EX-99.2 3 v460356_ex99-2.htm MANAGEMENT'S DISCUSSION AND ANALYSIS FROM THE 2016 ANNUAL REPORT TO SHAREHOLDERS

Exhibit 99.2

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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
bcf	billion cubic feet
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
btu	British thermal units
DRIP	Dividend Reinvestment Plan
GJ	gigajoules
mbbls	thousand barrels
mboe	thousand barrel of oil equivalent
mcf	thousand cubic feet
mcf/d	thousand cubic feet per day
mmboe	million barrel of oil equivalent
mmbtu	million British thermal units
mmcf	million cubic feet
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

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following is Management’s Discussion and Analysis (“MD&A”), dated February 24, 2017, 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, 2016 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, 2016 and 2015, 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, 2016 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.

CHANGE IN PRESENTATION

Prior to 2016, we reported our condensate production in Canada and the Netherlands business units within the NGLs production line. Beginning in Q1 2016, we reported condensate production 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). Comparative periods have been adjusted to reflect this change.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

2016 REVIEW AND 2017 GUIDANCE

On November 9, 2015, we announced preliminary 2016 capital expenditure guidance of $350 million and production guidance of between 63,000-65,000 boe/d. On January 5, 2016, in response to the continued weakness in commodity prices we reduced our 2016 capital expenditure guidance to $285 million with corresponding production guidance of 62,500-63,500 boe/d. On February 29, 2016, we further revised our 2016 capital expenditure guidance to $235 million as a result of continued commodity price deterioration. We maintained our production guidance of 62,500-63,500 boe/d. The February 29, 2016 reduction primarily reflected lower expected non-operated drilling activity in Canada, fewer workovers in France, and a deferral of our Netherlands pipeline twinning program. On August 8, 2016, we modestly increased our 2016 capital expenditure guidance to $240 million with the reinstatement of a four-well drilling program in the Champotran field in France and added drilling activity in Canada, partially offset by capital cost savings achieved to date. Actual 2016 capital spending of $242.4 million was within 1% of our guidance and 2016 production of 63,526 boe/d modestly exceeded the top end of our guidance range.

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.

The following table summarizes our guidance:

	Date	Capital Expenditures ($MM)	Production (boe/d)
2016 Guidance
2016 Guidance	November 9, 2015	350	63,000 to 65,000
2016 Guidance	January 5, 2016	285	62,500 to 63,500
2016 Guidance	February 29, 2016	235	62,500 to 63,500
2016 Guidance	August 8, 2016	240	62,500 to 63,500
2017 Guidance
2017 Guidance	October 31, 2016	295	69,000 to 70,000

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

CONSOLIDATED RESULTS OVERVIEW

		Three Months Ended			% change		Year Ended		% change
		Dec 31,	Sep 30,	Dec 31,	Q4/16 vs.	Q4/16 vs.	Dec 31,	Dec 31,	2016 vs.
		2016	2016	2015	Q3/16	Q4/15	2016	2015	2015
Production
	Crude oil and condensate (bbls/d)	25,972	27,842	31,304	(7%)	(17%)	27,852	30,408	(8%)
	NGLs (bbls/d)	2,467	2,478	2,739	-	(10%)	2,582	2,308	12%
	Natural gas (mmcf/d)	194.54	199.66	162.09	(3%)	20%	198.55	133.24	49%
	Total (boe/d)	60,863	63,596	61,058	(4%)	-	63,526	54,922	16%
Sales
	Crude oil and condensate (bbls/d)	26,610	30,111	32,306	(12%)	(18%)	28,005	30,178	(7%)
	NGLs (bbls/d)	2,467	2,478	2,739	-	(10%)	2,582	2,308	12%
	Natural gas (mmcf/d)	194.54	199.66	162.09	(3%)	20%	198.55	133.24	49%
	Total (boe/d)	61,501	65,865	62,061	(7%)	(1%)	63,679	54,692	16%
	Build (draw) in inventory (mbbls)	(58)	(209)	(93)			(55)	84
Financial metrics
	Fund flows from operations ($M)	149,582	140,974	136,441	6%	10%	510,791	516,167	(1%)
	Per share ($/basic share)	1.27	1.21	1.22	5%	4%	4.41	4.71	(6%)
	Net loss	(4,032)	(14,475)	(142,080)	(72%)	(97%)	(160,051)	(217,302)	(26%)
	Per share ($/basic share)	(0.03)	(0.12)	(1.28)	(75%)	(98%)	(1.38)	(1.98)	(30%)
	Net debt ($M)	1,427,148	1,343,923	1,381,951	6%	3%	1,427,148	1,381,951	3%
	Cash dividends ($/share)	0.645	0.645	0.645	-	-	2.580	2.580	-
Activity
	Capital expenditures ($M)	66,882	41,039	128,996	63%	(48%)	242,408	486,861	(50%)
	Acquisitions ($M)	78,713	10,391	6,227	658%	1,164%	98,524	28,897	241%
	Gross wells drilled	16.00	6.00	8.00			38.00	53.00
	Net wells drilled	12.02	2.08	5.56			25.50	36.12

Operational review

·	Increased consolidated average production for the year ended December 31, 2016 by 16% versus 2015. This increase was primarily due to the addition of Corrib production in Ireland. For the three months ended December 31, 2016, production was relatively consistent with the comparable period in 2015 as the addition of Corrib production in Ireland was offset by natural declines and actively managed production in Canada, the Netherlands, and Australia.
·	Achieved consolidated average production of 60,863 boe/d in Q4 2016, a 4% decrease from Q3 2016 due to natural declines, the timing of capital projects, and actively managed production in Canada, the Netherlands, and Australia.
·	Incurred capital expenditures in Q4 2016 of $66.9 million primarily related to France and Canada. In France, capital expenditures of $31.1 million were incurred related to the drilling of four wells in Champotran and other development activities in the quarter. In Canada, capital expenditures of $16.9 million related primarily to drilling activity.
·	For the year ended December 31, 2016, capital expenditures of $242.4 million primarily related to France, Canada, Australia, and the Netherlands. In France, capital expenditures of $68.5 million related to drilling activity and other development activities, including workover and optimization programs in the Aquitaine and Paris basins. In Canada, capital expenditures of $62.7 million related primarily to drilling activity. In Australia, capital expenditures of $59.9 million related primarily to drilling two sidetrack wells and our Wandoo Platforms Life Extension project. In the Netherlands, capital expenditures of $23.7 million related primarily to drilling activity.
·	For the year ended December 31, 2016, acquisition spending of $98.5 million related primarily to Germany and the Netherlands. In Germany, acquisition spending of $48.4 million related to the acquisition of operated and non-operated interests in five oil and three gas producing fields. In the Netherlands, acquisition spending of $28.3 million related to the acquisition of an additional 30% working interest in the Drenthe VI production license, which adds 30,000 net acres of land, including 26,000 net acres of undeveloped land and a 30% after payout interest in one well..

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Financial review

Net loss

·	The net loss for Q4 2016 was $4.0 million ($0.03/basic share), compared to a net loss of $14.5 million ($0.12/basic share) in Q3 2016. The change in the net loss was primarily attributable to higher revenue as a result of higher commodity prices.
·	The net loss for Q4 2016 was $4.0 million ($0.03/basic share), compared to a net loss of $142.1 million ($1.28/basic share) in Q4 2015. The change was a result of a non-cash gain on business combination recognized in the current quarter and the absence of a non-cash impairment charge recognized in Q4 2015, partially offset by an unrealized loss on derivative instruments.
·	The net loss for the year ended December 31, 2016 of $160.1 million compared to a net loss of $217.3 million for 2015. The change was primarily a result of a lower non-cash impairment charge in 2016, partially offset by the impact of lower commodity prices and an unrealized loss on derivative instruments.

Fund flows from operations

·	Generated fund flows from operations of $149.6 million during Q4 2016, an increase of 6% from Q3 2016. This quarter-over-quarter increase was primarily attributable to higher commodity prices, partially offset by lower sales volumes.
·	Fund flows from operations increased by 10% in Q4 2016 as compared to Q4 2015 due to revenue from Ireland and higher crude oil pricing. For the year ended December 31, 2016, fund flows from operations was relatively consistent with the corresponding period in 2015 despite significantly lower commodity prices due to production from Ireland and a 16% reduction in per unit operating costs.

Net debt

Net debt increased to $1.43 billion as at December 31, 2016 from $1.38 billion at December 31, 2015 primarily due to changes in net current derivatives, partially offset by a decrease in long term debt of $25.7 million as fund flows from operations generated in excess of capital expenditures, abandonment expenditures, net dividends, and acquisitions was used to reduce debt.

Dividends

·	Declared dividends of $0.215 per common share per month during the fourth quarter of 2016, totalling $2.58 per common share for the year ended December 31, 2016. This was consistent with dividends declared of $2.58 per common share for the year ended December 31, 2015.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

COMMODITY PRICES

	Three Months Ended			% change		Year Ended		% change
	Dec 31,	Sep 30,	Dec 31,	Q4/16 vs.	Q4/16 vs.	Dec 31,	Dec 31,	2016 vs.
	2016	2016	2015	Q3/16	Q4/15	2016	2015	2015
Average reference prices
Crude oil
WTI (US $/bbl)	49.29	44.94	42.18	10%	17%	43.32	48.80	(11%)
Edmonton Sweet index (US $/bbl)	46.18	42.06	39.72	10%	16%	40.11	44.91	(11%)
Dated Brent (US $/bbl)	49.46	45.85	43.69	8%	13%	43.69	52.46	(17%)
Natural gas
AECO ($/mmbtu)	3.09	2.32	2.46	33%	26%	2.16	2.69	(20%)
NBP ($/mmbtu)	7.51	5.29	7.41	42%	1%	6.15	8.33	(26%)
NBP (€/mmbtu)	5.22	3.63	5.07	44%	3%	4.19	5.87	(29%)
TTF ($/mmbtu)	7.21	5.43	7.28	33%	(1%)	6.00	8.23	(27%)
TTF (€/mmbtu)	5.01	3.73	4.98	34%	1%	4.09	5.80	(29%)
Henry Hub ($/mmbtu)	3.98	3.67	3.03	8%	31%	3.27	3.41	(4%)
Henry Hub (US $/mmbtu)	2.98	2.81	2.27	6%	31%	2.46	2.66	(8%)
Average foreign currency exchange rates
CDN $/US $	1.33	1.31	1.34	2%	(1%)	1.33	1.28	4%
CDN $/Euro	1.44	1.46	1.46	(1%)	(1%)	1.47	1.42	4%
Average realized prices ($/boe)
Canada	33.48	28.75	28.94	16%	16%	26.81	34.32	(22%)
France	63.71	55.88	54.20	14%	18%	55.15	62.67	(12%)
Netherlands	40.84	31.80	42.61	28%	(4%)	34.15	46.77	(27%)
Germany	36.54	30.47	39.68	20%	(8%)	31.97	43.10	(26%)
Ireland	44.29	28.68	-	54%	100%	35.16	-	100%
Australia	69.05	60.61	58.74	14%	18%	60.33	70.22	(14%)
United States	53.58	44.53	41.94	20%	28%	43.70	47.53	(8%)
Consolidated	45.93	38.40	41.04	20%	12%	37.88	47.07	(20%)
Production mix (% of production)
% priced with reference to WTI	18%	19%	22%			19%	25%
% priced with reference to AECO	20%	20%	24%			22%	22%
% priced with reference to TTF and NBP	33%	32%	20%			30%	19%
% priced with reference to Dated Brent	29%	29%	34%			29%	34%

·	Crude oil prices in Q4 2016 were higher as compared to both Q3 2016 and Q4 2015 as OPEC and select non-OPEC countries reached an agreement to cut output for the first six months of 2017. This coordinated effort to curb the surplus supply of crude oil resulted in an increase in WTI of 10% as compared to Q3 2016 and 17% as compared to Q4 2015. Similarly, Dated Brent increased 8% as compared to Q3 2016 and 13% as compared to Q4 2015.
·	An early start to winter increased demand for AECO natural gas both domestically and for exports to the US. For the three months ended December 31, 2016, the AECO price increased 33% and 26%, respectively, versus Q3 2016 and Q4 2015. In Q4 2016, Henry Hub prices increased by 6% and 31% versus Q3 2016 and Q4 2015, respectively, as US supply/demand fundamentals showed signs of tightening.
·	European natural gas prices increased in Q4 2016 as higher power sector demand, gas-in-storage constraints and lower-than-expected LNG imports resulted in tighter balances. For the three months ended December 31, 2016, NBP and TTF increased by 42% and 33%, respectively, in Canadian dollar terms versus Q3 2016, and were effectively unchanged versus Q4 2015.
·	A highly anticipated 25 basis points rate hike by the US Federal Reserve in Q4 2016 resulted in the Canadian dollar weakening against the US dollar.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

