CALGARY, March 6, 2020 /PRNewswire/ - Vermilion
Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX,
NYSE: VET) is pleased to report operating and financial results for
the year ended December 31, 2019 along with our 2019
reserves and resources information.
The audited financial statements, management discussion and
analysis, and annual information form for the year
ended December 31, 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
- Fund flows from operations ("FFO") in Q4 2019 was $216 million ($1.38/basic share(1)), which is in
line with the previous quarter despite a significant inventory
build in Australia. FFO in 2019
was a record $908 million
($5.87/basic share), representing an
increase of 8% from the prior year primarily due to higher
production, partially offset by lower commodity prices.
- Q4 2019 production averaged 97,875 boe/d, representing a 1%
increase from the prior quarter, primarily due to higher
performance in our US and Netherlands business units. Annual average
production for 2019 increased by 15% year-over-year to a record
100,357 boe/d, reflecting a full-year contribution from the assets
acquired in 2018 and organic growth from our Netherlands, Australia and US business units. Production
per share increased by 5% in 2019.
- In the United States, Q4 2019
production averaged 5,683 boe/d, an increase of 15% from the prior
quarter, primarily driven by contributions from our Q3 2019
drilling program.
- In the Netherlands, Q4 2019
production averaged 8,088 boe/d, an increase of 9% from the prior
quarter, primarily due to the restoration of production following
planned and unplanned facility downtime in Q3 2019. During the
fourth quarter, we successfully drilled and completed the
Weststellingwerf well (0.5 net), representing our first drilling
activity in the Netherlands since
2017. We encountered three gas-bearing zones in the Vlieland,
Zechstein and Rotliegend formations. The Weststellingwerf well
flowed at an initial gross rate of 14.7 mmcf/d(2) and is
expected to be brought on production during 2020.
- In Canada, Q4 2019 production
averaged 58,593 boe/d, up slightly from the prior quarter as strong
results from new well completions more than offset natural decline.
During the quarter, we drilled one of our best ever condensate-rich
Lower Mannville wells in Drayton
Valley, achieving an IP30 rate of 1,900 boe/d (60%
liquids).
- Our 2019 reserves as evaluated by GLJ as at December 31, 2019 are as follows:
-
- Proved plus probable ("2P") reserves increased 3% from year-end
2018 to 501.2(3) mmboe. We replaced 120% of 2019
production through development activities and 136% including
acquisitions. Our 2P finding and development ("F&D")
cost(4) was $9.93 per boe,
including future development capital ("FDC")(4),
resulting in an organic 2P Operating Recycle Ratio(5)
(including FDC) of 3.0x.
- Proved ("1P") reserves increased 4% from year-end 2018 to
310.2(3) mmboe. We replaced 121% of 1P reserves through
development activities and 133% including acquisitions. Our 1P
F&D cost was $11.90 per boe,
including FDC, resulting in an organic 1P Operating Recycle
Ratio(5) (including FDC) of 2.5x.
- Proved developed producing ("PDP") reserves increased 4% from
year-end 2018 to 200.0(3) mmboe. We replaced 113% of PDP
reserves through development activities and 122% including
acquisitions. Our PDP F&D cost was $12.71 per boe, including FDC, resulting in an
organic PDP Operating Recycle Ratio(5) (including FDC)
of 2.3x.
- Vermilion's board of directors has approved a 50% reduction in
our monthly dividend to $0.115 per
share in response to weakness in commodity prices and reduced
global economic prospects following the outbreak of the novel
coronavirus (COVID-19). The revised dividend will be effective for
the March dividend payable on April 15,
2020.
(1)
|
Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section
of the accompanying Management's Discussion and
Analysis.
|
|
|
(2)
|
The Weststellingwerf
flow rate was 14.7 mmcf/d gross over a 24 hour period at a wellhead
pressure of 1,625 psi. Initial flow rates are not necessarily
indicative of long-term performance or ultimate
recovery.
|
|
|
(3)
|
Estimated company
interest proved, developed and producing, total proved, and total
proved plus probable reserves as evaluated by GLJ Petroleum
Consultants Ltd. ("GLJ") in a report dated February 10, 2020 with
an effective date of December 31, 2019 (the "2019 GLJ Reserves
Report").
|
|
|
(4)
|
F&D (finding and
development) and FD&A (finding, development and acquisition)
costs are used as a measure of capital efficiency and are
calculated by dividing the applicable capital expenditures for the
period, including the change in undiscounted FDC (future
development capital), by the change in the reserves, incorporating
revisions and production, for the same period.
