Exhibit 99.2

Vermilion Energy Inc. 2017 Annual Report

ABBREVIATIONS

$M	thousand dollars
$MM	million dollars
AECO	the daily average benchmark price for natural gas at the AECO ‘C’ hub in southeast Alberta
bbl(s)	barrel(s)
bbls/d	barrels per day
boe	barrel of oil equivalent, including: crude oil, condensate, natural gas liquids, and natural gas (converted on the basis of one boe for six mcf of natural gas)
boe/d	barrel of oil equivalent per day
GJ	gigajoules
HH	Henry Hub, a reference price paid for natural gas in US dollars at Erath, Louisiana
mbbls	thousand barrels
mcf	thousand cubic feet
mmbtu	million British thermal units
mmcf/d	million cubic feet per day
MWh	megawatt hour
NBP	the reference price paid for natural gas in the United Kingdom, quoted in pence per therm, at the National Balancing Point Virtual Trading Point.  Our production in Ireland is priced with reference to NBP.
NGLs	natural gas liquids, which includes butane, propane, and ethane
PRRT	Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia
TTF	the price for natural gas in the Netherlands, quoted in MWh of natural gas, at the Title Transfer Facility
	Virtual Trading Point
WTI	West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma

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Vermilion Energy Inc. 2017 Annual Report

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; 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.

All oil and natural gas reserve 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. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document. The estimated future net revenue from the production of crude oil and natural gas reserves does not represent the fair market value of these reserves.

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

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

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Vermilion Energy Inc. 2017 Annual Report

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following is Management’s Discussion and Analysis (“MD&A”), dated February 28, 2018, of Vermilion Energy Inc.’s (“Vermilion”, “we”, “our”, “us” or the “Company”) operating and financial results as at and for the three months and year ended December 31, 2017 compared with the corresponding periods in the prior year.

This discussion should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2017 and 2016, together with the accompanying notes. Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR at www.sedar.com or on Vermilion’s website at www.vermilionenergy.com.

The audited consolidated financial statements for the year ended December 31, 2017 and comparative information have been prepared in Canadian dollars, except where another currency has been indicated, and in accordance with International Financial Reporting Standards (“IFRS” or, alternatively, “GAAP”) as issued by the International Accounting Standards Board.

This MD&A includes references to certain financial and performance measures which do not have standardized meanings prescribed by IFRS. These measures include:

• Fund flows from operations: Fund flows from operations is a measure of profit or loss in accordance with IFRS 8 “Operating Segments”.  Please see SEGMENTED INFORMATION in the NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS for a reconciliation of fund flows from operations to net earnings.  We analyze fund flows from operations both on a consolidated basis and on a business unit basis in order to assess the contribution of each business unit to our ability to generate income necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments.

• Netbacks: Netbacks are per boe and per mcf performance measures used in the analysis of operational activities.  We assess netbacks both on a consolidated basis and on a business unit basis in order to compare and assess the operational and financial performance of each business unit versus other business units and also versus third party crude oil and natural gas producers.

In addition, this MD&A includes references to certain financial measures which are not specified, defined, or determined under IFRS and are therefore considered non-GAAP financial measures. These non-GAAP financial measures are unlikely to be comparable to similar financial measures presented by other issuers. For a full description of these non-GAAP financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to “NON-GAAP FINANCIAL MEASURES”.

VERMILION’S BUSINESS

Vermilion is a Calgary, Alberta based international oil and gas producer focused on the acquisition, exploration, development and optimization of producing properties in North America, Europe, and Australia. We manage our business through our Calgary head office and our international business unit offices. This MD&A separately discusses each of our business units in addition to our corporate segment.

CONDENSATE PRESENTATION

We report our condensate production in Canada and the Netherlands business units within the crude oil and condensate production line.  We believe that this presentation better reflects the historical and forecasted pricing for condensate, which is more closely correlated with crude oil pricing than with pricing for propane, butane and ethane (collectively “NGLs” for the purposes of this report).

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Vermilion Energy Inc. 2017 Annual Report

2017 REVIEW AND 2018 GUIDANCE

On October 31, 2016, we released our 2017 capital expenditure guidance of $295 million and associated production guidance of between 69,000-70,000 boe/d. On July 26, 2017 we announced an increase in our capital expenditure guidance from $295 million to $315 million following the acceleration of 2018 activities in our Canadian business unit. We also adjusted our 2017 annual production guidance on October 30, 2017 to 68,000-69,000 boe/d to reflect an extended downtime period following a plant turnaround at our Corrib asset in Ireland. Actual 2017 capital spending of $320 million was within 2% of our guidance and 2017 production of 68,021 boe/d modestly exceeded the bottom end of our guidance range.

On October 30, 2017, we released our 2018 capital expenditure guidance of $315 million and associated production guidance of between 74,500-76,500 boe/d. On January 15, 2018, we increased our capital expenditure guidance to $325 million and production guidance to between 75,000-77,500 boe/d to reflect the post-closing impact of the acquisition of a private southeast Saskatchewan and southwest Manitoba light oil producer.

The following table summarizes our guidance:

	Date	Capital Expenditures ($MM)	Production (boe/d)
2017 Guidance
2017 Guidance	October 31, 2016	295	69,000 to 70,000
2017 Guidance	July 26, 2017	315	69,000 to 70,000
2017 Guidance	October 30, 2017	315	68,000 to 69,000
2017 Actual Results		320	68,021
2018 Guidance
2018 Guidance	October 30, 2017	315	74,500 to 76,500
2018 Guidance	January 15, 2018	325	75,000 to 77,500

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Vermilion Energy Inc. 2017 Annual Report

CONSOLIDATED RESULTS OVERVIEW

	Three Months Ended					% change				Year Ended			% change
	Dec 31, 2017	Sep 30, 2017		Dec 31, 2016		Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		Dec 31, 2017	Dec 31, 2016		2017 vs. 2016
Production
Crude oil and condensate (bbls/d)	27,830	27,687		25,972		1	%	7	%	27,721	27,852		—	%
NGLs (bbls/d)	5,279	4,947		2,467		7	%	114	%	4,194	2,582		62	%
Natural gas (mmcf/d)	238.27	208.63		194.54		14	%	22	%	216.64	198.55		9	%
Total (boe/d)	72,821	67,403		60,863		8	%	20	%	68,021	63,526		7	%
Sales
Crude oil and condensate (bbls/d)	27,638	28,391		26,610		(3	)%	4	%	27,483	28,005		(2	)%
NGLs (bbls/d)	5,279	4,946		2,467		7	%	114	%	4,194	2,582		62	%
Natural gas (mmcf/d)	238.27	208.63		194.54		14	%	22	%	216.64	198.55		9	%
Total (boe/d)	72,628	68,108		61,501		7	%	18	%	67,784	63,679		6	%
Build (draw) in inventory (mbbls)	18	(64	)	(58	)					87	(55	)
Financial metrics
Fund flows from operations ($M)	181,253	130,755		149,582		39	%	21	%	602,565	510,791		18	%
Per share ($/basic share)	1.49	1.08		1.27		38	%	17	%	5.00	4.41		13	%
Net earnings (loss)	8,645	(39,191	)	(4,032	)	N/A		N/A		62,258	(160,051	)	N/A
Per share ($/basic share)	0.07	(0.32	)	(0.03	)	N/A		N/A		0.52	(1.38	)	N/A
Net debt ($M)	1,371,790	1,370,995		1,427,148		—	%	(4	)%	1,371,790	1,427,148		(4	)%
Cash dividends ($/share)	0.645	0.645		0.645		—	%	—	%	2.580	2.580		—	%
Activity
Capital expenditures ($M)	74,303	91,382		66,882		(19	)%	11	%	320,449	242,408		32	%
Acquisitions ($M)	3,048	20,976		78,713		(85	)%	(96	)%	27,637	98,524		(72	)%
Gross wells drilled	8.00	17.00		16.00						56.00	38.00
Net wells drilled	6.00	13.77		12.02						46.58	25.50

Operational review

• Consolidated average production during Q4 2017 increased 8% to 72,821 boe/d versus Q3 2017 due to production increases in the Netherlands, Canada, and Ireland. In the Netherlands, production growth was positively impacted by the approval of a production rate increase on two of our key pools and production from a new well drilled in Q3 2017. In Canada, increased production was driven by continued organic growth from our Mannville condensate-rich resource play. In Ireland, production growth was the result of reduced downtime at the Corrib project.

• Consolidated average production increased by 20% and 7% for the three months and year ended December 31, 2017, versus the comparable periods in 2016, respectively. Year-over-year production increases were primarily driven by continued organic production growth from our Mannville condensate-rich resource play in Canada and incremental volumes from our acquisition in Germany in late 2016.

• For the three months ended December 31, 2017, capital expenditures of $74.3 million primarily related to activity in Canada, France, and the Netherlands. In Canada, capital expenditures of $26.9 million included the drilling of 6.0 (4.0 net) wells in the Mannville. In France, capital expenditures of $20.0 million included the drilling of 2.0 (2.0 net) wells in the Neocomian. In the Netherlands, capital expenditures of $12.3 million included the acquisition of 315 square kilometers of 3D seismic.

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Vermilion Energy Inc. 2017 Annual Report

Financial review

Net earnings

• Net earnings for Q4 2017 of $8.6 million ($0.07/basic share) compared to a net loss of $39.2 million ($0.32/basic share) in Q3 2017. The net earnings in Q4 2017 largely resulted from higher revenues due to increased production volumes and stronger crude oil and European natural gas prices. In addition, net earnings in Q4 2017 benefited from an unrealized foreign exchange gain of $40.7 million, compared to an unrealized loss of $3.0 million in Q3 2017. These favourable variances were partially offset by an $80.0 million unrealized loss on derivative instruments in Q4 2017, compared to an unrealized loss of $24.2 million in the prior quarter.

• Unrealized losses and gains on derivative instruments result from mark-to-market accounting based on prevailing commodity prices at each period end. As a result, unrealized gains and losses for all derivative instruments are recognized in current period earnings based on current forward price curves, while the instruments themselves reduce Vermilion’s exposure to commodity price volatility in future periods.

• Net earnings for the three months and year ended December 31, 2017 of $8.6 million ($0.07/basic share) and $62.3 million ($0.52/basic share) compare to net losses of $4.0 million ($0.03/basic share) and $160.1 million ($1.38/basic share) in the comparative periods in 2016. The net earnings in the current year largely resulted from higher revenues due to increased production volumes and stronger crude oil and European natural gas prices. In addition, net earnings benefited from unrealized foreign exchange gains of $40.7 million and $71.7 million for the three months and year ended December 31, 2017, compared to unrealized losses of $2.5 million and $0.8 million in the respective comparative periods. For the year ended December 31, 2017, these favourable variances were coupled with a smaller unrealized loss on derivative instruments of $1.1 million (compared to an unrealized loss of $138.0 million 2016) and lower depletion and depreciation charges.

Fund flows from operations

• Generated fund flows from operations of $181.3 million during Q4 2017, an increase of 39% from Q3 2017. This quarter-over-quarter increase was driven by higher crude oil and European natural gas prices and higher sales volumes. In addition, Q4 2017 fund flows from operations benefited from lower taxes, primarily in the Netherlands as a result of an increased tax deduction for future asset retirement obligations resulting from a reduction in applicable discount rate assumptions.

• Fund flows from operations increased by 21% for the three months ended December 31, 2017 versus 2016 primarily due to a 20% increase in production and a 3% increase in realized pricing. For the year ended December 31, 2017, fund flows from operations increased 18% from 2016 primarily as a result of higher production and higher realized pricing while maintaining per unit operating expenses at a level consistent with 2016.

Net debt

• Net debt decreased to $1.37 billion as at December 31, 2017 from $1.43 billion at December 31, 2016 as fund flows from operations generated in excess of capital expenditures, acquisitions, and net dividends was used to reduce long-term debt.

Dividends

• Declared dividends of $0.215 per common share per month during the year ended December 31, 2017 ($2.58 per common share for the year).

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Vermilion Energy Inc. 2017 Annual Report

COMMODITY PRICES

	Three Months Ended			% change				Year Ended		% change
	Dec 31, 2017	Sep 30, 2017	Dec 31, 2016	Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		Dec 31, 2017	Dec 31, 2016	2017 vs. 2016
Average reference prices
Crude oil
WTI ($/bbl)	70.43	60.37	65.75	17	%	7	%	66.13	57.42	15	%
WTI (US $/bbl)	55.40	48.20	49.29	15	%	12	%	50.95	43.32	18	%
Edmonton Sweet index ($/bbl)	68.98	56.76	61.60	22	%	12	%	62.94	53.17	18	%
Edmonton Sweet index (US $/bbl)	54.26	45.32	46.18	20	%	17	%	48.49	40.11	21	%
Dated Brent ($/bbl)	78.05	65.22	65.97	20	%	18	%	70.44	57.92	22	%
Dated Brent (US $/bbl)	61.39	52.08	49.46	18	%	24	%	54.27	43.69	24	%
Natural gas
AECO ($/mmbtu)	1.69	1.45	3.09	17	%	(45	)%	2.16	2.16	—	%
NBP ($/mmbtu)	8.70	6.78	7.51	28	%	16	%	7.49	6.15	22	%
NBP (€/mmbtu)	5.81	4.61	5.22	26	%	11	%	5.12	4.19	22	%
TTF ($/mmbtu)	8.36	6.93	7.21	21	%	16	%	7.43	6.00	24	%
TTF (€/mmbtu)	5.58	4.71	5.01	18	%	11	%	5.07	4.09	24	%
Henry Hub ($/mmbtu)	3.73	3.76	3.98	(1	)%	(6	)%	4.04	3.27	24	%
Henry Hub (US $/mmbtu)	2.93	3.00	2.98	(2	)%	(2	)%	3.11	2.46	26	%
Average exchange rates
CDN $/US $	1.27	1.25	1.33	2	%	(5	)%	1.30	1.33	(2	)%
CDN $/Euro	1.50	1.47	1.44	2	%	4	%	1.46	1.47	(1	)%
Realized Prices
Crude oil and condensate ($/bbl)	74.12	61.47	64.51	21	%	15	%	67.00	55.42	21	%
NGLs ($/bbl)	29.28	23.96	18.13	22	%	62	%	25.00	11.70	114	%
Natural gas ($/mmbtu)	5.23	4.01	5.47	30	%	(4	)%	4.91	4.18	17	%
Total ($/boe)	47.49	39.66	45.93	20	%	3	%	44.41	37.88	17	%

Crude Oil

• Q4 2017 was a stronger quarter for crude oil prices with WTI and Dated Brent increasing by 15% and 18% versus the previous quarter. The increase in crude oil prices during Q4 2017 was largely due to continued indicators of supply and demand rebalancing through inventory draws in addition to the extension of the OPEC and non-OPEC coordinated production reductions until the end of 2018.

• During Q4 2017, Dated Brent crude oil averaged a premium to WTI of US$5.99/bbl and a premium to the Edmonton Sweet index of US$7.13/bbl. Approximately 63% of our crude oil and condensate production during Q4 2017 benefited from this premium pricing. As a result, our fourth quarter consolidated crude oil and condensate price of $74.12/bbl was $3.69/bbl higher than the Canadian dollar WTI average price and $5.14/bbl higher than the Canadian dollar Edmonton Sweet index price, representing premiums of 5% and 7%.

Natural Gas

• Cold weather in North America at the end of 2017 helped AECO gas prices increase 17% above the average price for Q3 2017. However, despite the late-year increase, AECO prices remain weak, averaging $1.69/mmbtu in Q4 2017 (45% below the same period the previous year).

• Supportive weather, supply disruptions, and strong Asian LNG demand all helped to boost European gas prices during Q4 2017. Both TTF and NBP markets benefited from increased demand for LNG in Asia where consumption growth has exceeded expectations and is offsetting the continued growth in global liquefaction capacity. As a result, NBP averaged $8.70/mmbtu in Q4 2017, an increase of 28% over Q3 2017 and a 16% increase year-over-year. Similarly, TTF averaged $8.36/mmbtu in Q4 2017, a 21% increase over Q3 2017 and a 16% increase year-over-year.

• During Q4 2017, average European gas prices were $8.53/mmbtu, which reflects a $6.84/mmbtu premium to AECO and a $4.80/mmbtu premium to Henry Hub pricing. We receive this premium pricing on our natural gas production in Europe, which made up nearly 55% of our total company natural gas production during Q4 2017. As a result, our Q4 2017 consolidated natural gas realized price of $5.23/mmbtu represented a $3.54/mmbtu premium to AECO and a $1.50/mmbtu premium to Henry Hub Pricing.

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Vermilion Energy Inc. 2017 Annual Report

Foreign Exchange

• While the Canadian dollar weakened slightly versus the US dollar during Q4 2017, it has generally increased in strength throughout 2017.

• The Euro also posted small gains versus the Canadian dollar during the Q4 2017, following a general increase in strength throughout 2017.

