Vermilion Energy Inc. Announces Results for the Three and Six Months Ended June 30, 2015

CALGARY, Aug. 10, 2015 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three and six months ended June 30, 2015.

HIGHLIGHTS

• Average production of 51,831 boe/d for Q2 2015 exceeded prior quarter production of 50,386 boe/d by 3%.  The quarter-over-quarter increase was primarily due to successful drilling and workovers in France.  Canadian operations also contributed to the production increase through successful drilling and higher volumes from the commissioning of a natural gas processing facility in Saskatchewan in the prior quarter.  Partially offsetting these favorable impacts was the planned maintenance shutdown at our largest natural gas processing facility in the Netherlands.  Mid-stream and facility restrictions in Canada continued to negatively impact our production volumes in the second quarter of 2015.
  
  
• Fund flows from operations ("FFO")⁽¹⁾ for Q2 2015 of $129.5 million ($1.18/basic share) represented an increase of 7% quarter-over-quarter. The increase in FFO from the prior quarter was attributable to higher oil prices, an inventory draw in Australia (due to the timing of crude liftings) as well as higher production in France, Australia and Canada.
  
  
• Following a comprehensive review of 2015 development capital opportunities, Vermilion has elected to proceed with a two-well Australian sidetrack program and to also provide modest incremental capital funding for projects in Canada and France.  The Australian drilling program was previously deferred as part of our reduction in planned 2015 capital expenditures for exploration and development ("E&D).  Despite the recent renewed downturn in oil prices, the strong economics and operational efficiencies now associated with the Australia sidetrack program are sufficiently compelling to reinstate funding for the project.  Accordingly, Vermilion now expects E&D capital spending for 2015 of approximately $485 million, an increase of $70 million from our previous capital guidance of $415 million (but less than our original 2015 E&D capital budget of $525 million and 2014 E&D capital expenditures of $688 million).  We are maintaining our original production guidance of between 55,000 and 57,000 boe/d, assuming a mid-fourth quarter start-up for Corrib natural gas production and only modest production contributions in late 2015 from the incremental capital.
  
  
• At our non-operated Corrib project in Ireland, all natural gas terminal systems have now been commissioned. Following minor remaining compressor maintenance, operator Shell E&P Ireland Limited ("SEPIL") expects to declare all wells, facilities and transport systems (both offshore and onshore) ready for service by the end of August.  SEPIL conducted a workover and production test of the Corrib P2 well during July, achieving a stabilized flow rate of 107 mmcf/d (17,830 boe/d)⁽³⁾ gross.  The P2 well is expected be tied-in to the subsea production system during August, providing additional back-up to augment the deliverability of the other five wells in the Corrib field.  With respect to remaining regulatory approvals, a Final Determination for the Corrib Industrial Emissions License ("IEL") from the Irish Environmental Protection Agency ("EPA") and a Ministerial Consent from Ireland's Department of Communications, Energy and Natural Resources must be received prior to commencing natural gas production. In accordance with statutory guidelines on applicable review periods, the EPA is expected to issue its Final Determination on the IEL on or before mid-September. We now estimate that the Ministerial Consent process will be completed, and that production will commence, in the early-to-mid fourth quarter of 2015. Production at Corrib is expected to increase over the first six months after first gas to peak production levels estimated at approximately 58 mmcf/d (approximately 9,700 boe/d), net to Vermilion. While the final regulatory approvals are taking longer than we expected, we believe that we are very near the end of the regulatory process for Corrib. Our ability to maintain our 2015 production guidance (originally set in March 2014), despite foregoing approximately 3,000 net boe/d of planned calendar year average production from Corrib, is indicative of the operational and asset strength of our company. Moreover, we have maintained this production guidance while reducing 2015 capital expenditures by more than $200 million (over 30%) from 2014 levels.
  
  
• During the second quarter, we drilled and completed two (1.9 net) successful extension wells in the Netherlands. These 93% working interest natural gas wells are located in the province of North Holland.  The first well, Slootdorp-06, targeted the Slochteren formation of the Rotliegend group, while the second well, Slootdorp-07, targeted two separate intervals of the Zechstein formation.  Gross stabilized test flow rates⁽²⁾ were 23.1 mmcf/d (3,850 boe/d) for Slootdorp-06 and 11.9 mmcf/d (2,000 boe/d) and 2.4 mmcf/d (400 boe/d), respectively, for the lower and upper zones of Slootdorp-07.  The two wells are currently on sales at a combined facility-restricted rate of 21 mmcf/d (3,500 boe/d), net to Vermilion.
  
  
• In late April, we started production from the successful four (4.0 net) well program in the Champotran field in the Paris Basin in France, executed in the first quarter.  These wells contributed approximately 800 bbls/d to our second quarter average production rate.  This was our third successive Champotran drilling program since 2013, with a cumulative total of 13 wells at a 100% success rate.
  
• Subsequent to the end of the second quarter, we entered into a significant farm-in agreement in northwest Germany.  The farm-in provides Vermilion with participating interest in 850,000 net undeveloped acres in the North German Basin, in exchange for carrying 50% of the costs associated with the drilling and testing of six net exploration wells over the next five years.  The agreement also provides for the transfer to Vermilion of operatorship for the exploration phase and data spanning these lands.  A large number of crude oil and natural gas prospects and leads, primarily in the Rotliegend and Zechstein formations, have been identified on the lands.  The farm-in is consistent with our objective of steadily increasing our position in the sizable German exploration and production industry, and represents our first operated position in Germany.  The farm-in remains subject to customary conditions and regulatory approvals.
  
  
• On June 3, 2015, we were conditionally awarded four exploration blocks in northeast Croatia near the Hungarian border, by the Croatian Hydrocarbon Agency.  This award remains subject to successful execution of a definitive contract acceptable to both Vermilion and the Government of the Republic of Croatia. The four exploration blocks consist of approximately 2.35 million gross acres with a substantial portion of the acreage located near existing crude oil and natural gas fields. Capital commitments on the four blocks are modest and back-loaded.  The initial 5-year exploration period consists of two phases with an option to relinquish the blocks following the initial 3-year phase.  In aggregate, our capital commitments, excluding an initial bonus payment of €1.3 million, total approximately €7.3 million over the three-year mandatory phase, followed by an additional €11.6 million during the remaining two-year optional phase.
  
  
• We continue to direct considerable focus to our Profitability Enhancement Program ("PEP") initiative which supports the long-term profitability of our business.  Prior installments of PEP achieved strong results in both the 1998 industry downturn and the financial crisis of 2008-2009.  Based on savings identified to-date, our third installment of PEP will result in cost savings related to capital spending, operating expense and G&A expenditures estimated at between $60 and $70 million for full-year 2015.
  
  
• During the quarter, we negotiated a further expansion and extension of our existing revolving credit facilities from $1.75 billion to $2 billion.  In Q1 2015, we had previously increased our credit facility from $1.5 billion to $1.75 billion.  After the most recent expansion to our credit facility, we have approximately $775 million of borrowing capacity available.  The facility, which matures in May 2019, is fully revolving up to the date of maturity and is subject to standard form covenants.  We are, and we expect to continue to remain, in compliance with all applicable debt covenants and expect to maintain our current dividend of $0.215 per share per month ($2.58 per share per year).
  
  
• During the second quarter, Vermilion was recognized by the Great Place to Work^® Institute as a Best Workplace in Canada and France for the sixth consecutive year.  Vermilion was also recognized for a second consecutive year as a Best Workplace in the Netherlands in 2015, after becoming eligible for ranking in 2014.  Vermilion is the only energy company in its 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.
  
  
• Vermilion was recently 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 an increase over the Company's debut ranking of 32nd last year), and we were also named Top International Producer of the year by the Explorers and Producers Association of Canada.  This recognition reflects Vermilion's continued focus on financial results combined with exemplary environmental, social and governance performance.  Strong workplace practices and a culture that respects both people and communities are key elements in our success.  Please refer to our Sustainability Report at http://www.vermilionenergy.com/sustainability for more information about our environmental and social stewardship.

^(1)	Additional GAAP Financial Measure.  Please see the "Additional and Non-GAAP Financial Measures" section of Management's Discussion and Analysis.
^(2)	Slootdorp-06 (Slochteren) production test was performed over an 18-day period at a maximum choke of 64/64" with approximately 45% drawdown over the test period.  Slootdorp-07 (lower zone - Z2) production test was performed over a 4-hour test period at a maximum choke of 36/64" with approximately 35% drawdown over the test period.  Slootdorp-07 (upper zone - Z3) production test was performed over a 12-hour test period at a maximum choke of 16/64" with approximately 40% drawdown over the test period. This test result is not necessarily indicative of long-term performance or of ultimate recovery.
^(3)	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.

Conference Call and Audio Webcast Details

Vermilion will discuss these results in a conference call to be held on Monday, August 10, 2015 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 61285178.  The replay will be available until midnight mountain time on August 17, 2015.

You may also listen to the audio webcast by going to http://event.on24.com/r.htm?e=1008324&s=1&k=F4CB45E944014BE7D369F641D1A3B805 or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.

HIGHLIGHTS
				Three Months Ended									Six Months Ended
($M except as indicated)				Jun 30,			Mar 31,			Jun 30,			Jun 30,			Jun 30,
Financial				2015			2015			2014			2015			2014
Petroleum and natural gas sales				264,331			195,885			387,684			460,216			768,867
Fund flows from operations^(1)				129,496			120,795			216,076			250,291			421,439
	Fund flows from operations ($/basic share)			1.18			1.12			2.05			2.31			4.05
	Fund flows from operations ($/diluted share)			1.17			1.11			2.01			2.28			3.99
Net earnings				6,813			1,275			53,993			8,088			156,781
	Net earnings ($/basic share)			0.06			0.01			0.51			0.07			1.51
Capital expenditures				90,173			174,311			135,073			264,484			331,448
Acquisitions				480			35			381,139			515			559,366
Asset retirement obligations settled				1,218			3,107			2,381			4,325			5,032
Cash dividends ($/share)				0.645			0.645			0.645			1.290			1.290
Dividends declared				70,976			69,390			68,710			140,366			134,717
	% of fund flows from operations			55%			57%			32%			56%			32%
Net dividends^(1)				28,675			48,012			49,561			76,687			96,683
	% of fund flows from operations			22%			40%			23%			31%			23%
Payout^(1)				120,066			225,430			187,015			345,496			433,163
	% of fund flows from operations			93%			187%			87%			138%			103%
	% of fund flows from operations (excluding the Corrib project)			76%			173%			73%			123%			92%
Net debt^(1)				1,377,902			1,388,603			1,168,998			1,377,902			1,168,998
Ratio of net debt to annualized fund flows from operations^(1)				2.7			2.9			1.4			2.8			1.4
Operational
Production
	Crude oil (bbls/d)			28,916			28,181			30,184			28,550			28,759
	NGLs (bbls/d)			3,867			3,039			2,892			3,455			2,518
	Natural gas (mmcf/d)			114.29			115.00			114.08			114.64			108.73
	Total (boe/d)			51,831			50,386			52,089			51,113			49,398
Average realized prices
	Crude oil and NGLs ($/bbl)			68.90			58.25			109.89			64.23			110.73
	Natural gas ($/mcf)			4.86			5.26			6.19			5.06			7.04
Production mix (% of production)
	% priced with reference to WTI			27%			28%			30%			27%			27%
	% priced with reference to AECO			21%			20%			18%			21%			18%
	% priced with reference to TTF			16%			18%			18%			17%			19%
	% priced with reference to Dated Brent			36%			34%			34%			35%			36%
Netbacks ($/boe)^(1)
	Operating netback			36.89			31.30			59.52			34.30			61.29
	Fund flows from operations netback			26.76			29.07			46.24			27.83			46.98
	Operating expenses			12.12			10.56			12.46			11.40			12.95
Average reference prices
	WTI (US $/bbl)			57.94			48.63			102.99			53.29			100.84
	Edmonton Sweet index (US $/bbl)			55.08			41.83			96.85			48.46			93.65
	Dated Brent (US $/bbl)			61.92			53.97			109.63			57.95			108.93
	AECO ($/GJ)			2.52			2.60			4.44			2.56			4.93
	TTF ($/GJ)			7.94			8.25			7.91			8.10			9.02
Average foreign currency exchange rates
	CDN $/US $			1.23			1.24			1.09			1.24			1.10
	CDN $/Euro			1.36			1.40			1.50			1.38			1.50
Share information ('000s)
Shares outstanding - basic				109,806			107,718			106,620			109,806			106,620
Shares outstanding - diluted^(1)				112,626			110,761			109,371			112,626			109,371
Weighted average shares outstanding - basic				109,319			107,513			105,577			108,421			103,936
Weighted average shares outstanding - diluted				110,746			109,305			107,330			109,792			105,531

^(1)	The above table includes additional GAAP and non-GAAP financial measures which may not be comparable to other companies.  Please see the "ADDITIONAL AND 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 present value of future net cash flows 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 and prospective 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; the timing of regulatory proceedings and approvals; and the timing of first commercial natural gas and the estimate of Vermilion's share of the expected natural gas production from the Corrib field.

