CALGARY, AB, Nov. 9, 2021 /PRNewswire/ - Vermilion Energy
Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX: VET)
(NYSE: VET) is pleased to report operating and condensed financial
results for the three and nine months ended September 30,
2021.
The unaudited interim financial statements and management
discussion and analysis for the three and nine months
ended September 30, 2021 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
- Fund flows from operations ("FFO") was $263 million in Q3 2021, an increase of 52% from
the prior quarter. The increase was primarily due to higher
commodity prices.
- E&D capital expenditures were $66
million in the quarter, resulting in $196 million of free cash flow
("FCF")(1) and a payout ratio of 27% including
reclamation and abandonment expenditures.
- Through the first nine months of 2021 we have generated
$369 million of FCF and have reduced
net debt by $231 million while also
funding acquisitions to benefit future FCF deliverability. Based on
the forward commodity strip, we expect to generate in excess of
$500 million, or over $3.00 per share, of FCF in 2021 and exit the year
with net debt forecast to be in the range of $1.65 billion, implying a net debt to trailing
FFO ratio of approximately 1.8 times.
- Production in Q3 2021 averaged 84,633 boe/d(2),
which was down slightly from the previous quarter primarily due to
planned maintenance activity in Canada and Ireland, partially offset by higher production
in the Netherlands, Germany, Australia and the
United States, including the contribution from a small
bolt-on acquisition in the Powder River Basin.
- Production from our North American assets averaged 57,022 boe/d
in Q3 2021, a decrease of 2% from the prior quarter primarily due
to planned and unplanned downtime in Canada, which was partially offset by strong
performance from our United States
business unit, including the acquisition noted above.
- In Canada, we continued with
our two-rig drilling program in south-east Saskatchewan where we drilled 19 (19.0 net)
wells and completed 20 (19.5 net) wells in the quarter. Activity in
Alberta was primarily focused on
plant turnarounds and maintenance and preparing for our Q4 2021
condensate-rich Mannville gas
drilling program.
- In the United States, we
completed and brought on production the remaining two (2.0 net)
wells from our four (4.0 net) well Q2 2021 drilling program. With
our growing knowledge of the Turner play, we were able to identify
and execute a strategic acquisition during Q3 2021. The acquisition
includes 20,000 net acres of land adjacent to our Hilight field in
Wyoming with current production of
approximately 1,500 boe/d (72% liquids). We have identified up to
40 drilling locations in the Turner sands along with longer-term
resource potential from the emerging Niobrara and Parkman formations. Total consideration for
the acquisition was US$76 million
which was funded through our credit facility.
- Production from our International assets averaged 27,612 boe/d
in Q3 2021, a decrease of 1% from the prior quarter primarily due
to a planned turnaround in Ireland, which was partially offset by strong
performance from the Netherlands,
Germany and Australia.
- In the Netherlands, the Nijega
well (1.0 net) was tied in during the third quarter, while the
Blesdijke well (0.5 net) is currently undergoing stimulation
operations and is expected to be tested in Q4 2021.
- In Germany, the Burgmoor Z-5
well (46% working interest) was brought on production during the
third quarter.
- Our board of directors have approved a $75 million increase to our 2021 capital program
to $375 million. The incremental
capital investment will be primarily directed towards our
Alberta condensate-rich natural
gas drilling, Saskatchewan light
oil drilling and seismic acquisitions in Europe. As a result of the strong production
achieved year-to-date, combined with the US acquisition completed
in Q3 2021, we have increased our 2021 annual production guidance
to 84,500 - 85,500 boe/d.
- Based on our preliminary work to date, we anticipate a 2022
capital program in the range of $400
- $450 million with production at a
similar level to our original 2021 guidance of 83,000 to 85,000
boe/d. Based on this targeted capital and production range and
using forward strip pricing for 2022, we anticipate FCF in excess
of $600 million with net debt in the
range of $1 billion by the end of the
year, implying a net debt to trailing FFO ratio of less than 1.0
times.
- We plan to reinstate a dividend in Q1 2022. Although it is
still subject to board approval, our intention is to reinstate a
fixed quarterly dividend (5-10% of FFO stress-tested at lower
prices including US$55/bbl
WTI) while continuing to focus on debt reduction. As
further debt targets are achieved we will consider augmenting our
return of capital through fixed dividend increases, share buybacks
and/or special dividends. We will provide more details on our
return of capital framework with our formal 2022 budget release in
early December.