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Vermilion Energy Inc. 2017 Annual Report

FUND FLOWS FROM OPERATIONS

	Three Months Ended												Year Ended
	Dec 31, 2017				Sep 30, 2017				Dec 31, 2016				Dec 31, 2017				Dec 31, 2016
	$M		$/boe		$M		$/boe		$M		$/boe		$M		$/boe		$M		$/boe
Petroleum and natural gas sales	317,341		47.49		248,505		39.66		259,891		45.93		1,098,838		44.41		882,791		37.88
Royalties	(23,541	)	(3.52	)	(16,994	)	(2.71	)	(14,999	)	(2.65	)	(74,476	)	(3.01	)	(54,284	)	(2.33	)
Petroleum and natural gas revenues	293,800		43.97		231,511		36.95		244,892		43.28		1,024,362		41.40		828,507		35.55
Transportation	(11,986	)	(1.79	)	(10,800	)	(1.72	)	(9,565	)	(1.69	)	(43,448	)	(1.76	)	(39,511	)	(1.70	)
Operating	(65,240	)	(9.76	)	(61,832	)	(9.87	)	(59,616	)	(10.54	)	(242,267	)	(9.79	)	(222,185	)	(9.53	)
General and administration	(15,941	)	(2.39	)	(12,114	)	(1.93	)	(11,464	)	(2.03	)	(54,373	)	(2.20	)	(52,829	)	(2.27	)
PRRT	(3,572	)	(0.53	)	(4,345	)	(0.69	)	(1,568	)	(0.28	)	(19,819	)	(0.80	)	(1,568	)	(0.07	)
Corporate income taxes	2,330		0.35		(3,092	)	(0.49	)	(5,840	)	(1.03	)	(12,288	)	(0.50	)	(18,110	)	(0.78	)
Interest expense	(13,710	)	(2.05	)	(13,400	)	(2.14	)	(14,410	)	(2.55	)	(57,313	)	(2.32	)	(56,957	)	(2.44	)
Realized (loss) gain on derivative instruments	(7,493	)	(1.12	)	8,723		1.39		1,920		0.34		4,721		0.19		65,376		2.81
Realized foreign exchange gain (loss)	2,899		0.43		(4,110	)	(0.66	)	1,291		0.23		2,316		0.09		4,041		0.17
Realized other income	166		0.02		214		0.03		3,942		0.70		674		0.03		4,027		0.17
Fund flows from operations	181,253		27.13		130,755		20.87		149,582		26.43		602,565		24.34		510,791		21.91

The following table shows a reconciliation of the change in fund flows from operations:

($M)	Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		2017 vs. 2016
Fund flows from operations – Comparative period	130,755		149,582		510,791
Sales volume variance:
Canada	3,859		30,891		33,420
France	211		(4,828	)	(25,361	)
Netherlands	12,554		9,324		(15,383	)
Germany	(1,012	)	8,964		32,216
Ireland	4,090		(4,573	)	15,812
Australia	(6,252	)	(8,446	)	(10,948	)
United States	(1,189	)	1,719		5,060
Pricing variance on sales volumes:
WTI	13,785		5,249		40,279
AECO	408		(11,601	)	7,318
Dated Brent	21,168		17,860		75,105
TTF and NBP	21,214		12,891		58,529
Changes in:
Royalties	(6,547	)	(8,542	)	(20,192	)
Transportation	(1,186	)	(2,421	)	(3,937	)
Operating	(3,408	)	(5,624	)	(20,082	)
General and administration	(3,827	)	(4,477	)	(1,544	)
PRRT	773		(2,004	)	(18,251	)
Corporate income taxes	5,422		8,170		5,822
Interest	(310	)	700		(356	)
Realized derivatives	(16,216	)	(9,413	)	(60,655	)
Realized foreign exchange	7,009		1,608		(1,725	)
Realized other income	(48	)	(3,776	)	(3,353	)
Fund flows from operations – Current period	181,253		181,253		602,565

Please see CONSOLIDATED RESULTS OVERVIEW for a discussion of the key variances for the periods presented.

Fluctuations in fund flows from operations may occur as a result of changes in commodity prices and costs to produce petroleum and natural gas. In addition, fund flows from operations may be significantly affected by the timing of crude oil shipments in Australia and France. When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on the consolidated balance sheet. When the crude oil inventory is subsequently drawn down, the related expenses are recognized.

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Vermilion Energy Inc. 2017 Annual Report

CANADA BUSINESS UNIT

Overview

• Production and assets focused in West Pembina near Drayton Valley, Alberta and Northgate in southeast Saskatchewan.

• Potential for three significant resource plays sharing the same surface infrastructure in the West Pembina region in Alberta:

– Cardium light oil (1,800m depth) - in development phase

– Mannville condensate-rich gas (2,400 - 2,700m depth) - in development phase

– Duvernay condensate-rich gas (3,200 - 3,400m depth) - in appraisal phase with no investment at present

• Southeast Saskatchewan light oil development:

– Primary target is the Mississippian Midale formation (1,400 - 1,700m depth)

– Secondary targets of Mississippian Frobisher (1,400 - 1,700m depth) and Devonian Bakken/Three Forks (2,000 - 2,100m depth)

Operational and financial review

	Three Months Ended						% change				Year Ended				% change
Canada business unit ($M except as indicated)	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		Dec 31, 2017		Dec 31, 2016		2017 vs. 2016
Production and sales
Crude oil and condensate (bbls/d)	9,703		9,288		7,945		4	%	22	%	9,051		9,171		(1	)%
NGLs (bbls/d)	5,235		4,891		2,444		7	%	114	%	4,144		2,552		62	%
Natural gas (mmcf/d)	107.91		103.92		75.12		4	%	44	%	97.89		84.29		16	%
Total (boe/d)	32,923		31,499		22,910		5	%	44	%	29,510		25,771		15	%
Production mix (% of total)
Crude oil and condensate	29	%	29	%	35	%					31	%	36	%
NGLs	16	%	16	%	11	%					14	%	10	%
Natural gas	55	%	55	%	54	%					55	%	54	%
Activity
Capital expenditures	26,865		43,746		16,895		(39	)%	59	%	148,667		62,706		137	%
Acquisitions	788		19,712		1,378						22,011		13,309
Gross wells drilled	6.00		15.00		11.00						44.00		29.00
Net wells drilled	4.00		12.75		7.02						35.56		17.62
Financial results
Sales	94,522		77,238		70,573		22	%	34	%	330,903		252,867		31	%
Royalties	(9,301	)	(6,653	)	(7,390	)	40	%	26	%	(33,258	)	(21,475	)	55	%
Transportation	(4,836	)	(4,485	)	(3,504	)	8	%	38	%	(17,368	)	(15,392	)	13	%
Operating	(22,356	)	(22,071	)	(18,161	)	1	%	23	%	(80,444	)	(71,543	)	12	%
General and administration	(2,540	)	(2,239	)	(2,035	)	13	%	25	%	(9,604	)	(11,826	)	(19	)%
Fund flows from operations	55,489		41,790		39,483		33	%	41	%	190,229		132,631		43	%
Netbacks ($/boe)
Sales	31.21		26.65		33.48		17	%	(7	)%	30.72		26.81		15	%
Royalties	(3.07	)	(2.30	)	(3.51	)	33	%	(13	)%	(3.09	)	(2.28	)	36	%
Transportation	(1.60	)	(1.55	)	(1.66	)	3	%	(4	)%	(1.61	)	(1.63	)	(1	)%
Operating	(7.38	)	(7.62	)	(8.62	)	(3	)%	(14	)%	(7.47	)	(7.59	)	(2	)%
General and administration	(0.84	)	(0.77	)	(0.97	)	9	%	(13	)%	(0.89	)	(1.25	)	(29	)%
Fund flows from operations netback	18.32		14.41		18.72		27	%	(2	)%	17.66		14.06		26	%
Realized prices
Crude oil and condensate ($/bbl)	69.20		57.15		62.13		21	%	11	%	63.41		52.44		21	%
NGLs ($/bbl)	29.18		23.93		18.12		22	%	61	%	25.00		11.75		113	%
Natural gas ($/mmbtu)	1.88		1.84		3.05		2	%	(38	)%	2.34		2.14		9	%
Total ($/boe)	31.21		26.65		33.48		17	%	(7	)%	30.72		26.81		15	%
Reference prices
WTI (US $/bbl)	55.40		48.20		49.29		15	%	12	%	50.95		43.32		18	%
Edmonton Sweet index (US $/bbl)	54.26		45.32		46.18		20	%	17	%	48.49		40.11		21	%
Edmonton Sweet index ($/bbl)	68.98		56.76		61.60		22	%	12	%	62.94		53.17		18	%
AECO ($/mmbtu)	1.69		1.45		3.09		17	%	(45	)%	2.16		2.16		—	%

10

Vermilion Energy Inc. 2017 Annual Report

Production

• Q4 2017 average production increased by 5% from Q3 2017, and 44% year-over-year primarily due to organic production growth in our Mannville condensate-rich gas resource play.

• Mannville production averaged approximately 19,000 boe/d in Q4 2017, representing a 10% increase quarter-over-quarter. Full year 2017 production averaged more than 15,800 boe/d.

• Cardium production averaged approximately 5,400 boe/d in Q4 2017, a decrease of 7% quarter-over-quarter. Full year 2017 production averaged nearly 5,700 boe/d.

• Production from southeast Saskatchewan averaged approximately 2,500 boe/d in Q4 2017, a decrease of 4% quarter-over-quarter.

Activity review

• Vermilion drilled or participated in the drilling of six (4.0 net) wells during Q4 2017. During 2017, Vermilion drilled or participated in the drilling of 44 (35.6 net) wells in Canada

Mannville

– During Q4 2017, we drilled or participated in the drilling of six (4.0 net) wells and brought nine (5.5 net) wells on production.

– We have drilled or participated in the drilling of 24 (17.5 net) wells in 2017. We plan to drill or participate in 17 (13.8 net) wells in 2018.

Cardium

– In 2017, we drilled seven (7.0 net) operated wells.

– In 2018, we plan to drill or participate in five (4.2 net) wells.

Saskatchewan

– In 2017, we drilled 13 (11.1 net) wells.

– In 2018, we plan to drill or participate in 21 (20.5 net) wells, which includes the planned drilling of an additional five (5.0 net) wells associated with our acquisition of a private southeast Saskatchewan and southwest Manitoba light oil producer in Q1 2018.

• On February 15, 2018, Vermilion acquired all of the issued and outstanding shares of a private producer with assets in southeast Saskatchewan and southwest Manitoba. The acquisition is comprised of light oil producing fields near Vermilion's existing operations in southeast Saskatchewan. Total consideration of $90.8 million, which includes both cash paid to the shareholders' of the acquiree and the assumption of the acquiree's long-term debt, was funded through Vermilion's revolving credit facility.

Sales

• The realized price for our crude oil and condensate production in Canada is linked to WTI, and is also subject to market conditions in western Canada. These market conditions can result in fluctuations in the pricing differential to WTI, as reflected by the Edmonton Sweet index price. The realized price of our NGLs in Canada is based on product specific differentials pertaining to trading hubs in the United States. The realized price of our natural gas in Canada is based on the AECO index in Canada.

• Q4 2017 sales per boe increased compared to Q3 2017, driven by higher crude oil and natural gas pricing.

• Sales per boe decreased for the three months ended December 31, 2017 versus the comparable period in the prior year, driven by lower natural gas pricing but partially offset by higher crude oil pricing. For the year ended December 31, 2017, relatively flat natural gas pricing was coupled with higher crude oil pricing, resulting in an increase to sales per boe compared to 2016.

Royalties

• Fluctuations in royalties for all comparable periods were primarily due to the impact of commodity prices on the sliding scale used to determine royalty rates.

Transportation

• Transportation expense relates to the delivery of crude oil and natural gas production to major pipelines where legal title transfers.

• Transportation expense on a per unit basis was consistent versus all comparable periods.

Operating

• In Q4 2017, operating expense on a per unit and dollar basis was consistent as compared to Q3 2017.

• For the three months and year ended December 31, 2017, operating expense on a dollar basis increased versus the comparable periods in the prior year due to higher gas processing costs resulting from higher production volumes. On a per unit basis, operating expense for the three months and year ended December 31, 2017 decreased versus the comparable periods in 2016 due to the impact of spreading fixed costs over higher volumes.

11

Vermilion Energy Inc. 2017 Annual Report

FRANCE BUSINESS UNIT

Overview

• Entered France in 1997 and completed three subsequent acquisitions, including two in 2012.

• Largest oil producer in France, constituting approximately three-quarters of domestic oil production.

• Low base decline producing assets comprised of large conventional oil fields with high working interests located in the Aquitaine and Paris Basins.

• Identified inventory of workover, infill drilling, and secondary recovery opportunities.

Operational and financial review

	Three Months Ended						% change				Year Ended				% change
France business unit ($M except as indicated)	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		Dec 31, 2017		Dec 31, 2016		2017 vs. 2016
Production
Crude oil (bbls/d)	11,215		10,918		11,220		3	%	—	%	11,084		11,896		(7	)%
Natural gas (mmcf/d)	—		—		0.38		—	%	(100	)%	—		0.44		(100	)%
Total (boe/d)	11,215		10,918		11,283		3	%	(1	)%	11,085		11,970		(7	)%
Sales
Crude oil (bbls/d)	11,397		11,360		12,209		—	%	(7	)%	10,950		12,157		(10	)%
Natural gas (mmcf/d)	—		—		0.38		—	%	(100	)%	—		0.44		(100	)%
Total (boe/d)	11,397		11,360		12,272		—	%	(7	)%	10,950		12,231		(10	)%
Inventory (mbbls)
Opening crude oil inventory	214		254		239						148		243
Crude oil production	1,032		1,004		1,032						4,046		4,354
Crude oil sales	(1,049	)	(1,044	)	(1,123	)					(3,997	)	(4,449	)
Closing crude oil inventory	197		214		148						197		148
Activity
Capital expenditures	20,027		15,756		31,127		27	%	(36	)%	73,381		68,472		7	%
Gross wells drilled	2.00		—		4.00						7.00		4.00
Net wells drilled	2.00		—		4.00						7.00		4.00
Financial results
Sales	78,778		66,100		71,926		19	%	10	%	268,103		246,863		9	%
Royalties	(10,599	)	(6,399	)	(6,692	)	66	%	58	%	(28,565	)	(27,091	)	5	%
Transportation	(4,475	)	(3,434	)	(3,983	)	30	%	12	%	(14,627	)	(14,758	)	(1	)%
Operating	(14,332	)	(13,148	)	(11,482	)	9	%	25	%	(51,002	)	(50,000	)	2	%
General and administration	(4,259	)	(2,543	)	(5,101	)	67	%	(17	)%	(13,585	)	(19,101	)	(29	)%
Other income	—		—		3,822		—	%	(100	)%	—		3,822		(100	)%
Current income taxes	(2,348	)	(1,396	)	(2,867	)	68	%	(18	)%	(10,556	)	(2,867	)	268	%
Fund flows from operations	42,765		39,180		45,623		9	%	(6	)%	149,768		136,868		9	%
Netbacks ($/boe)
Sales	75.13		63.24		63.71		19	%	18	%	67.08		55.15		22	%
Royalties	(10.11	)	(6.12	)	(5.93	)	65	%	70	%	(7.15	)	(6.05	)	18	%
Transportation	(4.27	)	(3.29	)	(3.53	)	30	%	21	%	(3.66	)	(3.30	)	11	%
Operating	(13.67	)	(12.58	)	(10.17	)	9	%	34	%	(12.76	)	(11.17	)	14	%
General and administration	(4.06	)	(2.43	)	(4.52	)	67	%	(10	)%	(3.40	)	(4.27	)	(20	)%
Other income	—		—		3.39		—	%	(100	)%	—		0.85		(100	)%
Current income taxes	(2.24	)	(1.34	)	(2.54	)	67	%	(12	)%	(2.64	)	(0.64	)	313	%
Fund flows from operations netback	40.78		37.48		40.41		9	%	1	%	37.47		30.57		23	%
Realized prices
Crude oil ($/bbl)	75.13		63.24		63.99		19	%	17	%	67.08		55.42		21	%
Natural gas ($/mmbtu)	—		—		1.55		—	%	(100	)%	1.52		1.59		(4	)%
Total ($/boe)	75.13		63.24		63.71		19	%	18	%	67.08		55.15		22	%
Reference prices
Dated Brent (US $/bbl)	61.39		52.08		49.46		18	%	24	%	54.27		43.69		24	%
Dated Brent ($/bbl)	78.05		65.22		65.97		20	%	18	%	70.44		57.92		22	%

12

Vermilion Energy Inc. 2017 Annual Report

Production

• Q4 2017 production increased 3% versus the prior quarter and was relatively consistent with Q4 2016. Full year production decreased by 7% from 2016 due to production declines, well downtime and third party restrictions impacting Vic Bilh gas production. These decreases more than offset new well production and optimization activities.

Activity review

• During Q4 2017, we drilled two (2.0 net) Neocomian wells as we accelerated a portion of our 2018 drilling program into late 2017. We also continued our workover and optimization programs in the Aquitaine and Paris Basins.

• Our 2017 capital activity included the drilling of six (6.0 net) and completion of four (4.0 net) Neocomian wells and one (1.0 net) horizontal sidetrack well in the Vulaines field as well as the completion of four (4.0 net) Champotran wells that were drilled in Q4 2016.

Sales

• Crude oil in France is priced with reference to Dated Brent.

• Q4 2017 sales per boe increased versus Q3 2017, consistent with stronger Dated Brent pricing. This increase in price was combined with relatively consistent sales volumes, resulting in an increase in sales.

• Sales per boe for the three months and year ended December 31, 2017 increased versus the comparable periods in the prior year, consistent with stronger Dated Brent pricing. In dollar terms, the increase in price was partially offset by lower sales volumes.

Royalties

• Royalties in France relate to two components: RCDM (levied on units of production and not subject to changes in commodity prices) and R31 (based on a percentage of sales).

• In December 2017, the French government enacted legislation resulting in increased rates for both RCDM and R31 royalties. The change in RCDM royalties was applied retroactively to January 1, 2017 and the change in R31 royalties takes effect January 1, 2018. As a result of these changes, we expect RCDM royalties in 2018 to be approximately €3.65/bbl (compared to approximately €2.90/bbl prior to the newly enacted legislation) and R31 royalties to represent approximately 7.5% of sales (compared to approximately 3.5% in 2017).

• Royalties as a percentage of sales of 13.5% in Q4 2017 increased as compared to 9.7% in Q3 2017 and 9.3% in Q4 2016 due to the aforementioned revision to RCDM royalties. Q4 2017 royalty expense included the entire impact of the retroactive increase in RCDM to the beginning of 2017.

• Royalties as a percentage of sales for the year ended December 31, 2017 of 10.7% were relatively consistent with 11.0% in 2016 as the impact of the higher per unit RCDM royalty rates were offset by higher realized pricing in the current year.

Transportation

• Transportation expense increased in Q4 2017 compared to Q3 2017 and Q4 2016 due to the impact of a prior period adjustment recorded in the current quarter.

• For the year ended December 31, 2017, transportation expense was relatively consistent with the prior year.

Operating

• Operating expense on a per unit and dollar basis increased in Q4 2017 as compared to Q3 2017 due to the timing of maintenance activity and higher electricity costs due to colder weather.

• For the three months and year ended December 31, 2017, operating expense on a per unit basis increased versus the comparable periods in the prior year due to the impact of spreading fixed costs over lower sales volumes. In dollars, the increase in operating expense in Q4 2017 as compared to Q4 2016 is due to a favourable prior period adjustment recorded in the prior year.

