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Vermilion Energy Inc. Announces Results for the Three and Nine Months Ended September 30, 2019

October 31, 2019

CALGARY, Oct. 31, 2019 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three and nine months ended September 30, 2019.

The unaudited financial statements and management discussion and analysis for the three and nine months ended September 30, 2019, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.

Highlights

  • Q3 2019 production averaged 97,239 boe/d, a decrease of 6% from the prior quarter. The lower production level resulted from a number of plant turnarounds, unplanned downtime, and weather delays. Higher production in the US and France was more than offset by lower production in Canada, Netherlands, Ireland and Australia.

  • We have reduced our 2019 capital investment guidance by $10 million to $520 million. With nine months of results in place, we are revising our 2019 annual production guidance range to 100,000 to 101,000 boe/d to account for the unplanned downtime and lower capital investment. We expect to deliver annual production at the mid-point of this revised guidance range, reflecting strong year-over-year production per share growth of 5%.

  • Fund flows from operations ("FFO") for Q3 2019 was $216 million ($1.39/basic share(1)), a decrease of 3% from the previous quarter, primarily due to lower production volumes and weaker commodity prices. FFO for Q3 2019 decreased 17% from the same quarter last year as increased production was more than offset by weaker global commodity pricing.

  • In the United States, Q3 2019 production averaged 4,925 boe/d, an increase of 12% from the prior quarter, primarily driven by contributions from our 2019 drilling program, which continues to perform above our expectations. New well results were partially offset by a longer-than-expected turnaround at a third-party operated gas plant.

  • In Central and Eastern Europe, we drilled one (1.0 net) exploration well in Croatia during Q3 2019, which resulted in a second consecutive gas discovery. The well tested at a rate of 17.2 mmcf/d(2). We were also provisionally awarded the SA-07 license in Croatia, adding approximately 500,000 net acres to our portfolio, which will bring our total licensed acreage to approximately 2.4 million net acres in the country.

  • In France, Q3 2019 production averaged 10,347 boe/d, an increase of 6% from the prior quarter. Production volumes in the Paris Basin were no longer restricted after restart of the Grandpuits refinery in mid-August.

  • In Canada, Q3 2019 production averaged 58,504 boe/d, a decrease of 5% from the prior quarter. The decrease was primarily due to planned turnarounds and project delays caused by abnormally wet weather.

  • In the Netherlands, Q3 2019 production averaged 7,429 boe/d, a decrease of 17% from the prior quarter, primarily due to a planned turnaround and subsequent repairs required on a gas compression facility.

  • In Ireland, Q3 2019 production averaged 43 mmcf/d (7,202 boe/d), a decrease of 12% from the prior quarter. The decrease was primarily due to a planned plant turnaround and unplanned downtime at the Corrib natural gas processing facility. The downtime, which was unrelated to the plant turnaround, was remedied by early October.

  • In Australia, Q3 2019 production averaged 5,564 bbl/d, a decrease of 17% from the previous quarter primarily due to well management and unplanned vessel maintenance on the Wandoo platform.

  • Our Board of Directors has approved a 2020 Exploration and Development ("E&D") capital budget of $450 million, with associated production guidance of 100,000 to 103,000 boe/d. Our 2020 budget reflects continued emphasis on returning capital to investors, while still providing modest production growth. Within this budget, we also continue to advance strategic capital projects associated with early-stage exploration and development activities.

  • We have elected to phase out the Dividend Reinvestment Plan ("DRIP"), prorating the available DRIP shares by 25% each quarter starting in Q1 2020, until completely eliminated in Q4 2020.

  • Vermilion received top quartile rankings for 2019 for our industry sector in both the Sustainalytics ESG Rating and SAM (formerly known as RobecoSAM) annual Corporate Sustainability Assessment ("CSA"). These agencies analyze sustainability performance across economic, environmental, governance and social criteria, and the CSA is also the basis of the Dow Jones Sustainability Indices. Our 2019 Sustainability Report is available on our corporate website at: http://sustainability.vermilionenergy.com.

(1)

Non-GAAP Financial Measure.  Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis.



