarily due to a planned turnaround and subsequent
repairs required on a gas compression facility.
- In Ireland, Q3 2019 production
averaged 43 mmcf/d (7,202 boe/d), a decrease of 12% from the prior
quarter. The decrease was primarily due to a planned plant
turnaround and unplanned downtime at the Corrib natural gas
processing facility. The downtime, which was unrelated to the plant
turnaround, was remedied by early October.
- In Australia, Q3 2019
production averaged 5,564 bbl/d, a decrease of 17% from the
previous quarter primarily due to well management and unplanned
vessel maintenance on the Wandoo platform.
- Our Board of Directors has approved a 2020 Exploration and
Development ("E&D") capital budget of $450 million, with associated production guidance
of 100,000 to 103,000 boe/d. Our 2020 budget reflects continued
emphasis on returning capital to investors, while still providing
modest production growth. Within this budget, we also continue to
advance strategic capital projects associated with early-stage
exploration and development activities.
- We have elected to phase out the Dividend Reinvestment Plan
("DRIP"), prorating the available DRIP shares by 25% each quarter
starting in Q1 2020, until completely eliminated in Q4 2020.
- Vermilion received top quartile rankings for 2019 for our
industry sector in both the Sustainalytics ESG Rating and SAM
(formerly known as RobecoSAM) annual Corporate Sustainability
Assessment ("CSA"). These agencies analyze sustainability
performance across economic, environmental, governance and social
criteria, and the CSA is also the basis of the Dow Jones
Sustainability Indices. Our 2019 Sustainability Report is available
on our corporate website at:
http://sustainability.vermilionenergy.com.
(1)
|
Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section
of Management's Discussion and Analysis.
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(2)
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Berak-01 well (100%
working interest) tested at a rate of 17.2 mmcf/d during a
four-hour flow period with a stabilized flowing wellhead pressure
of 908 psi on a 0.875 inch diameter choke. A final shut in
wellhead pressure of 1,186 psi was recorded following the flow
test. The flow test continued an additional 12 hours at
reduced choke sizes to minimize flaring. No formation water
was produced during the test. The well logged 21 feet of net
gas pay with an average porosity of 32% from the Upper Miocene
Pannonian sandstone occurring within a gross measured depth
interval of 3,006-3,033 feet. Test results are not
necessarily indicative of long-term performance or ultimate
recovery.
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|
|
|
|
|
|
|
|
|
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($M except as
indicated)
|
Q3
2019
|
|
Q2
2019
|
|
Q3
2018
|
|
|
YTD
2019
|
|
YTD
2018
|
Financial
|
|
|
|
|
|
|
|
|
|
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Petroleum and natural
gas sales
|
391,935
|
|
|
428,043
|
|
|
508,411
|
|
|
|
1,301,061
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|
|
1,221,178
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|
Fund flows from
operations
|
216,153
|
|
|
222,738
|
|
|
260,705
|
|
|
|
692,463
|
|
|
616,310
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|
Fund flows from operations ($/basic share)
(1)
|
1.39
|
|
|
1.44
|
|
|
1.71
|
|
|
|
4.49
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|
|
4.51
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Fund flows from operations ($/diluted share)
(1)
|
1.39
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|
|
1.42
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|
|
1.69
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|
|
|
4.45
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|
|
4.46
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Net earnings
(loss)
|
(10,229)
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|
|
2,004
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|
|
(15,099)
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|
|
|
31,322
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|
|
(51,723)
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Net earnings (loss) ($/basic share)
|
(0.07)
|
|
|
0.01
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|
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(0.10)
|
|
|
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0.2
|
|
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(0.38)
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Capital
expenditures
|
127,879
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|
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92,607
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|
|
146,185
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|
|
|
422,539