General and administration

• Fluctuations in general and administration expense for all comparable periods were due to the timing of expenditures and allocations from our corporate segment.

Current income taxes

• In France, current income taxes are applied to taxable income, after eligible deductions, at a statutory rate of 34.4%.

• Current income taxes for the year ended December 31, 2017 versus the comparative periods were higher mainly due to higher Dated Brent prices resulting in increased sales.

• On December 21, 2017, the French Parliament approved the Finance Bill for 2018. The Finance Bill for 2018 provides for a progressive decrease of the French corporate income tax rate from 34.43% to 25.825% by 2022, with the first reduction planned for 2019 to 32.02%

13

Vermilion Energy Inc. 2017 Annual Report

NETHERLANDS BUSINESS UNIT

Overview

• Entered the Netherlands in 2004.

• Second largest onshore gas producer (excluding state-owned energy company EBN).

• Interests include 24 onshore licenses and two offshore licenses.

• Licenses include more than 800,000 net acres of land, 95% of which is undeveloped.

Operational and financial review

	Three Months Ended						% change				Year Ended				% change
Netherlands business unit ($M except as indicated)	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		Dec 31, 2017		Dec 31, 2016		2017 vs. 2016
Production and sales
Condensate (bbls/d)	105		74		57		42	%	84	%	90		88		2	%
Natural gas (mmcf/d)	55.66		34.90		41.15		59	%	35	%	40.54		47.82		(15	)%
Total (boe/d)	9,381		5,890		6,915		59	%	36	%	6,847		8,058		(15	)%
Activity
Capital expenditures	12,300		11,590		5,737		6	%	114	%	31,575		23,740		33	%
Acquisitions	(38	)	14		28,259						(24	)	28,259
Gross wells drilled	—		2.00		—						2.00		2.00
Net wells drilled	—		1.02		—						1.02		0.88
Financial results
Sales	40,914		21,258		25,978		92	%	57	%	108,060		100,707		7	%
Royalties	(647	)	(360	)	(294	)	80	%	120	%	(1,722	)	(1,462	)	18	%
Operating	(6,981	)	(4,498	)	(5,660	)	55	%	23	%	(21,212	)	(20,796	)	2	%
General and administration	(546	)	(510	)	(162	)	7	%	237	%	(2,212	)	(1,525	)	45	%
Current income taxes	6,975		(1,983	)	100		N/A		6,875	%	3,331		(6,624	)	N/A
Fund flows from operations	39,715		13,907		19,962		186	%	99	%	86,245		70,300		23	%
Netbacks ($/boe)
Sales	47.41		39.23		40.84		21	%	16	%	43.24		34.15		27	%
Royalties	(0.75	)	(0.66	)	(0.46	)	14	%	63	%	(0.69	)	(0.50	)	38	%
Operating	(8.09	)	(8.30	)	(8.90	)	(3	)%	(9	)%	(8.49	)	(7.05	)	20	%
General and administration	(0.63	)	(0.94	)	(0.26	)	(33	)%	142	%	(0.89	)	(0.52	)	71	%
Current income taxes	8.08		(3.66	)	0.16		N/A		4,950	%	1.33		(2.25	)	N/A
Fund flows from operations netback	46.02		25.67		31.38		79	%	47	%	34.50		23.83		45	%
Realized prices
Condensate ($/bbl)	66.38		52.10		63.18		27	%	5	%	56.90		44.93		27	%
Natural gas ($/mmbtu)	7.87		6.51		6.78		21	%	16	%	7.18		5.67		27	%
Total ($/boe)	47.41		39.23		40.84		21	%	16	%	43.24		34.15		27	%
Reference prices
TTF ($/mmbtu)	8.36		6.93		7.21		21	%	16	%	7.43		6.00		24	%
TTF (€/mmbtu)	5.58		4.71		5.01		18	%	11	%	5.07		4.09		24	%

Production

• Q4 2017 production increased 59% quarter-over-quarter and 36% year-over-year following the receipt of permits to increase production on two key pools, and also due to the impact of a major turnaround at the Garjip processing facility that occurred during Q2 2017. Year-over-year production decreased 15% due to the restriction of production related to permitting delays earlier in 2017.

14

Vermilion Energy Inc. 2017 Annual Report

Activity review

• In Q4 2017, we completed a 315 square kilometre 3D seismic survey in the Akkrum exploration licence and the South Friesland III production licence.

• The test rate from the Eesveen-2 well (60% working interest) drilled in the prior quarter was limited to approximately 10 mmcf/d net during the test period.

Sales

• The price of our natural gas in the Netherlands is based on the TTF index.

• Q4 2017 sales per boe increased versus Q3 2017, consistent with an increase in the TTF reference price.

• Sales per boe for the three months and year ended December 31, 2017 increased versus the comparable periods in the prior year, consistent with increases in the TTF reference price.

Royalties

• In the Netherlands, certain wells are subject to overriding royalties or royalties that take effect only when specified production levels are exceeded. As such, fluctuations in royalty expense in the periods presented primarily relates to the amount of production from those wells subject to overriding and production royalties.

Transportation

• Our production in the Netherlands is not subject to transportation expense as gas is sold at the plant gate.

Operating

• Q4 2017 per unit operating expense decreased slightly versus Q3 2017 and Q4 2016 due to the impact of higher volumes.

• Operating expense on a per unit basis increased compared to 2016 due to the impact of fixed expenditures on lower production volumes.

General and administration

• Fluctuations in general and administration expense for all comparable periods were due to the timing of expenditures and allocations from our corporate segment.

Current income taxes

• In the Netherlands, current income taxes are applied to taxable income, after eligible deductions and a 10% uplift deduction applied to operating expenses, eligible G&A and tax deductions for depletion and asset retirement obligations, at a tax rate of 50%.

• Current income taxes in Q4 2017 and for the year ended December 31, 2017 versus the comparative periods were lower mainly due to an increased tax deduction for future asset retirement obligations resulting from a reduction in applicable discount rate assumptions.

15

Vermilion Energy Inc. 2017 Annual Report

GERMANY BUSINESS UNIT

Overview

• Entered Germany in February 2014.

• Successfully integrated the December 2016 acquisition of operated and non-operated interests in five oil and three gas producing fields from Engie E&P Deutschland GmbH (“Engie Acquisition”). Vermilion has assumed operatorship of six of the eight producing fields, representing our first operated producing properties in Germany.

• Hold a 25% interest in a four partner consortium at Dummersee-Uchte. Associated assets include four gas producing fields spanning 11 production licenses as well as an exploration license in surrounding fields. Total license area comprises 204,000 gross acres, of which 85% is in the exploration license.

• Entered into a farm-in agreement in July 2015 that provides Vermilion with a participating interest in 18 onshore exploration licenses in northwest Germany, comprising approximately 850,000 net undeveloped acres of oil and natural gas rights. Vermilion will operate 11 of the 18 licenses during the exploration phase.

• Awarded Ossenbeck and Weesen licenses (110,000 net acres) in 2015 and Aller license (50,000 net acres) in March 2017 surrounding the operated oil fields acquired in December 2016.

Operational and financial review

	Three Months Ended						% change				Year Ended				% change
Germany business unit ($M except as indicated)	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		Dec 31, 2017		Dec 31, 2016		2017 vs. 2016
Production and sales
Crude oil (bbls/d)	1,148		1,054		—		9	%	100	%	1,060		—		100	%
Natural gas (mmcf/d)	18.19		20.12		14.80		(10	)%	23	%	19.39		14.90		30	%
Total (boe/d)	4,180		4,407		2,467		(5	)%	69	%	4,291		2,483		73	%
Production mix (% of total)
Crude oil	27	%	24	%	—	%					25	%	—	%
Natural gas	73	%	76	%	100	%					75	%	100	%
Activity
Capital expenditures	5,279		3,020		1,694		75	%	212	%	9,531		3,803		151	%
Acquisitions	—		—		48,377						—		48,377
Financial results
Sales	18,898		15,663		8,294		21	%	128	%	68,696		29,049		136	%
Royalties	(1,798	)	(2,261	)	(12	)	(20	)%	14,883	%	(6,655	)	(2,089	)	219	%
Transportation	(1,164	)	(1,603	)	(375	)	(27	)%	210	%	(6,207	)	(2,869	)	116	%
Operating	(6,025	)	(3,477	)	(3,959	)	73	%	52	%	(20,176	)	(12,379	)	63	%
General and administration	(2,080	)	(1,708	)	(1,755	)	22	%	19	%	(7,767	)	(8,314	)	(7	)%
Fund flows from operations	7,831		6,614		2,193		18	%	257	%	27,891		3,398		721	%
Netbacks ($/boe)
Sales	50.22		38.52		36.54		30	%	37	%	44.37		31.97		39	%
Royalties	(4.78	)	(5.56	)	(0.06	)	(14	)%	7,867	%	(4.30	)	(2.30	)	87	%
Transportation	(3.09	)	(3.94	)	(1.65	)	(22	)%	87	%	(4.01	)	(3.16	)	27	%
Operating	(16.01	)	(8.55	)	(17.44	)	87	%	(8	)%	(13.03	)	(13.62	)	(4	)%
General and administration	(5.53	)	(4.20	)	(7.73	)	32	%	(28	)%	(5.02	)	(9.15	)	(45	)%
Fund flows from operations netback	20.81		16.27		9.66		28	%	115	%	18.01		3.74		382	%
Realized prices
Crude oil ($/bbl)	72.58		55.95		—		30	%	100	%	63.91		—		100	%
Natural gas ($/mmbtu)	7.07		5.50		6.09		29	%	16	%	6.38		5.33		20	%
Total ($/boe)	50.22		38.52		36.54		30	%	37	%	44.37		31.97		39	%
Reference prices
Dated Brent (US $/bbl)	61.39		52.08		49.46		18	%	24	%	54.27		43.69		24	%
Dated Brent ($/bbl)	78.05		65.22		65.97		20	%	18	%	70.44		57.92		22	%
TTF ($/mmbtu)	8.36		6.93		7.21		21	%	16	%	7.43		6.00		24	%
TTF (€/mmbtu)	5.58		4.71		5.01		18	%	11	%	5.07		4.09		24	%

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Vermilion Energy Inc. 2017 Annual Report

Production

• Q4 2017 production decreased from the prior quarter due to longer than anticipated downtime on one of our wells in December following a SCADA installation. Fourth quarter and full year 2017 production increased 69% and 73% year-over-year, respectively, due to production additions from the Engie Acquisition that closed December 2016.

Activity review

• 2017 activity focused on workover and optimization opportunities on the assets included in the Engie Acquisition.

• In 2018, we plan to continue permitting and pre-drill activities associated with our first operated well in Germany, Burgmoor Z5 (25% working interest) in the Dümmersee-Uchte area, which we expect to drill in 2019.

Sales

• The price of our natural gas in Germany is based on the TTF index. Crude oil in Germany is priced with reference to Dated Brent.

• Sales per boe increased versus all comparable periods due to the timing of sales and increases in both crude oil and natural gas benchmark prices.

Royalties

• Our production in Germany is subject to state and private royalties on sales after certain eligible deductions.

• Royalties as a percentage of sales of 9.5% in Q4 2017 were lower than 14.4% in Q3 2017 due to the impact of an adjustment recorded in the prior quarter.

• For the three months ended December 31, 2017, royalties as a percentage of sales of 9.5% increased from a negligible amount in Q4 2016 due to the impact of favourable prior period adjustments recorded in Q4 2016. For the year ended December 31, 2017, royalties as a percentage of sales of 9.7% was higher than 7.2% in the prior year due the impact of the prior period adjustment recorded in 2016.

Transportation

• Transportation expense in Germany relates to costs incurred to deliver natural gas from the processing facility to the customer and deliver crude oil to the refinery.

• Q4 2017 per unit transportation expense was relatively consistent with Q3 2017.

• For the three months and year ended December 31, 2017, transportation expense increased on a per unit and dollar basis relative to the comparable periods in the prior year due to the impact of the aforementioned acquisition.

Operating

• Operating expense increased in Q4 2017 versus Q3 2017 due to the impact of a favourable prior period adjustment recorded in the prior quarter.

• For the three months and year ended December 31, 2017, operating expense on a per unit basis decreased slightly versus the comparable periods in 2016 due to the impact of higher volumes.

General and administration

• Fluctuations in general and administration expense for all comparable periods were due to the timing of expenditures and allocations from our corporate segment.

• On a per unit basis, general and administration costs have improved compared to 2016 as a result of our growing production base in Germany.

Current income taxes

• As a result of our tax pools in Germany, we do not expect to incur current income taxes in the German Business Unit in for the foreseeable future.

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Vermilion Energy Inc. 2017 Annual Report

IRELAND BUSINESS UNIT

Overview

• Entered Ireland in 2009.

• Initial investment was an 18.5% non-operating interest in the offshore Corrib gas field located approximately 83 km off the northwest coast of Ireland.

• On July 12, 2017, Vermilion and Canada Pension Plan Investment Board (“CPPIB”) announced a strategic partnership that is expected to result in Vermilion increasing ownership in Corrib to 20% and taking over operatorship upon close of the acquisition which is expected to occur in the first half of 2018.

• The Corrib gas development comprises six offshore wells, offshore and onshore sales and transportation pipeline segments as well as a natural gas processing facility.

• Natural gas began to flow from our Corrib gas project on December 30, 2015 and production volumes reached full plant capacity of approximately 65 mmcf/d (10,900 boe/d), net to Vermilion at the end of Q2 2016.

Operational and financial review

	Three Months Ended						% change				Year Ended				% change
Ireland business unit ($M except as indicated)	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		Dec 31, 2017		Dec 31, 2016		2017 vs. 2016
Production and sales
Natural gas (mmcf/d)	56.23		49.04		62.92		15	%	(11	)%	58.43		50.89		15	%
Total (boe/d)	9,372		8,173		10,486		15	%	(11	)%	9,737		8,482		15	%
Activity
Capital expenditures	327		1,101		1,711		(70	)%	(81	)%	551		9,375		(94	)%
Financial results
Sales	43,793		28,218		42,727		55	%	2	%	153,330		109,156		40	%
Transportation	(1,496	)	(1,252	)	(1,703	)	19	%	(12	)%	(5,205	)	(6,492	)	(20	)%
Operating	(2,977	)	(5,717	)	(5,148	)	(48	)%	(42	)%	(17,596	)	(18,646	)	(6	)%
General and administration	(517	)	(670	)	(1,523	)	(23	)%	(66	)%	(2,320	)	(4,772	)	(51	)%
Fund flows from operations	38,803		20,579		34,353		89	%	13	%	128,209		79,246		62	%
Netbacks ($/boe)
Sales	50.79		37.53		44.29		35	%	15	%	43.14		35.16		23	%
Transportation	(1.74	)	(1.66	)	(1.77	)	5	%	(2	)%	(1.46	)	(2.09	)	(30	)%
Operating	(3.45	)	(7.60	)	(5.34	)	(55	)%	(35	)%	(4.95	)	(6.01	)	(18	)%
General and administration	(0.60	)	(0.89	)	(1.58	)	(33	)%	(62	)%	(0.65	)	(1.54	)	(58	)%
Fund flows from operations netback	45.00		27.38		35.60		64	%	26	%	36.08		25.52		41	%
Reference prices
NBP ($/mmbtu)	8.70		6.78		7.51		28	%	16	%	7.49		6.15		22	%
NBP (€/mmbtu)	5.81		4.61		5.22		26	%	11	%	5.12		4.19		22	%

Production

• Q4 2017 production increased by 15% quarter-over-quarter and decreased by 11% year-over-year. This was due to an extended downtime period following a plant turnaround, which started during Q3 2017 and ended early Q4 2017.

Activity review

• On July 12, 2017 Vermilion and CPPIB announced a strategic partnership in Corrib, whereby CPPIB will acquire Shell E&P Ireland Limited’s 45% interest in Corrib for total cash consideration of €830 million, subject to customary closing adjustments and future contingent value payments based on performance and realized pricing. At closing, Vermilion expects to assume operatorship of Corrib. In addition to operatorship, CPPIB plans to transfer a 1.5% working interest to Vermilion for €19.4 million ($28.4 million), before closing adjustments. Vermilion’s incremental 1.5% ownership of Corrib would represent approximately 850 boe/d (100% gas) based on current production expectations for Corrib. The acquisition has an effective date of January 1, 2017 and is anticipated to close in the first half of 2018.

Sales

• The price of our natural gas in Ireland is based on the NBP index.

• Q4 2017 sales per boe increased versus Q3 2017, consistent with an increase in the NBP reference price.

• For the three months and year ended December 31, 2017, sales per boe increased relatively to the comparable periods in the prior year, consistent with increases in the NBP reference price.

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Vermilion Energy Inc. 2017 Annual Report

Royalties

• Our production in Ireland is not subject to royalties.

Transportation

• Transportation expense in Ireland relates to payments under a ship-or-pay agreement related to the Corrib project.

• Q4 2017 transportation expense was consistent with Q3 2017.

• Transportation expense for the three months and year ended December 31, 2017 decreased relative to the comparable periods in the prior year due to a decrease in the current year ship-or-pay obligation.

Operating

• Operating expense on a per unit and dollar basis decreased versus all comparable periods due to the timing of maintenance work.

General and administration

• Fluctuations in general and administration expense for all comparable periods were due to the timing of expenditures and allocations from our corporate segment.

Current income taxes

• Given the significant level of investment in Corrib and the resulting tax pools, we do not expect to incur current income taxes in the Ireland Business Unit for the foreseeable future.

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Vermilion Energy Inc. 2017 Annual Report

AUSTRALIA BUSINESS UNIT

Overview

• Entered Australia in 2005.

• Hold a 100% operated working interest in the Wandoo field, located approximately 80 km offshore on the northwest shelf of Australia.

• Production is operated from two off-shore platforms, and originates from 18 well bores and five lateral sidetrack wells.

• Wells that utilize horizontal legs (ranging in length from 500 to 3,000 plus metres) are located 600 metres below the seabed in approximately 55 metres of water depth.

