Vermilion Energy Inc. Announces Results for the Year Ended December 31, 2015

Vermilion Energy Inc. Announces Results for the Year Ended December 31, 2015

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February 29, 2016 12:10 AM

CALGARY, Feb. 29, 2016 /CNW/ – Vermilion Energy Inc. (“Vermilion”, “We”,
“Our”, “Us” or the “Company”) (TSX, NYSE: VET) is pleased to report
operating and audited financial results for the year ended December 31, 2015.

HIGHLIGHTS

Vermilion’s annual production volumes increased by 11% in 2015 to 54,922
boe/d. This strong production performance was achieved despite a
nearly 4,000 boe/d shortfall in anticipated Corrib volumes associated
with regulatory delays and a 30% decrease in exploration and
development (“E&D”) capital spending as compared to the prior year.
Production volumes for Q4 2015 increased by 8% as compared to the prior
quarter to a record 61,058 boe/d. Each of Vermilion’s business units
increased production, with the most significant increases driven by
drilling successes in Canada, Australia and the Netherlands.
Fund flows from operations in 2015 was $516.2 million ($4.71/basic share⁽¹⁾) as compared to $804.9 million ($7.63/basic share) in 2014. Higher
production in 2015 partially offset the impact of a 48% decrease in oil
prices. Q4 2015 fund flows from operations of $136.4 million
($1.22/basic share) was higher than the $129.4 million ($1.17/basic
share) in Q3 2015 as a result of higher production volumes, realized
hedging gains and lower taxes, partially offset by lower commodity
pricing.
Subsequent to the end of the year, we released a $285 million E&D
capital budget for 2016 that represented a decrease in spending of over
40% from 2015 levels and a decrease of nearly 60% from 2014 levels.
Since that time, we have further reduced our E&D budget by another $50
million in response to still lower commodity prices. Our new E&D
capital budget for 2016 is $235 million, with the flexibility to
restore certain projects if commodity prices improve. We still expect
to deliver nearly 15% production growth year-over-year with only a
modest impact expected in 2016 from this further reduction in capital.
Following the receipt of final regulatory approval, first gas production
started at our Corrib project in Ireland on December 30, 2015. Corrib
is expected to provide significant high-margin production growth and
generate meaningful free cash flow⁽¹⁾ in 2016. To date, production has been in-line with forecasts, with
well deliverability better than our expectations. Production levels at
Corrib are expected to rise over a period of approximately six months
to an estimated peak rate of 58 mmcf/d (9,700 boe/d), net to Vermilion.
Total proved (“1P”) reserves increased 6% to 160.7⁽²⁾ mmboe, while total proved plus probable (“2P”) reserves also increased
6% to 260.9⁽²⁾ mmboe. This represents year-over-year 1P and 2P per share reserves
growth of 2% and 1%, respectively.
Finding and Development (“F&D”)⁽³⁾ and Finding, Development and Acquisition (“FD&A”)⁽³⁾ costs, including Future Development Capital (“FDC”)⁽³⁾ for 2015 on a 2P basis decreased 48% to $8.98/boe and 55% to
$10.03/boe, respectively. Similarly, our three-year F&D and FD&A,
including FDC, on a 2P basis were $14.82/boe and $17.81/boe,
respectively.
Recycle ratio⁽⁵⁾ (including FDC) was 3.6x during 2015, an increase over 3.2x achieved
during 2014, indicating that we were able to not only maintain but
improve our high level of investment efficiency in 2015 despite the
decline in commodity prices. We increased Proved Developed Producing
reserves (net of production) by 25% at an average F&D cost (including
FDC) of $10.67/boe generating a recycle ratio (including FDC) of 3.0x.
Our independent GLJ 2015 Resource Assessment⁽⁴⁾ indicates low, best, and high estimates for contingent resources in the
Development Pending category are 95.1 mmboe, 160.7 mmboe, and 254.7
mmboe, respectively. Approximately 80% of our best estimate contingent
resources evaluated reside in the Development Pending category,
reflecting the high quality nature of our contingent resource base.
In Q4 2015 we drilled and completed a horizontal sidetrack well at the
Wandoo A platform in Australia. The well was successfully brought on
production in mid-November. We produced the well through December 31,
2015 at an average rate of approximately 3,900 boe/d.
The Diever-02 exploration well in the Netherlands (45% working
interest), drilled in 2014, came on production at the end of October
2015 at a gross rate of 28.5 mmcf/d (4,750 boe/d). Our net incremental
production increase from this well is presently limited to
approximately 6 mmcf/d (1,000 boe/d) due to current pipeline
constraints in the multi-well system that Diever-02 produces into.
We continued to make progress in mitigating the impact of third-party
plant capacity and transportation restrictions on our Canadian
production volumes. At the end of Q4, approximately 1,600 boe/d
remained shut-in, pending capacity availability.
Vermilion was recently awarded two additional exploration licenses in
Germany, adding approximately 110,000 net acres to our land position.
We continued to prioritize preserving the strength of our balance sheet
through our Profitability Enhancement Program (“PEP”) initiative.
Associated cost savings related to capital spending, operating expense
and G&A expenditures reached nearly $90 million for full-year 2015.

⁽¹⁾	Non-GAAP Financial Measure. Please see the “Non-GAAP Financial Measures” section of Management’s Discussion and Analysis.
⁽²⁾	Estimated proved and proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) in a report dated February 8, 2016 with an effective date of December 31, 2015 (the “2015 GLJ Reserves Evaluation”)
⁽³⁾	F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital costs for the period, including the change in undiscounted future development capital (“FDC”), by the change in the reserves, incorporating revisions and production, for the same period.
⁽⁴⁾	Vermilion retained GLJ to conduct an independent resource evaluation dated February 8, 2016 to assess contingent resources across all of the Company’s key operating regions with an effective date of December 31, 2015 (the “GLJ 2015 Resource Assessment”). The associated chance of development for each of the low, best, and high estimate for contingent resources in the Development Pending category are 83%, 82%, and 81%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources.
⁽⁵⁾	Recycle ratio is Operating Netback divided by F&D (including FDC)

ORGANIZATIONAL UPDATE

As announced on November 30, 2015, Mr. Lorenzo Donadeo will be retiring
as Chief Executive Officer (“CEO”), effective March 1, 2016, at which
time he will become Chair of the Board of Directors. Mr. Anthony
Marino, currently President and Chief Operating Officer (“COO”), will
assume the role of President and CEO. Mr. Larry Macdonald, the Board
of Director’s current Chair, will transition to the newly created role
of Lead Independent Director.

Concurrent with those changes, Vermilion is pleased to announce the
appointments of Mr. Michael Kaluza to the position of Executive Vice
President and COO, and Mr. Dion Hatcher to the position of Vice
President of our Canadian Business Unit.

Mr. Kaluza joined Vermilion in February 2013 as Director of our Canadian
Business Unit, and was promoted to Vice President of our Canadian
Business Unit in May 2014. Mr. Kaluza has over 30 years of operations
and executive management experience, and has a Bachelor of Science in
Petroleum Engineering (Honors) from the Montana College of Mineral,
Science and Technology.

Mr. Hatcher joined Vermilion in 2006 and has over 18 years of industry
experience focused on operations engineering and project management. He
has a Bachelor of Science in Mechanical Engineering (Honors) from
Memorial University of Newfoundland.

Conference Call and Audio Webcast Details

Vermilion will discuss these results in a conference call to be held on
Monday, February 29, 2016 at 9:00 AM MST (11:00 AM EST). To
participate, you may call 1-888-231-8191 (Canada and US Toll Free) or
1-647-427-7450 (International and Toronto Area). The conference call
will also be available on replay by calling 1-855-859-2056 using
conference ID number 21667130. The replay will be available until
midnight mountain time on March 7, 2016.

You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=1117164&s=1&k=1F2188A24FF5A3DA8F83BE1F0C213F7B or visit Vermilion’s website at www.vermilionenergy.com/ir/eventspresentations.cfm.

HIGHLIGHTS

		Three Months Ended			Year Ended
($M except as indicated)		Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
Financial		2015	2015	2014	2015	2014
Petroleum and natural gas sales		234,319	245,051	306,073	939,586	1,419,628
Fund flows from operations		136,441	129,435	185,528	516,167	804,865
	Fund flows from operations ($/basic share)⁽¹⁾	1.22	1.17	1.73	4.71	7.63
	Fund flows from operations ($/diluted share)⁽¹⁾	1.21	1.16	1.71	4.65	7.51
Net earnings (loss)		(142,080)	(83,310)	58,642	(217,302)	269,326
	Net earnings (loss) ($/basic share)	(1.28)	(0.76)	0.55	(1.98)	2.55
Capital expenditures		128,996	93,381	166,243	486,861	687,724
Acquisitions		6,227	22,155	1,652	28,897	601,865
Asset retirement obligations settled		4,921	2,123	6,247	11,369	15,956
Cash dividends ($/share)		0.645	0.645	0.645	2.580	2.580
Dividends declared		71,965	71,244	69,119	283,575	272,732
	% of fund flows from operations	53%	55%	37%	55%	34%
Net dividends⁽¹⁾		25,201	26,654	48,139	128,542	193,302
	% of fund flows from operations	18%	21%	26%	25%	24%
Payout⁽¹⁾		159,118	122,158	220,629	626,772	896,982
	% of fund flows from operations	117%	94%	119%	121%	111%
	% of fund flows from operations (excluding the Corrib project)⁽¹⁾	106%	77%	106%	107%	99%
Net debt		1,381,951	1,363,043	1,265,650	1,381,951	1,265,650
Ratio of net debt to annualized fund flows from operations		2.5	2.6	1.7	2.7	1.6
Operational
Production
	Crude oil (bbls/d)	28,745	28,164	28,846	28,502	28,879
	NGLs (bbls/d)	5,298	4,622	2,822	4,214	2,553
	Natural gas (mmcf/d)	162.09	140.97	107.42	133.24	108.85
	Total (boe/d)	61,058	56,280	49,571	54,922	49,573
Average realized prices
	Crude oil and NGLs ($/bbl)	51.64	56.57	78.64	58.80	100.06
	Natural gas ($/mcf)	4.55	5.36	5.90	4.98	6.42
Production mix (% of production)
	% priced with reference to WTI	21%	24%	28%	25%	28%
	% priced with reference to AECO	24%	22%	20%	22%	18%
	% priced with reference to TTF	20%	20%	16%	19%	18%
	% priced with reference to Dated Brent	35%	34%	36%	34%	36%
Netbacks ($/boe)
	Operating netback	28.44	32.25	45.85	32.09	55.50
	Fund flows from operations netback	23.91	24.58	38.67	25.86	44.09
	Operating expenses	11.50	10.99	12.48	11.32	12.72
Average reference prices
	WTI (US $/bbl)	42.18	46.43	73.15	48.80	93.00
	Edmonton Sweet index (US $/bbl)	39.72	43.01	66.79	44.91	85.83
	Dated Brent (US $/bbl)	43.69	50.26	76.27	52.46	98.99
	AECO ($/mmbtu)	2.46	2.90	3.60	2.69	4.50
	TTF ($/mmbtu)	7.28	8.48	9.16	8.23	8.96
Average foreign currency exchange rates
	CDN $/US $	1.34	1.31	1.14	1.28	1.10
	CDN $/Euro	1.46	1.46	1.42	1.42	1.47
Share information (‘000s)
Shares outstanding – basic		111,991	110,818	107,303	111,991	107,303
Shares outstanding – diluted ⁽¹⁾		115,025	113,643	110,334	115,025	110,334
Weighted average shares outstanding – basic		111,393	110,293	107,102	109,642	105,448
Weighted average shares outstanding – diluted ⁽¹⁾		112,543	111,193	108,646	111,051	107,187

⁽¹⁾	The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the “NON-GAAP FINANCIAL MEASURES” section of Management’s Discussion and 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; estimated
contingent resources; 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.

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, 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
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
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 crude oil of standard grade in US dollars at Cushing, Oklahoma
CGU			Cash generating unit, the basis upon which Vermilions assets are evaluated for potential impairments
DRIP			Dividend Reinvestment Plan

MESSAGE TO SHAREHOLDERS

Commodity price volatility continued unabated through 2015, and it does
not appear that 2016 will provide any immediate relief. Although the
current economic environment poses significant challenges for all
industry participants, including Vermilion, we believe that continued
adherence to our long-term strategy will enable us to emerge from this
price cycle stronger than ever.

Our long-term strategy is focused on three main priorities, presented in
order of importance:

			1)	Preserving the strength of our balance sheet;
			2)	Protecting our dividend; and
			3)	Investing to fund production growth.

Preserving the Strength of Our Balance Sheet

We have always been highly disciplined in the management of our balance
sheet, historically maintaining leverage ratios that are significantly
more conservative than most of our peers. This has allowed us to
effectively manage through prior low commodity price environments. We
entered the current commodity downturn in a position of relative
financial strength, and we took a number of purposeful actions
throughout 2015 to preserve our balance sheet.

We have significantly reduced capital investment to support our
sustainability in this price environment. Our 2016 E&D budget is now
$235 million, representing a decrease of over 50% from 2015 levels and
a decrease of more than 65% from 2014 levels. Our intent is to balance
cash outlays in 2016 for net dividends and E&D capital investment with
our fund flows from operations.

During 2015 we increased our credit facility capacity by $500 million to
$2.0 billion and extended the term to May 2019, providing additional
financial certainty. At year-end 2015, we had $837 million of undrawn
capacity which allowed us to retire the $225 million of 6.5% Senior
Unsecured Notes that came due on February 10, 2016 with funds from the
credit facility. While we are continuing to assess opportunities to
diversify our debt structure, our credit facility is currently our most
cost-effective method of borrowing.

In early 2015 we amended our existing Dividend Reinvestment Plan
(“DRIP”) to include a Premium Dividend™ Component. The Premium
Dividend™ Component, when combined with our legacy Dividend
Reinvestment Plan, significantly expands our access to the lowest cost
source of equity capital available. The program can be suspended or
prorated at our discretion, offering considerable flexibility. We view
the implementation of the Premium Dividend™ as a short-term measure and
we will actively monitor our ongoing needs and manage our continued use
of each component as circumstances dictate. In the event of a
commodity price recovery, it is our intent to reduce, and ultimately
eliminate, the Premium Dividend™ Component.

We have hedged a meaningful component of our natural gas production,
particularly European natural gas, which remains a significantly
stronger market than North American natural gas. At present, we have
25% of our total 2016 net-of-royalty production hedged, including 44%
of our anticipated natural gas volumes.

Protecting Our Dividend

We have never reduced our dividend since it was initiated in 2003. We
are constantly monitoring both our dividend and accompanying capital
program, taking into consideration prevailing and expected commodity
prices and equity issued under our DRIP program. Although this
commodity downturn has been more pronounced than we anticipated when it
began in mid-2014, we believe that our existing dividend remains
manageable with the actions we have taken to date. We remain committed
to first prioritizing our balance sheet and preserving our financial
flexibility. To safeguard our long-term sustainability, we are
managing our business based on the current commodity price strip, with
the objective that our funds from operations will approximately balance
or exceed our cash outflows for net dividends and capital
expenditures. Should commodity conditions arise under which we can no
longer expect to balance outflows and inflows over longer periods of
time, we would protect our balance sheet through further modifications
of our capital investment and dividend programs.

Investing to Fund Production Growth

We believe our inventory of organic growth projects is strong and each
of our business units is capable of delivering production growth. The
diversity of our asset base and commodity and currency exposures allows
us to select and fund projects that will generate the highest return in
a given economic environment. This advantage is even more pronounced
in a low commodity price environment in which available capital funding
is highly restricted. Our improved recycle ratio at year-end 2015,
despite lower commodity prices, is indicative of the improvement of our
project inventory and execution over the past few years.

With the start-up of production at Corrib in Ireland in late 2015, we
are positioned to provide strong per share production growth of
approximately 10% for our shareholders in 2016. We expect Corrib to
meaningfully contribute to production growth in 2017 as well, with a
full year of production following the ramp-up to peak rates during the
first half of 2016. With production commencing at Corrib plus the
improvement in capital efficiencies in our other business units, we
have been able to significantly reduce our planned capital investment
program to preserve the strength of our balance sheet and protect our
dividend. These structural advantages in our production profile
position Vermilion to achieve all three priorities outlined above
despite the commodity downturn. At such time as commodity market
fundamentals warrant additional capital investment, we have the project
inventory to provide long-term organic production growth.

2015 Review

We delivered 11% year-over-year production growth, despite a nearly
4,000 boe/d shortfall in anticipated Corrib volumes associated with
regulatory delays. We believe that this accomplishment demonstrates
the depth of our operational and project capacity. In addition,
despite the prevailing commodity price environment, we continued to
deliver extremely strong performance across all segments of our
business, achieving a number of important milestones.

Europe

Following the receipt of final regulatory approval, first gas production
started at Corrib on December 30, 2015. Corrib is expected to provide
significant high-margin production growth and generate meaningful free
cash flow⁽¹⁾ in 2016 – unique attributes in our industry in the current price
environment. To date, Corrib has been producing in-line with
expectations, with well deliverability better than anticipated and no
significant downtime events. Production initially started with one well
before year-end, and a second well was brought on-line in early January
2016. Current production levels are approximately 33 mmcf/d (5,500
boe/d) net to Vermilion. Production levels at Corrib are expected to
rise over a period of approximately six months to a peak rate estimated
at 58 mmcf/d (9,700 boe/d), net to Vermilion.

In France, we completed a successful four (4.0 net) well drilling
program at Champotran during Q1 2015. This was our third successive
drilling campaign at Champotran since 2013. We have achieved 100%
drilling success across a cumulative 13 wells during that period.
Incorporating the impact of our waterflood program, our 2015 drilling
program delivered incremental exit production of approximately 1,000
boe/d. Our other activities in France during the year centered around
workovers and optimization projects, as well as infrastructure and
facility maintenance. In 2016, we intend to continue with workover and
optimization activities in France.

In the Netherlands, we drilled two (1.9 net) wells during Q2 2015 on the
Slootdorp concession in the province of North Holland. Both wells were
successful and encountered more natural gas pay than expected. The
wells are currently on sales during an extended production test to size
permanent production equipment and are currently producing at a
facility-restricted combined rate of 25.8 mmcf/d (4,300 boe/d) net to
Vermilion. The Diever-02 exploration well (45% working interest),
drilled in 2014, came on production in late October 2015 for an
extended production test and continues to produce at a gross rate of
28.5 mmcf/d (4,750 boe/d). Our net incremental production increase from
this well is presently limited to approximately 6 mmcf/d (1,000 boe/d)
due to current pipeline constraints in the multi-well system that
Diever-02 produces into. Activity in the Netherlands during 2016 will
focus on permitting and the optimization of existing assets.

In Germany, our partner ExxonMobil Production Deutschland GmbH drilled
and completed the Burgmoor Z3a well (25% net interest to Vermilion) in
the first half of 2015, which began producing at a sales gas rate of
approximately 1.7 mmcf/d (280 boe/d) net to Vermilion. In July 2015,
we entered into a farm-in agreement that provides us with participating
interest in 19 onshore exploration licenses in northwest Germany and
associated proprietary data. The licenses comprise approximately
850,000 net acres of undeveloped oil and natural gas rights in the
prolific North German Basin. More recently, we were awarded two
additional exploration licenses in Germany adding approximately 110,000
net acres to our land position. Further bolstering our presence in the
country, we have taken over the drilling operatorship for the Burgmoor
Z5 well in our Dumersee-Uchte producing concession, which is scheduled
to be drilled in 2017. The majority of our capital in 2016 will be
directed to permitting and pre-drill activities for Burgmoor Z5 and two
exploration prospects. In addition, we will continue our ongoing
analysis of the geologic and geophysical data acquired with the farm-in
assets.

North America

During 2015, we drilled or participated in nine (3.4 net) Cardium wells,
28 (18.5 net) Mannville wells, and five (4.1 net) Midale wells.
Overall activity levels in Canada were significantly lower than in
prior years as a result of reduced capital availability. Nevertheless,
we achieved a number of successes in our Mannville play. One such
success was the drilling of a two-mile well that targeted the Notikewin
formation and came on production at an infrastructure limited rate of
approximately 14 mmcf/d (2,300 boe/d). The productive capability
demonstrated by this well ranks it among the top natural gas wells
currently producing in Alberta.

In Q2 2015, we completed an infrastructure project that included the
expansion of a compressor station as well as the construction of a 22
km pipeline. This infrastructure will play a critical role in
supporting the continued growth of our Mannville play over the next few
years.

Throughout 2015, we made significant progress in addressing the impact
of third-party plant capacity and transportation restrictions on our
production volumes. At the end of December, total volumes impacted by
capacity issues had been reduced to 1,600 boe/d.

Canadian drilling activities in 2016 will be limited to operated expiry
wells and capital commitments on non-operated wells.

In the United States, we completed and began testing one (1 net) Turner
Shurley Sand well in the eastern Powder River Basin of Wyoming in Q3
2015. During the year, we consolidated our ownership of this project
area to 100% working interest through the acquisition of the remaining
30% interest. We also drilled two additional wells in Q4 2015 which
will be completed and tied-in in 2016. We intend to drill one (1.0
net) additional expiry well in 2016. We expect to increase our
investment in this play when commodity prices improve.

Australia

In Q4 2015 we completed and placed on production the horizontal
sidetrack well that was drilled at the Wandoo A platform. Well
performance has been strong at approximately 3,900 boe/d over the last
six weeks of 2015. Following this success, we are planning a two-well
drilling program in Australia for 2016. Offshore drilling in Australia
requires a great deal of advance contracting and logistical planning,
which means that full-cycle costs are minimized by proceeding with this
program in 2016 despite current oil price weakness. Furthermore, we
expect service costs to be near their lows in 2016 at the time of
drilling, making this a desirable time to drill these high-quality
sidetrack locations.

External Recognition

Vermilion’s Board of Directors was recently recognized as a TopGun Board
in Canada for 2015/2016 by Brendan Wood International (“BWI”)
reflecting the high degree of confidence major institutional investors
have in Vermilion’s Board. The voting panel, which was comprised of
over 500 institutional investors and sell-side professionals considered
a short-list of 323 potential companies and awarded TopGun status to
only 27 companies, less than 10% of those nominated.

Lorenzo Donadeo, Chief Executive Officer and Curtis W. Hicks, Executive
Vice President and Chief Financial Officer were also recognized in
BWI’s Shareholder Confidence survey as a Top Gun CEO and CFO,
respectively, reflecting continuing institutional investor confidence
in Vermilion’s strategic execution, financial practices and investor
communications.

During Q4 2015, we were named to the CDP Climate Disclosure Leadership
Index (“CDLI”), recognizing the depth and quality of our
climate-related disclosure as compared to the 200 largest companies
listed on the TSX. CDP (formerly Carbon Disclosure Project), is a
global, not-for-profit organization that manages the world’s only
global environmental disclosure system. To be named to the CDLI, a
company must have a disclosure score within the top 10% of surveyed
companies. We have voluntarily reported to CDP since 2012. We believe
that by measuring and understanding our current environmental profile,
we can direct our business strategy to operate in an even more
environmentally and socially sustainable manner in the future.

As previously announced, we have been recognized by the Great Place to
Work® Institute as a Best Workplace in Canada and France for a sixth
consecutive year. We were also recognized for a second consecutive
year as a Best Workplace in the Netherlands in 2015, after becoming
eligible for ranking in 2014. We are the only energy company in our
category to rank on the Best Workplaces lists in Canada and the
Netherlands, and the highest scoring energy company on the Best
Workplaces list in France.

During 2015, we were ranked 15th by Corporate Knights on the Future 40
Responsible Corporate Leaders in Canada list (the highest ranking for
an oil and gas company, and improved from our debut ranking of 32nd
last year). We were also named Top International Producer of the year
by the Explorers and Producers Association of Canada. This recognition
reflects our continued focus on achieving robust shareholder returns
combined with environmental, social and governance performance.

Outlook

This is an extraordinarily challenging time for the energy industry.
The commodity downturn was largely unexpected, has been breathtaking in
its depth and breadth and will leave an impact on the industry that
will be felt for years to come. At Vermilion, we are committed to
maintaining our focus on delivering a capital markets model that
benefits our shareholders over the long-term. We believe that our
diversified asset portfolio and operational capabilities position us to
protect our balance sheet, defend our dividend, and continue long-term
growth. Our management and directors hold approximately 6% of the
outstanding shares of Vermilion, ensuring alignment of interests with
our shareholders. We look forward to meeting the current challenges,
and believe that this business environment will illustrate the
differentiating benefits of our global operating, capital markets and
cultural model.

CEO Succession

As announced in November 2015, I will be retiring as CEO on March 1,
2016 at which time I will become Chair of the Board of Directors.
Since co-founding Vermilion some 22 years ago,‎ we have had great
success and it has been an exciting and personally rewarding
experience. I want to thank our staff, our executive team, our Board of
Directors and our shareholders for their contributions and support over
the years. I look forward to working with Anthony Marino as our new
CEO, the executive team, and the Board of Directors in taking Vermilion
to new and exciting heights.

⁽¹⁾	The above discussion includes non-GAAP measures which may not be comparable to other companies. Please see the “NON-GAAP FINANCIAL MEASURES” section of Management’s Discussion and Analysis.
⁽²⁾	Corrib P2 well produces from the Sherwood sandstones. The production test was performed over a 12-hour period at a maximum choke of 80/64″, achieving a peak production rate of 113 mmcf/d and a stabilized flow rate of 107 mmcf/d with approximately 30% drawdown over the test period. This test result is not necessarily indicative of long-term performance or of ultimate recovery.