FUND FLOWS FROM OPERATIONS

	Three Months Ended						Year Ended
	Dec 31, 2016		Sep 30, 2016		Dec 31, 2015		Dec 31, 2016		Dec 31, 2015
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Petroleum and natural gas sales	259,891	45.93	232,660	38.40	234,319	41.04	882,791	37.88	939,586	47.07
Royalties	(14,999)	(2.65)	(12,969)	(2.14)	(16,285)	(2.85)	(54,284)	(2.33)	(65,920)	(3.30)
Petroleum and natural gas revenues	244,892	43.28	219,691	36.26	218,034	38.19	828,507	35.55	873,666	43.77
Transportation	(9,565)	(1.69)	(9,696)	(1.60)	(10,147)	(1.78)	(39,511)	(1.70)	(41,660)	(2.09)
Operating	(59,616)	(10.54)	(54,825)	(9.05)	(65,645)	(11.50)	(222,185)	(9.53)	(225,938)	(11.32)
General and administration	(11,464)	(2.03)	(12,295)	(2.03)	(12,431)	(2.18)	(52,829)	(2.27)	(53,584)	(2.68)
PRRT	(1,568)	(0.28)	272	0.04	(1,054)	(0.18)	(1,568)	(0.07)	(6,878)	(0.34)
Corporate income taxes	(5,840)	(1.03)	(3,546)	(0.59)	3,113	0.55	(18,110)	(0.78)	(44,237)	(2.22)
Interest expense	(14,410)	(2.55)	(14,150)	(2.34)	(16,584)	(2.90)	(56,957)	(2.44)	(59,852)	(3.00)
Realized gain on derivative instruments	1,920	0.34	13,532	2.23	21,164	3.71	65,376	2.81	41,356	2.07
Realized foreign exchange gain (loss)	1,291	0.23	2,073	0.34	(252)	(0.04)	4,041	0.17	623	0.03
Realized other income (expense)	3,942	0.70	(82)	(0.01)	243	0.04	4,027	0.17	32,671	1.64
Fund flows from operations	149,582	26.43	140,974	23.25	136,441	23.91	510,791	21.91	516,167	25.86

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

($M)	Q4/16 vs. Q3/16	Q4/16 vs. Q4/15	2016 vs. 2015
Fund flows from operations – Comparative period	140,974	136,441	516,167
Sales volume variance:
Canada	(4,835)	(14,094)	(21,614)
France	(2,111)	(1,673)	699
Netherlands	(3,279)	(10,168)	8,917
Germany	135	(838)	(2,249)
Ireland	1,612	42,670	109,099
Australia	(11,171)	(15,327)	(3,500)
United States	(127)	(269)	3,343
Pricing variance on sales volumes:
WTI	6,708	7,821	(26,730)
AECO	4,582	3,340	(19,719)
Dated Brent	13,504	15,915	(57,688)
TTF and NBP	22,213	(1,805)	(47,353)
Changes in:
Royalties	(2,030)	1,286	11,636
Transportation	131	582	2,149
Operating	(4,791)	6,029	3,753
General and administration	831	967	755
PRRT	(1,840)	(514)	5,310
Corporate income taxes	(2,294)	(8,953)	26,127
Interest	(260)	2,174	2,895
Realized derivatives	(11,612)	(19,244)	24,020
Realized foreign exchange	(782)	1,543	3,418
Realized other income	4,024	3,699	(28,644)
Fund flows from operations – Current period	149,582	149,582	510,791

Fund flows from operations was $149.6 million during Q4 2016, an increase of 6% from Q3 2016. This quarter-over-quarter increase was primarily attributable to higher commodity prices, partially offset by lower sales volumes.

Fund flows from operations increased by 10% in Q4 2016 as compared to Q4 2015 due to revenue from Ireland and higher crude oil pricing. For the year ended December 31, 2016, fund flows from operations was relatively consistent with the corresponding period in 2015 despite significantly lower commodity prices due to production from Ireland and a 16% reduction in per unit operating costs.

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.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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

Canadian cash flows are fully tax-sheltered for the foreseeable future.

Operational and financial review

		Three Months Ended			% change		Year Ended		% change
Canada business unit		Dec 31,	Sep 30,	Dec 31,	Q4/16 vs.	Q4/16 vs.	Dec 31,	Dec 31,	2016 vs.
($M except as indicated)		2016	2016	2015	Q3/16	Q4/15	2016	2015	2015
Production and sales
	Crude oil and condensate (bbls/d)	7,945	8,984	10,413	(12%)	(24%)	9,171	11,357	(19%)
	NGLs (bbls/d)	2,444	2,448	2,710	-	(10%)	2,552	2,301	11%
	Natural gas (mmcf/d)	75.12	77.62	87.90	(3%)	(15%)	84.29	71.65	18%
	Total (boe/d)	22,910	24,368	27,773	(6%)	(18%)	25,771	25,598	1%
Production mix (% of total)
	Crude oil and condensate	35%	37%	37%			36%	44%
	NGLs	11%	10%	10%			10%	9%
	Natural gas	54%	53%	53%			54%	47%
Activity
	Capital expenditures	16,895	10,421	27,554	62%	(39%)	62,706	201,508	(69%)
	Acquisitions	1,378	10,380	6,169			13,309	14,650
	Gross wells drilled	11.00	4.00	5.00			29.00	42.00
	Net wells drilled	7.02	1.20	2.56			17.62	26.01
Financial results
	Sales	70,573	64,453	73,952	9%	(5%)	252,867	320,613	(21%)
	Royalties	(7,390)	(4,817)	(7,146)	53%	3%	(21,475)	(28,144)	(24%)
	Transportation	(3,504)	(3,978)	(3,784)	(12%)	(7%)	(15,392)	(16,326)	(6%)
	Operating	(18,161)	(15,579)	(24,575)	17%	(26%)	(71,543)	(89,085)	(20%)
	General and administration	(2,035)	(3,010)	(3,669)	(32%)	(45%)	(11,826)	(16,888)	(30%)
	Fund flows from operations	39,483	37,069	34,778	7%	14%	132,631	170,170	(22%)
Netbacks ($/boe)
	Sales	33.48	28.75	28.94	16%	16%	26.81	34.32	(22%)
	Royalties	(3.51)	(2.15)	(2.80)	63%	25%	(2.28)	(3.01)	(24%)
	Transportation	(1.66)	(1.77)	(1.48)	(6%)	12%	(1.63)	(1.75)	(7%)
	Operating	(8.62)	(6.95)	(9.62)	24%	(10%)	(7.59)	(9.54)	(20%)
	General and administration	(0.97)	(1.34)	(1.44)	(28%)	(33%)	(1.25)	(1.81)	(31%)
	Fund flows from operations netback	18.72	16.54	13.60	13%	38%	14.06	18.21	(23%)
Realized prices
	Crude oil and condensate ($/bbl)	62.13	53.96	53.44	15%	16%	52.44	57.71	(9%)
	NGLs ($/bbl)	18.12	12.49	7.89	45%	130%	11.75	10.32	14%
	Natural gas ($/mmbtu)	3.05	2.39	2.57	28%	19%	2.14	2.78	(23%)
	Total ($/boe)	33.48	28.75	28.94	16%	16%	26.81	34.32	(22%)
Reference prices
	WTI (US $/bbl)	49.29	44.94	42.18	10%	17%	43.32	48.80	(11%)
	Edmonton Sweet index (US $/bbl)	46.18	42.06	39.72	10%	16%	40.11	44.91	(11%)
	Edmonton Sweet index ($/bbl)	61.60	54.89	53.04	12%	16%	53.17	57.43	(7%)
	AECO ($/mmbtu)	3.09	2.32	2.46	33%	26%	2.16	2.69	(20%)

Production

Q4 2016 average production in Canada decreased by 6% quarter-over-quarter and 18% year-over-year due to production declines, cold weather related issues and the voluntary curtailment of approximately 13 mmcf/d (2,350 boe/d) of gas weighted production during the quarter. Full year average production increased 1% versus 2015 primarily due to strong organic production in our Mannville condensate-rich gas play offsetting declines in our Cardium and Saskatchewan Midale light oil plays.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Cardium production averaged approximately 6,100 boe/d in Q4 2016, a 7% decrease quarter-over-quarter. Full year 2016 production averaged approximately 6,700 boe/d.

Mannville production averaged approximately 9,600 boe/d in Q4 2016 representing a 6% decrease quarter-over-quarter. Full year 2016 production averaged more than 11,000 boe/d.

Production from southeast Saskatchewan averaged approximately 2,100 boe/d in Q4 2016, a decrease of 13% quarter-over-quarter.

Activity review

Vermilion drilled seven (6.0 net) operated wells and participated in the drilling of five (1.5 net) non-operated wells during Q4 2016. During 2016, Vermilion drilled 14 (12.6 net) operated wells and participated in the drilling of 15 (5.0 net) non-operated wells in Canada.

Cardium

In 2016, we participated in the drilling of two (0.2 net) non-operated wells and three (0.5 net) non-operated wells were brought on production.

In 2017, we plan to drill or participate in nine (6.0 net) wells.

Mannville

During Q4 2016, we drilled seven (6.0 net) operated wells and participated in the drilling of four (1.5 net) non-operated wells.

In 2016, we drilled or participated in 20 (12.0 net) wells.

In 2017, we plan to drill or participate in 23 (15.0 net) wells and complete and tie-in six (5.0 net) wells drilled in 2016.

Saskatchewan

During Q1 and Q2 2016, we drilled four (4.0 net) operated wells and participated in three (1.5 net) non-operated wells. We plan to complete and bring the four operated wells on production in Q1 2017. The non-operated wells were brought on production during the first half of 2016.

In 2017, we plan to drill or participate in 13 (11.3 net) wells.

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 2016 sales per boe increased versus Q3 2016 and Q4 2015 due to stronger crude oil and natural gas pricing.

Sales per boe for the year ended December 31, 2016 decreased versus the comparable period in 2015, primarily as a result of lower average crude oil and natural gas pricing.

Royalties

Royalties as a percentage of sales for Q4 2016 increased to 10.5% as compared to 7.5% in Q3 2016 and 9.7% in Q4 2015 due to the impact of higher reference prices on the sliding scale used to determine royalty rates.

Royalties as a percentage of sales for the year ended December 31, 2016 was 8.5% versus 8.8% in 2015 as the impact of lower reference prices more than offset wells coming off of incentive royalty rates after reaching specified production thresholds.

Transportation

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

Transportation expense for Q4 2016 was lower than Q3 2016 and Q4 2015 due to lower production.

Transportation expense for the year ended December 31, 2016 was 6% lower than the prior year while production increased 1%. This was due to a lower oil weighting, which incurs a higher per unit expense, and a reduction in transportation rates.

Operating

Operating expense was higher on an absolute dollar and per boe basis in Q4 2016 versus Q3 2016. This was primarily due to the timing of project and maintenance activity that was executed in the current quarter.

Operating expense for the three months and year ended December 31, 2016 decreased by 10% and 20% respectively on a per unit basis versus the comparable periods in 2015. Our continued focus on cost reduction initiatives including major project, transportation and other costs resulted in an annual reduction to operating expenses of $17.5 million while growing production by 1%.

General and administration

General and administration expense fluctuation in Q4 2016 as compared to Q3 2016 was the result of timing of expenditures.

Year-over-year, 2016 general and administration expense was 30% lower than 2015 due to initiatives to reduce our cost structure.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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		Dec 31,	Sep 30,	Dec 31,	Q4/16 vs.	Q4/16 vs.	Dec 31,	Dec 31,	2016 vs.
($M except as indicated)		2016	2016	2015	Q3/16	Q4/15	2016	2015	2015
Production
	Crude oil (bbls/d)	11,220	11,827	12,537	(5%)	(11%)	11,896	12,267	(3%)
	Natural gas (mmcf/d)	0.38	0.42	1.36	(10%)	(72%)	0.44	0.97	(55%)
	Total (boe/d)	11,283	11,897	12,763	(5%)	(12%)	11,970	12,429	(4%)
Sales
	Crude oil (bbls/d)	12,209	12,617	12,490	(3%)	(2%)	12,157	12,141	-
	Natural gas (mmcf/d)	0.38	0.42	1.36	(11%)	(72%)	0.44	0.97	(54%)
	Total (boe/d)	12,272	12,687	12,717	(3%)	(3%)	12,231	12,302	(1%)
Inventory (mbbls)
	Opening crude oil inventory	239	312	239			243	197
	Crude oil production	1,032	1,088	1,153			4,354	4,477
	Crude oil sales	(1,123)	(1,161)	(1,149)			(4,449)	(4,431)
	Closing crude oil inventory	148	239	243			148	243
Activity
	Capital expenditures	31,127	11,110	24,085	180%	29%	68,472	92,265	(26%)
	Acquisitions	-	-	79			-	317
	Gross wells drilled	4.00	-	-			4.00	4.00
	Net wells drilled	4.00	-	-			4.00	4.00
Financial results
	Sales	71,926	65,221	63,411	10%	13%	246,863	281,422	(12%)
	Royalties	(6,692)	(7,069)	(7,198)	(5%)	(7%)	(27,091)	(26,958)	-
	Transportation	(3,983)	(3,586)	(4,275)	11%	(7%)	(14,758)	(15,378)	(4%)
	Operating	(11,482)	(12,933)	(15,792)	(11%)	(27%)	(50,000)	(50,718)	(1%)
	General and administration	(5,101)	(4,590)	(4,894)	11%	4%	(19,101)	(20,217)	(6%)
	Other income	3,822	-	-	100%	100%	3,822	31,775	(88%)
	Current income taxes	(2,867)	955	4,529	(400%)	(163%)	(2,867)	(23,764)	(88%)
	Fund flows from operations	45,623	37,998	35,781	20%	28%	136,868	176,162	(22%)
Netbacks ($/boe)
	Sales	63.71	55.88	54.20	14%	18%	55.15	62.67	(12%)
	Royalties	(5.93)	(6.06)	(6.15)	(2%)	(4%)	(6.05)	(6.00)	1%
	Transportation	(3.53)	(3.07)	(3.65)	15%	(3%)	(3.30)	(3.42)	(4%)
	Operating	(10.17)	(11.08)	(13.50)	(8%)	(25%)	(11.17)	(11.30)	(1%)
	General and administration	(4.52)	(3.93)	(4.18)	15%	8%	(4.27)	(4.50)	(5%)
	Other income	3.39	-	-	100%	100%	0.85	7.08	(88%)
	Current income taxes	(2.54)	0.82	3.87	(410%)	(166%)	(0.64)	(5.29)	(88%)
	Fund flows from operations	40.41	32.56	30.59	24%	32%	30.57	39.24	(22%)
Realized prices
	Crude oil ($/bbl)	63.99	56.14	54.88	14%	17%	55.42	63.31	(12%)
	Natural gas ($/mmbtu)	1.55	1.58	2.81	(2%)	(45%)	1.59	2.52	(37%)
	Total ($/boe)	63.71	55.88	54.20	14%	18%	55.15	62.67	(12%)
Reference prices
	Dated Brent (US $/bbl)	49.46	45.85	43.69	8%	13%	43.69	52.46	(17%)
	Dated Brent ($/bbl)	65.97	59.84	58.34	10%	13%	57.92	67.09	(14%)

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Production

Q4 2016 production decreased 5% versus the prior quarter and 12% versus Q4 2015. Full year production decreased 4% versus 2015. Decreased production for the quarter and the year were primarily due to production declines, well downtime and third party restrictions impacting Vic Bilh gas production.