(2)

Berak-01 well (100% working interest) tested at a rate of 17.2 mmcf/d during a four-hour flow period with a stabilized flowing wellhead pressure of 908 psi on a 0.875 inch diameter choke.  A final shut in wellhead pressure of 1,186 psi was recorded following the flow test.  The flow test continued an additional 12 hours at reduced choke sizes to minimize flaring.  No formation water was produced during the test.  The well logged 21 feet of net gas pay with an average porosity of 32% from the Upper Miocene Pannonian sandstone occurring within a gross measured depth interval of 3,006-3,033 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

 













($M except as indicated)

Q3 2019


Q2 2019


Q3 2018



YTD 2019


YTD 2018

Financial











Petroleum and natural gas sales

391,935



428,043



508,411




1,301,061



1,221,178


Fund flows from operations

216,153



222,738



260,705




692,463



616,310


    Fund flows from operations ($/basic share) (1)

1.39



1.44



1.71




4.49



4.51


    Fund flows from operations ($/diluted share) (1)

1.39



1.42



1.69




4.45



4.46


Net earnings (loss)

(10,229)



2,004



(15,099)




31,322



(51,723)


    Net earnings (loss) ($/basic share)

(0.07)



0.01



(0.10)




0.2



(0.38)


Capital expenditures

127,879



92,607



146,185




422,539



354,634


Acquisitions

4,657



8,623



198,173




29,307



1,756,736


Asset retirement obligations settled

3,586



4,907



2,986




12,090



9,203


Cash dividends ($/share)

0.690



0.690



0.690




2.070



2.025


Dividends declared

107,176



106,884



105,192




319,609



282,801


    % of fund flows from operations

50

%


48

%


40

%



46

%


46

%

Net dividends (1)

98,316



98,111



100,872




294,872



238,865


    % of fund flows from operations

45

%


44

%


39

%



43

%


39

%

Payout (1)

229,781



195,625



250,043




729,501



602,702


    % of fund flows from operations

106

%


88

%


96

%



105

%


98

%

Net debt

2,001,870



1,950,509



2,034,086




2,001,870



2,034,086


Net debt to trailing twelve months fund flows from operations

2.19



2.03



2.55




2.19



2.55


Operational

Production











    Crude oil and condensate (bbls/d)

47,242



48,964



47,152




48,455



36,318


    NGLs (bbls/d)

7,772



8,107



6,839




7,925



5,878


    Natural gas (mmcf/d)

253.36



275.60



253.38




268.88



241.42


    Total (boe/d)

97,239



103,003



96,222




101,193



82,433


Average realized prices











    Crude oil and condensate ($/bbl)

73.45



79.46



85.84




75.38



84.98


    NGLs ($/bbl)

6.14



11.25



27.97




13.25



26.61


    Natural gas ($/mcf)

2.43



3.09



5.35




3.56



5.30


Production mix (% of production)











    % priced with reference to WTI

39

%


38

%


37

%



38

%


30

%

    % priced with reference to Dated Brent

19

%


18

%


18

%



18

%


21

%

    % priced with reference to AECO

26

%


26

%


26

%



26

%


26

%

    % priced with reference to TTF and NBP

16

%


18

%


19

%



18

%


23

%

Netbacks ($/boe)











    Operating netback (1)

28.22



29.62



34.85




29.80



33.26


    Fund flows from operations netback

23.73



24.15



29.69




24.89



27.59


    Operating expenses

11.55



11.04



11.13




11.85



10.94


    General and administration expenses

1.50



1.70



1.51




1.53



1.75


Average reference prices











    WTI (US $/bbl)

56.45



59.81



69.50




57.06



66.75


    Edmonton Sweet index (US $/bbl)

51.79



55.19



62.68




52.34



60.69


    Saskatchewan LSB index (US $/bbl)

52.01



55.54



63.35




52.81



60.61


    Dated Brent (US $/bbl)

61.94



68.82



75.27




64.65



72.13


    AECO ($/mcf)

1.06



1.03



1.19




1.64



1.48


    NBP ($/mcf)

4.50



5.44



10.95




6.08



10.12


    TTF ($/mcf)