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following is Management’s Discussion and Analysis (“MD&A”), dated
February 25, 2016, 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, 2015 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, 2015
and 2014, together with the accompanying notes. Additional information
relating to Vermilion, including its Annual Information Form, will be
available on or after March 4, 2016 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, 2015 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 measures which do not
have standardized meanings prescribed by IFRS. These financial
measures include:

Fund flows from operations: This financial measure is calculated as cash
flows from operating activities before changes in non-cash operating
working capital and asset retirement obligations settled. 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 cash necessary to pay
dividends, repay debt, fund asset retirement obligations and make
capital investments.
Netbacks: These financial measures are per boe and per mcf 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 third party crude oil and natural
gas producers.

In addition, this MD&A includes references to certain financial measures
which do not have standardized meanings prescribed by IFRS and are not
disclosed in our audited financial statements. As such, these
financial measures are considered non-GAAP financial measures and
therefore are unlikely to be comparable with 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, 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.

Canada business unit: Relates to our assets in Alberta and Saskatchewan.
France business unit: Relates to our operations in France in the Paris
and Aquitaine Basins.
Netherlands business unit: Relates to our operations in the Netherlands.
Germany business unit: Relates to our operations in Germany.
Ireland business unit: Relates to our 18.5% non-operated interest in the
Corrib offshore natural gas field.
Australia business unit: Relates to our operations in the Wandoo
offshore crude oil field.
United States business unit: Relates to our operations in Wyoming in the
Powder River Basin.
Corporate: Includes expenditures related to our global hedging program,
financing expenses, and general and administration expenses, primarily
incurred in Canada and not directly related to the operations of a
specific business unit.

2015 REVIEW AND 2016 GUIDANCE

We first issued 2015 capital expenditure guidance of $525 million on
December 8, 2014. We subsequently adjusted our 2015 capital
expenditure guidance to $415 million on February 27, 2015, in response
to the continued weakness in commodity prices. That reduction
reflected lower planned activity levels, including the deferral of our
Australian drilling program. On August 10, 2015 we announced an
increase in our capital expenditure guidance of $70 million to $485
million following the reinstatement of the Australian drilling program
as well as additional funding for projects in Canada, France and
Ireland. We maintained our previous production guidance of
55,000-57,000 boe/d, albeit towards the lower end of our guidance range
due to later-than-originally expected first gas from Corrib. Actual
2015 capital spending of $486.9 million was within 1% of guidance.
Production for 2015 proved to be within 0.1% of the guidance range.

On November 9, 2015 we announced preliminary 2016 capital expenditure
guidance of $350 million and affirmed production guidance of between
63,000-65,000 boe/d. On January 5, 2016, in response to the continued
weakness in commodity prices we adjusted 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
reflects lower expected non-operated drilling activity in Canada, fewer
workovers in France, and a deferral of our Netherlands drilling and
pipeline twinning programs.

The following table summarizes our 2015 and 2016 guidance:

Date

Capital Expenditures ($MM)

Production (boe/d)

2015 – Guidance

2015 Guidance

December 8, 2014

525

55,000 to 57,000

2015 Guidance

February 27, 2015

415

55,000 to 57,000

2015 Guidance

August 10, 2015

485

55,000 to 57,000

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

SHAREHOLDER RETURN

Vermilion strives to provide investors with reliable and growing
dividends in addition to sustainable, global production growth. The
following table, as of December 31, 2015, reflects our trailing one,
three, and five year performance:

Total return⁽¹⁾	Trailing One Year	Trailing Three Year	Trailing Five Year
Dividends per Vermilion share	$2.58	$7.56	$12.12
Capital appreciation per Vermilion share	($19.39)	($14.36)	($8.61)
Total return per Vermilion share	(29.5%)	(13.1%)	7.6%
Annualized total return per Vermilion share	(29.5%)	(4.6%)	1.5%
Annualized total return on the S&P TSX High Income Energy Index	(31.2%)	(13.1%)	(8.5%)

⁽¹⁾	The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the “NON-GAAP FINANCIAL MEASURES” section of this MD&A.

CONSOLIDATED RESULTS OVERVIEW

		Three Months Ended			% change		Year Ended		% change
		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
Production
	Crude oil (bbls/d)	28,745	28,164	28,846	2%	–	28,502	28,879	(1%)
	NGLs (bbls/d)	5,298	4,622	2,822	15%	88%	4,214	2,553	65%
	Natural gas (mmcf/d)	162.09	140.97	107.42	15%	51%	133.24	108.85	22%
	Total (boe/d)	61,058	56,280	49,571	8%	23%	54,922	49,573	11%
	Build (draw) in inventory (mbbl)	(93)	(85)	(238)			84	(165)
Financial metrics
	Fund flows from operations ($M)	136,441	129,435	185,528	5%	(26%)	516,167	804,865	(36%)
	Per share ($/basic share)	1.22	1.17	1.73	4%	(29%)	4.71	7.63	(38%)
	Net earnings (loss)	(142,080)	(83,310)	58,642	71%	(342%)	(217,302)	269,326	(181%)
	Per share ($/basic share)	(1.28)	(0.76)	0.55	68%	(333%)	(1.98)	2.55	(178%)
	Cash flows from operating activities ($M)	164,863	122,230	229,146	35%	(28%)	444,408	791,986	(44%)
	Net debt ($M)	1,381,951	1,363,043	1,265,650	1%	9%	1,381,951	1,265,650	9%
	Cash dividends ($/share)	0.645	0.645	0.645	–	–	2.580	2.580	–
Activity
	Capital expenditures ($M)	128,996	93,381	166,243	38%	(22%)	486,861	687,724	(29%)
	Acquisitions ($M)	6,227	22,155	1,652	(72%)	277%	28,897	601,865	(95%)
	Gross wells drilled	8.00	11.00	26.00			53.00	89.00
	Net wells drilled	5.56	6.91	16.58			36.12	62.43

Operational review

Recorded consolidated average production of 61,058 boe/d in Q4 2015,
which was an 8% increase over Q3 2015. This quarter-over-quarter
increase was the result of production growth in all of our business
units, including a 2,075 boe/d increase in Canada, largely attributable
to growth in our Mannville condensate-rich gas play, and a 1,391 boe/d
increase from Australia driven by our sidetrack well drilled in Q4
2015.
Increased consolidated average production for the three months and year
ended December 31, 2015 by 23% and 11%, respectively, versus the
comparable periods in 2014, primarily due to growth in Canada, the
Netherlands, and France.
Activity during the quarter included capital expenditures totalling
$129.0 million, incurred primarily in Australia, Canada, and France. In
Australia, capital expenditures totalling $40.9 million related to the
horizontal sidetrack drilling program. In Canada, capital expenditures
totalling $27.6 million were 26% lower than the $37.2 million incurred
during Q3 2015 and related to the drilling of 2.6 net wells (6.9 net
wells in Q3 2015). In France, capital expenditures of $24.1 million
were 39% higher than the $17.4 million incurred in Q3 2015 and related
primarily to facility maintenance, accretive workovers, and subsurface
activity.

Financial review

Net earnings (loss)

The net loss for Q4 2015 was $142.1 million ($1.28/basic share) as
compared to a net loss of $83.3 million ($0.76/basic share) in Q3
2015. The increase in the net loss was primarily attributable to
unfavourable foreign exchange variances and the impact of a valuation
allowance recorded on deferred tax assets. The valuation allowance
relates to certain non-capital losses for which there is uncertainty as
to the Company’s ability to fully utilize such losses when applying
forecasted commodity prices in effect as at December 31, 2015.
The net loss for the three months and year ended December 31, 2015
represented decreases of $200.7 million and $486.6 million,
respectively, versus the comparative periods in 2014. These decreases
were driven primarily by lower petroleum and natural gas sales as a
result of lower commodity prices, as well as impairment charges
recognized in Canada and a valuation allowance recorded on deferred tax
assets due to declines in commodity price forecasts. The impacts of
weakened commodity prices were partially offset by significant
production growth and global cost reductions, including an 8% and 11%
reduction in per unit operating expense for the three months and year
ended December 31, 2015, respectively. The year ended December 31,
2015 was also positively impacted by the recovery of $31.8 million
(before taxes) recognized in Q1 2015 following a judgment in favour of
Vermilion for costs incurred as a result of a 2007 oil spill at the
Ambès oil terminal in France that occurred shortly after Vermilion
acquired the asset.

Cash flows from operating activities

Absent changes in working capital, cash flows from operating activities
increased by 3% quarter-over-quarter, despite significantly lower
commodity prices, due to production growth in every business unit,
coupled with increased realized gains from our commodity hedges.
Cash flows from operating activities decreased by 28% and 44% for the
three months and year ended December 31, 2015, respectively, versus the
comparable periods in 2014. These decreases were primarily related to
lower revenue due to lower commodity prices, as well as timing
differences pertaining to working capital, partially offset by lower
royalties and current taxes.

Fund flows from operations

Generated fund flows from operations of $136.4 million during Q4 2015,
an increase of 5% over Q3 2015. This quarter-over-quarter increase
occurred despite lower commodity pricing, driven primarily by
production growth in all business units, lower current taxes, and
higher receipts from commodity hedges.
Fund flows from operations decreased by 26% and 36% for the three months
and year ended December 31, 2015, respectively, versus the comparable
periods in 2014. These decreases were primarily driven by lower crude
oil pricing, partially offset by higher sold volumes resulting from
significant production growth, global cost reductions, and favourable
current tax and royalty variances. The decrease in fund flows from
operations for the year ended December 31, 2015 was also partially
offset by the previously mentioned recovery of costs in France.

Net debt

Net debt increased by $116.3 million to $1.38 billion for the year ended
December 31, 2015 due to capital expenditures in Canada, France, and
Ireland, partially offset by fund flows from operations.

Dividends

Declared dividends of $0.215 per common share per month during the
fourth quarter of 2015, totalling $2.58 per common share for the year
ended December 31, 2015.

COMMODITY PRICES

		Three Months Ended			% change		Year Ended		% change
		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
Average reference prices
Crude oil
	WTI (US $/bbl)	42.18	46.43	73.15	(9%)	(42%)	48.80	93.00	(48%)
	Edmonton Sweet index (US $/bbl)	39.72	43.01	66.79	(8%)	(41%)	44.91	85.83	(48%)
	Dated Brent (US $/bbl)	43.69	50.26	76.27	(13%)	(43%)	52.46	98.99	(47%)
Natural gas
	AECO ($/mmbtu)	2.46	2.90	3.60	(15%)	(32%)	2.69	4.50	(40%)
	TTF ($/mmbtu)	7.28	8.48	9.16	(14%)	(21%)	8.23	8.96	(8%)
	TTF (€/mmbtu)	4.98	5.82	6.46	(14%)	(23%)	5.80	6.11	(5%)
	NBP ($/mmbtu)	7.41	8.40	9.52	(12%)	(22%)	8.33	9.10	(8%)
	NBP (€/mmbtu)	5.07	5.77	6.71	(12%)	(24%)	5.87	6.20	(5%)
	Henry Hub ($/mmbtu)	3.03	3.62	4.54	(16%)	(33%)	3.41	4.88	(30%)
	Henry Hub (US $/mmbtu)	2.27	2.77	4.00	(18%)	(43%)	2.66	4.41	(40%)
Average foreign currency exchange rates
CDN $/US $		1.34	1.31	1.14	2%	18%	1.28	1.10	16%
CDN $/Euro		1.46	1.46	1.42	–	3%	1.42	1.47	(3%)
Average realized prices ($/boe)
Canada		28.94	32.78	51.27	(12%)	(44%)	34.32	64.06	(46%)
France		54.20	60.96	79.25	(11%)	(32%)	62.67	105.43	(41%)
Netherlands		42.61	49.42	52.07	(14%)	(18%)	46.77	52.65	(11%)
Germany		39.68	44.36	49.19	(11%)	(19%)	43.10	46.03	(6%)
Australia		58.74	68.20	90.37	(14%)	(35%)	70.22	113.80	(38%)
United States		41.94	51.60	74.08	(19%)	(43%)	47.53	74.08	(36%)
Consolidated		41.04	46.56	63.79	(12%)	(36%)	47.07	77.75	(39%)
Production mix (% of production)
% priced with reference to WTI		22%	24%	28%			25%	28%
% priced with reference to AECO		24%	22%	20%			22%	18%
% priced with reference to TTF		20%	20%	16%			19%	18%
% priced with reference to Dated Brent		34%	34%	36%			34%	36%

Reference prices

Oil benchmarks faced strong headwinds throughout the fourth quarter,
causing both WTI and Dated Brent to average the quarter at US
$42.18/bbl and US $43.69/bbl respectively. Compared to the previous
quarter, WTI was down an additional 9% whereas Dated Brent averaged 13%
lower versus the previous quarter. On a year-over-year basis, WTI was
down 48% and Dated Brent was down 47%.
Crude oil prices set at Edmonton were less volatile during the fourth
quarter, but still tracked lower to average the quarter at US
$39.72/bbl, or 8% lower quarter-over-quarter, and 41% lower
year-over-year.
AECO natural gas suffered a 15% quarter-over-quarter decline as high
levels of gas-in-storage, strong field receipts, and below-normal
demand weighed on the market. Averaging $2.46/mmbtu for the three
months ending December 31, 2015, AECO was down 32% versus the same
quarter in 2014.
Despite having lower gas-in-storage, a mild start to winter and the
anticipation of increasing LNG supply reduced European natural gas
prices in Q4 2015, driving similar movements in TTF and NBP reference
prices. For the fourth quarter, TTF averaged $7.28/mmbtu, which was 14%
lower versus the previous quarter and 21% lower versus the same quarter
in the prior year. In Euro terms, TTF averaged the quarter at
€4.98/mmbtu, which was a 14% decrease versus Q3 2015, and 23% lower
year-over-year.
Weakness in the price of oil and a rate hike by the US Federal Reserve
in December kept the Canadian dollar on its declining path against the
US dollar; however, a similar impact was felt by the Euro versus the US
dollar, causing CDN $/Euro to remain flat quarter-over-quarter.

Realized prices

Consolidated realized price decreased by 12% for Q4 2015 as compared to
Q3 2015. This decrease was primarily the result of weakening crude oil
and natural gas pricing.
Consolidated realized price for the three months and year ended December
31, 2015 decreased by 36% and 39%, respectively, as compared to the
comparable periods in 2014. These decreases were due to weakening
commodity prices, primarily driven by a weakening of crude oil and
North American natural gas prices, as well as changes in production
mix, which included increased relative NGL and natural gas volumes in
Canada.

FUND FLOWS FROM OPERATIONS

	Three Months Ended						Year Ended
	Dec 31, 2015		Sep 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Petroleum and natural gas sales	234,319	41.04	245,051	46.56	306,073	63.79	939,586	47.07	1,419,628	77.75
Royalties	(16,285)	(2.85)	(17,100)	(3.25)	(25,963)	(5.41)	(65,920)	(3.30)	(108,000)	(5.92)
Petroleum and natural gas revenues	218,034	38.19	227,951	43.31	280,110	58.38	873,666	43.77	1,311,628	71.83
Transportation expense	(10,147)	(1.78)	(11,090)	(2.11)	(9,489)	(1.98)	(41,660)	(2.09)	(42,361)	(2.32)
Operating expense	(65,645)	(11.50)	(57,826)	(10.99)	(59,881)	(12.48)	(225,938)	(11.32)	(232,307)	(12.72)
General and administration	(12,431)	(2.18)	(13,088)	(2.49)	(13,236)	(2.76)	(53,584)	(2.68)	(61,727)	(3.38)
PRRT	(1,054)	(0.18)	(99)	(0.02)	(13,568)	(2.83)	(6,878)	(0.34)	(60,340)	(3.30)
Corporate income taxes	3,113	0.55	(12,383)	(2.35)	(8,304)	(1.73)	(44,237)	(2.22)	(96,996)	(5.31)
Interest expense	(16,584)	(2.90)	(15,420)	(2.93)	(12,943)	(2.70)	(59,852)	(3.00)	(49,655)	(2.72)
Realized gain on derivative instruments	21,164	3.71	10,854	2.06	22,816	4.76	41,356	2.07	36,712	2.01
Realized foreign exchange (loss) gain	(252)	(0.04)	309	0.06	(179)	(0.03)	623	0.03	(821)	(0.04)
Realized other income	243	0.04	227	0.04	202	0.04	32,671	1.64	732	0.04
Fund flows from operations	136,441	23.91	129,435	24.58	185,528	38.67	516,167	25.86	804,865	44.09

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

($M)		Q4/15 vs. Q3/15	Q4/15 vs. Q4/14	2015 vs. 2014
Fund flows from operations – Comparative period		129,435	185,528	804,865
Sales volume variance:
	Canada	1,779	3,636	24,239
	France	(5,232)	8,916	36,817
	Netherlands	2,104	20,038	21,601
	Germany	1,478	(1,153)	2,245
	Ireland	57	57	57
	Australia	16,350	2,802	(19,697)
	United States	1,051	524	2,948
Pricing variance on sold volumes:
	WTI	(3,075)	(32,707)	(195,644)
	AECO	(2,507)	(9,461)	(45,760)
	Dated Brent	(15,632)	(53,825)	(287,666)
	TTF	(7,105)	(10,581)	(19,182)
Changes in:
	Royalties	815	9,678	42,080
	Transportation	943	(658)	701
	Operating expense	(7,819)	(5,764)	6,369
	General and administration	657	805	8,143
	PRRT	(955)	12,514	53,462
	Corporate income taxes	15,496	11,417	52,759
	Interest	(1,164)	(3,641)	(10,197)
	Realized derivatives	10,310	(1,652)	4,644
	Realized foreign exchange	(561)	(73)	1,444
	Realized other income	16	41	31,939
Fund flows from operations – Current period		136,441	136,441	516,167

Fund flows from operations of $136.4 million during Q4 2015 represented
an increase of 5% versus Q3 2015. Quarter-over-quarter, the increase
was achieved, despite significant commodity price declines, as a result
of higher sold volumes driven by production growth in every business
unit, lower current taxes, and increased receipts from commodity
hedges.

Fund flows from operations decreased 26% and 36% for the three months
and year ended December 31, 2015, respectively, versus the comparable
periods in 2014. The 2015 decreases were primarily driven by
unfavourable crude oil and natural gas price variances, partially
offset by higher sold volumes resulting from significant production
growth and global cost reductions, most notably in per unit operating
expense which decreased 8% and 11% for the quarter and full year,
respectively. The full year decrease in fund flows from operations was
partially offset by the previously mentioned recovery of costs in
France.

Fluctuations in fund flows from operations (and correspondingly net
earnings (loss) and cash flows from operating activities) 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 highly
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 in income.

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

Operational review

		Three Months Ended			% change		Year Ended		% change
		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
Canada business unit		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
Production
	Crude oil (bbls/d)	7,964	9,195	11,384	(13%)	(30%)	9,550	11,248	(15%)
	NGLs (bbls/d)	5,159	4,513	2,741	14%	88%	4,108	2,476	66%
	Natural gas (mmcf/d)	87.90	71.94	58.36	22%	51%	71.65	55.67	29%
	Total (boe/d)	27,773	25,698	23,851	8%	16%	25,598	23,001	11%
Production mix (% of total)
	Crude oil	29%	36%	48%			37%	49%
	NGLs	19%	18%	11%			16%	11%
	Natural gas	52%	46%	41%			47%	40%
Activity
	Capital expenditures ($M)	27,554	37,224	85,442	(26%)	(68%)	201,508	334,742	(40%)
	Acquisitions ($M)	6,169	8,062	1,671			14,650	415,648
	Gross wells drilled	5.00	11.00	23.00			42.00	74.00
	Net wells drilled	2.56	6.91	15.16			26.01	50.27

Production

Q4 2015 average production in Canada increased by 8%
quarter-over-quarter and 16% year-over-year. Full year average
production increased 11% versus 2014. Quarterly and annual increases
were primarily due to strong organic production growth in our Mannville
condensate-rich gas resource play.
In early December 2015, some transportation restrictions were lifted,
resulting in approximately 1,000 boe/d of non-operated volumes being
brought online. At the end of Q4 2015, approximately 1,600 boe/d of
production was shut-in due to a lack of field compression capacity, but
the majority of these volumes are expected to be brought online in Q1
2016.
Cardium production averaged approximately 8,000 boe/d in Q4 2015, a 14%
decrease quarter-over-quarter. Full year 2015 average production of
approximately 9,100 boe/d represented a decrease of 16% versus 2014.
Mannville production averaged approximately 11,000 boe/d in Q4 2015, a
57% increase quarter-over-quarter and more than 2.5 times Q4 2014
production of approximately 4,300 boe/d. Full year 2015 production
averaged more than 7,100 boe/d, representing an 82% increase versus
2014.
Production from our southeast Saskatchewan assets averaged approximately
2,500 boe/d in Q4 2015, a decrease of 17% quarter-over-quarter. The
North Portal Gas Plant was commissioned late in Q1 2015. The plant
enables the processing of approximately 5,500 mcf/d (920 boe/d net) of
natural gas which was previously being flared.

Activity review

Vermilion drilled two (2.0 net) operated wells and participated in the
drilling of three (0.6 net) non-operated wells during Q4 2015. During
2015, Vermilion drilled 20 (17.6 net) operated wells and participated
in the drilling of 22 (8.4 net) non-operated wells in Canada.

Cardium

During Q4 2015, we participated in the drilling of two (0.3 net)
non-operated wells; no wells were placed on production.
In 2015, we drilled one (1.0 net) operated well and brought ten (9.3
net) operated wells on production. We also participated in the drilling
of eight (2.4 net) non-operated wells and six (2.1 net) non-operated
wells were brought on production.
2016 activity will focus on the optimization of existing assets.

Mannville

During Q4 2015, we drilled two (2.0 net) operated wells and brought one
(1.0 net) operated well on production. We also participated in the
drilling of one (0.3 net) non-operated well and one (0.4 net)
non-operated well was placed on production.
In 2015, we drilled 14 (12.5 net) operated wells and brought 11 (9.5
net) operated wells on production. We also participated in the drilling
of 14 (6.0 net) non-operated wells and ten (3.8 net) non-operated wells
were placed on production.
In 2016, we plan to drill or participate in approximately six (4.0 net)
wells.

Saskatchewan

We drilled and brought on production five (4.1 net) operated Midale
wells during Q1 2015, completing our 2015 drilling activity in
Saskatchewan.
In 2016, we plan to drill or participate in six (5.5 net) wells.

Financial review

		Three Months Ended			% change		Year Ended		% change
Canada business unit		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
($M except as indicated)		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
	Sales	73,952	77,493	112,494	(5%)	(34%)	320,613	537,788	(40%)
	Royalties	(7,146)	(6,638)	(15,626)	8%	(54%)	(28,144)	(65,563)	(57%)
	Transportation expense	(3,784)	(4,131)	(3,455)	(8%)	10%	(16,326)	(14,625)	12%
	Operating expense	(24,575)	(23,877)	(19,315)	3%	27%	(89,085)	(76,178)	17%
	General and administration	(3,669)	(3,694)	(2,840)	(1%)	29%	(16,888)	(16,791)	1%
	Fund flows from operations	34,778	39,153	71,258	(11%)	(51%)	170,170	364,631	(53%)
Netbacks ($/boe)
	Sales	28.94	32.78	51.27	(12%)	(44%)	34.32	64.06	(46%)
	Royalties	(2.80)	(2.81)	(7.12)	–	(61%)	(3.01)	(7.81)	(61%)
	Transportation expense	(1.48)	(1.75)	(1.57)	(15%)	(6%)	(1.75)	(1.74)	1%
	Operating expense	(9.62)	(10.10)	(8.80)	(5%)	9%	(9.54)	(9.07)	5%
	General and administration	(1.44)	(1.56)	(1.29)	(8%)	12%	(1.81)	(2.00)	(10%)
	Fund flows from operations netback	13.60	16.56	32.49	(18%)	(58%)	18.21	43.44	(58%)
Reference prices
	WTI (US $/bbl)	42.18	46.43	73.15	(9%)	(42%)	48.80	93.00	(48%)
	Edmonton Sweet index (US $/bbl)	39.72	43.01	66.79	(8%)	(41%)	44.91	85.83	(48%)
	Edmonton Sweet index ($/bbl)	53.04	56.32	75.85	(6%)	(30%)	57.43	94.82	(39%)
	AECO ($/mcf)	2.46	2.90	3.60	(15%)	(32%)	2.69	4.50	(40%)

Sales

The realized price for our crude oil production in Canada is directly
linked to WTI, but 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 spot price in Canada.
Q4 2015 and full year 2015 sales per boe decreased versus all comparable
periods, largely as the result of weakening crude oil and natural gas
pricing.

Royalties

Royalties as a percentage of sales for Q4 2015 of 9.7% was slightly
higher than the 8.6% for Q3 2015 due to the absence of certain royalty
credits recorded in the third quarter.
Royalties as a percentage of sales for the three months and year ended
December 31, 2015 decreased to 9.7% and 8.8% versus the same periods in
2014 (13.9% and 12.2%, respectively) due to the impact of lower
reference prices on the sliding scale used to determine crude oil
royalty rates.

Transportation

Transportation expense relates to the delivery of crude oil and natural
gas production to major pipelines where legal title transfers.
Transportation expense for the three months and year ended December 31,
2015 was higher than the comparable periods in 2014 due to increased
natural gas and natural gas liquids volumes produced in 2015. In
addition, full year 2015 expense includes incremental trucking costs
from Vermilion’s Saskatchewan properties, which were acquired in April
2014.

