Vermilion Energy Inc. Announces Results for the Year Ended December 31, 2019 and 2019 Reserves and Resources Information

CALGARY, March 6, 2020 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and financial results for the year ended December 31, 2019 along with our 2019 reserves and resources information.

The audited financial statements, management discussion and analysis, and annual information form for the year ended December 31, 2019 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.

Vermilion Energy Inc. Announces Results for the Year Ended December 31, 2019 and 2019 Reserves and Resources Information (CNW Group/Vermilion Energy Inc.)

Highlights

• Fund flows from operations ("FFO") in Q4 2019 was $216 million ($1.38/basic share⁽¹⁾), which is in line with the previous quarter despite a significant inventory build in Australia. FFO in 2019 was a record $908 million ($5.87/basic share), representing an increase of 8% from the prior year primarily due to higher production, partially offset by lower commodity prices.
  
  
• Q4 2019 production averaged 97,875 boe/d, representing a 1% increase from the prior quarter, primarily due to higher performance in our US and Netherlands business units. Annual average production for 2019 increased by 15% year-over-year to a record 100,357 boe/d, reflecting a full-year contribution from the assets acquired in 2018 and organic growth from our Netherlands, Australia and US business units. Production per share increased by 5% in 2019.
  
  
• In the United States, Q4 2019 production averaged 5,683 boe/d, an increase of 15% from the prior quarter, primarily driven by contributions from our Q3 2019 drilling program.
  
  
• In the Netherlands, Q4 2019 production averaged 8,088 boe/d, an increase of 9% from the prior quarter, primarily due to the restoration of production following planned and unplanned facility downtime in Q3 2019. During the fourth quarter, we successfully drilled and completed the Weststellingwerf well (0.5 net), representing our first drilling activity in the Netherlands since 2017. We encountered three gas-bearing zones in the Vlieland, Zechstein and Rotliegend formations. The Weststellingwerf well flowed at an initial gross rate of 14.7 mmcf/d⁽²⁾ and is expected to be brought on production during 2020.
  
  
• In Canada, Q4 2019 production averaged 58,593 boe/d, up slightly from the prior quarter as strong results from new well completions more than offset natural decline. During the quarter, we drilled one of our best ever condensate-rich Lower Mannville wells in Drayton Valley, achieving an IP30 rate of 1,900 boe/d (60% liquids).
  
  
• Our 2019 reserves as evaluated by GLJ as at December 31, 2019 are as follows:
  
  
• Proved plus probable ("2P") reserves increased 3% from year-end 2018 to 501.2⁽³⁾ mmboe. We replaced 120% of 2019 production through development activities and 136% including acquisitions. Our 2P finding and development ("F&D") cost⁽⁴⁾ was $9.93 per boe, including future development capital ("FDC")⁽⁴⁾, resulting in an organic 2P Operating Recycle Ratio⁽⁵⁾ (including FDC) of 3.0x.
  
  
• Proved ("1P") reserves increased 4% from year-end 2018 to 310.2⁽³⁾ mmboe. We replaced 121% of 1P reserves through development activities and 133% including acquisitions. Our 1P F&D cost was $11.90 per boe, including FDC, resulting in an organic 1P Operating Recycle Ratio⁽⁵⁾ (including FDC) of 2.5x.
  
  
• Proved developed producing ("PDP") reserves increased 4% from year-end 2018 to 200.0⁽³⁾ mmboe. We replaced 113% of PDP reserves through development activities and 122% including acquisitions. Our PDP F&D cost was $12.71 per boe, including FDC, resulting in an organic PDP Operating Recycle Ratio⁽⁵⁾ (including FDC) of 2.3x.
  
  
• Vermilion's board of directors has approved a 50% reduction in our monthly dividend to $0.115 per share in response to weakness in commodity prices and reduced global economic prospects following the outbreak of the novel coronavirus (COVID-19). The revised dividend will be effective for the March dividend payable on April 15, 2020.