|
|
|
(5)
|
Operating Recycle
Ratio is a measure of capital efficiency calculated by dividing the
Operating Netback by the cost of adding reserves (F&D
cost). Operating Netback is calculated as sales less
royalties, operating expense, transportation costs, PRRT and
realized hedging gains and losses presented on a per unit
basis.
|
|
|
|
|
|
|
($M except as
indicated)
|
Q4
2019
|
Q3
2019
|
Q4
2018
|
2019
|
2018
|
Financial
|
|
|
|
|
|
Petroleum and natural
gas sales
|
388,802
|
391,935
|
456,939
|
1,689,863
|
1,678,117
|
Fund flows from
operations
|
215,592
|
216,153
|
222,342
|
908,055
|
838,652
|
Fund flows from
operations ($/basic share) (1)
|
1.38
|
1.39
|
1.46
|
5.87
|
5.96
|
Fund flows from
operations ($/diluted share) (1)
|
1.38
|
1.39
|
1.44
|
5.82
|
5.89
|
Net earnings
(loss)
|
1,477
|
(10,229)
|
323,373
|
32,799
|
271,650
|
Net earnings (loss)
($/basic share)
|
0.01
|
(0.07)
|
2.12
|
0.21
|
1.93
|
Capital
expenditures
|
100,625
|
127,879
|
163,580
|
523,164
|
518,214
|
Acquisitions
|
9,165
|
4,657
|
2,689
|
38,472
|
1,759,425
|
Asset retirement
obligations settled
|
7,352
|
3,586
|
6,562
|
19,442
|
15,765
|
Cash dividends
($/share)
|
0.690
|
0.690
|
0.690
|
2.760
|
2.715
|
Dividends
declared
|
107,702
|
107,176
|
105,310
|
427,311
|
388,111
|
% of fund flows from
operations
|
50%
|
50%
|
47%
|
47%
|
46%
|
Net dividends
(1)
|
97,502
|
98,316
|
100,195
|
392,374
|
339,060
|
% of fund flows from
operations
|
45%
|
45%
|
45%
|
43%
|
40%
|
Payout
(1)
|
205,479
|
229,781
|
270,337
|
934,980
|
873,039
|
% of fund flows from
operations
|
95%
|
106%
|
122%
|
103%
|
104%
|
Net debt
|
1,993,194
|
2,001,870
|
1,929,529
|
1,993,194
|
1,929,529
|
Net debt to four
quarter trailing fund flows from operations
|
2.20
|
2.19
|
2.30
|
2.20
|
2.30
|
Operational
|
|
|
|
|
|
Production
|
|
|
|
|
|
Crude oil and
condensate (bbls/d)
|
46,261
|
47,242
|
47,678
|
47,902
|
39,182
|
NGLs
(bbls/d)
|
8,160
|
7,772
|
7,815
|
7,984
|
6,366
|
Natural gas
(mmcf/d)
|
260.72
|
253.36
|
276.77
|
266.82
|
250.33
|
Total
(boe/d)
|
97,875
|
97,239
|
101,621
|
100,357
|
87,270
|
Average realized
prices
|
|
|
|
|
|
Crude oil and
condensate ($/bbl)
|
71.25
|
73.45
|
66.19
|
74.42
|
79.16
|
NGLs
($/bbl)
|
14.63
|
6.14
|
25.69
|
13.61
|
26.33
|
Natural gas
($/mcf)
|
3.61
|
2.43
|
5.83
|
3.58
|
5.45
|
Production mix (% of
production)
|
|
|
|
|
|
% priced with
reference to WTI
|
40%
|
39%
|
37%
|
39%
|
32%
|
% priced with
reference to Dated Brent
|
17%
|
19%
|
18%
|
18%
|
20%
|
% priced with
reference to AECO
|
26%
|
26%
|
26%
|
25%
|
26%
|
% priced with
reference to TTF and NBP
|
17%
|
16%
|
19%
|
18%
|
22%
|
Netbacks
($/boe)
|
|
|
|
|
|
Operating netback
(1)
|
27.53
|
28.22
|
27.58
|
29.25
|
31.59
|
Fund flows from
operations netback
|
24.40
|
23.73
|
23.79
|
24.77
|
26.47
|
Operating
expenses
|
12.52
|
11.55
|
12.04
|
12.01
|
11.26
|
General and
administration expenses
|
1.88
|
1.50
|
1.37
|
1.61
|
1.64
|
Average reference
prices
|
|
|
|
|
|
WTI (US
$/bbl)
|
56.96
|
56.45
|
58.81
|
57.03
|
64.77
|
Edmonton Sweet index
(US $/bbl)
|
51.59
|
51.79
|
32.51
|
52.15
|
53.65
|
Saskatchewan LSB index
(US $/bbl)
|
51.58
|
52.01
|
44.03
|
52.50
|
56.46
|
Dated Brent (US
$/bbl)
|
63.25
|
61.94
|
67.76
|
64.30
|
71.04
|
AECO
($/mcf)
|
2.48
|
1.06
|
1.56
|
1.76
|
1.50
|
NBP ($/mcf)
|
5.38
|
4.50
|
11.03
|
5.90
|
10.35
|
TTF ($/mcf)
|
5.36
|
4.40
|
10.91
|
5.90
|
10.23
|
Average foreign
currency exchange rates
|
|
|
|
|
|
CDN $/US $
|
1.32
|
1.32
|
1.32
|
1.33
|
1.30
|
CDN $/Euro
|
1.46
|
1.47
|
1.51
|
1.49
|
1.53
|
Share information
('000s)
|
|
|
|
|
|
Shares outstanding -
basic
|
156,290
|
155,505
|
152,704
|
156,290
|
152,704
|
Shares outstanding -
diluted (1)
|
159,912
|
159,260
|
156,173
|
159,912
|
156,173
|
Weighted average
shares outstanding - basic
|
155,950
|
155,254
|
152,588
|
154,736
|
140,619
|
Weighted average
shares outstanding - diluted (1)
|
156,180
|
155,421
|
153,880
|
156,094
|
142,335
|
(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
We are now in the sixth year of a period of reduced energy
prices that began in the second half of 2014, with the novel
