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Vermilion Energy Inc. Announces Results for the Three and Six Months Ended June 30, 2019


 

Schachter Energy Conference 2019
Schachter Energy Conference 2019

 

CALGARY, July 29, 2019 /PRNewswire/ – 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 six months ended June 30, 2019.

The unaudited financial statements and management discussion and analysis for the three and six months ended June 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

  • Q2 2019 production averaged 103,003 boe/d, down slightly from the prior quarter, as increases in the US and Australia were more than offset by lower production in France due to a refinery outage in the ParisBasin.
  • Fund flows from operations (“FFO”) for Q2 2019 was $223 million ($1.44/basic share(1)), a decrease of 12% from the previous quarter due to the refinery outage, timing of crude lifting in Australia, and lower natural gas prices. Despite lower year-over-year commodity prices, FFO for Q2 2019 was up 14% from the same quarter last year due to increased production.
  • In Germany, we finished drilling and completing our first exploratory well, which was tested subsequent to the end of the quarter. The well (46% working interest) encountered 125 feet of net pay and tested at a rate of 8.8mmcf/d(2), with the test rate limited by weather conditions.
  • In CEE, we drilled three (2.3 net) exploration wells in Hungary and one (1.0 net) exploration well in Croatiaduring Q2 2019. Subsequent to the end of the quarter, we drilled and completed a fourth (1.0 net) exploration well in Hungary. Three of the Hungarian wells and the Croatian well resulted in gas discoveries. The Hungarian wells tested at rates of 1.7 mmcfe/d(3) (81% gas), 2.0 mmcf/d(4) and 3.4 mmcf/d(5)respectively. The Croatian well tested at a rate of 15.0 mmcf/d(6).
  • Subsequent to the end of the second quarter, we were awarded two exploration licenses in Ukraine, subject to finalization of production sharing agreements, in partnership with Ukrgazvydobuvannya (“UGV”, a Ukrainian state owned gas producer). The licenses cover approximately 585,000 gross acres in the Dnieper-Donets Basin, one of the most prolific natural gas regions in Europe.
  • In the United States, Q2 2019 production averaged 4,414 boe/d, an increase of 21% from the prior quarter, primarily driven by contributions from our first half 2019 Hilight drilling program. Production performance from the drilling program is above our type curves.
  • In Australia, production averaged 6,689 bbl/d in Q2 2019, an increase of 14% from the previous quarter, primarily due to contributions from the two (2.0 net) well drilling program completed at the end of January 2019.
  • In France, Q2 2019 production averaged 9,800 boe/d, a 15% decrease from the prior quarter. The decrease resulted from curtailment of our production in the Paris Basin as a result of an unplanned outage at the Grandpuits refinery, where all of our Paris Basin production is processed. The refinery was returned to service in late July and has now resumed accepting our oil deliveries. During the refinery outage, we utilized trucks and barges to ship a portion of our oil production to alternate delivery points in France and Germany.
  • On June 12, 2019, Vermilion entered into a series of cross currency interest rate swaps with a syndicate of banks, financially swapping the remaining term of our 5.625% US$300 million senior unsecured notes due March 15, 2025 into a €265 million obligation bearing interest at 3.275%. At current foreign exchange rates, this swap is expected to reduce our annual cash interest costs by approximately $9 million.
  • Our Board of Directors has authorized an application to the TSX to implement a normal course issuer bid (“NCIB”) for a maximum amount of 5% of the issued and outstanding shares of Vermilion, which we plan to use as an additional means of returning capital to shareholders under appropriate market conditions. The NCIB is intended to augment our dividend, with excess free cash flow allocated to a combination of debt reduction and share buybacks.
  • Vermilion was recently rated “AA” in MSCI’s annual ESG rankings for 2019, placing us in the top 19% of oil and gas companies worldwide. This rating is an improvement from “A” in the previous two years, and is driven by our determination to be the leader in ESG in the energy industry.