^(1)	Non-GAAP Financial Measure.  Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis.
^(2)	The Weststellingwerf flow rate was 14.7 mmcf/d gross over a 24 hour period at a wellhead pressure of 1,625 psi.  Initial flow rates are not necessarily indicative of long-term performance or ultimate recovery.
^(3)	Estimated company interest proved, developed and producing, total proved, and total proved plus probable reserves as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 10, 2020 with an effective date of December 31, 2019 (the "2019 GLJ Reserves Report").
^(4)	F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted FDC (future development capital), by the change in the reserves, incorporating revisions and production, for the same period.
^(5)	Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost).  Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis.

($M except as indicated)	Q4 2019	Q3 2019		Q4 2018	2019	2018
Financial
Petroleum and natural gas sales	388,802	391,935		456,939	1,689,863	1,678,117
Fund flows from operations	215,592	216,153		222,342	908,055	838,652
Fund flows from operations ($/basic share) (1)	1.38	1.39		1.46	5.87	5.96
Fund flows from operations ($/diluted share) (1)	1.38	1.39		1.44	5.82	5.89
Net earnings (loss)	1,477	(10,229)		323,373	32,799	271,650
Net earnings (loss) ($/basic share)	0.01	(0.07)		2.12	0.21	1.93
Capital expenditures	100,625	127,879		163,580	523,164	518,214
Acquisitions	9,165	4,657		2,689	38,472	1,759,425
Asset retirement obligations settled	7,352	3,586		6,562	19,442	15,765
Cash dividends ($/share)	0.690	0.690		0.690	2.760	2.715
Dividends declared	107,702	107,176		105,310	427,311	388,111
% of fund flows from operations	50%	50%		47%	47%	46%
Net dividends ^(1)	97,502	98,316		100,195	392,374	339,060
% of fund flows from operations	45%	45%		45%	43%	40%
Payout ^(1)	205,479	229,781		270,337	934,980	873,039
% of fund flows from operations	95%	106%		122%	103%	104%
Net debt	1,993,194	2,001,870		1,929,529	1,993,194	1,929,529
Net debt to four quarter trailing fund flows from operations	2.20	2.19		2.30	2.20	2.30
Operational
Production
Crude oil and condensate (bbls/d)	46,261	47,242		47,678	47,902	39,182
NGLs (bbls/d)	8,160	7,772		7,815	7,984	6,366
Natural gas (mmcf/d)	260.72	253.36		276.77	266.82	250.33
Total (boe/d)	97,875	97,239		101,621	100,357	87,270
Average realized prices
Crude oil and condensate ($/bbl)	71.25	73.45		66.19	74.42	79.16
NGLs ($/bbl)	14.63	6.14		25.69	13.61	26.33
Natural gas ($/mcf)	3.61	2.43		5.83	3.58	5.45
Production mix (% of production)
% priced with reference to WTI	40%	39%		37%	39%	32%
% priced with reference to Dated Brent	17%	19%		18%	18%	20%
% priced with reference to AECO	26%	26%		26%	25%	26%
% priced with reference to TTF and NBP	17%	16%		19%	18%	22%
Netbacks ($/boe)
Operating netback (1)	27.53	28.22		27.58	29.25	31.59
Fund flows from operations netback	24.40	23.73		23.79	24.77	26.47
Operating expenses	12.52	11.55		12.04	12.01	11.26
General and administration expenses	1.88	1.50		1.37	1.61	1.64
Average reference prices
WTI (US $/bbl)	56.96	56.45		58.81	57.03	64.77
Edmonton Sweet index (US $/bbl)	51.59	51.79		32.51	52.15	53.65
Saskatchewan LSB index (US $/bbl)	51.58	52.01		44.03	52.50	56.46
Dated Brent (US $/bbl)	63.25	61.94		67.76	64.30	71.04
AECO ($/mcf)	2.48	1.06		1.56	1.76	1.50
NBP ($/mcf)	5.38	4.50		11.03	5.90	10.35
TTF ($/mcf)	5.36	4.40		10.91	5.90	10.23
Average foreign currency exchange rates
CDN $/US $	1.32	1.32		1.32	1.33	1.30
CDN $/Euro	1.46	1.47		1.51	1.49	1.53
Share information ('000s)
Shares outstanding - basic	156,290	155,505		152,704	156,290	152,704
Shares outstanding - diluted ^(1)	159,912	159,260		156,173	159,912	156,173
Weighted average shares outstanding - basic	155,950	155,254		152,588	154,736	140,619
Weighted average shares outstanding - diluted ^(1)	156,180	155,421		153,880	156,094	142,335

^(1)	The above table includes non-GAAP financial measures which may not be comparable to other companies.  Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis.