coronavirus (COVID-19) being the latest event to produce a
retracement in commodity markets. Throughout this period, we
have maintained focus on profitability by grinding costs out of all
phases of our business ranging from field operations to financing
expense, upgrading our capital project slate, and adapting our
capital markets model to focus even more acutely on returning
capital to shareholders. In this environment, we have been
unique among our traditional competitor group in maintaining our
dividend while still providing a moderate level of growth. We
have paid a monthly dividend (or distribution in the trust era) for
the past 205 consecutive months, returning over $40 per share to shareholders over this
period. During the energy downturn, we have put more
production, reserves and free cash flow behind each share despite
dramatically lower capital budgets. While still modestly over
100%, we brought our total payout ratio down to 103% in 2019,
representing our lowest total payout ratio since before the
financial crisis in 2008. Moreover, we are phasing out the
small level of remaining DRIP participation at the end of Q3 2020,
resulting in 100% of dividends being paid in cash.
We are proud of this record of returning capital to shareholders
while still providing per share growth. We think paying
dividends is the right thing to do. This model has kept us
disciplined in a capital-intensive industry and has put substantial
cash back in the hands of investors. As we started 2020, our
funding status continued to improve to a projected total payout
ratio below 100%, driven by a significantly lower capital budget
for 2020 as compared to 2019, and by a modestly positive trend for
oil prices. In that environment, we were confident in our
ability to continue our monthly dividend at $0.23 while deleveraging our balance sheet.
We were clear in stating that we would reevaluate the dividend in
the event of a structural change in commodity prices that could
affect our ability to self-fund our combination of capital
expenditures and dividends, and that we would prioritize balance
sheet strength over other objectives, including either growth or
dividends.
The emergence of COVID-19 was an unanticipated event, and we do
not claim any special expertise in assessing what the appropriate
type or degree of public health responses are to the
outbreak. Nonetheless, we must make an assessment of its
current and probable future market and economic impacts. We
observe that COVID-19 has dramatically altered individual, business
and government behavior, and that these impacts are decidedly
negative for the outlook for global economic growth, commodity
prices in general, and oil demand and prices in particular.
We do not believe that the long-term prospects for the oil and gas
industry are likely to be significantly altered, and ultimately we
expect a resumption of a positive trend for commodity prices.
However, we do think the recovery in oil prices that we began to
experience at the outset of 2020 will be pushed back for an unknown
period. In the short-to-medium term, we believe COVID-19
represents a hard-to-quantify set of macro risks, probably lower in
economic severity than the financial crisis of 2008, but of a type
that is also likely unprecedented in our lifetimes.
We have maintained our dividend though a number of other periods
of downside volatility since the commodity crash of 2014, making
all of the necessary adjustments to costs and growth levels.
During these periods, we continuously assessed our dividend policy
in light of our top priority of balance sheet strength. As we
consider today's economic and commodity outlook, we believe it is
unlikely that we would achieve fully-funded status for our present
dividend at a reasonable level of capital expenditures.
Therefore, we have determined that a reduction to our dividend is
the most prudent course of action at this time. Accordingly,
our board of directors has approved a 50% reduction in our monthly
dividend to $0.115 per share, or
$1.38 on an annualized basis.