4.40



5.75



10.92




6.08



10.00


Average foreign currency exchange rates











    CDN $/US $

1.32



1.34



1.31




1.33



1.29


    CDN $/Euro

1.47



1.50



1.52




1.49



1.54


Share information ('000s)

Shares outstanding - basic

155,505



155,032



152,497




155,505



152,497


Shares outstanding - diluted (1)

159,260



158,633



155,747




159,260



155,747


Weighted average shares outstanding - basic

155,254



154,795



152,432




154,326



136,585


Weighted average shares outstanding - diluted (1)

155,421



156,844



153,839




155,673



138,258


(1) 

The above table includes non-GAAP financial measures which may not be comparable to other companies.  Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis.

 

Message to Shareholders

The third quarter of 2019 continued to be an exceptionally difficult period for energy investors, as the upstream oil and gas sector traded down to multi-year lows and significantly underperformed the broader equity market.  Vermilion was not spared.  Our stock price declined over 30% during the quarter, bringing our current dividend yield to approximately 14%.  While we are certainly disappointed with our share price performance, we would like to stress that Vermilion's dividend policy is not based on the market price of our shares. Our dividend policy is based on the fundamental economic sustainability and free cash flow generation of our business, which remains strong.

The capital markets environment for oil and gas companies has changed dramatically over recent years due to a multitude of factors, including poor investment returns from energy issuers, increased focus on ESG and SRI mandates, and a growing concern about the future of fossil fuels amongst both investors and the general public.  This has led to valuation multiple compression across the entire sector with many companies, including Vermilion, trading significantly below their historical valuation metrics.  Despite these changing capital market dynamics, the oil and gas sector is a vital contributor to the global economy and will be around for many decades to support the long-term energy transition.  During this transition, we believe there is significant value to be realized from responsible energy investment, and that Vermilion is optimally positioned to prosper in this industry and market environment.  Our belief in Vermilion is founded in the economic sustainability of our business model and our leadership in environmental sustainability in the upstream oil and gas sector.

Throughout our 25-year history, we have repeatedly made the necessary adjustments to adapt to the changing landscape around us.  Our business model has focused on sustainable growth and income, which we have successfully delivered to our shareholders over the years.  Vermilion has paid over $39 per share in distributions and dividends since 2003 and generated compounded growth in production per share of over 8% annually since 2012.  Our investment cycle time is short with minimal fixed commitments.  Consequently, we have flexibility to adjust our investment and growth levels to provide the combination of return of capital and growth which we think will maximize shareholder value in a changing capital market environment.  Based on the current market and commodity environment, we believe a strategy that is even more focused on free cash flow generation will create the most value for our shareholders.  As such, for 2020, while maintaining our dividend at current levels, we have elected to reduce our production growth rate and to introduce additional flexibility in how we return capital to investors.

This lower growth strategy was embedded in the preparation of our 2020 budget as well as our capital plans for the remainder of 2019.  For 2019, we have reduced capital investment by $10 million, and now expect to invest $520 million.  As a result of this reduced level of investment and after accounting for higher-than-expected downtime and weather delays, we have correspondingly reduced our 2019 annual production guidance to 100,000 to 101,000 boe/d.  We expect to deliver annual production at the mid-point of this revised guidance range,  reflecting strong year-over-year production per share growth of 5%.  Our Board of Directors has approved a 2020 capital budget of $450 million with associated production guidance of 100,000 to 103,000 boe/d.  This budget is designed to deliver modest production growth of about 1%.  The 2020 budget includes approximately $20 million of strategic capital associated with early-stage exploration and development activities.  These activities will lay the groundwork for future development and production growth from a highly economic asset base.

During the third quarter we received approval from the TSX for a normal course issuer bid ("NCIB"), which will allow us to buy back up to 7.75 million shares.  With this approval, we intend to use the NCIB in combination with debt reduction when we have excess free cash flow available (beyond dividends) to enhance per share growth.  We will also be phasing out our DRIP over the course of the next year, prorating the available DRIP shares by 25% each quarter starting in Q1 2020 until the DRIP is completely eliminated in Q4 2020.  The DRIP has been a shareholder service that we have provided since our first income distribution in 2003, with discounted share purchases offered until 2018.  We recognize that the elimination of the DRIP may be a disappointment to some shareholders.  Nonetheless, we feel that in an environment of lower trading commissions, the establishment of our NCIB, and lower energy issuer valuation multiples, the elimination of the DRIP is in the best interests of our broad shareholder group.