(1)

Non-GAAP Financial Measure.  Please see the “Non-GAAP Financial Measures” section of the accompanying Management’s Discussion and Analysis.

(2)

Burgmoor Z5 well (46% working interest) tested at a final flow rate of 8.8 mmcf/d at a flowing wellhead pressure of 431 psi, with the rate limited by weather conditions during a 30 hour clean-up flow.  The well produced at a final rate of 480 bbls/d of drilling and completion load fluid during clean-up operations, but is not expected to produce meaningful amounts of formation water under long-term producing conditions.  The flowing wellhead pressure continued to increase during the clean-up period and was 431 psi immediately prior to being shut-in.  The well encountered 125 feet of net pay in the Permian Zechstein Carbonate from 11,014-11,276 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

(3)

Hajdubagos-01 well (100% working interest) tested at a flow rate of 1.4 mmcf/d of natural gas with 55 barrels per day of 60° API condensate with no formation water during a 12 hour flow test on a 0.374 inch choke with a stabilized flowing wellhead pressure of 590 psi.  The well encountered 15 feet of net pay in an Upper Miocene Pannonian sandstone at depths from 6,517-6,550 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

(4)

Mh-21 well (30% working interest) tested at a flow rate of 2.0 mmcf/d with no formation water during a six hour flow test with a stabilized flowing wellhead pressure of 543 psi on a 0.43 inch choke.  The well encountered 26 feet of net pay in an Upper Miocene Pannonian sandstone at depths from  2,901-2,930 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

(5)

Battonya E-09 well (100% working interest) tested at a flow rate of 3.4 mmcf/d with no formation water during an eight hour flow test with a stabilized flowing wellhead pressure of 739 psi on a 0.47 inch choke.  The well encountered 17 feet of net pay in an Upper Miocene Pannonian sandstone from 2,448-2,476 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

(6)

Ceric-01 well (100% working interest) tested at a final flow rate of 15.0 mmcf/d at a stabilized flowing wellhead pressure of 851 psi on a 0.86 inch diameter choke during a one hour flow period following perforating.  An additional 18 hour flow test was later conducted at reduced rates to limit flaring.  During this test, the well flowed at a rate of 6.2 mmcf/d at a stabilized flowing pressure of 1,376 psi on a 0.37 inch choke.  No formation water was produced during the tests.  The well encountered 32 feet of net pay in two Upper Miocene Pannonian sandstones from 3,346-3,353 and 3,828-3,861 feet.  Only the lower zone was tested.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

 

($M except as indicated)

Q2 2019

Q1 2019

Q2 2018

YTD 2019

YTD 2018

Financial

Petroleum and natural gas sales

428,043

481,083

394,498

909,126

712,767

Fund flows from operations

222,738

253,572

195,190

476,310

355,605

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

1.44

1.66

1.45

3.10

2.77

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

1.42

1.64

1.43

3.07

2.73

Net earnings (loss)

2,004

39,547

(61,364)

41,551

(36,624)

    Net earnings (loss) ($/basic share)

0.01

0.26

(0.46)

0.27

(0.28)

Capital expenditures

92,607

202,053

79,984

294,660

208,449

Acquisitions

8,623

16,027

1,465,485

24,650

1,558,563

Asset retirement obligations settled

4,907

3,597

2,626

8,504

6,217

Cash dividends ($/share)

0.690

0.690

0.690

1.380

1.335

Dividends declared

106,884

105,549

98,604

212,433

177,609

    % of fund flows from operations

48%

42%

51%

45%

50%

Net dividends (1)

98,111

98,445

78,629

196,556

137,993

    % of fund flows from operations

44%

39%

40%

41%

39%

Payout (1)

195,625

304,095

161,239

499,720

352,659

    % of fund flows from operations

88%

120%

83%

105%

99%

Net debt

1,950,509

2,000,144

1,796,807

1,950,509

1,796,807

Ratio of net debt to annualized fund flows from operations

2.19

1.97

2.30

2.05

2.53

Operational

Production

    Crude oil and condensate (bbls/d)