Operating expense

Operating expense was higher in Q4 2015 versus Q4 2014 due to higher gas
gathering and processing expenditures following significantly increased
natural gas and natural gas liquids production. For Q4 2015 versus Q3
2015, this increase was largely offset by cost reduction initiatives
including reduced major project, transportation and other costs,
resulting in a 5% reduction in per unit costs.
Full year operating expense increased on a spend basis by approximately
17% due to incremental operating expense associated with Vermilion’s
Saskatchewan properties acquired in Q2 2014 and higher gas gathering
and processing fees following increased natural gas and natural gas
liquids production in Alberta. This increase in spending was partially
offset by increased production volumes, resulting in a 5% increase in
operating expense per boe.

General and administration

General and administration expense increased from Q4 2014 primarily due
to a decrease in recoveries, which more than offset lower gross costs.
Year-over-year, 2015 general and administrative expense were essentially
flat due to lower current year recoveries more than offsetting a
decrease in gross costs.

Impairment

For the three months and year ended December 31, 2015, Vermilion
recorded an impairment charge of $131.6 million and $274.6 million,
respectively, related to the light crude oil play in Saskatchewan,
Canada ($267.9 million in 2015) and the shallow coal bed methane gas
properties in Alberta, Canada ($6.7 million in 2015). These impairment
charges were a result of declines in the price forecasts for crude oil
and natural gas in Canada which decreased the expected future cash
flows from the respective cash generating units.

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.
Producing assets include large conventional fields with high working
interests located in the Aquitaine and Paris Basins with an identified
inventory of workover, infill drilling, and secondary recovery
opportunities.
Production is characterized by Brent-based crude pricing and low base
decline rates.

Operational review

		Three Months Ended			% change		Year Ended		% change
		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
France business unit		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
Production
	Crude oil (bbls/d)	12,537	12,310	11,133	2%	13%	12,267	11,011	11%
	Natural gas (mmcf/d)	1.36	1.47	–	(7%)	100%	0.97	–	100%
	Total (boe/d)	12,763	12,555	11,133	2%	15%	12,429	11,011	13%
Inventory (mbbls)
	Opening crude oil inventory	239	340	214			197	269
	Crude oil production	1,153	1,133	1,024			4,477	4,019
	Crude oil sales	(1,149)	(1,234)	(1,041)			(4,431)	(4,091)
	Closing crude oil inventory	243	239	197			243	197
Production mix (% of total)
	Crude oil	98%	98%	100%			99%	100%
	Natural gas	2%	2%	–			1%	–
Activity
	Capital expenditures ($M)	24,085	17,369	37,189	39%	(35%)	92,265	147,852	(38%)
	Acquisitions ($M)	79	142	–			317	–
	Gross wells drilled	–	–	1.00			4.00	8.00
	Net wells drilled	–	–	0.50			4.00	7.50

Production

Ongoing workover and optimization activities in Q4 2015 resulted in
stable quarter-over-quarter production. Production increased versus
2014, for both the quarter and full year periods, due to production
additions from our 2015 Champotran drilling program and workovers.

Activity review

Vermilion drilled four (4.0 net) wells in the Champotran field in the
Paris Basin in Q1 2015, completing our planned France drilling program
for 2015.
In 2015, additional activity included workover and optimization programs
in the Aquitaine and Paris Basins, and the resumption of sales from a
portion of our shut-in natural gas at Vic Bilh, which was brought back
on-line in Q2 2015.
In 2016, our planned capital activity includes a program of
approximately 15 well workovers.

Financial review

		Three Months Ended			% change		Year Ended		% change
France business unit		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
($M except as indicated)		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
	Sales	63,411	76,552	82,499	(17%)	(23%)	281,422	431,252	(35%)
	Royalties	(7,198)	(8,038)	(6,319)	(10%)	14%	(26,958)	(28,444)	(5%)
	Transportation expense	(4,275)	(4,566)	(4,096)	(6%)	4%	(15,378)	(18,975)	(19%)
	Operating expense	(15,792)	(11,998)	(13,544)	32%	17%	(50,718)	(61,729)	(18%)
	General and administration	(4,894)	(5,338)	(3,765)	(8%)	30%	(20,217)	(20,929)	(3%)
	Other income	–	–	–	–	–	31,775	–	100%
	Current income taxes	4,529	(4,696)	(6,132)	(196%)	(174%)	(23,764)	(66,901)	(64%)
	Fund flows from operations	35,781	41,916	48,643	(15%)	(26%)	176,162	234,274	(25%)
Netbacks ($/boe)
	Sales	54.20	60.96	79.25	(11%)	(32%)	62.67	105.43	(41%)
	Royalties	(6.15)	(6.40)	(6.07)	(4%)	1%	(6.00)	(6.95)	(14%)
	Transportation expense	(3.65)	(3.64)	(3.94)	–	(7%)	(3.42)	(4.64)	(26%)
	Operating expense	(13.50)	(9.55)	(13.01)	41%	4%	(11.30)	(15.09)	(25%)
	General and administration	(4.18)	(4.25)	(3.62)	(2%)	15%	(4.50)	(5.12)	(12%)
	Other income	–	–	–	–	–	7.08	–	100%
	Current income taxes	3.87	(3.74)	(5.89)	(203%)	(166%)	(5.29)	(16.36)	(68%)
	Fund flows from operations netback	30.59	33.38	46.72	(8%)	(35%)	39.24	57.27	(31%)
Reference prices
	Dated Brent (US $/bbl)	43.69	50.26	76.27	(13%)	(43%)	52.46	98.99	(47%)
	Dated Brent ($/bbl)	58.34	65.81	86.62	(11%)	(33%)	67.09	109.36	(39%)

Sales

Crude oil in France is priced with reference to Dated Brent.
Sales per boe decreased quarter-over-quarter, consistent with a decrease
in the Dated Brent reference price. This decrease in price was combined
with decreased sales volumes due to a slight build in inventory of
4,000 bbls in Q4 (versus a draw in Q3 2015).
On a year-over-year basis, sales decreased for the three months and year
ended December 31, 2015, consistent with a decline in the Dated Brent
reference price, and was partially offset by increased sales volumes
driven by production growth.

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 11.4% and 9.6% for the three
months and year ended December 31, 2015 was higher than Q3 2015 (10.5%)
and the 2014 periods (7.7% and 6.6%, respectively) as a result of the
impact of fixed RCDM royalties coupled with lower realized pricing.

Transportation

Transportation expense for Q4 2015 was relatively consistent with both
Q3 2015 and Q4 2014.
Transportation expense decreased by 19% for 2015 versus 2014 due to a
lower level of maintenance and project activity at the Ambès terminal
coupled with the favourable foreign exchange impact of the
strengthening of the Canadian dollar versus the Euro.

Operating expense

Operating expense on a dollar and per boe basis increased in Q4 2015
versus both Q3 2015 and Q4 2014 due to increased electricity usage and
costs coupled with a higher level of project activity in the current
quarter.
Operating expense on a dollar and per boe basis decreased in 2015 versus
2014 due largely to the successful implementation of cost reduction
initiatives undertaken in response to commodity price weakness. These
cost reduction initiatives included lower costs on downhole and other
maintenance activities, lower labour usage and costs and savings from
service contract renegotiations. These cost cutting initiatives were
delivered while growing production during the year by 13%, resulting in
a 25% decrease in unit costs.

General and administration

General and administration expense for Q4 2015 was 8% lower than Q3 2015
and 30% higher than Q4 2014. These fluctuations in general and
administration expense for the quarters presented primarily result from
variances in the timing of spending, including the timing of
allocations from our Corporate segment.
Year-over-year, 2015 general and administration expense was 3% lower
than 2014 due to the impact of a number of cost reduction initiatives
undertaken in response to commodity price weakness, including a
reduction in third party consultant expenditures.

Other income

Included in the results for the year ended December 31, 2015 is a
judgment award pertaining to costs incurred as a result of an oil spill
at the Ambès oil terminal in France that occurred in 2007. As a result
of the award, $31.8 million (before taxes) was recognized as other
income.

Current income taxes

Current income taxes in France are applied to taxable income, after
eligible deductions, at a statutory rate of 34.4% for 2015. France is
not expected to incur any current income taxes for 2016. This is
subject to change in response to commodity price fluctuations, the
timing of capital expenditures, and other eligible in-country
adjustments.
Q4 2015 current income taxes decreased compared to Q3 2015 and Q4 2014
due to decreased revenues and additional tax deductions taken for
depletion.
Current income taxes for the full year ended December 31, 2015 decreased
versus the comparative period in 2014 mainly due to lower fund flows
from operations as a result of the decline in the Dated Brent reference
price and additional tax deductions taken for depletion.

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 undeveloped land.
Natural gas drilling and development.
Natural gas produced in the Netherlands is priced off the TTF index,
which receives a significant premium over North American gas prices.

Operational review

		Three Months Ended			% change		Year Ended		% change
		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
Netherlands business unit		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
Production
	NGLs (bbls/d)	110	109	81	1%	36%	99	77	29%
	Natural gas (mmcf/d)	56.34	53.56	31.35	5%	80%	44.76	38.20	17%
	Total (boe/d)	9,500	9,035	5,306	5%	79%	7,559	6,443	17%
Activity
	Capital expenditures ($M)	18,810	5,297	10,022	255%	88%	47,325	61,740	(23%)
	Gross wells drilled	–	–	2.00			2.00	7.00
	Net wells drilled	–	–	0.92			1.86	4.66

Production

Q4 2015 production represented a new record for our Netherlands Business
Unit at 9,500 boe/d, which is an increase of 5% from the prior
quarter. This increase is primarily attributable to production from
the Diever-02 exploration well (45% working interest), coming on an
extended production test in late October. Diever-02 is currently
producing approximately 13.2 mmcf/d (2,200 boe/d) net to Vermilion.
Q4 2015 production increased 79% year-over-year, mainly driven by the
extended production test of three wells: Slootdorp-06/07 (92.8% working
interest) and Diever-02 (45% working interest). Slootdorp-06/07 were
drilled in Q2 2015 and placed on an extended production test in the
following quarter. Slootdorp-06/07 are currently producing
approximately 25.8 mmcf/d (4,300 boe/d) net to Vermilion.
2015 average production increased 17% versus 2014. Production additions
from the Slootdorp-06/07 and Diever-02 wells later in the year were
partially offset by the loss of production from our Middenmeer-3 well,
which was fully depleted and taken offline in February 2015. The
depletion of this well occurred as expected. The turnaround at the
Garijp Treatment Centre during Q2 2015 further impacted current year
production.
Production in the Netherlands is actively managed to optimize facility
use and regulate declines.

Activity review

During Q2 2015, Vermilion drilled two (1.9 net) wells, Slootdorp-06 and
Slootdorp-07. These wells are currently on sales during an extended
production test to size additional production equipment.
The Diever-02 exploration well (45% working interest), drilled in 2014,
came on production in late October for an extended production test
During the year, we executed numerous debottlenecking activities to
enhance deliverability from the Slootdorp wells as well as a turnaround
at the Garijp Treatment Centre.
Activity in 2016 will focus on permitting and optimization initiatives.

Financial review

		Three Months Ended			% change		Year Ended		% change
Netherlands business unit		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
($M except as indicated)		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
	Sales	37,243	41,083	25,420	(9%)	47%	129,057	123,815	4%
	Royalties	(224)	(638)	(1,171)	(65%)	(81%)	(3,082)	(5,014)	(39%)
	Operating expense	(6,263)	(5,243)	(6,200)	19%	1%	(22,746)	(24,041)	(5%)
	General and administration	(813)	(2,154)	(2,489)	(62%)	(67%)	(4,158)	(3,617)	15%
	Current income taxes	(2,930)	(4,487)	2,124	(35%)	(238%)	(12,152)	(4,154)	193%
	Fund flows from operations	27,013	28,561	17,684	(5%)	53%	86,919	86,989	–
Netbacks ($/boe)
	Sales	42.61	49.42	52.07	(14%)	(18%)	46.77	52.65	(11%)
	Royalties	(0.26)	(0.77)	(2.40)	(66%)	(89%)	(1.12)	(2.13)	(47%)
	Operating expense	(7.17)	(6.31)	(12.70)	14%	(44%)	(8.24)	(10.22)	(19%)
	General and administration	(0.93)	(2.59)	(5.10)	(64%)	(82%)	(1.51)	(1.54)	(2%)
	Current income taxes	(3.35)	(5.40)	4.35	(38%)	(177%)	(4.40)	(1.77)	149%
	Fund flows from operations netback	30.90	34.35	36.22	(10%)	(15%)	31.50	36.99	(15%)
Reference prices
	TTF ($/mmbtu)	7.28	8.48	9.16	(14%)	(21%)	8.23	8.96	(8%)
	TTF (€/mmbtu)	4.98	5.82	6.46	(14%)	(23%)	5.80	6.11	(5%)

Sales

The price of our natural gas in the Netherlands is based on the TTF
day-ahead index, as determined on the Title Transfer Facility Virtual
Trading Point operated by Dutch TSO Gas Transport Services, plus
various fees. GasTerra, a state owned entity, continues to purchase
all of the natural gas we produce in the Netherlands.
Sales per boe decreased 14% quarter-over-quarter, consistent with a
decrease in the TTF reference price. The decrease in price was
partially offset by a 5% increase in production, resulting in a 9%
decrease in sales.
On a year-over-year basis, sales per boe decreased, consistent with
declines in the TTF reference price for the respective periods. For the
three months ended December 31, 2015, the decrease in price was more
than offset by a 79% increase in production. For the year ended
December 31, 2015, the decrease in price was offset by a 17% increase
in production.

Royalties

In the Netherlands, we pay overriding royalties on certain wells
associated with an acquisition completed by the Netherlands business
unit in October 2013. As such, fluctuations in royalty expense in the
periods presented relate to the amount of production from those wells
subject to overriding royalties.

Transportation expense

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

Operating expense

Q4 2015 operating expenses on a dollar and per boe basis increased
versus Q3 2015 as a result of higher power usage and gas processing
tariffs associated with our Diever-02 exploration well, which came on
production in late October 2015.
2015 operating expenses decreased by 5% on a dollar basis compared to
2014 due in equal parts to the favourable foreign exchange impact of a
stronger Canadian dollar coupled with reduced facility operation
expenditures following cost reduction initiatives undertaken in
response to commodity price weakness. These cost reduction initiatives
were executed while growing production 17%, resulting in a 19%
reduction in per unit costs.

General and administration

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

Current income taxes

Current income taxes in the Netherlands apply to taxable income after
eligible deductions at an implied tax rate of approximately 46%. For
2016, the effective rate on current taxes is expected to be between
approximately 13% and 15%. This rate is subject to change in response
to commodity price fluctuations, the timing of capital expenditures,
and other eligible in-country adjustments.
Current income taxes in Q4 2015 were lower compared to Q3 2015 due to
decreased revenues. Current income taxes in Q4 2015 compared to Q4 2014
were higher due to increased revenues.
Current income taxes for the full year ended December 31, 2015 were
higher compared to 2014 as increased revenues in 2015 were combined
with comparatively lower tax depletion due to accelerated tax
deductions recognized in 2014.

GERMANY BUSINESS UNIT

Overview

Vermilion entered Germany in February 2014.
Holds 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 19 onshore exploration licenses in
northwest Germany, comprising approximately 850,000 net undeveloped
acres of oil and natural gas rights. Vermilion will assume
operatorship for 11 of the 19 licenses during the exploration phase.
Awarded 110,000 net acres (100% working interest) across two exploration
licenses in Lower Saxony.

Operational review

Three Months Ended

% change

Year Ended

% change

Dec 31,

Sep 30,

Dec 31,

Q4/15 vs.

Dec 31,

2015 vs.

Germany business unit

2015

2014

Q3/15

Q4/14

2015

2014

Production

Natural gas (mmcf/d)

16.17

14.00

17.71

16%

(9%)

15.78

14.99

Total (boe/d)

2,695

2,333

2,952

16%

(9%)

2,630

2,498

Activity

Capital expenditures ($M)

(441)

1,605

563

(127%)

(178%)

5,363

2,747

95%

Acquisitions ($M)

–

172,871

Gross wells drilled

–

1.00

–

Net wells drilled

–

0.25

–

Production

Q4 2015 production increased by 16% quarter-over-quarter due to a
planned maintenance shutdown in Q3 2015 and decreased 9% year-over-year
due to additions from the Deblinghausen Z7a well that was brought on
production in Q4 2014. Full year production increased 5% versus prior
year, due to 2014 volumes only reflecting production from the
acquisition’s effective date of February 1, 2014.

Activity review

The Burgmoor Z3a sidetrack well (25% working interest), was completed in
Q2 2015 and was tied-in and placed on production in Q3 2015.
In 2016, the majority of activity will be associated with permitting and
pre-drill activities for Burgmoor Z5 and two farm-in prospects. In
addition, we will continue our ongoing analysis of the proprietary
geologic data associated with the farm-in assets.

Financial review

		Three Months Ended			% change		Year Ended		% change
Germany business unit		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
($M except as indicated)		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
	Sales	9,840	9,523	13,359	3%	(26%)	41,384	41,962	(1%)
	Royalties	(1,166)	(1,477)	(2,481)	(21%)	(53%)	(6,479)	(8,613)	(25%)
	Transportation expense	(508)	(627)	(218)	(19%)	133%	(3,269)	(2,367)	38%
	Operating expense	(4,788)	(2,796)	(2,862)	71%	67%	(10,956)	(8,686)	26%
	General and administration	(3,032)	(1,311)	(2,200)	131%	38%	(7,386)	(4,688)	58%
	Current income taxes	–	–	1,145	–	(100%)	–	(44)	(100%)
	Fund flows from operations	346	3,312	6,743	(90%)	(95%)	13,294	17,564	(24%)
Netbacks ($/boe)
	Sales	39.68	44.36	49.19	(11%)	(19%)	43.10	46.03	(6%)
	Royalties	(4.70)	(6.88)	(9.13)	(32%)	(49%)	(6.75)	(9.45)	(29%)
	Transportation expense	(2.05)	(2.92)	(0.80)	(30%)	156%	(3.41)	(2.60)	31%
	Operating expense	(19.31)	(13.03)	(10.54)	48%	83%	(11.41)	(9.53)	20%
	General and administration	(12.22)	(6.11)	(8.10)	100%	51%	(7.69)	(5.14)	50%
	Current income taxes	–	–	4.21	–	(100%)	–	(0.05)	(100%)
	Fund flows from operations netback	1.40	15.42	24.83	(91%)	(94%)	13.84	19.26	(28%)
Reference prices
	TTF ($/mmbtu)	7.28	8.48	9.16	(14%)	(21%)	8.23	8.96	(8%)
	TTF (€/mmbtu)	4.98	5.82	6.46	(14%)	(23%)	5.80	6.11	(5%)

Sales

The price of our natural gas in Germany is based on the TTF month-ahead
index, as determined on the Title Transfer Facility Virtual Trading
Point operated by Dutch TSO Gas Transport Services, plus various fees.
The 3% increase in sales quarter-over-quarter is due to an increase in
production, partially offset by decreases in the TTF reference price.
On a year-over-year basis, sales per boe decreased for the three months
and year ended December 31, 2015 consistent with movements in the TTF
reference price. For the three months ended December 31, 2015, this
pricing decline was combined with a decrease in production. For the
year ended December 31, 2015, the decrease in price was almost entirely
offset by an increase in production.

Royalties

Our production in Germany is subject to state and private royalties on
sales after certain eligible deductions.
In Q4 2015, royalties as a percentage of sales was 11.8%, a decrease
versus both the 15.5% for Q3 2015 and 18.6% for Q4 2014. The decrease
in Q4 2015 versus both comparable quarters was a result of adjustments
to Q3 2015 royalties following preliminary royalty submissions recorded
in the current quarter.
Full year 2015 royalties as a percentage of sales was 15.7% versus 20.5%
for 2014 as a result of lower state royalty rates in the current year.

Transportation expense

Transportation expense in Germany relates to costs incurred to deliver
natural gas from the processing facility to the customer.
Q4 2015 transportation expense was lower than Q3 2015 due to seasonal
changes in levels of transportation facility maintenance, which are
typically higher at the beginning of the year. Q4 2015 transportation
expense was higher than Q4 2014 due to the impact of prior period
adjustments recorded in the 2014 period.
Year-over-year, transportation expense has increased as 2014 included
only eleven months of expense due to the timing of our Germany
acquisition. In addition, 2015 included a prior period adjustment
payment related to 2014.

Operating expense

Operating expenses for Germany are billed monthly by the joint venture
operator and primarily relate to tariffs charged for facility
operations and gas processing.
Q4 2015 operating expense was higher than both Q3 2015 and Q4 2014 due
in equal parts to charges for prior period maintenance expenditures and
the inclusion of a full year gas processing tariff adjustment recorded
in the current quarter.
Full year operating expense was higher on a dollar basis versus 2014 due
to the inclusion of only eleven months of expense in 2014 due to the
timing of our Germany acquisition and additional charges from the
operator relating to 2014.

General and administration

Q4 2015 general and administration expenses were higher than both Q3
2015 and Q4 2014 due largely to increased allocations from our
Corporate segment in addition to higher staffing levels and office
extension costs incurred to support our farm-in agreement.
Full year 2015 general and administration expense increased in 2015
versus 2014 due to the aforementioned increased allocations coupled
with higher staffing levels and expenditures relating to our farm-in
agreement.

Current income taxes

Current income taxes in Germany apply to taxable income after eligible
deductions at a statutory tax rate of approximately 24.2%. As a
function of tax pools in Germany, Vermilion does not presently pay
taxes in Germany.

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.
Corrib is expected to produce approximately 58 mmcf/d (9,700 boe/d) net
to Vermilion at peak production rates.

Operational and financial review

		Three Months Ended			% change		Year Ended		% change
Ireland business unit		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
($M except as indicated)		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
	Sales	57	–	–	100%	100%	57	–	100%
	Transportation expense	(1,580)	(1,766)	(1,720)	(11%)	(8%)	(6,687)	(6,394)	5%
	Operating expense	(15)	–	–	100%	100%	(15)	–	100%
	General and administration	(714)	(663)	(579)	8%	23%	(2,517)	(1,447)	74%
	Fund flows from operations	(2,252)	(2,429)	(2,299)	(7%)	(2%)	(9,162)	(7,841)	17%
Reference prices
	NBP ($/mmbtu)	7.41	8.40	9.52	(12%)	(22%)	8.33	9.10	(8%)
	NBP (€/mmbtu)	5.07	5.77	6.71	(12%)	(24%)	5.87	6.20	(5%)
Activity
	Capital expenditures	12,493	20,694	20,932	(40%)	(40%)	66,409	94,439	(30%)

Activity review

On December 29, 2015, the operator, Shell E&P Ireland Limited received
consent from the office of Ireland’s Minister for Communication, Energy
and Natural Resources.
On December 30, 2015, natural gas began to flow from our Corrib gas
project.
Production volumes at Corrib are expected to rise over a period of
approximately six months to a peak rate of approximately 58 mmcf/d
(9,700 boe/d) net to Vermilion.

Transportation expense

Transportation expense in Ireland relates to payments under a ship or
pay agreement related to the Corrib project.
Q4 2015 transportation expense is lower than Q3 2015 due to lower
tariffs for the current gas year, which began in October of 2015, under
the ship or pay agreement.

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
21 producing well bores.
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.
Contracted crude oil production is priced with reference to Dated Brent.

Operational review

Three Months Ended

% change

Year Ended

% change

Dec 31,

Sep 30,

Dec 31,

Q4/15 vs.

Dec 31,

2015 vs.

Australia business unit

2015

2014

Q3/15

Q4/14

2015

2014

Production

Crude oil (bbls/d)

7,824

6,433

6,134

22%

28%

6,454

6,571

(2%)

Inventory (mbbls)

Opening crude oil inventory

172

156

258

130

Crude oil production

720

592

564

2,356

2,398

Crude oil sales

(817)

(576)

(785)

(2,318)

(2,491)

Closing crude oil inventory

172

Activity

Capital expenditures ($M)

40,852

7,966

11,616

413%

252%

61,741

44,283

39%

Gross wells drilled

1.00

–

1.00

–

Net wells drilled

1.00

–

1.00

–

Production

Q4 2015 quarterly production increased 22% quarter-over-quarter and 28%
year-over-year, due to production additions from the horizontal
sidetrack well drilled in the quarter. The well was brought on
production in mid-November and exhibited strong well performance,
producing approximately 3,900 bbls/d through the end of Q4. Full year
2015 production decreased 2% versus the prior year.
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

In Q4 2015, we completed a horizontal sidetrack drilling program and
placed the well on production.
Additional 2015 activities included ongoing facilities maintenance,
enhancement, and refurbishment.
We plan to drill a two-well sidetrack program in Q2 2016.

