CALGARY,
AB, Sept. 10, 2024 /CNW/ - Vermilion
Energy Inc. ("Vermilion", "We", "Our", or the "Company") (TSX: VET)
(NYSE: VET) is pleased to provide an operational update on key
projects.
In Germany, we successfully
completed testing operations for our first deep gas exploration
well drilled earlier this year. The well was completed in the
Rotliegend zone at a depth of approximately 5,000 meters and flow
tested at a restricted rate of 17 mmcf/d(1) of natural
gas with a wellhead pressure of 4,625 psi. Given the high pressure
reading from this well, we believe deliverability would have been
higher without testing equipment limitations. These results are
very encouraging and validate our initial assessment of the
reservoir. Tie-in operations are progressing to bring the well on
production in the first half of 2025. We expect this well to
produce into a third-party system at a restricted rate.
Following the success of our first deep gas exploration well, we
began drilling our second deep German exploration well in
August 2024, a process that will
continue through the fourth quarter. Recently, we signed an
agreement with a third-party to farm down half of our working
interest in this well to 30% (previously 60%) which will reduce our
risked capital requirements and further enhance project returns.
Consequently, along with deferring our 2024 drilling program in
France to 2025, we have
accelerated the drilling of a third deep gas exploration well (100%
working interest) in Germany,
which we expect to spud in the fourth quarter of 2024. Based on our
technical evaluation, we expect this well to be a higher chance of
success prospect, which is further supported by development in
adjacent fields. We believe there is potential resource-in-place to
justify follow-up drilling in the success case. We do not
anticipate the results from the second and third wells will be
known until the first half of 2025.
In Croatia, we successfully
increased production on the SA-10 block after commissioning the gas
plant in late June 2024. Current
production levels now exceed 2,000 boe/d (100% gas). This high
valued natural gas sells at a premium to the TTF benchmark
contributing to strong operating and cash flow netbacks. We plan to
maintain production on the SA-10 block in future years to maximize
free cashflow and have identified prospects for future development.
On the SA-7 block, we completed testing on the third well of our
four-well program, which flow tested at 5.6 mmcf/d(2) of
natural gas. We plan to test the fourth and final well in Q4 2024.
We are very encouraged with the four-well exploration results in
Croatia, which have proven up
multiple producing zones and de-risked future development and
exploration targets across four discrete areas.
European natural gas production comprises 22% of our corporate
production and 40% of our gas production. The primary benchmarks
for European natural gas, TTF and NBP, are strong, with 2025
forward pricing of approximately $17/mmcf or approximately seven times higher than
AECO. This pricing dynamic supports 2024 operating netbacks in
excess of $55/boe(3) from
our European natural gas operations. We continue to actively hedge
this period and have approximately 45% of European natural gas
hedged with protection of $17/mmcf
for 2025. Our continued operational successes in 2024 are
supportive of near and long-term European natural gas exposure.
In Canada, on our Mica Montney asset, we recently brought five
wells (5.0 net) on production from our 9-21 pad that were drilled
and completed earlier this year. The wells produced at an average
IP30 rate of over 1,000 boe/d(4) per well (52%
liquids)(4) which is in line with our type curve. We
continue to realize cost savings on each consecutive pad as we
apply past learnings and incorporate new infrastructure and
processes. The total drill, complete and tie-in cost for the 9-21
pad was approximately $9.6 million
per well as we continue to make progress towards our normalized
targeted cost range of $9.0 to
$9.5 million per well. The new
battery and water infrastructure have achieved 99% run time since
starting up and are contributing to these cost savings.
In Australia, we accelerated
annual turnround activity originally planned for Q4 2024 into Q3
2024 resulting in approximately one month of downtime during the
quarter. We are currently restarting, and we expect the Q3 2024
production impact to be largely offset by the deferral of a
third-party facility turnaround in Canada from Q3 2024 to Q4 2024. Our Q3 2024
capital program is progressing as planned and we remain on track to
achieve our Q3 2024 production forecast of 83,000 to 85,000 boe/d
and full year guidance range of 83,000 to 86,000 boe/d. Our 2024
E&D capital expenditure guidance remains unchanged.
We continue to be active under our NCIB program having
repurchased 1.4 million shares during the month of August 2024. This increases our year-to-date
total share buybacks to 7.5 million shares, representing a net
share count reduction of 4.6% since the start of the year to 155.9
million shares at August 31, 2024. As
we steward to our annual return of capital target of 50% of
EFCF(5) we plan to continue repurchasing shares through
the balance of the year in addition to paying our quarterly
dividend , which is reaffirmed at $0.12 per share for October 15, 2024, to shareholders of record on
September 27, 2024.
We plan to release our Q3 2024 results on November 6, 2024, after the close of North
American markets.
- Osterheide Z2-2 well (100% working interest) is currently being
tested. Flow rates, during the initial clean-up phase, of up to
approx. 490,000 m3(Vn)/d with a flowing wellhead pressure of 4,625
psi on an adjustable choke were achieved. These initial flow
results translate into an AOF of 986,000 m3(Vn)/d. The completion
fluid was recovered during the clean-up flow period. The zone being
tested is the Rotliegend Wustrow formation which was encountered at
5,757m MD and a 42.0 m gas column was logged with 13.8 m of net reservoir and average effective
porosity of 8.3%. Test results are not necessarily indicative of
long-term performance or ultimate recovery.