The revised dividend will be effective for the March dividend
payable on April 15, 2020. At
the current forward commodity strip, we estimate a 2020 payout
ratio of 99%, including previously declared dividends. Any
excess cash generated beyond the dividend and capital requirements
will be allocated towards debt reduction at this time, while
retaining the option of buying back shares through our NCIB program
in an improved macroeconomic environment.
We have had no operational impacts from COVID-19 to-date.
We have business continuity plans for each of our business units
and for our corporate center that can be invoked if the outbreak
significantly worsens and threatens our supply chain or workforce
capabilities.
During 2019, Vermilion generated record cash flow, production
and reserves despite a continued environment of challenging
commodity prices. We recorded FFO of $908 million in 2019 on a capital program of
$523 million, which translated to
free cash flow(1) generation of $385 million, also the highest in our
history. The resulting 2019 total payout ratio, after
accounting for dividends and asset retirement obligations, was
103%. In Q4 2019, we generated $216
million of FFO which was in line with the prior quarter
despite a large inventory build in Australia due to the timing of crude
liftings. Net debt in 2019 increased modestly to $2.0 billion, however the net debt to trailing
FFO ratio improved to 2.2x, compared to 2.3x in 2018. In
addition to an improving leverage profile, we also enhanced the
quality of our balance sheet over the past year. We have
recently received commitments to extend our $2.1 billion covenant-based credit facility,
resulting in a new a maturity date of May
2024. The closing of the extension remains subject to
customary closing conditions. In addition, in June 2019, we executed a cross currency interest
rate swap on our 2025 US$300 million
long-term senior notes, converting our 5.625% interest cost on
these notes to 3.275% for the remainder of their term. As a
result of these initiatives, our pre-tax cost of debt today is
approximately 3.2% with a weighted-average remaining term of 4.4
years.
We delivered record production of 100,357 boe/d in 2019,
representing year-over-year growth of 15%, or 5% on a per share
basis. We achieved these results despite several unexpected
operational challenges throughout the year, including a third-party
refinery outage in France and
uncharacteristic weather-driven delays in Canada. During the
fourth quarter we tied-in two discoveries in Hungary and successfully drilled the
Weststellingwerf well in the
Netherlands, marking our first drilling activity in that
country in two and a half years. In the US, new well
completions from our Q3 2019 program drove increased production
from our North American region. Two months into the new year,
the execution of our 2020 capital program is progressing as
planned. To mitigate the risk of another season of
post-breakup weather delays, which affected our results in 2019, we
are front-loading our 2020 capital program by scheduling most of
our North American drilling activity into the first quarter.
Proved plus probable reserves increased by 3% year-over-year to
501.2 mmboe. The large majority of our new reserve additions
were through organic activities as we continue to enhance the
recovery factor on existing assets and advanced resources to
reserves in a number of our operating areas. We added these
reserves at an organic F&D cost of $9.93/boe, including FDC, resulting in an
operating recycle ratio of 3.0x and funds flow recycle ratio of
2.5x. Our F&D costs have been below $10.00/boe for the past three years (3-year
average F&D of $9.38, including
FDC), while growing our liquids weighting. Driven by a
capital-efficient project slate and a continued focus on cost
improvements, our 3-year organic operating recycle ratio stands at
3.2x. Our contingent and prospective resource bases remain a
source of reserve additions, with 31.8 mmboe of contingent and 5.0
mmboe of prospective resources converted to 2P reserves during
2019.
As we stated earlier, our top financial priority remains balance
sheet strength. Both our debt-to-cash flow ratio and
weighted-average interest rate decreased in 2019, and our debt
exposures are fully termed-out via our covenant-based bank facility
and long-term notes. Nonetheless, we will continue to be
vigilant regarding commodity prices and resulting cash flows.
It remains to be seen how long oil demand and economic growth will
be suppressed by the global reaction to COVID-19. Should we
experience an even more-pronounced and protracted commodity
downturn due to COVID-19 or any other cause, we will be attentive
to all forms of cash outlays, focusing first on capital investment
levels, to protect the financial position of the company.
Q4 2019 Operations Review
Europe
In France, Q4 2019 production
averaged 10,264 boe/d, representing a slight decrease from the
prior quarter primarily due to weather-driven downtime in the
Aquitaine Basin. Production in the Paris Basin was relatively consistent with the
prior quarter.
In the Netherlands, Q4 2019
production averaged 8,088 boe/d, an increase of 9% from the prior
quarter. The increase was primarily due to the restoration of
production following planned and unplanned facility downtime in Q3
2019. During the quarter, we successfully drilled and
completed the Weststellingwerf well (0.5 net), representing our
first drilling activity in the
Netherlands since 2017. We encountered three
gas-bearing zones in the Vlieland, Zechstein and Rotliegend
formations. The Weststellingwerf well flowed at an initial
gross rate of 14.7 mmcf/d(2) and is expected to be
brought on production during 2020.