Activity review

During Q4 2016, we drilled four wells in Champotran and commenced drilling of a horizontal sidetrack well in the Vulaines field, with completion and tie-in planned for early 2017.

In 2016, additional activity included workover and optimization programs in the Aquitaine and Paris Basins.

In 2017, we plan to drill our first four (4.0 net) wells in the Neocomian fields in the Paris Basin, in addition to continuing our workover and optimization activities.

Sales

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

Q4 2016 sales per boe increased versus Q3 2016 and Q4 2015 as a result of stronger Dated Brent pricing.

Sales per boe for the year ended December 31, 2016, decreased versus the comparable period in 2015 as a result of lower average crude oil pricing.

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).

Royalties as a percentage of sales of 9.3% for the three months ended December 31, 2016 was lower than Q3 2016 (10.8%) and Q4 2015 (11.3%) as a result of the impact of fixed RCDM royalties coupled with higher realized pricing in the current quarter. On a year-over-year basis, the royalty rate increased to 11.0% versus 9.6% in 2015 due to lower realized pricing in the current year.

Transportation

Transportation expense per boe for Q4 2016 was higher than Q3 2016 and consistent with Q4 2015. The increase over Q3 2016 was due to the timing of project and maintenance activity executed in the current quarter.

Transportation expense decreased by 4% for 2016 versus 2015 as a result of initiatives to reduce our cost structure, which included vessel cost renegotiation and lower project activity.

Operating

Operating expense on a dollar and per boe basis decreased in Q4 2016 versus both Q3 2016 and Q4 2015 due to the timing of expenditures and a continued focus on initiatives to reduce costs.

Year-over-year, operating expense decreased on a dollar and per boe basis in 2016 versus 2015 due to the continuation of focus on cost reduction initiatives identified in 2015 and new initiatives identified in 2016, which more than off-set unfavourable foreign exchange rates as the Canadian dollar weakened versus the Euro. After normalizing for the unfavorable foreign exchange, per unit costs decreased 4.5% in 2016.

General and administration

General and administration expense for Q4 2016 was 11% higher than Q3 2016 and 4% higher than Q4 2015 due to the timing of expenditures and recoveries.

Year-over-year, 2016 general and administration expense was 6% lower than 2015 due to the impact of cost reduction initiatives.

Other income

In 2015, Vermilion was awarded a recovery of costs resulting from an oil spill at the Ambès oil terminal in France that occurred in 2007. The court awarded Vermilion approximately €25 million (before taxes), of which 50% was due immediately to Vermilion upon posting a surety bond. The payment was received in 2015, with the remainder due upon conclusion of the appeal process. Approximately 90% of the recovery was recorded as other income in 2015.

In Q4 2016, the Court of Appeal of Versailles maintained this award. The remaining payment was received and Vermilion’s surety bond was returned in 2017. The remaining amount of the recovery was recognized as other income in 2016.

Current income taxes

In France, current income taxes are applied to taxable income, after eligible deductions, at a statutory rate of 34.4% for 2016.

Current income taxes in Q4 2016 were higher compared to Q3 2016 due to increased sales and other income. Q4 2016 current income taxes were higher compared to Q4 2015 due to increased sales and the reversal of tax depletion impairments taken in Q4 2015.

Current income taxes for the year ended December 31, 2016 were lower versus the comparative period in 2015 as a result of decreased sales and other income.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

NETHERLANDS BUSINESS UNIT

Overview

	·	Entered the Netherlands in 2004.
	·	Second largest onshore gas producer.
	·	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		Dec 31,	Sep 30,	Dec 31,	Q4/16 vs.	Q4/16 vs.	Dec 31,	Dec 31,	2016 vs.
($M except as indicated)		2016	2016	2015	Q3/16	Q4/15	2016	2015	2015
Production and sales
	Condensate (bbls/d)	57	86	110	(34%)	(48%)	88	99	(11%)
	Natural gas (mmcf/d)	41.15	47.62	56.34	(14%)	(27%)	47.82	44.76	7%
	Total (boe/d)	6,915	8,023	9,500	(14%)	(27%)	8,058	7,559	7%
Activity
	Capital expenditures	5,737	6,441	18,810	(11%)	(70%)	23,740	47,325	(50%)
	Acquisitions	28,259	-	-			28,259	-
	Gross wells drilled	-	2.00	-			2.00	2.00
	Net wells drilled	-	0.88	-			0.88	1.86
Financial results
	Sales	25,978	23,470	37,243	11%	(30%)	100,707	129,057	(22%)
	Royalties	(294)	(312)	(224)	(6%)	31%	(1,462)	(3,082)	(53%)
	Operating	(5,660)	(4,854)	(6,263)	17%	(10%)	(20,796)	(22,746)	(9%)
	General and administration	(162)	633	(813)	(126%)	(80%)	(1,525)	(4,158)	(63%)
	Current income taxes	100	(1,264)	(2,930)	(108%)	(103%)	(6,624)	(12,152)	(45%)
	Fund flows from operations	19,962	17,673	27,013	13%	(26%)	70,300	86,919	(19%)
Netbacks ($/boe)
	Sales	40.84	31.80	42.61	28%	(4%)	34.15	46.77	(27%)
	Royalties	(0.46)	(0.42)	(0.26)	10%	77%	(0.50)	(1.12)	(55%)
	Operating	(8.90)	(6.58)	(7.17)	35%	24%	(7.05)	(8.24)	(14%)
	General and administration	(0.26)	0.86	(0.93)	(130%)	(72%)	(0.52)	(1.51)	(66%)
	Current income taxes	0.16	(1.71)	(3.35)	(109%)	(105%)	(2.25)	(4.40)	(49%)
	Fund flows from operations netback	31.38	23.95	30.90	31%	2%	23.83	31.50	(24%)
Realized prices
	Condensate ($/bbl)	63.18	49.43	48.30	28%	31%	44.93	49.98	(10%)
	Natural gas ($/mmbtu)	6.78	5.27	7.09	29%	(4%)	5.67	7.79	(27%)
	Total ($/boe)	40.84	31.80	42.61	28%	(4%)	34.15	46.77	(27%)
Reference prices
	TTF ($/mmbtu)	7.21	5.43	7.28	33%	(1%)	6.00	8.23	(27%)
	TTF (€/mmbtu)	5.01	3.73	4.98	34%	1%	4.09	5.80	(29%)

Production

Q4 2016 production decreased 14% quarter-over-quarter and 27% year-over-year due to production curtailments in accordance with extended well test plans and management of production to meet corporate production targets.

Full year 2016 production increased 7% versus 2015, primarily due to production additions from Slootdorp-06/07 and Diever-02 wells, which were on extended production test.

Production in the Netherlands is actively managed to optimize facility use and regulate declines.

Activity review

During Q3 2016, Vermilion drilled two (0.9 net) wells. Langezwaag-3 (42% working interest) was completed and brought on production during Q4 2016, at a restricted rate of 7.5 mmcf/d. The Andel-6ST (45% working interest) encountered a large gas column of inadequate reservoir quality to justify completion.

During Q4 2016, we acquired an additional 30% working interest in the Drenthe VI production license, adding 30,000 net acres of land, including 26,000 net acres of undeveloped land and a 30% after payout interest in one well.

In 2017, we plan to drill two (1.0 net) exploration wells, acquire 230 square kilometres of 3D seismic and execute a major turnaround at the Garijp Treatment Centre.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Sales

	·	The price of our natural gas in the Netherlands is based on the TTF index.
	·	Q4 2016 sales per boe increased versus Q3 2016 consistent with an increase in the TTF reference price.
	·	Sales per boe for the three months ended December 31, 2016 were relatively consistent with the comparable period in 2015. For the year ended December 31, 2016, sales per boe decreased consistent with a decrease in the TTF reference price.

Royalties

In the Netherlands, we pay overriding royalties on certain wells. As such, fluctuations in royalty expense in the periods presented relate to the amount of production from those wells subject to overriding royalties.

Transportation

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

Operating

Q4 2016 operating expense on a per boe basis increased versus Q3 2016 and Q4 2015 due to increased project activity and lower recoveries.

Year-over-year, 2016 operating expense decreased by 9% on a dollar basis while growing production by 7% resulting in a 14% per unit decrease as a result of focus on initiatives to reduce our cost structure.

General and administration

Variances in general and administration expense from quarter to quarter relate to timing of expenditures, including the timing of allocations from Vermilion’s Corporate segment.

Year-over-year the decrease in general and administration is primarily due to lower head office allocations.

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 abandonment retirement obligations, at a tax rate of 50%.

Current income taxes in Q4 2016 were lower compared to Q3 2016 due to increased tax deductions for current year capital expenditures. Q4 2016 current income taxes were lower compared to Q4 2015 mainly due to decreased sales.

Current income taxes for the year ended December 31, 2016 were lower versus the comparative period in 2015 due to decreased operating income in 2016, partially offset by additional tax deductions for capital expenditures in 2015.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

GERMANY BUSINESS UNIT

Overview

Vermilion entered Germany in February 2014.

Hold a 25% interest in a four partner consortium. 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 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 110,000 net acres (100% working interest) across two exploration licenses in the Lower Saxony basin in 2015.

In December 2016, Vermilion closed the acquisition of operated and non-operated interests in five oil and three gas producing fields from Engie E&P Deutschland GmbH. Vermilion will assume operatorship of six of the eight producing fields. During 2016, the assets produced approximately 2,000 boe/d (50% oil), representing our first operated producing properties in Germany.

Operational and financial review

		Three Months Ended			% change		Year Ended		% change
Germany business unit		Dec 31,	Sep 30,	Dec 31,	Q4/16 vs.	Q4/16 vs.	Dec 31,	Dec 31,	2016 vs.
($M except as indicated)		2016	2016	2015	Q3/16	Q4/15	2016	2015	2015
Production and sales
	Natural gas (mmcf/d)	14.80	14.52	16.17	2%	(8%)	14.90	15.78	(6%)
	Total (boe/d)	2,467	2,420	2,695	2%	(8%)	2,483	2,630	(6%)
Activity
	Capital expenditures	1,694	978	(441)	73%	(484%)	3,803	5,363	(29%)
	Acquisitions	48,377	-	-			48,377	-
	Gross wells drilled	-	-	-			-	1.00
	Net wells drilled	-	-	-			-	0.25
Financial results
	Sales	8,294	6,783	9,840	22%	(16%)	29,049	41,384	(30%)
	Royalties	(12)	(246)	(1,166)	(95%)	(99%)	(2,089)	(6,479)	(68%)
	Transportation	(375)	(556)	(508)	(33%)	(26%)	(2,869)	(3,269)	(12%)
	Operating	(3,959)	(3,321)	(4,788)	19%	(17%)	(12,379)	(10,956)	13%
	General and administration	(1,755)	(1,657)	(3,032)	6%	(42%)	(8,314)	(7,386)	13%
	Fund flows from operations	2,193	1,003	346	119%	534%	3,398	13,294	(74%)
Netbacks ($/boe)
	Sales	36.54	30.47	39.68	20%	(8%)	31.97	43.10	(26%)
	Royalties	(0.06)	(1.10)	(4.70)	(95%)	(99%)	(2.30)	(6.75)	(66%)
	Transportation	(1.65)	(2.50)	(2.05)	(34%)	(20%)	(3.16)	(3.41)	(7%)
	Operating	(17.44)	(14.92)	(19.31)	17%	(10%)	(13.62)	(11.41)	19%
	General and administration	(7.73)	(7.44)	(12.22)	4%	(37%)	(9.15)	(7.69)	19%
	Fund flows from operations netback	9.66	4.51	1.40	114%	590%	3.74	13.84	(73%)
Reference prices
	TTF ($/mmbtu)	7.21	5.43	7.28	33%	(1%)	6.00	8.23	(27%)
	TTF (€/mmbtu)	5.01	3.73	4.98	34%	1%	4.09	5.80	(29%)

Production

Q4 2016 production remained consistent with the prior quarter, and decreased 8% versus Q4 2015 and 6% for the full year 2016 versus 2015 mainly due to natural declines.