Message to Shareholders

We are now in the sixth year of a period of reduced energy prices that began in the second half of 2014, with the novel coronavirus (COVID-19) being the latest event to produce a retracement in commodity markets.  Throughout this period, we have maintained focus on profitability by grinding costs out of all phases of our business ranging from field operations to financing expense, upgrading our capital project slate, and adapting our capital markets model to focus even more acutely on returning capital to shareholders.  In this environment, we have been unique among our traditional competitor group in maintaining our dividend while still providing a moderate level of growth.  We have paid a monthly dividend (or distribution in the trust era) for the past 205 consecutive months, returning over $40 per share to shareholders over this period.  During the energy downturn, we have put more production, reserves and free cash flow behind each share despite dramatically lower capital budgets.  While still modestly over 100%, we brought our total payout ratio down to 103% in 2019, representing our lowest total payout ratio since before the financial crisis in 2008.  Moreover, we are phasing out the small level of remaining DRIP participation at the end of Q3 2020, resulting in 100% of dividends being paid in cash.

We are proud of this record of returning capital to shareholders while still providing per share growth.  We think paying dividends is the right thing to do.  This model has kept us disciplined in a capital-intensive industry and has put substantial cash back in the hands of investors.  As we started 2020, our funding status continued to improve to a projected total payout ratio below 100%, driven by a significantly lower capital budget for 2020 as compared to 2019, and by a modestly positive trend for oil prices.  In that environment, we were confident in our ability to continue our monthly dividend at $0.23 while deleveraging our balance sheet.  We were clear in stating that we would reevaluate the dividend in the event of a structural change in commodity prices that could affect our ability to self-fund our combination of capital expenditures and dividends, and that we would prioritize balance sheet strength over other objectives, including either growth or dividends.

The emergence of COVID-19 was an unanticipated event, and we do not claim any special expertise in assessing what the appropriate type or degree of public health responses are to the outbreak.  Nonetheless, we must make an assessment of its current and probable future market and economic impacts.  We observe that COVID-19 has dramatically altered individual, business and government behavior, and that these impacts are decidedly negative for the outlook for global economic growth, commodity prices in general, and oil demand and prices in particular.  We do not believe that the long-term prospects for the oil and gas industry are likely to be significantly altered, and ultimately we expect a resumption of a positive trend for commodity prices.  However, we do think the recovery in oil prices that we began to experience at the outset of 2020 will be pushed back for an unknown period.  In the short-to-medium term, we believe COVID-19 represents a hard-to-quantify set of macro risks, probably lower in economic severity than the financial crisis of 2008, but of a type that is also likely unprecedented in our lifetimes.

We have maintained our dividend though a number of other periods of downside volatility since the commodity crash of 2014, making all of the necessary adjustments to costs and growth levels.  During these periods, we continuously assessed our dividend policy in light of our top priority of balance sheet strength.  As we consider today's economic and commodity outlook, we believe it is unlikely that we would achieve fully-funded status for our present dividend at a reasonable level of capital expenditures.  Therefore, we have determined that a reduction to our dividend is the most prudent course of action at this time.  Accordingly, our board of directors has approved a 50% reduction in our monthly dividend to $0.115 per share, or $1.38 on an annualized basis.  The revised dividend will be effective for the March dividend payable on April 15, 2020.  At the current forward commodity strip, we estimate a 2020 payout ratio of 99%, including previously declared dividends.  Any excess cash generated beyond the dividend and capital requirements will be allocated towards debt reduction at this time, while retaining the option of buying back shares through our NCIB program in an improved macroeconomic environment.

We have had no operational impacts from COVID-19 to-date.  We have business continuity plans for each of our business units and for our corporate center that can be invoked if the outbreak significantly worsens and threatens our supply chain or workforce capabilities.