48,964

49,181

34,574

49,072

30,812

    NGLs (bbls/d)

8,107

7,897

5,651

8,002

5,390

    Natural gas (mmcf/d)

275.60

277.96

242.40

276.77

235.34

    Total (boe/d)

103,003

103,404

80,625

103,203

75,425

Average realized prices

    Crude oil and condensate ($/bbl)

79.46

73.45

87.50

76.36

84.32

    NGLs ($/bbl)

11.25

22.49

26.06

16.76

25.73

    Natural gas ($/mcf)

3.09

5.10

4.77

4.09

5.27

Production mix (% of production)

    % priced with reference to WTI

38%

37%

29%

37%

25%

    % priced with reference to Dated Brent

18%

18%

21%

19%

23%

    % priced with reference to AECO

26%

26%

26%

26%

26%

    % priced with reference to TTF and NBP

18%

19%

24%

18%

26%

Netbacks ($/boe)

    Operating netback (1)

29.62

31.50

33.03

30.57

32.22

    Fund flows from operations netback

24.15

26.76

26.58

25.46

26.20

    Operating expenses

11.04

12.92

10.75

11.99

10.82

    General and administration expenses

1.70

1.38

1.93

1.54

1.91

Average reference prices

    WTI (US $/bbl)

59.81

54.90

67.88

57.36

65.37

    Edmonton Sweet index (US $/bbl)

55.19

50.05

62.43

52.62

59.70

    Saskatchewan LSB index (US $/bbl)

55.54

50.84

61.84

53.19

59.23

    Dated Brent (US $/bbl)

68.82

63.20

74.35

66.01

70.55

    AECO ($/mcf)

1.03

2.62

1.18

1.83

1.63

    NBP ($/mcf)

5.44

8.33

9.42

6.89

9.69

    TTF ($/mcf)

5.75

8.14

9.50

6.94

9.54

Average foreign currency exchange rates

    CDN $/US $

1.34

1.33

1.29

1.33

1.28

    CDN $/Euro

1.50

1.51

1.54

1.51

1.55

Share information (‘000s)

Shares outstanding – basic

155,032

153,213

152,363

155,032

152,363

Shares outstanding – diluted (1)

158,633

156,650

155,355

158,633

155,355

Weighted average shares outstanding – basic

154,795

152,904

134,603

153,855

128,531

Weighted average shares outstanding – diluted (1)

156,844

154,550

136,559

155,335

130,224

(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

During the second quarter, we conducted our most active exploration drilling program in Europe in the history of the company.  Over the past four months, we have drilled one exploration well in Germany and five exploration wells in our Central and Eastern European (“CEE”) business unit, with successes on all but one well in Hungary.  This drilling campaign was preceded by several years of careful implementation of our new country entry strategy.  We entered Germany in 2014 and initially focused on expanding our land position through various acquisitions, farm-ins and government concessions, and we now have approximately 1.2 million net acres of land, comprising about one-quarter of the prolific North German Basin.  The first few years were focused on building our team and executing on low risk development opportunities on the existing producing assets while evaluating future exploration and development prospects.  Following the successful completion of our first operated drilling in Germany this summer, we now plan to drill at least one exploration well in Germany each year over the next several years, targeting other sizable gas prospects in the basin.

We followed a similar approach when we entered Central and Eastern Europe later in 2014.  We acquired land in the Pannonian Basin in HungaryCroatia and Slovakia through various government concessions and deals with industry partners. Our initial focus was on building our knowledge of the basin and operating environment, while acquiring and evaluating seismic to identify future drilling prospects. This summer’s drilling program has yielded four conventional discoveries in Hungary and Croatia in five exploratory attempts.  We look forward to executing the remainder of our Croatian program and to initiating our Slovakian program later this year.