Activity review

In 2016, the majority of activity was associated with permitting and pre-drill activities for the Burgmoor Z5 well.

During December 2016, we completed the acquisition of oil and gas producing properties from Engie E&P Deutschland GmbH, which provides us with our first operated production in the country.

In 2017, we plan to continue our ongoing analysis of the geologic data associated with the farm-in assets and to continue integration activities associated with the Engie acquisition. We will also continue permitting and pre-drill activities associated our first operated well in Germany, Burgmoor Z5 well (25% working interest) in the Dümmersee-Uchte area, which we plan to drill in 2018.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Sales

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

Q4 2016 sales per boe increased versus Q3 2016, consistent with an increase in the TTF reference price. Q4 2016 sales per boe decreased versus Q4 2015 as a result of a decrease in the TTF month-ahead index on which sales in Germany are primarily based.

For the year ended December 31, 2016, sales per boe decreased compared to 2015, consistent with a decline in the TTF reference price.

Royalties

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

Q4 2016 royalties as a percentage of sales was a negligible amount versus 3.6% in Q3 2016 and 11.8% in Q4 2015. The decrease in Q4 2016 was due to favourable adjustments from prior periods.

Full year 2016 royalties as a percentage of sales was 7.2% versus 15.7% in 2015 as a result of favourable prior year adjustments impacting 2016.

Transportation

Transportation expense in Germany relates to costs incurred to deliver natural gas from the processing facility to the customer.

Q4 2016 transportation expense decreased from Q3 2016 due to seasonal changes in the level of transportation facility maintenance, which is typically higher at the beginning of the year.

Year-over-year transportation expense decreased due to a decrease in volumes and a reduction in unfavourable prior period adjustments in 2016.

Operating

Operating expenses for Germany primarily relate to tariffs charged for facility operations and gas processing.

Operating expense for Q4 2016 increased versus Q3 2016 due to increased project activity.

Full year operating expense was higher on a dollar and per boe basis due to an unfavorable adjustment from the prior year recorded in 2016 and increased project activity.

General and administration

Q4 2016 general and administration expense was higher than Q3 2016 and lower than Q4 2015 due to timing of head office allocations.

Full year 2016 general and administration expense increased over 2015 due to higher staffing levels and office costs incurred to support our farm-in agreement as well as costs incurred to support asset acquisition activity.

We expect per unit general and administration costs to improve as our production base in Germany grows.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

IRELAND BUSINESS UNIT

Overview

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

Project comprises six offshore wells, offshore and onshore sales and transportation pipeline segments as well as a natural gas processing facility.

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		Dec 31,	Sep 30,	Dec 31,	Q4/16 vs.	Q4/16 vs.	Dec 31,	Dec 31,	2016 vs.
($M except as indicated)		2016	2016	2015	Q3/16	Q4/15	2016	2015	2015
Production and sales
	Natural gas (mmcf/d)	62.92	59.28	0.12	6%	52,771%	50.89	0.03	169,547%
	Total (boe/d)	10,486	9,879	20.00	6%	52,330%	8,482	5.00	169,540%
Activity
	Capital expenditures	1,711	2,416	12,493	(29%)	(86%)	9,375	66,409	(86%)
Financial results
	Sales	42,727	26,065	57	64%	74,860%	109,156	57	191,402%
	Transportation	(1,703)	(1,576)	(1,580)	8%	8%	(6,492)	(6,687)	(3%)
	Operating	(5,148)	(4,695)	(15)	10%	34,220%	(18,646)	(15)	124,207%
	General and administration	(1,523)	(955)	(714)	59%	113%	(4,772)	(2,517)	90%
	Fund flows from operations	34,353	18,839	(2,252)	82%	(1,625%)	79,246	(9,162)	(965%)
Netbacks ($/boe)
	Sales	44.29	28.68	-	54%	100%	35.16	-	100%
	Transportation	(1.77)	(1.73)	-	2%	100%	(2.09)	-	100%
	Operating	(5.34)	(5.17)	-	3%	100%	(6.01)	-	100%
	General and administration	(1.58)	(1.05)	-	50%	100%	(1.54)	-	100%
	Fund flows from operations netback	35.60	20.73	-	72%	100%	25.52	-
Reference prices
	NBP ($/mmbtu)	7.51	5.29	7.41	42%	1%	6.15	8.33	(26%)
	NBP (€/mmbtu)	5.22	3.63	5.07	44%	3%	4.19	5.87	(29%)

Production

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.

Q4 2016 production increased 6% quarter-over-quarter due to reduced downtime. Full year production averaged 51 mmcf/d (8,482 boe/d) while ramping up to full capacity.

Production results continued to benefit from better than expected well deliverability and minimal downtime.

Activity review

Following the conclusion of a successful offshore work campaign in Q3 2016 that included laying a flowline to the P2 well, all six wells are now available for production.

Sales

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

Q4 2016 sales per boe increased relative to Q3 2016, consistent with an increase in the NBP reference price.

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 2016 transportation expense increased versus Q3 2016 and Q4 2015 due to a prior period adjustment in the current quarter offsetting the decrease in the ship-or-pay obligation.

Full year 2016 transportation expense decreased versus 2015 due to the decrease in the ship or pay obligation.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Operating

Q4 2016 operating expense on a per unit basis was consistent with Q3 2016, contributing to full year 2016 per unit costs of $6.01/boe.

General and administration

General and administrative expense for the three months ended December 31, 2016 was higher versus Q3 2016 due to timing of expenditures.

General and administrative expense for the three months and year ended December 31, 2016 was higher than the comparable periods in 2015 due to increased corporate support provided in the first full year of operations.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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		Dec 31,	Sep 30,	Dec 31,	Q4/16 vs.	Q4/16 vs.	Dec 31,	Dec 31,	2016 vs.
($M except as indicated)		2016	2016	2015	Q3/16	Q4/15	2016	2015	2015
Production
	Crude oil (bbls/d)	6,388	6,562	7,824	(3%)	(18%)	6,304	6,454	(2%)
Sales
	Crude oil (bbls/d)	6,038	8,041	8,873	(25%)	(32%)	6,197	6,351	(2%)
Inventory (mbbls)
	Opening crude oil inventory	82	218	172	(62%)	(52%)	75	37	103%
	Crude oil production	588	604	720	(3%)	(18%)	2,307	2,356	(2%)
	Crude oil sales	(555)	(740)	(817)	(25%)	(32%)	(2,267)	(2,318)	(2%)
	Closing crude oil inventory	115	82	75			115	75
Activity
	Capital expenditures	5,236	6,908	40,852	(24%)	(87%)	59,910	61,741	(3%)
	Gross wells drilled	-	-	1.00			2.00	1.00
	Net wells drilled	-	-	1.00			2.00	1.00
Financial results
	Sales	38,352	44,835	47,952	(14%)	(20%)	136,835	162,765	(16%)
	Operating	(14,905)	(13,011)	(13,941)	15%	7%	(47,507)	(51,676)	(8%)
	General and administration	(1,998)	(1,289)	(1,768)	55%	13%	(6,400)	(5,754)	11%
	PRRT	(1,568)	272	(1,054)	(676%)	49%	(1,568)	(6,878)	(77%)
	Current income taxes	(2,703)	(2,916)	1,201	(7%)	(325%)	(7,522)	(7,230)	4%
	Fund flows from operations	17,178	27,891	32,390	(38%)	(47%)	73,838	91,227	(19%)
Netbacks ($/boe)
	Sales	69.05	60.61	58.74	14%	18%	60.33	70.22	(14%)
	Operating	(26.83)	(17.59)	(17.08)	53%	57%	(20.95)	(22.29)	(6%)
	General and administration	(3.60)	(1.74)	(2.17)	107%	66%	(2.82)	(2.48)	14%
	PRRT	(2.82)	0.37	(1.29)	(862%)	119%	(0.69)	(2.97)	(77%)
	Current income taxes	(4.87)	(3.94)	1.47	24%	(431%)	(3.32)	(3.12)	6%
	Fund flows from operations netback	30.93	37.71	39.67	(18%)	(22%)	32.55	39.36	(17%)
Reference prices
	Dated Brent (US $/bbl)	49.46	45.85	43.69	8%	13%	43.69	52.46	(17%)
	Dated Brent ($/bbl)	65.97	59.84	58.34	10%	13%	57.92	67.09	(14%)

Production

Q4 2016 production decreased 3% quarter-over-quarter and 18% year-over-year. The year-over-year decrease is primarily due to production decline from the horizontal sidetrack well drilled and placed on production in Q4 2015. Full year 2016 production decreased 2% versus 2015.

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 production levels of between 6,000 and 8,000 bbls/d.

Activity review

The two sidetrack wells we drilled during Q2 2016 continued to demonstrate strong productive capability with combined production rates of approximately 4,300 bbls/d when utilized. Vermilion intends to produce these wells intermittently to meet corporate production targets while seeking to optimize ultimate recoveries and oil pricing. Following our successful 2015 and 2016 drilling campaigns, we do not expect to drill any additional wells in Australia until 2019.

Additional 2016 activity included work on our Wandoo Platforms Life Extension project, CALM buoy maintenance and subsea inspections.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Sales

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

Q4 2016 sales per boe increased versus Q3 2016 and Q4 2015 consistent with an increase in the Dated Brent reference price. This increase in price was offset by lower sold volumes due to an inventory build in Q4 2016, resulting in a decrease in sales.

Sales per boe for the year ended December 31, 2016 decreased versus the comparable period in 2015 consistent with a decrease in the Dated Brent reference price.

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 dollar per boe basis increased in Q4 2016 versus Q3 2016 and Q4 2015. The increase was a result of increased project and maintenance work being completed in the current quarter as a result of the drill program being executed earlier in the year.

Operating expense on a dollar and per boe basis decreased in 2016 versus 2015 due to a continued focus on initiatives to reduce our cost structure resulting in lower diesel, vessel and maintenance costs.

General and administration

Fluctuation in general and administration expense for Q4 2016 versus the comparable quarters was largely the result of the timing of expenditures. Full year 2016 general and administration expense increased due to higher employee benefit costs.

PRRT and corporate 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 2016 were lower compared to Q3 2016 due to decreased sales. Q4 2016 current income taxes were higher compared to Q4 2015 as decreased sales were offset by lower tax deductions.

Current income taxes for the year ended December 31, 2016 were slightly higher versus the comparable period in 2015 as lower sales were offset with increased deductions for PRRT and foreign exchange in 2015.

PRRT in Q4 2016 was higher compared to Q3 2016 due to the impact of an increase in full year sales (resulting from a significant increase in crude oil pricing) compared to our forecast in Q3 2016. Q4 2016 PRRT was higher compared to Q4 2015 as lower sales were offset with higher deductions for capital expenditures in Q4 2015.

PRRT for the year ended December 31, 2016, was lower versus the comparable period in 2015 as a result of decreased sales.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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		Dec 31,	Sep 30,	Dec 31,	Q4/16 vs.	Q4/16 vs.	Dec 31,	Dec 31,	2016 vs.
($M except as indicated)		2016	2016	2015	Q3/16	Q4/15	2016	2015	2015
Production and sales
	Crude oil (bbls/d)	362	383	420	(5%)	(14%)	393	231	70%
	NGLs (bbls/d)	23	30	29	(23%)	(21%)	29	7	314%
	Natural gas (mmcf/d)	0.18	0.20	0.20	(10%)	(13%)	0.21	0.05	312%
	Total (boe/d)	414	447	483	(7%)	(14%)	457	247	85%
Activity
	Capital expenditures	4,037	2,765	5,643	46%	(28%)	13,539	12,250	11%
	Acquisitions	377	11	(21)			5,935	12,764
	Gross wells drilled	1.00	-	2.00			1.00	3.00
	Net wells drilled	1.00	-	2.00			1.00	3.00
Financial results
	Sales	2,041	1,833	1,864	11%	9%	7,314	4,288	71%
	Royalties	(611)	(525)	(551)	16%	11%	(2,167)	(1,257)	72%
	Operating	(301)	(432)	(271)	(30%)	11%	(1,314)	(742)	77%
	General and administration	(877)	(918)	(897)	(4%)	(2%)	(3,624)	(3,836)	(6%)
	Fund flows from operations	252	(42)	145	700%	74%	209	(1,547)	114%
Netbacks ($/boe)
	Sales	53.58	44.53	41.94	20%	28%	43.70	47.53	(8%)
	Royalties	(16.05)	(12.74)	(12.40)	26%	29%	(12.95)	(13.93)	(7%)
	Operating	(7.91)	(10.50)	(6.11)	(25%)	29%	(7.85)	(8.23)	(5%)
	General and administration	(23.02)	(22.30)	(20.18)	3%	14%	(21.65)	(42.51)	(49%)
	Fund flows from operations netback	6.60	(1.01)	3.25	753%	103%	1.25	(17.14)	107%
Realized prices
	Crude oil ($/bbl)	59.09	51.29	47.59	15%	24%	49.86	50.49	(1%)
	NGLs ($/bbl)	19.48	5.14	5.13	279%	280%	7.38	5.13	44%
	Natural gas ($/mmbtu)	1.93	0.64	0.52	202%	271%	0.85	0.52	63%
	Total ($/boe)	53.58	44.53	41.94	20%	28%	43.70	47.53	(8%)
Reference prices
	WTI (US $/bbl)	49.29	44.94	42.18	10%	17%	43.32	48.80	(11%)
	WTI ($/bbl)	65.75	58.65	56.32	12%	17%	57.42	62.41	(8%)
	Henry Hub (US $/mmbtu)	2.98	2.81	2.27	6%	31%	2.46	2.66	(8%)
	Henry Hub ($/mmbtu)	3.98	3.67	3.03	8%	31%	3.27	3.41	(4%)

Production

Q4 2016 production decreased 7% quarter-over-quarter and 14% year-over-year due to natural declines.