Financial review

		Three Months Ended			% change		Year Ended		% change
Australia business unit		Dec 31,	Sep 30,	Dec 31,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
($M except as indicated)		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
	Sales	47,952	39,325	70,971	22%	(32%)	162,765	283,481	(43%)
	Operating expense	(13,941)	(13,766)	(17,719)	1%	(21%)	(51,676)	(61,432)	(16%)
	General and administration	(1,768)	(1,391)	(1,628)	27%	9%	(5,754)	(5,873)	(2%)
	PRRT	(1,054)	(99)	(13,568)	965%	(92%)	(6,878)	(60,340)	(89%)
	Corporate income taxes	1,201	(2,720)	(4,799)	(144%)	(125%)	(7,230)	(24,477)	(70%)
	Fund flows from operations	32,390	21,349	33,257	52%	(3%)	91,227	131,359	(31%)
Netbacks ($/boe)
	Sales	58.74	68.20	90.37	(14%)	(35%)	70.22	113.80	(38%)
	Operating expense	(17.08)	(23.87)	(22.56)	(28%)	(24%)	(22.29)	(24.66)	(10%)
	General and administration	(2.17)	(2.41)	(2.07)	(10%)	5%	(2.48)	(2.36)	5%
	PRRT	(1.29)	(0.17)	(17.28)	659%	(93%)	(2.97)	(24.22)	(88%)
	Corporate income taxes	1.47	(4.72)	(6.11)	(131%)	(124%)	(3.12)	(9.83)	(68%)
	Fund flows from operations netback	39.67	37.03	42.35	7%	(6%)	39.36	52.73	(25%)
Reference prices
	Dated Brent (US $/bbl)	43.69	50.26	76.27	(13%)	(43%)	52.46	98.99	(47%)
	Dated Brent ($/bbl)	58.34	65.81	86.62	(11%)	(33%)	67.09	109.36	(39%)

Sales

Crude oil in Australia is priced with reference to Dated Brent.
Sales per boe decreased 14% in Q4 2015 versus Q3 2015, consistent with a
decrease in the Dated Brent reference price. This decrease in sales per
boe was more than offset by an increase in sold volumes, resulting in a
22% increase in sales
Year-over-year, sales on a dollar and on a per boe basis decreased for
the three months and year ended December 31, 2015, consistent with
decreases in Dated Brent reference price.

Royalties and transportation expense

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

Operating expense

Operating expense on a dollar basis remained relatively consistent
between Q3 and Q4 2015. The flat cost profile was achieved while crude
volumes sold increased by 42% as a result of strong production growth
and a 97,000 bbl inventory draw, which led to increase recognition of
deferred operating expense. A continued focus on cost reduction
initiatives resulted in reduced helicopter and vessel costs,
contributing to a 28% decrease in per unit costs.
Operating expense on a dollar basis decreased for the three months and
year ended December 31, 2015 versus 2014 due to cost-cutting
initiatives, favourable foreign exchange from a weaker Australian
dollar during 2015, and inventory variances. On a per boe basis,
operating expense decreased by 24% and 10% during the three months and
year ended 2015 versus 2014 as a result of savings from cost reduction
initiatives undertaken in response to commodity price weakness – these
initiatives included reduced vessel usage, lower diesel consumption,
and reduced staffing costs.

General and administration

Fluctuations in general and administration expense for Q4 2015 versus
the comparable quarters is largely the result of the timing of
expenditures. Full year 2015 general and administration expense was
relatively consistent with 2014.

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.
Australia is not expected to incur any corporate income tax or PRRT for
2016. This is subject to change in response to commodity price
fluctuations, the timing of capital expenditures and other eligible
in-country adjustments.
Combined corporate income taxes and PRRT for the three months and full
year ended December 31, 2015 were lower than the comparable periods as
a result of decreased revenues and increased capital spending in the
2015 periods. Q4 2015 combined taxes were lower compared to Q3 2015 as
increased sales were offset by increased capital spending.

UNITED STATES BUSINESS UNIT

Overview

Entered the United States in September 2014.
Interests include approximately 90,700 acres of land (98% 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,	Q4/15 vs.	Q4/15 vs.	Dec 31,	Dec 31,	2015 vs.
($M except as indicated)		2015	2015	2014	Q3/15	Q4/14	2015	2014	2014
Production
	Crude oil (bbls/d)	420	226	195	86%	115%	231	49	371%
	NGLs (bbls/d)	29	–	–	100%	100%	7	–	100%
	Natural gas (mmcf/d)	0.20	–	–	100%	100%	0.05	–	100%
	Total (boe/d)	483	226	195	114%	148%	247	49	404%
Activity
	Capital expenditures	5,643	3,226	460	75%	1,127%	12,250	460	2,563%
	Acquisitions	(21)	12,785	–			12,764	11,175
	Gross wells drilled	2.00	–	–			3.00	–
	Net wells drilled	2.00	–	–			3.00	–
	Sales	1,864	1,075	1,330	73%	40%	4,288	1,330	222%
	Royalties	(551)	(309)	(366)	78%	51%	(1,257)	(366)	243%
	Operating expense	(271)	(146)	(241)	86%	12%	(742)	(241)	208%
	General and administration	(897)	(896)	(959)	–	(6%)	(3,836)	(959)	300%
	Fund flows from operations	145	(276)	(236)	153%	161%	(1,547)	(236)	556%
Netbacks ($/boe)
	Sales	41.94	51.60	74.08	(19%)	(43%)	47.53	74.08	(36%)
	Royalties	(12.40)	(14.83)	(20.38)	(16%)	(39%)	(13.93)	(20.38)	(32%)
	Operating expense	(6.11)	(6.98)	(13.44)	(12%)	(55%)	(8.23)	(13.44)	(39%)
	General and administration	(20.18)	(43.03)	(53.44)	(53%)	(62%)	(42.51)	(53.44)	(20%)
	Fund flows from operations netback	3.25	(13.24)	(13.18)	125%	125%	(17.14)	(13.18)	30%
Reference prices
	WTI (US $/bbl)	42.18	46.43	73.15	(9%)	(42%)	48.80	93.00	(48%)
	WTI ($/bbl)	56.32	60.80	83.08	(7%)	(32%)	62.41	102.75	(39%)
	Henry Hub (US $/mmbtu)	2.27	2.77	4.00	(18%)	(43%)	2.66	4.41	(40%)
	Henry Hub ($/mmbtu)	3.03	3.62	4.54	(16%)	(33%)	3.41	4.88	(30%)

Activity review

Vermilion drilled two (2.0 net) wells in the East Finn prospect area in
Q4 2015 with well completions planned for Q1 2016.
In Q4 2015, we initiated sales of associated natural gas from our East
Finn wells, enabled by the completion of construction of a gas
gathering system in the area.
During the year, we consolidated our ownership interest in the eastern
Powder River Basin of Wyoming to a 100% working interest through the US
$9.6 million acquisition of the remaining 30% interest that was
previously outstanding. The acquisition encompassed an estimated 0.9
mmboe of 2P reserves and an additional 22,000 net acres.
In 2016, we plan to drill one (1.0 net) well and tie-in an additional
two (2.0 net) wells drilled in Q4 2015.

Sales

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

Royalties

Our production in the United States is subject to federal and private
royalties, severance tax, and ad valorem tax.
Royalties as a percentage of sales for the three months and year ended
December 31, 2015 of approximately 29.6% was slightly higher than Q3
2015 (28.7%) and the 2014 periods (27.5%) due to nominally higher
royalty rates on the well we brought online in August 2015.

Operating expense

Operating expense decreased quarter-over-quarter by 12% from $6.98/boe
to $6.11/boe.

General and administration

General and administration expense was relatively consistent
quarter-over-quarter. Full year 2015 expenditures were higher than
2014 due to the timing of the formation of the US business unit in Q4
2014.

CORPORATE

Overview

Our Corporate segment includes costs related to our global hedging
program, financing expenses, and general and administration expenses,
primarily incurred in Canada and not directly related to the operations
of our business units.

Financial review

	Three Months Ended			Year Ended
	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2015	2015	2014	2015	2014
General and administration recovery (expense)	3,356	2,359	1,224	7,172	(7,423)
Current income taxes	313	(480)	(642)	(1,091)	(1,420)
Interest expense	(16,584)	(15,420)	(12,943)	(59,852)	(49,655)
Realized gain on derivatives	21,164	10,854	22,816	41,356	36,712
Realized foreign exchange (loss) gain	(252)	309	(179)	623	(821)
Realized other income	243	227	202	896	732
Fund flows from operations	8,240	(2,151)	10,478	(10,896)	(21,875)

General and administration

The increase in the recovery of general and administration costs for the
three months and year ended December 31, 2015 versus the comparable
periods in the prior year is due to a decrease in staff-related
expenditures, general cost saving initiatives in response to declining
crude oil prices, and increased salary allocations to the various
business unit segments.

Current income taxes

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

Interest expense

The increase in interest expense in Q4 2015 versus all comparable
periods is primarily due to increased average borrowings under our
revolving credit facility. In addition, interest expense for the three
months and year ended December 31, 2015 versus the comparable periods
in 2014 was higher due to interest expense related to a finance lease
recognized in Q1 2015.

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. 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 (loss) 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 forward collars, swaps, and
physical fixed price arrangements.
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 in Q4 2015 related primarily to amounts received on
our TTF, WTI, and Dated Brent derivatives, partially offset by payments
made on our foreign exchange derivatives.
A listing of derivative positions as at December 31, 2015 is included in
“Supplemental Table 2” of this MD&A.

FINANCIAL PERFORMANCE REVIEW

							Year Ended
							Dec 31,	Dec 31,	Dec 31,
($M except per share)							2015	2014	2013
Total assets							4,209,220	4,386,091	3,708,719
Long-term debt							1,162,998	1,238,080	990,024
Petroleum and natural gas sales							939,586	1,419,628	1,273,835
Net earnings (loss)							(217,302)	269,326	327,641
Net earnings (loss) per share
	Basic						(1.98)	2.55	3.24
	Diluted						(1.98)	2.51	3.20
Cash dividends ($/share)							2.58	2.58	2.40

		Three Months Ended
		Dec 31,	Sep 30,	Jun 30,	Mar 31,	Dec 31,	Sep 30,	Jun 30,	Mar 31,
($M except per share)		2015	2015	2015	2015	2014	2014	2014	2014
Petroleum and natural gas sales		234,319	245,051	264,331	195,885	306,073	344,688	387,684	381,183
Net earnings (loss)		(142,080)	(83,310)	6,813	1,275	58,642	53,903	53,993	102,788
Net earnings (loss) per share
	Basic	(1.28)	(0.76)	0.06	0.01	0.55	0.50	0.51	1.00
	Diluted	(1.28)	(0.76)	0.06	0.01	0.54	0.50	0.50	0.99

The following table shows a reconciliation of the change in net earnings
(loss):

($M)	Q4/15 vs. Q3/15	Q4/15 vs. Q4/14	2015 vs. 2014
Net earnings (loss) – Comparative period	(83,310)	58,642	269,326
Changes in:
Fund flows from operations	7,006	(49,087)	(288,698)
Equity based compensation	(4,760)	(3,140)	(7,430)
Unrealized gain or loss on derivative instruments	(4,627)	10,236	16,177
Unrealized foreign exchange gain or loss	(21,315)	(2,371)	26,386
Unrealized other expense	75	511	484
Accretion	(125)	(137)	2
Depletion and depreciation	41,031	9,369	(33,064)
Deferred tax	(87,432)	(34,480)	74,138
Impairment	11,377	(131,623)	(274,623)
Net loss – Current period	(142,080)	(142,080)	(217,302)

The fluctuations in net earnings (loss) from quarter-to-quarter and from
year-to-year are caused by changes in both cash and non-cash based
income and charges. Cash based items are reflected in fund flows from
operations and include: sales, royalties, operating expenses,
transportation, general and administration expense, current tax
expense, interest expense, realized gains and losses on derivative
instruments, and realized foreign exchange gains and losses. 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 acquisitions or charges resulting from impairment or impairment
recoveries.

Equity based compensation
Equity based compensation expense relates to non-cash compensation
expense attributable to long-term incentives granted to directors,
officers, and employees under the Vermilion Incentive Plan (“VIP”). The
expense is recognized over the vesting period based on the grant date
fair value of awards, adjusted for the ultimate number of awards that
actually vest as determined by the Company’s achievement of performance
conditions.

Equity based compensation expense for the three months and year ended
December 31, 2015 was higher versus the comparable periods in 2014 due
to a higher average number of awards outstanding and higher 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.

For the year ended December 31, 2015, we recognized an unrealized gain
on derivative instruments of $43.5 million, relating primarily to our
TTF, Dated Brent, and WTI swaps and collars. As at December 31, 2015,
we have a net derivative asset position of $68.3 million.

Unrealized foreign exchange gain or loss
As a result of Vermilion’s international operations, Vermilion conducts
business in currencies other than the Canadian dollar and has monetary
assets and liabilities (including cash, receivables, payables,
derivative assets and liabilities, and intercompany loans) denominated
in such currencies. Vermilion’s exposure to foreign currencies
includes the US dollar, the Euro and the Australian dollar.

Unrealized foreign exchange gains and losses are the result of
translating monetary assets and liabilities held in non-functional
currencies to the respective functional currencies 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, 2015, the Canadian dollar
weakened against the US dollar and remained relatively flat against the
Euro, leading to an unrealized foreign exchange loss of $6.4 million.
During the year ended December 31, 2015, the Canadian dollar weakened
significantly versus the US dollar, but was offset by a strengthening
in the Canadian dollar against the Euro resulting in an unrealized
foreign exchange gain of $8.8 million.

Accretion
Fluctuations in accretion expense are primarily the result of changes in
discount rates applicable to the balance of asset retirement
obligations and additions resulting from drilling and acquisitions.

Q4 2015 accretion expense was relatively consistent with all comparative
periods.

Depletion and depreciation
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 2015 of $18.88 was
lower as compared to $28.28 in Q3 2015 and $24.42 for Q4 2014. This
decrease is primarily due to increased production natural gas
properties in Drayton Valley, Canada which have a lower per boe
depletion expense. For the year ended December 31, 2015, depletion and
depreciation on a per boe basis of $22.98 was relatively consistent
with $23.31 for the comparable period in 2014 as increased production
from natural gas properties in the Netherlands and light crude oil
properties in Saskatchewan, Canada, which both have relatively higher
per boe depletion expense, was offset with higher production from
natural gas properties in Drayton Valley, Canada, which have a
relatively lower per boe depletion expense.

Deferred tax
Deferred tax expense (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. The
increase in deferred tax recovery largely pertains to the tax effect on
the $274.6 million impairment charge recorded in 2015, increased
accounting basis depletion primarily associated with higher global
production, partially offset by a valuation allowance recorded on
deferred tax assets. The valuation allowance relates to certain
non-capital losses for which there is uncertainty as to the Company’s
ability to fully utilize such losses when applying forecasted commodity
prices in effect as at December 31, 2015.

Impairment
For the three months and year ended December 31, 2015, Vermilion
recorded impairment charges of $131.6 million and $274.6 million,
respectively, related to the light crude oil play in Saskatchewan,
Canada ($267.9 million in 2015) and the shallow coal bed methane gas
properties in Alberta, Canada ($6.7 million in 2015). These impairment
charges were a result of declines in the price forecasts for crude oil
and natural gas in Canada which decreased the expected future cash
flows from the CGU.

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	2015	2014
Canada ⁽¹⁾	25.5% / 27.0%	25.5%
France	34.4%	34.4%
Netherlands	46.0%	46.0%
Germany	24.2%	22.8%
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.

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. Vermilion did not pay any dividends from
its French entities in 2015.

Tax pools
As at December 31, 2015, we had the following tax pools:

($M)	Oil & Gas Assets	Tax Losses⁽⁴⁾	Other	Total
Canada	1,176,574 ⁽¹⁾	341,445	2,448	1,520,467
France	430,735 ⁽²⁾	14,171	–	444,906
Netherlands	54,104 ⁽³⁾	–	–	54,104
Germany	112,038 ⁽³⁾	43,360	18,977	174,375
Ireland	1,028,986 ⁽⁴⁾	429,987	–	1,458,973
Australia	265,743 ⁽¹⁾	–	–	265,743
United States	28,950 ⁽¹⁾	15,767	–	44,717
Total	3,097,130 ⁽¹⁾	844,730	21,425	3,963,285

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 excess with debt (including
borrowing using the unutilized capacity of our existing revolving
credit facility) or issue equity.

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 1.3 in a
normalized commodity price environment. When prices trend higher, we
may target a lower ratio and conversely, in a lower commodity price
environment, the debt ratio may prove to 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 ratio is expected to be higher than the longer term target
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 consists of our revolving credit facility and our
senior unsecured notes. The applicable annual interest rates and the
balances recognized on our balance sheet are as follows:

	Annual Interest Rate		As at
	Dec 31,	Dec 31,	Dec 31,	Dec 31,
($M)	2015	2014	2015	2014
Revolving credit facility	3.1%	3.1%	1,162,998	1,014,067
Senior unsecured notes ⁽¹⁾	6.5%	6.5%	224,901	224,013
Long-term debt	3.7%	3.8%	1,387,899	1,238,080

⁽¹⁾	The senior unsecured notes, which matured on February 10, 2016, are included in the current portion of long-term debt as at December 31, 2015.

Revolving Credit Facility
On January 30, 2015, Vermilion increased its credit facility from $1.5
billion to $1.75 billion. During Q2 2015, we negotiated a further
expansion and extension of our existing revolving credit facilities
from $1.75 billion to $2 billion with a maturity of May 2019. This
allowed Vermilion to redeem the senior unsecured notes, which matured
on February 10, 2016, with a portion of the credit facility. The
facility bears interest at rates applicable to demand loans plus
applicable margins. The following table outlines the terms of our
revolving credit facility:

	As at
	Dec 31,	Dec 31,
	2015	2014
Total facility amount	$2.0 billion	$1.5 billion
Amount drawn	$1.2 billion	$1.0 billion
Letters of credit outstanding	$25.2 million	$8.6 million
Facility maturity date	31-May-19	31-May-17

In addition, the revolving credit facility is subject to the following
covenants:

		As at
		Dec 31,	Dec 31,
Financial covenant	Limit	2015	2014
Consolidated total debt to consolidated EBITDA	4.0	2.23	1.21
Consolidated total senior debt to consolidated EBITDA	3.0	1.83	0.99
Consolidated total senior debt to total capitalization	50%	36%	31%

Our covenants include financial measures defined within our revolving
credit facility agreement that are not defined under GAAP. 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.

Vermilion was in compliance with its financial covenants for all periods
presented.

Senior Unsecured Notes
As at December 31, 2015, we had outstanding senior unsecured notes that
were senior unsecured obligations and ranked pari passu with all our
unsecured and unsubordinated indebtedness. The following table
outlines the terms of these notes:


Total issued and outstanding amount	$225.0 million
Interest rate	6.5% per annum
Issued date	February 10, 2011
Maturity date	February 10, 2016

Vermilion redeemed the full principal outstanding of the notes on
February 10, 2016 using available capacity under the revolving credit
facility. The notes were initially recognized at fair value net of
transaction costs and were subsequently measured at amortized cost
using an effective interest rate of 7.1%.

Net debt
Net debt is reconciled to its most directly comparable GAAP measure,
long-term debt, as follows:

	As at
	Dec 31,	Dec 31,
($M)	2015	2014
Long-term debt	1,162,998	1,238,080
Current liabilities ⁽¹⁾	503,731	365,729
Current assets	(284,778)	(338,159)
Net debt	1,381,951	1,265,650

Ratio of net debt to fund flows from operations	2.7	1.6

⁽¹⁾	Includes the current portion of long-term debt, which, as at December 31, 2015, represented the senior unsecured notes that matured on February 10, 2016.

Long term debt, including the current portion, as at December 31, 2015,
increased to $1.39 billion from $1.24 billion as at December 31, 2014
as a result of draws on the revolving credit facility during the
current year to fund capital expenditures, particularly relating to
development expenditures in Canada, France, Ireland, and Australia.
The increase in long-term debt resulted in an increase to net debt from
$1.27 billion to $1.38 billion. As a result of this increase to
long-term debt coupled with weak commodity prices, the ratio of net
debt to fund flows from operations increased from 1.6 times as at
December 31, 2014 to 2.7 times for the year ended December 31, 2015.

Shareholders’ capital
During the year ended December 31, 2015, we maintained monthly dividends
at $0.215 per share and declared dividends which totalled $283.6
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. As a further
step to preserve our financial flexibility and conservatively exercise
our access to capital, we amended our existing DRIP to include a
Premium Dividend™ Component in February 2015. 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. We view
implementation of a Premium Dividend™ as a short-term measure to
maintain our financial flexibility while we continue to lower our unit
costs and await further clarity on the direction of commodity prices.
Both components of our program can be reduced or eliminated at the
company’s discretion, offering considerable flexibility. We will
actively monitor our ongoing needs and manage our continued use of each
component as circumstances dictate.

Although we currently expect to be able to maintain our current
dividend, fund flows from operations may not be sufficient during this
period to fund cash dividends, capital expenditures and asset
retirement obligations. We will evaluate our ability to finance any
shortfalls 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, 2014		107,303	1,959,021
Issuance of shares pursuant to the dividend reinvestment and Premium Dividend^TM plans		3,338	155,033
Vesting of equity based awards		1,158	56,855
Share-settled dividends on vested equity based awards		135	7,561
Shares issued pursuant to the employee savings and bonus plans		57	2,619
Balance as at December 31, 2015		111,991	2,181,089

As at December 31, 2015, there were approximately 1.7 million VIP awards
outstanding. As at February 25, 2016, there were approximately 113.0
million common shares issued and outstanding.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

As at December 31, 2015, 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	226,625	–	1,171,620	–	1,398,245
Operating lease obligations	12,535	22,049	16,617	9,288	60,489
Ship or pay agreement relating to the Corrib project	8,215	8,893	7,292	40,446	64,846
Purchase obligations	17,897	4,071	3,156	–	25,124
Drilling and service agreements	23,205	2,480	–	–	25,685
Total contractual obligations and commitments	288,477	37,493	1,198,685	49,734	1,574,389

ASSET RETIREMENT OBLIGATIONS

As at December 31, 2015, asset retirement obligations were $305.6
million compared to $350.8 million as at December 31, 2014.

The decrease in asset retirement obligations is largely attributable to
an overall increase in the discount rates applied to the abandonment
obligations.

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.

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 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.

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, revenues and expenses, gains and losses,
and 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.

Depletion and depreciation
We classify our assets into depletion units, which are groups of assets
or properties that are within a specific production area and have
similar economic lives. The depletion units represent the lowest level
of disaggregation for which we accumulate costs for the purposes of
calculating and recording depletion and depreciation.

The net carrying value of each depletion unit is depleted using the unit
of production method by reference to the ratio of production in the
period to the total proven and probable reserves, taking into account
the future development costs necessary to bring the applicable reserves
into production. As a result, depletion and depreciation charges are
based on estimates of total proven and probable reserves that we expect
to recover in the future. The reserve estimates are reviewed annually
by management or when material changes occur to the underlying
assumptions.

Asset retirement obligations
Our estimate of asset retirement obligations are based on past
experience and current economic factors which management believes are
reasonable. The estimates include assumptions of environmental
regulations, legal requirements, technological advances, inflation and
the timing of expenditures, all of which impact our measurement of the
present value of the obligations. Due to these estimates, the actual
cost of the obligation may change from period to period due to new
information being available. Several or all of these estimates are
subject to change and such changes could have a material impact on our
financial position and net earnings.

Assessment of impairments
Impairment tests are performed at the level of the cash generating unit
(“CGU”), which are determined based on management’s judgment of the
lowest level at which there are identifiable cash inflows which are
largely independent of the cash inflows of other groups of assets or
properties. The factors used to determine CGUs vary by country due to
the unique operating and geographic circumstances in each
jurisdiction. However, in general, we will assess the following
factors in determining whether a group of assets generate largely
independent cash inflows: 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 or transport
production.

The calculation of the recoverable amount of CGUs is based on market
factors as well as estimates of reserves and resources and future costs
required to develop reserves and resources. Our reserve and resource
estimates and the related future cash flows are subject to measurement
uncertainty, and the impact on the consolidated financial statements in
future periods could be material. Considerable judgment is used in
determining the recoverable amount of petroleum and natural gas assets
as well as exploration and evaluation assets, including determining the
quantity of reserves and resources, the time horizon to develop and
produce such reserves and resources, and the estimated revenues and
expenditures from such production.

Taxes
Tax interpretations, regulations and legislation in the various
jurisdictions in which we operate are subject to change. Such changes
can affect the timing of the reversal of temporary tax differences, the
tax rates in effect when such differences reverse and our ability to
use tax losses and other credits in the future. The determination of
deferred tax amounts recognized in the consolidated financial
statements was based on management’s assessment of the tax positions,
including consideration of their technical merits and communications
with tax authorities. The effect of a change in income tax rates or
legislation on tax assets and liabilities is recognized in net earnings
in the period in which the change is enacted.

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, 2015.

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

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

The impacts of the adoption of the following pronouncements are
currently being evaluated.

IFRS 9 “Financial Instruments”
On July 24, 2014, the IASB issued the final element of its comprehensive
response to the financial crisis by issuing IFRS 9 “Financial
Instruments”. The improvements introduced by IFRS 9 includes a model
for classification and measurement, a single, forward-looking ‘expected
loss’ impairment model and a substantially-reformed approach to hedge
accounting. Vermilion will adopt the standard for reporting periods
beginning January 1, 2018.

IFRS 15 “Revenue from Contracts with Customers”
On May 28, 2014, the IASB issued IFRS 15 “Revenue from Contracts with
Customers”, a new standard that specifies recognition requirements for
revenue as well as requiring entities to provide the users of financial
statements with more informative and relevant disclosures. The
standard replaces IAS 11 “Construction Contracts” and IAS 18 “Revenue”
as well as a number of revenue-related interpretations. Vermilion will
adopt the standard for reporting periods beginning January 1, 2018.

IFRS 16 “Leases”
On January 13, 2016, the IASB issued IFRS 16, “Leases”, a new standard
which will replace IAS 17, “Leases”. Under IFRS 16, a single
recognition and measurement model will apply for lessees which will
require recognition of assets and liabilities for most leases.
Vermilion will adopt the standard for reporting periods beginning
January 1, 2019.