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.  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
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
mmcf			million cubic feet
mmcf/d			million cubic feet per day
MWh			megawatt hour
NGLs			natural gas liquids
NGTL			NOVA Gas Transmission Ltd., a wholly owned subsidiary of TransCanada is the owner of a gas transmission system known as the NGTL system. The NGTL system is a 23,500 km pipeline that gathers natural gas for both use in Alberta, and to deliver it to provincial border points for export to North American markets.
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

MESSAGE TO SHAREHOLDERS

After appearing to reach some degree of range-bound stability during the second quarter, crude oil prices have recently come under renewed pressure as a result of a number of macroeconomic uncertainties.  Although this price environment poses significant challenges for many energy sector participants, Vermilion remains comparatively well-positioned given our disciplined approach to financial management and our commodity diversification. In particular, our exposure to European natural gas markets, where fundamentals and pricing remain strong, is a key advantage differentiating Vermilion from its competitors.

As current European natural gas prices remain nearly triple those in Canada, a significant part of our strategic focus has been on maximizing our exposure to this advantageously priced commodity.  In 2014, we expanded our European natural gas production by nearly 50% with our entry into Germany, a producing region with a long history of development activity and strong market fundamentals.  As detailed later in this Message (see German Farm-In), we have further expanded our European natural gas opportunities by entering into an 850,000 acre farm-in in the key German producing basin.  In addition, we have received a conditional award for a 2.35 million acre position in the underexploited Croatian portion of the Pannonian basin (see Croatian Exploration Block Award).  With continued organic growth in Netherlands natural gas production, combined with forthcoming natural gas production from our Corrib project in Ireland, European natural gas will continue to increase in prominence for Vermilion.

Our international diversification and associated exposure to Brent-based crude oil pricing continues to favorably distinguish us from our North America-focused competitors.  This advantage is illustrated by the second quarter's operating netback for our Brent-based crude oil sales in Australia and France, which was a blended $51.89/boe, as compared to the operating netback of $48.41/boe for our WTI-based crude oil sales in North America.

In February 2015, we announced a reduction in our 2015 exploration and development ("E&D") capital program to $415 million in response to the significant decrease in crude oil prices that began in mid-2014. Following a comprehensive review of our E&D capital opportunities, we have elected to increase our 2015 E&D capital program to $485 million, an increase of $70 million from our previous capital guidance of $415 million (but less than our original 2015 E&D capital budget of $525 million and 2014 E&D capital expenditures of $688 million). The majority of this increase is associated with the reinstatement of a two-well Australia sidetrack program. The strong economics of this program, coupled with current services pricing advantages and operational efficiencies associated with drilling the wells outside of cyclone season, support our decision to proceed with this project. Vermilion also intends to drill and complete two additional (1.8 net) Mannville condensate-rich natural gas wells and tie-in a third Mannville well. Modest incremental funding has been made available for additional highly economic workovers in France and Canada, and the revised capital program also reflects a minor increase in capital for Ireland as we ramp up for first gas production. We remain on target to achieve our original full year 2015 production guidance of 55,000 to 57,000 boe/d. Based on a mid-fourth quarter start-up for Corrib natural gas production and only modest production contributions in 2015 from our incremental capital, we consider it more likely that annual production will come in closer to the lower end of our guidance range. This would still represent year-over-year production growth exceeding 10%, supported by consolidated organic production growth in each successive quarter of 2015.

In late 2014, we initiated a Profitability Enhancement Program ("PEP") to systematically identify cost savings and efficiency opportunities company-wide.  Prior installments of PEP achieved strong results in both the 1998 industry downturn and the financial crisis of 2008-2009.  Based on savings identified to-date, this iteration of PEP is expected to result in cost savings related to capital spending, operating expense and G&A estimated at between $60 and $70 million for full-year 2015.

Results from our European development activities have exceeded our expectations.  In late April, we started production from the four (4.0 net) wells we drilled in the Champotran field in the Paris Basin in France in Q1 2015.  These wells contributed approximately 800 boe/d to our second quarter average production rate, and are producing at rates that are better than anticipated.  This was our third drilling program in the Champotran field since 2013, with a cumulative total of 13 wells, at a 100% success rate.   After-tax rates of return associated with our Champotran oil drilling program remain in excess of 100%⁽²⁾ at today's oil prices.  The remainder of our 2015 capital activities in France will continue to focus on highly economic workovers and optimization projects, as well as infrastructure and facility maintenance.  During the second quarter, we successfully restored approximately 2 mmcf/d (330 boe/d) of shut-in natural gas production from our Vic Bilh field.

In the Netherlands, we drilled two (1.9 net) wells during the quarter on the Slootdorp concession, in the province of North Holland.  Both wells were successful, encountering more natural gas pay than expected.  The first well, Slootdorp-06, encountered 70 meters of net natural gas pay in the Slochteren formation of the Rotliegend group.  The second well, Slootdorp-07, encountered 41 meters of net natural gas pay in two separate intervals in the Zechstein Carbonate.  Gross stabilized test flow rates⁽³⁾ were 23.1 mmcf/d (3,850 boe/d) for Slootdorp-06 and 11.9 mmcf/d (2,000 boe/d) and 2.4 mmcf/d (400 boe/d), respectively, for the lower and upper Zechstein intervals of Slootdorp-07.  Both wells are on sales during an extended production test to size additional production equipment. The wells are producing at a facility-restricted combined rate of 21 mmcf/d (3,500 boe/d) net.  We completed planned major facility maintenance at the Garijp Treatment Centre in late June, which reduced production in the quarter by approximately 2,400 mcf/d (400 boe/d).  The shutdown went as intended and the facility returned to service in late June.

In our non-operated German producing assets, our partner (ExxonMobil Production Deutschland GmbH) finished drilling and completing the Burgmoor Z3a well (25% net interest to Vermilion).  The well was placed on production subsequent to the quarter and is currently producing at a rate of approximately 1.4 mmcf/d (230 boe/d), net to Vermilion.

At our non-operated Corrib project in Ireland, all natural gas terminal systems have now been commissioned. Following minor remaining compressor maintenance, operator Shell E&P Ireland Limited ("SEPIL") expects to declare all wells, facilities and transport systems (both offshore and onshore) ready for service by the end of August.  SEPIL conducted a workover and production test of the Corrib P2 well during July, achieving a stabilized flow rate of 107 mmcf/d (17,830 boe/d)⁽⁴⁾ gross.  The P2 well is expected to be tied-in to the subsea production system during August, providing additional back-up to augment the deliverability of the other five wells in the Corrib field. With respect to remaining regulatory approvals, a Final Determination for the Corrib Industrial Emissions License ("IEL") from the Irish Environmental Protection Agency ("EPA") and a Ministerial Consent from Ireland's Department of Communications, Energy and Natural Resources must be received prior to commencing natural gas production. In accordance with statutory guidelines on applicable review periods, the EPA is expected to issue its Final Determination on the IEL on or before mid-September. We now estimate that the Ministerial Consent process will be completed, and that production will commence, in the early-to-mid fourth quarter of 2015. Production at Corrib is expected to increase over the first six months after first gas to peak production levels estimated at approximately 58 mmcf/d (approximately 9,700 boe/d), net to Vermilion.

While the final regulatory approvals are taking longer than we expected, we believe that we are very near the end of the regulatory process for Corrib. Our ability to maintain our 2015 production guidance (originally set in March 2014), despite foregoing approximately 3,000 net boe/d of planned calendar year average production from Corrib, is indicative of the operational and asset strength of our company. Moreover, we have maintained this production guidance while reducing 2015 capital expenditures by more than $200 million (over 30%) from 2014 levels. Upon commencement, Corrib production will further increase Vermilion's exposure to advantageously priced European natural gas.

With the compelling opportunities inherent in our overseas business units, and the significant operating flexibility offered by our Canadian asset base, planned activity levels for Canada in 2015 are less than in prior years.  That being said, our Canadian opportunities continue to offer robust economics with the Cardium light-oil resource play generating capital investment rates of return of approximately 30%⁽²⁾. Results to-date have been strong, with better-than-forecasted production volumes on our two-mile extended reach horizontal wells. In Q1 2015, we participated in the drilling of only seven (3.1 net) Cardium wells, which represented our planned Cardium drilling activities for 2015 (compared to 30 to 50 net wells in previous years). During Q2, we focused predominately on the completion and tie-in of previously drilled wells. Our Mannville condensate-rich conventional natural gas play remains the most economic play in our Canadian portfolio with current rates of return in excess of 100%⁽²⁾.   During Q1 2015, we participated in drilling 13 (8.9 net) wells followed by an additional one (0.5 net) well in Q2.  In total, we plan on drilling approximately 30 (17.8 net) Mannville wells in 2015.  During the second quarter, we also concluded a significant 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 the Mannville play.  In Saskatchewan, we had previously reduced our drilling activity to five (4.1 net) wells for 2015, all of which were drilled in the first quarter. New well results in our downdip Midale play in southeast Saskatchewan have been better than we expected at the time we entered this area in 2014.  Duvernay drilling activities have been deferred to beyond 2015 as we monitor the performance of our two appraisal wells drilled in 2014.  In Alberta, we continue to be negatively impacted by plant capacity restrictions and interruptible service curtailments on the NGTL system, with approximately 1,700 boe/d of production offline during the second quarter.

In the United States, we drilled one gross (1 net) well in our Turner Sand resource play in the eastern Powder River Basin during the second quarter.  We expect to complete this well during the third quarter of 2015.

To maintain financial flexibility in this commodity price environment, we further increased our existing revolving credit facilities from $1.75 billion to $2 billion during the second quarter.  Taking into account this most recent expansion to our credit facility, we have approximately $775 million of borrowing capacity available.  The facility, which matures in May 2019, is fully revolving up to the date of maturity and is subject to standard form covenants (discussed in the "Financial Position Review" section of our MD&A).  We are, and we expect to continue to remain, in compliance with all applicable debt covenants, and expect to maintain our current dividend of $0.215 per share per month ($2.58 per share per year).  We currently anticipate our balance sheet leverage to remain at current levels assuming consistent commodity prices, and then to naturally de-lever with the addition of FFO from our Corrib asset starting in the fourth quarter of 2015 and into 2016. While our current debt-to-cash flow ratio is higher than our targeted levels, it remains lower than the average debt ratio of our peer group.  Our conservative financial management continues to provide us with the flexibility to manage our business effectively and provide continued growth and returns for shareholders in this challenging price environment.

During Q2, Vermilion was pleased to announce that for a sixth consecutive year, it has been recognized by the Great Place to Work® Institute as a Best Workplace in Canada and France.  Vermilion was also recognized for a second consecutive year as a Best Workplace in the Netherlands in 2015, after becoming eligible for ranking in 2014.  Vermilion is the only energy company in its 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.

Vermilion was recently 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 Vermilion's continued focus on achieving robust shareholder returns combined with environmental, social and governance performance. Our non-financial initiatives and performance are also articulated in the Company's annual Carbon Disclosure Project (CDP) submissions and in our Sustainability Report (http://www.vermilionenergy.com/sustainability). Strong workplace practices and a culture that respects both people and communities are key elements in our success.

The management and directors of Vermilion continue to hold approximately 6% of the outstanding shares and remain committed to delivering superior rewards to all stakeholders.  In spite of the challenges posed by the current business environment, we continue to believe that Vermilion is situated for long-term, diversified growth.  We remain confident that the assets in our portfolio can support organic growth for future years, and in the current environment, we also find ourselves well positioned to take advantage of potential acquisition activity in both North American and international markets.  Our long-term focus on the creation of real value through our technical capabilities, combined with our conservative financial approach and patience, should allow us to compete and transact for the benefit of our existing shareholders if suitable opportunities arise.

German Farm-In

Subsequent to the end of the second quarter, we entered into a definitive farm-in agreement (the "Farm-in" or the "Agreement") with Mobil Erdgas-Erdӧl GmbH ("MEEG") and BEB Erdgas und Erdӧl GmbH & Co.KG ("BEB").  MEEG is 100% held by ExxonMobil and BEB is jointly held by ExxonMobil and Royal Dutch Shell.  ExxonMobil Production Deutschland GmbH ("EMPG") currently operates and manages both MEEG's and BEB's interests in the exploration licenses involved in the Farm-in. The Agreement, signed July 27, 2015 and with an anticipated closing date of January 1, 2016, remains subject to customary conditions and regulatory approvals.