Full year 2016 production increased 85% versus 2015 due to production from our two wells drilled in the East Finn prospect in Q4 2015.

Activity

In Q4 2016, we completed the Seedy Draw East Federal well. The nearly 1,400 metre horizontal lateral was stimulated with 32 frac stages, but due to a screen-out during treatment, only 23 stages were completed. We plan to clean sand out of this well and put it on production during Q1 2017, leaving the remaining nine stages for potential stimulation at a later date.

During 2016, we drilled one (1.0 net) well, and completed and tied-in two (2.0 net) wells drilled in Q4 2015.

In 2017, we plan to drill and complete three (3.0 net) wells.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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 2016 sales per boe increased versus Q3 2016 and Q4 2015 consistent with an increase in the WTI reference price.

Sales per boe for the year ended December 31, 2016 decreased versus the comparable period in 2015, consistent with a decrease in the WTI reference price.

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 30% and has remained consistent across all periods.

Operating

The decrease in operating expense for Q4 2016 compared to Q3 2016 and increase from Q4 2015 were primarily due to timing of maintenance and repair activity.

On a year-over-year basis, per unit costs have decreased 5% due to production growth and initiatives to reduce our cost structure.

General and administration

On a year-over-year basis initiatives taken to reduce our cost structure have resulted in a 6% reduction in costs while growing production 85%.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2016	2016	2015	2016	2015
General and administration recovery (expense)	1,987	(509)	3,356	2,733	7,172
Current income taxes	(370)	(321)	313	(1,097)	(1,091)
Interest expense	(14,410)	(14,150)	(16,584)	(56,957)	(59,852)
Realized gain on derivatives	1,920	13,532	21,164	65,376	41,356
Realized foreign exchange gain (loss)	1,291	2,073	(252)	4,041	623
Realized other income (expense)	120	(82)	243	205	896
Fund flows from operations	(9,462)	543	8,240	14,301	(10,896)

General and administration

Fluctuations in general and administration costs for Q4 2016 versus all comparable periods is due to the timing of expenditures and 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

Interest expense in Q4 2016 was relatively consistent with Q3 2016.

The decrease in interest expense for the three months and year ended December 31, 2016 compared to the same periods in 2015, was primarily due to the retiring of our 6.5% senior unsecured notes in February 2016 using funds from our revolving credit facility, partially offset by higher average borrowings under our revolving credit facility.

Hedging

The nature of our operations results in exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates. We monitor and, when appropriate, use derivative financial instruments to manage our exposure to these fluctuations and reduce cash flow volatility. All transactions of this nature entered into are related to an underlying financial position or to future crude oil and natural gas production. We do not use derivative financial instruments for speculative purposes. We have elected not to designate any of our derivative financial instruments as accounting hedges and thus account for changes in fair value in net earnings at each reporting period. We have not obtained collateral or other security to support our financial derivatives as we review the creditworthiness of our counterparties prior to entering into derivative contracts.

Our hedging philosophy is to hedge solely for the purposes of risk mitigation. Our approach is to hedge centrally to manage our global risk (typically with an outlook of 12 to 18 months) up to 50% of net of royalty volumes through a portfolio of collars and swaps. We currently have European gas contracts for 2019 as an exception to our typical horizon.

We believe that our hedging philosophy and approach increases the stability of revenues, cash flows, and future dividends while also assisting us in the execution of our capital and development plans.

The realized gain on derivatives in 2016 related primarily to amounts received on our European natural gas hedges.

A listing of derivative positions as at December 31, 2016 is included in “Supplemental Table 2” of this MD&A.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

FINANCIAL PERFORMANCE REVIEW

		Year Ended
		Dec 31,	Dec 31,	Dec 31,
($M except per share)		2016	2015	2014
Total assets		4,087,184	4,209,220	4,386,091
Long-term debt		1,362,192	1,162,998	1,238,080
Petroleum and natural gas sales		882,791	939,586	1,419,628
Net (loss) earnings		(160,051)	(217,302)	269,326
Net (loss) earnings per share
	Basic	(1.38)	(1.98)	2.55
	Diluted	(1.38)	(1.98)	2.51
Cash dividends ($/share)		2.58	2.58	2.58

		Three Months Ended
		Dec 31,	Sep 30,	Jun 30,	Mar 31,	Dec 31,	Sep 30,	Jun 30,	Mar 31,
($M except per share)		2016	2016	2016	2016	2015	2015	2015	2015
Petroleum and natural gas sales		259,891	232,660	212,855	177,385	234,319	245,051	264,331	195,885
Net (loss) earnings		(4,032)	(14,475)	(55,696)	(85,848)	(142,080)	(83,310)	6,813	1,275
Net (loss) earnings per share
	Basic	(0.03)	(0.12)	(0.48)	(0.76)	(1.28)	(0.76)	0.06	0.01
	Diluted	(0.03)	(0.12)	(0.48)	(0.76)	(1.28)	(0.76)	0.06	0.01

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

	Three Months Ended			Year Ended
	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
	2016	2016	2015	2016	2015
Fund flows from operations	149,582	140,974	136,441	510,791	516,167
Equity based compensation	(19,489)	(15,642)	(21,533)	(69,235)	(75,232)
Unrealized (loss) gain on derivative instruments	(74,943)	332	27,393	(137,993)	43,548
Unrealized foreign exchange (loss) gain	(2,457)	2,899	(6,357)	(792)	8,787
Unrealized income (expense)	-	(24)	(234)	(131)	(1,008)
Accretion	(6,308)	(6,341)	(6,324)	(24,783)	(23,911)
Depletion and depreciation	(126,855)	(143,556)	(107,812)	(528,002)	(458,758)
Deferred taxes	54,437	6,883	(32,031)	82,855	47,728
Gain on business combination	22,001	-	-	22,001	-
Impairment	-	-	(131,623)	(14,762)	(274,623)
Net loss	(4,032)	(14,475)	(142,080)	(160,051)	(217,302)

The 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 amounts 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 in Q4 2016 increased as compared to Q3 2016 due to a revision of performance estimates. For the three months and year ended December 31, 2016, the decrease in equity based compensation is primarily due to the lower average grant value.

Unrealized gain or loss on derivative instruments

Unrealized gain or loss on derivative instruments arise as a result of changes in forecasted future commodity prices. 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 forecasted future commodity prices decline and vice-versa.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

For the year ended December 31, 2016, we recognized an unrealized loss on derivative instruments of $138.0 million. This unrealized loss resulted from realizing gains on derivatives for contracts settled during the period, coupled with higher forward prices for European natural gas as at December 31, 2016. As at December 31, 2016, we have a net derivative liability position of $69.7 million.

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, primarily denominated in the US dollar and Euro.

Unrealized foreign exchange gains and losses result from translating these monetary assets and liabilities from their underlying currency to the functional currency of Vermilion and its subsidiaries. Unrealized foreign exchange primarily results from the translation of Euro denominated financial assets and US dollar denominated financial liabilities. 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, 2016, the Canadian dollar weakened against the US dollar and strengthened against the Euro, resulting in an unrealized foreign exchange loss of $2.5 million. For the year ended December 31, 2016, the Canadian dollar strengthened more significantly against the Euro than the US dollar, resulting in an unrealized foreign exchange loss of $0.8 million.

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 capitalized cost of extracting natural resources and the cost of material assets over the useful life of the respective assets. Fluctuations in depletion and depreciation expense are primarily the result of changes in produced crude oil and natural gas volumes.

Depletion and depreciation on a per boe basis for Q4 2016 of $22.42 was relatively consistent as compared to $23.69 in Q3 2016.

For the three months ended December 31, 2016, depletion and depreciation on a per boe basis of $22.42 was higher than $18.88 in the same period of 2015 due to production from Ireland. For the year ended December 31, 2016, depletion and depreciation on a per boe basis of $22.65 was relatively consistent with $22.98 in the same period of 2015 as increased production from Ireland was offset by increased production from our Mannville condensate-rich gas properties.

Deferred tax

Deferred tax recovery arises primarily as a result of changes in the accounting basis and tax basis for capital assets and asset retirement obligations and changes in available tax losses.

Impairment

In 2015, as a result of declines in price forecasts for crude oil and Canadian natural gas, Vermilion recorded a non-cash impairment charge of $274.6 million ($219.8 million relating to capital assets and $54.8 million relating to E&E assets) in the Canada segment. The impairment charge related to the light crude oil play in Saskatchewan ($267.9 million based on a recoverable amount of $266.8 million) and shallow coal bed methane properties in Alberta ($6.7 million based on a recoverable amount of $19.7 million).

In the first quarter of 2016, as a result of declines in price forecasts for European natural gas, Vermilion recorded a non-cash impairment charge of $14.8 million (based on a recoverable amount of $737.3 million).

Gain on business combination

In December of 2016, we acquired, through a wholly-owned subsidiary, interests in production and exploration assets in Germany from Engie E&P Deutschland GmbH.

We recognized a non-cash gain on business combination of $22.0 million that resulted from the recognition of additional reserve value when the acquisition closed in December 2016, compared to the estimated value in June when Vermilion entered into a definitive purchase and sale agreement and the acquisition price was determined.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

TAXES

Corporate income tax rates

Vermilion pays corporate income taxes in France, the Netherlands, and Australia. In addition, Vermilion pays 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.

Taxable income was subject to corporate income tax at the following rates:

Jurisdiction	2016	2015
Canada ⁽¹⁾	27.0%	25.5% / 27.0%
France	34.4%	34.4%
Netherlands ⁽²⁾	50.0%	50.0%
Germany	24.2%	24.2%
Ireland	25.0%	25.0%
Australia	30.0%	30.0%
United States	35.0%	35.0%
⁽¹⁾Alberta corporate income tax rates increased from 10% to 12% effective July 1, 2015.
⁽²⁾In the Netherlands, an additional 10% uplift deduction is allowed against taxable income that is applied to operating expenses, eligible G&A and tax deductions for depletion and abandonment retirement obligations.

In 2012, the France government enacted a new 3% tax on dividend distributions made by entities subject to corporate income tax in France. The tax applies to any dividends paid on or after April 17, 2012 and is not recovered by any tax treaties or deductible for French corporate income tax purposes. In late December 2016, the French government passed legislation that will exempt any dividend distributions made by Vermilion after January 1, 2017 from the 3% tax. Vermilion did not pay any dividends from its French entities in 2016.

Tax pools

As at December 31, 2016, we had the following tax pools:

($M)	Oil & Gas Assets	Tax Losses	Other	Total
Canada	978,949 ⁽¹⁾	489,702 ⁽⁵⁾	32,503	1,501,154
France	351,551 ⁽²⁾	13,360 ⁽⁶⁾	-	364,911
Netherlands	68,139 ⁽³⁾	- ⁽⁰⁾	-	68,139
Germany	190,002 ⁽³⁾	57,156 ⁽⁷⁾	20,306	267,464
Ireland	942,129 ⁽⁴⁾	403,779 ⁽⁵⁾	-	1,345,908
Australia	276,911 ⁽¹⁾	- ⁽⁰⁾	-	276,911
United States	34,885 ⁽¹⁾	30,328 ⁽⁵⁾	797	66,010
Total	2,842,566 ⁽¹⁾	994,325 ⁽⁰⁾	53,606	3,890,497

⁽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⁾Deduction for current development expenditures and tax losses at 100% against taxable income

⁽⁵⁾Tax losses can be carried forward at 100% against taxable income

⁽⁶⁾Tax losses carried forward are available to offset the first Euro 1million of taxable income and 50% of taxable profits in excess each taxation year

⁽⁷⁾Tax losses carried forward are available to offset the first Euro 1million of taxable income and 60% of taxable profits in excess each taxations year

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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 and typically strive to maintain an internally targeted ratio of approximately 1.0 to 1.5 in a normalized commodity price environment. Where prices trend higher, we may target a lower ratio and conversely, in a lower commodity price environment, an acceptable ratio may be higher. At times, we will use our balance sheet to finance acquisitions and, in these situations, we are prepared to accept a higher ratio in the short term but will implement a strategy to reduce the ratio to acceptable levels within a reasonable period of time, usually considered to be no more than 12 to 24 months. This plan could potentially include an increase in hedging activities, a reduction in capital expenditures, an issuance of equity or the utilization of excess fund flows from operations to reduce outstanding indebtedness.