We remain committed to maximizing value for our shareholders over the long-term through a combination of a sustainable dividend, low financial leverage, share buybacks, and production growth as appropriate.  In addition, we will remain disciplined in our acquisition strategy as we continue to evaluate strategic opportunities that fit within our business model and add value for existing shareholders.  Our highest financial priority is our balance sheet, and under no circumstance will we do anything that jeopardizes Vermilion's long-term financial stability.  We have a robust balance sheet with termed-out borrowing, strong liquidity, and a very low cost of debt.  Coupled with low operating leverage due to high margins, a diversified product mix, and a strong hedge position, our balance sheet provides us with the flexibility to weather volatility in commodity prices.

Q3 2019 Operations Review

Our Q3 2019 operational results were impacted by several planned turnarounds, a high level of unplanned downtime, weather related delays and a moderate carry-over impact from the refinery outage in France.  As a result, our Q3 2019 production decreased 6% from the prior quarter to 97,239 boe/d, with variances discussed by business unit below.  We generated FFO of $216 million in the third quarter, down by 3% from the prior quarter, with positive contributions from hedging gains, lower G&A expense, and lower taxes partially offsetting lower production and commodity prices.

Europe

In France, Q3 2019 production averaged 10,347 boe/d, an increase of 6% from the prior quarter.  Production volumes in the Paris Basin returned to near full capacity in mid-August following the restart of the Grandpuits refinery which had been offline due to a failure on its main feedstock pipeline.  Most of our wells in the Paris Basin have returned to pre-shutdown production levels, although some wells continue to clean up and workover activity is continuing to restore full productivity.  The net impact from the refinery outage reduced our Q3 2019 production volumes by approximately 400 boe/d.  In the Aquitaine Basin, production was consistent with the prior quarter as we successfully completed our 2019 workover campaign, which continues to yield results above our expectations.

In the Netherlands, Q3 2019 production averaged 7,429 boe/d, a decrease of 17% from the prior quarter.  The decrease was primarily due to a planned turnaround and unexpected downtime to repair a gas compressor, which extended the length of the turnaround.  The combined impact was a reduction in Netherlands production of approximately 1,200 boe/d in Q3 2019.  Our facilities have returned to service and production has been restored.  We are currently in the process of drilling the Weststellingwerf well (0.5 net), representing our first drilling activity in the Netherlands since 2017, and we expect drilling to be completed before the end of the year.

In Ireland, production averaged 43 mmcf/d (7,202 boe/d) in Q3 2019, a decrease of 12% from the prior quarter.  The decrease was primarily due to planned and unplanned downtime at the Corrib natural gas processing facility and natural decline.  Our planned turnaround was successfully completed as scheduled in mid-September.  Later in the month, we identified the need for repairs in one of the plant auxiliary systems which necessitated shutting the plant down for approximately 10 days spanning the end of Q3 and early Q4 2019.  The combined impact of the planned and unplanned downtime was approximately 800 boe/d in Q3.

In Germany, production in Q3 2019 averaged 3,269 boe/d, a decrease of 6% from the prior quarter.  The decrease was primarily due to unplanned downtime on several operated and non-operated assets, partially offset by contributions from successful workovers performed earlier this year.  Following the successful drilling of the Burgmoor Z5 (46% working interest) well, completed early in the third quarter of 2019, we continue to evaluate tie-in alternatives and expect to bring the well on production in late 2020.