The Farm-in will provide Vermilion participating interest in 19 onshore exploration licenses in northwest Germany, comprising approximately 850,000 net acres of oil and natural gas rights (100% undeveloped) (the "Assets").  Under the terms of the Agreement, Vermilion will acquire the Assets (which represent 50% of MEEG's and BEB's current interests in these licenses) in exchange for committing to the financial carry of the remaining 50% of MEEG's and BEB's interests in 11 gross (6 net) exploratory wells over the next five years.  At present, approximately 75 exploratory and semi-exploratory leads and prospects have been identified in the Rotliegend, Carboniferous, Triassic and Zechstein formations on these lands.  Eleven of the 19 licenses are currently operated by EMPG, which will transfer operatorship for the exploration phase to Vermilion.  The Agreement also grants Vermilion proportional ownership to EMPG proprietary data spanning the Assets.  No existing oil or natural gas production is being acquired by Vermilion in the Farm-in.

The Farm-in provides Vermilion with a large, nearly contiguous land block in the heart of the North German Basin.  This basin has cumulative production of more than two billion barrels of oil and 34 trillion cubic feet of natural gas since its discovery, representing approximately 97% of Germany's historical onshore production.  We believe that the Assets are prospective for both oil and natural gas.  The Farm-in follows our entry in early 2014 into the exploration and production business in Germany, a jurisdiction with a long history of oil and natural gas development activity, a consistent fiscal framework and low political risk.  The Assets are a natural and synergistic expansion to our existing German and Netherlands portfolios, and share the same subsurface genre and development approach.  We believe that our capability in conventional oil and natural gas exploration and production in onshore Europe, coupled with our track record of accretive European consolidation, positions us for future development and expansion opportunities in both Germany and the greater European region.

Croatian Exploration Block Award

On June 3, 2015, we were conditionally awarded four exploration blocks in northeast Croatia near the Hungarian border, by the Croatian Hydrocarbon Agency.  This award remains subject to successful execution of a definitive contract acceptable to both Vermilion and the Government of the Republic of Croatia. The four exploration blocks consist of approximately 2.35 million gross acres with a substantial portion of the acreage located near existing crude oil and natural gas fields. Capital commitments on the four blocks are modest and back-loaded.  The initial 5-year exploration period consists of two phases with an option to relinquish the blocks following the initial 3-year phase.  In aggregate, our capital commitments, excluding an initial bonus payment of €1.3 million, total approximately €7.3 million over the three-year mandatory phase, followed by an additional €11.6 million during the remaining two-year optional phase.

^(1)	The above discussion includes additional GAAP and non-GAAP measures which may not be comparable to other companies.  Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.
^(2)	Economics calculated using the following commodity price deck assumptions:  $50/bbl WTI; $55/bbl Dated Brent; $2.85/mmbtu AECO; CAD/USD 1.30; CAD/EUR 1.40.
^(3)	Slootdorp-06 (Slochteren) production test was performed over an 18-day test period at a maximum choke of 64/64" with approximately 45% drawdown over the test period.  Slootdorp-07 (lower zone - Z2) production test was performed over a 4-hour test period at a maximum choke of 36/64" with approximately 35% drawdown over the test period.  Slootdorp-07 (upper zone - Z3) production test was performed over a 12-hour test period at a maximum choke of 16/64" with approximately 40% drawdown over the test period. This test result is not necessarily indicative of long-term performance or of ultimate recovery.
^(4)	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 August 6, 2015, of Vermilion Energy Inc.'s ("Vermilion", "We", "Our", "Us" or the "Company") operating and financial results as at and for the three and six months ended June 30, 2015 compared with the corresponding periods in the prior year.

This discussion should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2015 and the audited consolidated financial statements for the year ended December 31, 2014 and 2013, together with accompanying notes.  Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

The unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2015 and comparative information have been prepared in Canadian dollars, except where another currency is indicated, and in accordance with IAS 34, "Interim Financial Reporting", as issued by the International Accounting Standard Board ("IASB").

This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS").  As such, these financial measures are considered additional GAAP or non-GAAP financial measures and therefore are unlikely to be comparable with similar financial measures presented by other issuers.  These additional GAAP and non-GAAP financial measures include:

• Fund flows from operations: This additional GAAP 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 non-GAAP 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.

For a full description of these and other non-GAAP financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to "ADDITIONAL AND 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 25% contractual participation interest in a four-partner consortium 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.

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 campaign.  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 campaign as well as additional funding for projects in Canada, France and Ireland.  We are maintaining 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.

The following table summarizes our 2015 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

SHAREHOLDER RETURN

Vermilion strives to provide investors with reliable and growing dividends in addition to sustainable, global production growth.  The following table, as of June 30, 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				$7.41				$11.97
Capital appreciation per Vermilion share				-$20.30				$7.98				$20.28
Total return per Vermilion share				-23.9%				33.5%				95.8%
Annualized total return per Vermilion share				-23.9%				10.1%				14.4%
Annualized total return on the S&P TSX High Income Energy Index				-32.2%				-2.9%				0.4%

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

CONSOLIDATED RESULTS OVERVIEW

				Three Months Ended									% change						Six Months Ended						% change
				Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
				2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
Production
	Crude oil (bbls/d)			28,916			28,181			30,184			3%			(4%)			28,550			28,759			(1%)
	NGLs (bbls/d)			3,867			3,039			2,892			27%			34%			3,455			2,518			37%
	Natural gas (mmcf/d)			114.29			115.00			114.08			(1%)			-			114.64			108.73			5%
	Total (boe/d)			51,831			50,386			52,089			3%			-			51,113			49,398			3%
	Build (draw) in inventory (mbbl)			(121)			383			67									262			(31)
Financial metrics
	Fund flows from operations ($M)			129,496			120,795			216,076			7%			(40%)			250,291			421,439			(41%)
	Per share ($/basic share)			1.18			1.12			2.05			5%			(42%)			2.31			4.05			(43%)
	Net earnings ($M)			6,813			1,275			53,993			434%			(87%)			8,088			156,781			(95%)
	Per share ($/basic share)			0.06			0.01			0.51			500%			(88%)			0.07			1.51			(95%)
	Cash flows from operating activities ($M)			134,668			22,647			149,592			495%			(10%)			157,315			327,830			(52%)
	Net debt ($M)			1,377,902			1,388,603			1,168,998			(1%)			18%			1,377,902			1,168,998			18%
	Cash dividends ($/share)			0.645			0.645			0.645			-			-			1.290			1.290			-
Activity
	Capital expenditures ($M)			90,173			174,311			135,073			(48%)			(33%)			264,484			331,448			(20%)
	Acquisitions ($M)			480			35			381,139			1,271%			(100%)			515			559,366			(100%)
	Gross wells drilled			5.00			29.00			13.00									34.00			37.00
	Net wells drilled			3.61			20.04			6.72									23.65			25.55

Operational review

• Recorded consolidated average production of 51,831 boe/d during Q2 2015, which was a 3% increase over Q1 2015 as a result of production growth in France and Canada driven primarily by new wells on production, partially offset by decreased production in the Netherlands due to planned facility maintenance.  As compared to Q2 2014, production remained relatively consistent. Steady production, coupled with a draw in inventory of 121,000 bbls in Q2 2015, resulted in higher volumes sold versus the comparable quarters.
• Increased consolidated average production to 51,113 for the six months ended June 30, 2015, a 3% increase versus the same period in 2014 primarily due to production growth in Canada and France, partially offset by decreased production in the Netherlands and Australia.  In Canada, production growth of 9% year-over-year was achieved through continued development of the Cardium and Mannville plays in Alberta, combined with six months of production from southeast Saskatchewan, as compared to two months of production included in the 2014 period following our acquisition in April 2014 of Elkhorn Resources Inc.  In France, production increased 12% following our successful Champotran drilling program and workovers, as well as the resumption of a portion of previously shut-in natural gas production at Vic Bilh. These increases were offset by production decreases in the Netherlands and Australia due to the planned maintenance shutdown at our largest gas processing facility in the Netherlands, as well as active management to control inventory levels and meet marketing schedules in Australia.
• Activity during the quarter included capital expenditures totalling $90.2 million, evenly distributed between Canada, Ireland, France, and the Netherlands.  In Canada, capital expenditures totalling $21.9 million were 81% lower than the $114.8 million incurred in Q1 2015 due to spring breakup and were related to facility work and the drilling of one (0.5 net) well compared to 16.0 net wells in Q1 2015.  In France, capital expenditures totalled $16.7 million with activity focused on the completion of the Champotran drilling campaign and accretive workovers.  In Ireland, capital expenditures of $20.3 million were incurred, the majority of which related to facility commissioning and subsurface activities.  In the Netherlands, capital expenditures of $18.9 million were significantly higher than the $4.3 million incurred in Q1 2015 and related to the drilling of 1.9 net wells, while no wells were drilled in Q1 2015.

Financial review

Net earnings

• Net earnings for Q2 2015 were $6.8 million ($0.06/basic share) as compared to net earnings of $1.3 million ($0.01/basic share) in Q1 2015. The increase is attributable to higher petroleum and natural gas sales driven by higher commodity prices and higher sales volumes, as well as a $7.2 million gain on derivative instruments (compared to a loss of $13.7 million in Q1 2015). These increases were partially offset by higher operating costs and depletion and depreciation, both of which were driven by inventory drawdowns in Australia, and the absence of the Q1 2015 recognition of the recovery of costs in France. In Q1 2015, Vermilion recognized $31.8 million (before taxes) following a judgment which awarded Vermilion costs incurred as a result of an oil spill at the Ambès oil terminal in France that occurred in 2007 shortly after Vermilion acquired the asset.
• Net earnings for the three and six months ended June 30, 2015 decreased by $47.2 million and $148.7 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, and were partially offset by decreases in royalties and taxes.  In the six months ended June 30, 2015, the decrease in net earnings was also minimized by the recovery of costs in France recognized in Q1 2015.

Cash flows from operating activities

• Cash flows from operating activities increased as compared to Q1 2015, driven primarily by higher volumes sold and higher realized prices, as well as significant timing differences pertaining to working capital.
• Cash flows from operating activities decreased by 10% and 52% for the three and six months ended June 30, 2015, respectively, versus the comparable periods in 2014. The decreases primarily related to lower sales due to lower commodity prices, partially offset by timing differences pertaining to working capital, foreign exchange gains and lower royalties.

Fund flows from operations

• Generated fund flows from operations of $129.5 million during Q2 2015, an increase of 7% versus Q1 2015. This quarter-over-quarter increase was the result of higher sales, driven by higher volumes and prices, and lower tax expense. This was partially offset by higher operating expenses, as well as the absence of the recovery of costs resulting from the oil spill at the Ambès terminal in France that occurred in 2007, which was recognized in Q1 2015.
• Fund flows from operations decreased 40% and 41% for the three and six months ended June 30, 2015, respectively, versus the comparable periods in 2014.  These decreases were primarily driven by lower crude oil pricing, partially offset by higher sold volumes in Australia (due to an inventory draw in Q2 2015), as well as favorable royalty and tax variances, consistent with lower commodity prices.  The decrease in fund flows from operations for the six months ended June 30, 2015, was further minimized by the previously mentioned recovery of costs in France.

Net debt

• Net debt increased by $112.3 million to $1.38 billion for the period ended June 30, 2015 due to capital expenditures in Canada and Ireland coupled with the decrease in fund flows from operations, driven by weaker commodity prices in the first half of 2015.

Dividends

• Declared dividends remained consistent at $0.215 per common share per month during the second quarter of 2015, totalling $0.645 per common share and $1.290 per common share for the three and six months ended June 30, 2015, respectively.