Operational and financial review

	Three Months Ended						% change				Year Ended				% change
Australia business unit ($M except as indicated)	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		Dec 31, 2017		Dec 31, 2016		2017 vs. 2016
Production
Crude oil (bbls/d)	4,993		5,473		6,388		(9	)%	(22	)%	5,770		6,304		(8	)%
Sales
Crude oil (bbls/d)	4,707		5,722		6,038		(18	)%	(22	)%	5,717		6,197		(8	)%
Inventory (mbbls)
Opening crude oil inventory	108		131		82						115		75
Crude oil production	459		503		588						2,106		2,307
Crude oil sales	(433	)	(526	)	(555	)					(2,087	)	(2,267	)
Closing crude oil inventory	134		108		115						134		115
Activity
Capital expenditures	7,192		10,154		5,236		(29	)%	37	%	29,942		59,910		(50	)%
Gross wells drilled	—		—		—						—		2.00
Net wells drilled	—		—		—						—		2.00
Financial results
Sales	36,086		35,257		38,352		2	%	(6	)%	154,391		136,835		13	%
Operating	(12,172	)	(12,292	)	(14,905	)	(1	)%	(18	)%	(50,139	)	(47,507	)	6	%
General and administration	(3,193	)	(1,675	)	(1,998	)	91	%	60	%	(8,194	)	(6,400	)	28	%
Current income taxes	(5,327	)	(4,538	)	(4,271	)	17	%	25	%	(24,355	)	(9,090	)	168	%
Fund flows from operations	15,394		16,752		17,178		(8	)%	(10	)%	71,703		73,838		(3	)%
Netbacks ($/boe)
Sales	83.32		66.97		69.05		24	%	21	%	73.99		60.33		23	%
Operating	(28.11	)	(23.35	)	(26.83	)	20	%	5	%	(24.03	)	(20.95	)	15	%
General and administration	(7.37	)	(3.18	)	(3.60	)	132	%	105	%	(3.93	)	(2.82	)	39	%
PRRT	(8.25	)	(8.25	)	(2.82	)	—	%	193	%	(9.50	)	(0.69	)	1,277	%
Corporate income taxes	(4.05	)	(0.37	)	(4.87	)	995	%	(17	)%	(2.17	)	(3.32	)	(35	)%
Fund flows from operations netback	35.54		31.82		30.93		12	%	15	%	34.36		32.55		6	%
Reference prices
Dated Brent (US $/bbl)	61.39		52.08		49.46		18	%	24	%	54.27		43.69		24	%
Dated Brent ($/bbl)	78.05		65.22		65.97		20	%	18	%	70.44		57.92		22	%

Production

• Q4 2017 production decreased 9% quarter-over-quarter and 22% year-over-year, primarily due to planned maintenance during the quarter, which resulted in eight days of downtime. Full year 2017 production decreased 8% versus 2016.

• Production volumes are managed within corporate targets while meeting customer demands and the requirements of long-term supply agreements.

• We continue to plan for long-term annual production levels of approximately 6,000 bbls/d.

Activity review

• 2017 efforts were largely focused on facility enhancements, including work relating to platform life extension, and debottlenecking fluid handling capabilities on Wandoo B.

• Following our successful 2015 and 2016 drilling campaigns, we do not expect to drill any additional wells in Australia until 2019.

• 2018 activity will be focused on adding value through asset optimization and targeted proactive maintenance, in addition to preparing for our 2019 planned drilling campaign.

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Vermilion Energy Inc. 2017 Annual Report

Sales

• Crude oil in Australia is priced with reference to Dated Brent.

• Q4 2017 sales per boe increased versus Q3 2017 and Q4 2016, consistent with an increase in the Dated Brent reference price. This increase in price was offset by lower sales volumes in the current quarter versus the comparable quarters, resulting in relatively consistent sales.

• Sales per boe for the year ended December 31, 2017 increased versus the prior year, consistent with an increase in the Dated Brent reference price. This increase in price was partially offset by lower sales volumes in the current year.

Royalties and transportation

• Our production in Australia is not subject to royalties or transportation expense as crude oil is sold directly at the Wandoo B platform.

Operating

• Operating expense on a per unit basis increased in Q4 2017 versus Q3 2017 due to lower sales volumes. On a dollar basis, operating expense was relatively consistent.

• For the three months and year ended December 31, 2017, operating expense on a per unit basis increased versus the comparable periods in the prior year due to lower sales volumes in the current periods. On a dollar basis, fluctuations in operating expense versus the comparable periods were due to the timing of maintenance work.

General and administration

• Fluctuations in general and administration expense for all comparable periods are primarily due to the timing of expenditures and allocations from our corporate segment. The increase in Q4 2017 over the prior quarter and prior year was primarily due to additional costs associated with the evaluation of a discontinued acquisition opportunity.

Current income taxes

• In Australia, current income taxes include both PRRT and corporate income taxes. PRRT is a profit based tax applied at a rate of 40% on sales less eligible expenditures, including operating expenses and capital expenditures. Corporate income taxes are applied at a rate of 30% on taxable income after eligible deductions, which include PRRT paid.

• Current income taxes in Q4 2017 and for the year ended December 31, 2017 versus the comparative periods were higher mainly due to increased pre-tax fund flows from operations.

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Vermilion Energy Inc. 2017 Annual Report

UNITED STATES BUSINESS UNIT

Overview

• Entered the United States in September 2014.

• Interests include approximately 97,200 net acres of land (97% undeveloped) in the Powder River Basin of northeastern Wyoming.

• Tight oil development targeting the Turner Sand at a depth of approximately 1,500 metres.

Operational and financial review

	Three Months Ended						% change				Year Ended				% change
United States business unit ($M except as indicated)	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Q4/17 vs. Q3/17		Q4/17 vs. Q4/16		Dec 31, 2017		Dec 31, 2016		2017 vs. 2016
Production and sales
Crude oil (bbls/d)	667		880		362		(24	)%	84	%	666		393		69	%
NGLs (bbls/d)	43		56		23		(23	)%	87	%	50		29		72	%
Natural gas (mmcf/d)	0.29		0.64		0.18		(55	)%	61	%	0.39		0.21		86	%
Total (boe/d)	758		1,043		414		(27	)%	83	%	781		457		71	%
Activity
Capital expenditures	1,018		1,362		4,037		(25	)%	(75	)%	19,074		13,539		41	%
Acquisitions	91		1,250		377						3,403		5,935
Gross wells drilled	—		—		1.00						3.00		1.00
Net wells drilled	—		—		1.00						3.00		1.00
Financial results
Sales	4,350		4,771		2,041		(9	)%	113	%	15,355		7,314		110	%
Royalties	(1,196	)	(1,321	)	(611	)	(9	)%	96	%	(4,276	)	(2,167	)	97	%
Transportation	(15	)	(26	)	—		(42	)%	100	%	(41	)	—		100	%
Operating	(397	)	(629	)	(301	)	(37	)%	32	%	(1,698	)	(1,314	)	29	%
General and administration	(1,274	)	(935	)	(877	)	36	%	45	%	(4,341	)	(3,624	)	20	%
Fund flows from operations	1,468		1,860		252		(21	)%	483	%	4,999		209		2,292	%
Netbacks ($/boe)
Sales	62.40		49.72		53.58		26	%	16	%	53.84		43.70		23	%
Royalties	(17.16	)	(13.77	)	(16.05	)	25	%	7	%	(14.99	)	(12.95	)	16	%
Transportation	(0.21	)	(0.27	)	—		(22	)%	100	%	(0.14	)	—		100	%
Operating	(5.70	)	(6.56	)	(7.91	)	(13	)%	(28	)%	(5.95	)	(7.85	)	(24	)%
General and administration	(18.28	)	(9.74	)	(23.02	)	88	%	(21	)%	(15.22	)	(21.65	)	(30	)%
Fund flows from operations netback	21.05		19.38		6.60		9	%	219	%	17.54		1.25		1,303	%
Realized prices
Crude oil ($/bbl)	67.15		55.74		59.09		20	%	14	%	60.07		49.86		20	%
NGLs ($/bbl)	41.25		26.35		19.48		57	%	112	%	25.11		7.38		240	%
Natural gas ($/mmbtu)	2.48		2.07		1.93		20	%	28	%	2.05		0.85		141	%
Total ($/boe)	62.40		49.72		53.58		26	%	16	%	53.84		43.70		23	%
Reference prices
WTI (US $/bbl)	55.40		48.20		49.29		15	%	12	%	50.95		43.32		18	%
WTI ($/bbl)	70.43		60.37		65.75		17	%	7	%	66.13		57.42		15	%
Henry Hub (US $/mmbtu)	2.93		3.00		2.98		(2	)%	(2	)%	3.11		2.46		26	%
Henry Hub ($/mmbtu)	3.73		3.76		3.98		(1	)%	(6	)%	4.04		3.27		24	%

Production

• Q4 2017 production decreased 27% from the prior quarter as a result of depleted flush production from the three (3.0 net) wells placed on production during Q2 2017 and due to a force majeure event at a third-party gas plant. Fourth quarter production increased 83% year-over-year as a result of the 2017 drilling program.

• Full year 2017 production increased 71% from 2016 as a result of our 2017 drilling program.

Activity

• 2017 activity was focused on drilling three (3.0 net) horizontal wells targeting the light oil bearing Turner Sand in the Powder River Basin. The wells were completed late in the first quarter and into the second quarter with fracs ranging from 31 to 40 stages per well.

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Vermilion Energy Inc. 2017 Annual Report

Sales

• The price of crude oil in the United States is directly linked to WTI, but is also subject to market conditions in the United States.

• Q4 2017 sales per boe increased versus Q3 2017, consistent with an increase in the WTI reference price.

• For the three months and year ended December 31, 2017, sales per boe increased relative to the comparable periods in the prior year, consistent with stronger crude oil pricing.

Royalties

• Our production in the United States is subject to federal and private royalties, severance tax, and ad valorem tax.

• Royalties (including severance and ad valorem taxes) as a percentage of sales are approximately 28%, and remained relatively consistent in Q4 2017 as compared to Q3 2017.

• For the three months and year ended December 31, 2017, royalties as a percentage of sales decreased to approximately 28% from approximately 30% in the comparable periods in the prior year. This decrease is a result of our purchase of overriding royalty interests (ranging from 0.83% to 5.00%) for US$1.5 million, effective January 1, 2017. On a go-forward basis, we expect royalties as a percentage of sales to remain at approximately 28%.

Transportation

• Transportation expense in the United States relates to the delivery of crude oil and condensate production to major pipelines where legal title transfers.

• Fluctuations in transportation expense for all periods presented relate to fluctuations in production subject to trucking costs.

Operating

• Operating expense on a per unit and dollar basis decreased in Q4 2017 as compared to Q3 2017 due to the timing of maintenance work.

• For the three months and year ended December 31, 2017, operating expense on a per unit basis decreased versus the comparable periods in the prior year due to the impact of higher volumes. In dollars, the increase in operating expense in both periods was attributable to higher production.

General and administration

• Fluctuations in general and administration expense for all comparable periods were due to the timing of expenditures and allocations from our corporate segment.

Current income taxes

• As a result of our tax pools in the United States, we do not expect to incur current income taxes in the US Business Unit for the foreseeable future.

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Vermilion Energy Inc. 2017 Annual Report

CORPORATE

Overview

• Our Corporate segment includes costs related to our global hedging program, financing expenses, and general and administration expenses that are primarily incurred in Canada and are not directly related to the operations of our business units. Expenditures relating to our activities in Central and Eastern Europe are also included in the Corporate segment.

Financial review

	Three Months Ended						Year Ended
CORPORATE ($M)	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Activity
Capital expenditures	1,295		4,653		445		7,728		863
Acquisitions	2,207		—		322		2,247		2,644
Financial results
General and administration (expense) recovery	(1,532	)	(1,834	)	1,987		(6,350	)	2,733
Current income taxes	(542	)	480		(370	)	(527	)	(1,097	)
Interest expense	(13,710	)	(13,400	)	(14,410	)	(57,313	)	(56,957	)
Realized (loss) gain on derivatives	(7,493	)	8,723		1,920		4,721		65,376
Realized foreign exchange gain (loss)	2,899		(4,110	)	1,291		2,316		4,041
Realized other income	166		214		120		674		205
Fund flows from operations	(20,212	)	(9,927	)	(9,462	)	(56,479	)	14,301

General and administration

• Fluctuations in general and administration costs for the three months and year ended December 31, 2017 versus all comparable periods were due to allocations to the various business unit segments.

Current income taxes

• Taxes in our corporate segment relate to holding companies that pay current taxes in foreign jurisdictions.

Interest expense

• The decrease in interest expense for the three months ended December 31, 2017 versus the comparable period in the prior year was due to lower drawings on the revolving credit facility.

• The increase in interest expense for the year ended December 31, 2017 versus the prior year was due to the issuance of the senior unsecured notes in Q1 2017, which bear interest at a higher fixed rate compared to the variable rates under the revolving credit facility. The impact of the higher fixed rates was partially offset by lower drawings on the revolving credit facility and lower standby fees from a voluntary reduction of the available credit on the revolving credit facility from $2.0 billion to $1.4 billion.

Realized gain or loss on derivatives

• The realized gain on derivatives for the year ended December 31, 2017 related primarily to amounts received on European natural gas hedges.

• A listing of derivative positions as at December 31, 2017 is included in “Supplemental Table 2” of this MD&A.

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Vermilion Energy Inc. 2017 Annual Report

FINANCIAL PERFORMANCE REVIEW

								Year Ended
($M except per share)								Dec 31, 2017		Dec 31, 2016		Dec 31, 2015
Total assets								3,974,965		4,087,184		4,209,220
Long-term debt								1,270,330		1,362,192		1,162,998
Petroleum and natural gas sales								1,098,838		882,791		939,586
Net earnings (loss)								62,258		(160,051	)	(217,302	)
Net earnings (loss) per share
Basic								0.52		(1.38	)	(1.98	)
Diluted								0.51		(1.38	)	(1.98	)
Cash dividends ($/share)								2.58		2.58		2.58
	Three Months Ended
($M except per share)	Dec 31, 2017	Sep 30, 2017		Jun 30, 2017	Mar 31, 2017	Dec 31, 2016		Sep 30, 2016		Jun 30, 2016		Mar 31, 2016
Petroleum and natural gas sales	317,341	248,505		271,391	261,601	259,891		232,660		212,855		177,385
Net (loss) earnings	8,645	(39,191	)	48,264	44,540	(4,032	)	(14,475	)	(55,696	)	(85,848	)
Net (loss) earnings per share
Basic	0.07	(0.32	)	0.40	0.38	(0.03	)	(0.12	)	(0.48	)	(0.76	)
Diluted	0.07	(0.32	)	0.39	0.37	(0.03	)	(0.12	)	(0.48	)	(0.76	)

The following table shows a reconciliation from fund flows from operations to net earnings (loss):

	Three Months Ended						Year Ended
	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Fund flows from operations	181,253		130,755		149,582		602,565		510,791
Equity based compensation	(16,087	)	(12,858	)	(19,489	)	(61,579	)	(69,235	)
Unrealized loss on derivative instruments	(80,012	)	(24,198	)	(74,943	)	(1,062	)	(137,993	)
Unrealized foreign exchange gain (loss)	40,660		(3,016	)	(2,457	)	71,742		(792	)
Unrealized other expense	(197	)	(200	)	—		(637	)	(131	)
Accretion	(6,991	)	(6,850	)	(6,308	)	(26,971	)	(24,783	)
Depletion and depreciation	(129,179	)	(120,826	)	(126,855	)	(491,683	)	(528,002	)
Deferred tax	19,198		(1,998	)	54,437		(30,117	)	82,855
Gain on acquisition	—		—		22,001		—		22,001
Impairments	—		—		—		—		(14,762	)
Net earnings (loss)	8,645		(39,191	)	(4,032	)	62,258		(160,051	)

Fluctuations in net income from period-to-period are caused by changes in both cash and non-cash based income and charges. Cash based items are reflected in fund flows from operations. Non-cash items include: equity based compensation expense, unrealized gains and losses on derivative instruments, unrealized foreign exchange gains and losses, accretion, depletion and depreciation expense, and deferred taxes. In addition, non-cash items may also include gains resulting from business combinations or charges resulting from impairment or impairment reversals.

Equity based compensation

Equity based compensation expense relates primarily to non-cash compensation expense attributable to long-term incentives granted to directors, officers, and employees under the Vermilion Incentive Plan (“VIP”).

Equity based compensation expense increased in Q4 2017 compared to Q3 2017 due to a revision of performance estimates. For the three months and year ended December 31, 2017, equity based compensation decreased versus the comparable periods in 2016 due to a reduction in the value of awards outstanding under the VIP.

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Unrealized gain or loss on derivative instruments

Unrealized gain or loss on derivative instruments arise as a result of changes in future commodity price forecasts. As Vermilion uses derivative instruments to manage the commodity price exposure of our future crude oil and natural gas production, we will normally recognize unrealized gains on derivative instruments when future commodity price forecasts decline and vice-versa.

For the three months ended December 31, 2017, we recognized an unrealized loss on derivative instruments of $80.0 million. This loss primarily related to crude oil and European natural gas derivative instruments for 2018 and 2019, partially offset by unrealized gains on our North American natural gas derivative instruments for 2018.

For the year ended December 31, 2017, we recognized an unrealized loss on derivative instruments of $1.1 million. This unrealized loss largely related to crude oil derivative instruments for 2018, as well as the aforementioned offsetting cross-currency interest rate swap entered into in Q4 2017. This loss was almost entirely offset by the reversal of the net derivative liability position of $69.7 million on our balance sheet as at December 31, 2016, as well as unrealized gains on North American natural gas derivative instruments for 2018.

Unrealized foreign exchange gain or loss

As a result of Vermilion’s international operations, Vermilion has monetary assets and liabilities denominated in currencies other than the Canadian dollar. These monetary assets and liabilities include cash, receivables, payables, long-term debt, derivative instruments and intercompany loans. These monetary assets primarily relate to Euro denominated intercompany loans from Vermilion Energy Inc. to our international subsidiaries. These monetary liabilities primarily relate to our US$300.0 million senior unsecured notes.