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|
|
354,634
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Acquisitions
|
4,657
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|
|
8,623
|
|
|
198,173
|
|
|
|
29,307
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|
|
1,756,736
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Asset retirement
obligations settled
|
3,586
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|
|
4,907
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|
|
2,986
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|
|
|
12,090
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|
|
9,203
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Cash dividends
($/share)
|
0.690
|
|
|
0.690
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|
|
0.690
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|
|
|
2.070
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|
|
2.025
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Dividends
declared
|
107,176
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|
|
106,884
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|
|
105,192
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|
|
|
319,609
|
|
|
282,801
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%
of fund flows from operations
|
50
|
%
|
|
48
|
%
|
|
40
|
%
|
|
|
46
|
%
|
|
46
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%
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Net dividends
(1)
|
98,316
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|
98,111
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100,872
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294,872
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|
238,865
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%
of fund flows from operations
|
45
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%
|
|
44
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%
|
|
39
|
%
|
|
|
43
|
%
|
|
39
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%
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Payout
(1)
|
229,781
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|
|
195,625
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|
|
250,043
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|
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729,501
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|
602,702
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|
%
of fund flows from operations
|
106
|
%
|
|
88
|
%
|
|
96
|
%
|
|
|
105
|
%
|
|
98
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%
|
Net debt
|
2,001,870
|
|
|
1,950,509
|
|
|
2,034,086
|
|
|
|
2,001,870
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|
|
2,034,086
|
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Net debt to trailing
twelve months fund flows from operations
|
2.19
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|
|
2.03
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|
|
2.55
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|
|
|
2.19
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|
|
2.55
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Operational
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Production
|
|
|
|
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|
|
|
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Crude oil and condensate (bbls/d)
|
47,242
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|
|
48,964
|
|
|
47,152
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|
|
|
48,455
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|
|
36,318
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NGLs (bbls/d)
|
7,772
|
|
|
8,107
|
|
|
6,839
|
|
|
|
7,925
|
|
|
5,878
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|
Natural gas (mmcf/d)
|
253.36
|
|
|
275.60
|
|
|
253.38
|
|
|
|
268.88
|
|
|
241.42
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Total (boe/d)
|
97,239
|
|
|
103,003
|
|
|
96,222
|
|
|
|
101,193
|
|
|
82,433
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Average realized
prices
|
|
|
|
|
|
|
|
|
|
|
Crude oil and condensate ($/bbl)
|
73.45
|
|
|
79.46
|
|
|
85.84
|
|
|
|
75.38
|
|
|
84.98
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|
NGLs ($/bbl)
|
6.14
|
|
|
11.25
|
|
|
27.97
|
|
|
|
13.25
|
|
|
26.61
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|
Natural gas ($/mcf)
|
2.43
|
|
|
3.09
|
|
|
5.35
|
|
|
|
3.56
|
|
|
5.30
|
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Production mix (% of
production)
|
|
|
|
|
|
|
|
|
|
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%
priced with reference to WTI
|
39
|
%
|
|
38
|
%
|
|
37
|
%
|
|
|
38
|
%
|
|
30
|
%
|
%
priced with reference to Dated Brent
|
19
|
%
|
|
18
|
%
|
|
18
|
%
|
|
|
18
|
%
|
|
21
|
%
|
%
priced with reference to AECO
|
26
|
%
|
|
26
|
%
|
|