In Ireland, production averaged
42 mmcf/d (7,049 boe/d) in Q4 2019, a decrease of 2% from the prior
quarter. The decrease was primarily due to natural decline,
partially offset by higher uptime at the Corrib natural gas
processing facility compared to the prior quarter. As
disclosed in our Q3 2019 release, we had 10 days of unplanned
downtime in one of the plant auxiliary systems, which occurred at
the end of Q3 2019 and continued into Q4 2019. Since assuming
operatorship of Corrib at the end of 2018, we have reduced
operating costs by approximately 20% and continue to evaluate other
optimization opportunities.
In Germany, Q4 2019 production
averaged 3,373 boe/d, an increase of 3% from the prior
quarter. The increase was primarily due to improved uptime on
our operated oil and natural gas assets, partially offset by
unplanned downtime on our non-operated oil assets. Following
the successful drilling of the Burgmoor Z5 (46% working interest)
well in 2019, the partner group has agreed to a tie-in plan which
should allow for production early next year.
In Central and Eastern Europe
("CEE"), production averaged 276 boe/d following the tie-in of two
discoveries from our 2019 drilling program late in the year.
In Hungary, we tied-in the Mh-21
(0.3 net) and Battonya E-09 (1.0 net) wells, drilled in the second
and third quarters of 2019, respectively. The wells were
brought on production midway through the fourth quarter of 2019 at
a restricted rate of approximately 600 boe/d net for the two wells
combined. In addition, we were provisionally awarded the
Kadarkút exploration license in western Hungary during the quarter and we expect to
receive final government approvals in the first quarter of
2020. The license covers approximately 298,500 net acres and
consists of primarily oil prospects. Most of the license is
covered by 3D seismic. The license term covers a four year
period, with the option to extend the license for a further two
years. In Croatia, we
continued to prepare for our 2020-2021 drilling programs, in
addition to evaluating natural gas plant processing facility
construction options, which we expect to allow tie-in of our 2019
natural gas discoveries next year.
North America
In Canada, production averaged
58,593 boe/d in Q4 2019, up slightly from the prior quarter.
Strong results from new well completions in the quarter more than
offset natural decline. We drilled or participated in 26
(16.8 net) wells in the fourth quarter of 2019, eight (8.0 net) of
which were drilled in Alberta and
18 (8.8 net) drilled in Saskatchewan. During the quarter, we
drilled one of our best ever condensate-rich Lower Mannville wells
in Drayton Valley, Alberta,
achieving an IP30 rate of approximately 1,900 boe/d (60%
liquids). In Ferrier, we drilled a liquids-rich Upper
Mannville well which delivered an IP30 rate of approximately 1,800
boe/d (15% liquids). We brought 33 (23.5 net) wells on
production in Saskatchewan and
four (4.0 net) wells on production in Alberta during the quarter. We are
currently in the midst of a very active Q1 2020 drilling campaign
in Canada, with rig activity in
the quarter peaking at six rigs in Saskatchewan and four rigs in Alberta.
We plan to complete the majority of our 2020 Canadian drilling
program in the first quarter of the year in order to avoid
potential delays from an extended spring break-up season or
unseasonably wet summer weather.
In the United States, Q4 2019
production averaged 5,683 boe/d, representing an increase of 15%
from the prior quarter. The increase was primarily due to a
full quarter of contribution from the four wells we brought on
production during the third quarter of 2019. These wells
continue to perform in line with our type curves, achieving an
average IP90 rate of approximately 450 boe/d. We also began
drilling two (1.98 net) wells in December
2019, for which drilling finished in January 2020, and are currently undergoing
completion. We currently have two rigs operating in our
Hilight field in the Powder River Basin. Similar to our
Canadian business unit, we plan to execute a front-end weighted
capital program in the United
States, completing our twelve (11.9 net) well 2020 drilling
program in the first half of the year.
Australia
In Australia, production
averaged 4,548 bbl/d in Q4 2019, a decrease of 18% from the
previous quarter, primarily due to the planned shutdown of the
Wandoo platform for eight days to perform facility upgrades and
regular maintenance. We recently began the installation of
electric submersible pumps on two wells and will continue to
advance process optimization projects throughout 2020.