In the current low commodity price environment, Vermilion’s net debt to fund flows from operations ratio is expected to be higher than the internally targeted ratio. During this period, Vermilion will remain focused on maintaining a strong balance sheet by aligning capital expenditures within forecasted fund flows from operations, which is continually monitored for revised forward price estimates, as well as by hedging additional European natural gas volumes to maintain a diversified commodity portfolio.

Long-term debt

Our long-term debt as at December 31, 2016 consists entirely of borrowings against our revolving credit facility. We redeemed the senior unsecured notes that came due on February 10, 2016 using funds drawn against the revolving credit facility.

The balances recognized on our balance sheet are as follows:

	As at
	Dec 31,	Dec 31,
($M)	2016	2015
Revolving credit facility	1,362,192	1,162,998
Senior unsecured notes	-	224,901
Long-term debt	1,362,192	1,387,899

Revolving Credit Facility

The following table outlines the current terms of our revolving credit facility:

	As at
	Dec 31,	Dec 31,
($M)	2016	2015
Total facility amount	2,000,000	2,000,000
Amount drawn	(1,362,192)	(1,162,998)
Letters of credit outstanding	(20,100)	(25,200)
Unutilized capacity	617,708	811,802

In addition, as at December 31, 2016, the revolving credit facility was subject to the following covenants:

		As at
		Dec 31,	Dec 31,
Financial covenant	Limit	2016	2015
Consolidated total debt to consolidated EBITDA	4.0	2.36	2.23
Consolidated total senior debt to total capitalization	55%	46%	36%

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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”, “Current portion of 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.

Net debt

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

	As at
	Dec 31,	Dec 31,
($M)	2016	2015
Long-term debt	1,362,192	1,162,998
Current liabilities⁽¹⁾	290,862	503,731
Current assets	(225,906)	(284,778)
Net debt	1,427,148	1,381,951

Ratio of net debt to fund flows from operations	2.8	2.7

⁽¹⁾

Current liabilities at December 31, 2015 includes $224,901 relating to the current portion of long-term debt.

As at December 31, 2016, long term debt decreased to $1.36 billion (December 31, 2015 - $1.39 billion, including the current portion of long-term debt) as fund flows from operations generated in excess of capital expenditures, abandonment expenditures, acquisitions, and cash dividends was used to reduce debt. The decrease in long-term debt was coupled with working capital changes, such that net debt increased from $1.38 billion at December 31, 2015 to $1.43 billion at December 31, 2016. Weaker commodity prices versus the prior period decreased fund flows from operations, resulting in the ratio of net debt to fund flows from operations increasing slightly from 2.7 to 2.8.

Shareholders’ capital

During the year ended December 31, 2016, we maintained monthly dividends at $0.215 per share and declared dividends which totalled $299.1 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

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.

In February of 2015, we amended our existing dividend reinvestment plan to include a Premium Dividend™ Component. The Premium Dividend™ Component, when combined with our continuing Dividend Reinvestment Component, increases our access to the lowest cost sources of equity capital available. While the Premium Dividend™ results in a modest amount of equity issuance, we believe it represents the most prudent approach to preserving near-term balance sheet strength. Both components of our program can be reduced or eliminated at the company’s discretion, offering considerable flexibility.

As previously announced, we commenced proration of the Premium Dividend™ of our Dividend Reinvestment Plan by 25% beginning with our October dividend payment. Eligible shareholders who have elected to participate in the Premium Dividend^TM component were then receiving the 1.5% premium on 75% of their participating shares and the regular cash dividend on the remaining 25% of their shares. We increased the proration factor by a further 25% beginning with the January 2017 dividend payment. Subject to unexpected changes in the commodity price outlook, we expect to continue to increase the proration by 25% per quarter during the first half of 2017, such that, by the beginning of the third quarter, there would be no further equity issuance under the Premium Dividend^TM component of our Dividend Reinvestment Plan. We also reduced the discount associated with our traditional Dividend Reinvestment Plan from 3% to 2%, beginning with the January 2017 dividend payment.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Although we expect to be able to maintain our current dividend, fund flows from operations may not be sufficient during this low commodity price environment 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, 2015		111,991	2,181,089
Shares issued for the DRIP⁽¹⁾		4,671	192,998
Vesting of equity based awards		1,320	67,146
Share-settled dividends on vested equity based awards		87	3,242
Shares issued for equity based compensation		194	8,247
Balance as at December 31, 2016		118,263	2,452,722

⁽¹⁾ DRIP Refers to Vermilion’s Premium Dividend^TM and Dividend Reinvestment Plan.

As at December 31, 2016, there were approximately 1.7 million VIP awards outstanding. As at February 24, 2017, there were approximately 118.7 million common shares issued and outstanding.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

As at December 31, 2016, 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	-	1,335,600	-	-	1,335,600
Operating lease obligations	12,683	21,087	18,228	1,657	53,655
Ship or pay agreement relating to the Corrib project	4,241	7,331	6,074	31,427	49,073
Purchase obligations	9,007	3,852	7	-	12,866
Drilling and service agreements	5,437	9,850	20,511	26,870	62,668
Total contractual obligations and commitments	31,368	1,377,720	44,820	59,954	1,513,862

ASSET RETIREMENT OBLIGATIONS

As at December 31, 2016, asset retirement obligations were $525.0 million compared to $305.6 million as at December 31, 2015.

The increase in asset retirement obligations is largely attributable to an overall decrease in the discount rates applied to the abandonment obligation, additional obligations recognized on our acquisition in Germany, and accretion expense.

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.

Commodity prices

Our operational results and financial condition is 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 U.S. dollars and as such an increase in the strength of the Canadian dollar relative to the U.S. dollar may result in the receipt of fewer Canadian dollars with respect to our production. In addition, we incur expenses and capital costs in U.S. 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.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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, in Canada, France, the Netherlands, Australia, Germany, Ireland, Hungary, Croatia, Slovakia and the United States. 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.

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.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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 highly 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/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.

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, 2016.

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

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

The following IFRS have been issued by the IASB but are not yet effective:

IFRS 9 “Financial Instruments” will be adopted January 1, 2018. IFRS 9 includes changes to the classification and measurement of financial instruments and general hedge accounting.

IFRS 15 “Revenue from Contracts with Customers” will be adopted January 1, 2018. IFRS 15 specifies recognition and measurement requirements for contracts with customers.

IFRS 16 “Leases” will be adopted January 1, 2019. IFRS 16 requires lessees to recognize a lease obligation and right-of-use asset for the majority of leases.

On the adoption of IFRS 9, Vermilion does not currently anticipate changes to the measured amount of financial instruments and correspondingly does not currently anticipate material changes to net earnings.

In the adoption of IFRS 15, Vermilion has in place a transition team that will perform a detailed review of the Company’s standard contracts with customers in accordance with the issued IFRS.

The 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 2016 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;

Completed and published our Corporate Sustainability Report;

Reported our CO₂e emissions to the Carbon Disclosure Project, achieving a position on the Climate “A” list. One of only 5 oil and gas companies world-wide to achieve this ranking.

Completed a corporate wide HSE perception survey to monitor program progress and verify plan forward;

Emphasized improving energy efficiency, greenhouse gas emissions reduction and water efficiency optimization;

Further refined and expanded our enterprise wide corporate risk register;

Developed and delivered 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 risk and energy type exposures;

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

Implemented our Corporate Process Hazards Analysis Standard in support of our focus on process safety;

Initiated the development of our Corporate Process Safety Management System;

Further progressed our Asset Integrity Management System;

Completed a comprehensive review of our Management of Change procedures across the organization;

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

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

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

Further enhanced of our competency and training programs;

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

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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 regularly communicates with its stakeholders, including shareholders and potential investors, and we continually monitor trends and best practices in stakeholder engagement. Reporting on sustainability, or corporate social responsibility, is an increasingly important way to reflect Company performance for shareholders and potential investors. As a result, Vermilion published its first sustainability report in August 2014, in compliance with the comprehensive option of 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.

Our stakeholders expect us to deliver strong financial results in a responsible and ethical way. Reflecting this, 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.

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.

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

Vermilion’s sustainability performance has earned consistently higher rankings. In 2016, Corporate Knights ranked Vermilion 9^th in their Future 40 listing, up from 15^thin 2015 and 32^nd in 2014.

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).

A summary of the significant differences between the governance practices of the Company and those required of U.S. domestic companies under the New York Stock Exchange listing standards can be found in the Governance section of the Company’s website at http://www.vermilionenergy.com/about/governance.cfm.

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, 2016, 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.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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, 2016. The effectiveness of Vermilion’s internal control over financial reporting as of December 31, 2016 has been audited by Deloitte LLP, as reflected in their report included in the 2016 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, 2016, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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	Year
							Ended Dec	Ended Dec
	Three Months Ended December 31, 2016			Year Ended December 31, 2016			31, 2015	31, 2015
	Crude Oil,			Crude Oil,
	Condensate			Condensate
	& NGLs	Natural Gas	Total	& NGLs	Natural Gas	Total	Total	Total
	$/bbl	$/mcf	$/boe	$/bbl	$/mcf	$/boe	$/boe	$/boe
Canada
Sales	51.77	3.05	33.48	43.58	2.14	26.81	28.94	34.32
Royalties	(6.17)	(0.22)	(3.51)	(4.37)	(0.09)	(2.28)	(2.80)	(3.01)
Transportation	(2.34)	(0.18)	(1.66)	(2.36)	(0.17)	(1.63)	(1.48)	(1.75)
Operating	(9.49)	(1.32)	(8.62)	(8.05)	(1.20)	(7.59)	(9.62)	(9.54)
Operating netback	33.77	1.33	19.69	28.80	0.68	15.31	15.04	20.02
General and administration			(0.97)			(1.25)	(1.44)	(1.81)
Fund flows from operations netback			18.72			14.06	13.60	18.21
France
Sales	63.99	1.55	63.71	55.42	1.59	55.15	54.20	62.67
Royalties	(5.95)	(0.36)	(5.93)	(6.08)	(0.34)	(6.05)	(6.15)	(6.00)
Transportation	(3.55)	-	(3.53)	(3.32)	-	(3.30)	(3.65)	(3.42)
Operating	(10.13)	(3.12)	(10.17)	(11.15)	(2.51)	(11.17)	(13.50)	(11.30)
Operating netback	44.36	(1.93)	44.08	34.87	(1.26)	34.63	30.90	41.95
General and administration			(4.52)			(4.27)	(4.18)	(4.50)
Other income			3.39			0.85	-	7.08
Current income taxes			(2.54)			(0.64)	3.87	(5.29)
Fund flows from operations netback			40.41			30.57	30.59	39.24
Netherlands
Sales	63.18	6.78	40.84	44.93	5.67	34.15	42.61	46.77
Royalties	-	(0.08)	(0.46)	-	(0.08)	(0.50)	(0.26)	(1.12)
Operating	-	(1.49)	(8.90)	-	(1.19)	(7.05)	(7.17)	(8.24)
Operating netback	63.18	5.21	31.48	44.93	4.40	26.60	35.18	37.41
General and administration			(0.26)			(0.52)	(0.93)	(1.51)
Current income taxes			0.16			(2.25)	(3.35)	(4.40)
Fund flows from operations netback			31.38			23.83	30.90	31.50
Germany
Sales	-	6.09	36.54	-	5.33	31.97	39.68	43.10
Royalties	-	(0.01)	(0.06)	-	(0.38)	(2.30)	(4.70)	(6.75)
Transportation	-	(0.28)	(1.65)	-	(0.53)	(3.16)	(2.05)	(3.41)
Operating	-	(2.91)	(17.44)	-	(2.27)	(13.62)	(19.31)	(11.41)
Operating netback	-	2.89	17.39	-	2.15	12.89	13.62	21.53
General and administration			(7.73)			(9.15)	(12.22)	(7.69)
Fund flows from operations netback			9.66			3.74	1.40	13.84
Ireland
Sales	-	7.38	44.29	-	5.86	35.16	-	-
Transportation	-	(0.29)	(1.77)	-	(0.35)	(2.09)	-	-
Operating	-	(0.89)	(5.34)	-	(1.00)	(6.01)	-	-
Operating netback	-	6.20	37.18	-	4.51	27.06	-	-
General and administration			(1.58)			(1.54)	-	-
Fund flows from operations netback			35.60			25.52	-	-
Australia
Sales	69.05	-	69.05	60.33	-	60.33	58.74	70.22
Operating	(26.83)	-	(26.83)	(20.95)	-	(20.95)	(17.08)	(22.29)
PRRT ⁽¹⁾	(2.82)	-	(2.82)	(0.69)	-	(0.69)	(1.29)	(2.97)
Operating netback	39.40	-	39.40	38.69	-	38.69	40.37	44.96
General and administration			(3.60)			(2.82)	(2.17)	(2.48)
Corporate income taxes			(4.87)			(3.32)	1.47	(3.12)
Fund flows from operations netback			30.93			32.55	39.67	39.36