Unrealized foreign exchange gains and losses result from translating these monetary assets and liabilities from their underlying currency to the Canadian dollar. Unrealized foreign exchange primarily results from the translation of Euro denominated intercompany loans and US dollar denominated long-term debt. As such, an appreciation in the Euro against the Canadian dollar will result in an unrealized foreign exchange gain while an appreciation in the US dollar against the Canadian dollar will result in an unrealized foreign exchange loss (and vice-versa).

For the three months ended December 31, 2017, the impact of the Canadian dollar weakening against the Euro was more significant than the impact of the Canadian dollar weakening against the US dollar, resulting in an unrealized foreign exchange gain. For the year ended December 31, 2017, the Canadian dollar weakened against the Euro and strengthened against the US dollar, resulting in an unrealized foreign exchange gain.

As at December 31, 2017, a $0.01 appreciation of the Euro against the Canadian dollar would result in a $4.6 million increase to net earnings. In contrast, a $0.01 appreciation of the US dollar against the Canadian dollar would result in a $2.2 million decrease to net earnings.

Accretion

Accretion expense is recognized to update the present value of the asset retirement obligation balance. Accretion expense was relatively consistent with all comparative periods.

Depletion and depreciation

Depletion and depreciation expense is recognized to allocate the cost of capital assets over the useful life of the respective assets. Depletion and depreciation expense per unit of production is determined for each depletion unit (which are groups of assets within a specific production area that have similar economic lives) by dividing the sum of the net book value of capital assets and future development costs by total proved plus probable reserves.

Fluctuations in depletion and depreciation expense are primarily the result of changes in produced crude oil and natural gas volumes and changes in depletion and depreciation per unit. Fluctuations in depletion and depreciation per unit are the result of changes in reserves, future development costs, and relative production mix.

Depletion and depreciation on a per boe basis for Q4 2017 of $19.33 was consistent with $19.28 in Q3 2017. For the three months and year ended December 31, 2017, depletion and depreciation on a per boe basis of $19.33 and $19.87 were lower than $22.42 and $22.65 in the respective comparable periods in 2016 due to reduced depletion and depreciation rates as a result of increased reserves and lower estimated future development costs.

Deferred tax

On our balance sheet, deferred tax assets arise when the tax basis of an asset exceeds its accounting basis (known as a deductible temporary difference). Conversely, deferred tax liabilities arise when the tax basis of an asset is less than its accounting basis (known as a taxable temporary difference). Deferred tax assets are recognized only to the extent that it is probable that there are future taxable profits against which the deductible temporary difference can be utilized. Deferred tax assets and liabilities are measured at the enacted or substantively enacted tax rate that is expected to apply when the asset is realized or the liability is settled.

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As such, fluctuations in deferred tax expenses and recoveries primarily arise as a result of: changes in the accounting basis of an asset or liability without a corresponding tax basis change (e.g. when derivative assets and liabilities are marked-to-market or when accounting depletion differs from tax depletion), changes in available tax losses (e.g. if they are utilized to offset taxable income), changes in estimated future taxable profits resulting in a de-recognition or re-recognition of deferred tax assets, and changes in enacted or substantively enacted tax rates.

In Q4 2017, a $19.2 million deferred tax recovery primarily resulted from the impact of the adoption by the French Parliament of the Finance Law for 2018. The Finance Law for 2018 included progressive reductions of the corporate tax rate from 34.43% to 25.825% by 2022 and thus reduced the effective tax rate applied against Vermilion's taxable temporary differences in France. For the year ended December 31, 2017, the deferred tax expense of $30.1 million related to the de-recognition of a portion of non-expiring tax loss pools in Ireland as there is uncertainty as to the Company’s ability to fully utilize such losses based on forecasted commodity prices in effect as at December 31, 2017, partially offset by the aforementioned change in effective tax rates in France.

TAXES

Current income tax rates

Vermilion pays corporate income taxes in France, the Netherlands, and Australia. In addition, Vermilion pays Petroleum Resource Rent Tax ("PRRT") in Australia. PRRT is a profit based tax applied at a rate of 40% on sales less operating expenses, capital expenditures, and other eligible expenditures. PRRT is deductible in the calculation of taxable income in Australia.

For 2017 and 2016, taxable income was subject to corporate income tax at the following rates:

Jurisdiction	2017		2016
Canada	27.0	%	27.0	%
France	34.4	%	34.4	%
Netherlands (1)	50.0	%	50.0	%
Germany	26.3	%	24.2	%
Ireland	25.0	%	25.0	%
Australia	30.0	%	30.0	%
United States	35.0	%	35.0	%

⁽¹⁾ In the Netherlands, an additional 10% uplift deduction is allowed against taxable income that is applied to operating expenses, eligible general and administration expenses and tax deductions for depletion and abandonment retirement obligations.

Tax legislation changes

On December 22, 2017, the Tax Cuts and Jobs Act was signed into law in the United States. The Tax Cuts and Jobs Act reduces the U.S. federal corporate income tax rate to 21%.

On December 21, 2017, the French Parliament approved the Finance Bill for 2018. The Finance Bill for 2018 provides for a progressive decrease of the French corporate income tax rate from 34.43% to 25.825% by 2022, with the first reduction planned for 2019 to 32.02%.

Tax pools

As at December 31, 2017, we had the following tax pools:

($M)	Oil & Gas Assets		Tax Losses		Other	Total
Canada	914,071	(1)	517,687	(4)	20,113	1,451,871
France	332,435	(2)	10,688	(5)	—	343,123
Netherlands	78,417	(3)	7,078	(4)	—	85,495
Germany	184,549	(3)	88,712	(6)	18,878	292,139
Ireland	—		1,327,743	(4)	—	1,327,743
Australia	266,208	(1)	—		—	266,208
United States	37,022	(1)	43,305	(4)	1,783	82,110
Total	1,812,702		1,995,213		40,774	3,848,689

(1) Deduction calculated using various declining balance rates

(2) Deduction calculated using a combination of straight-line over the assets life and unit of production method

(3) Deduction calculated using a unit of production method

(4) Tax losses can be carried forward at 100% against taxable income

(5) Tax losses carried forward are available to offset the first €1 million of taxable income and 50% of taxable profits in excess each taxation year

(6) Tax losses carried forward are available to offset the first €1 million of taxable income and 60% of taxable profits in excess each taxation year

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FINANCIAL POSITION REVIEW

Balance sheet strategy

We believe that our balance sheet supports our defined growth initiatives and our focus is on managing and maintaining a conservative balance sheet. To ensure that our balance sheet continues to support our defined growth initiatives, we regularly review whether forecasted fund flows from operations is sufficient to finance planned capital expenditures, dividends, and abandonment and reclamation expenditures. To the extent that forecasted fund flows from operations is not expected to be sufficient to fulfill such expenditures, we will evaluate our ability to finance any shortfall with debt (including borrowing using the unutilized capacity of our existing revolving credit facility), issue equity, or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.

To ensure that we maintain a conservative balance sheet, we monitor the ratio of net debt to fund flows from operations. As at December 31, 2017 our ratio of net debt to trailing fund flows from operations was 2.3 (2016 - 2.8) and was 1.9 based on annualized Q4 2017 fund flows from operations.

We remain focused on maintaining and strengthening our balance sheet by aligning our exploration and development capital budget with forecasted fund flows from operations to target a payout ratio (a non-GAAP financial measure) of at or less than 100%. We continually monitor for changes in forecasted fund flows from operations as a result of changes to forward commodity prices and as appropriate we will make adjustments to our exploration and development capital plans. As a result of our focus on this payout ratio target, we intend for the ratio of net debt to fund flows from operations to trend towards 1.5 over time.

Net debt

Net debt is reconciled to long-term debt, as follows:

	As at
($M)	Dec 31, 2017		Dec 31, 2016
Long-term debt	1,270,330		1,362,192
Current liabilities	363,306		290,862
Current assets	(261,846	)	(225,906	)
Net debt	1,371,790		1,427,148
Ratio of net debt to fund flows from operations	2.3		2.8
Ratio of net debt to fourth quarter annualized fund flows from operations	1.9		2.4

As at December 31, 2017, long term debt decreased to $1.27 billion (December 31, 2016 - $1.36 billion) as fund flows from operations generated in excess of expenditures was used to reduce debt. This decrease in long-term debt decreased net debt from $1.43 billion at December 31, 2016 to $1.37 billion at December 31, 2017. Stronger commodity prices and higher production versus the prior period increased fund flows from operations, resulting in the ratio of net debt to fund flows from operations decreasing from 2.8 to 2.3.

Long term debt

The balances recognized on our balance sheet are as follows:

	As at
($M)	Dec 31, 2017	Dec 31, 2016
Revolving credit facility	899,595	1,362,192
Senior unsecured notes	370,735	—
Long-term debt	1,270,330	1,362,192

Revolving Credit Facility

As at December 31, 2017, Vermilion had in place a bank revolving credit facility maturing May 31, 2021 with the following outstanding positions:

	As at
($M)	Dec 31, 2017		Dec 31, 2016
Total facility amount	1,400,000		2,000,000
Amount drawn	(899,595	)	(1,362,192	)
Letters of credit outstanding	(7,400	)	(20,100	)
Unutilized capacity	493,005		617,708

In April of 2017, we negotiated an extension of our revolving credit facility with our syndicate of lenders from May 31, 2019 to May 31, 2021.  Further, as a result of projected liquidity requirements and the proceeds from our senior unsecured notes issuance, we elected to reduce the total facility amount from $2.0 billion to $1.4 billion. 

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As at December 31, 2017, the revolving credit facility was subject to the following covenants: 

			As at
Financial covenant	Limit		Dec 31, 2017		Dec 31, 2016
Consolidated total debt to consolidated EBITDA	4.0		1.87		2.36
Consolidated total senior debt to consolidated EBITDA	3.5		1.3		2.32
Consolidated total senior debt to total capitalization	55	%	32	%	46	%

Our covenants include financial measures defined within our revolving credit facility agreement that are not defined under IFRS. These financial measures are defined by our revolving credit facility agreement as follows:

• Consolidated total debt: Includes all amounts classified as “Long-term debt”, and “Finance lease obligation” on our balance sheet.

• Consolidated total senior debt: Defined as consolidated total debt excluding unsecured and subordinated debt.

• Consolidated EBITDA: Defined as consolidated net earnings before interest, income taxes, depreciation, accretion and certain other non-cash items.

• Total capitalization: Includes all amounts on our balance sheet classified as “Shareholders’ equity” plus consolidated total debt as defined above.

Senior Unsecured Notes

On March 13, 2017, Vermilion issued US$300 million of senior unsecured notes at par. The notes bear interest at a rate of 5.625% per annum, paid semi-annually on March 15 and September 15, and mature on March 15, 2025. As direct senior unsecured obligations of Vermilion, the notes rank equally in right of payment with existing and future senior indebtedness of the Company.

The senior unsecured notes were recognized at amortized cost and include the transaction costs directly related to the issuance.

Vermilion may, at its option, redeem the senior unsecured notes prior to maturity as follows:

• Prior to March 15, 2020, Vermilion may redeem up to 35% of the original principal amount of the senior unsecured notes with the proceeds of certain equity offerings by the Company at a redemption price of 105.625% of the principal amount, plus any accrued and unpaid interest to but excluding the applicable redemption date.

• Prior to March 15, 2020, Vermilion may redeem some or all of the senior unsecured notes at a price equal to 100% of the principal amount of the senior unsecured notes, plus a “make-whole” premium and any accrued and unpaid interest.

• On or after March 15, 2020, Vermilion may redeem some or all of the senior unsecured notes at the redemption prices set forth in the following table, plus any accrued and unpaid interest.

Year	Redemption price
2020	104.219	%
2021	102.813	%
2022	101.406	%
2023 and thereafter	100.000	%

Shareholders’ capital

During the year ended December 31, 2017 we maintained monthly dividends at $0.215 per share. In total, dividends declared in 2017 were $311.4 million.

The following table outlines our dividend payment history:

Date	Monthly dividend per unit or share
January 2003 to December 2007		$0.170
January 2008 to December 2012		$0.190
January 2013 to December 31, 2013		$0.200
January 2014 to Present		$0.215

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Our policy with respect to dividends is to be conservative and maintain a low ratio of dividends to fund flows from operations. During low commodity price cycles, we will initially maintain dividends and allow the ratio to rise. Should low commodity price cycles remain for an extended period of time, we will evaluate the necessity of changing the level of dividends, taking into consideration capital development requirements, debt levels, and acquisition opportunities.

Although we expect to be able to maintain our current dividend, fund flows from operations may not be sufficient to fund cash dividends, capital expenditures, and asset retirement obligations. We will evaluate our ability to finance any shortfall with debt, issuances of equity, or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.

The following table reconciles the change in shareholders’ capital:

Shareholders’ Capital	Number of Shares ('000s)		Amount ($M)
Balance as at December 31, 2016		118,263	2,452,722
Shares issued for the Dividend Reinvestment Plan		2,429	110,493
Vesting of equity based awards		1,060	69,743
Equity based compensation		197	9,270
Share-settled dividends on vested equity based awards		170	8,478
Balance as at December 31, 2017		122,119	2,650,706

As at December 31, 2017, there were approximately 1.7 million VIP awards outstanding. As at February 28, 2018, there were approximately 122.4 million common shares issued and outstanding.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

As at December 31, 2017, we had the following contractual obligations and commitments: 

($M)	Less than 1 year	1 - 3 years	3 - 5 years	After 5 years	Total
Long-term debt	21,295	42,339	947,534	429,274	1,440,442
Operating lease obligations	10,716	19,129	10,303	28	40,176
Finance lease obligations	6,680	10,207	4,665	3,351	24,903
Processing and transportation agreements	26,002	34,343	10,960	35,153	106,458
Purchase obligations	21,105	16,649	1,664	—	39,418
Drilling and service agreements	10,255	46,129	20,132	5,110	81,626
Total contractual obligations and commitments	96,053	168,796	995,258	472,916	1,733,023

ASSET RETIREMENT OBLIGATIONS

As at December 31, 2017, asset retirement obligations were $517.2 million compared to $525.0 million as at December 31, 2016.

The decrease in asset retirement obligations is largely attributable to an extension to the estimated timing of abandonment spending. This decrease was partially offset by accretion expense and a weakening of the Canadian dollar against the Euro.

Vermilion has estimated the asset retirement obligations based on a total undiscounted future liability of $1.6 billion (2016 - $1.4 billion). These payments are expected to be made between 2018 and 2067, with the majority of spending occurring between 2027 and 2034 ($0.6 billion) and between 2063 and 2067 ($0.4 billion). Inflation rates used in determining the cash flow estimates were between 0.6% and 2.2% (2016 - between 0.5% and 2.2%). Vermilion calculated the present value of the obligations using a credit-adjusted risk-free rate, calculated using a credit spread of 3.8% (2016 - 3.8%) added to risk-free rates based on long-term, risk-free government bonds.

A 0.5% increase/decrease in the discount rate applied to asset retirement obligations would decrease/increase asset retirement obligations by approximately $40.0 million. A one year increase/decrease in the expected timing of abandonment spend would decrease/increase asset retirement obligations by approximately $20.0 million.

RISKS AND UNCERTAINTIES

Crude oil and natural gas exploration, production, acquisition and marketing operations involve a number of risks and uncertainties including financial risks and uncertainties. These include fluctuations in commodity prices, exchange rates and interest rates as well as uncertainties associated with reserve and resource volumes, sales volumes and government regulatory and income tax regime changes. These and other related risks and uncertainties are discussed in additional detail below.

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Vermilion Energy Inc. 2017 Annual Report

Commodity prices

Our operational results and financial condition are dependent on the prices received for crude oil and natural gas production. Crude oil and natural gas prices have fluctuated significantly during recent years and are determined by supply and demand factors, including weather and general economic conditions as well as conditions in other crude oil and natural gas producing regions.

Exchange rates

Much of our revenue stream is priced in US dollars and as such an increase in the strength of the Canadian dollar relative to the US dollar may result in the receipt of fewer Canadian dollars with respect to our production. In addition, we incur expenses and capital costs in US dollars, Euros and Australian dollars and accordingly, the Canadian dollar equivalent of these expenditures as reported in our financial results is impacted by the prevailing exchange rates at the time the transaction occurs. We monitor risks associated with exchange rates and, when appropriate, use derivative financial instruments to manage our exposure to these risks.

Production and sales volumes

The operation of crude oil and natural gas wells and facilities involves a number of operating and natural hazards which may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damage to us and possible liability to third parties. We maintain liability insurance, where available, in amounts consistent with industry standards. Business interruption insurance may also be purchased for selected operations, to the extent that such insurance is commercially viable. We may become liable for damages arising from such events against which we cannot insure or against which we may elect not to insure because of high premium costs or other reasons. Costs incurred to repair such damage or pay such liabilities may materially impact our financial results.

Continuing production from a property, and to some extent the marketing of produced volumes, is largely dependent upon the ability of the operator of the property. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat our claim to certain properties. Such circumstances could negatively affect our financial results.

An increase in operating costs or a decline in our production level could have an adverse effect on our financial results. The level of production may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond our control. A significant decline in production could result in materially lower revenues.

Interest rates

An increase in interest rates could result in a significant increase in the amount we pay to service debt.

Reserve volumes

Our reserve volumes and related reserve values support the carrying value of our crude oil and natural gas assets on the consolidated balance sheets and provide the basis to calculate the depletion of those assets. There are numerous uncertainties inherent in estimating quantities of reserves and future net revenues to be derived therefrom, including many factors beyond our control. These include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of crude oil, NGLs and natural gas, operating expenses, well abandonment and salvage values, royalties and any government levies that may be imposed over the producing life of the reserves. These assumptions were based on estimated prices in use at the date the evaluation was prepared, and many of these assumptions are subject to change and are beyond our control. Actual production and income derived therefrom will vary from these evaluations, and such variations could be material.

Asset retirement obligations

Our asset retirement obligations are based on environmental regulations and estimates of future costs and the timing of expenditures. Changes in environmental regulations, the estimated costs associated with reclamation activities and the related timing may impact our financial position and results of operations.