Dividend Reinvestment Plan
As previously announced, we are phasing out the Dividend
Reinvestment Plan ("DRIP") in 2020 by prorating the available DRIP
shares by 25% each quarter starting in Q1 2020. It is our
intention to increase this proration each quarter throughout the
year, such that the DRIP will be eliminated at the end of the third
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 February
24, 2020, we currently have 51% of our expected
net-of-royalty production hedged for Q1 2020. More than half
of our Q1 2020 corporate hedge position consists of two-way collars
and three-way structures, which allow participation in price
increases up to contract ceilings. For 2020 as a whole,
approximately 42% of our production is hedged, with 63% of our
hedge position in participating structures.
With respect to individual products within our product mix, we
have hedged 70% of anticipated European natural gas volumes for Q1
2020. We have also hedged 78% 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, 44% of our expected Q1 2020 oil production is
hedged. For Q1 2020, 45% of our North American natural gas
production is priced away from AECO, with a variety of contracts to
sell gas at the SoCal Border, Henry Hub, Saskatchewan and Wyoming.
Sustainability
We delivered another year of industry-leading performance as
indicated by a number of important ESG rankings. The Company
received a top quartile ranking for our industry sector in SAM's
2019 Corporate Sustainability Assessment ("CSA"). The CSA
analyzes sustainability performance across economic, environmental,
governance, and social criteria, and is the basis of the Dow Jones
Sustainability Indices. Vermilion was ranked second in our
peer group in the Sustainalytics ESG (environment, social,
governance) rankings. Vermilion's MSCI ESG rating increased
to AA in 2019, and our Governance Metrics score ranked in the top
decile globally. We received ISS QualityScore decile ratings
of 1 for both Environmental and Social, which assess corporate
disclosure and transparency practices in these areas, where 1
indicates the lowest risk. These rankings reflect our high
degree of ESG focus, and we will strive to continue to this record
of high performance as we move forward.
2019 Reserves and Resources
In 2019 we increased our reserves and resources predominantly
through development activities. Based on the 2019 GLJ
Reserves Report, our 2P reserves increased 3% from year-end 2018 to
501.2(3) mmboe, while our 1P reserves increased 4% from
year-end 2018 to 310.2(3) mmboe in 2019. PDP
reserves increased 4% from year-end 2018 to 200.0(3)
mmboe. Our PDP reserves represent 65% of our 1P reserves.
The following table provides a summary of company interest
reserves by reserve category and country on an oil equivalent
basis. Please refer to Vermilion's 2019 Annual Information
Form for the year ending December 31,
2019 ("2019 Annual Information Form") for detailed by
product type information.
|
|
|
|
|
|
|
BOE
(mboe)
|
Proved
Developed
Producing
|
Proved
Developed
Non-Producing
|
Proved
Undeveloped
|
Proved
|
Probable
|
Proved Plus
Probable
|
Australia
|
8,608
|
—
|
—
|
8,608
|
4,552
|
13,160
|
Canada
|
111,738
|
7,125
|
72,764
|
191,627
|
109,262
|
300,889
|
CEE
|
228
|
1,503
|
—
|
1,731
|
972
|
2,703
|
France
|
35,109
|
934
|
4,920
|
40,963
|
18,729
|
59,692
|
Germany
|
9,694
|
2,930
|
1,157
|
13,781
|
12,959
|
26,740
|
Ireland
|
11,772
|
—
|
—
|
11,772
|
6,002
|
17,774
|
Netherlands
|
8,620
|
2,035
|
450
|
11,105
|
9,875
|
20,980
|
United
States
|
14,222
|
515
|
15,886
|
30,623
|
28,673
|
59,296
|
Vermilion
|
199,991
|
15,042
|
95,177
|
310,210
|
191,024
|
501,233
|
Through development activities, we replaced 120% of 2P reserves,
121% of 1P reserves and 113% of PDP reserves, respectively.
Including acquisitions, we replaced 136% of 2P reserves, 133% of 1P
reserves and 122% of PDP reserves, respectively. Reserve
additions included 15.0 million boe of positive technical revisions
at the 1P level.
Our Operating Recycle Ratio(5) (including FDC) at the
2P level was 3.0x in 2019. We have achieved F&D costs
below $10.00/boe for the past three
years (3-year average F&D of $9.38, including FDC) as a result of our highly
capital-efficient project slate and continued focus on cost
improvements.