Subsequent to the second quarter, we further expanded our CEE presence as we were awarded two exploration licenses in Ukraine in partnership with Ukrgazvydobuvannya (“UGV”, a Ukrainian state owned gas producer) in the prolific Dnieper-Donets Basin.  These two licenses are in close proximity to several multi-TCF gas fields with most of the basin (and awarded license areas) still not covered by 3D seismic.  Entering Ukraine aligns with our strategy to capitalize on opportunities in under-exploited basins by using modern technologies to improve success rates and recovery.

In addition to our Germany and CEE exploration drilling programs, we are also currently preparing to drill the first well (0.5 net) of our two (1.0 net) well 2019 program in the Netherlands after having received permits for these wells in the second quarter.  Netherlands continues to be a strong free cash flow generating business and we look forward to resuming drilling there after a two-year hiatus.

Our second quarter results were negatively impacted by a third-party refinery outage in France which reduced production and forced us to find alternate transportation methods and delivery points for our oil in the ParisBasin, which is the larger of our two producing regions in the country.  Our French team did an exceptional job of contracting for alternate delivery points for most of our production, and conducting the required long-haul trucking and barging in a safe manner.  Despite the refinery outage, which impacted quarterly production volumes by approximately 1,300 boe/d and FFO by approximately $11 million, we recorded corporate production of approximately 103,000 boe/d, little changed from the previous quarter.

We recorded FFO of $223 million in Q2 2019, down 12% from the prior quarter.  In addition to the Francerefinery impact, the primary drivers for this lower FFO were the timing of crude lifting in Australia, which resulted in an inventory build and lower sales volumes ($8 million impact), and weaker natural gas prices in Europe and North America ($33 million impact).

We were able to mitigate a portion of this pricing variance through our hedging program, particularly in European gas, realizing a $14 million pre-tax gain during the quarter.  European gas prices weakened this summer due to increased LNG deliveries.  However, we have locked in pricing on approximately 70% of our summer European gas at significantly higher prices than the spot price.  The forward price for European gas remains in strong contango compared to the front month price, with the calendar 2020 strip for NBP at approximately $8.50/mmbtu, and calendar year strips for the next three years are currently trading within approximately 1% of where they were one year ago.  While our fundamental view on European gas is that the forward market realistically reflects supply and demand drivers, we are willing to lock in this curve and attendant strong levels of free cash flow and expected project economics.  Accordingly, we have already hedged 65% of our expected 2020 European gas production, with hedges continuing at lower percentages on into 2022.

Since 2003, Vermilion has had a track record of returning capital to shareholders through our monthly dividend (previously a cash distribution during the trust era).  This distribution and dividend stream has been increased four times and has never been reduced.  We also recognize that other forms of returning capital to shareholders, such as share buybacks, may be appropriate to complement our dividend in certain market conditions.  With this in mind, our Board of Directors has authorized an application to the TSX to implement a normal course issuer bid (“NCIB”) for a maximum amount of 5% of the issued and outstanding shares of Vermilion.  We intend to use the NCIB to return capital to our shareholders, augmenting our current return of cash through dividends.  We will also continue to allocate a portion of excess free cash flow to debt reduction.

Q2 2019 Operations Review

Europe

In France, Q2 2019 production averaged 9,800 boe/d, a decrease of 15% from the prior quarter.  Our production in the Paris Basin was temporarily curtailed as a result of a third party refinery outage due to a failure on the refinery’s main feedstock line. The Grandpuits refinery, where all of our Paris Basin production is processed, returned to service in late July, and has resumed processing Vermilion deliveries. During the refinery outage, we made arrangements to ship most of our oil to alternate delivery points in France and Germany utilizing trucks and barges. The net impact from the refinery outage reduced our Q2 2019 production volumes by approximately 1,300 boe/d and after-tax FFO by approximately $11 million ($0.07/share) from reduced sales and higher transportation expense.  In addition, approximately $2 million in capital investment was required to put truck and barge loading equipment in place.