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 workplace free of incidents. Our mantra is
HSE: Everywhere. Everyday. Everyone.

We maintain health, safety and environmental practices and procedures
that comply with or exceed regulatory requirements and industry
standards. It is a condition of employment that our personnel work
safely and in accordance with established regulations and procedures.

In 2015, we remained committed to the principles of the Responsible
Canadian Energy™ program set out by the Canadian Association of
Petroleum Producers. Responsible Canadian Energy™ is an
association-wide performance reporting program to demonstrate progress
in environmental, health, safety, and social performance.

We uphold our commitment to keep our people safe and to reduce impacts
to land, water and air, as policies and procedures demonstrating
leadership in these areas, were maintained and further developed in
2015. Examples of our accomplishments during the year included:

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 100% score and
a CDLI ranking;
Emphasized improving energy efficiency, greenhouse gas emissions
reduction and water efficiency optimization;
Further refined and expanded our enterprise wide corporate risk
register;
Developed a robust organizational wide HSE leadership training program
to improve hazard identification and risk reduction;
Implemented a fair culture policy to ensure transparency in our
processes;
Developed a robust risk mitigation program around our top fatal risk and
energy type exposures;
Developed a robust hazard identification and risk mitigation program
specific to environmentally sensitive areas;
Audited our HSE and asset integrity management systems;
Updated various key Corporate HSE Standards such as our process hazards
analysis;
Reduced long-term environmental liabilities through decommissioning,
abandoning and reclaiming well leases and facilities;
Performed continuous 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.

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 will be provided in our
Management Proxy Circular, which will be filed on SEDAR (www.sedar.com)
and mailed to all shareholders on April 6, 2016.

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, 2015, 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.

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, 2015. The effectiveness of
Vermilion’s internal control over financial reporting as of December
31, 2015 has been audited by Deloitte LLP, as reflected in their report
included in the 2015 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, 2015, that have materially affected, or are
reasonably likely to materially affect, the internal controls over
financial reporting.

Supplemental Table 1: Netbacks

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

	Three Months Ended December 31, 2015			Year Ended December 31, 2015				Three Months Ended December 31, 2014		Year Ended December 31, 2014
	Oil & NGLs	Natural Gas	Total	Oil & NGLs	Natural Gas	Total		Total		Total
	$/bbl	$/mcf	$/boe	$/bbl	$/mcf	$/boe		$/boe		$/boe
Canada
Sales	44.03	2.57	28.94	49.73	2.78	34.32		51.27		64.06
Royalties	(5.15)	(0.12)	(2.80)	(5.26)	(0.07)	(3.01)		(7.12)		(7.81)
Transportation	(2.04)	(0.16)	(1.48)	(2.38)	(0.17)	(1.75)		(1.57)		(1.74)
Operating	(10.97)	(1.40)	(9.62)	(10.47)	(1.41)	(9.54)		(8.80)		(9.07)
Operating netback	25.87	0.89	15.04	31.62	1.13	20.02		33.78		45.44
General and administration			(1.44)			(1.81)		(1.29)		(2.00)
Fund flows from operations netback			13.60			18.21		32.49		43.44
France
Sales	54.88	2.81	54.20	63.31	2.52	62.67		79.25		105.43
Royalties	(6.23)	(0.32)	(6.15)	(6.06)	(0.33)	(6.00)		(6.07)		(6.95)
Transportation	(3.72)	–	(3.65)	(3.47)	–	(3.42)		(3.94)		(4.64)
Operating	(13.55)	(1.81)	(13.50)	(11.34)	(1.31)	(11.30)		(13.01)		(15.09)
Operating netback	31.38	0.68	30.90	42.44	0.88	41.95		56.23		78.75
General and administration			(4.18)			(4.50)		(3.62)		(5.12)
Other income			–			7.08		–		–
Current income taxes			3.87			(5.29)		(5.89)		(16.36)
Fund flows from operations netback			30.59			39.24		46.72		57.27
Netherlands
Sales	48.30	7.09	42.61	49.98	7.79	46.77		52.07		52.65
Royalties	–	(0.04)	(0.26)	–	(0.19)	(1.12)		(2.40)		(2.13)
Operating	–	(1.21)	(7.17)	–	(1.39)	(8.24)		(12.70)		(10.22)
Operating netback	48.30	5.84	35.18	49.98	6.21	37.41		36.97		40.30
General and administration			(0.93)			(1.51)		(5.10)		(1.54)
Current income taxes			(3.35)			(4.40)		4.35		(1.77)
Fund flows from operations netback			30.90			31.50		36.22		36.99
Germany
Sales	–	6.61	39.68	–	7.18	43.10		49.19		46.03
Royalties	–	(0.78)	(4.70)	–	(1.12)	(6.75)		(9.13)		(9.45)
Transportation	–	(0.34)	(2.05)	–	(0.57)	(3.41)		(0.80)		(2.60)
Operating	–	(3.22)	(19.31)	–	(1.90)	(11.41)		(10.54)		(9.53)
Operating netback	–	2.27	13.62	–	3.59	21.53		28.72		24.45
General and administration			(12.22)			(7.69)		(8.10)		(5.14)
Current income taxes			–			–		4.21		(0.05)
Fund flows from operations netback			1.40			13.84		24.83		19.26
Australia
Sales	58.74	–	58.74	70.22	–	70.22		90.37		113.80
Operating	(17.08)	–	(17.08)	(22.29)	–	(22.29)		(22.56)		(24.66)
PRRT⁽¹⁾	(1.29)	–	(1.29)	(2.97)	–	(2.97)		(17.28)		(24.22)
Operating netback	40.37	–	40.37	44.96	–	44.96		50.53		64.92
General and administration			(2.17)			(2.48)		(2.07)		(2.36)
Corporate income taxes			1.47			(3.12)		(6.11)		(9.83)
Fund flows from operations netback			39.67			39.36		42.35		52.73
United States
Sales	44.83	0.52	41.94	49.10	0.52	47.53		74.08		74.08
Royalties	(13.19)	(0.30)	(12.40)	(14.36)	(0.30)	(13.93)		(20.38)		(20.38)
Operating	(6.56)	–	(6.11)	(8.52)	–	(8.23)		(13.44)		(13.44)
Operating netback	25.08	0.22	23.43	26.22	0.22	25.37		40.26		40.26
General and administration			(20.18)			(42.51)		(53.44)		(53.44)
Fund flows from operations netback			3.25			(17.14)		(13.18)		(13.18)
Total Company
Sales	51.64	4.55	41.04	58.80	4.98	47.07		63.79		77.75
Realized hedging gain	2.69	0.84	3.71	1.32	0.53	2.07		4.76		2.01
Royalties	(4.32)	(0.16)	(2.85)	(4.58)	(0.24)	(3.30)		(5.41)		(5.92)
Transportation	(2.09)	(0.23)	(1.78)	(2.30)	(0.30)	(2.09)		(1.98)		(2.32)
Operating	(13.35)	(1.52)	(11.50)	(13.06)	(1.46)	(11.32)		(12.48)		(12.72)
PRRT⁽¹⁾	(0.33)	–	(0.18)	(0.58)	–	(0.34)		(2.83)		(3.30)
Operating netback	34.24	3.48	28.44	39.60	3.51	32.09	–	45.85	–	55.50
General and administration			(2.18)			(2.68)		(2.76)		(3.38)
Interest expense			(2.90)			(3.00)		(2.70)		(2.72)
Realized foreign exchange (loss) gain			(0.04)			0.03		(0.03)		(0.04)
Other income			0.04			1.64		0.04		0.04
Corporate income taxes⁽¹⁾			0.55			(2.22)		(1.73)		(5.31)
Fund flows from operations netback			23.91			25.86		38.67		44.09

⁽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.

Supplemental Table 2: Hedges

The following tables outline Vermilion’s outstanding risk management
positions as at December 31, 2015:

	Note	Volume	Strike Price(s)
Crude Oil
WTI – Collar
July 2015 – March 2016	1	250 bbl/d	75.00 – 83.45 CAD $
July 2015 – June 2016	2	500 bbl/d	75.50 – 85.08 CAD $
Dated Brent – Collar
July 2015 – June 2016	3	1,000 bbl/d	80.50 – 93.49 CAD $
July 2015 – June 2016	4	500 bbl/d	64.50 – 75.48 US $
October 2015 – June 2016	5	250 bbl/d	82.00 – 94.55 CAD $
January 2016 – June 2016	1	250 bbl/d	84.00 – 93.70 CAD $

North American Natural Gas
AECO – Collar
November 2015 – March 2016		2,500 GJ/d	2.50 – 3.76 CAD $
November 2015 – October 2016		10,000 GJ/d	2.56 – 3.23 CAD $
January 2016 – December 2016		10,000 GJ/d	2.53 – 3.29 CAD $
April 2016 – October 2016		5,000 GJ/d	2.30 – 2.80 CAD $
AECO Basis – Fixed Price Differential
November 2015 – March 2016		2,500 mmbtu/d	Nymex HH less 0.47 US $
Nymex HH – Collar
November 2015 – March 2016	6	5,000 mmbtu/d	3.25 – 3.86 US $

⁽¹⁾	The contracted volumes increase to 500 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽²⁾	The contracted volumes increase to 1,250 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽³⁾	The contracted volumes increase to 2,500 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽⁴⁾	The contracted volumes increase to 1,000 boe/d for any monthly settlement periods above the contracted ceiling price.
⁽⁵⁾	The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽⁶⁾	The contracted volumes increase to 10,000 mmbtu/d for any monthly settlement periods above the contracted ceiling price.

	Note	Volume	Strike Price(s)
European Natural Gas
NBP – Call
October 2016 – March 2017		2,638 GJ/d	4.64 GBP £
NBP – Collar
April 2016 – March 2017		2,638 GJ/d	3.79 – 4.53 GBP £
January 2017 – December 2017		2,638 GJ/d	3.22 – 3.75 GBP £
January 2018 – December 2018		2,638 GJ/d	2.99 – 3.63 GBP £
NBP – Put
April 2016 – September 2016		2,638 GJ/d	3.79 GBP £
NBP – Swap
July 2015 – March 2016		2,592 GJ/d	6.42 EUR €
October 2015 – March 2016		10,368 GJ/d	6.54 EUR €
January 2016 – June 2016		5,184 GJ/d	6.24 EUR €
January 2016 – June 2016		2,592 GJ/d	6.82 US $
July 2016 – March 2017		2,592 GJ/d	5.43 EUR €
January 2017 – December 2017	1	2,638 GJ/d	4.00 GBP £
January 2018 – December 2018	2	2,638 GJ/d	3.83 GBP £
TTF – Call
October 2016 – March 2017		2,592 GJ/d	6.03 EUR €
TTF – Collar
January 2016 – December 2016	3	2,592 GJ/d	5.76 – 6.50 EUR €
April 2016 – December 2016	4	12,960 GJ/d	5.58 – 6.21 EUR €
April 2016 – March 2017	5	5,184 GJ/d	5.28 – 6.35 EUR €
July 2016 – December 2016		2,592 GJ/d	5.00 – 5.63 EUR €
July 2016 – March 2017	3	2,592 GJ/d	5.07 – 6.56 EUR €
July 2016 – March 2018	3	2,592 GJ/d	5.32 – 6.54 EUR €
October 2016 – December 2017		2,592 GJ/d	5.00 – 5.89 EUR €
January 2017 – December 2017	6	7,776 GJ/d	5.00 – 6.15 EUR €
January 2018 – December 2018		5,184 GJ/d	4.17 – 5.03 EUR €
TTF – Put
April 2016 – September 2016		2,592 GJ/d	5.21 EUR €
TTF – Swap
January 2015 – March 2016		5,184 GJ/d	6.40 EUR €
January 2015 – June 2016		2,592 GJ/d	6.07 EUR €
February 2015 – March 2016		5,184 GJ/d	6.24 EUR €
April 2015 – March 2016		5,832 GJ/d	6.18 EUR €
October 2015 – March 2016		2,592 GJ/d	6.64 EUR €
January 2016 – June 2016		5,184 GJ/d	5.94 EUR €
April 2016 – December 2016		2,592 GJ/d	5.91 EUR €
July 2016 – June 2018		2,700 GJ/d	5.58 EUR €
October 2016 – December 2016		2,592 GJ/d	5.45 EUR €
January 2017 – December 2017	7	2,592 GJ/d	5.04 EUR €

Electricity
AESO – Swap
January 2016 – December 2016		93.6 MWh/d	38.58 CAD $

Interest Rate
CDOR to fixed – Swap
September 2015 – September 2019		100,000,000 CAD $/year	1.00 %
October 2015 – October 2019		100,000,000 CAD $/year	1.10 %

⁽¹⁾	On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 2,638 GJ/d at the contracted price, for the following month.
⁽²⁾	On the last business day of each month, the counterparty has the option to increase the contracted volumes to 7,913 GJ/d at the contracted price, for the following month.
⁽³⁾	The contracted volumes increase to 5,184 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽⁴⁾	The contracted volumes increase to 15,552 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽⁵⁾	The contracted volumes increase to 10,368 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽⁶⁾	The contracted volumes increase to 18,144 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽⁷⁾	On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 5,184 GJ/d at the contracted price, for the following month.

Supplemental Table 3: Capital Expenditures

	Three Months Ended			Year Ended
By classification	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2015	2015	2014	2015	2014
Drilling and development	128,996	93,381	151,395	486,861	618,689
Exploration and evaluation	–	–	14,848	–	69,035
Capital expenditures	128,996	93,381	166,243	486,861	687,724
Property acquisition	6,227	22,155	1,652	28,897	220,726
Corporate acquisition	–	–	–	–	381,139
Acquisitions	6,227	22,155	1,652	28,897	601,865

	Three Months Ended			Year Ended
By category	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2015	2015	2014	2015	2014
Land	819	763	1,457	3,793	9,506
Seismic	4,217	810	7,598	8,243	19,034
Drilling and completion	58,327	39,712	69,691	212,358	311,696
Production equipment and facilities	55,662	44,589	77,272	218,963	275,538
Recompletions	6,338	3,948	7,696	26,689	36,234
Other	3,633	3,559	2,529	16,815	35,716
Capital expenditures	128,996	93,381	166,243	486,861	687,724
Acquisitions	6,227	22,155	1,652	28,897	601,865
Total capital expenditures and acquisitions	135,223	115,536	167,895	515,758	1,289,589

	Three Months Ended			Year Ended
By country	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2015	2015	2014	2015	2014
Canada	33,723	45,286	87,113	216,158	750,390
France	24,164	17,511	37,189	92,582	147,852
Netherlands	18,810	5,297	10,022	47,325	61,740
Germany	(441)	1,605	563	5,363	175,618
Ireland	12,493	20,694	20,932	66,409	94,439
Australia	40,852	7,966	11,616	61,741	44,283
United States	5,622	16,011	460	25,014	11,635
Corporate	–	1,166	–	1,166	3,632
Total capital expenditures and acquisitions	135,223	115,536	167,895	515,758	1,289,589

Supplemental Table 4: Production

		Q4/15	Q3/15	Q2/15	Q1/15	Q4/14	Q3/14	Q2/14	Q1/14	Q4/13	Q3/13	Q2/13	Q1/13
Canada
	Crude oil (bbls/d)	7,964	9,195	10,182	10,893	11,384	11,469	12,676	9,437	8,719	7,969	8,885	7,966
	NGLs (bbls/d)	5,159	4,513	3,755	2,976	2,741	2,291	2,796	2,071	1,699	1,897	1,725	1,335
	Natural gas (mmcf/d)	87.90	71.94	64.66	61.78	58.36	57.07	57.59	49.53	41.43	43.40	43.69	41.04
	Total (boe/d)	27,773	25,698	24,713	24,165	23,851	23,272	25,070	19,763	17,322	17,099	17,892	16,140
	% of consolidated	45%	47%	48%	48%	49%	47%	49%	42%	43%	41%	42%	41%
France
	Crude oil (bbls/d)	12,537	12,310	12,746	11,463	11,133	11,111	11,025	10,771	11,131	11,625	10,390	10,330
	Natural gas (mmcf/d)	1.36	1.47	1.03	–	–	–	–	–	–	5.23	4.19	4.21
	Total (boe/d)	12,763	12,555	12,917	11,463	11,133	11,111	11,025	10,771	11,131	12,496	11,088	11,032
	% of consolidated	21%	22%	25%	23%	22%	22%	21%	23%	27%	30%	26%	29%
Netherlands
	NGLs (bbls/d)	110	109	112	63	81	63	96	69	62	48	50	96
	Natural gas (mmcf/d)	56.34	53.56	32.43	36.41	31.35	38.07	40.35	43.15	37.53	28.78	38.52	36.91
	Total (boe/d)	9,500	9,035	5,517	6,132	5,306	6,407	6,822	7,260	6,318	4,845	6,470	6,248
	% of consolidated	16%	16%	11%	12%	11%	13%	13%	16%	15%	12%	15%	16%
Germany
	Natural gas (mmcf/d)	16.17	14.00	16.18	16.80	17.71	15.38	16.13	10.64	–	–	–	–
	Total (boe/d)	2,695	2,333	2,696	2,801	2,952	2,563	2,689	1,773	–	–	–	–
	% of consolidated	4%	4%	5%	6%	6%	5%	5%	4%	–	–	–	–
Ireland
	Natural gas (mmcf/d)	0.12	–	–	–	–	–	–	–	–	–	–	–
	Total (boe/d)	20	–	–	–	–	–	–	–	–	–	–	–
	% of consolidated	–	–	–	–	–	–	–	–	–	–	–	–
Australia
	Crude oil (bbls/d)	7,824	6,433	5,865	5,672	6,134	6,567	6,483	7,110	6,189	7,070	7,363	5,287
	% of consolidated	13%	11%	11%	11%	12%	13%	12%	15%	15%	17%	17%	14%
United States
	Crude oil (bbls/d)	420	226	123	153	195	–	–	–	–	–	–	–
	NGLs (bbls/d)	29	–	–	–	–	–	–	–	–	–	–	–
	Natural gas (mmcf/d)	0.20	–	–	–	–	–	–	–	–	–	–	–
	Total (boe/d)	483	226	123	153	195	–	–	–	–	–	–	–
	% of consolidated	1%	–	–	–	–	–	–	–	–	–	–	–
Consolidated
	Crude oil & NGLs (bbls/d)	34,043	32,786	32,783	31,220	31,668	31,501	33,076	29,458	27,800	28,609	28,413	25,014
	% of consolidated	56%	58%	63%	62%	64%	63%	63%	63%	68%	69%	66%	65%
	Natural gas (mmcf/d)	162.09	140.97	114.29	115.00	107.42	110.52	114.08	103.32	78.96	77.41	86.40	82.16
	% of consolidated	44%	42%	37%	38%	36%	37%	37%	37%	32%	31%	34%	35%
	Total (boe/d)	61,058	56,280	51,831	50,386	49,571	49,920	52,089	46,677	40,960	41,510	42,813	38,707

		2015	2014	2013	2012	2011	2010
Canada
	Crude oil (bbls/d)	9,550	11,248	8,387	7,659	4,701	2,778
	NGLs (bbls/d)	4,108	2,476	1,666	1,232	1,297	1,427
	Natural gas (mmcf/d)	71.65	55.67	42.39	37.50	43.38	43.91
	Total (boe/d)	25,598	23,001	17,117	15,142	13,227	11,524
	% of consolidated	46%	47%	41%	40%	38%	36%
France
	Crude oil (bbls/d)	12,267	11,011	10,873	9,952	8,110	8,347
	Natural gas (mmcf/d)	0.97	–	3.40	3.59	0.95	0.92
	Total (boe/d)	12,429	11,011	11,440	10,550	8,269	8,501
	% of consolidated	23%	22%	28%	28%	23%	26%
Netherlands
	NGLs (bbls/d)	99	77	64	67	58	35
	Natural gas (mmcf/d)	44.76	38.20	35.42	34.11	32.88	28.31
	Total (boe/d)	7,559	6,443	5,967	5,751	5,538	4,753
	% of consolidated	14%	13%	15%	15%	16%	15%
Germany
	Natural gas (mmcf/d)	15.78	14.99	–	–	–	–
	Total (boe/d)	2,630	2,498	–	–	–	–
	% of consolidated	5%	5%	–	–	–	–
Ireland
	Natural gas (mmcf/d)	0.03	–	–	–	–	–
	Total (boe/d)	5	–	–	–	–	–
	% of consolidated	–	–	–	–	–	–
Australia
	Crude oil (bbls/d)	6,454	6,571	6,481	6,360	8,168	7,354
	% of consolidated	12%	13%	16%	17%	23%	23%
United States
	Crude oil (bbls/d)	231	49	–	–	–	–
	NGLs (bbls/d)	7	–
	Natural gas (mmcf/d)	0.05	–	–	–	–	–
	Total (boe/d)	247	49	–	–	–	–
	% of consolidated	–	–	–	–	–	–
Consolidated
	Crude oil & NGLs (bbls/d)	32,716	31,432	27,471	25,270	22,334	19,941
	% of consolidated	60%	63%	67%	67%	63%	62%
	Natural gas (mmcf/d)	133.24	108.85	81.21	75.20	77.21	73.14
	% of consolidated	40%	37%	33%	33%	37%	38%
	Total (boe/d)	54,922	49,573	41,005	37,803	35,202	32,132

Supplemental Table 5: Segmented Financial Results

	Three Months Ended December 31, 2015
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Drilling and development	27,554	24,085	18,810	(441)	12,493	40,852	5,643	–	128,996
Oil and gas sales to external customers	73,952	63,411	37,243	9,840	57	47,952	1,864	–	234,319
Royalties	(7,146)	(7,198)	(224)	(1,166)	–	–	(551)	–	(16,285)
Revenue from external customers	66,806	56,213	37,019	8,674	57	47,952	1,313	–	218,034
Transportation expense	(3,784)	(4,275)	–	(508)	(1,580)	–	–	–	(10,147)
Operating expense	(24,575)	(15,792)	(6,263)	(4,788)	(15)	(13,941)	(271)	–	(65,645)
General and administration	(3,669)	(4,894)	(813)	(3,032)	(714)	(1,768)	(897)	3,356	(12,431)
PRRT	–	–	–	–	–	(1,054)	–	–	(1,054)
Corporate income taxes	–	4,529	(2,930)	–	–	1,201	–	313	3,113
Interest expense	–	–	–	–	–	–	–	(16,584)	(16,584)
Realized gain on derivative instruments	–	–	–	–	–	–	–	21,164	21,164
Realized foreign exchange loss	–	–	–	–	–	–	–	(252)	(252)
Realized other income	–	–	–	–	–	–	–	243	243
Fund flows from operations	34,778	35,781	27,013	346	(2,252)	32,390	145	8,240	136,441


	Year Ended December 31, 2015
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Total assets	1,609,180	863,304	212,749	167,908	908,453	235,139	42,927	169,560	4,209,220
Drilling and development	201,508	92,265	47,325	5,363	66,409	61,741	12,250	–	486,861
Oil and gas sales to external customers	320,613	281,422	129,057	41,384	57	162,765	4,288	–	939,586
Royalties	(28,144)	(26,958)	(3,082)	(6,479)	–	–	(1,257)	–	(65,920)
Revenue from external customers	292,469	254,464	125,975	34,905	57	162,765	3,031	–	873,666
Transportation expense	(16,326)	(15,378)	–	(3,269)	(6,687)	–	–	–	(41,660)
Operating expense	(89,085)	(50,718)	(22,746)	(10,956)	(15)	(51,676)	(742)	–	(225,938)
General and administration	(16,888)	(20,217)	(4,158)	(7,386)	(2,517)	(5,754)	(3,836)	7,172	(53,584)
PRRT	–	–	–	–	–	(6,878)	–	–	(6,878)
Corporate income taxes	–	(23,764)	(12,152)	–	–	(7,230)	–	(1,091)	(44,237)
Interest expense	–	–	–	–	–	–	–	(59,852)	(59,852)
Realized gain on derivative instruments	–	–	–	–	–	–	–	41,356	41,356
Realized foreign exchange gain	–	–	–	–	–	–	–	623	623
Realized other income	–	31,775	–	–	–	–	–	896	32,671
Fund flows from operations	170,170	176,162	86,919	13,294	(9,162)	91,227	(1,547)	(10,896)	516,167

NON-GAAP FINANCIAL MEASURES

This MD&A includes references to certain financial measures which do not
have standardized meanings prescribed by IFRS and are not disclosed in
our audited consolidated financial statements. As such, these
financial measures are considered non-GAAP financial measures and
therefore may not be comparable with similar measures presented by
other issuers.

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 our equity based compensation plans
as determined using the treasury stock method.

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.

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

Payout: We define payout as net dividends plus drilling and development,
exploration and evaluation, 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.

Fund flows from operations (excluding Corrib) and Payout (excluding
Corrib): Management excludes expenditures relating to the Corrib project in
assessing fund flows from operations (a non-GAAP financial measure) and
payout in order to assess our ability to generate cash and finance
organic growth from our current producing assets.

Diluted shares outstanding: Is 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.

Cash dividends per share: Represents cash dividends declared per share.

Total returns: Includes cash dividends per share and the change in Vermilion’s share
price on the Toronto Stock Exchange.