Government regulation and income tax regime

Our operations are governed by many levels of government, including municipal, state, provincial and federal governments. We are subject to laws and regulations regarding environment, health and safety issues, lease interests, taxes and royalties, among others. Failure to comply with the applicable laws can result in significant increases in costs, penalties and even losses of operating licences. The regulatory process involved in each of the countries in which we operate is not uniform and regulatory regimes vary as to complexity, timeliness of access to, and response from, regulatory bodies and other matters specific to each jurisdiction. If regulatory approvals or permits are delayed or not obtained, there can also be delays or abandonment of projects and decreases in production and increases in costs, potentially resulting in us being unable to fully execute our strategy. Governments may also amend or create new legislation and regulatory bodies may also amend regulations or impose additional requirements which could result in increased capital, operating and compliance costs.

There can be no assurance that income tax laws and government incentive programs relating to the crude oil and natural gas industry in Canada and the foreign jurisdictions in which we operate, will not be changed in a manner which adversely affects the results of our operations.

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Vermilion Energy Inc. 2017 Annual Report

A change in the royalty regime resulting in an increase in royalties would reduce our net earnings and could make future capital expenditures or our operations uneconomic and could, in the event of a material increase in royalties, make it more difficult to service and repay outstanding debt. Any material increase in royalties would also significantly reduce the value of the associated assets.

FINANCIAL RISK MANAGEMENT

To mitigate the aforementioned risks whenever possible, we seek to hire personnel with experience in specific areas. In addition, we provide continued training and development to staff to further develop their skills. When appropriate, we use third party consultants with relevant experience to augment our internal capabilities with respect to certain risks.

We consider our commodity price risk management program as a form of insurance that protects our cash flow and rate of return. The primary objective of the risk management program is to support our dividends and our internal capital development program. The level of commodity price risk management that occurs is dependent on the amount of debt that is carried. When debt levels are higher, we will be more active in protecting our cash flow stream through our commodity price risk management strategy.

When executing our commodity price risk management programs, we use derivative financial instruments encompassing over-the-counter financial structures as well as fixed and collar structures to economically hedge a part of our physical crude oil and natural gas production. We have strict controls and guidelines in relation to these activities and contract principally with counterparties that have investment grade credit ratings.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, income and expenses, as well as disclosures of any possible contingencies. These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made. As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on our consolidated financial statements or financial performance. Estimates are reviewed by management on an ongoing basis, and as a result, certain estimates may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction in which we operate, the critical accounting estimates may affect one or more jurisdictions.

The following discussion outlines what management believes to be the most critical accounting policies involving the use of estimates and assumptions.

• Asset retirement obligations: Asset retirement obligations are based on judgments regarding regulatory requirements, estimates of future costs, and the expected timing of expenditures. The carrying balance of asset retirement obligations and accretion expense may differ due to changes in: laws and regulations, technology, the expected timing of expenditures, and market conditions affecting the discount rate applied.

• Determination of CGUs: CGU determination is subject to management’s judgment of the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets. The factors used by Vermilion to determine CGUs vary by jurisdiction due to their unique operating and geographic conditions. In general, Vermilion will assess the following factors: geographic proximity of the assets within a group to one another, geographic proximity of the group of assets to other groups of assets, homogeneity of the production from the group of assets and the sharing of infrastructure used to process and/or transport production. The composition of CGUs can directly impact the calculated recoverable amount of a CGU and the recorded impairment loss or recovery.

• Assessment of impairments or recovery of previous impairments: The calculation of the recoverable amount of a CGU is based on market factors and estimates of reserves and resources. Reserve and resource estimates are based on: engineering data, estimated future commodity prices, expected future rates of production, and assumptions regarding the timing and amount of future expenditures. Changes in these judgments, estimates and assumptions can directly impact the calculated recoverable amount of a CGU and the recorded impairment loss or recovery.

• Income Taxes: Tax interpretations, regulations, and legislation in the various jurisdictions in which Vermilion and its subsidiaries operate are subject to change and interpretation. Changes in laws and interpretations can affect the timing of the reversal of temporary tax differences, the tax rates in effect when such differences reverse and Vermilion’s ability to use tax losses and other tax pools in the future. The Company’s income tax filings are subject to audit by taxation authorities in numerous jurisdictions and the results of such audits may increase or decrease the tax liability. The determination of tax amounts recognized in the consolidated financial statements are based on management’s assessment of the tax positions, which includes consideration of their technical merits, communications with tax authorities and management’s view of the most likely outcome.

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OFF BALANCE SHEET ARRANGEMENTS

We have certain lease agreements that are entered into in the normal course of operations, including operating leases for which no asset or liability value has been assigned to the consolidated balance sheet as at December 31, 2017.

We have not entered into any guarantee or off balance sheet arrangements that would materially impact our financial position or results of operations.

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

2018 Accounting Standards

On January 1, 2018, Vermilion will adopt IFRS 9 "Financial Instruments" and IFRS 15 "Revenue from Contracts with Customers".

IFRS 9 includes a new classification and measurement approach for financial assets and a forward-looking 'expected credit loss' model. Vermilion expects that there will be no material impact as a result of adopting IFRS 9. These changes are discussed in greater detail below:

• New classification and measurement approach for financial assets: IFRS 9 contains three classifications for financial assets - measured at amortized cost, fair value through other comprehensive income, and fair value through profit or loss. Vermilion's held for trading financial instruments will be classified as fair value through profit or loss while Vermilion's loans and receivables will be classified as measured at amortized cost. The new classification requirements are not expected to result in a change in the measured amounts of these financial instruments.

• Forward-looking 'expected credit loss' model: IFRS 9 includes a lifetime expected credit loss model that applies to Vermilion's accounts receivable. Based on the Company's actual credit loss experience and creditworthiness of Vermilion's customers and joint operations partners, the impact of adopting this credit loss model is not expected to be material.

IFRS 15 establishes a comprehensive framework for determining whether, how much, and when revenue from contracts with customers is recognized. Vermilion's revenue consists of the sale of petroleum and natural gas to customers at specified delivery points with pricing determined based on benchmark pricing plus or minus applicable offsets. Based on the Company's historic and outstanding contracts with customers, Vermilion anticipates that there will be no changes to the timing, measurement, or presentation of revenue upon adoption of IFRS 15. However, there will be additional disclosure requirements necessary to comply with IFRS 15. This additional disclosure will primarily relate to the disclosure of the disaggregation of revenue by commodity, information which is currently available within Vermilion's Management's Discussion and Analysis.

2019 Accounting Standard

Vermilion is required to adopt IFRS 16 "Leases" by January 1, 2019. IFRS 16 requires lessees to recognize a lease obligation and right-of-use asset for the majority of leases. On adoption, non-current assets, current liabilities, and non-current liabilities on Vermilion's consolidated balance sheet will increase. Interest expense will be recognized on the lease obligation and lease payments will be applied against the lease obligation. This is expected to result in a decrease to both operating expense and general and administration expense, and an increase to fund flows from operations. The quantitative impact of the adoption of IFRS 16 is currently being evaluated.

HEALTH, SAFETY AND ENVIRONMENT

We are committed to ensuring we conduct our activities in a manner that will protect the health and safety of our employees, contractors, and the public.  Our health, safety, and environment (“HSE”) vision is to fully integrate health, safety, and environment into our business, where our culture is recognized as a model by industry and stakeholders, resulting in a safe and healthy workplace. Our mantra is HSE: Everywhere. Everyday. Everyone.

We maintain health, safety and environmental practices and procedures in compliance with or exceeding regulatory requirements and industry standards. All of our personnel are expected to work safely and in accordance with established regulations and procedures, and we seek to keep our people safe and to reduce impacts to land, water and air. During 2017 we:

• Maintained clear priorities around 5 key focus areas of HSE Culture, Communication and Knowledge Management, Technical Safety Management, Incident Prevention and Operational Stewardship & Sustainability;

• Continued comprehensive investigations of all our incidents and near misses to ensure root causes were identified and corrective actions effectively implemented;

• Rolled out “Vermilion High 5”, an individual safety awareness initiative aimed at keeping front line workers safe;

• Conducted a company wide review of contractor management, field supervision selection and onboarding, management of new and inexperienced workers, work procedures around mobile equipment;

• Further developed and validated critical procedures and implemented fit-for-purpose training and competency programs;

• Implemented a comprehensive HSE integration plan for Vermilion’s new and emerging operations;

• Reported our CO₂e emissions to the CDP and have been recognized as a Climate Leadership level (A-) performer. We are one of only 18 Energy Sector companies globally to receive a leadership score (Top 4%).

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Vermilion Energy Inc. 2017 Annual Report

• Completed and published our Corporate Sustainability Report with emphasis on improving energy efficiency, greenhouse gas emissions reduction and water efficiency optimization;

• Managed our waste products by reducing, recycling and recovering;

• Reduced long-term environmental liabilities through decommissioning, abandoning and reclaiming well leases and facilities;

• Further refined and expanded our enterprise wide corporate risk register;

• Expanded a robust organization-wide HSE leadership training program to improve hazard identification and risk reduction;

• Maintained focus on our recently developed risk mitigation program around our top fatal risks and energy type exposures;

• Continued the development of a robust hazard identification and risk mitigation program specific to environmentally sensitive areas;

• Continued the development of our Corporate Process Safety Management System with emphasis on Process Hazards Analysis;

• Further progressed our Asset Integrity Management System;

• Performed auditing, management inspections and workforce observations to measure compliance and identify potential hazards and apply risk reduction measures;

• Developed, communicated and measured against leading and lagging HSE key performance indicators; and

• Continued risk management efforts in addition to detailed emergency-response planning.

We are a member of several organizations concerned with environment, health and safety, including numerous regional co-operatives and synergy groups.  In the area of stakeholder relations, we work to build long-term relationships with environmental stakeholders and communities.

SUSTAINABILITY

As a responsible oil and gas producer, we consistently seek to deliver long-term shareholder value by operating in an economically, environmentally and socially sustainable manner that is recognized as a model in our industry.

Vermilion understands our stakeholders' expectations that we deliver strong financial results in a responsible and ethical way. We strive to operate in a manner that protects the health and safety of our staff and communities, provides responsible stewardship over the environment, and treats staff, contractors, partners and suppliers respectfully and fairly. Reflecting these priorities, we believe we are playing a meaningful role in the energy transition that is unfolding globally, within the universal context of the United Nations Sustainable Development Goals. These Global Goals provide an important call to action for sustainable, inclusive growth that supports an end to poverty, protection of the planet, and peace and prosperity for all people.

Our sustainability performance demonstrates our contribution to long-term economic growth, and the way we have shown that delivering shareholder value can go hand-in-hand with delivering sustainability. We began reporting on sustainability, or corporate social responsibility, in August 2014, using the comprehensive option within the Global Reporting Initiative’s G4 reporting framework. We continue to report on this basis annually, as it provides an opportunity to share how we identify our economic, environmental and social impacts, integrate their associated opportunities and risks into our business strategies, and chart our progress.

In December 2015, we further prioritized sustainability by implementing Integrated Sustainability as one of six strategic objectives for our global business. We believe that the integration of sustainability principles into our business is not only the right thing to do, it also increases shareholder returns, enhances our business development opportunities and reduces long-term risks to our business model. We defined our strategic objective as Integrated Sustainability because we believe sustainability impacts every business unit, department and employee in the company - and, in turn, they impact our sustainability. In keeping with this approach, our Board of Directors provides oversight of Vermilion’s sustainability programs, with individual committees offering insight and guidance on specific economic, environmental, social and governance factors.

To support our sustainability strategy, Vermilion regularly communicates with its stakeholders, and we continually monitor trends and best practices in stakeholder engagement. As a result, we align expectations for economic success with the elements of our sustainability commitments, leading us to prioritize our objectives as follows:

• the safety and health of our staff and those involved directly or indirectly in our operations;

• our responsibility to protect the environment. We follow the Precautionary Principle introduced in 1992 by the United Nations "Rio Declaration on Environment and Development" by using environmental risk as part of our development decision criteria, and by continually seeking improved environmental performance in our operations; and

• economic success through a focus on operational excellence across our business, which includes technical and process excellence, efficiency, expertise and stakeholder relations.

For more information about how we manage sustainability, including climate-related risks, please see our detailed Sustainability Report online.

Vermilion’s sustainability performance and reporting have earned consistently strong recognition from external stakeholders:

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Vermilion Energy Inc. 2017 Annual Report

Accomplishments:

• In 2017, Vermilion was named to the CDP (formerly Carbon Disclosure Project) Climate Leadership Level rating of (A-). We were the only Canadian Energy Sector company, one of only two in North America, and 18 globally to achieve a Leadership Level score this year. As context, only 9% of 6,020 companies achieved an 'A or A-' grade for performance in 2017.

• Vermilion was one of only 193 companies globally to achieve CDP Climate "A" List recognition in 2016 and the only North American energy company on the list. Across all sectors, only three Canadian companies, including Vermilion, were awarded a position on 2016's Climate "A" List. Vermilion was one of only five oil and gas companies in the world to be named to the Climate "A" List.

• Vermilion has earned recognition on the Corporate Knights Future 40 Responsible Corporate Leaders in Canada listing every year since the list’s inception in 2014; in 2017, we ranked 13^th, and were the highest rated oil and gas company on the list.

• Between 2016 and 2017, Vermilion's MSCI ESG (environment, social and governance) rating increased from BBB to A, and our score on MSCI's Governance Metrics Report ranks Vermilion at 7.7/10 top decile performance globally.

• The Montreal-based Finance and Sustainability Initiative has selected Vermilion as the winner of the FSI Competition for Best Sustainability Report in the Non-Renewable Resources-Oil and Gas category for 2018.

CORPORATE GOVERNANCE

We are committed to a high standard of corporate governance practices, a dedication that begins at the Board level and extends throughout the Company. We believe good corporate governance is in the best interest of our shareholders, and that successful companies are those that deliver growth and a competitive return along with a commitment to the environment, to the communities where they operate and to their employees.

We comply with the objectives and guidelines relating to corporate governance adopted by the Canadian Securities Administrators and the Toronto Stock Exchange. In addition, the Board monitors and considers the implementation of corporate governance standards proposed by various regulatory and non-regulatory authorities in Canada. A discussion of corporate governance policies is included each year in our proxy materials for our annual general meeting of shareholders, copies of which are available on SEDAR (www.sedar.com).

As a Canadian reporting issuer with securities listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange (“NYSE”), Vermilion Energy Inc. (“Vermilion”) is required to comply with all applicable Canadian requirements adopted by the Canadian Securities Administrators and the TSX, and applicable rules for foreign private issuers adopted by the U.S. Securities and Exchange Commission which give effect to the provisions of the Sarbanes-Oxley Act of 2002.

Our corporate governance practices also incorporate many “best practices” derived from those required to be followed by US domestic companies under the NYSE listing standards. We are required by Section 303A.11 of the NYSE Listed Company Manual to identify any significant ways in which our corporate governance practices differ from those required to be followed by US domestic companies under NYSE listing standards. We believe that there are no such significant differences in our corporate governance practices, except as follows:

• Shareholder Approval of Equity Compensation Plans. Section 303A.8 of the NYSE Listed Company Manual requires shareholder approval of all “equity compensation plans” and material revisions to those plans. The definition of “equity compensation plans” covers plans that provide for the delivery of newly issued securities, and also plans which rely on securities reacquired on the market by the issuing company for the purpose of redistribution to employees and directors. The TSX rules provide that equity compensation plans and material amendments thereto require shareholder approval only if they involve newly issued securities and the amendments are not otherwise addressed in the plan’s amendment procedures. In addition, the TSX rules require that every three years after institution, all unallocated options, rights or other entitlements under equity compensation plans which does not have a fixed maximum aggregate of securities issuable must be approved by shareholders. Vermilion follows the TSX rules with respect to shareholder approval of equity compensation plans and material revisions to those plans.

DISCLOSURE CONTROLS AND PROCEDURES

Our officers have established and maintained disclosure controls and procedures and evaluated the effectiveness of these controls in conjunction with our filings.

As of December 31, 2017, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded and certified that our disclosure controls and procedures are effective.

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Vermilion Energy Inc. 2017 Annual Report

INTERNAL CONTROL OVER FINANCIAL REPORTING

A company's internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

The Chief Executive Officer and the Chief Financial Officer of Vermilion have assessed the effectiveness of Vermilion’s internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. The assessment was based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Chief Executive Officer and the Chief Financial Officer of Vermilion have concluded that Vermilion’s internal control over financial reporting was effective as of December 31, 2017. The effectiveness of Vermilion’s internal control over financial reporting as of December 31, 2017 has been audited by Deloitte LLP, as reflected in their report included in the 2017 audited annual financial statements filed with the US Securities and Exchange Commission. No changes were made to Vermilion’s internal control over financial reporting during the year ended December 31, 2017, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

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Vermilion Energy Inc. 2017 Annual Report

Supplemental Table 1: Netbacks

The following table includes financial statement information on a per unit basis by business unit. Natural gas sales volumes have been converted on a basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.