In the Netherlands, Q2 2019 production averaged 8,917 boe/d, an increase of 3% from the prior quarter.  The increase is primarily due to the successful completion of our first half 2019 workover and facility maintenance program, which was partially offset by minor downtime.  During the second quarter we received the draft drilling permit for the Waalwijk South well (0.5 net), the second well in our planned 2019 drilling program.  We recently began site construction for the first well of our 2019 program, the Weststellingwerf well (0.5 net), which is expected to commence drilling in August 2019.  Drilling of the Waalwijk South well is expected to begin in Q4 2019.

In Ireland, production averaged 49 mmcf/d (8,201 boe/d) in Q2 2019, a decrease of 4.8% from the prior quarter.  The decrease was due to natural decline and minor unplanned downtime at the Corrib natural gas processing facility.  Since we took over as operator of the Corrib Project late in 2018, operating costs have decreased 14% over the comparative six-month period.  At present, our efforts are focused on evaluating future facility and drilling projects, and optimizing our maintenance activities, including a scheduled plant turnaround in Q3 2019.

In Germany, production in Q2 2019 averaged 3,474 boe/d, a decrease of 8% from the prior quarter.  The decrease is primarily due to unplanned downtime on several operated and non-operated assets, which was partially offset by a full quarter contribution from various well workovers performed on our operated oil assets earlier this year.  During the quarter, we completed drilling our first exploratory well in Germany, the Burgmoor Z5 well (46% working interest).  The well reached a measured depth of 11,480 feet and encountered 125 feet of net pay in the Zechstein carbonate.  The well was tested at the end of July at a final flow rate of 8.8 mmcf/d(2) limited by weather conditions.  The Burgmoor Z5 well has been turned over to ExxonMobil as operator during the testing and production phases.  We also completed and brought on production a non-operated coil tubing sidetrack (0.25 net) during the quarter.

In Central and Eastern Europe, we drilled four (3.3 net) exploration wells during Q2 2019, and one (1.0 net) subsequent to the end of the quarter.  Four of these wells resulted in new gas discoveries.  In Hungary, we drilled four (3.3 net) exploration wells, the first (1.0 net) of which was dry.  The second well (1.0 net) of our 2019 Hungary drilling program encountered 15 feet of net gas pay and tested at a rate of 1.4 mmcf/d and 55 bbls/d(3) of condensate.  The third well (0.3 net) encountered 26 feet of net gas pay, and tested at a rate of 2.0 mmcf/d(4) in July.  The fourth Hungarian well (1.0 net) was drilled and tested in July, encountering 17 feet of net gas pay and testing at 3.4 mmcf/d(5).  In Croatia, we drilled our first natural gas exploration well (1.0 net) in the country which encountered 32 feet of net gas pay in two zones.  Subsequent to the end of the quarter, it tested 15.0 mmcf/d(6) from the lower zone.

Subsequent to the end of the second quarter, we were awarded two exploration licenses in Ukraine, subject to a final production sharing agreement, in a 50/50 partnership with Ukrgazvydobuvannya (“UGV”, a Ukrainian state owned gas producer).  The licenses cover approximately 585,000 gross acres situated in one of Europe’s most prolific natural gas regions (Dnieper-Donets Basin).  The new licenses are in close proximity to several multi-TCF gas fields with most of the basin (and awarded license areas) still uncovered by 3D seismic.  The terms of the licenses include a modest capital commitment, back-loaded over a five-year time frame.

North America

In Canada, production averaged 61,507 boe/d in Q2 2019, up slightly from the prior quarter.  The increase was primarily due to the contribution from our first quarter drilling program in Saskatchewan and Alberta, partially offset by unplanned facility downtime and less drilling activity in the second quarter due to spring breakup.  We drilled or participated in 28 (22.9 net) wells in the second quarter of 2019, including 27 (22.4 net) wells in Saskatchewan and one (0.5 net) Mannville well in Alberta.  We brought six (6.0 net) wells on production in Saskatchewan and one (1.0 net) well in Alberta during the quarter.  During the second half of the year, we plan to drill 73 (62.7 net) wells in Saskatchewan and six (4.2 net) wells in Alberta, in addition to completing several plant turnarounds in Alberta in Q3 2019.  We are currently operating four drilling rigs in Saskatchewan, but have been delayed in resuming Alberta activity due to wet weather conditions.