COMMODITY PRICES

			Three Months Ended									% change						Six Months Ended						% change
			Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
			2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
Average reference prices
WTI (US $/bbl)			57.94			48.63			102.99			19%			(44%)			53.29			100.84			(47%)
Edmonton Sweet index (US $/bbl)			55.08			41.83			96.85			32%			(43%)			48.46			93.65			(48%)
Dated Brent (US $/bbl)			61.92			53.97			109.63			15%			(44%)			57.95			108.93			(47%)
AECO ($/GJ)			2.52			2.60			4.44			(3%)			(43%)			2.56			4.93			(48%)
TTF ($/GJ)			7.94			8.25			7.91			(4%)			-			8.10			9.02			(10%)
TTF (€/GJ)			5.84			5.91			5.27			(1%)			11%			5.87			6.01			(2%)
Average foreign currency exchange rates
CDN $/US $			1.23			1.24			1.09			(1%)			13%			1.24			1.10			13%
CDN $/Euro			1.36			1.40			1.50			(3%)			(9%)			1.38			1.50			(8%)
Average realized prices ($/boe)
Canada			40.59			35.81			71.56			13%			(43%)			38.24			70.55			(46%)
France			71.96			64.33			117.29			12%			(39%)			68.52			117.41			(42%)
Netherlands			47.63			48.60			48.14			(2%)			(1%)			48.13			56.06			(14%)
Germany			43.31			45.21			45.36			(4%)			(5%)			44.27			49.50			(11%)
Australia			80.87			83.80			126.87			(3%)			(36%)			81.60			127.11			(36%)
United States			60.57			48.79			-			24%			100%			54.07			-			100%
Consolidated			54.65			47.17			82.96			16%			(34%)			51.19			85.70			(40%)
Production mix (% of production)
% priced with reference to WTI			27%			28%			30%									27%			27%
% priced with reference to AECO			21%			20%			18%									21%			18%
% priced with reference to TTF			16%			18%			18%									17%			19%
% priced with reference to Dated Brent			36%			34%			34%									35%			36%

Reference prices

• Evidence of slowing production growth and stronger demand helped support oil prices in the second quarter of 2015.  Compared to Q1 2015, the three months ended June 30, 2015 showed a 19% increase for WTI and a 15% increase for Dated Brent.
• The second quarter of 2015 proved to be a particularly strong quarter for Edmonton Sweet index pricing as strong refining demand and maintenance work combined to tighten supply/demand fundamentals.  For the three months ending June 30, 2015, the Edmonton Sweet index was up 32% versus the previous quarter, but was still 43% lower year-over-year.
• AECO natural gas prices were relatively flat quarter-over-quarter, but were below last year's levels.  AECO averaged C$2.52/GJ in Q2 2015, which is just 3% lower than the previous three months, but 43% lower year-over-year.
• TTF natural gas averaged just slightly lower in Q2 2015 versus Q1 2015 despite seasonal dynamics.  Lower inventories and maintenance were the main factors that helped to keep TTF natural gas prices firm throughout the second quarter, ending just 1% lower quarter-over-quarter and 11% higher versus the same quarter last year in Euro terms.
• Despite a rather volatile quarter, the Canadian dollar averaged nearly the same in Q2 2015 as in Q1 2015 versus the US dollar at 1.23 CDN$/US$.  The low commodity price environment and broader US dollar strength continues to limit Canadian dollar strength; however, versus the Euro, the Canadian dollar posted a modest increase quarter-over-quarter.  In Q2 2015, the CDN $/Euro averaged 1.36 versus 1.40 in Q1 2015 and 1.50 in Q2 2014.

Realized prices

• Consolidated realized price increased by 16% for Q2 2015 as compared to Q1 2015. This increase was the result of improving crude oil pricing, coupled with relatively consistent natural gas pricing.
• Consolidated realized price for the three and six months ended June 30, 2015 decreased by 34% and 40%, respectively, as compared to the comparable periods in 2014. These decreases were driven by a decrease in crude oil pricing, as well as a decrease in North American natural gas pricing.

FUND FLOWS FROM OPERATIONS

			Three Months Ended																		Six Months Ended
			Jun 30, 2015						Mar 31, 2015						Jun 30, 2014						Jun 30, 2015						Jun 30, 2014
			$M			$/boe			$M			$/boe			$M			$/boe			$M			$/boe			$M			$/boe
Petroleum and natural gas sales			264,331			54.65			195,885			47.17			387,684			82.96			460,216			51.19			768,867			85.70
Royalties			(16,111)			(3.33)			(16,424)			(3.95)			(29,013)			(6.21)			(32,535)			(3.62)			(53,037)			(5.91)
Petroleum and natural gas revenues			248,220			51.32			179,461			43.22			358,671			76.75			427,681			47.57			715,830			79.79
Transportation expense			(10,883)			(2.25)			(9,540)			(2.30)			(12,032)			(2.57)			(20,423)			(2.27)			(21,893)			(2.44)
Operating expense			(58,616)			(12.12)			(43,851)			(10.56)			(58,213)			(12.46)			(102,467)			(11.40)			(116,199)			(12.95)
General and administration			(14,505)			(3.00)			(13,560)			(3.27)			(17,762)			(3.80)			(28,065)			(3.12)			(32,229)			(3.59)
PRRT			(3,371)			(0.70)			(2,354)			(0.57)			(12,699)			(2.72)			(5,725)			(0.64)			(32,938)			(3.67)
Corporate income taxes			(17,344)			(3.59)			(17,623)			(4.24)			(32,635)			(6.98)			(34,967)			(3.89)			(71,238)			(7.94)
Interest expense			(14,550)			(3.01)			(13,298)			(3.20)			(12,334)			(2.64)			(27,848)			(3.10)			(23,794)			(2.65)
Realized gain on derivative instruments			3,081			0.64			6,257			1.51			2,419			0.52			9,338			1.04			5,059			0.56
Realized foreign exchange (loss) gain			(2,740)			(0.57)			3,306			0.78			587			0.12			566			0.06			(1,454)			(0.16)
Realized other income			204			0.04			31,997			7.70			74			0.02			32,201			3.58			295			0.03
Fund flows from operations			129,496			26.76			120,795			29.07			216,076			46.24			250,291			27.83			421,439			46.98

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

($M)					Q2/15 vs. Q1/15				Q2/15 vs. Q2/14					2015 vs. 2014
Fund flows from operations - Comparative period					120,795				216,076					421,439
Sales volume variance:
	Canada				1,950				(10,845)					15,826
	France				12,285				6,751					(1,469)
	Netherlands				(2,407)				(5,585)					(12,187)
	Germany				(313)				30					4,606
	Australia				38,956				29,345					(31,213)
	United States				(127)				677					1,349
Pricing variance on sold volumes:
	WTI				12,700				(50,424)					(108,609)
	AECO				(1,118)				(10,708)					(24,490)
	Dated Brent				7,474				(81,710)					(141,350)
	TTF				(954)				(884)					(11,114)
Changes in:
	Royalties				313				12,902					20,502
	Transportation				(1,343)				1,149					1,470
	Operating expense				(14,765)				(403)					13,732
	General and administration				(945)				3,257					4,164
	PRRT				(1,017)				9,328					27,213
	Corporate income taxes				279				15,291					36,271
	Interest				(1,252)				(2,216)					(4,054)
	Realized derivatives				(3,176)				662					4,279
	Realized foreign exchange				(6,046)				(3,327)					2,020
	Realized other income				(31,793)				130					31,906
Fund flows from operations - Current period					129,496				129,496					250,291

Fund flows from operations of $129.5 million during Q2 2015 represented an increase of 7% versus Q1 2015.  This quarter-over-quarter increase was principally the result of higher sales volumes and stronger crude oil pricing.  Sales increased by $68.4 million, which included a $50.3 million sales volumes variance driven by increased sales in Australia ($39.0 million) and France ($12.3 million).  Both Australia and France were impacted by inventory variances, where Australia had an inventory draw of 162,000 bbls (as compared to a build of 281,000 bbls) and France's inventory increased by 41,000 bbls (as compared to a build of 102,000 bbls).  The increase in fund flows from operations was further impacted by an $18.1 million favorable pricing variance driven by higher crude oil prices.  Higher sold volumes and crude oil pricing was partially offset by higher operating expenses resulting from the recognition of inventoried operating costs in Australia, as well as the absence of the previously mentioned recovery of costs in France.

Fund flows from operations decreased by 40% and 41% for the three and six months ended June 30, 2015, respectively, versus the comparable periods in the prior year.  This decrease was primarily driven by unfavorable crude oil and natural gas pricing variances, partially offset by favorable royalty and tax variances.  For the three months ended June 30, 2015, the decrease in fund flows from operations was further offset by a favorable sales variance of $20.4 million driven by increased sold volume in Australia. For the six months ended June 30, 2015, the decrease in fund flows from operations was further impacted by a $23.1 million unfavorable sales variance, driven by a build in inventory of 262,000 bbls (as compared to a draw of 31,000 bbls in the comparative period), partially offset by the previously mentioned recovery of costs in France.

Fluctuations in fund flows from operations (and correspondingly net earnings 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 balance sheet.  When the crude oil inventory is subsequently drawn down, the related expenses are recognized in fund flows from operations.

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						Six Months Ended						% change
					Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
Canada business unit					2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
Production
	Crude oil (bbls/d)				10,182			10,893			12,676			(7%)			(20%)			10,535			11,065			(5%)
	NGLs (bbls/d)				3,755			2,976			2,796			26%			34%			3,367			2,435			38%
	Natural gas (mmcf/d)				64.66			61.78			57.59			5%			12%			63.23			53.58			18%
	Total (boe/d)				24,713			24,165			25,070			2%			(1%)			24,441			22,430			9%
Production mix (% of total)
	Crude oil				41%			45%			51%									43%			49%
	NGLs				15%			12%			11%									14%			11%
	Natural gas				44%			43%			38%									43%			40%
Activity
	Capital expenditures ($M)				21,881			114,849			36,968			(81%)			(41%)			136,730			151,907			(10%)
	Acquisitions ($M)				384			35			381,326									419			386,094
	Gross wells drilled				1.00			25.00			9.00									26.00			29.00
	Net wells drilled				0.50			16.04			3.29									16.54			18.26

Production

• Production in Canada increased by 2% quarter-over-quarter and decreased by 1% year-over-year. Year-to-date average production increased by 9%, primarily attributable to strong organic production growth in our Mannville condensate-rich gas resource play and production associated with our acquisition of Elkhorn Resources Inc. completed in April 2014. Q2 2015 volumes were negatively impacted by approximately 1,700 boe/d of production offline as a result of plant capacity restrictions and interruptible service curtailments on the NGTL system.  We anticipate having the majority of the curtailed volumes online during Q3 2015 with full productive capability expected to be achieved during Q4 2015.
• Cardium production averaged more than 9,300 boe/d in Q2 2015, a 5% decrease quarter-over-quarter, with some non-operated volume currently constrained due to pipeline restrictions.
• Mannville production averaged more than 5,600 boe/d in Q2 2015, a 15% increase quarter-over-quarter.  As with Cardium production, non-operated Mannville volume was constrained due to pipeline restrictions.
• Production from our southeast Saskatchewan assets averaged approximately 3,300 boe/d in Q2 2015, an increase of 15% quarter-over-quarter attributable to increased natural gas and NGL sales.  The North Portal Gas Plant was commissioned late in Q1 2015. The plant will enable the processing of approximately 5,500 mcf/d (920 boe/d) net of natural gas which was previously being flared.

Activity review

• Vermilion participated in the drilling of one (0.5 net) non-operated well during Q2 2015.

Cardium

• During Q2 2015, three (1.5 net) non-operated wells were brought on production.
• In 2015, we plan to drill or participate in seven (3.1 net) wells executed in Q1 2015, and complete, equip and tie-in an additional 8.2 net wells which were drilled in 2014.

Mannville

• During Q2 2015, we completed four (3.5 net) operated wells and brought three (3.0 net) operated wells on production. We also participated in the drilling of one (0.5 net) non-operated well and one (0.4 net) non-operated well was placed on production.
• In 2015, we expect to drill or participate in approximately 30 (17.8 net) wells and complete, equip and tie-in an additional 1.0 net well which was drilled in 2014.

Saskatchewan

• We drilled and brought on production five (4.1 net) operated Midale wells during Q1 2015, completing our 2015 drilling activity in Saskatchewan.

Financial review

				Three Months Ended									% change						Six Months Ended						% change
Canada business unit				Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
($M except as indicated)				2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
	Sales			91,284			77,884			163,261			17%			(44%)			169,168			286,441			(41%)
	Royalties			(5,768)			(8,592)			(18,240)			(33%)			(68%)			(14,360)			(30,903)			(54%)
	Transportation expense			(4,469)			(3,942)			(4,024)			13%			11%			(8,411)			(7,122)			18%
	Operating expense			(21,534)			(19,099)			(21,179)			13%			2%			(40,633)			(37,789)			8%
	General and administration			(5,510)			(4,015)			(6,560)			37%			(16%)			(9,525)			(9,428)			1%
	Fund flows from operations			54,003			42,236			113,258			28%			(52%)			96,239			201,199			(52%)
Netbacks ($/boe)
	Sales			40.59			35.81			71.56			13%			(43%)			38.24			70.55			(46%)
	Royalties			(2.56)			(3.95)			(7.99)			(35%)			(68%)			(3.25)			(7.61)			(57%)
	Transportation expense			(1.99)			(1.81)			(1.76)			10%			13%			(1.90)			(1.75)			9%
	Operating expense			(9.58)			(8.78)			(9.28)			9%			3%			(9.19)			(9.31)			(1%)
	General and administration			(2.45)			(1.85)			(2.88)			32%			(15%)			(2.15)			(2.32)			(7%)
	Fund flows from operations netback			24.01			19.42			49.65			24%			(52%)			21.75			49.56			(56%)
Reference prices
	WTI (US $/bbl)			57.94			48.63			102.99			19%			(44%)			53.29			100.84			(47%)
	Edmonton Sweet index (US $/bbl)			55.08			41.83			96.85			32%			(43%)			48.46			93.65			(48%)
	Edmonton Sweet index ($/bbl)			67.72			51.92			105.61			30%			(36%)			59.86			102.73			(42%)
	AECO ($/GJ)			2.52			2.60			4.44			(3%)			(43%)			2.56			4.93			(48%)

Sales

• The realized price for our crude oil production in Canada is directly linked to WTI but is subject to market conditions in Western Canada.  These market conditions can result in fluctuations in the pricing differential, 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.
• Sales per boe increased by 13% quarter-over-quarter as a result of a 30% increase in Edmonton Sweet index pricing in Canadian dollar terms offset by a 3% decrease in AECO pricing. This increase, coupled with relatively consistent production volumes, resulted in a 17% increase in sales.
• On a year-over-year basis, sales per boe decreased by 43% and 46% for the three and six months ended June 30, 2015, largely as the result of weakening crude oil and natural gas pricing.  For the three months ended June 30, 2015, the lower pricing was combined with consistent production volumes, resulting in a 44% decrease in sales. For the six months ended June 30, 2015, the decline in commodity prices was partially offset by a 9% increase in production, resulting in a 41% decrease in sales.