26
|
%
|
|
|
26
|
%
|
|
26
|
%
|
%
priced with reference to TTF and NBP
|
16
|
%
|
|
18
|
%
|
|
19
|
%
|
|
|
18
|
%
|
|
23
|
%
|
Netbacks
($/boe)
|
|
|
|
|
|
|
|
|
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Operating netback (1)
|
28.22
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|
|
29.62
|
|
|
34.85
|
|
|
|
29.80
|
|
|
33.26
|
|
Fund flows from operations netback
|
23.73
|
|
|
24.15
|
|
|
29.69
|
|
|
|
24.89
|
|
|
27.59
|
|
Operating expenses
|
11.55
|
|
|
11.04
|
|
|
11.13
|
|
|
|
11.85
|
|
|
10.94
|
|
General and administration expenses
|
1.50
|
|
|
1.70
|
|
|
1.51
|
|
|
|
1.53
|
|
|
1.75
|
|
Average reference
prices
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
56.45
|
|
|
59.81
|
|
|
69.50
|
|
|
|
57.06
|
|
|
66.75
|
|
Edmonton Sweet index (US $/bbl)
|
51.79
|
|
|
55.19
|
|
|
62.68
|
|
|
|
52.34
|
|
|
60.69
|
|
Saskatchewan LSB index (US $/bbl)
|
52.01
|
|
|
55.54
|
|
|
63.35
|
|
|
|
52.81
|
|
|
60.61
|
|
Dated Brent (US $/bbl)
|
61.94
|
|
|
68.82
|
|
|
75.27
|
|
|
|
64.65
|
|
|
72.13
|
|
AECO ($/mcf)
|
1.06
|
|
|
1.03
|
|
|
1.19
|
|
|
|
1.64
|
|
|
1.48
|
|
NBP ($/mcf)
|
4.50
|
|
|
5.44
|
|
|
10.95
|
|
|
|
6.08
|
|
|
10.12
|
|
TTF ($/mcf)
|
4.40
|
|
|
5.75
|
|
|
10.92
|
|
|
|
6.08
|
|
|
10.00
|
|
Average foreign
currency exchange rates
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $
|
1.32
|
|
|
1.34
|
|
|
1.31
|
|
|
|
1.33
|
|
|
1.29
|
|
CDN $/Euro
|
1.47
|
|
|
1.50
|
|
|
1.52
|
|
|
|
1.49
|
|
|
1.54
|
|
Share information
('000s)
|
Shares outstanding -
basic
|
155,505
|
|
|
155,032
|
|
|
152,497
|
|
|
|
155,505
|
|
|
152,497
|
|
Shares outstanding -
diluted (1)
|
159,260
|
|
|
158,633
|
|
|
155,747
|
|
|
|
159,260
|
|
|
155,747
|
|
Weighted average
shares outstanding - basic
|
155,254
|
|
|
154,795
|
|
|
152,432
|
|
|
|
154,326
|
|
|
136,585
|
|
Weighted average
shares outstanding - diluted (1)
|
155,421
|
|
|
156,844
|
|
|
153,839
|
|
|
|
155,673
|
|
|
138,258
|
|
(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
The third quarter of 2019 continued to be an exceptionally
difficult period for energy investors, as the upstream oil and gas
sector traded down to multi-year lows and significantly
underperformed the broader equity market. Vermilion was not
spared. Our stock price declined over 30% during the quarter,
bringing our current dividend yield to approximately 14%.
While we are certainly disappointed with our share price
performance, we would like to stress that Vermilion's dividend
policy is not based on the market price of our shares. Our
dividend policy is based on the fundamental economic sustainability
and free cash flow generation of our business, which remains
strong.
The capital markets environment for oil and gas companies has
changed dramatically over recent years due to a multitude of
factors, including poor investment returns from energy issuers,
increased focus on ESG and SRI mandates, and a growing concern
about the future of fossil fuels amongst both investors and the
general public. This has led to valuation multiple
compression across the entire sector with many companies, including
Vermilion, trading significantly below their historical valuation
metrics. Despite these changing capital market dynamics, the
oil and gas sector is a vital contributor to the global economy and
will be around for many decades to support the long-term energy
transition. During this transition, we believe there is
significant value to be realized from responsible energy
investment, and that Vermilion is optimally positioned to prosper
in this industry and market environment. Our belief in
Vermilion is founded in the economic sustainability of our business
model and our leadership in environmental sustainability in the
upstream oil and gas sector.
Throughout our 25-year history, we have repeatedly made the
necessary adjustments to adapt to the changing landscape around
us. Our business model has focused on sustainable growth and
income, which we have successfully delivered to our shareholders
over the years. Vermilion has paid over $39 per share in distributions and dividends
since 2003 and generated compounded growth in production per share
of over 8% annually since 2012. Our investment cycle time is
short with minimal fixed commitments. Consequently, we have
flexibility to adjust our investment and growth levels to provide
the combination of return of capital and growth which we think will
maximize shareholder value in a changing capital market
environment. Based on the current market and commodity
environment, we believe a strategy that is even more focused on
free cash flow generation will create the most value for our
shareholders. As such, for 2020, while maintaining our
dividend at current levels, we have elected to reduce our
production growth rate and to introduce additional flexibility in
how we return capital to investors.