(1)
|
Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section of
the accompanying Management's Discussion and Analysis.
|
(2)
|
Please refer to
Supplemental Table 4 "Production" of the accompanying Management's
Discussion and Analysis for disclosure by product type.
|
($M except as
indicated)
|
Q3
2021
|
Q2
2021
|
Q3
2020
|
YTD
2021
|
YTD
2020
|
Financial
|
|
|
|
|
|
Petroleum and natural
gas sales
|
538,530
|
|
407,179
|
|
282,020
|
|
1,313,846
|
|
803,347
|
|
Fund flows from
operations
|
262,696
|
|
172,942
|
|
114,776
|
|
597,689
|
|
366,853
|
|
Fund flows from
operations ($/basic share) (1)
|
1.62
|
|
1.07
|
|
0.73
|
|
3.72
|
|
2.33
|
|
Fund flows from
operations ($/diluted share) (1)
|
1.59
|
|
1.05
|
|
0.73
|
|
3.65
|
|
2.33
|
|
Net (loss)
earnings
|
(147,130)
|
|
451,274
|
|
(69,926)
|
|
804,108
|
|
(1,459,720)
|
|
Net (loss) earnings
($/basic share)
|
(0.91)
|
|
2.79
|
|
(0.44)
|
|
5.00
|
|
(9.26)
|
|
Capital
expenditures
|
66,450
|
|
79,176
|
|
31,330
|
|
228,989
|
|
307,308
|
|
Acquisitions
|
94,420
|
|
12,519
|
|
6,720
|
|
107,332
|
|
20,989
|
|
Asset retirement
obligations settled
|
5,142
|
|
3,321
|
|
2,305
|
|
15,486
|
|
7,007
|
|
Cash dividends
($/share)
|
—
|
|
—
|
|
—
|
|
—
|
|
0.575
|
|
Dividends
declared
|
—
|
|
—
|
|
—
|
|
—
|
|
90,067
|
|
% of fund flows from
operations
|
—
|
%
|
—
|
%
|
—
|
%
|
—
|
%
|
25
|
%
|
Payout
(1)
|
71,592
|
|
82,497
|
|
33,635
|
|
244,475
|
|
396,105
|
|
% of fund flows from
operations
|
27
|
%
|
48
|
%
|
29
|
%
|
41
|
%
|
108
|
%
|
Free Cash Flow
(1)
|
196,246
|
|
93,766
|
|
83,446
|
|
368,700
|
|
59,545
|
|
Net debt
(2)
|
1,778,052
|
|
1,854,195
|
|
2,083,317
|
|
1,778,052
|
|
2,083,317
|
|
Net debt to four
quarter trailing fund flows from operations
|
2.43
|
|
3.17
|
|
3.58
|
|
2.43
|
|
3.58
|
|
Operational
|
Production
(3)
|
|
|
|
|
|
Crude oil and
condensate (bbls/d)
|
38,777
|
|
38,354
|
|
43,240
|
|
38,777
|
|
44,383
|
|
NGLs
(bbls/d)
|
8,068
|
|
8,695
|
|
9,509
|
|
8,279
|
|
9,041
|
|
Natural gas
(mmcf/d)
|
226.73
|
|
235.72
|
|
256.34
|
|
232.12
|
|
265.39
|
|
Total
(boe/d)
|
84,633
|
|
86,335
|
|
95,471
|
|
85,742
|
|
97,656
|
|
Average realized
prices
|
|
|
|
|
|
Crude oil and
condensate ($/bbl)
|
87.05
|
|
79.06
|
|
52.77
|
|
79.40
|
|
49.03
|
|
NGLs
($/bbl)
|
35.55
|
|
25.43
|
|
15.04
|
|
30.03
|
|
11.09
|
|
Natural gas
($/mcf)
|
9.20
|
|
5.24
|
|
2.34
|
|
6.63
|
|
2.37
|
|
Production mix (% of
production)
|
|
|
|
|
|
% priced with
reference to WTI
|
39
|
%
|
38
|
%
|
40
|
%
|
38
|
%
|
40
|
%
|
% priced with
reference to Dated Brent
|
18
|
%
|
17
|
%
|
17
|
%
|
18
|
%
|
16
|
%
|
% priced with
reference to AECO
|
28
|
%
|
30
|
%
|
28
|
%
|
29
|
%
|
28
|
%
|
% priced with
reference to TTF and NBP
|
15
|
%
|
15
|
%
|
15
|
%
|
15
|
%
|
16
|
%
|
Netbacks
($/boe)
|
|
|
|
|
|
Operating netback
(1)
|
36.17
|
|
25.90
|
|
16.29
|
|
29.30
|
|
16.94
|
|
Fund flows from
operations netback
|
33.27
|
|
22.04
|
|