Royalties

• Royalties as a percentage of sales for Q2 2015 decreased to 6.3% as compared to Q1 2015 of 11.0% despite higher reference prices (which would typically result in higher royalty rates) due to the timing of when par prices used in the royalty calculations were set.  This timing difference resulted in lower crude oil royalty rates for Q2 2015.  In addition, an annual favorable gas cost allowance ("GCA") adjustment in Alberta resulted in gas royalties being in a recovery position for the current quarter.
• Royalties as a percentage of sales for the three and six months ended June 30, 2015 decreased to 6.3% and 8.5% versus 11.2% and 10.8% for the same periods in 2014 due to the impact of lower reference prices on the sliding scale used to determine crude oil royalty rates and the aforementioned favorable GCA adjustment.

Transportation

• Transportation expense relates to the delivery of crude oil and natural gas production to major pipelines where legal title transfers.
• Transportation expense for Q2 2015 was higher than Q1 2015 as a result of higher natural gas liquids and natural gas production.
• Transportation expense for the three and six months ended June 30, 2015 was higher than the same periods in the prior year as a result of incremental trucking costs from Vermilion's Saskatchewan properties, which were acquired in April of 2014.

Operating expense

• Operating expenses were higher for Q2 2015 versus Q1 2015 on both a dollar and per boe basis due to higher road use fees and a higher level of facilities maintenance activity in Saskatchewan.
• Operating expenses were higher on a dollar basis for the three and six months ended June 30, 2015 compared to the same periods in 2014 due to incremental operating expenses associated with Vermilion's Saskatchewan properties, acquired in Q2 2014.  This dollar increase resulting from the acquisition was largely offset by a wide range of cost reduction initiatives undertaken in response to commodity price weakness resulting in reduced operating expense on a per boe basis for year-to-date 2015.

General and administration

• General and administration expense fluctuations in Q2 2015 as compared to both Q1 2015 and Q2 2014 were a result of the timing of expenditures.
• Year-over-year, general and administration expense for the six months ended June 30, 2015 was consistent with 2014.

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						Six Months Ended						% change
					Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
France business unit					2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
Production
	Crude oil (bbls/d)				12,746			11,463			11,025			11%			16%			12,108			10,899			11%
	Natural gas (mmcf/d)				1.03			-			-			100%			100%			0.52			-			100%
	Total (boe/d)				12,917			11,463			11,025			13%			17%			12,194			10,899			12%
Inventory (mbbls)
	Opening crude oil inventory				299			197			238									197			269
	Crude oil production				1,160			1,032			1,003									2,192			1,973
	Crude oil sales				(1,119)			(930)			(1,062)									(2,049)			(2,063)
	Closing crude oil inventory				340			299			179									340			179
Production mix (% of total)
	Crude oil				99%			100%			100%									99%			100%
	Natural gas				1%			-			-									1%			-
Activity
	Capital expenditures ($M)				16,697			34,114			37,614			(51%)			(56%)			50,811			75,581			(33%)
	Acquisitions ($M)				96			-			-									96			-
	Gross wells drilled				-			4.00			2.00									4.00			4.00
	Net wells drilled				-			4.00			2.00									4.00			4.00

Production

• Quarter-over-quarter and year-over-year production growth of 13% and 17%, respectively, due to production additions from our 2015 Champotran drilling program and workovers.
• In late September 2013, the third party Lacq processing facility that processed our Vic Bilh gas production was permanently closed.  As a result, our Vic Bilh gas production was temporarily shut-in while preparations to transfer to an alternative facility were completed.  During Q2 2015, approximately 2 mmcf/d (330 boe/d) of Vic Bilh gas production was restored.

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 includes a 26-well workover program and the resumption of sales from a portion of our shut-in natural gas at Vic Bilh, which was brought on-line in Q2 2015.

Financial review

				Three Months Ended									% change						Six Months Ended						% change
France business unit				Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
($M except as indicated)				2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
	Sales			81,627			59,832			124,617			36%			(34%)			141,459			242,177			(42%)
	Royalties			(6,620)			(5,102)			(7,796)			30%			(15%)			(11,722)			(15,147)			(23%)
	Transportation expense			(3,526)			(3,011)			(5,385)			17%			(35%)			(6,537)			(10,138)			(36%)
	Operating expense			(12,102)			(10,826)			(16,550)			12%			(27%)			(22,928)			(32,970)			(30%)
	General and administration			(4,874)			(5,111)			(5,559)			(5%)			(12%)			(9,985)			(10,753)			(7%)
	Other income			-			31,775			-			(100%)			-			31,775			-			100%
	Current income taxes			(9,316)			(14,281)			(24,761)			(35%)			(62%)			(23,597)			(50,025)			(53%)
	Fund flows from operations			45,189			53,276			64,566			(15%)			(30%)			98,465			123,144			(20%)
Netbacks ($/boe)
	Sales			71.96			64.33			117.29			12%			(39%)			68.52			117.41			(42%)
	Royalties			(5.84)			(5.49)			(7.34)			6%			(20%)			(5.68)			(7.34)			(23%)
	Transportation expense			(3.11)			(3.24)			(5.07)			(4%)			(39%)			(3.17)			(4.91)			(35%)
	Operating expense			(10.67)			(11.64)			(15.58)			(8%)			(32%)			(11.11)			(15.98)			(30%)
	General and administration			(4.30)			(5.49)			(5.24)			(22%)			(18%)			(4.84)			(5.21)			(7%)
	Other income			-			34.16			-			(100%)			-			15.39			-			100%
	Current income taxes			(8.21)			(15.35)			(23.30)			(47%)			(65%)			(11.43)			(24.25)			(53%)
	Fund flows from operations netback			39.83			57.28			60.76			(30%)			(34%)			47.68			59.72			(20%)
Reference prices
	Dated Brent (US $/bbl)			61.92			53.97			109.63			15%			(44%)			57.95			108.93			(47%)
	Dated Brent ($/bbl)			76.12			66.98			119.55			14%			(36%)			71.59			119.50			(40%)

Sales

• Crude oil production in France is priced with reference to Dated Brent.
• Sales per boe increased by 12% quarter-over-quarter, consistent with a 14% increase in the Canadian dollar equivalent of the Dated Brent reference price.  This increase, coupled with a smaller inventory build in the quarter, resulted in a 36% increase in sales.
• On a year-over-year basis, sales per boe decreased by 39% and 42% for the three and six months ended June 30, 2015, respectively.  In both periods, this was consistent with a decrease in the Dated Brent reference price, and was partially offset by increases in production.  This resulted in a decrease in sales for both the three and six month periods ended June 30, 2015 of 34% and 42%, respectively.

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 revenue).
• Royalties as a percentage of sales was 8.1% and 8.3% for the three and six months ended June 30, 2015, relatively consistent with 8.5% in Q1 2015, and an increase over both comparable periods in 2014.  The year-over-year increase was due to the impact of fixed RCDM royalties coupled with lower realized pricing.

Transportation

• Transportation expense increased slightly for Q2 2015 as compared to Q1 2015 due to a higher number of shipments from the Ambès terminal during the current quarter.
• Transportation expense decreased for both the three and six months ended June 30, 2015 as compared to the same periods in 2014 due to a lower level of maintenance and project activity at the Ambès terminal coupled with cost savings associated with fewer shipments at the terminal due to the usage of larger shipping vessels.

Operating expense

• On a dollar basis, Q2 2015 operating expense was higher than Q1 2015 due to increased electricity costs and a higher level of well intervention activities.
• Operating expense on a dollar and per boe basis decreased for the three and six months ended June 30, 2015 versus the same periods in 2014 due to a number of cost reduction initiatives undertaken in response to commodity price weakness.  These cost reduction initiatives included lower costs on downhole and other activities, lower labour usage and costs, as well as savings from service contract renegotiations.
• In addition, on a year-over-year basis, operating expenses further decreased due to the favorable foreign exchange impact of the strengthening of the Canadian dollar versus the Euro and the deferral of costs following a build in crude oil inventory in the 2015 periods.

General and administration

• Fluctuations in general and administration expense for the three and six months ended June 30, 2015 versus all comparable periods was primarily the result of the favorable foreign exchange impact of a stronger Canadian dollar versus the Euro.

Other income

• In the six months ended June 30, 2015, Vermilion was awarded a judgment 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.  In addition, a 10.7% temporary surtax (as a percentage of the statutory rate) is applicable for tax year 2015 if annual revenue exceeds €250 million.  For 2015, the effective rate on current income taxes is expected to be between approximately 17% and 19%.  This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures, and other eligible in-country adjustments.
• Absent of the taxes recognized in Q1 2015 for the previously mentioned recovery of costs in France, Q2 2015 current income taxes increased compared to Q1 2015 due to increased revenues.
• Current income taxes for the three and six months ended June 30, 2015 decreased versus the comparative periods in 2014.  The decrease was the result of lower funds from operations as a result of the decline in the Dated Brent reference price.

NETHERLANDS BUSINESS UNIT

Overview

• Entered the Netherlands in 2004.
• Second largest onshore gas producer.
• Interests include 16 licenses in the northeast region, five licenses in the central region, and two offshore licenses.
• Licenses include more than 800,000 net acres of undeveloped land.
• High impact 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						Six Months Ended						% change
					Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
Netherlands business unit					2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
Production
	NGLs (bbls/d)				112			63			96			78%			17%			88			83			6%
	Natural gas (mmcf/d)				32.43			36.41			40.35			(11%)			(20%)			34.41			41.74			(18%)
	Total (boe/d)				5,517			6,132			6,822			(10%)			(19%)			5,823			7,040			(17%)
Activity
	Capital expenditures ($M)				18,885			4,333			21,513			336%			(12%)			23,218			41,631			(44%)
	Gross wells drilled				2.00			-			2.00									2.00			4.00
	Net wells drilled				1.86			-			1.43									1.86			3.29

Production

• Production decreased 10% quarter-over-quarter due to a planned major facility maintenance at our Garijp Treatment Centre which negatively impacted Q2 production by approximately 2,400 mcf/d (400 boe/d).
• Year-over-year and year-to-date production decreased 19% and 17% respectively due to 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 contributed to the decrease in production
• Production in the Netherlands is actively managed to optimize facility use and regulate declines.

Activity review

• During Q2, 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 wells are currently producing at facility-restricted rates totaling 21 mmcf/d (3,500 boe/d) net.
• Capital previously allocated to a planned third well has been redeployed to support a highly economic debottlenecking project in our Garijp Treatment Centre and associated gathering system.
• During the second half of 2015, we expect to equip and tie-in the Diever-02 discovery well drilled in 2014.

Financial review

				Three Months Ended									% change						Six Months Ended						% change
Netherlands business unit				Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
($M except as indicated)				2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
	Sales			23,913			26,818			29,881			(11%)			(20%)			50,731			71,435			(29%)
	Royalties			(1,294)			(926)			(693)			40%			87%			(2,220)			(2,901)			(23%)
	Operating expense			(5,414)			(5,826)			(6,390)			(7%)			(15%)			(11,240)			(12,432)			(10%)
	General and administration			(454)			(737)			(326)			(38%)			39%			(1,191)			(924)			29%
	Current income taxes			(2,347)			(2,388)			(1,301)			(2%)			80%			(4,735)			(5,089)			(7%)
	Fund flows from operations			14,404			16,941			21,171			(15%)			(32%)			31,345			50,089			(37%)
Netbacks ($/boe)
	Sales			47.63			48.60			48.14			(2%)			(1%)			48.13			56.06			(14%)
	Royalties			(2.58)			(1.68)			(1.12)			54%			130%			(2.11)			(2.28)			(7%)
	Operating expense			(10.78)			(10.56)			(10.29)			2%			5%			(10.66)			(9.76)			9%
	General and administration			(0.90)			(1.34)			(0.53)			(33%)			70%			(1.13)			(0.73)			55%
	Current income taxes			(4.67)			(4.33)			(2.10)			8%			122%			(4.49)			(3.99)			13%
	Fund flows from operations netback			28.70			30.69			34.10			(6%)			(16%)			29.74			39.30			(24%)
Reference prices
	TTF ($/GJ)			7.94			8.25			7.91			(4%)			-			8.10			9.02			(10%)
	TTF (€/GJ)			5.84			5.91			5.27			(1%)			11%			5.87			6.01			(2%)

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 by 2% quarter-over-quarter, consistent with a 4% decrease in the Canadian dollar equivalent TTF reference price.  This was coupled with a 10% decrease in production, resulting in an 11% decrease in sales.
• On a year-over-year basis, sales per boe declined by 1% and 14% for the three and six months ended June 30, 2015, respectively.  For the three months ended June 30, 2015, the 20% decrease in sales was entirely attributable to the decrease in production.  For the six months ended June 30, 2015, a decrease in sales per boe of 14% was consistent with a 10% decrease in the Canadian dollar equivalent of TTF, and, combined with a 17% decrease in production, resulted in a 29% decrease in sales.