This lower growth strategy was embedded in the preparation of
our 2020 budget as well as our capital plans for the remainder of
2019. For 2019, we have reduced capital investment by
$10 million, and now expect to invest
$520 million. As a result of
this reduced level of investment and after accounting for
higher-than-expected downtime and weather delays, we have
correspondingly reduced our 2019 annual production guidance to
100,000 to 101,000 boe/d. We expect to deliver annual
production at the mid-point of this revised guidance range,
reflecting strong year-over-year production per share growth of
5%. Our Board of Directors has approved a 2020 capital budget
of $450 million with associated
production guidance of 100,000 to 103,000 boe/d. This budget
is designed to deliver modest production growth of about 1%.
The 2020 budget includes approximately $20
million of strategic capital associated with early-stage
exploration and development activities. These activities will
lay the groundwork for future development and production growth
from a highly economic asset base.
During the third quarter we received approval from the TSX for a
normal course issuer bid ("NCIB"), which will allow us to buy back
up to 7.75 million shares. With this approval, we intend to
use the NCIB in combination with debt reduction when we have excess
free cash flow available (beyond dividends) to enhance per share
growth. We will also be phasing out our DRIP over the course
of the next year, prorating the available DRIP shares by 25% each
quarter starting in Q1 2020 until the DRIP is completely eliminated
in Q4 2020. The DRIP has been a shareholder service that we
have provided since our first income distribution in 2003, with
discounted share purchases offered until 2018. We recognize
that the elimination of the DRIP may be a disappointment to some
shareholders. Nonetheless, we feel that in an environment of
lower trading commissions, the establishment of our NCIB, and lower
energy issuer valuation multiples, the elimination of the DRIP is
in the best interests of our broad shareholder group.
We remain committed to maximizing value for our shareholders
over the long-term through a combination of a sustainable dividend,
low financial leverage, share buybacks, and production growth as
appropriate. In addition, we will remain disciplined in our
acquisition strategy as we continue to evaluate strategic
opportunities that fit within our business model and add value for
existing shareholders. Our highest financial priority is our
balance sheet, and under no circumstance will we do anything that
jeopardizes Vermilion's long-term financial stability. We
have a robust balance sheet with termed-out borrowing, strong
liquidity, and a very low cost of debt. Coupled with low
operating leverage due to high margins, a diversified product mix,
and a strong hedge position, our balance sheet provides us with the
flexibility to weather volatility in commodity prices.
Q3 2019 Operations Review
Our Q3 2019 operational results were impacted by
several planned turnarounds, a high level of unplanned
downtime, weather related delays and a moderate carry-over
impact from the refinery outage in France. As a result, our
Q3 2019 production decreased 6% from the prior quarter to 97,239
boe/d, with variances discussed by business unit below. We
generated FFO of $216 million in the
third quarter, down by 3% from the prior quarter, with positive
contributions from hedging gains, lower G&A expense, and lower
taxes partially offsetting lower production and commodity
prices.
Europe
In France, Q3 2019 production
averaged 10,347 boe/d, an increase of 6% from the prior
quarter. Production volumes in the Paris Basin returned to near full capacity in
mid-August following the restart of the Grandpuits refinery which
had been offline due to a failure on its main feedstock
pipeline. Most of our wells in the Paris Basin have returned to pre-shutdown
production levels, although some wells continue to clean up and
workover activity is continuing to restore full productivity.
The net impact from the refinery outage reduced our Q3 2019
production volumes by approximately 400 boe/d. In the
Aquitaine Basin, production was consistent with the prior quarter
as we successfully completed our 2019 workover campaign, which
continues to yield results above our expectations.
In the Netherlands, Q3 2019
production averaged 7,429 boe/d, a decrease of 17% from the prior
quarter. The decrease was primarily due to a planned
turnaround and unexpected downtime to repair a gas compressor,
which extended the length of the turnaround. The combined
impact was a reduction in Netherlands production of approximately 1,200
boe/d in Q3 2019. Our facilities have returned to service and
production has been restored. We are currently in the process
of drilling the Weststellingwerf well (0.5 net), representing our
first drilling activity in the
Netherlands since 2017, and we expect drilling to be
completed before the end of the year.
In Ireland, production averaged
43 mmcf/d (7,202 boe/d) in Q3 2019, a decrease of 12% from the
prior quarter. The decrease was primarily due to planned and
unplanned downtime at the Corrib natural gas processing facility
and natural decline. Our planned turnaround was successfully
completed as scheduled in mid-September. Later in the month,
we identified the need for repairs in one of the plant auxiliary
systems which necessitated shutting the plant down for
approximately 10 days spanning the end of Q3 and early Q4
2019. The combined impact of the planned and unplanned
downtime was approximately 800 boe/d in Q3.