The following table summarizes the finding and development costs
and associated operating recycle ratios by reserve category for the
year ending December 31, 2019:
|
|
|
|
2019
|
3-Year
Average
|
|
PDP
|
1P
|
2P
|
PDP
|
1P
|
2P
|
Finding and
Development Costs, including FDC (F&D)(4)
($/boe)
|
$12.71
|
$11.90
|
$9.93
|
$13.66
|
$12.71
|
$9.38
|
Finding, Development
and Acquisition Costs, including FDC (FD&A)(4)
($/boe)
|
$12.69
|
$11.82
|
$9.85
|
$19.31
|
$17.48
|
$13.84
|
|
|
|
|
|
|
|
F&D Operating
Recycle Ratio(5) *
|
2.3
|
2.5
|
3.0
|
2.2
|
2.4
|
3.2
|
FD&A Operating
Recycle Ratio(5) *
|
2.3
|
2.5
|
3.0
|
1.6
|
1.7
|
2.2
|
In addition to our reserve base, we report contingent and
prospective resources. According to the 2019 GLJ Resources
Report, risked low, best, and high estimates for our contingent
resources in the Development Pending category were
139.0(6) mmboe, 236.8(6) mmboe, and
330.2(6) mmboe, respectively. The 2019 GLJ
Resources Report also indicates risked low, best, and high
estimates for contingent resources in the Development Unclarified
category of 10.8(6) mmboe, 37.6(6) mmboe, and
54.1(6) mmboe, respectively. Over 86% of our best
estimate risked contingent resources reside in the Development
Pending category. Prospective resources were assessed at
risked low, best and high estimates of 51.9(6) mmboe,
179.2(6) mmboe, and 330.2(6) mmboe,
respectively. Our contingent and prospective resource bases
remain a source of reserve additions, with 31.8 mmboe of contingent
and 5.0 mmboe of prospective resources converted to 2P reserves
during 2019.
The following table provides a reconciliation of changes in
company interest reserves by reserve category and country.
Please refer to Vermilion's 2019 Annual Information Form for
detailed by product type information.
|
|
|
|
|
|
|
|
|
|
1P
(mboe)
|
Australia
|
Canada
|
CEE
|
France
|
Germany
|
Ireland
|
Netherlands
|
United
States
|
Vermilion
|
December 31,
2018
|
9,668
|
181,938
|
131
|
43,467
|
12,990
|
13,094
|
11,804
|
25,146
|
298,236
|
Discoveries
|
—
|
491
|
1,725
|
—
|
844
|
—
|
—
|
—
|
3,060
|
Extensions &
improved recovery
|
—
|
20,981
|
—
|
551
|
470
|
—
|
720
|
4,254
|
26,976
|
Technical
revisions
|
1,007
|
7,019
|
(100)
|
806
|
743
|
1,511
|
1,601
|
2,368
|
14,955
|
Acquisitions
|
—
|
3,847
|
—
|
—
|
—
|
—
|
—
|
561
|
4,408
|
Dispositions
|
—
|
(13)
|
—
|
—
|
—
|
—
|
—
|
—
|
(13)
|
Economic
factors
|
—
|
(744)
|
—
|
(40)
|
—
|
—
|
—
|
—
|
(784)
|
Production
|
(2,067)
|
(21,892)
|
(25)
|
(3,821)
|
(1,266)
|
(2,833)
|
(3,020)
|
(1,706)
|
(36,630)
|
December 31,
2019
|
8,608
|
191,627
|
1,731
|
40,963
|
13,781
|
11,772
|
11,105
|
30,623
|
310,210
|
|
|
|
|
|
|
|
|
|
|
2P
(mboe)
|
Australia
|
Canada
|
CEE
|
France
|
Germany
|
Ireland
|
Netherlands
|
United
States
|
Vermilion
|
December 31,
2018
|
14,480
|
284,835
|
190
|
63,918
|
25,733
|
20,576
|
22,200
|
56,213
|
488,145
|
Discoveries
|
—
|
1,044
|
2,686
|
—
|
1,250
|
—
|
—
|
—
|
4,980
|
Extensions &
improved recovery
|
—
|
31,200
|
—
|
810
|
920
|
—
|
1,131
|
2,693
|
36,754
|
Technical
revisions
|
747
|
1,190
|
(148)
|
(549)
|
103
|
31
|
669
|
1,143
|
3,186
|
Acquisitions
|
—
|
5,350
|
—
|
—
|
—
|
—
|
—
|
953
|
6,303
|
Dispositions
|
—
|
(428)
|
—
|
—
|
—
|
—
|
—
|
—
|
(428)
|
Economic
factors
|
—
|
(410)
|
—
|
(666)
|
—
|
—
|
—
|
—
|
(1,076)
|
Production
|
(2,067)
|
(21,892)
|
(25)
|
(3,821)
|
(1,266)
|
(2,833)
|
(3,020)
|
(1,706)
|
(36,630)
|
December 31,
2019
|
13,160
|
300,889
|
2,703
|
59,692
|
26,740
|
17,774
|
20,980
|
59,296
|
501,233
|
Additional information about our 2019 GLJ Reserves Report and
GLJ 2019 Resources Report can be found in our 2019 Annual
Information Form on our website at www.vermilionenergy.com and on
SEDAR at www.sedar.com.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
March 5, 2020
(1)
|
Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section
of the accompanying Management's Discussion and
Analysis.