	Three Months Ended Dec 31, 2017						Year Ended Dec 31, 2017						Three Months Ended Dec 31, 2016		Year Ended Dec 31, 2016
	Crude Oil, Condensate & NGLs		Natural Gas		Total		Crude Oil, Condensate & NGLs		Natural Gas		Total		Total		Total
	$/bbl		$/mcf		$/boe		$/bbl		$/mcf		$/boe		$/boe		$/boe
Canada
Sales	55.17		1.88		31.21		51.36		2.34		30.72		33.48		26.81
Royalties	(6.26	)	(0.07	)	(3.07	)	(6.21	)	(0.09	)	(3.09	)	(3.51	)	(2.28	)
Transportation	(2.40	)	(0.15	)	(1.60	)	(2.25	)	(0.18	)	(1.61	)	(1.66	)	(1.63	)
Operating	(7.65	)	(1.19	)	(7.38	)	(7.85	)	(1.19	)	(7.47	)	(8.62	)	(7.59	)
Operating netback	38.86		0.47		19.16		35.05		0.88		18.55		19.69		15.31
General and administration					(0.84	)					(0.89	)	(0.97	)	(1.25	)
Fund flows from operations netback					18.32						17.66		18.72		14.06
France
Sales	75.13		—		75.13		67.08		1.52		67.08		63.71		55.15
Royalties	(10.11	)	—		(10.11	)	(7.15	)	(2.30	)	(7.15	)	(5.93	)	(6.05	)
Transportation	(4.27	)	—		(4.27	)	(3.66	)	—		(3.66	)	(3.53	)	(3.30	)
Operating	(13.67	)	—		(13.67	)	(12.76	)	—		(12.76	)	(10.17	)	(11.17	)
Operating netback	47.08		—		47.08		43.51		(0.78	)	43.51		44.08		34.63
General and administration					(4.06	)					(3.40	)	(4.52	)	(4.27	)
Other income					—						—		3.39		0.85
Current income taxes					(2.24	)					(2.64	)	(2.54	)	(0.64	)
Fund flows from operations netback					40.78						37.47		40.41		30.57
Netherlands
Sales	66.38		7.87		47.41		56.90		7.18		43.24		40.84		34.15
Royalties	—		(0.13	)	(0.75	)	—		(0.12	)	(0.69	)	(0.46	)	(0.50	)
Operating	—		(1.36	)	(8.09	)	—		(1.43	)	(8.49	)	(8.90	)	(7.05	)
Operating netback	66.38		6.38		38.57		56.90		5.63		34.06		31.48		26.60
General and administration					(0.63	)					(0.89	)	(0.26	)	(0.52	)
Current income taxes					8.08						1.33		0.16		(2.25	)
Fund flows from operations netback					46.02						34.50		31.38		23.83
Germany
Sales	72.58		7.07		50.22		63.91		6.38		44.37		36.54		31.97
Royalties	(1.72	)	(0.97	)	(4.78	)	(1.70	)	(0.85	)	(4.30	)	(0.06	)	(2.30	)
Transportation	(5.86	)	(0.35	)	(3.09	)	(8.00	)	(0.46	)	(4.01	)	(1.65	)	(3.16	)
Operating	(30.31	)	(1.84	)	(16.01	)	(32.30	)	(1.17	)	(13.03	)	(17.44	)	(13.62	)
Operating netback	34.69		3.91		26.34		21.91		3.90		23.03		17.39		12.89
General and administration					(5.53	)					(5.02	)	(7.73	)	(9.15	)
Fund flows from operations netback					20.81						18.01		9.66		3.74
Ireland
Sales	—		8.47		50.79		—		7.19		43.14		44.29		35.16
Transportation	—		(0.29	)	(1.74	)	—		(0.24	)	(1.46	)	(1.77	)	(2.09	)
Operating	—		(0.58	)	(3.45	)	—		(0.83	)	(4.95	)	(5.34	)	(6.01	)
Operating netback	—		7.60		45.60		—		6.12		36.73		37.18		27.06
General and administration					(0.60	)					(0.65	)	(1.58	)	(1.54	)
Fund flows from operations netback					45.00						36.08		35.60		25.52

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Vermilion Energy Inc. 2017 Annual Report

	Three Months Ended Dec 31, 2017						Year Ended Dec 31, 2017						Three Months Ended Dec 31, 2016		Year Ended Dec 31, 2016
	Crude Oil, Condensate & NGLs		Natural Gas		Total		Crude Oil, Condensate & NGLs		Natural Gas		Total		Total		Total
	$/bbl		$/mcf		$/boe		$/bbl		$/mcf		$/boe		$/boe		$/boe
Australia
Sales	83.32		—		83.32		73.99		—		73.99		69.05		60.33
Operating	(28.11	)	—		(28.11	)	(24.03	)	—		(24.03	)	(26.83	)	(20.95	)
PRRT (1)	(8.25	)	—		(8.25	)	(9.50	)	—		(9.50	)	(2.82	)	(0.69	)
Operating netback	46.96		—		46.96		40.46		—		40.46		39.40		38.69
General and administration					(7.37	)					(3.93	)	(3.60	)	(2.82	)
Corporate income taxes					(4.05	)					(2.17	)	(4.87	)	(3.32	)
Fund flows from operations netback					35.54						34.36		30.93		32.55
United States
Sales	65.58		2.48		62.40		57.64		2.05		53.84		53.58		43.70
Royalties	(17.96	)	(0.88	)	(17.16	)	(15.93	)	(0.80	)	(14.99	)	(16.05	)	(12.95	)
Transportation	(0.22	)	—		(0.21	)	(0.16	)	—		(0.14	)	—		—
Operating	(6.08	)	—		(5.70	)	(6.50	)	—		(5.95	)	(7.91	)	(7.85	)
Operating netback	41.32		1.60		39.33		35.05		1.25		32.76		29.62		22.90
General and administration					(18.28	)					(15.22	)	(23.02	)	(21.65	)
Fund flows from operations netback					21.05						17.54		6.60		1.25
Total Company
Sales	66.93		5.23		47.49		61.44		4.91		44.41		45.93		37.88
Realized hedging gain	(0.88	)	(0.22	)	(1.12	)	0.50		(0.01	)	0.19		0.34		2.81
Royalties	(6.78	)	(0.14	)	(3.52	)	(5.47	)	(0.14	)	(3.01	)	(2.65	)	(2.33	)
Transportation	(2.76	)	(0.17	)	(1.79	)	(2.46	)	(0.19	)	(1.76	)	(1.69	)	(1.70	)
Operating	(13.33	)	(1.13	)	(9.76	)	(13.19	)	(1.13	)	(9.79	)	(10.54	)	(9.53	)
PRRT (1)	(1.18	)	—		(0.53	)	(1.71	)	—		(0.80	)	(0.28	)	(0.07	)
Operating netback	42.00		3.57		30.77		39.11		3.44		29.24		31.11		27.06
General and administration					(2.39	)					(2.20	)	(2.03	)	(2.27	)
Interest expense					(2.05	)					(2.32	)	(2.55	)	(2.44	)
Realized foreign exchange gain (loss)					0.43						0.09		0.23		0.17
Other income					0.02						0.03		0.70		0.17
Corporate income taxes (1)					0.35						(0.50	)	(1.03	)	(0.78	)
Fund flows from operations netback					27.13						24.34		26.43		21.91

⁽¹⁾  Vermilion considers Australian PRRT to be an operating item and, accordingly, has included PRRT in the calculation of operating netbacks. Current income taxes presented above excludes PRRT.

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Vermilion Energy Inc. 2017 Annual Report

Supplemental Table 2: Hedges

The prices in these tables may represent the weighted averages for several contracts. The weighted average price for the portfolio of options listed below may not have the same payoff profile as the individual contracts. As such, the presentation of the weighted average prices is purely for indicative purposes.

The following tables outline Vermilion’s outstanding risk management positions as at December 31, 2017: 

				Bought Put Volume	Weighted Average Bought Put	Sold Call Volume	Weighted Average Sold Call	Sold Put Volume	Weighted Average Sold Put	Swap Volume	Weighted Average Swap		Additional Swap Volume
Crude Oil	Period	Exercise date (1)	Currency	(bbl/d)	Price / bbl	(bbl/d)	Price / bbl	(bbl/d)	Price / bbl	(bbl/d)	Price / bbl		(bbld) (2)
Dated Brent
Swap	Jan 2018 - Dec 2018		CAD	—	—	—	—	—	—	500	76.25		—
3-Way Collar	Jul 2017 - Jun 2018		USD	2,000	55.00	2,000	64.06	2,000	45.00	—	—		—
3-Way Collar	Jul 2017 - Dec 2018		USD	2,000	48.89	2,000	55.00	2,000	42.50	—	—		—
3-Way Collar	Oct 2017 - Dec 2018		USD	2,000	50.50	2,000	55.75	2,000	43.00	—	—		—
3-Way Collar	Dec 2017 - Mar 2018		USD	500	57.50	500	62.50	500	52.50	—	—		—
3-Way Collar	Jan 2018 - Jun 2018		USD	1,000	53.58	1,000	59.50	1,000	46.25	—	—		—
Collar	Jan 2018 - Dec 2018		USD	1,000	50.00	1,000	57.50	—	—	—	—		—
Swap	Jan 2018 - Mar 2018		USD	—	—	—	—	—	—	750	67.22		—
Swap	Jan 2018 - Dec 2018		USD	—	—	—	—	—	—	1,000	55.00		—
Swaption	Apr 2018 - Mar 2019	Jan 31, 2018	USD	—	—	—	—	—	—	500	60.00		—
Swaption	Apr 2018 - Mar 2019	Mar 30, 2018	USD	—	—	—	—	—	—	750	64.33		—
WTI
Swap	Jan 2018 - Jan 2018		CAD	—	—	—	—	—	—	1,000	75.50		—
3-Way Collar	Jan 2018 - Jun 2018		USD	500	48.50	500	56.00	500	42.50	—	—		—
Collar	Jan 2018 - Dec 2018		USD	500	50.00	500	55.00	—	—	—	—		—
Swap	Jan 2018 - Jun 2018		USD	—	—	—	—	—	—	500	54.00		—
Swap	Jan 2018 - Dec 2018		USD	—	—	—	—	—	—	1,000	54.00		—
Swaption	Apr 2018 - Mar 2019	Jan 31, 2018	USD	—	—	—	—	—	—	250	54.00		—
				Bought Put Volume	Weighted Average Bought	Sold Call Volume	Weighted Average Sold	Sold Put Volume	Weighted Average Sold	Swap Volume	Weighted Average Swap		Additional Swap Volume
North American Gas	Period	Exercise date (1)	Currency	(mmbtu/d)	Put Price / mmbtu	(mmbtu/d)	Call Price / mmbtu	(mmbtu/d)	Put Price / mmbtu	(mmbtu/d)	Price / mmbtu		(mmbtu/d) (2)
AECO
Swap	Jan 2018 - Dec 2018		CAD	—	—	—	—	—	—	9,478	2.80		—
AECO Basis (AECO less NYMEX HH)
Swap	Oct 2017 - Dec 2018		USD	—	—	—	—	—	—	10,000	(1.03	)	—
Swap	Jan 2018 - Dec 2018		USD	—	—	—	—	—	—	20,000	(0.95	)	—
Swap	Jan 2019 - Jun 2020		USD	—	—	—	—	—	—	2,500	(0.93	)	—
NYMEX HH
3-Way Collar	Oct 2017 - Dec 2018		USD	10,000	3.11	10,000	3.40	10,000	2.40	—	—		—
3-Way Collar	Jan 2018 - Dec 2018		USD	10,000	3.06	10,000	3.40	10,000	2.40	—	—		—
Swap	Apr 2018 - Dec 2018		USD	—	—	—	—	—	—	10,000	3.10		—

⁽¹⁾ The sold swaption instrument allows the counterparty, at the specified date, to enter into a derivative instrument contract with Vermilion at the above detailed terms.

⁽²⁾ On the last business day of each month, the counterparty has the option to increase the contracted volumes for the following month.

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Vermilion Energy Inc. 2017 Annual Report

				Bought Put Volume	Weighted Average Bought	Sold Call Volume	Weighted Average Sold	Sold Put Volume			Weighted Average Sold	Swap Volume	Weighted Average Swap	Additional Swap Volume
European Gas	Period	Exercise date (1)	Currency	(mmbtu/d)	Put Price / mmbtu	(mmbtu/d)	Call Price / mmbtu	(mmbtu/d)			Put Price /mmbtu	(mmbtu/d)	Price / mmbtu	(mmbtu/d) (2)
NBP
3-Way Collar	Apr 2018 - Sep 2018		EUR	4,913	4.73	4,913	5.42	4,913			3.52	—	—	—
3-Way Collar	Jan 2019 - Dec 2019		EUR	14,740	4.82	14,740	5.52	14,740			3.74	—	—	—
3-Way Collar	Jan 2019 - Dec 2020		EUR	7,370	4.96	7,370	5.76	7,370			3.74	—	—	—
3-Way Collar	Jan 2020 - Dec 2020		EUR	14,740	4.85	14,740	5.63	14,740			3.88	—	—	—
Swap	Jan 2018 - Jan 2018		EUR	—	—	—	—	—			—	4,913	6.80	—
Call	Oct 2018 - Mar 2019		EUR	—	—	2,457	6.42	—			—	—	—	—
Put	Apr 2018 - Sep 2018		EUR	—	—	—	—	2,457			4.98	—	—	—
Collar	Jan 2018 - Dec 2018		GBP	2,500	3.15	2,500	3.82	—			—	—	—	—
Swap	Apr 2017 - Mar 2018		GBP	—	—	—	—	—			—	5,300	4.20	—
Swap	Jan 2018 - Dec 2018		GBP	—	—	—	—	—			—	2,500	4.04	5,000
NBP Basis (NBP less NYMEX HH)
Collar	Jan 2018 - Dec 2018		USD	2,500	1.85	2,500	4.00	—			—	—	—	—
Collar	Jan 2019 - Sep 2020		USD	7,500	2.07	7,500	4.00	—			—	—	—	—
TTF
3-Way Collar	Oct 2017 - Dec 2019		EUR	7,370	4.59	7,370	5.42	7,370			2.93	—	—	—
3-Way Collar	Jan 2018 - Dec 2018		EUR	12,284	4.75	12,284	5.48	12,284			3.25	—	—	—
3-Way Collar	Jan 2018 - Dec 2019		EUR	3,685	4.74	3,685	5.52	3,685			3.13	—	—	—
3-Way Collar	Jan 2019 - Dec 2019		EUR	9,827	4.92	9,827	5.48	9,827			3.66	—	—	—
Collar	Jul 2016 - Mar 2018		EUR	2,457	5.61	4,913	6.90	—			—	—	—	—
Collar	Jan 2018 - Dec 2018		EUR	4,913	4.40	4,913	5.31	—			—	—	—	—
Swap	Jul 2016 - Jun 2018		EUR	—	—	—	—	—			—	2,559	5.89	—
Swap	Apr 2017 - Jun 2018		EUR	—	—	—	—	—			—	4,299	4.50	—
Swap	Oct 2017 - Dec 2018		EUR	—	—	—	—	—			—	17,197	4.80	—
Swap	Oct 2017 - Dec 2019		EUR	—	—	—	—	—			—	7,370	4.87	—
Swap	Jan 2018 - Dec 2019		EUR	—	—	—	—	—			—	1,228	5.00	—
Swap	Jul 2018 - Dec 2019		EUR	—	—	—	—	—			—	4,913	4.98	—
Swap	Jan 2019 - Dec 2019		EUR	—	—	—	—	—			—	2,457	4.92	—
Swaption	Jan 2019 - Dec 2020	April 30, 2018	EUR	—	—	—	—	—			—	9,827	5.28	—
Cross Currency Interest Rate				Receive Notional amount (USD)			Rate (LIBOR +)			Pay Notional amount(CAD)			Rate (CDOR +)
Swap	Jan 2018				603,793,015		1.70		%		775,800,000		1.11		%

⁽¹⁾ The sold swaption instrument allows the counterparty, at the specified date, to enter into a swap with Vermilion at the above detailed terms.

⁽²⁾ On the last business day of each month, the counterparty has the option to increase the contracted volumes for the following month.

40

Vermilion Energy Inc. 2017 Annual Report

Supplemental Table 3: Capital Expenditures and Acquisitions

	Three Months Ended					Year Ended
By classification ($M)	Dec 31, 2017		Sep 30, 2017	Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Drilling and development	61,911		75,837	66,437		290,593		241,545
Exploration and evaluation	12,392		15,545	445		29,856		863
Capital expenditures	74,303		91,382	66,882		320,449		242,408
Property acquisition	3,048		20,976	78,713		27,637		98,524
Acquisitions	3,048		20,976	78,713		27,637		98,524
	Three Months Ended					Year Ended
By category ($M)	Dec 31, 2017		Sep 30, 2017	Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Drilling, completion, new well equip and tie-in, workovers and recompletions	45,533		62,451	53,867		225,668		166,795
Production equipment and facilities	18,109		16,982	14,427		59,629		49,453
Seismic, studies, land and other	10,661		11,949	(1,412	)	35,152		26,160
Capital expenditures	74,303		91,382	66,882		320,449		242,408
Acquisitions	3,048		20,976	78,713		27,637		98,524
Total capital expenditures and acquisitions	77,351		112,358	145,595		348,086		340,932
	Three Months Ended					Year Ended
Capital expenditures by country ($M)	Dec 31, 2017		Sep 30, 2017	Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Canada	26,865		43,746	16,895		148,667		62,706
France	20,027		15,756	31,127		73,381		68,472
Netherlands	12,300		11,590	5,737		31,575		23,740
Germany	5,279		3,020	1,694		9,531		3,803
Ireland	327		1,101	1,711		551		9,375
Australia	7,192		10,154	5,236		29,942		59,910
United States	1,018		1,362	4,037		19,074		13,539
Corporate	1,295		4,653	445		7,728		863
Total capital expenditures	74,303		91,382	66,882		320,449		242,408
	Three Months Ended					Year Ended
Acquisitions by country ($M)	Dec 31, 2017		Sep 30, 2017	Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Canada	788		19,712	1,378		22,011		13,309
Netherlands	(38	)	14	28,259		(24	)	28,259
Germany	—		—	48,377		—		48,377
United States	91		1,250	377		3,403		5,935
Corporate	2,207		—	322		2,247		2,644
Total acquisitions	3,048		20,976	78,713		27,637		98,524