12.95
|
|
25.75
|
|
13.63
|
|
Operating
expenses
|
13.21
|
|
12.72
|
|
10.21
|
|
12.93
|
|
11.55
|
|
General and
administration expenses
|
1.56
|
|
1.46
|
|
1.35
|
|
1.53
|
|
1.57
|
|
Average reference
prices and foreign exchange rates
|
|
|
|
|
|
WTI (US
$/bbl)
|
70.56
|
|
66.07
|
|
40.93
|
|
64.82
|
|
38.32
|
|
Edmonton Sweet index
(US $/bbl)
|
66.49
|
|
62.96
|
|
37.42
|
|
60.68
|
|
32.57
|
|
Saskatchewan LSB index
(US $/bbl)
|
66.35
|
|
62.71
|
|
37.57
|
|
60.63
|
|
32.53
|
|
Dated Brent (US
$/bbl)
|
73.47
|
|
68.83
|
|
43.00
|
|
67.73
|
|
40.82
|
|
AECO
($/mcf)
|
3.60
|
|
3.09
|
|
2.24
|
|
3.28
|
|
2.09
|
|
NBP ($/mcf)
|
20.21
|
|
10.92
|
|
3.67
|
|
13.32
|
|
3.43
|
|
TTF ($/mcf)
|
20.65
|
|
10.76
|
|
3.51
|
|
13.27
|
|
3.38
|
|
CDN $/US $
|
1.26
|
|
1.23
|
|
1.33
|
|
1.25
|
|
1.35
|
|
CDN $/Euro
|
1.49
|
|
1.48
|
|
1.56
|
|
1.50
|
|
1.52
|
|
Share information
('000s)
|
Shares outstanding -
basic
|
161,985
|
|
161,893
|
|
158,308
|
|
161,985
|
|
158,308
|
|
Shares outstanding -
diluted (1)
|
169,012
|
|
168,903
|
|
163,800
|
|
169,012
|
|
163,800
|
|
Weighted average
shares outstanding - basic
|
161,957
|
|
161,546
|
|
158,307
|
|
160,809
|
|
157,688
|
|
Weighted average
shares outstanding - diluted (1)
|
164,991
|
|
165,034
|
|
158,307
|
|
163,693
|
|
157,688
|
|
(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.
|
(2)
|
Prior period
comparatives have been revised. Net debt is defined as long-term
debt (excluding unrealized foreign exchange on swapped USD
borrowings) plus adjusted working capital (defined as current
assets less current liabilities, excluding current derivatives and
current lease liabilities).
|
(3)
|
Please refer to
Supplemental Table 4 "Production" of the accompanying Management's
Discussion and Analysis for disclosure by product type.
|
Message to Shareholders
Global commodity prices continued to strengthen during the third
quarter which we were able to take advantage of through our
internationally diversified asset base. Compared to the previous
quarter, global oil prices increased approximately 7%, Canadian
natural gas prices increased by 24%, United States natural gas prices increased by
42%, while European natural gas prices (TTF) increased over 90%.
Vermilion's exposure to global
commodity prices is what sets us apart from our North American
peers. Not only does this global commodity exposure enhance our
revenue and cash flow during strong market cycles, but it also
serves to reduce cash flow volatility over the long-term.
As a result of the strong commodity prices, we generated
$263 million of FFO in Q3 2021,
representing a 52% increase over the prior quarter. We invested
$66 million in E&D capital
expenditures during the quarter, resulting in $196 million of FCF(1) with the
majority of that FCF used to reduce debt and the remainder
allocated to an acquisition in the United
States as well as reclamation and abandonment
expenditures.