In Germany, production in Q3
2019 averaged 3,269 boe/d, a decrease of 6% from the prior
quarter. The decrease was primarily due to unplanned downtime
on several operated and non-operated assets, partially offset by
contributions from successful workovers performed earlier this
year. Following the successful drilling of the Burgmoor Z5
(46% working interest) well, completed early in the third quarter
of 2019, we continue to evaluate tie-in alternatives and expect to
bring the well on production in late 2020.
In Central and Eastern Europe
("CEE"), we drilled one (1.0 net) natural gas exploration well in
Croatia during Q3 2019, which
resulted in a second consecutive gas discovery, testing at a rate
of 17.2 mmcf/d(2). During the third quarter, we
were also provisionally awarded the SA-07 license in Croatia, which is contiguous with our existing
land position and will add approximately 500,000 net acres to our
portfolio in the country. Vermilion continues to be the
largest onshore landholder in Croatia, with total licensed acreage of
approximately 2.4 million net acres, including the new SA-07
block. In Hungary, we began
tie-in activities for the Mh-21 (0.3 net) and Battonya E-09 (1.0
net) wells, drilled in the second and third quarters of 2019,
respectively, and expect to bring them on production during the
fourth quarter of 2019.
North America
In Canada, production averaged
58,504 boe/d in Q3 2019, a decrease of 5% from the prior
quarter. The decrease was primarily due to planned
turnarounds (700 boe/d impact) and project delays caused by
abnormally wet weather (2,100 boe/d impact). We drilled or
participated in 40 (38.3 net) wells in the third quarter of 2019,
all of which were drilled in Saskatchewan, as no drilling in Alberta was possible due to wet conditions
throughout the summer. Well activity in Alberta, including tie-in and completions, was
delayed until late September due to extremely wet ground, three
months later than when we typically resume post-break-up
activity. We brought 41 (36.2 net) wells on production in
Saskatchewan and three (2.5 net)
wells on production in Alberta
during the quarter. We have continued to realize capital and
operating efficiencies in our southeast Saskatchewan assets, achieving a 10%
improvement in drilling, completion, equipping and tie-in ("DCET")
costs on our Q3 2019 open-hole drilling program compared to our Q1
2019 program.
In the United States, Q3 2019
production averaged 4,925 boe/d, representing an increase of 12%
from the prior quarter. The increase was primarily driven by
production contributions from our 2019 Hilight drilling campaign,
as we successfully completed and brought on production four (4.0
net) wells during the third quarter. The increased production
was partially offset by planned and unplanned third-party gas plant
maintenance, which reduced production by approximately 200
boe/d. The first two wells drilled in the quarter were
brought on production in late August and achieved an average peak
IP30 rate of approximately 600 boe/d per well (86% oil and
NGLs). The other two wells were brought on production at the
end of September and are currently producing at an average rate of
approximately 500 boe/d per well (92% oil and NGLs). We
continue to progress along the learning curve in reducing costs
since our Hilight acquisition one year ago, with a 20% DCET cost
reduction in our H2 2019 program to-date compared to our H1 2019
program. As a result of these cost savings, we have added two
(1.5 net) wells to our 2019 program and plan to drill these wells
in Q4 2019.
Australia
In Australia, production
averaged 5,564 bbl/d in Q3 2019, a decrease of 17% from the
previous quarter, primarily due to well management and unplanned
vessel maintenance on the Wandoo platform. We plan to conduct
facility upgrades in Q4 2019 to increase fluid handling capacity,
which will necessitate a shutdown of the Wandoo platform for an
estimated eight days in the fourth quarter of 2019.
2020 Budget
Our Board of Directors has approved an exploration and
development capital expenditure budget of $450 million, with associated production guidance
of 100,000 to 103,000 boe/d. As previously communicated, we
are placing less emphasis on production growth as we navigate the
current commodity price and capital markets environment.