In Central and Eastern Europe ("CEE"), we drilled one (1.0 net) natural gas exploration well in Croatia during Q3 2019, which resulted in a second consecutive gas discovery, testing at a rate of 17.2 mmcf/d(2).  During the third quarter, we were also provisionally awarded the SA-07 license in Croatia, which is contiguous with our existing land position and will add approximately 500,000 net acres to our portfolio in the country.  Vermilion continues to be the largest onshore landholder in Croatia, with total licensed acreage of approximately 2.4 million net acres, including the new SA-07 block.  In Hungary, we began tie-in activities for the Mh-21 (0.3 net) and Battonya E-09 (1.0 net) wells, drilled in the second and third quarters of 2019, respectively, and expect to bring them on production during the fourth quarter of 2019.

North America

In Canada, production averaged 58,504 boe/d in Q3 2019, a decrease of 5% from the prior quarter.  The decrease was primarily due to planned turnarounds (700 boe/d impact) and project delays caused by abnormally wet weather (2,100 boe/d impact).  We drilled or participated in 40 (38.3 net) wells in the third quarter of 2019, all of which were drilled in Saskatchewan, as no drilling in Alberta was possible due to wet conditions throughout the summer.  Well activity in Alberta, including tie-in and completions, was delayed until late September due to extremely wet ground, three months later than when we typically resume post-break-up activity.  We brought 41 (36.2 net) wells on production in Saskatchewan and three (2.5 net) wells on production in Alberta during the quarter.  We have continued to realize capital and operating efficiencies in our southeast Saskatchewan assets, achieving a 10% improvement in drilling, completion, equipping and tie-in ("DCET") costs on our Q3 2019 open-hole drilling program compared to our Q1 2019 program.

In the United States, Q3 2019 production averaged 4,925 boe/d, representing an increase of 12% from the prior quarter.  The increase was primarily driven by production contributions from our 2019 Hilight drilling campaign, as we successfully completed and brought on production four (4.0 net) wells during the third quarter.  The increased production was partially offset by planned and unplanned third-party gas plant maintenance, which reduced production by approximately 200 boe/d.  The first two wells drilled in the quarter were brought on production in late August and achieved an average peak IP30 rate of approximately 600 boe/d per well (86% oil and NGLs).  The other two wells were brought on production at the end of September and are currently producing at an average rate of approximately 500 boe/d per well (92% oil and NGLs).  We continue to progress along the learning curve in reducing costs since our Hilight acquisition one year ago, with a 20% DCET cost reduction in our H2 2019 program to-date compared to our H1 2019 program.  As a result of these cost savings, we have added two (1.5 net) wells to our 2019 program and plan to drill these wells in Q4 2019.

Australia

In Australia, production averaged 5,564 bbl/d in Q3 2019, a decrease of 17% from the previous quarter, primarily due to well management and unplanned vessel maintenance on the Wandoo platform.  We plan to conduct facility upgrades in Q4 2019 to increase fluid handling capacity, which will necessitate a shutdown of the Wandoo platform for an estimated eight days in the fourth quarter of 2019.

2020 Budget

Our Board of Directors has approved an exploration and development capital expenditure budget of $450 million, with associated production guidance of 100,000 to 103,000 boe/d.  As previously communicated, we are placing less emphasis on production growth as we navigate the current commodity price and capital markets environment.

We plan to drill 13 (8.7 net) wells in Europe.  In addition, we plan to continue significant workover programs in France, Netherlands and Germany, and facility optimization in Ireland.  The capital budget includes approximately $20 million of strategic, non-production-adding capital invested to facilitate our long-term future growth plans in Europe.

In North America, our activity will focus on our three core areas of southeast Saskatchewan (light oil), west-central Alberta (condensate-rich natural gas), and the Powder River Basin in Wyoming (light oil).  We have made significant progress on improving the capital and operating efficiencies on the North American assets we acquired in 2018, and we plan to continue that trend in 2020.

Assuming WTI oil prices remain at approximately US$55/bbl in 2020, and holding all other commodities at the October 11, 2019 commodity strip, we would more than cover our dividend and capital investment.  Excess cash generated beyond our capital program and dividend commitment will be allocated to a combination of debt reduction and share buybacks.  Our top financial priorities in 2020 will be balance sheet and dividend protection, and we maintain the capital investment flexibility to reduce capital outlays if required by lower commodity prices.