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

• Operating expense on a dollar basis decreased for the three and six months ended June 30, 2015 versus all comparable periods primarily as a result of a stronger Canadian dollar versus the Euro coupled with lower facility operations expenditures due to cost reduction initiatives undertaken in response to commodity price weakness.
• However, as production in the Netherlands was lower in the current year, operating expense per boe for the three and six months ended June 30, 2015 was higher versus all comparable periods.

General and administration

• Variances in general and administration expense generally relates 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 a statutory tax rate of approximately 46%.  For 2015, the effective rate on current taxes is expected to be between approximately 12% and 14%.  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 Q2 2015 were comparable to Q1 2015.
• Current income taxes in Q2 2015 were higher than Q2 2014 as higher revenues were offset with accelerated tax deductions in the current quarter.

GERMANY BUSINESS UNIT

Overview

• Vermilion entered Germany in February 2014.
• Assets include four gas producing fields across 11 production licenses and an exploration license in surrounding fields. Our working interest is 25%.
• Total license area comprises 204,000 gross acres, of which 85% is in the exploration license.

Operational review

						Three Months Ended									% change						Six Months Ended						% change
						Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
Germany business unit						2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
Production
	Natural gas (mmcf/d)					16.18			16.80			16.13			(4%)			-			16.49			13.40			23%
	Total (boe/d)					2,696			2,801			2,689			(4%)			-			2,748			2,234			23%
Activity
	Capital expenditures ($M)					3,231			968			630			234%			413%			4,199			826			408%
	Acquisitions ($M)					-			-			-									-			172,871
	Gross wells drilled					1.00			-			-									1.00			-
	Net wells drilled					0.25			-			-									0.25			-

Production

• Q2 2015 production of 2,696 boe/d represented a decrease of 4% as compared to the prior quarter while year-over-year production was flat.  Year-to-date production increased 23% versus prior year, due to 2014 volumes only reflecting production from the acquisition's effective date of February 1, 2014.

Activity review

• Participated in the drilling of the Burgmoor Z3a sidetrack well (25% working interest), which was completed in Q2 2015.  Subsequent to the quarter, the well was tied-in and placed on production.

Financial review

				Three Months Ended									% change						Six Months Ended						% change
Germany business unit				Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
($M except as indicated)				2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
	Sales			10,626			11,395			11,097			(7%)			(4%)			22,021			20,012			10%
	Royalties			(2,238)			(1,598)			(2,284)			40%			(2%)			(3,836)			(4,086)			(6%)
	Transportation expense			(1,240)			(894)			(1,052)			39%			18%			(2,134)			(1,474)			45%
	Operating expense			(1,373)			(1,999)			(2,043)			(31%)			(33%)			(3,372)			(3,597)			(6%)
	General and administration			(1,435)			(1,608)			(830)			(11%)			73%			(3,043)			(1,398)			118%
	Current income taxes			-			-			(506)			-			(100%)			-			(1,043)			(100%)
	Fund flows from operations			4,340			5,296			4,382			(18%)			(1%)			9,636			8,414			15%
Netbacks ($/boe)
	Sales			43.31			45.21			45.36			(4%)			(5%)			44.27			49.50			(11%)
	Royalties			(9.12)			(6.34)			(9.34)			44%			(2%)			(7.71)			(10.11)			(24%)
	Transportation expense			(5.05)			(3.55)			(4.30)			42%			17%			(4.29)			(3.65)			18%
	Operating expense			(5.60)			(7.93)			(8.35)			(29%)			(33%)			(6.78)			(8.90)			(24%)
	General and administration			(5.85)			(6.38)			(3.39)			(8%)			73%			(6.12)			(3.46)			77%
	Current income taxes			-			-			(2.07)			-			(100%)			-			(2.58)			(100%)
	Fund flows from operations netback			17.69			21.01			17.91			(16%)			(1%)			19.37			20.80			(7%)
Reference prices
	TTF ($/GJ)			7.94			8.25			7.91			(4%)			-			8.10			9.02			(10%)
	TTF (€/GJ)			5.84			5.91			5.27			(1%)			11%			5.87			6.01			(2%)

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 7% decrease in sales quarter-over-quarter is due to a 4% decrease in sales per boe, consistent with the decrease in the Canadian dollar equivalent of the TTF reference price, and a 4% decrease in production.
• On a year-over-year basis, sales per boe declined by 5% and 11% for the three and six months ended June 30, 2015, respectively.  For the three months ended June 30, 2015, production remained relatively consistent, resulting in a 4% decrease in sales.  For the six months ended June 30, 2015, production increased by 23% but was partially offset by a stronger CAD versus the Euro, resulting in a 10% increase in sales.

Royalties

• Our production in Germany is subject to state and private royalties on sales after certain eligible deductions.  As a percentage of sales, royalties are expected to range from 15% to 20% in 2015.
• Q2 2015 royalties as a percentage of sales of 21.1% were higher than the 14.0% for Q1 2015 due to adjustments for prior period royalties.  Year-to-date royalties as a percentage of sales of 17.4% were lower than the 20.4% for the comparable period in 2014 as a result of lower state royalty rates for 2015.

Transportation expense

• Transportation expense in Germany relates to costs incurred to deliver natural gas from the processing facility to the customer.
• Q2 2015 transportation expense was higher than Q1 2015 and Q2 2014 due to final adjustments recorded for 2014 during the current quarter.  Year-to-date transportation expense was higher than the comparable period in 2014 due to the aforementioned adjustments and the inclusion of only 5 months of expense in 2014 due to the timing of our Germany acquisition.

Operating expense

• Operating expenses for Germany are billed monthly by the joint venture operator and primarily relate to tariffs charged for gas processing.
• Q2 2015 had lower operating expenses on a dollar and per boe basis versus both Q1 2015 and Q2 2014 due to lower levels of project activity during the current quarter.
• Operating expense for the six months ended June 30, 2015 decreased on a dollar and per boe basis versus the same period in 2014 due to the timing of the acquisition and reduced gas processing tariffs in 2015.

General and administration

• General and administration expense decreased quarter-over-quarter as a result of the timing of allocations from Vermilion's Corporate segment.

Current income taxes

• Current income taxes in Germany apply to taxable income after eligible deductions at a statutory tax rate of approximately 24%.  As a function of Germany's tax pools, 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						Six Months Ended						% change
Ireland business unit						Jun 30,			Mar 31,			Jun 30,			Q2/15 vs.			Q2/15 vs.			Jun 30,			Jun 30,			2015 vs.
($M)						2015			2015			2014			Q1/15			Q2/14			2015			2014			2014
	Transportation expense					(1,648)			(1,693)			(1,571)			(3%)			5%			(3,341)			(3,159)			6%
	General and administration					(628)			(512)			(252)			23%			149%			(1,140)			(534)			113%
	Fund flows from operations					(2,276)			(2,205)			(1,823)			3%			25%			(4,481)			(3,693)			21%
Activity
	Capital expenditures					20,267			12,955			27,221			56%			(26%)			33,222			43,457			(24%)

Activity review

• Following minor remaining compressor maintenance, operator Shell E&P Ireland Limited expects to declare all wells, facilities and transport systems ready for service by the end of August.  Prior to commencing gas production, the Irish Environmental Protection Agency ("EPA") must issue its Final Determination for the Corrib Industrial Emissions Licence ("IEL") and Ministerial Consent is required from the Department of Communications, Environment, and Natural Resources. The EPA issued its Proposed Determination for the Corrib IEL in April 2015, and following statutory consultation and review periods is expected to issue its Final Determination on the IEL on or before mid-September. We now estimate that the Ministerial Consent process will be completed, and that production will commence, in early-to-mid fourth quarter of 2015.
• Capital expenditures at Corrib total $33 million year-to-date in 2015.  We currently expect to incur an additional $30 to $35 million of capital expenditures at Corrib prior to achieving first gas in early to mid-Q4 2015.
• Production at Corrib is expected to increase over the first few months toward peak production levels estimated at approximately 58 mmcf/d (approximately 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.

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				Six Months Ended			% change
				Jun 30,		Mar 31,		Jun 30,		Q2/15 vs.	Q2/15 vs.			Jun 30,	Jun 30,		2015 vs.
Australia business unit				2015		2015		2014		Q1/15	Q2/14			2015	2014		2014
Production
	Crude oil (bbls/d)			5,865		5,672		6,483		3%	(10%)			5,769	6,795		(15%)
Inventory (mbbls)
	Opening crude oil inventory			318		37		63						37	130
	Crude oil production			534		511		590						1,044	1,230
	Crude oil sales			(696)		(230)		(464)						(925)	(1,171)
	Closing crude oil inventory			156		318		189						156	189
Activity
	Capital expenditures ($M)			6,468		6,455		10,991		-	(41%)			12,923	16,682		(23%)

Production

• Quarterly production increased 3% quarter-over-quarter and decreased 10% year-over-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 Q2 2015, efforts were largely focused on maintenance work, facilities enhancement and preparations for 2015 and 2016 drilling programs.
• We have reinstated the previously-deferred two-well sidetrack drilling program for 2015.
• Additional 2015 planned activities include ongoing facilities maintenance, enhancement, and refurbishment, as well as preparation and permitting activities in advance of our 2016 drilling program.

Financial review

		Three Months Ended				% change				Six Months Ended			% change
Australia business unit		Jun 30,	Mar 31,	Jun 30,		Q2/15 vs.	Q2/15 vs.			Jun 30,	Jun 30,		2015 vs.
($M except as indicated)		2015	2015	2014		Q1/15	Q2/14			2015	2014		2014
	Sales	56,204	19,284	58,828		191%	(4%)			75,488	148,802		(49%)
	Operating expense	(18,083)	(5,886)	(12,051)		207%	50%			(23,969)	(29,411)		(19%)
	General and administration	(1,141)	(1,454)	(1,661)		(22%)	(31%)			(2,595)	(2,867)		(9%)
	PRRT	(3,371)	(2,354)	(12,699)		43%	(73%)			(5,725)	(32,938)		(83%)
	Corporate income taxes	(5,134)	(577)	(5,689)		790%	(10%)			(5,711)	(14,530)		(61%)
	Fund flows from operations	28,475	9,013	26,728		216%	7%			37,488	69,056		(46%)
Netbacks ($/boe)
	Sales	80.87	83.80	126.87		(3%)	(36%)			81.60	127.11		(36%)
	Operating expense	(26.02)	(25.58)	(25.99)		2%	-			(25.91)	(25.12)		3%
	General and administration	(1.64)	(6.32)	(3.58)		(74%)	(54%)			(2.81)	(2.45)		15%
	PRRT	(4.85)	(10.23)	(27.39)		(53%)	(82%)			(6.19)	(28.14)		(78%)
	Corporate income taxes	(7.39)	(2.51)	(12.27)		194%	(40%)			(6.17)	(12.41)		(50%)
	Fund flows from operations netback	40.97	39.16	57.64		5%	(29%)			40.52	58.99		(31%)
Reference prices
	Dated Brent (US $/bbl)	61.92	53.97	109.63		15%	(44%)			57.95	108.93		(47%)
	Dated Brent ($/bbl)	76.12	66.98	119.55		14%	(36%)			71.59	119.50		(40%)

Sales

• Our production in Australia currently receives a premium to Dated Brent.
• During Q2 2015, inventory decreased by 162,000 bbls versus builds of 281,000 bbls and 126,000 bbls in Q1 2015 and Q2 2014, respectively.  For the six months ended June 30, 2015, inventory increased by 119,000 bbls, as compared to a build of 59,000 bbls in the comparable period in 2014.
• Sales per boe decreased 3% in Q2 2015 versus Q1 2015 despite an increase of 14% in the Canadian dollar equivalent of the Dated Brent reference price due to the timing of sales.  This was more than offset by a significant increase in sales volumes driven by the draw in inventory, resulting in a 191% increase in sales.
• On a year-over-year basis, sales per boe decreased by 36% for both the three and six months ended June 30, 2015, consistent with a decrease in the Dated Brent reference price.  For the three months ended June 30, 2015, this was almost entirely offset by a significant increase in sales volumes driven by a draw in inventory, resulting in a 4% decrease in sales.  For the six months ended June 30, 2015, a greater build in inventory led to a 49% decrease in sales.