We plan to drill 13 (8.7 net) wells in Europe. In
addition, we plan to continue significant workover programs in
France, Netherlands and Germany, and facility optimization in
Ireland. The capital budget includes approximately
$20 million of strategic,
non-production-adding capital invested to facilitate our long-term
future growth plans in Europe.
In North America, our activity
will focus on our three core areas of southeast Saskatchewan (light oil), west-central
Alberta (condensate-rich natural
gas), and the Powder River Basin in Wyoming (light oil). We have made
significant progress on improving the capital and operating
efficiencies on the North American assets we acquired in 2018, and
we plan to continue that trend in 2020.
Assuming WTI oil prices remain at approximately US$55/bbl in 2020, and holding all other
commodities at the October 11, 2019
commodity strip, we would more than cover our dividend and capital
investment. Excess cash generated beyond our capital program
and dividend commitment will be allocated to a combination of debt
reduction and share buybacks. Our top financial priorities in
2020 will be balance sheet and dividend protection, and we maintain
the capital investment flexibility to reduce capital outlays if
required by lower commodity prices.
Europe
In France, our 2020 E&D
capital budget of $57 million
represents a 23% reduction from our 2019 spending. While we
do not intend to invest in any new wells in 2020, we plan to
continue with our workover and asset optimization programs in both
the Paris and Aquitaine
Basins. These workover programs are expected to maintain
production at roughly the same level in 2020 as we have averaged in
2019.
Our 2020 E&D budget in the
Netherlands of $18 million
represents a 22% decrease from 2019. While significant
progress has been made on our permitting efforts, we will plan for
modest growth in the Netherlands
in 2020 as we reschedule our slate of capital projects in the
context of a lower corporate growth rate target. We plan to
drill or participate in three (0.6 net) wells. Assuming
success on the Weststellingwerf well (0.5 net) currently being
drilled, we plan to bring this well on production during the first
half of 2020. We will continue to advance our well permitting
throughout the year in order to compile a backlog of projects for
implementation beginning in 2021.
In Ireland, we plan to invest
approximately $3 million of E&D
capital in 2020 as we continue to focus on facility maintenance and
compression optimization.
In Germany, our 2020 E&D
capital budget of $18 million
represents a decrease of 18% year-over-year. In addition to
our planned workover and facility program, we plan to drill
sidetracks in three (3.0 net) of our operated oil wells and begin
drilling activities on one (0.6 net) exploratory gas prospect.
In Central and Eastern Europe,
our 2020 E&D budget will be approximately the same as in 2019,
building on the success we had in 2019 and laying the groundwork
for future growth. We plan to invest $20 million in E&D capital expenditures in
2020. While the majority of this capital program will be
focused on following-up our successful 2019 drilling program, a
portion of the budget will be directed to strategic infrastructure
investments in Croatia and
Slovakia, notably the commencement
of construction of natural gas compression facilities in each
country. In 2020, we plan to drill six (4.5 net) wells in CEE
comprised of two (2.0 net) wells in Croatia, one (1.0 net) well in Hungary and three (1.5 net) wells in
Slovakia.
North America
In Canada, we plan to invest
$250 million of E&D capital in
2020, a decrease of 14% from our 2019 capital program. We
plan to drill 107 (95.5 net) wells in Canada in 2020, comprised of 87 (76.3 net)
light oil wells in southeast Saskatchewan and 20 (19.2 net) wells in
Alberta. In addition to the drilling program, we will also
continue to focus on our waterflood program in southeast
Saskatchewan, as well as
production and facility optimization opportunities, as we have in
previous years.
In the United States, our 2020
E&D capital budget of $59 million
represents a 4% increase from our 2019 capital program. We
plan to drill 10 (9.6 net) wells on our Hilight asset in
Wyoming. This expanded drilling program will allow us to
capitalize on the efficiencies we have achieved since the Hilight
acquisition and to continue to increase production in the Powder
River Basin.
Australia
In Australia, our 2020 E&D
budget of $25 million will focus
primarily on workovers and facility modifications to increase
artificial lift capacity and facility throughput.