|
|
|
(2)
|
The Weststellingwerf
flow rate was 14.7 mmcf/d gross over a 24 hour period at a wellhead
pressure of 1,625 psi. Initial flow rates are not necessarily
indicative of long-term performance or ultimate
recovery.
|
|
|
(3)
|
Estimated company
interest proved, developed and producing, total proved, and total
proved plus probable reserves as evaluated by GLJ Petroleum
Consultants Ltd. ("GLJ") in a report dated February 10, 2020 with
an effective date of December 31, 2019 (the "2019 GLJ Reserves
Report").
|
|
|
(4)
|
F&D (finding and
development) and FD&A (finding, development and acquisition)
costs are used as a measure of capital efficiency and are
calculated by dividing the applicable capital expenditures for the
period, including the change in undiscounted FDC (future
development capital), by the change in the reserves, incorporating
revisions and production, for the same period.
|
|
|
(5)
|
Operating Recycle
Ratio is a measure of capital efficiency calculated by dividing the
Operating Netback by the cost of adding reserves (F&D
cost). Operating Netback is calculated as sales less
royalties, operating expense, transportation costs, PRRT and
realized hedging gains and losses presented on a per unit
basis.
|
|
|
(6)
|
Vermilion retained
GLJ to conduct an independent resource evaluation dated February
10, 2020 to assess contingent and prospective resources across all
of the Company's key operating regions with an effective date of
December 31, 2019 (the "GLJ 2019 Resources Report"). The
aggregate associated chance of development for each of the low,
best and high estimate for contingent resources in the Development
Pending category are 83%, 81% and 81%, respectively. The
aggregate associated chance of commerciality for each of the low,
best and high estimate for prospective resources in the Prospect
category are 24%, 24% and 24%, respectively. There is
uncertainty that it will be commercially viable to produce any
portion of the resources. Project maturity subclass
development pending is defined as contingent resources where
resolution of the final conditions for development is being
actively pursued (high chance of development). Project
maturity subclass development unclarified is defined as contingent
resources when the evaluation is incomplete and there is ongoing
activity to resolve any risks or uncertainties. Prospective
resources are defined as those quantities of petroleum estimated,
as of a given date, to be potentially recoverable from unknown
accumulations by application of future development projects.
There is no certainty that it will be commercially viable to
produce any portion of the contingent resources or that Vermilion
will produce any portion of the volumes currently classified as
contingent resources. There is no certainty that any portion
of the prospective resources will be discovered. If
discovered, there is no certainty that it will be commercially
viable to produce any portion of the prospective resources or that
Vermilion will produce any portion of the volumes currently
classified as prospective resources. Please refer to
Vermilion's 2019 Annual Information Form for further information on
Vermilion's contingent resources and prospective
resources.
|
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. On October 31, 2019,
we reduced our 2019 capital expenditure guidance to $520 million and our 2019 annual production
guidance to 100,000 to 101,000 boe/d. Actual 2019 capital
spending of $523 million was within
1% of our guidance and 2019 average production of 100,357 boe/d was
approximately at the mid-point of our revised guidance range.
On October 31, 2019, we released
our 2020 capital budget and associated production guidance.
The following table summarizes our guidance:
|
|
|
|
|
Date
|
Capital
Expenditures ($MM)
|
Production
(boe/d)
|
2019
Guidance
|
|
|
|
2019
Guidance
|
October 25,
2018
|
530
|
101,000 to
106,000
|
2019
Guidance
|
October 31,
2019
|
520
|
100,000 to
101,000
|
2019 Actual
Results
|
March 6,
2020
|
523
|
100,357
|
2020
Guidance
|
|
|
|
2020
Guidance
|
October 31,
2019
|
450
|
100,000 to
103,000
|
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call and
webcast presentation on Friday, March 6,
2020 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 conference ID 8457996 from March 6, 2020 at 12:00 PM
MST to March 20, 2020 at
9:59 PM MST.
You may also access the webcast at
https://event.on24.com/wcc/r/2209057/77DA8099A827A0D8BC4A73C85AFABBDD.
The webcast link, along with conference call slides, will be
available on Vermilion's website at
https://www.vermilionenergy.com/ir/eventspresentations.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 $0.115 per
share, which provides a current yield of approximately 11%.
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
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 2020 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 2020; 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.
View original content to download
multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-results-for-the-year-ended-december-31-2019-and-2019-reserves-and-resources-information-301018846.html
SOURCE Vermilion Energy Inc.