In the United States, Q2 2019 production averaged 4,414 boe/d, representing an increase of 21% from the prior quarter.  The increase was primarily driven by production contributions from our first half 2019 Hilight drilling campaign, in which four (4.0 net) wells were completed and brought on production during the quarter.  The first two wells were equipped with rod pumps and brought on production in mid-April.  These wells have performed ahead of our expectations, producing in excess of our rod-pump type curve through the end of the quarter, and achieving an average peak IP30 rate of approximately 325 boe/d to date, with production still on a modest incline in one of the wells.  The two subsequent wells were equipped with electric submersible pumps (“ESP”) and were brought on production in mid-May.  These two wells have also performed ahead of our expectations by approximately 150 bbls/d on average, while achieving an average peak IP30 rate of approximately 635 boe/d per well.  We recently mobilized a rig that we had been using on our Canadian operations to Wyoming for our remaining (4.0 net) Hilight wells planned for this year.  The fifth well of the program was spud toward the end of Q2 2019 and was drilled in less than 12 days, representing a 28% improvement over the fastest H1 2019 well.  Since taking over operatorship last year, we have achieved a 15% reduction in DCET costs, and expect another 10% improvement in the remaining wells this year.

Australia

In Australia, production averaged 6,689 bbl/d in Q2 2019, an increase of 14% from the previous quarter primarily due to contributions from the two (2.0 net) well drilling program completed at the end of January 2019.  We continue to manage our Australian production to our annual production target of 6,000 bbl/d.

Cross Currency Interest Rate Swaps

On June 12, 2019, Vermilion entered into a series of cross currency interest rate swaps with a syndicate of banks, financially swapping the remaining term of our 5.625% US$300 million senior unsecured notes due March 2025 into a €265 million obligation bearing interest at 3.275%.  At current foreign exchange rates, this swap is expected to reduce our annual cash interest costs by approximately $9 million.

Credit Rating

On July 26, 2019, Fitch Ratings initiated a credit rating for Vermilion.  The corporate first-time Long-Term Issuer Default Rating was initiated at a BB- with a stable outlook and the BB- rating was assigned to the issued and outstanding senior unsecured notes due March 2025.

Normal Course Issuer Bid

Our Board of Directors has authorized an application to the TSX to implement a normal course issuer bid (“NCIB”) for a maximum amount of 5% of the issued and outstanding shares of Vermilion, which we plan to use as an additional means of returning capital to shareholders under appropriate market conditions.  The NCIB is intended to augment our ongoing return of capital via dividends.  We plan to allocate excess free cash flow beyond our dividend stream to both debt reduction and buybacks.

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 July 25, 2019, we currently have 40% of our expected net-of-royalty production hedged for Q3 2019.  More than half of our Q3 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 70% of our hedge position is in participating structures.

We have currently hedged 71% of anticipated European natural gas volumes for Q3 2019.  We have also hedged 69% and 65% of our anticipated full-year 2019 and 2020 European natural gas volumes, respectively, at prices which are expected to provide for strong project economics and free cash flows.  At present, 33% of both our expected Q3 2019 and Q4 2019 oil production is hedged.  For Q3 2019, 45% 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 15% of our North American gas production is located in Saskatchewan and Wyoming.

Sustainability

Vermilion was recently rated “AA” in MSCI’s annual ESG rankings for 2019, placing us in the top 19% of oil and gas companies worldwide.  This rating is an improvement from “A” in the previous two years.  MSCI ESG Research LLC is the world’s largest provider of ESG ratings and research, rating over 13,000 equity and income issuers.  Its research is used globally to help investors understand how ESG factors can impact the long-term risk and return profile of their investments.  Our increased rating is the result of improving company ESG performance and enhanced disclosure on topics relevant to MSCI’s detailed assessment process.