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

• The increase in operating expense for Q2 2015 as compared to Q1 2015 and Q2 2014 was largely the result of a drawdown of inventory during the quarter versus a build in the comparable periods.  Operating expense per boe for Q2 2015 versus both Q1 2015 and Q2 2014 was largely unchanged.
• The decrease in operating expense for the year-to-date 2015 period versus 2014 was largely the result of savings from a wide range of cost reduction initiatives undertaken in response to commodity price weakness including reduced vessel usage, lower diesel consumption, and reduced staffing costs.  On a per boe basis, these cost reductions were offset by lower production volumes causing increased per barrel costs.

General and administration

• Fluctuations in general and administration expense for the three and six months versus the comparable periods was largely a result of the timing of expenditures.

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.
• For 2015, the combined corporate income tax and PRRT effective rate is expected to be between approximately 22% and 24%.  This rate 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 six months ended June 30, 2015 was lower than the comparable period in 2014.  The decrease was due to a more significant decrease in revenues in the current year as compared to capital spending.

UNITED STATES BUSINESS UNIT

Overview

• Entered the United States in September 2014.
• Interests include approximately 68,000 acres of land (98% undeveloped) in the Powder River Basin of northeastern Wyoming.
• Promising tight oil development targeting the Turner Sand at a depth of approximately 1,500 metres.

Operational and financial review

				Three Months Ended			% change
United States business unit				Jun 30,	Mar 31,		Q2/15 vs.
($M except as indicated)				2015	2015		Q1/15
	Sales			677	672		1%
	Royalties			(191)	(206)		(7%)
	Operating expense			(110)	(215)		(49%)
	General and administration			(963)	(1,080)		(11%)
	Fund flows from operations			(587)	(829)		(29%)
Netbacks ($/boe)
	Sales			60.57	48.79		24%
	Royalties			(17.08)	(14.98)		14%
	Operating expense			(9.88)	(15.61)		(37%)
	General and administration			(86.12)	(78.41)		10%
	Fund flows from operations netback			(52.51)	(60.21)		(13%)
Reference prices
	WTI (US $/bbl)			57.94	48.63		19%
	WTI ($/bbl)			71.23	60.35		18%
Production
	Crude oil (bbls/d)			123	153		(20%)
Activity
	Capital expenditures			2,744	637		331%
	Gross wells drilled			1.00	-
	Net wells drilled			1.00	-

Activity review

• Vermilion drilled the Seedy Draw North well (100% working interest) in the East Finn prospect area in Q2 2015, with completion of the well planned in Q3 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 at a combined rate of approximately 27.5% of sales.

Operating expense

• Operating expense was lower than the previous quarter due to lower fuel and salt water disposal costs.

General and administration

• General and administration expense was consistent with the prior quarter.

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					Six Months Ended
			Jun 30,	Mar 31,	Jun 30,			Jun 30,	Jun 30,
($M)			2015	2015	2014			2015	2014
General and administration			500	957	(2,574)			1,457	(6,325)
Current income taxes			(547)	(377)	(378)			(924)	(551)
Interest expense			(14,550)	(13,298)	(12,334)			(27,848)	(23,794)
Realized gain on derivatives			3,081	6,257	2,419			9,338	5,059
Realized foreign exchange (loss) gain			(2,740)	3,306	587			566	(1,454)
Realized other income			204	222	74			426	295
Fund flows from operations			(14,052)	(2,933)	(12,206)			(16,985)	(26,770)

General and administration

• The decrease in general and administration costs for the three and six months ended June 30, 2015 versus the comparable periods in 2014 is due to a decrease in staff-related expenditures, general cost saving initiatives in response to declining crude prices, and increased salary allocations to the various segments.

Current income taxes

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

Interest expense

• Interest expense increased in Q2 2015 versus Q1 2015 and Q2 2014 primarily due to the recognition of a full quarter of interest expense related to the finance lease recognized in Q1 2015. For the six months ended June 30, 2015, the increase versus the comparable period in 2014 is due to increased borrowings under our revolving credit facility, as well as the aforementioned interest on the finance lease.

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 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 Q2 2015 related primarily to amounts received on our Dated Brent, WTI, and AECO derivatives, partially offset by payments made on our foreign exchange derivatives.
• A listing of derivative positions as at June 30, 2015 is included in "Supplemental Table 2" in this MD&A.

FINANCIAL PERFORMANCE REVIEW

				Three Months Ended
				Jun 30,	Mar 31,	Dec 31,	Sep 30,	Jun 30,	Mar 31,	Dec 31,	Sep 30,
($M except per share)				2015	2015	2014	2014	2014	2014	2013	2013
Petroleum and natural gas sales				264,331	195,885	306,073	344,688	387,684	381,183	325,108	327,185
Net earnings				6,813	1,275	58,642	53,903	53,993	102,788	101,510	67,796
Net earnings per share
	Basic			0.06	0.01	0.55	0.50	0.51	1.00	1.00	0.67
	Diluted			0.06	0.01	0.54	0.50	0.50	0.99	0.98	0.66

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

($M)	Q2/15 vs. Q1/15	Q2/15 vs. Q2/14	2015 vs. 2014
Net earnings - Comparative period	1,275	53,993	156,781
Changes in:
Fund flows from operations	8,701	(86,580)	(171,148)
Equity based compensation	1,154	331	(2,237)
Unrealized gain or loss on derivative instruments	24,075	5,626	(18,279)
Unrealized foreign exchange gain or loss	9,876	28,777	1,932
Unrealized other expense	57	(308)	(315)
Accretion	(38)	237	274
Depletion and depreciation	(20,189)	(6,244)	2,251
Deferred tax	(18,098)	10,981	38,829
Net earnings - Current period	6,813	6,813	8,088

The fluctuations in net earnings 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 in Q2 2015 was lower than Q1 2015 as a result of awards that vested during Q2 2015 with higher actual performance conditions.  For the six months ended June 30, 2015, equity based compensation expense was higher versus the comparable period due to a higher number of awards outstanding.

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 six months ended June 30, 2015, we recognized an unrealized loss on derivative instruments of $15.9 million, relating primarily to our TTF, Dated Brent, and WTI swaps and collars. As at June 30, 2015, we have a net derivative asset position of $8.9 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.  As such, an appreciation in the Euro against the Canadian dollar will result in an unrealized foreign exchange gain, and vice-versa.

For the three months ended June 30, 2015, the Canadian dollar weakened versus the Euro and the US dollar, resulting in an unrealized foreign exchange gain of $5.0 million.  For the six months ended June 30, 2015, the foreign exchange gain of $0.2 million was driven by a significant weakening of the Canadian dollar against the US dollar, offset by a slight strengthening of the Canadian dollar relative to the Euro.

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.

Q2 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 Q2 2015 of $22.98 was slightly higher as compared to $21.90 and $22.45 in Q1 2015 and Q2 2014, respectively.  The increase is due to increased production from light crude oil properties in Saskatchewan, Canada which has higher per boe depletion expense, and decreased production from natural gas properties in Drayton Valley, Canada and in the Netherlands, which have lower per boe depletion expense.  On a year-over-year basis, depletion and depreciation on a per boe decreased to $22.48 per boe for the six months ended June 30, 2015, as compared to $22.78 in the comparable period in the prior year.  This decrease is primarily due to lower production in the Cardium light crude oil resource play in Canada and in Australia, which experience higher per boe amounts.

Deferred tax
Deferred tax expense 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.

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

In the current low commodity price environment, Vermilion's net debt to fund flows 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 and will manage its business accordingly.

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
				Jun 30,	Dec 31,			Jun 30,	Dec 31,
($M)				2015	2014			2015	2014
Revolving credit facility				3.0%	3.1%			1,200,077	1,014,067
Senior unsecured notes ^(1)				6.5%	6.5%			224,457	224,013
Long-term debt				3.6%	3.8%			1,424,534	1,238,080

^(1)	The senior unsecured notes, which will mature on February 10, 2016, are included in the current portion of long-term debt as at June 30, 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.  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
				Jun 30,			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				$26.5 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
							Jun 30,			Dec 31,
Financial covenant				Limit			2015			2014
Consolidated total debt to consolidated EBITDA				4.0			1.84			1.21
Consolidated total senior debt to consolidated EBITDA				3.0			1.52			0.99
Consolidated total senior debt to total capitalization				50%			35%			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 "Long-term debt", "Current portion of long-term debt", "Finance lease obligation", and "Shareholders' equity".

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

Senior Unsecured Notes
We have outstanding senior unsecured notes that are senior unsecured obligations and rank pari passu with all our other present and future 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 may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest.  The notes were initially recognized at fair value net of transaction costs and are 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
				Jun 30,			Dec 31,
($M)				2015			2014
Long-term debt				1,200,077			1,238,080
Current liabilities^(1)				479,848			365,729
Current assets				(302,023)			(338,159)
Net debt				1,377,902			1,265,650
Ratio of net debt to annualized fund flows from operations				2.8			1.6

^(1)	Includes the current portion of long-term debt, which, as at June 30, 2015, represents the senior unsecured notes that will mature on February 10, 2016.

Long term debt, including the current portion, as at June 30, 2015 increased to $1.42 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 and Ireland. 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 and weak commodity prices, the ratio of net debt to fund flows from operations increased from 1.6 times as at December 31, 2014 to 2.8 times for the six months ended June 30, 2015.

Shareholders' capital
During the six months ended June 30, 2015, we maintained monthly dividends at $0.215 per share and declared dividends which totalled $140.4 million.

The following table outlines our dividend payment history:

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

Our policy with respect to dividends is to be conservative and maintain a low ratio of dividends to fund flows from operations.  During low commodity price cycles, we will initially maintain dividends and allow the ratio to rise.  Should low commodity price cycles remain for an extended period of time, we will evaluate the necessity of changing the level of dividends, taking into consideration capital development requirements, debt levels and acquisition opportunities.  In a further step to preserve our financial flexibility and conservatively exercise our access to capital, an amendment to our existing DRIP to include a Premium Dividend™ Component was announced 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 turned off 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.  It is not currently expected that Vermilion will be required to change its dividend in 2015.

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		1,195			63,679
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		15			816
Balance as at June 30, 2015		109,806			2,087,932

As at June 30, 2015, there were approximately 1.7 million VIP awards outstanding.  As at August 6, 2015, there were approximately 110.1 million common shares issued and outstanding.

ASSET RETIREMENT OBLIGATIONS

As at June 30, 2015, asset retirement obligations were $351.3 million compared to $350.8 million as at December 31, 2014.

The slight increase in asset retirement obligations is largely attributable to accretion and additions from new wells drilled year-to-date, offset by an overall increase in the discount rates applied to the abandonment obligations.

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 June 30, 2015.

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

RISK MANAGEMENT

Vermilion is exposed to various market and operational risks.  For a detailed discussion of these risks, please see Vermilion's Annual Report for the year ended December 31, 2014.