The following tables reconcile fund flows from operations (excluding
Corrib), net dividends, payout, and diluted shares outstanding to 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)	2015	2015	2014	2015	2014
Cash flows from operating activities	164,863	122,230	229,146	444,408	791,986
Changes in non-cash operating working capital	(33,343)	5,082	(49,865)	60,390	(3,077)
Asset retirement obligations settled	4,921	2,123	6,247	11,369	15,956
Fund flows from operations	136,441	129,435	185,528	516,167	804,865
Expenses related to Corrib	2,252	2,429	2,299	9,162	7,841
Fund flows from operations (excluding Corrib)	138,693	131,864	187,827	525,329	812,706


	Three Months Ended			Year Ended
	Dec 31,	Sep 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2015	2015	2014	2015	2014
Dividends declared	71,965	71,244	69,119	283,575	272,732
Issuance of shares pursuant to the dividend reinvestment and Premium Dividend^TM plans	(46,764)	(44,590)	(20,980)	(155,033)	(79,430)
Net dividends	25,201	26,654	48,139	128,542	193,302
Drilling and development	128,996	93,381	151,395	486,861	618,689
Exploration and evaluation	–	–	14,848	–	69,035
Asset retirement obligations settled	4,921	2,123	6,247	11,369	15,956
Payout	159,118	122,158	220,629	626,772	896,982
Corrib drilling and development	(12,493)	(20,694)	(20,932)	(66,409)	(94,439)
Payout (excluding Corrib)	146,625	101,464	199,697	560,363	802,543


			As at
			Dec 31,	Sep 30,	Dec 31,
(‘000s of shares)			2015	2015	2014
Shares outstanding			111,991	110,818	107,303
Potential shares issuable pursuant to the VIP			3,033	2,825	3,031
Diluted shares outstanding			115,024	113,643	110,334

MANAGEMENT’S REPORT TO SHAREHOLDERS

Management’s Responsibility for Financial Statements

The accompanying consolidated financial statements of Vermilion Energy
Inc. are the responsibility of management and have been approved by the
Board of Directors of Vermilion Energy Inc. The consolidated financial
statements have been prepared in accordance with the accounting
policies detailed in the notes to the consolidated financial statements
and are prepared in accordance with International Financial Reporting
Standards as issued by the International Accounting Standards Board.
Where necessary, management has made informed judgments and estimates
of transactions that were not yet completed at the balance sheet date.
Financial information throughout the Annual Report is consistent with
the consolidated financial statements.

Management ensures the integrity of the consolidated financial
statements by maintaining high-quality systems of internal control.
Procedures and policies are designed to provide reasonable assurance
that assets are safeguarded and transactions are properly recorded, and
that the financial records are reliable for preparation of the
consolidated financial statements. Deloitte LLP, Vermilion’s external
auditors, have conducted an audit of the consolidated financial
statements in accordance with Canadian generally accepted auditing
standards and the standards of the Public Company Accounting Oversight
Board (United States) and have provided their report.

The Board of Directors is responsible for ensuring that management
fulfills its responsibility for financial reporting and internal
control. The Board carries out this responsibility principally through
the Audit Committee, which is appointed by the Board and is comprised
entirely of independent Directors. The Committee meets periodically
with management and Deloitte LLP to satisfy itself that each party is
properly discharging its responsibilities and to review the
consolidated financial statements, the Management’s Discussion and
Analysis and the external Auditor’s Report before they are presented to
the Board of Directors.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining an adequate
system of internal control over financial reporting. Management
conducted an evaluation of the effectiveness of the system of internal
control over financial reporting based on the criteria established in
“Internal Control – Integrated Framework (2013)” issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
Based on this evaluation, management has 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. Management concluded that
Vermilion’s internal control over financial reporting was effective as
of December 31, 2015. The effectiveness of Vermilion’s internal control
over financial reporting as of December 31, 2015 has been audited by
Deloitte LLP, the Company’s Independent Registered Public Accounting
Firm, who also audited the Company’s consolidated financial statements
for the year ended December 31, 2015.

(“Lorenzo Donadeo”)									(“Curtis W. Hicks”)

Lorenzo Donadeo Chief Executive Officer February 25, 2016									Curtis W. Hicks Executive Vice President & Chief Financial Officer

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Vermilion Energy Inc.

We have audited the internal control over financial reporting of
Vermilion Energy Inc. and subsidiaries (the “Company”) as of December 31, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Company’s management is responsible for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Report on Internal
Control over Financial Reporting. Our responsibility is to express an
opinion on the Company’s internal control over financial reporting
based on our audit.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial
reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal
control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process
designed by, or under the supervision of, the company’s principal
executive and principal financial officers, or persons performing
similar functions, and effected by the company’s board of directors,
management, and other personnel to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
International Financial Reporting Standards as issued by the
International Accounting Standards Board. 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 and dispositions of the
assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with International Financial
Reporting Standards as issued by the International Accounting Standards
Board, 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.

Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper
management override of controls, material misstatements due to error or
fraud may not be prevented or detected on a timely basis. Also,
projections of any evaluation of the effectiveness of the internal
control over financial reporting to future periods are subject to the
risk that the controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or
procedures may deteriorate.

In our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31,
2015, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission.

We have also audited, in accordance with Canadian generally accepted
auditing standards and the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements
as of and for the year ended December 31, 2015 of the Company and our
report dated February 26, 2016 expressed an unqualified opinion on
those financial statements.

(“/s/Deloitte LLP”)

Chartered Professional Accountants, Chartered Accountants
February 26, 2016
Calgary, Canada

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Vermilion Energy Inc.

We have audited the accompanying consolidated financial statements of
Vermilion Energy Inc. and subsidiaries (the “Company”), which comprise
the consolidated balance sheets as at December 31, 2015 and December
31, 2014, and the consolidated statements of net earnings (loss) and
comprehensive income (loss), cash flows, and changes in shareholders’
equity for the years then ended, and a summary of significant
accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of
these consolidated financial statements in accordance with
International Financial Reporting Standards as issued by the
International Accounting Standards Board, and for such internal control
as management determines is necessary to enable the preparation of
consolidated financial statements that are free from material
misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these consolidated
financial statements based on our audits. We conducted our audits in
accordance with Canadian generally accepted auditing standards and the
standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we comply with ethical
requirements and plan and perform the audit to obtain reasonable
assurance about whether the consolidated financial statements are free
from material misstatement.

An audit involves performing procedures to obtain audit evidence about
the amounts and disclosures in the consolidated financial statements.
The procedures selected depend on the auditor’s judgment, including the
assessment of the risks of material misstatement of the consolidated
financial statements, whether due to fraud or error. In making those
risk assessments, the auditor considers internal control relevant to
the entity’s preparation and fair presentation of the consolidated
financial statements in order to design audit procedures that are
appropriate in the circumstances. An audit also includes evaluating the
appropriateness of accounting policies used and the reasonableness of
accounting estimates made by management, as well as evaluating the
overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is
sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in
all material respects, the financial position of Vermilion Energy Inc.
and subsidiaries as at December 31, 2015 and December 31, 2014, and
their financial performance and their cash flows for the years then
ended in accordance with International Financial Reporting Standards as
issued by the International Accounting Standards Board.

Other Matter
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the Company’s
internal control over financial reporting as of December 31, 2015,
based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 26, 2016 expressed an
unmodified opinion on the Company’s internal control over financial
reporting.

(To be signed “/s/Deloitte LLP”)

Chartered Professional Accountants, Chartered Accountants
February 26, 2016
Calgary, Canada

CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS)

		December 31,		December 31,
	Note		2015		2014
ASSETS
Current
Cash and cash equivalents	17		41,676		120,405
Accounts receivable			160,499		171,820
Crude oil inventory			13,079		9,510
Derivative instruments	13		55,214		23,391
Prepaid expenses			14,310		13,033
			284,778		338,159

Derivative instruments	13		13,128		1,403
Deferred taxes	9		135,753		154,816
Exploration and evaluation assets	6		308,192		380,621
Capital assets	5		3,467,369		3,511,092
			4,209,220		4,386,091

LIABILITIES
Current
Accounts payable and accrued liabilities			248,747		298,196
Current portion of long-term debt	8		224,901		–
Dividends payable	10		24,077		23,070
Income taxes payable	9		6,006		44,463
			503,731		365,729

Long-term debt	8		1,162,998		1,238,080
Finance lease obligation	16		23,565		–
Asset retirement obligations	7		305,613		350,753
Deferred taxes	9		354,654		410,183
			2,350,561		2,364,745

SHAREHOLDERS’ EQUITY
Shareholders’ capital	10		2,181,089		1,959,021
Contributed surplus			107,946		92,188
Accumulated other comprehensive income			113,647		5,722
Deficit			(544,023)		(35,585)
			1,858,659		2,021,346
			4,209,220		4,386,091

CONSOLIDATED STATEMENTS OF NET EARNINGS (LOSS) AND COMPREHENSIVE INCOME
(LOSS)
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS)

		Year Ended
		December 31,	December 31,
	Note	2015	2014
REVENUE
Petroleum and natural gas sales		939,586	1,419,628
Royalties		(65,920)	(108,000)
Petroleum and natural gas revenue		873,666	1,311,628

EXPENSES
Operating	21	225,938	232,307
Transportation		41,660	42,361
Equity based compensation	11	75,232	67,802
Gain on derivative instruments	13	(84,904)	(64,083)
Interest expense		59,852	49,655
General and administration	21	53,584	61,727
Foreign exchange (gain) loss		(9,410)	18,420
Other (income) expense		(31,663)	760
Accretion	7	23,911	23,913
Depletion and depreciation	5, 6	458,758	425,694
Impairment	5, 6	274,623	–
		1,087,581	858,556
EARNINGS (LOSS) BEFORE INCOME TAXES		(213,915)	453,072

INCOME TAXES	9
Deferred		(47,728)	26,410
Current		51,115	157,336
		3,387	183,746

NET EARNINGS (LOSS)		(217,302)	269,326

OTHER COMPREHENSIVE (LOSS) INCOME
Currency translation adjustments		107,925	(41,420)
COMPREHENSIVE (LOSS) INCOME		(109,377)	227,906

NET EARNINGS (LOSS) PER SHARE	12
Basic		(1.98)	2.55
Diluted		(1.98)	2.51

WEIGHTED AVERAGE SHARES OUTSTANDING (‘000s)	12
Basic		109,642	105,448
Diluted		109,642	107,187

CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS)

			Year Ended
			December 31,	December 31,
		Note	2015	2014
OPERATING
Net earnings (loss)			(217,302)	269,326
Adjustments:
	Accretion	7	23,911	23,913
	Depletion and depreciation	5, 6	458,758	425,694
	Impairment	5, 6	274,623	–
	Unrealized gain on derivative instruments	13	(43,548)	(27,371)
	Equity based compensation	11	75,232	67,802
	Unrealized foreign exchange (gain) loss		(8,787)	17,599
	Unrealized other expense		1,008	1,492
	Deferred taxes	9	(47,728)	26,410
Asset retirement obligations settled		7	(11,369)	(15,956)
Changes in non-cash operating working capital		14	(60,390)	3,077
Cash flows from operating activities			444,408	791,986

INVESTING
Drilling and development		5	(486,861)	(618,689)
Exploration and evaluation		6	–	(69,035)
Property acquisitions		4, 5, 6	(28,897)	(220,726)
Corporate acquisitions, net of cash acquired		4	–	(176,179)
Changes in non-cash investing working capital		14	(25,980)	12,365
Cash flows used in investing activities			(541,738)	(1,072,264)

FINANCING
Increase in long-term debt		8	138,341	196,387
Decrease in finance lease obligation		16	(2,246)	–
Cash dividends		10	(127,535)	(190,657)
Cash flows from financing activities			8,560	5,730
Foreign exchange gain on cash held in foreign currencies			10,041	5,394

Net change in cash and cash equivalents			(78,729)	(269,154)
Cash and cash equivalents, beginning of year			120,405	389,559
Cash and cash equivalents, end of year		17	41,676	120,405

Supplementary information for operating activities – cash payments
	Interest paid		62,911	50,801
	Income taxes paid		92,907	166,993

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(THOUSANDS OF CANADIAN DOLLARS)

Accumulated

Other

Total

Shareholders’

Contributed

Comprehensive

Shareholders’

Note

Capital

Surplus

Income

Deficit

Equity

Balances as at January 1, 2014

1,618,443

75,427

47,142

(24,637)

1,716,375

Net earnings

–

269,326

Currency translation adjustments

–

(41,420)

–

(41,420)

Equity based compensation expense

–

67,081

–

67,081

Dividends declared

–

(272,732)

Shares issued pursuant to the

dividend reinvestment plan

79,430

–

79,430

Shares issued pursuant to

corporate acquisition

4, 10

204,960

–

204,960

Modification of equity based awards

–

(2,395)

–

(2,395)

Vesting of equity based awards

10, 11

47,925

(47,925)

–

Share-settled dividends

on vested equity based awards

10, 11

7,542

–

(7,542)

–

Shares issued pursuant to the bonus plan

721

–

721

Balances as at December 31, 2014

1,959,021

92,188

5,722

(35,585)

2,021,346

Accumulated

Other

Total

Shareholders’

Contributed

Comprehensive

Shareholders’

Note

Capital

Surplus

Income

Deficit

Equity

Balances as at January 1, 2015

1,959,021

92,188

5,722

(35,585)

2,021,346

Net loss

–

(217,302)

Currency translation adjustments

–

107,925

–

107,925

Equity based compensation expense

–

72,613

–

72,613

Dividends declared

–

(283,575)

Shares issued pursuant to the

dividend reinvestment and Premium

Dividend^TM plans

155,033

–

155,033

Vesting of equity based awards

10, 11

56,855

(56,855)

–

Share-settled dividends

on vested equity based awards

10, 11

7,561

–

(7,561)

–

Shares issued pursuant to the employee

savings and bonus plans

2,619

–

2,619

Balances as at December 31, 2015

2,181,089

107,946

113,647

(544,023)

1,858,659

DESCRIPTION OF EQUITY RESERVES

Shareholders’ capital
Represents the recognized amount for common shares when issued, net of
equity issuance costs and deferred taxes.

Contributed surplus
Represents the recognized value of employee awards which are settled in
shares. Once vested, the value of the awards is transferred to
shareholders’ capital.

Accumulated other comprehensive income
Represents the cumulative income and expenses which are not recorded
immediately in net earnings (loss) and are accumulated until an event
triggers recognition in net earnings (loss). The current balance
consists of currency translation adjustments resulting from translating
financial statements of subsidiaries with a foreign functional currency
to Canadian dollars at period-end rates.

Deficit
Represents the cumulative net earnings (loss) less distributed earnings
of Vermilion Energy Inc.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2015 AND 2014
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER
SHARE AMOUNTS)

1. BASIS OF PRESENTATION

Vermilion Energy Inc. (the “Company” or “Vermilion”) is a corporation
governed by the laws of the Province of Alberta and is actively engaged
in the business of crude oil and natural gas exploration, development,
acquisition and production.

These consolidated financial statements were approved and authorized for
issuance by the Board of Directors of Vermilion on February 25, 2016.

2. SIGNIFICANT ACCOUNTING POLICIES

Accounting Framework
The consolidated financial statements have been prepared in accordance
with International Financial Reporting Standards (“IFRS”) as issued by
the International Accounting Standards Board (“IASB”).

Principles of Consolidation
Subsidiaries that are directly controlled by the parent company or
indirectly controlled through other consolidated subsidiaries are fully
consolidated. Vermilion accounts for joint operations by recognizing
its share of assets, liabilities, income and expenses. All significant
intercompany balances, transactions, income and expenses are eliminated
upon consolidation.

Vermilion currently has no special purpose entities of which it retains
control and accordingly the consolidated financial statements do not
include the accounts of any such entities.

Exploration and Evaluation Assets
Vermilion accounts for exploration and evaluation of petroleum and
natural gas property (“E&E”) costs in accordance with IFRS 6
“Exploration for and Evaluation of Mineral Resources”. Costs incurred
are classified as E&E costs when they relate to exploring and
evaluating a property for which the Company has the licence or right to
explore and extract resources.

E&E costs related to each license or prospect area are initially
capitalized within E&E assets. E&E costs that are capitalized may
include costs of licence acquisitions, technical services and studies,
seismic acquisitions, exploration drilling and testing, directly
attributable overhead and administration expenses and, if applicable,
the estimated costs of retiring the assets. Any costs incurred prior
to the acquisition of the legal rights to explore an area are expensed
as incurred.

E&E assets are not initially depleted and are carried at cost until
technical feasibility and commercial viability of the area can be
determined. The technical feasibility and commercial viability of
extracting the reserves is considered to be determinable when proven
and probable reserves are identified. If proven and probable reserves
are identified as recoverable, the related E&E costs are reclassified
to Petroleum and Natural Gas (“PNG”) assets pending an impairment
test. If reserves are not found within the license area or the area is
abandoned, the related E&E costs are amortized over a period not
greater than five years.

Petroleum and Natural Gas Assets
Vermilion recognizes PNG assets at cost less accumulated depletion,
depreciation and impairment losses. Directly attributable costs
incurred for the drilling of development wells and for the construction
of production facilities are capitalized together with the discounted
value of estimated future costs of asset retirement obligations. When
components of PNG assets are replaced, disposed of, or no longer in
use, they are derecognized.

Gains and losses on disposal of a component of PNG assets, including oil
and gas interests, are determined by comparing the proceeds of disposal
with the carrying amount of the component, and are recognized in net
earnings (loss).

Depletion and Depreciation
Vermilion classifies its assets into PNG depletion units, which are
groups of assets or properties that are within a specific production
area and have similar economic lives. The PNG depletion units
represent the lowest level of disaggregation for which Vermilion
accumulates costs for the purposes of calculating and recording
depletion and depreciation.

The net carrying value of each PNG depletion unit is depleted using the
unit of production method by reference to the ratio of production in
the period to the total proven and probable reserves, taking into
account the future development costs necessary to bring the applicable
reserves into production. The reserve estimates are reviewed annually
by management or when material changes occur to the underlying
assumptions.

For the purposes of the depletion calculations, oil and gas reserves are
converted to a common unit of measure on the basis of their relative
energy content based on a conversion ratio of six thousand cubic feet
of natural gas to one barrel of oil equivalent.

Furniture and office equipment are recorded at cost and are depreciated
on a declining-balance basis.

Impairment of Long-Lived Assets
E&E assets are tested for impairment when reclassified to PNG assets or
when indicators of impairment are identified. If indicators of
impairment are identified, E&E assets are tested for impairment as part
of the group of Cash Generating Units (“CGUs”) attributable to the
jurisdiction in which the exploration area resides.

PNG depletion units are aggregated into CGUs for impairment testing.
The determination of CGUs is based on management’s judgment and
represents the lowest level at which there are identifiable cash
inflows that are largely independent of the cash inflows of other
groups of assets or properties. CGUs are reviewed for indicators that
the carrying value of the CGU may exceed its recoverable amount. If an
indication of impairment exists, the CGU’s recoverable amount is then
estimated. A CGU’s recoverable amount is defined as the higher of the
fair value less costs to sell and its value in use. If the carrying
amount exceeds its recoverable amount, an impairment loss is recorded
to net earnings (loss) in the period to reduce the carrying value of
the CGU to its recoverable amount.

For PNG assets and E&E assets, when there has been an impairment loss
recognized, at each reporting date an assessment is performed as to
whether the circumstances which led to the impairment loss have
reversed. If the change in circumstances leads to the recoverable
amount being higher than the carrying value after recognition of an
impairment, that impairment loss is reversed, with such reversal not to
exceed the depreciated value of the asset had no impairment loss been
previously recognized.

Finance leases
Finance leases, which transfer substantially all the risks and rewards
incidental to legal ownership, are recognized at the commencement of
the least term. The lease obligation and corresponding capitalized
lease asset are measured at the lower of fair value of the leased
property or the present value of the minimum lease payments, which are
determined at the inception of the lease. Capitalized leased assets are
depreciated over the shorter of the estimated useful life of the asset
or the lease term.

Cash and Cash Equivalents
Cash and cash equivalents include monies on deposit and short-term
investments, which are comprised primarily of guaranteed investment
certificates.

Crude Oil Inventory
Inventories of crude oil, consisting of production for which title has
not yet transferred to the customer, are valued at the lower of cost or
net realizable value. Cost is determined on a weighted-average basis
and includes related operating expenses, royalties, and depletion.

Provisions and Asset Retirement Obligations
Vermilion recognizes a provision or asset retirement obligation in the
consolidated financial statements when an event gives rise to an
obligation of uncertain timing or amount.

The estimated present value of the asset retirement obligation is
recorded as a long-term liability, with a corresponding increase in the
carrying amount of the related asset. This increase is depleted with
the related depletion unit and is allocated to a CGU for impairment
testing. The liability recorded is increased each reporting period due
to the passage of time and this change is charged to net earnings
(loss) in the period as accretion expense. The asset retirement
obligation can also increase or decrease due to changes in the
estimated timing of cash flows, changes in the discount rate and/or
changes in the original estimated undiscounted costs. Increases or
decreases in the obligation will result in a corresponding change in
the carrying amount of the related asset. Actual costs incurred upon
settlement of the asset retirement obligation are charged against the
asset retirement obligation to the extent of the liability recorded.
Vermilion discounts the costs related to asset retirement obligations
using the discount rate that reflects current market assessment of the
time value of money and risks specific to the liabilities that have not
been reflected in the cash flow estimates. Vermilion applies discount
rates applicable to each of the jurisdictions in which it has future
asset retirement obligations. Asset retirement obligations are
remeasured at each reporting period in order to reflect the discount
rates in effect at that time.

A provision for onerous contracts is recognized when the expected
benefits to be derived by Vermilion from a contract are lower than the
unavoidable cost of meeting the obligations under the contract. The
provision is measured at the lower of the expected cost of terminating
the contract and the present value of the expected net cost of the
remaining term of the contract. Before a provision is established,
Vermilion first recognizes any impairment loss on assets associated
with the onerous contract. For the periods presented in the
consolidated financial statements, there were no onerous contracts
recognized.

Revenue Recognition
Revenues associated with the sale of crude oil, natural gas and natural
gas liquids are recorded when title passes to the customer. For the
majority of Canadian oil and natural gas production, legal title
transfers upon delivery to major pipelines. In Australia, oil is sold
at the Wandoo B Platform. In the Netherlands, natural gas is sold at
the plant gate. In Germany, natural gas is sold upon delivery to major
pipelines. In France, oil is sold either when delivered to the refinery
by pipeline or when delivered to the refinery via tanker. In the United
States, oil is sold when transferred to the truck from the tank and
natural gas is sold at a custody transfer meter on location.

Financial Instruments
Cash and cash equivalents are classified as held for trading and are
measured at fair value. A gain or loss arising from a change in the
fair value is recognized in net earnings (loss) in the period in which
it occurs.

Accounts receivable are classified as loans and receivables and are
initially measured at fair value and are then subsequently measured at
amortized cost. The carrying value of accounts receivable approximates
the fair value due to the short-term nature of these instruments.

Accounts payable and accrued liabilities, dividends payable, finance
lease, and long-term debt have been classified as other financial
liabilities and are initially recognized at fair value and are
subsequently measured at amortized cost. Transaction costs and
discounts are recorded against the fair value of long-term debt on
initial recognition.

All derivative instruments have been classified as held for trading and
are measured at fair value. A gain or loss arising from a change in
the fair value is recognized in net earnings (loss) in the period in
which it occurs.

Equity Based Compensation
Vermilion has long-term equity based compensation plans for directors,
officers and employees of Vermilion and its subsidiaries. Equity based
compensation expense is recognized in net earnings (loss) over the
vesting period of the awards with a corresponding adjustment to
contributed surplus. Upon vesting, the amount previously recognized in
contributed surplus is reclassified to shareholders’ capital.

The expense recognized is based on the grant date fair value of the
awards and incorporates an estimate of the forfeiture rate based on
historical vesting data. The grant date fair value of the awards is
determined as the grant date closing price of Vermilion’s common shares
on the Toronto Stock Exchange, adjusted by the Company’s estimate of
the performance factor that will ultimately be achieved.

Per Share Amounts
Net earnings (loss) per share is calculated using the weighted-average
number of shares outstanding during the period. Diluted net earnings
per share is calculated using the diluted weighted-average number of
shares outstanding during the period. The diluted weighted-average
number of shares is determined by considering whether equity based
compensation plans, if converted during the year, would result in
reduced net earnings per share.

The treasury stock method is used to determine the dilutive effect of
equity based compensation plans. The treasury stock method assumes
that the deemed proceeds related to unrecognized equity based
compensation expense are used to repurchase shares at the average
market price during the period. Equity based awards outstanding are
included in the calculation of diluted net earnings per share based on
estimated performance factors.

Foreign Currency Translation
The consolidated financial statements are presented in Canadian dollars,
which is Vermilion’s reporting currency. As several of Vermilion’s
subsidiaries transact and operate primarily in countries other than
Canada, they accordingly have functional currencies other than the
Canadian dollar.

Transactions denominated in currencies other than the functional
currency of the subsidiary are translated to the functional currency at
the prevailing rates on the date of the transaction. Non-monetary
assets or liabilities that result from such transactions are held at
the prevailing rate on the date of the transaction. Monetary items
denominated in non-functional currencies are translated to the
functional currency of the subsidiary at the prevailing rate at the
balance sheet date. All translations associated with currencies other
than the respective functional currencies are recorded in net earnings
(loss).

Translation of all assets and liabilities from the respective functional
currencies to the reporting currency are performed using the rates
prevailing at the balance sheet date. The differences arising upon
translation from the functional currency to the reporting currency are
recorded as currency translation adjustments in other comprehensive
income (loss) and are held within accumulated other comprehensive
income (loss) until a disposal or partial disposal of a subsidiary. A
disposal or partial disposal may give rise to a realized gain or loss,
which is recorded in net earnings (loss).