Based on the forward commodity strip, we expect to generate in
excess of $500 million, or over
$3.00 per share, of free cash flow in
2021 and exit 2021 with net debt forecast to be in the range of
$1.65 billion. Based on these
projections, this would imply a net debt to trailing FFO ratio of
approximately 1.8 times which is well ahead of the original net
debt target that we had at the beginning of the year as stronger
commodity prices have enabled us to accelerate our debt
reduction.
We now have a clear line of sight to achieving our targeted debt
to trailing FFO ratio of 1.5 times or less in 2022, and with that
we plan to reinstate a dividend in Q1 2022. Although it is still
subject to board approval, our intention is to reinstate a fixed
quarterly dividend (5-10% of FFO stress-tested at lower prices
including US$55/bbl WTI) while
continuing to focus on debt reduction. As further debt targets
are achieved we will consider augmenting our return of capital
through fixed dividend increases, share buybacks and/or special
dividends. We will provide more details on our return of capital
framework with our formal 2022 budget release in early
December.
Q3 2021 Operations Review
During Q3 2021 we achieved average production of 84,633 boe/d
which was down slightly from the previous quarter primarily due to
planned maintenance activity. We completed the majority of our
planned annual maintenance in Canada and Ireland during the third quarter.
The impact from this was partially offset by higher production
in the Netherlands, Germany, Australia and United
States, including the contribution from a small bolt-on
acquisition in the Powder River Basin.
Production from our North American assets averaged 57,022 boe/d
in Q3 2021, a decrease of 2% from the prior quarter primarily due
to planned and unplanned downtime in Canada, which was partially offset by strong
performance from our United States
business unit. Production from the United
States increased by approximately 2,100 boe/d compared to
the previous quarter due to strong performance from our Q2 2021
drilling program and the contribution from a bolt-on acquisition
completed during the quarter.
In Canada, we continued with
our two-rig drilling program in southeast Saskatchewan where we drilled 19 (19.0 net)
wells and completed 20 (19.5 net) wells in the quarter. Activity in
Alberta was primarily focused on
plant turnarounds and maintenance and preparing for our Q4 2021
condensate-rich Mannville gas
drilling program. Our operations were also affected by an unplanned
outage at the Plains Midstream Fort Saskatchewan facility late in
the quarter, but we were able to minimize the impact by optimizing
our marketing logistics and rerouting some of our production to
other facilities. The net impact for Q3 2021 related to this event
was approximately 550 boe/d; however, most of our production has
since been restored and we expect minimal impact on our full year
production results.
In the United States, we
completed and brought on production the remaining two (2.0 net)
wells from our four (4.0 net) well Q2 2021 drilling program. We
continue to enhance our knowledge of the Turner play while
optimizing our drilling and completion execution. The results from
our 2021 drilling program have exceeded expectations from both a
cost and production performance basis. With our growing knowledge
of this play and region, we were able to identify and execute a
strategic acquisition during Q3 2021. The acquisition includes
20,000 net acres of land adjacent to our Hilight field in
Wyoming with current production of
approximately 1,500 boe/d (72% liquids), and we have identified up
to 40 drilling locations in the Turner sands. With an operating
netback in excess of $45/boe based on
current commodity prices, the acquired assets are free cash flow
positive and are expected to self-fund Turner development over the
next 5+ years. In addition, we believe the acquired acreage is
prospective for the Niobrara and
Parkman formations based on our
initial assessment and recent positive results by nearby industry
peers. We are optimistic about the future development potential of
these plays and will continue to evaluate our prospective land
while monitoring industry activity. The acquisition complements our
existing asset base by extending our Turner drilling inventory
while providing longer-term resource potential from the emerging
Niobrara and Parkman formations. Total consideration for
the acquisition was US$76 million
which was funded through our credit facility. The acquisition is
expected to add approximately 600 boe/d in 2021.
Production from our International assets averaged 27,612 boe/d
in Q3 2021, a decrease of 1% from the prior quarter primarily due
to a three-week planned turnaround in Ireland. The turnaround was successfully
completed in July and production resumed in August. Most of the
impact from the planned turnaround in Ireland was offset by new production added in
the Netherlands and Germany and strong operational uptime in
Australia. The 20-day planned
turnaround in Australia was
deferred from Q3 2021 to Q4 2021 to optimize work schedules.
Most of the activity in Europe
during the third quarter was focused on completing and tying in the
Nijega (1.0 net) and Blesdijke (0.5 net) gas wells in the Netherlands and the Burgmoor Z-5 gas well
(46% working interest) in Germany.