41

Vermilion Energy Inc. 2017 Annual Report

Supplemental Table 4: Production

	Q4/17		Q3/17		Q2/17		Q1/17		Q4/16		Q3/16		Q2/16		Q1/16		Q4/15		Q3/15		Q2/15		Q1/15
Canada
Crude oil & condensate (bbls/d)	9,703		9,288		9,205		7,987		7,945		8,984		9,453		10,317		10,413		11,030		11,843		12,163
NGLs (bbls/d)	5,235		4,891		3,745		2,670		2,444		2,448		2,687		2,633		2,710		2,678		2,094		1,706
Natural gas (mmcf/d)	107.91		103.92		93.68		85.74		75.12		77.62		87.44		97.16		87.90		71.94		64.66		61.78
Total (boe/d)	32,923		31,499		28,563		24,947		22,910		24,368		26,713		29,141		27,773		25,698		24,713		24,165
% of consolidated	45	%	46	%	43	%	38	%	38	%	37	%	42	%	44	%	45	%	47	%	48	%	48	%
France
Crude oil (bbls/d)	11,215		10,918		11,368		10,834		11,220		11,827		12,326		12,220		12,537		12,310		12,746		11,463
Natural gas (mmcf/d)	—		—		—		0.01		0.38		0.42		0.54		0.44		1.36		1.47		1.03		—
Total (boe/d)	11,215		10,918		11,368		10,836		11,283		11,897		12,416		12,293		12,763		12,555		12,917		11,463
% of consolidated	15	%	16	%	17	%	17	%	19	%	19	%	19	%	19	%	21	%	22	%	25	%	23	%
Netherlands
Condensate (bbls/d)	105		74		104		76		57		86		96		114		110		109		112		63
Natural gas (mmcf/d)	55.66		34.90		31.58		39.92		41.15		47.62		49.18		53.40		56.34		53.56		32.43		36.41
Total (boe/d)	9,381		5,890		5,368		6,729		6,915		8,023		8,293		9,015		9,500		9,035		5,517		6,132
% of consolidated	13	%	9	%	8	%	10	%	11	%	13	%	13	%	14	%	16	%	16	%	11	%	12	%
Germany
Crude oil (bbls/d)	1,148		1,054		1,047		989		—		—		—		—		—		—		—		—
Natural gas (mmcf/d)	18.19		20.12		19.86		19.39		14.80		14.52		14.31		15.96		16.17		14.00		16.18		16.80
Total (boe/d)	4,180		4,407		4,357		4,220		2,467		2,420		2,385		2,660		2,695		2,333		2,696		2,801
% of consolidated	6	%	7	%	6	%	7	%	4	%	4	%	4	%	4	%	4	%	4	%	5	%	6	%
Ireland
Natural gas (mmcf/d)	56.23		49.04		63.81		64.82		62.92		59.28		47.26		33.90		0.12		—		—		—
Total (boe/d)	9,372		8,173		10,634		10,803		10,486		9,879		7,877		5,650		20		—		—		—
% of consolidated	13	%	12	%	16	%	17	%	17	%	16	%	12	%	9	%	—		—		—		—
Australia
Crude oil (bbls/d)	4,993		5,473		6,054		6,581		6,388		6,562		6,083		6,180		7,824		6,433		5,865		5,672
% of consolidated	7	%	8	%	9	%	10	%	10	%	10	%	9	%	9	%	13	%	11	%	11	%	11	%
United States
Crude oil (bbls/d)	667		880		747		365		362		383		458		368		420		226		123		153
NGLs (bbls/d)	43		56		76		24		23		30		26		39		29		—		—		—
Natural gas (mmcf/d)	0.29		0.64		0.44		0.20		0.18		0.20		0.20		0.26		0.20		—		—		—
Total (boe/d)	758		1,043		896		422		414		447		518		450		483		226		123		153
% of consolidated	1	%	2	%	1	%	1	%	1	%	1	%	1	%	1	%	1	%	—		—		—
Consolidated
Crude oil, condensate
& NGLs (bbls/d)	33,109		32,634		32,346		29,526		28,439		30,320		31,129		31,871		34,043		32,786		32,783		31,220
% of consolidated	45	%	48	%	48	%	46	%	47	%	48	%	48	%	49	%	56	%	58	%	63	%	62	%
Natural gas (mmcf/d)	238.28		208.62		209.36		210.07		194.54		199.65		198.93		201.11		162.09		140.97		114.29		115.00
% of consolidated	55	%	52	%	52	%	54	%	53	%	52	%	52	%	51	%	44	%	42	%	37	%	38	%
Total (boe/d)	72,822		67,403		67,240		64,537		60,863		63,596		64,285		65,389		61,058		56,280		51,831		50,386

42

Vermilion Energy Inc. 2017 Annual Report

	2017		2016		2015		2014		2013		2012
Canada
Crude oil & condensate (bbls/d)	9,051		9,171		11,357		12,491		8,387		7,659
NGLs (bbls/d)	4,144		2,552		2,301		1,233		1,666		1,232
Natural gas (mmcf/d)	97.89		84.29		71.65		55.67		42.39		37.50
Total (boe/d)	29,510		25,771		25,598		23,001		17,117		15,142
% of consolidated	45	%	40	%	46	%	47	%	41	%	40	%
France
Crude oil (bbls/d)	11,084		11,896		12,267		11,011		10,873		9,952
Natural gas (mmcf/d)	—		0.44		0.97		—		3.40		3.59
Total (boe/d)	11,085		11,970		12,429		11,011		11,440		10,550
% of consolidated	16	%	19	%	23	%	22	%	28	%	28	%
Netherlands
Condensate (bbls/d)	90		88		99		77		64		67
Natural gas (mmcf/d)	40.54		47.82		44.76		38.20		35.42		34.11
Total (boe/d)	6,847		8,058		7,559		6,443		5,967		5,751
% of consolidated	10	%	13	%	14	%	13	%	15	%	15	%
Germany
Crude oil (bbls/d)	1,060		—		—		—		—		—
Natural gas (mmcf/d)	19.39		14.90		15.78		14.99		—		—
Total (boe/d)	4,291		2,483		2,630		2,498		—		—
% of consolidated	6	%	4	%	5	%	5	%	—		—
Ireland
Natural gas (mmcf/d)	58.43		50.89		0.03		—		—		—
Total (boe/d)	9,737		8,482		5		—		—		—
% of consolidated	14	%	13	%	—		—		—		—
Australia
Crude oil (bbls/d)	5,770		6,304		6,454		6,571		6,481		6,360
% of consolidated	8	%	10	%	12	%	13	%	16	%	17	%
United States
Crude oil (bbls/d)	666		393		231		49		—		—
NGLs (bbls/d)	50		29		7		—		—		—
Natural gas (mmcf/d)	0.39		0.21		0.05		—		—		—
Total (boe/d)	781		457		247		49		—		—
% of consolidated	1	%	1	%	—		—		—		—
Consolidated
Crude oil, condensate & NGLs (bbls/d)	31,915		30,433		32,716		31,432		27,471		25,270
% of consolidated	47	%	48	%	60	%	63	%	67	%	67	%
Natural gas (mmcf/d)	216.64		198.55		133.24		108.85		81.21		75.20
% of consolidated	53	%	52	%	40	%	37	%	33	%	33	%
Total (boe/d)	68,021		63,526		54,922		49,573		41,005		37,803

43

Vermilion Energy Inc. 2017 Annual Report

Supplemental Table 5: Segmented Financial Results

	Three Months Ended Dec 31, 2017
($M)	Canada		France		Netherlands		Germany		Ireland		Australia		United States		Corporate		Total
Drilling and development	26,865		19,557		2,874		4,078		327		7,192		1,018		—		61,911
Exploration and evaluation	—		470		9,426		1,201		—		—		—		1,295		12,392
Oil and gas sales to external customers	94,522		78,778		40,914		18,898		43,793		36,086		4,350		—		317,341
Royalties	(9,301	)	(10,599	)	(647	)	(1,798	)	—		—		(1,196	)	—		(23,541	)
Revenue from external customers	85,221		68,179		40,267		17,100		43,793		36,086		3,154		—		293,800
Transportation	(4,836	)	(4,475	)	—		(1,164	)	(1,496	)	—		(15	)	—		(11,986	)
Operating	(22,356	)	(14,332	)	(6,981	)	(6,025	)	(2,977	)	(12,172	)	(397	)	—		(65,240	)
General and administration	(2,540	)	(4,259	)	(546	)	(2,080	)	(517	)	(3,193	)	(1,274	)	(1,532	)	(15,941	)
PRRT	—		—		—		—		—		(3,572	)	—		—		(3,572	)
Corporate income taxes	—		(2,348	)	6,975		—		—		(1,755	)	—		(542	)	2,330
Interest expense	—		—		—		—		—		—		—		(13,710	)	(13,710	)
Realized gain on derivative instruments	—		—		—		—		—		—		—		(7,493	)	(7,493	)
Realized foreign exchange gain	—		—		—		—		—		—		—		2,899		2,899
Realized other income	—		—		—		—		—		—		—		166		166
Fund flows from operations	55,489		42,765		39,715		7,831		38,803		15,394		1,468		(20,212	)	181,253
	Year Ended December 31, 2017
($M)	Canada		France		Netherlands		Germany		Ireland		Australia		United States		Corporate		Total
Total assets	1,542,193		831,783		203,929		295,026		667,068		236,677		73,867		124,422		3,974,965
Drilling and development	148,667		71,087		15,107		6,165		551		29,942		19,074		—		290,593
Exploration and evaluation	—		2,294		16,468		3,366		—		—		—		7,728		29,856
Oil and gas sales to external customers	330,903		268,103		108,060		68,696		153,330		154,391		15,355		—		1,098,838
Royalties	(33,258	)	(28,565	)	(1,722	)	(6,655	)	—		—		(4,276	)	—		(74,476	)
Revenue from external customers	297,645		239,538		106,338		62,041		153,330		154,391		11,079		—		1,024,362
Transportation	(17,368	)	(14,627	)	—		(6,207	)	(5,205	)	—		(41	)	—		(43,448	)
Operating	(80,444	)	(51,002	)	(21,212	)	(20,176	)	(17,596	)	(50,139	)	(1,698	)	—		(242,267	)
General and administration	(9,604	)	(13,585	)	(2,212	)	(7,767	)	(2,320	)	(8,194	)	(4,341	)	(6,350	)	(54,373	)
PRRT	—		—		—		—		—		(19,819	)	—		—		(19,819	)
Corporate income taxes	—		(10,556	)	3,331		—		—		(4,536	)	—		(527	)	(12,288	)
Interest expense	—		—		—		—		—		—		—		(57,313	)	(57,313	)
Realized gain on derivative instruments	—		—		—		—		—		—		—		4,721		4,721
Realized foreign exchange gain	—		—		—		—		—		—		—		2,316		2,316
Realized other income	—		—		—		—		—		—		—		674		674
Fund flows from operations	190,229		149,768		86,245		27,891		128,209		71,703		4,999		(56,479	)	602,565

44

Vermilion Energy Inc. 2017 Annual Report

NON-GAAP FINANCIAL MEASURES

This MD&A includes references to certain financial measures which do not have standardized meanings and may not be comparable to similar measures presented by other issuers. These financial measures include fund flows from operations, a measure of profit or loss in accordance with IFRS 8 “Operating Segments” (please see SEGMENTED INFORMATION in the NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS) and net debt, a measure of capital in accordance with IAS 1 “Presentation of Financial Statements” (please see CAPITAL DISCLOSURES in the NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS).

In addition, this MD&A includes financial measures which are not specified, defined, or determined under IFRS and are therefore considered non-GAAP financial measures and may not be comparable to similar measures presented by other issuers. These non-GAAP financial measures include:

Capital expenditures: The sum of drilling and development and exploration and evaluation from the Consolidated Statement of Cash Flows. We consider capital expenditures to be a useful measure of our investment in our existing asset base. Capital expenditures are also referred to as E&D capital.

Cash dividends per share: Represents cash dividends declared per share and is a useful measure of the dividends a common shareholder was entitled to during the period.

Covenants: The financial covenants on our revolving credit facility contain non-GAAP measures. The definitions for these financial covenants are included in FINANCIAL POSITION REVIEW.

Diluted shares outstanding: The sum of shares outstanding at the period end plus outstanding awards under the VIP, based on current estimates of future performance factors and forfeiture rates.

Free cash flow: Represents fund flows from operations in excess of capital expenditures.  We use free cash flow to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures. We also assess free cash flow as a percentage of fund flows from operations, which is a measure of the percentage of fund flows from operations that is retained for incremental investing and financing activities.

Fund flows from operations per basic and diluted share: Management assesses fund flows from operations on a per share basis as we believe this provides a measure of our operating performance after taking into account the issuance and potential future issuance of Vermilion common shares. Fund flows from operations per basic share is calculated by dividing fund flows from operations by the basic weighted average shares outstanding as defined under IFRS. Fund flows from operations per diluted share is calculated by dividing fund flows from operations by the sum of basic weighted average shares outstanding and incremental shares issuable under the VIP as determined using the treasury stock method.

Net dividends: We define net dividends as dividends declared less proceeds received for the issuance of shares pursuant to the Dividend Reinvestment Plan. Management monitors net dividends and net dividends as a percentage of fund flows from operations to assess our ability to pay dividends.

Operating netback: Sales less royalties, operating expense, transportation costs, PRRT, and realized hedging gains and losses presented on a per unit basis. Management assesses operating netback as a measure of the profitability and efficiency of our field operations. In contrast, fund flows from operations netback also includes general and administration expense, corporate income taxes and interest. Fund flows from operations netback is used by management to assess the profitability of our business units and Vermilion as a whole.

Payout: We define payout as net dividends plus drilling and development costs, exploration and evaluation costs, dispositions, and asset retirement obligations settled. Management uses payout and payout as a percentage of fund flows from operations (also referred to as the sustainability ratio) to assess the amount of cash distributed back to shareholders and re-invested in the business for maintaining production and organic growth.

The following tables reconcile net dividends, payout, and diluted shares outstanding from their most directly comparable GAAP measures as presented in our financial statements:

45

Vermilion Energy Inc. 2017 Annual Report

	Three Months Ended						Year Ended
($M)	Dec 31, 2017		Sep 30, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Dividends declared	78,653		78,293		76,096		311,397		299,070
Shares issued for the Dividend Reinvestment Plan	(21,817	)	(23,929	)	(43,580	)	(110,493	)	(192,998	)
Net dividends	56,836		54,364		32,516		200,904		106,072
Drilling and development	61,911		75,837		66,437		290,593		241,545
Exploration and evaluation	12,392		15,545		445		29,856		863
Asset retirement obligations settled	3,216		1,749		3,327		9,334		9,617
Payout	134,355		147,495		102,725		530,687		358,097
% of fund flows from operations	74	%	113	%	69	%	88	%	70	%

	As at
('000s of shares)	Dec 31, 2017	Sep 30, 2017	Dec 31, 2016
Shares outstanding	122,119	121,585	118,263
Potential shares issuable pursuant to the VIP	3,021	2,868	3,090
Diluted shares outstanding	125,140	124,453	121,353

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Vermilion Energy Inc. 2017 Annual Report

DIRECTORS Lorenzo Donadeo ¹ Calgary, Alberta Larry J. Macdonald ^{2, 3, 4, 5} Chairman & CEO, Point Energy Ltd. Calgary, Alberta Stephen P. Larke ^{3, 4} Calgary, Alberta Loren M. Leiker ⁶ Houston, Texas William F. Madison ^{5, 6} Sugar Land, Texas Timothy R. Marchant ^{5, 6} Calgary, Alberta Anthony Marino Calgary, Alberta Robert Michaleski ^{3, 4} Calgary, Alberta Sarah E. Raiss ^{4, 5} Calgary, Alberta William Roby ^{5, 6} Katy, Texas Catherine L. Williams ^{3, 4} Calgary, Alberta ¹ Chairman of the Board ² Lead Director ³ Audit Committee ⁴ Governance and Human Resources Committee ⁵ Health, Safety and Environment Committee ⁶ Independent Reserves Committee ABBREVIATIONS $M          thousand dollars $MM       million dollars AECO     the daily average benchmark price for natural gas at the AECO       ‘C’ hub in Alberta bbl(s)      barrel(s) bbls/d      barrels per day boe         barrel of oil equivalent, including: crude oil, condensate, natural gas liquids, and natural gas (converted on the basis of one boe for six mcf of natural gas) boe/d      barrel of oil equivalent per day GJ           gigajoules HH          Henry Hub, a reference price paid for natural gas in US dollars at Erath, Louisiana mbbls      thousand barrels mcf          thousand cubic feet mmbtu     million British thermal units mmcf/d    million cubic feet per day MWh       megawatt hour NBP       the reference price paid for natural gas in the United Kingdom at the National Balancing Point Virtual Trading Point. NGLs      natural gas liquids, which includes butane, propane, and ethane PRRT      Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia TTF         the price for natural gas in the Netherlands at the Title Transfer Facility Virtual Trading Point. WTI         West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma OFFICERS AND KEY PERSONNEL CANADA Anthony Marino
President & Chief Executive Officer Curtis W. Hicks Executive Vice President & Chief Financial Officer Mona Jasinski Executive Vice President, People and Culture Michael Kaluza Executive Vice President & Chief Operating Officer Dion Hatcher Vice President Canada Business Unit Terry Hergott Vice President Marketing Jenson Tan Vice President Business Development Lars Glemser Director Finance Daniel Goulet Director Corporate HSE Jeremy Kalanuk Director Operations Accounting Bryce Kremnica Director Field Operations - Canada Business Unit Kyle Preston Director Investor Relations Mike Prinz Director Information Technology & Information Systems Robert (Bob) J. Engbloom Corporate Secretary UNITED STATES Daniel G. Anderson Managing Director - U.S. Business Unit Timothy R. Morris Director U.S. Business Development - U.S. Business Unit EUROPE Gerard Schut Vice President European Operations Sylvain Nothhelfer Managing Director - France Business Unit Scott Seatter Managing Director - Netherlands Business Unit Albrecht Moehring Managing Director - Germany Business Unit Darcy Kerwin Managing Director - Ireland Business Unit Bryan Sralla Managing Director - Central & Eastern Europe Business Unit AUSTRALIA Bruce D. Lake Managing Director - Australia Business Unit AUDITORS Deloitte LLP Calgary, Alberta BANKERS The Toronto-Dominion Bank Bank of Montreal Canadian Imperial Bank of Commerce National Bank of Canada Royal Bank of Canada The Bank of Nova Scotia Alberta Treasury Branches Bank of America N.A., Canada Branch BNP Paribas, Canada Branch Citibank N.A., Canadian Branch - Citibank Canada HSBC Bank Canada JPMorgan Chase Bank, N.A., Toronto Branch La Caisse Centrale Desjardins du Québec Wells Fargo Bank N.A., Canadian Branch Barclays Bank PLC Canadian Western Bank Goldman Sachs Lending Partners LLC EVALUATION ENGINEERS GLJ Petroleum Consultants Ltd. Calgary, Alberta LEGAL COUNSEL Norton Rose Fulbright Canada LLP Calgary, Alberta TRANSFER AGENT Computershare Trust Company of Canada STOCK EXCHANGE LISTINGS The Toronto Stock Exchange (“VET”) The New York Stock Exchange (“VET”) INVESTOR RELATIONS Kyle Preston Director Investor Relations 403-476-8431 TEL 403-476-8100 FAX 1-866-895-8101 IR TOLL FREE investor_relations@vermilionenergy.com

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