During 2019, Vermilion generated record cash flow, production and reserves despite a continued environment of challenging commodity prices.  We recorded FFO of $908 million in 2019 on a capital program of $523 million, which translated to free cash flow⁽¹⁾ generation of $385 million, also the highest in our history.  The resulting 2019 total payout ratio, after accounting for dividends and asset retirement obligations, was 103%.  In Q4 2019, we generated $216 million of FFO which was in line with the prior quarter despite a large inventory build in Australia due to the timing of crude liftings.  Net debt in 2019 increased modestly to $2.0 billion, however the net debt to trailing FFO ratio improved to 2.2x, compared to 2.3x in 2018.  In addition to an improving leverage profile, we also enhanced the quality of our balance sheet over the past year.  We have recently received commitments to extend our $2.1 billion covenant-based credit facility, resulting in a new a maturity date of May 2024. The closing of the extension remains subject to customary closing conditions.  In addition, in June 2019, we executed a cross currency interest rate swap on our 2025 US$300 million long-term senior notes, converting our 5.625% interest cost on these notes to 3.275% for the remainder of their term.  As a result of these initiatives, our pre-tax cost of debt today is approximately 3.2% with a weighted-average remaining term of 4.4 years.

We delivered record production of 100,357 boe/d in 2019, representing year-over-year growth of 15%, or 5% on a per share basis.  We achieved these results despite several unexpected operational challenges throughout the year, including a third-party refinery outage in France and uncharacteristic weather-driven delays in Canada.  During the fourth quarter we tied-in two discoveries in Hungary and successfully drilled the Weststellingwerf well in the Netherlands, marking our first drilling activity in that country in two and a half years.  In the US, new well completions from our Q3 2019 program drove increased production from our North American region.  Two months into the new year, the execution of our 2020 capital program is progressing as planned.  To mitigate the risk of another season of post-breakup weather delays, which affected our results in 2019, we are front-loading our 2020 capital program by scheduling most of our North American drilling activity into the first quarter.

Proved plus probable reserves increased by 3% year-over-year to 501.2 mmboe.  The large majority of our new reserve additions were through organic activities as we continue to enhance the recovery factor on existing assets and advanced resources to reserves in a number of our operating areas.  We added these reserves at an organic F&D cost of $9.93/boe, including FDC, resulting in an operating recycle ratio of 3.0x and funds flow recycle ratio of 2.5x.  Our F&D costs have been below $10.00/boe for the past three years (3-year average F&D of $9.38, including FDC), while growing our liquids weighting.  Driven by a capital-efficient project slate and a continued focus on cost improvements, our 3-year organic operating recycle ratio stands at 3.2x.  Our contingent and prospective resource bases remain a source of reserve additions, with 31.8 mmboe of contingent and 5.0 mmboe of prospective resources converted to 2P reserves during 2019.

As we stated earlier, our top financial priority remains balance sheet strength.  Both our debt-to-cash flow ratio and weighted-average interest rate decreased in 2019, and our debt exposures are fully termed-out via our covenant-based bank facility and long-term notes.  Nonetheless, we will continue to be vigilant regarding commodity prices and resulting cash flows.  It remains to be seen how long oil demand and economic growth will be suppressed by the global reaction to COVID-19.  Should we experience an even more-pronounced and protracted commodity downturn due to COVID-19 or any other cause, we will be attentive to all forms of cash outlays, focusing first on capital investment levels, to protect the financial position of the company.

Q4 2019 Operations Review

Europe

In France, Q4 2019 production averaged 10,264 boe/d, representing a slight decrease from the prior quarter primarily due to weather-driven downtime in the Aquitaine Basin.  Production in the Paris Basin was relatively consistent with the prior quarter.

In the Netherlands, Q4 2019 production averaged 8,088 boe/d, an increase of 9% from the prior quarter.  The increase was primarily due to the restoration of production following planned and unplanned facility downtime in Q3 2019.  During the quarter, we successfully drilled and completed the Weststellingwerf well (0.5 net), representing our first drilling activity in the Netherlands since 2017.  We encountered three gas-bearing zones in the Vlieland, Zechstein and Rotliegend formations.  The Weststellingwerf well flowed at an initial gross rate of 14.7 mmcf/d⁽²⁾ and is expected to be brought on production during 2020.