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

							Three Months	Year
							Ended Dec	Ended Dec
	Three Months Ended December 31, 2016			Year Ended December 31, 2016			31, 2015	31, 2015
	Crude Oil,			Crude Oil,
	Condensate			Condensate
	& NGLs	Natural Gas	Total	& NGLs	Natural Gas	Total	Total	Total
	$/bbl	$/mcf	$/boe	$/bbl	$/mcf	$/boe	$/bbl	$/boe
United States
Sales	56.77	1.93	53.58	46.89	0.85	43.70	41.94	47.53
Royalties	(16.49)	(1.72)	(16.05)	(13.71)	(0.62)	(12.95)	(12.40)	(13.93)
Operating	(8.51)	-	(7.91)	(8.50)	-	(7.85)	(6.11)	(8.23)
Operating netback	31.77	0.21	29.62	24.68	0.23	22.90	23.43	25.37
General and administration			(23.02)			(21.65)	(20.18)	(42.51)
Fund flows from operations netback			6.60			1.25	3.25	(17.14)
Total Company
Sales	60.58	5.47	45.93	51.73	4.18	37.88	41.04	47.07
Realized hedging gain	0.45	0.04	0.34	1.45	0.68	2.81	3.71	2.07
Royalties	(4.92)	(0.10)	(2.65)	(4.28)	(0.09)	(2.33)	(2.85)	(3.30)
Transportation	(2.33)	(0.19)	(1.69)	(2.22)	(0.20)	(1.70)	(1.78)	(2.09)
Operating	(13.33)	(1.34)	(10.54)	(11.88)	(1.23)	(9.53)	(11.50)	(11.32)
PRRT ⁽¹⁾	(0.59)	-	(0.28)	(0.14)	-	(0.07)	(0.18)	(0.34)
Operating netback	39.86	3.88	31.11	34.66	3.34	27.06	28.44	32.09
General and administration			(2.03)			(2.27)	(2.18)	(2.68)
Interest expense			(2.55)			(2.44)	(2.90)	(3.00)
Realized foreign exchange gain (loss)			0.23			0.17	(0.04)	0.03
Other income			0.70			0.17	0.04	1.64
Corporate income taxes⁽¹⁾			(1.03)			(0.78)	0.55	(2.22)
Fund flows from operations netback			26.43			21.91	23.91	25.86

⁽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.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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, 2016:

Crude Oil	Period	Exercise date⁽¹⁾	Currency	Bought Put Volume (bbl/d)	Weighted Average Bought Put Price / bbl	Sold Call Volume (bbl/d)	Weighted Average Sold Call Price / bbl	Sold Put Volume (bbl/d)	Weighted Average Sold Put Price / bbl	Swap Volume (bbl/d)	Weighted Average Swap Price / bbl	Additional Swap Volume (mmbtu/d) ⁽²⁾
Dated Brent
3-Way Collar	Oct 2016 - Mar 2017		USD	500	50.00	500	60.00	500	42.50	-	-	-
3-Way Collar	Jan 2017 - Dec 2017		USD	2,500	51.00	2,500	60.50	2,500	41.50	-	-	-
3-Way Collar	Jul 2017 - Jun 2018		USD	2,000	55.00	2,000	64.06	2,000	45.00	-	-	-
Swap	Jan 2017 - Dec 2017		USD	-	-	-	-	-	-	1,250	55.50	-
Swaption	Jul 2017 - Jun 2018	Mar 31, 2017	USD	-	-	-	-	-	-	500	60.00	-
Swaption	Jul 2017 - Jun 2018	Jun 30, 2017	USD	-	-	-	-	-	-	1,000	60.00	-

WTI
3-Way Collar	Jan 2017 - Dec 2017		CAD	1,500	70.00	1,500	75.00	1,500	55.00	-	-	-
3-Way Collar	Jan 2017 - Mar 2017		USD	2,500	50.00	2,500	55.00	2,500	42.50	-	-	-
3-Way Collar	Jul 2017 - Dec 2017		USD	1,500	53.67	1,500	63.00	1,500	45.00	-	-	-
Swap	Jan 2017 - Mar 2017		USD	-	-	-	-	-	-	2,500	53.10	-

North American Gas	Period	Exercise date⁽¹⁾	Currency	Bought Put Volume (mmbtu/d)	Weighted Average Bought Put Price / mmbtu	Sold Call Volume (mmbtu/d)	Weighted Average Sold Call Price / mmbtu	Sold Put Volume (mmbtu/d)	Weighted Average Sold Put Price / mmbtu	Swap Volume (mmbtu/d)	Weighted Average Swap Price / mmbtu	Additional Swap Volume (mmbtu/d) ⁽²⁾
AECO
Collar	Nov 2016 - Oct 2017		CAD	7,109	2.18	9,478	2.86	-	-	-	-	-
Collar	Nov 2016 - Dec 2017		CAD	9,478	2.33	9,478	3.02	-	-	-	-	-
Collar	Jan 2017 - Dec 2017		CAD	4,739	2.37	4,739	3.25	-	-	-	-	-
Swap	Nov 2016 - Dec 2017		CAD	-	-	-	-	-	-	2,370	2.99	-
Swap	Jan 2017 - Mar 2017		CAD	-	-	-	-	-	-	7,109	3.35	-
Swap	Jan 2017 - Dec 2017		CAD	-	-	-	-	-	-	7,109	2.94	-
Swap	Apr 2017 - Oct 2017		CAD	-	-	-	-	-	-	7,109	3.01	-
Swap	Nov 2017 - Dec 2017		CAD	-	-	-	-	-	-	7,109	3.35	-

AECO Basis
Swap	Jan 2017 - Dec 2017		USD	-	-	-	-	-	-	5,000	(0.75)	-
Swap	Jan 2018 - Dec 2018		USD	-	-	-	-	-	-	10,000	(0.83)	-

NYMEX
Swap	Jan 2017 - Dec 2017		USD	-	-	-	-	-	-	5,000	3.00	-

European Gas	Period	Exercise date⁽¹⁾	Currency	Bought Put Volume (mmbtu/d)	Weighted Average Bought Put Price / mmbtu	Sold Call Volume (mmbtu/d)	Weighted Average Sold Call Price / mmbtu	Sold Put Volume (mmbtu/d)	Weighted Average Sold Put Price / mmbtu	Swap Volume (mmbtu/d)	Weighted Average Swap price / mmbtu	Additional Swap Volume (mmbtu/d) ⁽²⁾
NBP
Collar	Apr 2016 - Mar 2017		GBP	2,500	4.00	2,500	4.77	-	-	-	-	-
Collar	Oct 2016 - Mar 2017		GBP	2,500	3.30	5,000	3.72	-	-	-	-	-
Collar	Oct 2016 - Sep 2017		GBP	5,000	3.25	10,000	4.03	-	-	-	-	-
Collar	Oct 2016 - Dec 2017		GBP	5,000	3.25	10,000	4.07	-	-	-	-	-
Collar	Jan 2017 - Dec 2017		GBP	5,000	3.30	7,500	3.77	-	-	-	-	-
Collar	Jan 2018 - Dec 2018		GBP	2,500	3.15	2,500	3.82	-	-	-	-	-
Put	Dec 2016 - Feb 2017		GBP	20,000	4.00	-	-	-	-	-	-	-
Call	Oct 2016 - Mar 2017		GBP	-	-	2,500	4.90	-	-	-	-	-
Swap	Jan 2017 - Dec 2017		GBP	-	-	-	-	-	-	2,500	4.22	2,500
Swap	Apr 2017 - Mar 2018		GBP	-	-	-	-	-	-	5,300	4.20	-
Swap	Jul 2017 - Dec 2017		GBP	-	-	-	-	-	-	2,500	3.95	-
Swap	Jan 2018 - Dec 2018		GBP	-	-	-	-	-	-	2,500	4.04	5,000
Swap	Jul 2016 - Mar 2017		EUR	-	-	-	-	-	-	2,457	5.73	-

⁽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.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

European Gas	Period	Exercise date⁽¹⁾	Currency	Bought Put Volume (mmbtu/d)	Weighted Average Bought Put Price / mmbtu	Sold Call Volume (mmbtu/d)	Weighted Average Sold Call Price / mmbtu	Sold Put Volume (mmbtu/d)	Weighted Average Sold Put Price / mmbtu	Swap Volume (mmbtu/d)	Weighted Average Swap price / mmbtu	Additional Swap Volume (mmbtu/d) ⁽²⁾
TTF
3-Way Collar	Apr 2017 - Sep 2017		EUR	9,827	4.18	9,827	5.06	9,827	3.08	-	-	-
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	9,827	4.67	9,827	5.42	9,827	3.22	-	-	-
3-Way Collar	Jan 2018 - Dec 2019		EUR	3,685	4.74	3,685	5.52	3,685	3.13	-	-	-
Collar	Apr 2016 - Mar 2017		EUR	4,913	5.57	9,827	6.70	-	-	-	-	-
Collar	Jul 2016 - Mar 2017		EUR	2,457	5.35	4,913	6.92	-	-	-	-	-
Collar	Jul 2016 - Mar 2018		EUR	2,457	5.61	4,913	6.90	-	-	-	-	-
Collar	Oct 2016 - Dec 2017		EUR	2,457	5.28	2,457	6.21	-	-	-	-	-
Collar	Jan 2017 - Dec 2017		EUR	9,827	5.06	22,111	6.37	-	-	-	-	-
Collar	Apr 2017 - Sept 2017		EUR	2,457	3.81	4,913	4.47	-	-	-	-	-
Collar	Jan 2018 - Dec 2018		EUR	4,913	4.40	4,913	5.31	-	-	-	-	-
Call	Oct 2016 - Mar 2017		EUR	-	-	2,457	6.36	-	-	-	-	-
Swap	Jul 2016 - Jun 2018		EUR	-	-	-	-	-	-	2,559	5.89	-
Swap	Jan 2017 - Dec 2017		EUR	-	-	-	-	-	-	2,457	5.32	2,457
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	Jan 2019 - Dec 2019		EUR	-	-	-	-	-	-	2,457	4.92	-
Put Spread	Apr 2017 - Sep 2017		EUR	14,740	4.40	-	-	14,740	3.15	-	-	-
Swaption	Apr 2017 - Jun 2018	Mar 31, 2017	EUR	-	-	-	-	-	-	4,913	4.55	-

Fuel and Electricity	Period		Currency							Swap Volume (unit/d)		Weighted Average Swap price / unit
AESO (mwh)
Swap	Jan 2017 - Dec 2017		CAD							65		33.47

Interest Rate										Notional amount		Rate (%)
CDOR Swap	Sep 2015 - Sep 2019		CAD							100,000,000		1.00
CDOR Swap	Oct 2015 - Oct 2019		CAD							100,000,000		1.10

Cross Currency Interest Rate						Receive Notional amount (USD)		Rate (US%)		Pay Notional amount (CAD)		Rate (CAD%)
Swap	Jan 2017 - Feb 2017					891,088,800		3.52		1,195,800,000		3.17

⁽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.

⁽³⁾

In January 2017, Vermilion repaid $1.2 billion of borrowings on the revolving credit facility bearing interest at CDOR plus applicable margins and simultaneously borrowed US $0.9 billion on the revolving credit facility bearing interest at LIBOR plus applicable margins.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Supplemental Table 3: Capital Expenditures and Acquisitions

	Three Months Ended			Year Ended
By classification	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2016	2016	2015	2016	2015
Drilling and development	66,437	41,039	128,996	241,545	486,861
Exploration and evaluation	445	-	-	863	-
Capital expenditures	66,882	41,039	128,996	242,408	486,861

Property acquisition	78,713	10,391	6,227	98,524	28,897
Acquisitions	78,713	10,391	6,227	98,524	28,897

	Three Months Ended			Year Ended
By category	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2016	2016	2015	2016	2015
Land	59	(36)	819	1,555	3,793
Seismic	1,757	1,110	4,217	10,458	8,243
Drilling and completion	38,233	18,694	58,327	121,322	212,358
Production equipment and facilities	26,768	18,046	55,662	86,664	218,963
Recompletions	3,293	603	6,338	8,262	26,689
Other	(3,228)	2,622	3,633	14,147	16,815
Capital expenditures	66,882	41,039	128,996	242,408	486,861
Acquisitions	78,713	10,391	6,227	98,524	28,897
Total capital expenditures and acquisitions	145,595	51,430	135,223	340,932	515,758

	Three Months Ended			Year Ended
By country	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2016	2016	2015	2016	2015
Canada	18,273	20,801	33,723	76,015	216,158
France	31,127	11,110	24,164	68,472	92,582
Netherlands	33,996	6,441	18,810	51,999	47,325
Germany	50,071	978	(441)	52,180	5,363
Ireland	1,711	2,416	12,493	9,375	66,409
Australia	5,236	6,908	40,852	59,910	61,741
United States	4,414	2,776	5,622	19,474	25,014
Corporate	767	-	-	3,507	1,166
Total capital expenditures and acquisitions	145,595	51,430	135,223	340,932	515,758