In the Netherlands, the Nijega
well (1.0 net) was tied in during the third quarter, while the
Blesdijke well (0.5 net) is currently undergoing stimulation
operations and is expected to be tested in Q4 2021. In Germany, the Burgmoor Z-5 well (46% working
interest) was brought on production during the third quarter.
We continue to advance our exploration initiatives in
Europe through the acquisition of
additional 3D seismic in the
Netherlands and Croatia.
With the ongoing evaluation of our land base across the CEE, we
have been able to hone in our focus on the most prospective regions
while relinquishing other blocks that are not deemed as
prospective. Progress on the gas plant for the SA-10 block in
Croatia also continued during the
quarter. We took physical delivery of the gas plant that was
shipped from the Netherlands and
we continue to advance the detailed design work with construction
planned for 2022 and first production anticipated in 2023.
2021 Capital Budget and Production Guidance Increase
When we announced our 2021 capital budget of $300 million earlier this year, we indicated that
our primary focus for 2021 was to maximize free cash flow and
reduce debt, while retaining the flexibility to adjust investment
levels depending on commodity prices. As commodity prices have been
much stronger than we anticipated, we have been able to exceed our
debt reduction target for the year. As a result, our board of
directors have approved a $75 million
increase to our 2021 capital program to $375
million. The incremental capital investment will be
primarily directed towards our Alberta condensate-rich natural gas and
Saskatchewan light oil drilling
programs and seismic acquisitions in Europe. In Saskatchewan, we will extend our 2H 2021
drilling program by keeping one rig active through the end of the
year which will add 8 (8.0 net) wells. In Alberta, we have advanced the completion date
for 9 (8.6 net) condensate-rich Mannville gas wells into Q4 2021 which were
originally planned for Q1 2022. Accelerating this capital into Q4
2021 has allowed us to secure our preferred drilling and completion
vendors while also improving overall capital efficiencies by
executing the majority of this program in Q4 2021 compared to the
busier winter months of 2022. This capital efficiency improvement
will help offset some of the inflation that we are seeing in our
program costs. As a result of the strong production achieved
year-to-date, combined with the US acquisition completed in Q3
2021, we have increased our 2021 annual production guidance to
84,500 - 85,500 boe/d.
Preliminary 2022 Outlook
We continue to work through our 2022 budgeting process and
expect to announce a formal 2022 budget and guidance in early
December. We are targeting a capital program that will deliver a
production base similar to our original 2021 guidance of 83,000 to
85,000 boe/d. Our preliminary capital plans for 2022 contemplate a
two-well drilling program in Australia as well as continued strategic
investment into Europe to expand
our business. In order to achieve our production goals, execute our
Australian drilling program and deliver on our strategic capital
investment to support long-term FCF generation and accommodate
anticipated inflation in our cost structure, we anticipate a 2022
capital program in the range of $400
- $450 million. Based on this
targeted capital and production range and using forward strip
pricing for 2022, we anticipate FCF in excess of $600 million with net debt in the range of
$1 billion by the end of the year,
implying a net debt to trailing FFO ratio of less than 1.0 times.
We will continue to monitor commodity prices, progress on debt
reduction and adjust our capital allocation plan as necessary.
Commodity Hedging
Vermilion hedges to manage commodity
price exposures and increase the stability of our cash flows. In
aggregate, as of November 9, 2021, we
have 31% of our expected net-of-royalty production hedged for the
fourth quarter of 2021. With respect to individual commodity
products, we have hedged 70% of our European natural gas
production, 10% of our oil production, and 45% of our North
American natural gas volumes for the fourth quarter of 2021,
respectively. Please refer to the Hedging section of our website
under Invest With Us for further details using the following link:
https://www.vermilionenergy.com/invest-with-us/hedging.cfm.
Sustainability
Subsequent to Q3 2021, Vermilion
announced that it had achieved certification under the EO100™
Standard for Responsible Energy Development (2017) from Equitable
Origin for three of its natural gas production sites in
west-central Alberta: Granada, Eta Lake and Carrot Creek.
Vermilion is the third producer of
natural gas in Canada to have
achieved this rigorous certification, which is based on an
independent assessment of performance targets within five
Environment, Social and Governance-related (ESG) principles:
corporate governance, transparency and ethics; human rights, social
impact and community development; Indigenous People's rights; fair
labor and working conditions; and climate change, biodiversity and
environment. Under this certification, Vermilion has now transacted three term gas sales
deals to date in which EO100TM certificates are being
delivered along with natural gas. Our partners in the deals share a
vision to transition toward a lower-carbon economy.