In Ireland, production averaged 42 mmcf/d (7,049 boe/d) in Q4 2019, a decrease of 2% from the prior quarter.  The decrease was primarily due to natural decline, partially offset by higher uptime at the Corrib natural gas processing facility compared to the prior quarter.  As disclosed in our Q3 2019 release, we had 10 days of unplanned downtime in one of the plant auxiliary systems, which occurred at the end of Q3 2019 and continued into Q4 2019.  Since assuming operatorship of Corrib at the end of 2018, we have reduced operating costs by approximately 20% and continue to evaluate other optimization opportunities.

In Germany, Q4 2019 production averaged 3,373 boe/d, an increase of 3% from the prior quarter.  The increase was primarily due to improved uptime on our operated oil and natural gas assets, partially offset by unplanned downtime on our non-operated oil assets.  Following the successful drilling of the Burgmoor Z5 (46% working interest) well in 2019, the partner group has agreed to a tie-in plan which should allow for production early next year.

In Central and Eastern Europe ("CEE"), production averaged 276 boe/d following the tie-in of two discoveries from our 2019 drilling program late in the year.  In Hungary, we tied-in the Mh-21 (0.3 net) and Battonya E-09 (1.0 net) wells, drilled in the second and third quarters of 2019, respectively.  The wells were brought on production midway through the fourth quarter of 2019 at a restricted rate of approximately 600 boe/d net for the two wells combined.  In addition, we were provisionally awarded the Kadarkút exploration license in western Hungary during the quarter and we expect to receive final government approvals in the first quarter of 2020.  The license covers approximately 298,500 net acres and consists of primarily oil prospects.  Most of the license is covered by 3D seismic.  The license term covers a four year period, with the option to extend the license for a further two years.  In Croatia, we continued to prepare for our 2020-2021 drilling programs, in addition to evaluating natural gas plant processing facility construction options, which we expect to allow tie-in of our 2019 natural gas discoveries next year.

North America

In Canada, production averaged 58,593 boe/d in Q4 2019, up slightly from the prior quarter.  Strong results from new well completions in the quarter more than offset natural decline.  We drilled or participated in 26 (16.8 net) wells in the fourth quarter of 2019, eight (8.0 net) of which were drilled in Alberta and 18 (8.8 net) drilled in Saskatchewan.  During the quarter, we drilled one of our best ever condensate-rich Lower Mannville wells in Drayton Valley, Alberta, achieving an IP30 rate of approximately 1,900 boe/d (60% liquids).  In Ferrier, we drilled a liquids-rich Upper Mannville well which delivered an IP30 rate of approximately 1,800 boe/d (15% liquids).  We brought 33 (23.5 net) wells on production in Saskatchewan and four (4.0 net) wells on production in Alberta during the quarter.  We are currently in the midst of a very active Q1 2020 drilling campaign in Canada, with rig activity in the quarter peaking at six rigs in Saskatchewan and four rigs in Alberta.  We plan to complete the majority of our 2020 Canadian drilling program in the first quarter of the year in order to avoid potential delays from an extended spring break-up season or unseasonably wet summer weather.

In the United States, Q4 2019 production averaged 5,683 boe/d, representing an increase of 15% from the prior quarter.  The increase was primarily due to a full quarter of contribution from the four wells we brought on production during the third quarter of 2019.  These wells continue to perform in line with our type curves, achieving an average IP90 rate of approximately 450 boe/d.  We also began drilling two (1.98 net) wells in December 2019, for which drilling finished in January 2020, and are currently undergoing completion.  We currently have two rigs operating in our Hilight field in the Powder River Basin.  Similar to our Canadian business unit, we plan to execute a front-end weighted capital program in the United States, completing our twelve (11.9 net) well 2020 drilling program in the first half of the year.

Australia

In Australia, production averaged 4,548 bbl/d in Q4 2019, a decrease of 18% from the previous quarter, primarily due to the planned shutdown of the Wandoo platform for eight days to perform facility upgrades and regular maintenance.  We recently began the installation of electric submersible pumps on two wells and will continue to advance process optimization projects throughout 2020.

Dividend Reinvestment Plan

As previously announced, we are phasing out the Dividend Reinvestment Plan ("DRIP") in 2020 by prorating the available DRIP shares by 25% each quarter starting in Q1 2020.  It is our intention to increase this proration each quarter throughout the year, such that the DRIP will be eliminated at the end of the third quarter of 2020.