Within the consolidated group there are outstanding intercompany loans
which in substance represent investments in certain subsidiaries. When
these loans are identified as part of the net investment in a foreign
subsidiary, any exchange differences arising on those loans are
recorded to currency translation adjustments within other comprehensive
income (loss) until the disposal or partial disposal of the subsidiary.

Income Taxes
Deferred taxes are calculated using the liability method of accounting.
Under this method, deferred tax is recognized for the estimated effect
of any temporary differences between the amounts recognized on
Vermilion’s consolidated balance sheets and respective tax basis. This
calculation uses enacted or substantively enacted tax rates that will
be in effect when the temporary differences are expected to reverse.
The effect of a change in tax rates on deferred taxes is recognized in
net earnings (loss) in the period in which the related legislation is
substantively enacted.

Deferred tax assets are reviewed each reporting period and a valuation
allowance is recognized if available evidence indicates that it is not
probable that all or a part of a deferred tax asset will be utilized in
future periods. A previously recognized valuation allowance is removed
when available evidence indicates that all or a part of the valuation
allowance is no longer required.

Vermilion is subject to current income taxes based on the tax
legislation of each respective country in which Vermilion conducts
business.

Borrowing Costs
Borrowing costs that are directly attributable to the acquisition or
construction of an asset that necessarily takes a substantial period of
time to prepare for its intended use are capitalized as part of the
cost of that asset. Borrowing costs are capitalized by applying
interest rates attributable to the project being financed and could
include both general and/or specific borrowings. Interest rates applied
from general borrowings are computed using the weighted average
borrowing rate for the period.

Measurement Uncertainty
The preparation of the consolidated financial statements requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and
the reported amounts of revenues and expenses for the periods
presented.

Key areas where management has made complex or subjective judgments
include asset retirement obligations, assessment of impairment or
recovery of impairment of long-lived assets and income taxes. Actual
results could differ significantly from these and other estimates.

Asset Retirement Obligations
Vermilion’s asset retirement obligations are based on the expected cost
of adherence to environmental regulations and estimates of the amount
and timing of future expenditures. Changes in environmental
regulations, the estimated costs associated with reclamation
activities, the discount rate applied and the timing of expenditures
could materially impact Vermilion’s measurement of the obligations and,
correspondingly, impact Vermilion’s financial position and net earnings
(loss).

Assessment of Impairments or Recovery of Previous Impairments
Impairment tests are performed at a CGU level. CGUs are determined
based on management’s judgment of the lowest level at which there is
identifiable cash inflows that are largely independent of the cash
inflows of other groups of assets or properties. The factors used by
Vermilion to determine CGUs may vary by country due to the unique
operating and geographic circumstances in each country. However, in
general, Vermilion will assess the following factors in determining
whether a group of assets generate largely independent cash inflows:
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 calculation of the recoverable amount of the CGUs is based on market
factors, estimates of PNG reserves and future costs required to develop
reserves. Vermilion’s reserve estimates and the related future cash
flows are subject to measurement uncertainty, and the impact on the
consolidated financial statements of future periods could be material.
Considerable management judgment is used in determining the recoverable
amount of PNG assets, including determining the quantity of reserves,
the time horizon to develop and produce such reserves and the estimated
revenues and expenditures of such production.

Income Taxes
Tax interpretations, regulations, and legislation in the various
jurisdictions in which Vermilion and its subsidiaries operate are
subject to change and interpretation. Such changes 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 current and deferred 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.

3. CHANGES TO ACCOUNTING PRONOUNCEMENTS

Accounting pronouncements not yet adopted

The impacts of the adoption of the following pronouncements are
currently being evaluated.

4. BUSINESS COMBINATIONS

Property acquisition:

Germany

In February of 2014, Vermilion acquired, through a wholly-owned
subsidiary, GDF’s 25% interest in four producing natural gas fields and
a surrounding exploration license located in northwest Germany. GDF is
an affiliate of GDF Suez S.A., a publicly traded, French multinational
utility. The acquisition represented Vermilion’s entry into the German
E&P business, a producing region with a long history of oil and gas
development activity, low political risk and strong marketing
fundamentals. The acquisition was well aligned with Vermilion’s
European focus, and has increased the company’s exposure to the strong
fundamentals and pricing of the European natural gas markets. The
acquisition closed in February of 2014 for cash proceeds of $172.9
million. Vermilion funded this acquisition with existing credit
facilities.

The acquired assets were comprised of four gas producing fields across
eleven production licenses and included both exploration and production
licenses that comprised a total of 207,000 gross acres, of which 85%
was in the exploration license.

The acquisition was accounted for as a business combination with the
fair value of the assets acquired and liabilities assumed at the date
of acquisition summarized as follows:

($M)	Consideration
Cash paid to vendor		172,871
Total consideration		172,871

($M)	Allocation of Consideration
Petroleum and natural gas assets		158,840
Exploration and evaluation		16,065
Asset retirement obligations assumed		(2,030)
Deferred tax liabilities		(4)
Net assets acquired		172,871

The results of operations from the assets acquired were included in
Vermilion’s consolidated financial statements beginning February of
2014 and had contributed net revenues of $33.3 million and a net loss
of $0.3 million for the year ended December 31, 2014.

Had the acquisition occurred on January 1, 2014, management estimates
that consolidated revenues would have increased by an additional $4.6
million and consolidated net earnings would have increased by $0.9
million for the year ended December 31, 2014.

Corporate acquisitions:

a) Elkhorn Resources Inc.

On April 29, 2014, Vermilion acquired Elkhorn Resources Inc., a private
southeast Saskatchewan producer. The acquisition created a new core
area for Vermilion in the Williston Basin.

The acquired assets included approximately 57,000 net acres of land
(approximately 80% undeveloped), seven oil batteries, and preferential
access to a minimum of 50% of capacity at a solution gas facility.

Total consideration was comprised of $180.4 million of cash, which was
funded with existing credit facilities, and the issuance of 2.8 million
Vermilion common shares valued at approximately $205.0 million (based
on the closing price per Vermilion common share of $72.50 on the
Toronto Stock Exchange on April 29, 2014).

The acquisition was accounted for as a business combination with the
fair value of the assets acquired and liabilities assumed at the date
of acquisition summarized as follows:

($M)	Consideration
Cash paid to shareholders of Elkhorn Resources Inc.		180,353
Shares issued pursuant to corporate acquisition		204,960
Total consideration		385,313

($M)	Allocation of Consideration
Petroleum and natural gas assets		390,523
Exploration and evaluation		138,264
Asset retirement obligations assumed		(5,974)
Deferred tax liabilities		(89,437)
Long-term debt assumed		(47,526)
Cash acquired		4,174
Acquired non-cash working capital deficiency		(4,711)
Net assets acquired		385,313

The results of operations from the assets acquired were included in
Vermilion’s consolidated financial statements beginning April 29, 2014
and contributed revenues of $50.6 million and operating income of $39.8
million for the year ended December 31, 2014.

Had the acquisition occurred on January 1, 2014, management estimates
that consolidated revenues would have increased by an additional $8.8
million and consolidated operating income would have increased by $7.0
million for the year ended December 31, 2014. In determining the
pro-forma amounts, management had assumed that the fair value
adjustments, determined provisionally, that arose at the date of
acquisition would have been the same if the acquisition had occurred on
January 1, 2014. It is impracticable to derive all amounts necessary
to determine the impact on net earnings from the acquisition as the
acquired company was immediately merged with Vermilion’s operations.

5. CAPITAL ASSETS

The following table reconciles the change in Vermilion’s capital assets:

	Petroleum and		Furniture and		Total
($M)	Natural Gas Assets		Office Equipment		Capital Assets
Balance at January 1, 2014		2,784,634		15,211	2,799,845
Additions		608,709		9,980	618,689
Property acquisitions		176,625		–	176,625
Corporate acquisitions		390,523		–	390,523
Changes in estimate for asset retirement obligations		19,107		–	19,107
Depletion and depreciation		(412,768)		(5,072)	(417,840)
Effect of movements in foreign exchange rates		(75,635)		(222)	(75,857)
Balance at December 31, 2014		3,491,195		19,897	3,511,092
Additions		482,574		4,287	486,861
Property acquisitions		27,731		–	27,731
Changes in estimate for asset retirement obligations		(78,429)		–	(78,429)
Depletion and depreciation		(431,889)		(6,453)	(438,342)
Recognition of finance lease asset⁽¹⁾		31,028		–	31,028
Impairment⁽²⁾		(219,808)		–	(219,808)
Effect of movements in foreign exchange rates		146,641		595	147,236
Balance at December 31, 2015		3,449,043		18,326	3,467,369

Cost		5,114,188		54,723	5,168,911
Accumulated depletion and depreciation		(1,622,993)		(34,826)	(1,657,819)
Carrying amount at December 31, 2014		3,491,195		19,897	3,511,092

Cost		5,624,809		57,652	5,682,461
Accumulated depletion and depreciation		(2,175,766)		(39,326)	(2,215,092)
Carrying amount at December 31, 2015		3,449,043		18,326	3,467,369


⁽¹⁾	Refer to Financial Statement Note 16 – Leases
⁽²⁾	Refer to Financial Statement Note 6 – Exploration and Evaluation Assets

Depletion and depreciation rates
PNG assets (unit of production method)
Furniture and office equipment (declining balance at rates of 5% to 25%)

Capitalized overhead
During the year ended December 31, 2015, Vermilion capitalized $5.1
million (2014 – $7.7 million) of overhead costs directly attributable
to PNG activities.

Impairments
On a quarterly basis, Vermilion performs an assessment as to whether any
CGUs have indicators of impairment. When indicators of impairment are
identified, Vermilion assesses the recoverable amount of the applicable
CGU based on the higher of the estimated fair value less costs to sell
and value in use as at the reporting date. The estimated recoverable
amount takes into account commodity price forecasts, expected
production, estimated costs and timing of development, and undeveloped
land values.

As a result of declines in commodity price forecasts, which decreased
expected cash flows, Vermilion recorded a non-cash impairment charge of
$131.6 million in the Canada segment for the three months ended
December 31, 2015 ($274.6 million for the year ended December 31, 2015,
of which $219.8 million related to PNG assets and $54.8 million related
to E&E assets). The recoverable amount of each CGU was determined using
a value in use approach based on 2015 year end reserves and resource
data, an after-tax discount rate of 9% for proved and probable
reserves, and an after-tax discount rate of 15% on resources carried
within exploration and evaluation assets.

This impairment charge in the year ended December 31, 2015 related to
the light crude oil play in Saskatchewan, Canada ($267.9 million based
on a recoverable amount of $266.8 million) and the shallow coal bed
methane properties in Alberta, Canada ($6.7 million based on a
recoverable amount of $19.7 million). The determination of impairment
is sensitive to changes in key judgments, including reserve or resource
revisions, changes in forward commodity prices and exchange rates, and
changes in costs and timing of development. Changes in these key
judgments would impact the recoverable amount of CGUs, therefore
resulting in additional impairment charges or recoveries. For the year
ended December 31, 2015, a one percent increase in the assumed discount
rate on expected cash flows of the Saskatchewan light crude oil and
Alberta shallow coal bed methane CGUs would result in an additional
impairment of $19.5 million, and a five percent decrease in commodity
prices would result in an additional impairment of $33.3 million.

Vermilion also identified indicators of impairment on the Ireland CGU
which consists of Vermilion’s non-operating interest in offshore Corrib
natural gas field, but determined that the recoverable amount exceeded
its carrying value and accordingly, no impairment charge was recorded.
For the year ended December 31, 2015, a one percent increase in the
assumed discount rate on expected cash flows of the Ireland CGU would
have resulted in impairment of $21.9 million, and a five percent
decrease in commodity prices would result in an impairment of $33.6
million.

The following table outlines the forward commodity price estimates that
were used in the calculation of recoverable amounts:

Forward Commodity Price Assumptions ⁽¹⁾
	WTI Oil (US $/bbl)	AECO Gas (CDN $/mmbtu)	Blended NGLs ⁽²⁾ (CDN $/bbl)	NBP Gas (US $/mmbtu)	CDN $/US $ Exchange Rate
2016	44.00	2.76	30.27	5.55	0.73
2017	52.00	3.27	35.76	5.68	0.75
2018	58.00	3.45	39.04	6.10	0.78
2019	64.00	3.63	42.96	6.70	0.80
2020	70.00	3.81	45.85	7.30	0.83
2021	75.00	3.90	47.86	7.80	0.85
2022	80.00	4.10	51.23	8.30	0.85
2023	85.00	4.30	54.59	8.80	0.85
2024	87.88	4.50	56.05	9.14	0.85
2025	89.63	4.60	57.18	9.32	0.85
Thereafter	+2.0% per year	+2.0% per year	+2.0% per year	+2.0% per year	0.85


⁽¹⁾	Source: GLJ Petroleum Consultants price forecast, effective January 1, 2016.
⁽²⁾	The price of blended NGLs shown above is determined used a simple average for Ethane, Propane, Butane, and C5+.

6. EXPLORATION AND EVALUATION ASSETS

The following table reconciles the change in Vermilion’s exploration and
evaluation assets:

($M)	Exploration and Evaluation Assets
Balance at January 1, 2014		136,259
Additions		69,035
Changes in estimate for asset retirement obligations		22
Property acquisitions		46,135
Corporate acquisitions		138,264
Depreciation		(5,038)
Effect of movements in foreign exchange rates		(4,056)
Balance at December 31, 2014		380,621
Changes in estimate for asset retirement obligations		(130)
Property acquisitions		1,166
Depreciation		(21,893)
Impairment ⁽¹⁾		(54,815)
Effect of movements in foreign exchange rates		3,243
Balance at December 31, 2015		308,192

Cost		399,348
Accumulated depreciation		(18,727)
Carrying amount at December 31, 2014		380,621

Cost		362,919
Accumulated depreciation		(54,727)
Carrying amount at December 31, 2015		308,192


⁽¹⁾	Refer to Financial Statement Note 5 – Capital Assets

7. ASSET RETIREMENT OBLIGATIONS

The following table reconciles the change in Vermilion’s asset
retirement obligations:

($M)	Asset Retirement Obligations
Balance at January 1, 2014		326,162
Additional obligations recognized		22,565
Changes in estimates for asset retirement obligations		(3,434)
Obligations settled		(15,956)
Accretion		23,913
Changes in discount rates		9,404
Effect of movements in foreign exchange rates		(11,901)
Balance at December 31, 2014		350,753
Additional obligations recognized		3,550
Changes in estimates for asset retirement obligations		1,117
Obligations settled		(11,369)
Accretion		23,911
Changes in discount rates		(83,226)
Effect of movements in foreign exchange rates		20,877
Balance at December 31, 2015		305,613

Vermilion has estimated the net present value of its asset retirement
obligations to be $305.6 million as at December 31, 2015 (2014 – $350.8
million) based on a total undiscounted future liability, after
inflation adjustment, of $1.3 billion (2014 – $1.3 billion). These
payments are expected to be made between 2016 and 2064. Vermilion
calculated the present value of the obligations using discount rates
between 7.1% and 10.3% (2014 – between 5.7% and 7.9%) to reflect the
market assessment of the time value of money as well as risks specific
to the liabilities that have not been included in the cash flow
estimates. Inflation rates used in determining the cash flow estimates
were between 0.6% and 2.4% (2014 – between 0.8% and 2.4%).

Vermilion reviews annually its estimates of the expected costs to
reclaim the net interest in its wells and facilities. The resulting
changes are categorized as changes in estimates for existing
obligations in the preceding table. The decrease in the liability for
the year ended December 31, 2015 primarily resulted from an overall
increase in the discount rates applied to the abandonment obligations.

8. LONG-TERM DEBT

The following table summarizes Vermilion’s outstanding long-term debt:

	As at
($M)	Dec 31, 2015	Dec 31, 2014
Revolving credit facility	1,162,998	1,014,067
Senior unsecured notes ⁽¹⁾	224,901	224,013
Long-term debt	1,387,899	1,238,080


⁽¹⁾	The senior unsecured notes, which matured on February 10, 2016, are included in the current portion of long-term debt as at December 31, 2015.

Revolving Credit Facility

At December 31, 2015, Vermilion had in place a bank revolving credit
facility totalling $2 billion, of which approximately $1.16 billion was
drawn. The facility, which matures on May 31, 2019, is fully revolving
up to the date of maturity.

The facility is extendable from time to time, but not more than once per
year, for a period not longer than four years, at the option of the
lenders and upon notice from Vermilion. If no extension is granted by
the lenders, the amounts owing pursuant to the facility are due at the
maturity date. This facility bears interest at a rate applicable to
demand loans plus applicable margins. For the year ended December 31,
2015, the interest rate on the revolving credit facility was
approximately 3.1% (2014 – 3.1%).

The amount available to Vermilion under this facility is reduced by
certain outstanding letters of credit associated with Vermilion’s
operations totalling $25.2 million as at December 31, 2015 (December
31, 2014 – $8.6 million).

The facility is secured by various fixed and floating charges against
the subsidiaries of Vermilion. Under the terms of the facility,
Vermilion must maintain:

A ratio of total borrowings (defined as amounts classified as “Long-term
debt”, “Current portion of long term debt”, and “Finance lease
obligation” on the balance sheet and referred to collectively as
consolidated total debt), to consolidated net earnings before interest,
income taxes, depreciation, accretion and other certain non-cash items
(defined as consolidated EBITDA) of not greater than 4.0.
A ratio of consolidated total senior debt (defined as consolidated total
debt excluding unsecured and subordinated debt) to consolidated EBITDA
of not greater than 3.0.
A ratio of consolidated total senior debt to total capitalization
(defined as amounts classified as “Shareholders’ equity” on the balance
sheet plus consolidated total senior debt as defined above) of not
greater than 50%.

As at December 31, 2015, Vermilion was in compliance with all financial
covenants.

Senior Unsecured Notes

On February 10, 2011, Vermilion issued $225.0 million of senior
unsecured notes at par. The notes bear interest at a rate of 6.5% per
annum and matured on February 10, 2016. As direct senior unsecured
obligations of Vermilion, the notes ranked pari passu with all other
present and future unsecured and unsubordinated indebtedness of the
Company. The notes were initially recognized at fair value net of
transaction costs and were subsequently measured at amortized cost
using an effective interest rate of 7.1%.

Subsequent to December 31, 2015, Vermilion repaid the senior unsecured
notes using funds from the revolving credit facility.

9. INCOME TAXES

Deferred taxes

The net deferred income tax liability at December 31, 2015 and 2014 is
comprised of the following:

		Year Ended
($M)		Dec 31, 2015		Dec 31, 2014
Deferred income tax liabilities:
	Derivative contracts		(18,452)		(5,965)
	Capital assets		(349,664)		(445,457)
	Asset retirement obligations		(130,904)		(96,616)
	Unrealized foreign exchange		(16,300)		(14,507)
	Other		(10,767)		(13,164)
Deferred income tax assets:
	Capital assets		77,343		72,821
	Non-capital losses		175,477		178,222
	Asset retirement obligations		51,958		65,760
	Unrealized foreign exchange		–		720
	Other		2,408		2,819
Net deferred income tax liability			(218,901)		(255,367)
Comprised of:
	Deferred income tax assets		135,753		154,816
	Deferred income tax liability		(354,654)		(410,183)
Net deferred income tax liability			(218,901)		(255,367)

Income tax expense differs from the amount that would have been expected
if the reported earnings had been subject only to the statutory
Canadian income tax rate of 26.2% (2014 – 25.5%), as follows:

		Year Ended
($M)		Dec 31, 2015		Dec 31, 2014
Earnings (loss) before income taxes			(213,915)	453,072
Canadian corporate tax rate			26.2%⁽¹⁾	25.5%
Expected tax expense (recovery)			(56,046)	115,533
Increase (decrease) in taxes resulting from:
	Petroleum resource rent tax rate (PRRT) differential⁽²⁾		8,310	37,035
	Foreign tax rate differentials^{(2), (3)}		(8,096)	3,492
	Equity based compensation expense		14,000	17,290
	Amended returns and changes to estimated tax pools and tax positions		(6,856)	(7,512)
	Changes in statutory tax rates and the estimated reversal rates associated with temporary differences		1,733	16,429
	Valuation allowance		51,736	–
	Other non-deductible items		(1,394)	1,479
Provision for income taxes			3,387	183,746


⁽¹⁾	The corporate tax rate increased to 26.2% in 2015 from 25.5% in 2014 due to the Alberta corporate tax rate increase of 2.0% effective July 1, 2015.
⁽²⁾	In Australia, current taxes include both corporate income tax rates and PRRT. Corporate income tax rates were applied at a rate of 30% and PRRT was applied at a rate of 40%.
⁽³⁾	The combined tax rate was 34.4% in France, 46.0% in the Netherlands, 24.2% in Germany, 25% in Ireland, and 35% in the United States.
	The corporate tax rate for Germany increased to 24.2% (2014 – 22.8%) due to a trade tax increase of 1.4% effective January 2015.

10. SHAREHOLDERS’ CAPITAL

The following table reconciles the change in Vermilion’s shareholders’
capital:

Shareholders’ Capital	Number of Shares (‘000s)		Amount ($M)
Balance as at January 1, 2014		102,123	1,618,443
Shares issued pursuant to corporate acquisition		2,827	204,960
Shares issued pursuant to the dividend reinvestment plan		1,279	79,430
Vesting of equity based awards		955	47,925
Share-settled dividends on vested equity based awards		108	7,542
Shares issued pursuant to the bonus plan		11	721
Balance as at December 31, 2014		107,303	1,959,021
Shares issued pursuant to the dividend reinvestment and Premium Dividend^TM plans		3,338	155,033
Vesting of equity based awards		1,158	56,855
Share-settled dividends on vested equity based awards		135	7,561
Shares issued pursuant to the employee savings and bonus plans		57	2,619
Balance as at December 31, 2015		111,991	2,181,089

Vermilion is authorized to issue an unlimited number of common shares
with no par value.

Dividends

Dividends declared to shareholders for the year ended December 31, 2015
were $283.6 million (2014 – $272.7 million). Dividends are approved by
the Board of Directors and are paid monthly. Vermilion has a dividend
reinvestment plan (“DRIP”) which allows eligible holders of common
shares to purchase additional common shares at a 3% discount to market
by reinvesting their cash dividends. Additionally, an amendment to the
existing DRIP to include a Premium Dividend™ Component was announced in
February 2015. With the addition of the Premium Dividend™ Component
eligible shareholders have the option to reinvest their dividends in
new common shares which are exchanged for a premium cash payment equal
to 101.5% of the reinvested dividends.

Subsequent to the end of year-end and prior to the consolidated
financial statements being authorized for issue on February 25, 2016,
Vermilion declared dividends totalling $48.5 million or $0.215 per
share for each of January and February of 2016.

11. EQUITY BASED COMPENSATION

The following table summarizes the number of awards outstanding under
the Vermilion Incentive Plan (“VIP”):


Number of Awards (‘000s)	2015	2014
Opening balance	1,775	1,665
Granted	609	707
Vested	(587)	(515)
Modified	–	(21)
Forfeited	(86)	(61)
Closing balance	1,711	1,775

The fair value of a VIP award is determined on the grant date at the
closing price of Vermilion’s common shares on the Toronto Stock
Exchange, adjusted by the estimated performance factor that will
ultimately be achieved. Dividends, which notionally accrue to the
awards during the vesting period, are not included in the determination
of grant date fair values. For the year ended December 31, 2015, the
awards granted had a weighted average fair value of $80.70 (2014 –
$101.63).

The performance factor is determined by the Board of Directors after
consideration of Company performance using Vermilion’s balanced
scorecard metrics including, but not limited to, relative total
shareholder return, financial and operational performance, and
performance on strategic objectives.

The expense recognized is based on the grant date fair value of the
awards and incorporates an estimate of forfeiture rate based on
historical vesting data. For the year ended December 31, 2015,
Vermilion incorporated an estimated forfeiture rate of 4.8% (2014 –
5.8%). Equity based compensation expense of $72.6 million was recorded
during the year ended December 31, 2015 (2014 – $67.1 million) related
to the VIP.

12. PER SHARE AMOUNTS

Basic and diluted net earnings (loss) per share have been determined
based on the following:

	Year Ended
($M except per share amounts)	Dec 31, 2015	Dec 31, 2014
Net (loss) earnings [1]	(217,302)	269,326
Basic weighted average shares outstanding [2]	109,642	105,448
Dilutive impact of equity based awards	–	1,739
Diluted weighted average shares outstanding [3]	109,642	107,187
Basic (loss) earnings per share ([1] ÷ [2])	(1.98)	2.55
Diluted (loss) earnings per share ([1] ÷ [3])	(1.98)	2.51

13. DERIVATIVE INSTRUMENTS

The nature of Vermilion’s operations results in exposure to fluctuations
in commodity prices, interest rates and foreign currency exchange
rates. Vermilion monitors and, when appropriate, uses derivative
financial instruments to manage its exposure to these fluctuations.
All transactions of this nature entered into by Vermilion are related
to an underlying financial position or to future crude oil and natural
gas production. Vermilion does not use derivative financial
instruments for speculative purposes. Vermilion has elected not to
designate any of its derivative financial instruments as accounting
hedges and thus accounts for changes in fair value in net earnings at
each reporting period. Vermilion has not obtained collateral or other
security to support its financial derivatives as management reviews the
creditworthiness of its counterparties prior to entering into
derivative contracts.

During the normal course of business, Vermilion may enter into fixed
price arrangements to sell a portion of its production or purchase
commodities for operational use. Vermilion does not apply fair value
accounting on these contracts as they were entered into and continue to
be held for the sale of production or operational use in accordance
with the Company’s expected requirements.