Organizational Update
During the third quarter, we announced the appointment of
Dion Hatcher as President effective
January 1, 2022, succeeding
Curtis Hicks who will remain with
the Company as an advisor until April 1,
2022. In addition to this leadership change, we also made
several other organizational changes including the promotion of Ms.
Yvonne Jeffery to Vice President,
Sustainability, Ms. Averyl Schraven
to Vice President, People & Culture, Mr. Bryce Kremnica to Vice President, North America, and Mr. Geoff MacDonald to Vice President,
Geosciences.
Mr. Dion Hatcher has been
promoted to President, effective January 1,
2022. Mr. Hatcher has over 25 years of industry experience
and has spent the last 15 years in a variety of leadership roles at
Vermilion. He has held increasingly
senior roles during his tenure at Vermilion and most recently held the position of
Vice President, North America over
the past year and as Vice President of the Canadian Business Unit
for five years prior to that. In his most recent role, he was
responsible for the profitability and operations of North America representing 67% of Vermilion's total production. His experience spans
corporate strategy, oil and gas operations, mergers, acquisitions
and divestures, health, safety and the environment and
sustainability. Mr. Hatcher has a Bachelor of Mechanical
Engineering from Memorial University of
Newfoundland.
Ms. Yvonne Jeffery has been
promoted to Vice President, Sustainability. Ms. Jeffery joined
Vermilion's community investment and
communications team in 2013, where she has since led sustainability
strategy and reporting, community investment and internal
communications. She previously held leadership and communications
roles specializing in the intersection of business, community and
sustainable development, including at the Calgary Herald. Ms.
Jeffery began her career with 10 years as a logistics officer in
the Canadian Army, serving across the country and on a United
Nations' peacekeeping mission in Cambodia. Ms. Jeffery has a Bachelor of Arts
in English and Management from the University
of Calgary and a Master's degree in Sustainability and
Responsibility from Ashridge / Hult International Business School
in Berkhamsted, England.
Ms. Averyl Schraven has been
promoted to Vice President, People & Culture. Ms. Schraven
joined Vermilion in 2014 as Manager,
Global HR Services and was promoted to Director, People and Culture
in December 2020. Prior to joining
Vermilion, she spent 13 years at
Schlumberger including 4 years working in the United Kingdom. Ms. Schraven has a Bachelor of
Science and a Masters of Business Administration from the
University of Victoria.
Mr. Bryce Kremnica has been
promoted to Vice President, North
America. Mr. Kremnica joined Vermilion in 2005 and has held various engineering
and management positions, including an expatriate assignment as
Operations Manager in the
Netherlands. He was promoted to Director, Field Operations –
Canadian Busines Unit in May 2014 and
has been instrumental to improving our safety and cost performance
while championing our culture. Prior to joining Vermilion, he worked for Chevron and ConocoPhillips
in production, exploitation, facilities and reservoir engineering
roles. In his new role, Mr. Kremnica will be a member of the
Executive Committee and will function as co-COO alongside
Darcy Kerwin, Vice President,
International & HSE. Mr. Kremnica holds a B.Sc. Chemical
Engineering and a Masters of Business Administration from the
University of Alberta.
Mr. Geoff MacDonald has been
promoted to Vice President, Geosciences. Mr. MacDonald joined
Vermilion as Chief Geoscientist in
March 2019 and has had a significant
impact on the Canadian and United States Business Units, including
strong well results, inventory management, geoscience training,
process improvements and contributing to the evaluation of various
acquisition opportunities. Prior to joining Vermilion, Mr. MacDonald was the Vice President,
Exploration at Velvet Energy and previously worked for EOG,
Enerplus and Encana. Mr. MacDonald has a Bachelor of Applied
Science in Geological Engineering from the University of Waterloo, and is an APEGA licensed
professional geologist.