Commodity Hedging

Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows, providing additional certainty with regard to the execution of our dividend and capital programs.  In aggregate, as of February 24, 2020, we currently have 51% of our expected net-of-royalty production hedged for Q1 2020.  More than half of our Q1 2020 corporate hedge position consists of two-way collars and three-way structures, which allow participation in price increases up to contract ceilings.  For 2020 as a whole, approximately 42% of our production is hedged, with 63% of our hedge position in participating structures.

With respect to individual products within our product mix, we have hedged 70% of anticipated European natural gas volumes for Q1 2020.  We have also hedged 78% of our anticipated full-year 2020 European natural gas volumes at prices which are expected to provide for strong project economics and free cash flows.  At present, 44% of our expected Q1 2020 oil production is hedged.  For Q1 2020, 45% of our North American natural gas production is priced away from AECO, with a variety of contracts to sell gas at the SoCal Border, Henry Hub, Saskatchewan and Wyoming.

Sustainability

We delivered another year of industry-leading performance as indicated by a number of important ESG rankings.  The Company received a top quartile ranking for our industry sector in SAM's 2019 Corporate Sustainability Assessment ("CSA").  The CSA analyzes sustainability performance across economic, environmental, governance, and social criteria, and is the basis of the Dow Jones Sustainability Indices.  Vermilion was ranked second in our peer group in the Sustainalytics ESG (environment, social, governance) rankings.  Vermilion's MSCI ESG rating increased to AA in 2019, and our Governance Metrics score ranked in the top decile globally.  We received ISS QualityScore decile ratings of 1 for both Environmental and Social, which assess corporate disclosure and transparency practices in these areas, where 1 indicates the lowest risk.  These rankings reflect our high degree of ESG focus, and we will strive to continue to this record of high performance as we move forward.

2019 Reserves and Resources

In 2019 we increased our reserves and resources predominantly through development activities.  Based on the 2019 GLJ Reserves Report, our 2P reserves increased 3% from year-end 2018 to 501.2⁽³⁾ mmboe, while our 1P reserves increased 4% from year-end 2018 to 310.2⁽³⁾ mmboe in 2019.  PDP reserves increased 4% from year-end 2018 to 200.0⁽³⁾ mmboe.  Our PDP reserves represent 65% of our 1P reserves.

The following table provides a summary of company interest reserves by reserve category and country on an oil equivalent basis.  Please refer to Vermilion's 2019 Annual Information Form for the year ending December 31, 2019 ("2019 Annual Information Form") for detailed by product type information.

BOE (mboe)	Proved Developed Producing	Proved Developed Non-Producing	Proved Undeveloped	Proved	Probable	Proved Plus Probable
Australia	8,608	—	—	8,608	4,552	13,160
Canada	111,738	7,125	72,764	191,627	109,262	300,889
CEE	228	1,503	—	1,731	972	2,703
France	35,109	934	4,920	40,963	18,729	59,692
Germany	9,694	2,930	1,157	13,781	12,959	26,740
Ireland	11,772	—	—	11,772	6,002	17,774
Netherlands	8,620	2,035	450	11,105	9,875	20,980
United States	14,222	515	15,886	30,623	28,673	59,296
Vermilion	199,991	15,042	95,177	310,210	191,024	501,233

Through development activities, we replaced 120% of 2P reserves, 121% of 1P reserves and 113% of PDP reserves, respectively.  Including acquisitions, we replaced 136% of 2P reserves, 133% of 1P reserves and 122% of PDP reserves, respectively.  Reserve additions included 15.0 million boe of positive technical revisions at the 1P level.

Our Operating Recycle Ratio⁽⁵⁾ (including FDC) at the 2P level was 3.0x in 2019.  We have achieved F&D costs below $10.00/boe for the past three years (3-year average F&D of $9.38, including FDC) as a result of our highly capital-efficient project slate and continued focus on cost improvements.