Europe

In France, our 2020 E&D capital budget of $57 million represents a 23% reduction from our 2019 spending.  While we do not intend to invest in any new wells in 2020, we plan to continue with our workover and asset optimization programs in both the Paris and Aquitaine Basins.  These workover programs are expected to maintain production at roughly the same level in 2020 as we have averaged in 2019.

Our 2020 E&D budget in the Netherlands of $18 million represents a 22% decrease from 2019.  While significant progress has been made on our permitting efforts, we will plan for modest growth in the Netherlands in 2020 as we reschedule our slate of capital projects in the context of a lower corporate growth rate target.  We plan to drill or participate in three (0.6 net) wells.  Assuming success on the Weststellingwerf well (0.5 net) currently being drilled, we plan to bring this well on production during the first half of 2020.  We will continue to advance our well permitting throughout the year in order to compile a backlog of projects for implementation beginning in 2021.

In Ireland, we plan to invest approximately $3 million of E&D capital in 2020 as we continue to focus on facility maintenance and compression optimization.

In Germany, our 2020 E&D capital budget of $18 million represents a decrease of 18% year-over-year.  In addition to our planned workover and facility program, we plan to drill sidetracks in three (3.0 net) of our operated oil wells and begin drilling activities on one (0.6 net) exploratory gas prospect.

In Central and Eastern Europe, our 2020 E&D budget will be approximately the same as in 2019, building on the success we had in 2019 and laying the groundwork for future growth.  We plan to invest $20 million in E&D capital expenditures in 2020.  While the majority of this capital program will be focused on following-up our successful 2019 drilling program, a portion of the budget will be directed to strategic infrastructure investments in Croatia and Slovakia, notably the commencement of construction of natural gas compression facilities in each country.  In 2020, we plan to drill six (4.5 net) wells in CEE comprised of two (2.0 net) wells in Croatia, one (1.0 net) well in Hungary and three (1.5 net) wells in Slovakia.

North America

In Canada, we plan to invest $250 million of E&D capital in 2020, a decrease of 14% from our 2019 capital program.  We plan to drill 107 (95.5 net) wells in Canada in 2020, comprised of 87 (76.3 net) light oil wells in southeast Saskatchewan and 20 (19.2 net) wells in Alberta.  In addition to the drilling program, we will also continue to focus on our waterflood program in southeast Saskatchewan, as well as production and facility optimization opportunities, as we have in previous years.

In the United States, our 2020 E&D capital budget of $59 million represents a 4% increase from our 2019 capital program.  We plan to drill 10 (9.6 net) wells on our Hilight asset in Wyoming.  This expanded drilling program will allow us to capitalize on the efficiencies we have achieved since the Hilight acquisition and to continue to increase production in the Powder River Basin.

Australia

In Australia, our 2020 E&D budget of $25 million will focus primarily on workovers and facility modifications to increase artificial lift capacity and facility throughput.

E&D Capital Investment by Country





Country

2020 Budget*
($MM)

2019 Budget
($MM)

2020 vs. 2019
% Change

2020
Gross Wells

2020
Net Wells

Canada

250

292

(14)

%

107

95.5

France

57

74

(23)

%

Netherlands

18

23

(22)

%

3

0.6

Germany

18

22

(18)

%

4

3.6

Ireland

3

1

200

%

Australia

25

31

(19)

%

USA

59

57

4

%

10

9.6

Central and Eastern Europe

20

20

%

6

4.5

Total E&D Capital Expenditures

450

520

(13)

%

130

113.8

 

E&D Capital Investment by Category





Category

2020 Budget*
($MM)

2019 Budget
($MM)

2020 vs. 2019
% Change

Drilling, completion, new well equipment and tie-in, workovers and recompletions

350

380

(8)

%

Production equipment and facilities

70

100

(30)

%

Seismic, land and other

30

40

(25)

%

Total E&D Capital Expenditures

450

520

(13)

%

 

*2020 Budget reflects foreign exchange assumptions of CAD/USD 1.32, CAD/EUR 1.48, and CAD/AUD 0.90.