Organizational Update

Mr. Kyle Preston, previously our Director of Investor Relations, has been promoted to the position of Vice President of Investor Relations.  He joined Vermilion in 2016 and has over 20 years of experience in oil and gas finance, including 13 years as an equity research analyst.  Mr. Preston has played a key role in developing and executing our differentiated capital markets strategy.  He holds the Chartered Financial Analyst® and Certified Management Accountant designations and earned a Bachelor of Commerce degree from the University of Manitoba.

(signed “Anthony Marino”)

Anthony Marino
President & Chief Executive Officer
July 25, 2019

(1)

Non-GAAP Financial Measure.  Please see the “Non-GAAP Financial Measures” section of the accompanying Management’s Discussion and Analysis.

(2)

Burgmoor Z5 well (46% working interest) tested at a final flow rate of 8.8 mmcf/d at a flowing wellhead pressure of 431 psi, with the rate limited by weather conditions during a 30 hour clean-up flow.  The well produced at a final rate of 480 bbls/d of drilling and completion load fluid during clean-up operations, but is not expected to produce meaningful amounts of formation water under long-term producing conditions.  The flowing wellhead pressure continued to increase during the clean-up period and was 431 psi immediately prior to being shut-in.  The well encountered 125 feet of net pay in the Permian Zechstein Carbonate from 11,014-11,276 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

(3)

Hajdubagos-01 well (100% working interest) tested at a flow rate of 1.4 mmcf/d of natural gas with 55 barrels per day of 60° API condensate with no formation water during a 12 hour flow test on a 0.374 inch choke with a stabilized flowing wellhead pressure of 590 psi.  The well encountered 15 feet of net pay in an Upper Miocene Pannonian sandstone at depths from 6,517-6,550 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

(4)

Mh-21 well (30% working interest) tested at a flow rate of 2.0 mmcf/d with no formation water during a six hour flow test with a stabilized flowing wellhead pressure of 543 psi on a 0.43 inch choke.  The well encountered 26 feet of net pay in an Upper Miocene Pannonian sandstone at depths from  2,901-2,930 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

(5)

Battonya E-09 well (100% working interest) tested at a flow rate of 3.4 mmcf/d with no formation water during an eight hour flow test with a stabilized flowing wellhead pressure of 739 psi on a 0.47 inch choke.  The well encountered 17 feet of net pay in an Upper Miocene Pannonian sandstone from 2,448-2,476 feet.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

(6)

Ceric-01 well (100% working interest) tested at a final flow rate of 15.0 mmcf/d at a stabilized flowing wellhead pressure of 851 psi on a 0.86 inch diameter choke during a one hour flow period following perforating.  An additional 18 hour flow test was later conducted at reduced rates to limit flaring.  During this test, the well flowed at a rate of 6.2 mmcf/d at a stabilized flowing pressure of 1,376 psi on a 0.37 inch choke.  No formation water was produced during the tests.  The well encountered 32 feet of net pay in two Upper Miocene Pannonian sandstones from 3,346-3,353 and 3,828-3,861 feet.  Only the lower zone was tested.  Test results are not necessarily indicative of long-term performance or ultimate recovery.

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.

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

Conference Call and Webcast Details

Vermilion will discuss these results in a conference call and webcast presentation on Monday, July 29, 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 4454959 from July 29, 2019 at 12:00 MST to August 12, 2019 at 21:59 MST.

You may also access the webcast at https://event.on24.com/wcc/r/2034202/D763FFCE3D2CBFC02220C1DD1B0A63FB.  The webcast link, along with conference call slides, can be found on Vermilion’s website at http://www.vermilionenergy.com/invest-with-us/events–presentations.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 AmericaEurope 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 11.5%.

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 Canadathe 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.



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