Board of Directors
Vermilion recently announced the
appointment of James J. Kleckner Jr.
to our Board of Directors. Mr. Kleckner has more than 35 years of
experience in various executive and senior leadership roles. He was
most recently Chief Executive Officer of Jagged Peak Energy with a
focus on production and development in the Permian Basin, and held
a number of executive positions with Anadarko Petroleum Corporation
and Kerr McGee Corporation. He has extensive operational and
technical experience in US onshore resource plays and international
oil and gas operations. During his career, he held leadership roles
responsible for a full range of exploration, development,
production and operational priorities, including mergers and
acquisitions, health safety and environment, community and
government relations and enterprise risk management.
Mr. Kleckner currently serves as a member of the Board of
Directors for Great Western Petroleum, a private company.
Previously, he served as a member of the Board of Directors of
Jagged Peak Energy, Parsley Energy Inc., and two private companies:
Delonex Energy Limited and Hawkwood Energy LLC. He has served on
the Industry and Advisory Board of the School of Energy Research at
the University of Wyoming, the
Petroleum Engineering Advisory Board at the Colorado School of Mines, the Executive Board for
the Colorado Oil and Gas Association, and the Executive Board for
the Independent Petroleum Association of Mountain States. Mr.
Kleckner holds a B.Sc. in Petroleum Engineering from the
Colorado School of Mines and is a
member of the Society of Petroleum Engineers.
(Signed "Lorenzo
Donadeo")
|
|
(Signed "Curtis
Hicks")
|
|
|
|
Lorenzo
Donadeo
|
|
Curtis
Hicks
|
Executive
Chairman
|
|
President
|
November 9,
2021
|
|
November 9,
2021
|
(1)
|
Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section of
the accompanying Management's Discussion and Analysis.
|
(2)
|
Please refer to
Supplemental Table 4 "Production" of the accompanying Management's
Discussion and Analysis for disclosure by product type.
|
Management's Discussion and Analysis and Consolidated
Financial Statements
To view Vermilion's Management's
Discussion and Analysis and Interim Condensed Consolidated
Financial Statements for the three and nine months ended
September 30, 2021 and 2020, please refer to SEDAR
(www.sedar.com) or Vermilion's
website at
https://www.vermilionenergy.com/invest-with-us/reports-filings.cfm.
About Vermilion
Vermilion is an international energy
producer that seeks to create value through the acquisition,
exploration, development and optimization of producing assets in
North America, Europe and Australia. Our business model emphasizes free
cash flow generation and returning capital to investors when
economically warranted, augmented by value-adding acquisitions.
Vermilion's operations are focused on
the exploitation of light oil and liquids-rich natural gas
conventional resource plays in North
America and the exploration and development of conventional
natural gas and oil opportunities in Europe and Australia.
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. In addition, Vermilion
emphasizes strategic community investment in each of our operating
areas. We have been recognized as a strong performer amongst
Canadian publicly listed companies in governance practices, 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 and Germany.
Employees and directors hold approximately 5% of our outstanding
shares and are committed to delivering long-term value for all
stakeholders. 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 and
Vermilion's ability to fund such
expenditures; Vermilion's additional
debt capacity providing it with additional working capital; the
flexibility of Vermilion's capital
program and operations; business strategies and objectives;
operational and financial performance; estimated volumes of
reserves and resources; petroleum and natural gas sales; future
production levels and the timing thereof, including Vermilion's 2021 guidance, and rates of average
annual production growth; the effect of changes in crude oil and
natural gas prices, changes in exchange rates and significant
declines in production or sales volumes due to unforeseen
circumstances; the effect of possible changes in critical
accounting estimates; statements regarding the growth and size of
Vermilion's future project inventory,
and the wells expected to be drilled in 2021; exploration and
development plans and the timing thereof; Vermilion's ability to reduce its debt, including
its ability to redeem senior unsecured notes prior to maturity;
statements regarding Vermilion's
hedging program, its plans to add to its hedging positions, and the
anticipated impact of Vermilion's
hedging program on project economics and free cash flows; the
potential financial impact of climate-related risks; 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 Vermilion's expectations regarding future taxes and
taxability; 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.
All crude oil and natural gas reserve and resource information
contained in this document has been prepared and presented in
accordance with National Instrument 51-101 Standards of
Disclosure for Oil and Gas Activities and the Canadian
Oil and Gas Evaluation Handbook. Reserves estimates have been made
assuming that development of each property in respect of which the
estimate is made will occur, without regard to the likely
availability of funding required for such development. The actual
crude oil and natural gas reserves and future production will be
greater than or less than the estimates provided in this
document.
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.