Dividend Reinvestment Plan

We have elected to phase out the Dividend Reinvestment Plan ("DRIP"), prorating the available DRIP shares by 25% each quarter starting in Q1 2020.  It is our intention to increase this proration each quarter throughout next year, such that the DRIP will be eliminated by the fourth quarter of 2020.

Commodity Hedging

Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows, providing additional certainty with regard to the execution of our dividend and capital programs.  In aggregate, as of October 29, 2019, we currently have 51% of our expected net-of-royalty production hedged for Q4 2019.  More than half of our Q4 2019 corporate hedge position consists of two-way collars and three-way structures, which allow participation in price increases up to contract ceilings.  For 2020, approximately one-third of our production is hedged, with 54% of our hedge position in participating structures.

With respect to individual products within our product mix, we have currently hedged 74% of anticipated European natural gas volumes for Q4 2019.  We have also hedged 75% of our anticipated full-year 2020 European natural gas volumes at prices which are expected to provide for strong project economics and free cash flows.  At present, 47% of our expected Q4 oil production is hedged.  For Q4 2019, 51% of our North American natural gas production is priced away from AECO, due to diversification hedges to financially sell at the SoCal Border and at Henry Hub for a portion of our Alberta natural gas production, and because 16% of our North American gas production is located in Saskatchewan and Wyoming.

Sustainability

Vermilion received top quartile rankings for 2019 for our industry sector in both the Sustainalytics ESG Rating and SAM (formerly known as  RobecoSAM) annual Corporate Sustainability Assessment ("CSA").  These agencies analyze sustainability performance across economic, environmental, governance and social criteria, and the CSA is also the basis of the Dow Jones Sustainability Indices.  We believe the integration of sustainability principles into our business is the right thing to do, increases shareholder return, and reduces long-term risks to our business model.  These ratings demonstrate our commitment to maintaining leadership in sustainability and ESG performance.  Our 2019 Sustainability Report is available on our corporate website at: http://sustainability.vermilionenergy.com.

(signed "Anthony Marino")

Anthony Marino
President & Chief Executive Officer
October 30, 2019

(1)

Non-GAAP Financial Measure.  Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis.



(2)

Berak-01 well (100% working interest) tested at a rate of 17.2 mmcf/d during a four-hour flow period with a stabilized flowing wellhead pressure of 908 psi on a 0.875 inch diameter choke.  A final shut in wellhead pressure of 1,186 psi was recorded following the flow test.  The flow test continued an additional 12 hours at reduced choke sizes to minimize flaring.  No formation water was produced during the test.  The well logged 21 feet of net gas pay with an average porosity of 32% from the Upper Miocene Pannonian sandstone occurring within a gross measured depth interval of 3,006-3,033 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

 

Conference Call and Webcast Details

Vermilion will discuss these results in a conference call on Thursday, October 31, 2019 at 9:00 AM MST (11:00 AM EST).  To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area).  A recording of the conference call will be available for replay by calling 1-855-859-2056 and using the conference ID 2090807 from October 31, 2019 at 12:00 MST to November 14, 2019 at 21:59 MST.

You may also access the webcast at https://event.on24.com/wcc/r/2114194/1C4F8D98D22708487A065827392F4760.  The webcast link can be found on Vermilion's website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm under upcoming events.

About Vermilion

Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia.  Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors.  Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia.  Vermilion holds a 20% working interest in the Corrib gas field in Ireland.  Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 14.5%.

Vermilion's priorities are health and safety, the environment, and profitability, in that order.  Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings.  We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany.  In addition, Vermilion emphasizes strategic community investment in each of our operating areas.

Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance.  Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.

Disclaimer

Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation.  Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project", or similar words suggesting future outcomes or statements regarding an outlook.  Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.

Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect.  In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.

Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct.  Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes.  Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information.  These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.

The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.

This document contains metrics commonly used in the oil and gas industry.  These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons.  Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.  Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation.  A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.

SOURCE Vermilion Energy Inc.

Vermilion Energy Inc.
3500, 520 3rd Avenue SW
Calgary, Alberta T2P 0R3
Phone: 1-403-269-4884
Fax: 1-403-476-8100
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