The following table summarizes the finding and development costs and associated operating recycle ratios by reserve category for the year ending December 31, 2019:

	2019			3-Year Average
	PDP	1P	2P	PDP	1P	2P
Finding and Development Costs, including FDC (F&D)^(4) ($/boe)	$12.71	$11.90	$9.93	$13.66	$12.71	$9.38
Finding, Development and Acquisition Costs, including FDC (FD&A)^(4) ($/boe)	$12.69	$11.82	$9.85	$19.31	$17.48	$13.84
F&D Operating Recycle Ratio^(5) *	2.3	2.5	3.0	2.2	2.4	3.2
FD&A Operating Recycle Ratio^(5) *	2.3	2.5	3.0	1.6	1.7	2.2

In addition to our reserve base, we report contingent and prospective resources.  According to the 2019 GLJ Resources Report, risked low, best, and high estimates for our contingent resources in the Development Pending category were 139.0⁽⁶⁾ mmboe, 236.8⁽⁶⁾ mmboe, and 330.2⁽⁶⁾ mmboe, respectively.  The 2019 GLJ Resources Report also indicates risked low, best, and high estimates for contingent resources in the Development Unclarified category of 10.8⁽⁶⁾ mmboe, 37.6⁽⁶⁾ mmboe, and 54.1⁽⁶⁾ mmboe, respectively.  Over 86% of our best estimate risked contingent resources reside in the Development Pending category.  Prospective resources were assessed at risked low, best and high estimates of 51.9⁽⁶⁾ mmboe, 179.2⁽⁶⁾ mmboe, and 330.2⁽⁶⁾ mmboe, respectively.  Our contingent and prospective resource bases remain a source of reserve additions, with 31.8 mmboe of contingent and 5.0 mmboe of prospective resources converted to 2P reserves during 2019.

The following table provides a reconciliation of changes in company interest reserves by reserve category and country.  Please refer to Vermilion's 2019 Annual Information Form for detailed by product type information.

1P (mboe)	Australia	Canada	CEE	France	Germany	Ireland	Netherlands	United States	Vermilion
December 31, 2018	9,668	181,938	131	43,467	12,990	13,094	11,804	25,146	298,236
Discoveries	—	491	1,725	—	844	—	—	—	3,060
Extensions & improved recovery	—	20,981	—	551	470	—	720	4,254	26,976
Technical revisions	1,007	7,019	(100)	806	743	1,511	1,601	2,368	14,955
Acquisitions	—	3,847	—	—	—	—	—	561	4,408
Dispositions	—	(13)	—	—	—	—	—	—	(13)
Economic factors	—	(744)	—	(40)	—	—	—	—	(784)
Production	(2,067)	(21,892)	(25)	(3,821)	(1,266)	(2,833)	(3,020)	(1,706)	(36,630)
December 31, 2019	8,608	191,627	1,731	40,963	13,781	11,772	11,105	30,623	310,210

2P (mboe)	Australia	Canada	CEE	France	Germany	Ireland	Netherlands	United States	Vermilion
December 31, 2018	14,480	284,835	190	63,918	25,733	20,576	22,200	56,213	488,145
Discoveries	—	1,044	2,686	—	1,250	—	—	—	4,980
Extensions & improved recovery	—	31,200	—	810	920	—	1,131	2,693	36,754
Technical revisions	747	1,190	(148)	(549)	103	31	669	1,143	3,186
Acquisitions	—	5,350	—	—	—	—	—	953	6,303
Dispositions	—	(428)	—	—	—	—	—	—	(428)
Economic factors	—	(410)	—	(666)	—	—	—	—	(1,076)
Production	(2,067)	(21,892)	(25)	(3,821)	(1,266)	(2,833)	(3,020)	(1,706)	(36,630)
December 31, 2019	13,160	300,889	2,703	59,692	26,740	17,774	20,980	59,296	501,233

Additional information about our 2019 GLJ Reserves Report and GLJ 2019 Resources Report can be found in our 2019 Annual Information Form on our website at www.vermilionenergy.com and on SEDAR at www.sedar.com.