- Gojlo-1 Jug well (60% working interest) tested at rate of
5.6 mmcf/d and flowing wellhead pressure of 692 psi during a
well cleanup on a 0.5938'' diameter choke. The well was shut-in and
then flow tested for 24 hours on 3 choke sizes (0.25", 0.3125",
0.375") to obtain necessary reservoir data and to minimize flaring.
Gojlo-1Jug well tested 8.5 hours at an average rate of 2.9 mmcf/d
with a flowing wellhead pressure of 861 psi on a 0.375'' diameter
choke. Load fluid was recovered, and no formation water was
produced during the test. A final shut-in wellhead pressure of 1009
psi and bottom hole pressure of 1070 psi were recorded following
the well test. The tested zone was the Mramor Brdo formation which
was encountered at 885mMD and a 17.6m
gas column was logged in the well to the base of the reservoir with
15.6m of net reservoir and an average
porosity of 31%. Test results are not necessarily indicative of
long-term performance or ultimate recovery.
- 2024 operating netback based on Company estimates using
September 3, 2024, strip pricing:
Brent US$80.84/bbl; WTI US$75.55/bbl; LSB = WTI less US$6.31/bbl; TTF $14.56/mmbtu; NBP $14.22/mmbtu; AECO $1.52/mcf; CAD/USD
1.35; CAD/EUR 1.47 and CAD/AUD
0.89. Operating netback is a non-GAAP financial measure comparable
to net earnings and is comprised of sales less royalties, operating
expense, transportation costs, PRRT, and realized hedging gains and
losses presented on a per unit basis. Management assesses operating
netback as a measure of the profitability and efficiency of our
field operations. Operating netback per boe is not a standardized
financial measure under IFRS and, therefore may not be comparable
with the calculation of similar financial measures disclosed by
other entities.
- Initial 30-day production ("IP30") for the Company's most
recent five (5.0 net) wells drilled on our British Columbia lands averaged 1,000 boe/d
per well. IP30 consisted of 44% light and medium crude oil, 8%
NGLs, and 48% shale gas, using a conversion of six mcf of gas to
one barrel of oil, based on field level estimates for the first 30
full days of production following the tie-in of the well.
Production rates presented are for a limited timeframe only and may
not be indicative of future performance or the ultimate recovery
for a given well or pad.
- Excess free cash flow ("EFCF") is comprised of free cash flow
("FCF") less asset retirement obligations settled and capital lease
payments, which are ongoing costs associated with running our
business, and more accurately reflects the free cash available to
return to shareholders. EFCF payout % reflects shareholder returns
as a percentage of EFCF.
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
and unconventional 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. We have been recognized by
leading ESG rating agencies for our transparency on and management
of key environmental, social and governance issues. In addition, we
emphasize strategic community investment in each of our operating
areas.
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 information
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:
well production timing and expected production rates therefrom;
wells expected to be drilled in 2024, 2025 and beyond; exploration
and development plans and the timing thereof; petroleum and natural
gas sales, netbacks, and the expectation of generating strong free
cash flow therefrom; the effect of changes in crude oil and natural
gas prices, changes in exchange and inflation rates; statements
regarding Vermilion's hedging program, its plans to add to its
hedging positions and the anticipate impact of Vermilion's hedging
program on project economics and free cash flows; capital
expenditures including Vermilion's ability to progress towards its
normalized targeted cost range and Vermilion's ability to fund such
expenditures; future production levels and the timing thereof,
including Vermilion's 2024 guidance, and rates of average annual
production growth; statements regarding Vermilion's normal course
issuer bid; the release of Vermilion's Q3 results and the timing
thereof; statements regarding the return of capital; the
flexibility of Vermilion's capital program and operations; business
strategies and objectives; operational and financial performance;
estimated volumes of reserves and resources; significant declines
in production or sales volumes due to unforeseen circumstances;
statements regarding the growth and size of Vermilion's future
project inventory, 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; 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; management's expectations relating to the
timing and results of exploration and development activities; the
impact of Vermilion's dividend policy on its future cash flows;
credit ratings; hedging program; expected earnings/(loss) and
adjusted earnings/(loss); expected earnings/(loss) or adjusted
earnings/(loss) per share; expected future cash flows and free cash
flow and expected future cash flow and free cash flow per share;
estimated future dividends; financial strength and flexibility;
debt and equity market conditions; general economic and competitive
conditions; ability of management to execute key priorities; and
the effectiveness of various actions resulting from the Vermilion's
strategic priorities.
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; constraints at processing facilities and/or
on transportation; 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,
interest rates and inflation; health, safety, and environmental
risks and uncertainties related to environmental legislation,
hydraulic fracturing regulations and climate change; 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; weather conditions, political events and terrorist
attacks; uncertainty in amounts and timing of royalty payments;
risks associated with existing and potential future law suits and
regulatory actions against or involving 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.