E&D Capital Investment by Country
|
|
|
|
Country
|
2020 Budget*
($MM)
|
2019 Budget
($MM)
|
2020 vs. 2019
% Change
|
2020
Gross Wells
|
2020
Net Wells
|
Canada
|
250
|
292
|
(14)
|
%
|
107
|
95.5
|
France
|
57
|
74
|
(23)
|
%
|
—
|
—
|
Netherlands
|
18
|
23
|
(22)
|
%
|
3
|
0.6
|
Germany
|
18
|
22
|
(18)
|
%
|
4
|
3.6
|
Ireland
|
3
|
1
|
200
|
%
|
—
|
—
|
Australia
|
25
|
31
|
(19)
|
%
|
—
|
—
|
USA
|
59
|
57
|
4
|
%
|
10
|
9.6
|
Central and Eastern
Europe
|
20
|
20
|
—
|
%
|
6
|
4.5
|
Total E&D
Capital Expenditures
|
450
|
520
|
(13)
|
%
|
130
|
113.8
|
E&D Capital Investment by Category
|
|
|
|
Category
|
2020 Budget*
($MM)
|
2019 Budget
($MM)
|
2020 vs. 2019
% Change
|
Drilling, completion,
new well equipment and tie-in, workovers and
recompletions
|
350
|
380
|
(8)
|
%
|
Production equipment
and facilities
|
70
|
100
|
(30)
|
%
|
Seismic, land and
other
|
30
|
40
|
(25)
|
%
|
Total E&D
Capital Expenditures
|
450
|
520
|
(13)
|
%
|
*2020 Budget reflects foreign exchange assumptions of
CAD/USD 1.32, CAD/EUR 1.48, and CAD/AUD 0.90.
Dividend Reinvestment Plan
We have elected to phase out the Dividend Reinvestment Plan
("DRIP"), prorating the available DRIP shares by 25% each quarter
starting in Q1 2020. It is our intention to increase this
proration each quarter throughout next year, such that the DRIP
will be eliminated by the fourth quarter of 2020.
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 October
29, 2019, we currently have 51% of our expected
net-of-royalty production hedged for Q4 2019. More than half
of our Q4 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
one-third of our production is hedged, with 54% of our hedge
position in participating structures.
With respect to individual products within our product mix, we
have currently hedged 74% of anticipated European natural gas
volumes for Q4 2019. We have also hedged 75% of our
anticipated full-year 2020 European natural gas volumes at prices
which are expected to provide for strong project economics and free
cash flows. At present, 47% of our expected Q4 oil production
is hedged. For Q4 2019, 51% 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 16% of our North American gas production is
located in Saskatchewan and
Wyoming.
Sustainability
Vermilion received top quartile rankings for 2019 for our
industry sector in both the Sustainalytics ESG Rating and SAM
(formerly known as RobecoSAM) annual Corporate Sustainability
Assessment ("CSA"). These agencies analyze sustainability
performance across economic, environmental, governance and social
criteria, and the CSA is also the basis of the Dow Jones
Sustainability Indices. We believe the integration of
sustainability principles into our business is the right thing to
do, increases shareholder return, and reduces long-term risks to
our business model. These ratings demonstrate our commitment
to maintaining leadership in sustainability and ESG
performance. Our 2019 Sustainability Report is available on
our corporate website at:
http://sustainability.vermilionenergy.com.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
October 30, 2019
(1)
|
Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section
of Management's Discussion and Analysis.
|
|
|
(2)
|
Berak-01 well (100%
working interest) tested at a rate of 17.2 mmcf/d during a
four-hour flow period with a stabilized flowing wellhead pressure
of 908 psi on a 0.875 inch diameter choke. A final shut in
wellhead pressure of 1,186 psi was recorded following the flow
test. The flow test continued an additional 12 hours at
reduced choke sizes to minimize flaring. No formation water
was produced during the test. The well logged 21 feet of net
gas pay with an average porosity of 32% from the Upper Miocene
Pannonian sandstone occurring within a gross measured depth
interval of 3,006-3,033 feet. Test results are not
necessarily indicative of long-term performance or ultimate
recovery.
|
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call on
Thursday, October 31, 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 2090807 from
October 31, 2019 at 12:00 MST to November 14,
2019 at 21:59 MST.
You may also access the webcast at
https://event.on24.com/wcc/r/2114194/1C4F8D98D22708487A065827392F4760.
The webcast link can be found on Vermilion's website at
http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm under
upcoming events.
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 14.5%.
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", "project", 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.