The following tables summarize Vermilion’s outstanding risk management
positions as at December 31, 2015:

	Note	Volume	Strike Price(s)
Crude Oil
WTI – Collar
July 2015 – March 2016	1	250 bbl/d	75.00 – 83.45 CAD $
July 2015 – June 2016	2	500 bbl/d	75.50 – 85.08 CAD $
Dated Brent – Collar
July 2015 – June 2016	3	1,000 bbl/d	80.50 – 93.49 CAD $
July 2015 – June 2016	4	500 bbl/d	64.50 – 75.48 US $
October 2015 – June 2016	5	250 bbl/d	82.00 – 94.55 CAD $
January 2016 – June 2016	1	250 bbl/d	84.00 – 93.70 CAD $

North American Natural Gas
AECO – Collar
November 2015 – March 2016		2,500 GJ/d	2.50 – 3.76 CAD $
November 2015 – October 2016		10,000 GJ/d	2.56 – 3.23 CAD $
January 2016 – December 2016		10,000 GJ/d	2.53 – 3.29 CAD $
April 2016 – October 2016		5,000 GJ/d	2.30 – 2.80 CAD $
AECO Basis – Fixed Price Differential
November 2015 – March 2016		2,500 mmbtu/d	Nymex HH less 0.47 US $
Nymex HH – Collar
November 2015 – March 2016	6	5,000 mmbtu/d	3.25 – 3.86 US $


⁽¹⁾	The contracted volumes increase to 500 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽²⁾	The contracted volumes increase to 1,250 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽³⁾	The contracted volumes increase to 2,500 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽⁴⁾	The contracted volumes increase to 1,000 boe/d for any monthly settlement periods above the contracted ceiling price.
⁽⁵⁾	The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽⁶⁾	The contracted volumes increase to 10,000 mmbtu/d for any monthly settlement periods above the contracted ceiling price.

	Note	Volume	Strike Price(s)
European Natural Gas
NBP – Call
October 2016 – March 2017		2,638 GJ/d	4.64 GBP £
NBP – Collar
April 2016 – March 2017		2,638 GJ/d	3.79 – 4.53 GBP £
January 2017 – December 2017		2,638 GJ/d	3.22 – 3.75 GBP £
January 2018 – December 2018		2,638 GJ/d	2.99 – 3.63 GBP £
NBP – Put
April 2016 – September 2016		2,638 GJ/d	3.79 GBP £
NBP – Swap
July 2015 – March 2016		2,592 GJ/d	6.42 EUR €
October 2015 – March 2016		10,368 GJ/d	6.54 EUR €
January 2016 – June 2016		5,184 GJ/d	6.24 EUR €
January 2016 – June 2016		2,592 GJ/d	6.82 US $
July 2016 – March 2017		2,592 GJ/d	5.43 EUR €
January 2017 – December 2017	1	2,638 GJ/d	4.00 GBP £
January 2018 – December 2018	2	2,638 GJ/d	3.83 GBP £
TTF – Call
October 2016 – March 2017		2,592 GJ/d	6.03 EUR €
TTF – Collar
January 2016 – December 2016	3	2,592 GJ/d	5.76 – 6.50 EUR €
April 2016 – December 2016	4	12,960 GJ/d	5.58 – 6.21 EUR €
April 2016 – March 2017	5	5,184 GJ/d	5.28 – 6.35 EUR €
July 2016 – December 2016		2,592 GJ/d	5.00 – 5.63 EUR €
July 2016 – March 2017	3	2,592 GJ/d	5.07 – 6.56 EUR €
July 2016 – March 2018	3	2,592 GJ/d	5.32 – 6.54 EUR €
October 2016 – December 2017		2,592 GJ/d	5.00 – 5.89 EUR €
January 2017 – December 2017	6	7,776 GJ/d	5.00 – 6.15 EUR €
January 2018 – December 2018		5,184 GJ/d	4.17 – 5.03 EUR €
TTF – Put
April 2016 – September 2016		2,592 GJ/d	5.21 EUR €
TTF – Swap
January 2015 – March 2016		5,184 GJ/d	6.40 EUR €
January 2015 – June 2016		2,592 GJ/d	6.07 EUR €
February 2015 – March 2016		5,184 GJ/d	6.24 EUR €
April 2015 – March 2016		5,832 GJ/d	6.18 EUR €
October 2015 – March 2016		2,592 GJ/d	6.64 EUR €
January 2016 – June 2016		5,184 GJ/d	5.94 EUR €
April 2016 – December 2016		2,592 GJ/d	5.91 EUR €
July 2016 – June 2018		2,700 GJ/d	5.58 EUR €
October 2016 – December 2016		2,592 GJ/d	5.45 EUR €
January 2017 – December 2017	7	2,592 GJ/d	5.04 EUR €

Electricity
AESO – Swap
January 2016 – December 2016		93.6 MWh/d	38.58 CAD $

Interest Rate
CDOR to fixed – Swap
September 2015 – September 2019		100,000,000 CAD $/year	1.00 %
October 2015 – October 2019		100,000,000 CAD $/year	1.10 %


⁽¹⁾	On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 2,638 GJ/d at the contracted price, for the following month.
⁽²⁾	On the last business day of each month, the counterparty has the option to increase the contracted volumes to 7,913 GJ/d at the contracted price, for the following month.
⁽³⁾	The contracted volumes increase to 5,184 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽⁴⁾	The contracted volumes increase to 15,552 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽⁵⁾	The contracted volumes increase to 10,368 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽⁶⁾	The contracted volumes increase to 18,144 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽⁷⁾	On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 5,184 GJ/d at the contracted price, for the following month.

The following table reconciles the change in the fair value of
Vermilion’s derivative instruments:


		Year ended
($M)		Dec 31, 2015	Dec 31, 2014
Fair value of contracts, beginning of year		24,794	(1,287)
Reversal of opening contracts settled during the year		(23,391)	1,287
Acquired derivative contracts		–	(1,290)
Realized gain on contracts settled during the year		41,356	36,712
Unrealized gain during the year on contracts outstanding at the end of the year		66,939	26,084
Net receipt from counterparties on contract settlements during the year		(41,356)	(36,712)
Fair value of contracts, end of year		68,342	24,794
Comprised of:
	Current derivative asset	55,214	23,391
	Non-current derivative asset	13,128	1,403
Fair value of contracts, end of year		68,342	24,794

The gain on derivative instruments for 2015 and 2014 were comprised of
the following:


	Year Ended
($M)	Dec 31, 2015	Dec 31, 2014
Realized gain on contracts settled during the year	(41,356)	(36,712)
Reversal of opening contracts settled during the year	23,391	(1,287)
Unrealized gain during the year on contracts outstanding at the end of the year	(66,939)	(26,084)
Gain on derivative instruments	(84,904)	(64,083)

14. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of the following:

		Year Ended
($M)			Dec 31, 2015	Dec 31, 2014
Changes in:
	Accounts receivable		11,321	(4,202)
	Crude oil inventory		(3,569)	7,633
	Prepaid expenses		2,577	1,400
	Accounts payable and accrued liabilities		(49,449)	30,364
	Income taxes payable		(38,457)	(11,152)
	Movements in foreign exchange rates		(8,793)	(8,601)
Changes in non-cash working capital			(86,370)	15,442
Changes in non-cash operating working capital			(60,390)	3,077
Changes in non-cash investing working capital			(25,980)	12,365
Changes in non-cash working capital			(86,370)	15,442

15. SEGMENTED INFORMATION

Vermilion has operations in three core areas: North America, Europe, and
Australia. Vermilion’s operating activities in each country relate
solely to the exploration, development and production of petroleum and
natural gas. Vermilion has a Corporate head office located in Calgary,
Alberta. Costs incurred in the Corporate segment relate to Vermilion’s
global hedging program and expenses incurred in financing and managing
our operating business units.

Vermilion’s chief operating decision maker reviews the financial
performance of the Company by assessing the fund flows from operations
of each country individually. Fund flows from operations provides a
measure of each business unit’s ability to generate cash (that is not
subject to short-term movements in non-cash operating working capital)
necessary to pay dividends, fund asset retirement obligations, and make
capital investments.

	Year Ended December 31, 2015
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Total assets	1,609,180	863,304	212,749	167,908	908,453	235,139	42,927	169,560	4,209,220
Drilling and development	201,508	92,265	47,325	5,363	66,409	61,741	12,250	–	486,861
Oil and gas sales to external customers	320,613	281,422	129,057	41,384	57	162,765	4,288	–	939,586
Royalties	(28,144)	(26,958)	(3,082)	(6,479)	–	–	(1,257)	–	(65,920)
Revenue from external customers	292,469	254,464	125,975	34,905	57	162,765	3,031	–	873,666
Transportation expense	(16,326)	(15,378)	–	(3,269)	(6,687)	–	–	–	(41,660)
Operating expense	(89,085)	(50,718)	(22,746)	(10,956)	(15)	(51,676)	(742)	–	(225,938)
General and administration	(16,888)	(20,217)	(4,158)	(7,386)	(2,517)	(5,754)	(3,836)	7,172	(53,584)
PRRT	–	–	–	–	–	(6,878)	–	–	(6,878)
Corporate income taxes	–	(23,764)	(12,152)	–	–	(7,230)	–	(1,091)	(44,237)
Interest expense	–	–	–	–	–	–	–	(59,852)	(59,852)
Realized gain on derivative instruments	–	–	–	–	–	–	–	41,356	41,356
Realized foreign exchange gain	–	–	–	–	–	–	–	623	623
Realized other income	–	31,775	–	–	–	–	–	896	32,671
Fund flows from operations	170,170	176,162	86,919	13,294	(9,162)	91,227	(1,547)	(10,896)	516,167


	Year Ended December 31, 2014
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Total assets	1,865,942	874,163	220,100	170,237	822,756	240,614	14,731	177,548	4,386,091
Drilling and development	291,046	136,019	49,695	2,747	94,439	44,283	460	–	618,689
Exploration and evaluation	43,696	11,833	12,045	–	–	–	–	1,461	69,035
Oil and gas sales to external customers	537,788	431,252	123,815	41,962	–	283,481	1,330	–	1,419,628
Royalties	(65,563)	(28,444)	(5,014)	(8,613)	–	–	(366)	–	(108,000)
Revenue from external customers	472,225	402,808	118,801	33,349	–	283,481	964	–	1,311,628
Transportation expense	(14,625)	(18,975)	–	(2,367)	(6,394)	–	–	–	(42,361)
Operating expense	(76,178)	(61,729)	(24,041)	(8,686)	–	(61,432)	(241)	–	(232,307)
General and administration	(16,791)	(20,929)	(3,617)	(4,688)	(1,447)	(5,873)	(959)	(7,423)	(61,727)
PRRT	–	–	–	–	–	(60,340)	–	–	(60,340)
Corporate income taxes	–	(66,901)	(4,154)	(44)	–	(24,477)	–	(1,420)	(96,996)
Interest expense	–	–	–	–	–	–	–	(49,655)	(49,655)
Realized gain on derivative instruments	–	–	–	–	–	–	–	36,712	36,712
Realized foreign exchange loss	–	–	–	–	–	–	–	(821)	(821)
Realized other income	–	–	–	–	–	–	–	732	732
Fund flows from operations	364,631	234,274	86,989	17,564	(7,841)	131,359	(236)	(21,875)	804,865

Reconciliation of fund flows from operations to net earnings (loss)

	Year Ended
		Dec 31,	Dec 31,
($M)		2015	2014
Fund flows from operations		516,167	804,865
Equity based compensation		(75,232)	(67,802)
Unrealized gain on derivative instruments		43,548	27,371
Unrealized foreign exchange loss		8,787	(17,599)
Unrealized other expense		(1,008)	(1,492)
Accretion		(23,911)	(23,913)
Depletion and depreciation		(458,758)	(425,694)
Deferred taxes		47,728	(26,410)
Impairment		(274,623)	–
Net earnings (loss)		(217,302)	269,326

Vermilion has two major customers with revenues in excess of 10% within
the France and Netherlands segments. Substantially all sales in the
France and Netherlands segments for the years ended December 31, 2015
and 2014 were to one customer in each respective segment.

16. LEASES

Vermilion had the following future commitments associated with its
operating and finance leases as at December 31, 2015:

($M)		Less than 1 year	1 – 3 years	4 – 5 years	After 5 years	Total
Operating lease payments by period		20,750	30,942	23,909	49,734	125,335

Finance lease minimum lease payments by period		6,285	12,571	9,515	6,984	35,355
	Interest	2,079	3,077	1,521	907	7,584
	Present value of minimum lease payments	6,029	10,746	7,069	4,148	27,992

In addition, Vermilion has various other commitments associated with its
business operations; none of which, in management’s view, are
significant in relation to Vermilion’s financial position.

As part of an acquisition in April of 2014, Vermilion assumed an
agreement for the use of a solution gas facility. The substance of the
arrangement was determined to be a lease and has been classified as a
finance lease. The assets are to be used for a minimum period of 10
years, with an option to renew. As at December 31, 2015, the carrying
amount of the asset included in capital assets is $28.4 million, and
the current portion of the finance lease obligation included in accrued
liabilities in $5.9 million.

17. CASH AND CASH EQUIVALENTS

Cash and cash equivalents was comprised of the following:

($M)	Dec 31, 2015		Dec 31, 2014
Money on deposit with financial institutions		31,175		116,643
Short-term investments		10,501		3,762
Cash and cash equivalents		41,676		120,405

18. CAPITAL DISCLOSURES

Vermilion defines capital as net debt (a non-standardized measure, which
is defined by management as long-term debt as shown on the consolidated
balance sheets plus net working capital) and shareholders’ capital.

In managing capital, Vermilion reviews whether fund flows from
operations (a non-standardized measure, defined by management as cash
flows from operating activities before changes in non-cash operating
working capital and asset retirement obligations settled), is
sufficient to pay for all capital expenditures, dividends and
abandonment and reclamation expenditures. To the extent that the
forecasted fund flows from operations is not expected to be sufficient
in relation to these expenditures, Vermilion will evaluate its ability
to finance any excess with debt, an issuance of equity or by reducing
some or all categories of expenditures to ensure that total
expenditures do not exceed available funds.

Additionally, Vermilion monitors the ratio of net debt to fund flows
from operations. Vermilion typically strives to maintain an internally
targeted ratio of net debt to fund flows from operations of 1.0 to 1.3
in a normalized commodity price environment. Where prices trend higher,
Vermilion may target a lower ratio and conversely, in a lower commodity
price environment, the acceptable ratio may be higher. At times,
Vermilion will use its balance sheet to finance acquisitions and, in
these situations, Vermilion is prepared to accept a higher ratio in the
short term but will implement a plan to reduce the ratio to acceptable
levels within a reasonable period of time, usually considered to be no
more than 12 to 18 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, the net debt to fund
flows ratio is expected to be higher than the longer term ratio. During
this period, Vermilion is managing the higher debt level 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.

The following table calculates Vermilion’s ratio of net debt to fund
flows from operations:

	Year Ended
($M except as indicated)	Dec 31, 2015	Dec 31, 2014
Long-term debt	1,162,998	1,238,080
Current liabilities⁽¹⁾	503,731	365,729
Current assets	(284,778)	(338,159)
Net debt [1]	1,381,951	1,265,650
Cash flows from operating activities	444,408	791,986
Changes in non-cash operating working capital	60,390	(3,077)
Asset retirement obligations settled	11,369	15,956
Fund flows from operations [2]	516,167	804,865
Ratio of net debt to fund flows from operations ([1] ÷ [2])	2.7	1.6


⁽¹⁾	Includes the current portion of long-term debt, which, as at December 31, 2015, represents the senior unsecured notes that matured on February 10, 2016.

Long-term debt, including the current portion, as at December 31, 2015
increased to $1.39 billion from $1.24 billion as at December 31, 2014,
primarily as a result of draws on the revolving credit facility to fund
capital expenditures as fund flows from operations for the year ended
December 31, 2015 were lower due to weakening crude oil and natural gas
prices. The increase in long-term debt resulted in an increase in net
debt from $1.27 billion as at December 31, 2014 to $1.38 billion as at
December 31, 2015.

Driven primarily by the weakness in crude oil prices, the ratio of net
debt to fund flows from operations increased to 2.7 times for the year
ended December 31, 2015.

19. FINANCIAL INSTRUMENTS

Classification of Financial Instruments

The following table summarizes information relating to Vermilion’s
financial instruments as at December 31, 2015 and December 31, 2014:

As at Dec 31, 2015

As at Dec 31, 2014

Class of financial
instrument

Consolidated balance
sheet caption

Accounting
designation

Related caption on Statement of Net
Earnings (Loss)

Carrying
value ($M)

Fair value
($M)

Carrying
value ($M)

Fair value
($M)

Fair value
measurement
hierarchy

Cash

Cash and cash equivalents

HFT

Gains and losses on foreign exchange
are included in foreign exchange (gain)
loss

41,676

120,405

Level 1

Receivables

Accounts receivable

LAR

Gains and losses on foreign exchange
are included in foreign exchange (gain)
loss and impairments are recognized as
general and administration expense

160,499

171,820

Not applicable

Derivative assets

Derivative instruments

HFT

Gain on derivative instruments

68,342

24,794

Level 2

Payables

Accounts payable and
accrued liabilities

OTH

Gains and losses on foreign exchange
are included in foreign exchange (gain)
loss

(272,824)

(321,266)

Not applicable

Dividends payable

Long-term debt

OTH

Interest expense

(1,387,899)

(1,387,998)

(1,238,080)

(1,238,505)

Level 2

The accounting designations used in the above table refer to the
following:

HFT – Classified as “Held for trading” in accordance with International
Accounting Standard 39 “Financial Instruments: Recognition and
Measurement”. These financial assets and liabilities are carried at
fair value on the consolidated balance sheets with associated gains and
losses reflected in net earnings (loss).

LAR – “Loans and receivables” are initially recognized at fair value and
are subsequently measured at amortized cost. Impairments and foreign
exchange gains and losses are recognized in net earnings (loss).

OTH – “Other financial liabilities” are initially recognized at fair
value net of transaction costs directly attributable to the issuance of
the instrument and subsequently are measured at amortized cost.
Interest is recognized in net earnings (loss) using the effective
interest method. Foreign exchange gains and losses are recognized in
net earnings (loss).

Level 1 – Fair value measurement is determined by reference to
unadjusted quoted prices in active markets for identical assets or
liabilities.

Level 2 – Fair value measurement is determined based on inputs other
than unadjusted quoted prices that are observable, either directly or
indirectly.

Level 3 – Fair value measurement is based on inputs for the asset or
liability that are not based on observable market data.

Determination of Fair Values

The level in the fair value hierarchy into which the fair value
measurements are categorized is determined on the basis of the lowest
level input that is significant to the fair value measurement.
Transfers between levels on the fair value hierarchy are deemed to have
occurred at the end of the reporting period.

Fair values for derivative assets and derivative liabilities are
determined using pricing models incorporating future prices that are
based on assumptions which are supported by prices from observable
market transactions and are adjusted for credit risk.

The carrying value of receivables approximate their fair value due to
their short maturities.

The carrying value of long-term debt outstanding on the revolving credit
facility approximates its fair value due to the use of short-term
borrowing instruments at market rates of interest.

The fair value of the senior unsecured notes changes in response to
changes in the market rates of interest payable on similar instruments
and was determined with reference to prevailing market rates for such
instruments.

Nature and Extent of Risks Arising from Financial Instruments

Vermilion is exposed to the following types of risks in relation to its
financial instruments:

Credit risk:

Vermilion extends credit to customers and is due amounts from
counterparties in relation to derivative instruments. Accordingly,
there is a risk of financial loss in the event that a counterparty
fails to discharge its obligation. For transactions that are
financially significant, Vermilion reviews third-party credit ratings
and may require additional forms of security. Cash held on behalf of
the Company by financial institutions is also subject to credit risk.

Liquidity risk:

Liquidity risk is the risk that Vermilion will encounter difficulty in
meeting obligations associated with its financial liabilities.
Vermilion does not consider this to be a significant risk as its
financial position and available committed borrowing facility provide
significant financial flexibility and allow Vermilion to meet its
obligations as they come due.

Currency risk:

Vermilion conducts business in foreign currencies in addition to
Canadian dollars and accordingly is subject to currency risk associated
with changes in foreign exchange rates in relation to cash and cash
equivalents, receivables, payables and derivative assets and
liabilities. The impact related to working capital is somewhat
mitigated as a result of the offsetting effects of foreign exchange
fluctuations on assets and liabilities. Vermilion monitors its
exposure to currency risk and reviews whether the use of derivative
financial instruments is appropriate to manage potential fluctuations
in foreign exchange rates.

Commodity price risk:

Vermilion uses derivative financial instruments as part of its risk
management program to mitigate the effects of changes in commodity
prices on future cash flows. Changes in the underlying commodity
prices impact the fair value and future cash flows related to these
derivatives.

Interest rate risk:

Vermilion’s long-term debt is comprised of borrowings under the
revolving credit facility and the Company’s senior unsecured notes.
Borrowings under the revolving credit facility bear interest at market
rates plus applicable margins and as such changes in interest rates
could result in an increase or decrease in the amount Vermilion pays to
service this debt. In 2015, Vermilion had interest rate swaps to
mitigate the effects of changes in variable interest rates. The senior
unsecured notes bear interest at a fixed 6.5% interest rate and as
such, changes in prevailing interest rates would affect the fair value
of these notes. However, as Vermilion does not intend to settle this
debt prior to maturity, the notes are carried at amortized cost and
changes in fair value do not affect net earnings.

Summarized Quantitative Data Associated with the Risks Arising from
Financial Instruments

Credit risk:

As at December 31, 2015, Vermilion’s maximum exposure to receivable
credit risk was $228.8 million (December 31, 2014 – $196.6 million)
which is the aggregate value of receivables and derivative assets at
the balance sheet date. Vermilion’s receivables are primarily due from
counterparties that have investment grade third party credit ratings
or, in the absence of the availability of such ratings, have been
satisfactorily reviewed by Vermilion for creditworthiness.
Additionally, cash and cash equivalents consist of moneys on deposit
and short-term investments which may be subject to counterparty credit
risk. Vermilion mitigates this risk by transacting with North American
institutions with high third party credit ratings.

As at the balance sheet date the amount of financial assets that were
past due or impaired was not material.

Liquidity risk:

Vermilion’s derivative financial instruments settle on a monthly basis.

The following table summarizes Vermilion’s undiscounted non-derivative
financial liabilities and their contractual maturities as at December
31, 2015 and December 31, 2014:

Later than

one month and

three months and

one year and

Due in

not later than

($M)

one month

three months

one year

five years

December 31, 2015

112,890

353,934

33,663

1,180,486

December 31, 2014

162,127

138,823

20,314

1,239,067

Market risk:

Vermilion’s financial instruments are exposed to currency risk related
to changes in foreign currency denominated financial instruments and
commodity price risk related to outstanding derivative positions. The
following table summarizes what the impact on comprehensive income
before tax would be for the year ended December 31, 2015 given changes
in the relevant risk variables that Vermilion considers were reasonably
possible at the balance sheet date. The impact on comprehensive income
before tax associated with changes in these risk variables for assets
and liabilities that are not considered financial instruments are
excluded from this analysis. This analysis does not attempt to reflect
any interdependencies between the relevant risk variables.

		Before tax effect on comprehensive
		income – increase (decrease)
Risk ($M)	Description of change in risk variable	December 31, 2015	December 31, 2014
Currency risk – Euro to Canadian	Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates	(1,986)	(4,030)

	Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates	1,986	4,030

Currency risk – US $ to Canadian	Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates	3,423	(5,739)

	Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates	(3,423)	5,739

Commodity price risk	Increase in relevant oil reference price within option pricing models used to determine	(3,262)	(1,072)
	the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates

	Decrease in relevant oil reference price within option pricing models used to determine	3,263	1,048
	the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates

	Increase in relevant European natural gas reference price within option pricing models used to	(23,813)	(10,279)
	determine the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates

	Decrease in relevant European natural gas reference price within option pricing models used to	21,754	10,085
	determine the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates

Interest rate risk	Increase in average Canadian prime interest rate by 100 basis points during the relevant periods	(10,543)	(9,032)

	Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods	10,543	9,032

Reasonably possible changes in North American natural gas prices would
not have had a material impact on comprehensive income for the years
ended December 31, 2015 and 2014.

20. RELATED PARTY DISCLOSURES

The compensation of directors and management are reviewed annually by
the independent Governance and Human Resources Committee against
industry practices for oil and gas companies of similar size and scope.

The following table summarizes the compensation of directors and other
members of key management personnel during the years ended December 31,
2015 and December 31, 2014:

	Year Ended
($M)	Dec 31. 2015		Dec 31, 2014
Short-term benefits		5,460		5,684
Share-based payments		20,310		16,414
		25,770		22,098
Number of individuals included in the above amounts		20		18

21. WAGES AND BENEFITS

Included in operating expenses and general and administrative expenses
for the year ended December 31, 2015 were $47.7 million and $40.4
million of wages and benefits, respectively (2014 – $56.2 million and
$47.2 million, respectively).

22. SIGNIFICANT TRANSACTIONS

During Q1 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 French 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 Q2 2015, with the
remainder due upon conclusion of the appeal process. Based on the
recent court decision and the conclusions of the expert engaged by the
French court, Vermilion is virtually certain that the award will be
upheld.

SOURCE Vermilion Energy Inc.

PDF available at: http://stream1.newswire.ca/media/2016/02/29/20160229_C9875_DOC_EN_44636.pdf

Deduction calculated using various declining balance rates

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

Deduction calculated using a unit of production method

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