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Supplemental Table 4: Production

		Q4/16	Q3/16	Q2/16	Q1/16	Q4/15	Q3/15	Q2/15	Q1/15	Q4/14	Q3/14	Q2/14	Q1/14
Canada
	Crude oil & condensate (bbls/d)	7,945	8,984	9,453	10,317	10,413	11,030	11,843	12,163	12,681	12,755	14,108	10,390
	NGLs (bbls/d)	2,444	2,448	2,687	2,633	2,710	2,678	2,094	1,706	1,444	1,005	1,364	1,118
	Natural gas (mmcf/d)	75.12	77.62	87.44	97.16	87.90	71.94	64.66	61.78	58.36	57.07	57.59	49.53
	Total (boe/d)	22,910	24,368	26,713	29,141	27,773	25,698	24,713	24,165	23,851	23,272	25,070	19,763
	% of consolidated	38%	37%	42%	44%	45%	47%	48%	48%	49%	47%	49%	42%
France
	Crude oil (bbls/d)	11,220	11,827	12,326	12,220	12,537	12,310	12,746	11,463	11,133	11,111	11,025	10,771
	Natural gas (mmcf/d)	0.38	0.42	0.54	0.44	1.36	1.47	1.03	-	-	-	-	-
	Total (boe/d)	11,283	11,897	12,416	12,293	12,763	12,555	12,917	11,463	11,133	11,111	11,025	10,771
	% of consolidated	19%	19%	19%	19%	21%	22%	25%	23%	22%	22%	21%	23%
Netherlands
	Condensate (bbls/d)	57	86	96	114	110	109	112	63	81	63	96	69
	Natural gas (mmcf/d)	41.15	47.62	49.18	53.40	56.34	53.56	32.43	36.41	31.35	38.07	40.35	43.15
	Total (boe/d)	6,915	8,023	8,293	9,015	9,500	9,035	5,517	6,132	5,306	6,407	6,822	7,260
	% of consolidated	11%	13%	13%	14%	16%	16%	11%	12%	11%	13%	13%	16%
Germany
	Natural gas (mmcf/d)	14.80	14.52	14.31	15.96	16.17	14.00	16.18	16.80	17.71	15.38	16.13	10.64
	Total (boe/d)	2,467	2,420	2,385	2,660	2,695	2,333	2,696	2,801	2,952	2,563	2,689	1,773
	% of consolidated	4%	4%	4%	4%	4%	4%	5%	6%	6%	5%	5%	4%
Ireland
	Natural gas (mmcf/d)	62.92	59.28	47.26	33.90	0.12	-	-	-	-	-	-	-
	Total (boe/d)	10,486	9,879	7,877	5,650	20	-	-	-	-	-	-	-
	% of consolidated	17%	16%	12%	9%	-	-	-	-	-	-	-	-
Australia
	Crude oil (bbls/d)	6,388	6,562	6,083	6,180	7,824	6,433	5,865	5,672	6,134	6,567	6,483	7,110
	% of consolidated	10%	10%	9%	9%	13%	11%	11%	11%	12%	13%	12%	15%
United States
	Crude oil (bbls/d)	362	383	458	368	420	226	123	153	195	-	-	-
	NGLs (bbls/d)	23	30	26	39	29	-	-	-	-	-	-	-
	Natural gas (mmcf/d)	0.18	0.20	0.20	0.26	0.20	-	-	-	-	-	-	-
	Total (boe/d)	414	447	518	450	483	226	123	153	195	-	-	-
	% of consolidated	1%	1%	1%	1%	1%	-	-	-	-	-	-	-
Consolidated
	Crude oil, condensate
	& NGLs (bbls/d)	28,439	30,320	31,129	31,871	34,043	32,786	32,783	31,220	31,668	31,501	33,076	29,458
	% of consolidated	47%	48%	48%	49%	56%	58%	63%	62%	64%	63%	63%	63%
	Natural gas (mmcf/d)	194.54	199.65	198.93	201.11	162.09	140.97	114.29	115.00	107.42	110.52	114.08	103.32
	% of consolidated	53%	52%	52%	51%	44%	42%	37%	38%	36%	37%	37%	37%
	Total (boe/d)	60,863	63,596	64,285	65,389	61,058	56,280	51,831	50,386	49,571	49,920	52,089	46,677

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

		2016	2015	2014	2013	2012	2011
Canada
	Crude oil & condensate (bbls/d)	9,171	11,357	12,491	8,387	7,659	4,701
	NGLs (bbls/d)	2,552	2,301	1,233	1,666	1,232	1,297
	Natural gas (mmcf/d)	84.29	71.65	55.67	42.39	37.50	43.38
	Total (boe/d)	25,771	25,598	23,001	17,117	15,142	13,227
	% of consolidated	40%	46%	47%	41%	40%	38%
France
	Crude oil (bbls/d)	11,896	12,267	11,011	10,873	9,952	8,110
	Natural gas (mmcf/d)	0.44	0.97	-	3.40	3.59	0.95
	Total (boe/d)	11,970	12,429	11,011	11,440	10,550	8,269
	% of consolidated	19%	23%	22%	28%	28%	23%
Netherlands
	Condensate (bbls/d)	88	99	77	64	67	58
	Natural gas (mmcf/d)	47.82	44.76	38.20	35.42	34.11	32.88
	Total (boe/d)	8,058	7,559	6,443	5,967	5,751	5,538
	% of consolidated	13%	14%	13%	15%	15%	16%
Germany
	Natural gas (mmcf/d)	14.90	15.78	14.99	-	-	-
	Total (boe/d)	2,483	2,630	2,498	-	-	-
	% of consolidated	4%	5%	5%	-	-	-
Ireland
	Natural gas (mmcf/d)	50.89	0.03	-	-	-	-
	Total (boe/d)	8,482	5	-	-	-	-
	% of consolidated	13%	-	-	-	-	-
Australia
	Crude oil (bbls/d)	6,304	6,454	6,571	6,481	6,360	8,168
	% of consolidated	10%	12%	13%	16%	17%	23%
United States
	Crude oil (bbls/d)	393	231	49	-	-	-
	NGLs (bbls/d)	29	7	-	-	-	-
	Natural gas (mmcf/d)	0.21	0.05	-	-	-	-
	Total (boe/d)	457	247	49	-	-	-
	% of consolidated	1%	-	-	-	-	-
Consolidated
	Crude oil, condensate & NGLs (bbls/d)	30,433	32,716	31,432	27,471	25,270	22,334
	% of consolidated	48%	60%	63%	67%	67%	63%
	Natural gas (mmcf/d)	198.55	133.24	108.85	81.21	75.20	77.21
	% of consolidated	52%	40%	37%	33%	33%	37%
	Total (boe/d)	63,526	54,922	49,573	41,005	37,803	35,202

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

Supplemental Table 5: Segmented Financial Results

	Three Months Ended December 31, 2016
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Drilling and development	16,895	31,127	5,737	1,694	1,711	5,236	4,037	-	66,437
Exploration and evaluation	-	-	-	-	-	-	-	445	445
Oil and gas sales to external customers	70,573	71,926	25,978	8,294	42,727	38,352	2,041	-	259,891
Royalties	(7,390)	(6,692)	(294)	(12)	-	-	(611)	-	(14,999)
Revenue from external customers	63,183	65,234	25,684	8,282	42,727	38,352	1,430	-	244,892
Transportation	(3,504)	(3,983)	-	(375)	(1,703)	-	-	-	(9,565)
Operating	(18,161)	(11,482)	(5,660)	(3,959)	(5,148)	(14,905)	(301)	-	(59,616)
General and administration	(2,035)	(5,101)	(162)	(1,755)	(1,523)	(1,998)	(877)	1,987	(11,464)
PRRT	-	-	-	-	-	(1,568)	-	-	(1,568)
Corporate income taxes	-	(2,867)	100	-	-	(2,703)	-	(370)	(5,840)
Interest expense	-	-	-	-	-	-	-	(14,410)	(14,410)
Realized gain on derivative instruments	-	-	-	-	-	-	-	1,920	1,920
Realized foreign exchange gain	-	-	-	-	-	-	-	1,291	1,291
Realized other income	-	3,822	-	-	-	-	-	120	3,942
Fund flows from operations	39,483	45,623	19,962	2,193	34,353	17,178	252	(9,462)	149,582

	Year Ended December 31, 2016
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Total assets	1,522,243	835,141	220,350	292,885	756,893	267,183	61,195	131,294	4,087,184
Drilling and development	62,706	68,472	23,740	3,803	9,375	59,910	13,539	-	241,545
Exploration and evaluation	-	-	-	-	-	-	-	863	863
Oil and gas sales to external customers	252,867	246,863	100,707	29,049	109,156	136,835	7,314	-	882,791
Royalties	(21,475)	(27,091)	(1,462)	(2,089)	-	-	(2,167)	-	(54,284)
Revenue from external customers	231,392	219,772	99,245	26,960	109,156	136,835	5,147	-	828,507
Transportation	(15,392)	(14,758)	-	(2,869)	(6,492)	-	-	-	(39,511)
Operating	(71,543)	(50,000)	(20,796)	(12,379)	(18,646)	(47,507)	(1,314)	-	(222,185)
General and administration	(11,826)	(19,101)	(1,525)	(8,314)	(4,772)	(6,400)	(3,624)	2,733	(52,829)
PRRT	-	-	-	-	-	(1,568)	-	-	(1,568)
Corporate income taxes	-	(2,867)	(6,624)	-	-	(7,522)	-	(1,097)	(18,110)
Interest expense	-	-	-	-	-	-	-	(56,957)	(56,957)
Realized gain on derivative instruments	-	-	-	-	-	-	-	65,376	65,376
Realized foreign exchange gain	-	-	-	-	-	-	-	4,041	4,041
Realized other income	-	3,822	-	-	-	-	-	205	4,027
Fund flows from operations	132,631	136,868	70,300	3,398	79,246	73,838	209	14,301	510,791

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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 consider free cash flow to be a key measure as it is used 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.

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 and Premium Dividend™ plans. 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 to assess the amount of cash distributed back to shareholders and re-invested in the business for maintaining production and organic growth.

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

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

	Three Months Ended			Year Ended
	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2016	2016	2015	2016	2015
Dividends declared	76,096	75,465	71,965	299,070	283,575
Shares issued for the DRIP⁽¹⁾	(43,580)	(50,912)	(46,764)	(192,998)	(155,033)
Net dividends	32,516	24,553	25,201	106,072	128,542
Drilling and development	66,437	41,039	128,996	241,545	486,861
Exploration and evaluation	445	-	-	863	-
Asset retirement obligations settled	3,327	2,066	4,921	9,617	11,369
Payout	102,725	67,658	159,118	358,097	626,772

⁽¹⁾ DRIP Refers to Vermilion’s dividend reinvestment and Premium Dividend^TM plans.

	As at
	Dec 31,	Sep 30,	Dec 31,
('000s of shares)	2016	2016	2015
Shares outstanding	118,263	117,386	111,991
Potential shares issuable pursuant to the VIP	3,090	2,797	3,033
Diluted shares outstanding	121,353	120,183	115,024

Vermilion Energy Inc.

2016 Management’s Discussion & Analysis

DIRECTORS

Lorenzo Donadeo ¹
Calgary, Alberta

Larry J. Macdonald ^{2, 3, 4, 5, 6}

Chairman & CEO, Point Energy Ltd.

Calgary, Alberta

Claudio A. Ghersinich ^{3, 6}

Executive Director, Carrera Investments Corp.
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

Calgary, Alberta

Sarah E. Raiss ^{4, 5}

Calgary, Alberta

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 southeast Alberta

bbl(s) barrel(s)

bbls/d barrels per day

bcf billion cubic feet

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

btu British thermal units

CGU Cash generating unit, the basis upon which Vermilion’s assets are evaluated for potential impairments

DRIP Dividend Reinvestment Plan

GJ gigajoules

HH Henry Hub, a reference price paid for natural gas in US dollars at Erath, Louisiana

mbbls thousand barrels

mboe thousand barrel of oil equivalent

mcf thousand cubic feet

mcf/d thousand cubic feet per day

mmboe million barrel of oil equivalent

mmbtu million British thermal units

mmcf million cubic feet

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 operated by National Grid. 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 day-ahead price for natural gas in the Netherlands, quoted in MWh of natural gas, at the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services

WTI West Texas Intermediate, the reference price paid for

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

Daniel Goulet

Director Corporate HSE

Bryce Kremnica

Director Field Operations – Canada Business Unit

Kyle Preston

Director Investor Relations

Mike Prinz

Director Information Technology & Information Systems

Jenson Tan

Director Business Development

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

Darcy Kerwin

Managing Director - France Business Unit

Scott Seatter

Managing Director - Netherlands Business Unit

Albrecht Moehring

Managing Director - Germany 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

HSBC Bank Canada

Wells Fargo Bank N.A., Canadian Branch

La Caisse Centrale Desjardins du Québec

Alberta Treasury Branches

Bank of America N.A., Canada Branch

BNP Paribas, Canada Branch

Citibank N.A., Canadian Branch - Citibank Canada

JPMorgan Chase Bank, N.A., Toronto Branch

Union Bank, Canada 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