(signed "Anthony Marino")

Anthony Marino
President & Chief Executive Officer
March 5, 2020

^(1)	Non-GAAP Financial Measure.  Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis.
^(2)	The Weststellingwerf flow rate was 14.7 mmcf/d gross over a 24 hour period at a wellhead pressure of 1,625 psi.  Initial flow rates are not necessarily indicative of long-term performance or ultimate recovery.
^(3)	Estimated company interest proved, developed and producing, total proved, and total proved plus probable reserves as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 10, 2020 with an effective date of December 31, 2019 (the "2019 GLJ Reserves Report").
^(4)	F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted FDC (future development capital), by the change in the reserves, incorporating revisions and production, for the same period.
^(5)	Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost).  Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis.
^(6)	Vermilion retained GLJ to conduct an independent resource evaluation dated February 10, 2020 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2019 (the "GLJ 2019 Resources Report").  The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 83%, 81% and 81%, respectively.  The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 24%, 24% and 24%, respectively.  There is uncertainty that it will be commercially viable to produce any portion of the resources.  Project maturity subclass development pending is defined as contingent resources where resolution of the final conditions for development is being actively pursued (high chance of development).  Project maturity subclass development unclarified is defined as contingent resources when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties.  Prospective resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from unknown accumulations by application of future development projects.  There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources.  There is no certainty that any portion of the prospective resources will be discovered.  If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources or that Vermilion will produce any portion of the volumes currently classified as prospective resources.  Please refer to Vermilion's 2019 Annual Information Form for further information on Vermilion's contingent resources and prospective resources.

Guidance

On October 25, 2018, we released our 2019 capital budget and related guidance.  On February 27, 2019, we deferred some activity to later in the year and reallocated capital between business units, although the 2019 total budget and production guidance remained unchanged.  On October 31, 2019, we reduced our 2019 capital expenditure guidance to $520 million and our 2019 annual production guidance to 100,000 to 101,000 boe/d.  Actual 2019 capital spending of $523 million was within 1% of our guidance and 2019 average production of 100,357 boe/d was approximately at the mid-point of our revised guidance range.

On October 31, 2019, we released our 2020 capital budget and associated production guidance.

The following table summarizes our guidance:

	Date	Capital Expenditures ($MM)	Production (boe/d)
2019 Guidance
2019 Guidance	October 25, 2018	530	101,000 to 106,000
2019 Guidance	October 31, 2019	520	100,000 to 101,000
2019 Actual Results	March 6, 2020	523	100,357
2020 Guidance
2020 Guidance	October 31, 2019	450	100,000 to 103,000

Conference Call and Webcast Details

Vermilion will discuss these results in a conference call and webcast presentation on Friday, March 6, 2020 at 9:00 AM MST (11:00 AM EST).  To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area).  A recording of the conference call will be available for replay by calling 1-855-859-2056 and using conference ID 8457996 from March 6, 2020 at 12:00 PM MST to March 20, 2020 at 9:59 PM MST.

You may also access the webcast at https://event.on24.com/wcc/r/2209057/77DA8099A827A0D8BC4A73C85AFABBDD.  The webcast link, along with conference call slides, will be available on Vermilion's website at https://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events prior to the conference call.

About Vermilion

Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia.  Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors.  Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia.  Vermilion holds a 20% working interest in the Corrib gas field in Ireland.  Vermilion pays a monthly dividend of Canadian $0.115 per share, which provides a current yield of approximately 11%.

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

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

Disclaimer

Certain statements included or incorporated by reference in this document may constitute forward-looking statements or financial outlooks under applicable securities legislation.  Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook.  Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion's ability to fund such expenditures;  Vermilion's additional debt capacity providing it with additional working capital; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; estimated volumes of reserves and resources; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2020 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange rates and significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; statements regarding the growth and size of Vermilion's future project inventory, and the wells expected to be drilled in 2020; exploration and development plans and the timing thereof; Vermilion's ability to reduce its debt, including its ability to redeem senior unsecured notes prior to maturity; statements regarding Vermilion's hedging program, its plans to add to its hedging positions, and the anticipated impact of Vermilion's hedging program on project economics and free cash flows; the potential financial impact of climate-related risks; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates and Vermilion's expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.

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

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

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

All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook.  Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development.  The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.

Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.  Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation.  A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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

SOURCE Vermilion Energy Inc.

Anthony Marino, President & CEO; Michael Kaluza, Executive VP & COO; Lars Glemser, C.A., Vice President & CFO; and/or Kyle Preston, Vice President, Investor Relations, TEL [phone] | IR TOLL FREE 1-866-895-8101 | [email protected] | www.vermilionenergy.com

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