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 Vermilion's consolidated financial statements.  Estimates are reviewed by management on an ongoing basis and as a result 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 that Vermilion operates in, the critical accounting estimates may affect one or more jurisdictions.  There have been no material changes to our critical accounting estimates used in applying accounting policies for the six months ended June 30, 2015.  Further information, including a discussion of critical accounting estimates, can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2014, available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

INTERNAL CONTROL OVER FINANCIAL REPORTING

There was no change in Vermilion's internal control over financial reporting that occurred during the period covered by this MD&A that has materially affected, or is reasonably likely to materially affect, its internal control 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 June 30, 2015										Six Months Ended June 30, 2015									Three Months Ended June 30, 2014		Six Months Ended June 30, 2014
			Oil & NGLs			Natural Gas			Total				Oil & NGLs			Natural Gas			Total			Total		Total
			$/bbl			$/mcf			$/boe				$/bbl			$/mcf			$/boe			$/boe		$/boe
Canada
Sales			59.06			2.78			40.59				54.14			2.88			38.24			71.56		70.55
Royalties			(5.31)			0.17			(2.56)				(5.59)			(0.03)			(3.25)			(7.99)		(7.61)
Transportation			(2.67)			(0.18)			(1.99)				(2.55)			(0.17)			(1.90)			(1.76)		(1.75)
Operating			(10.53)			(1.39)			(9.58)				(9.78)			(1.40)			(9.19)			(9.28)		(9.31)
Operating netback			40.55			1.38			26.46				36.22			1.28			23.90			52.53		51.88
General and administration									(2.45)										(2.15)			(2.88)		(2.32)
Fund flows from operations netback									24.01										21.75			49.65		49.56
France
Sales			72.83			1.53			71.96				68.97			1.53			68.52			117.29		117.41
Royalties			(5.92)			(0.01)			(5.84)				(5.72)			(0.01)			(5.68)			(7.34)		(7.34)
Transportation			(3.15)			-			(3.11)				(3.19)			-			(3.17)			(5.07)		(4.91)
Operating			(10.72)			(1.16)			(10.67)				(11.14)			(1.16)			(11.11)			(15.58)		(15.98)
Operating netback			53.04			0.36			52.34				48.92			0.36			48.56			89.30		89.18
General and administration									(4.30)										(4.84)			(5.24)		(5.21)
Other income									-										15.39			-		-
Current income taxes									(8.21)										(11.43)			(23.30)		(24.25)
Fund flows from operations netback									39.83										47.68			60.76		59.72
Netherlands
Sales			53.28			7.92			47.63				53.15			8.01			48.13			48.14		56.06
Royalties			-			(0.44)			(2.58)				-			(0.36)			(2.11)			(1.12)		(2.28)
Operating			-			(1.83)			(10.78)				-			(1.80)			(10.66)			(10.29)		(9.76)
Operating netback			53.28			5.65			34.27				53.15			5.85			35.36			36.73		44.02
General and administration									(0.90)										(1.13)			(0.53)		(0.73)
Current income taxes									(4.67)										(4.49)			(2.10)		(3.99)
Fund flows from operations netback									28.70										29.74			34.10		39.30
Germany
Sales			-			7.22			43.31				-			7.38			44.27			45.36		49.50
Royalties			-			(1.52)			(9.12)				-			(1.29)			(7.71)			(9.34)		(10.11)
Transportation			-			(0.84)			(5.05)				-			(0.72)			(4.29)			(4.30)		(3.65)
Operating			-			(0.93)			(5.60)				-			(1.13)			(6.78)			(8.35)		(8.90)
Operating netback			-			3.93			23.54				-			4.24			25.49			23.37		26.84
General and administration									(5.85)										(6.12)			(3.39)		(3.46)
Current income taxes									-										-			(2.07)		(2.58)
Fund flows from operations netback									17.69										19.37			17.91		20.80
Australia
Sales			80.87			-			80.87				81.60			-			81.60			126.87		127.11
Operating			(26.02)			-			(26.02)				(25.91)			-			(25.91)			(25.99)		(25.12)
PRRT^(1)			(4.85)			-			(4.85)				(6.19)			-			(6.19)			(27.39)		(28.14)
Operating netback			50.00			-			50.00				49.50			-			49.50			73.49		73.85
General and administration									(1.64)										(2.81)			(3.58)		(2.45)
Corporate income taxes									(7.39)										(6.17)			(12.27)		(12.41)
Fund flows from operations netback									40.97										40.52			57.64		58.99
United States
Sales			60.57			-			60.57				54.07			-			54.07			-		-
Royalties			(17.08)			-			(17.08)				(15.92)			-			(15.92)			-		-
Operating			(9.88)			-			(9.88)				(13.04)			-			(13.04)			-		-
Operating netback			33.61			-			33.61				25.11			-			25.11			-		-
General and administration									(86.12)										(81.87)			-		-
Fund flows from operations netback									(52.51)										(56.76)			-		-
Total Company
Sales			68.90			4.86			54.65				64.23			5.06			51.19			82.96		85.70
Realized hedging (loss) gain			(0.13)			0.33			0.64				0.26			0.38			1.04			0.52		0.56
Royalties			(4.37)			(0.25)			(3.33)				(4.73)			(0.31)			(3.62)			(6.21)		(5.91)
Transportation			(2.23)			(0.38)			(2.25)				(2.34)			(0.36)			(2.27)			(2.57)		(2.44)
Operating			(14.03)			(1.45)			(12.12)				(12.97)			(1.48)			(11.40)			(12.46)		(12.95)
PRRT^(1)			(1.09)			-			(0.70)				(1.03)			-			(0.64)			(2.72)		(3.67)
Operating netback			47.05			3.11			36.89				43.42			3.29			34.30			59.52		61.29
General and administration									(3.00)										(3.12)			(3.80)		(3.59)
Interest expense									(3.01)										(3.10)			(2.64)		(2.65)
Realized foreign exchange (loss) gain									(0.57)										0.06			0.12		(0.16)
Other income									0.04										3.58			0.02		0.03
Corporate income taxes^(1)									(3.59)										(3.89)			(6.98)		(7.94)
Fund flows from operations netback									26.76										27.83			46.24		46.98

^(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 June 30, 2015:

			Note			Volume			Strike Price(s)
Crude Oil
WTI - Collar
July 2015 - September 2015			1			250 bbl/d			60.00 - 68.60 US $
July 2015 - October 2015			1			250 bbl/d			60.00 - 72.40 US $
July 2015 - December 2015			2			750 bbl/d			75.00 - 82.60 CAD $
July 2015 - December 2015			1			250 bbl/d			61.00 - 69.75 US $
July 2015 - March 2016			3			250 bbl/d			75.00 - 83.45 CAD $
July 2015 - June 2016			4			500 bbl/d			75.50 - 85.08 CAD $
October 2015 - December 2015			3			250 bbl/d			70.00 - 82.95 CAD $
WTI - Swap
July 2015 - September 2015			5			250 bbl/d			75.71 CAD $
MSW - Fixed Price Differential
July 2015 - September 2015						250 bbl/d			WTI less 2.65 US $
Dated Brent - Collar
April 2015 - September 2015			1			250 bbl/d			60.00 - 74.15 US $
July 2015 - September 2015			1			250 bbl/d			65.00 - 75.05 US $
July 2015 - October 2015			6			250 bbl/d			65.00 - 74.40 US $
July 2015 - June 2016			7			1,000 bbl/d			80.50 - 93.49 CAD $
July 2015 - June 2016			8			500 bbl/d			64.50 - 75.48 US $
October 2015 - December 2015			9			1,000 bbl/d			79.38 - 92.45 CAD $
October 2015 - June 2016			10			250 bbl/d			82.00 - 94.55 CAD $
January 2016 - June 2016			3			250 bbl/d			84.00 - 93.70 CAD $

^(1)	The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price.
^(2)	The contracted volumes increase to 1,500 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
^(3)	The contracted volumes increase to 500 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
^(4)	The contracted volumes increase to 1,250 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
^(5)	The contract is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
^(6)	The contracted volumes increase to 500 boe/d for any monthly settlement periods above the contracted ceiling price.
^(7)	The contracted volumes increase to 2,500 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
^(8)	The contracted volumes increase to 1,000 boe/d for any monthly settlement periods above the contracted ceiling price.
^(9)	The contracted volumes increase to 2,000 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).
^(10)	The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).

			Note			Volume					Strike Price(s)
North American Natural Gas
AECO - Collar
April 2015 - October 2015						2,500 GJ/d					2.75 - 3.52 CAD $
April 2015 - December 2015						2,500 GJ/d					2.75 - 3.52 CAD $
October 2015 - December 2015						2,500 GJ/d					2.55 - 3.19 CAD $
November 2015 - March 2016						2,500 GJ/d					2.50 - 3.76 CAD $
January 2016 - December 2016						7,500 GJ/d					2.53 - 3.34 CAD $
April 2016 - October 2016						2,500 GJ/d					2.50 - 2.88 CAD $
AECO - Swap
April 2015 - October 2015			1			10,000 GJ/d					2.98 CAD $
April 2015 - December 2015			2			2,500 GJ/d					2.99 CAD $
AECO Basis - Fixed Price Differential
January 2015 - December 2015						5,000 mmbtu/d					Nymex HH less 0.68 US $
April 2015 - October 2015						7,500 mmbtu/d					Nymex HH less 0.62 US $
Nymex HH - Collar
April 2015 - October 2015						10,000 mmbtu/d					3.36 - 4.01 US $
April 2015 - December 2015						2,500 mmbtu/d					3.50 - 4.11 US $
November 2015 - March 2016			3			5,000 mmbtu/d					3.25 - 3.86 US $
European Natural Gas
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 $
TTF - Collar
January 2015 - December 2015						2,592 GJ/d					6.11 - 6.83 EUR €
April 2016 - December 2016						7,776 GJ/d					5.56 - 6.16 EUR €
TTF - Swap
January 2015 - December 2015						11,664 GJ/d					6.45 EUR €
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 - December 2015						2,592 GJ/d					6.30 EUR €
April 2015 - March 2016						5,832 GJ/d					6.18 EUR €
October 2015 - December 2015						2,592 GJ/d					5.69 EUR €
October 2015 - March 2016						2,592 GJ/d					6.64 EUR €
January 2016 - June 2016						2,592 GJ/d					6.10 EUR €
April 2016 - December 2016						2,592 GJ/d					5.91 EUR €
Electricity
AESO - Swap
January 2016 - December 2016						62.4 MWh/d					37.13 CAD $
AESO - Swap (Physical)
January 2013 - December 2015						72.0 MWh/d					53.17 CAD $
US Dollar
USD - Collar
February 2015 - December 2015						2,500,000 US $/month					1.180 - 1.223 CAD $
USD - Forward
February 2015 - December 2015						2,500,000 US $/month					1.198 CAD $

^(1)	On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 10,000 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 by an additional 2,500 GJ/d at the contracted price, for the following month.
^(3)	The contracted volumes increase to 10,000 mmbtu/d for any monthly settlement periods above the contracted ceiling price.

Supplemental Table 3: Capital Expenditures

			Three Months Ended										Six Months Ended
By classification			Jun 30,			Mar 31,			Jun 30,				Jun 30,			Jun 30,
($M)			2015			2015			2014				2015			2014
Drilling and development			90,173			174,311			117,975				264,484			286,815
Exploration and evaluation			-			-			17,098				-			44,633
Capital expenditures			90,173			174,311			135,073				264,484			331,448
Property acquisition			480			35			-				515			178,227
Corporate acquisition			-			-			381,139				-			381,139
Acquisitions			480			35			381,139				515			559,366
			Three Months Ended										Six Months Ended
By category			Jun 30,			Mar 31,			Jun 30,				Jun 30,			Jun 30,
($M)			2015			2015			2014				2015			2014
Land			1,469			742			950				2,211			5,703
Seismic			1,723			1,493			1,869				3,216			5,301
Drilling and completion			31,976			82,343			42,083				114,319			148,619
Production equipment and facilities			43,957			74,755			60,547				118,712			129,302
Recompletions			9,288			7,115			13,459				16,403			17,685
Other			1,760			7,863			16,165				9,623			24,838
Capital expenditures			90,173			174,311			135,073				264,484			331,448
Acquisitions			480			35			381,139				515			559,366
Total capital expenditures and acquisitions			90,653			174,346			516,212				264,999			890,814
			Three Months Ended										Six Months Ended
By country			Jun 30,			Mar 31,			Jun 30,				Jun 30,			Jun 30,
($M)			2015			2015			2014				2015			2014
Canada			22,265			114,884			418,294				137,149			538,001
France			16,793			34,114			37,614				50,907			75,581
Netherlands			18,885			4,333			21,513				23,218			41,631
Germany			3,231			968			630				4,199			173,697
Ireland			20,267			12,955			27,221				33,222			43,457
Australia			6,468			6,455			10,991				12,923			16,682
United States			2,744			637			-				3,381			-
Corporate			-			-			(51)				-			1,765
Total capital expenditures and acquisitions			90,653			174,346			516,212				264,999			890,814

Supplemental Table 4: Production

				Q2/15			Q1/15			Q4/14			Q3/14			Q2/14			Q1/14					Q4/13			Q3/13			Q2/13			Q1/13			Q4/12			Q3/12
Canada
	Crude oil (bbls/d)			10,182			10,893			11,384			11,469			12,676			9,437					8,719			7,969			8,885			7,966			7,983			7,322
	NGLs (bbls/d)			3,755			2,976			2,741			2,291			2,796			2,071					1,699			1,897			1,725			1,335			1,106			1,204
	Natural gas (mmcf/d)			64.66			61.78			58.36			57.07			57.59			49.53					41.43			43.40			43.69			41.04			31.41			35.54
	Total (boe/d)			24,713			24,165			23,851			23,272			25,070			19,763					17,322			17,099			17,892			16,140			14,323			14,449
	% of consolidated			48%			48%			49%			47%			49%			42%					43%			41%			42%			41%			40%			40%
France
	Crude oil (bbls/d)			12,746			11,463			11,133			11,111			11,025			10,771					11,131			11,625			10,390			10,330			9,843			9,767
	Natural gas (mmcf/d)			1.03			-			-			-			-			-					-			5.23			4.19			4.21			3.91			3.39
	Total (boe/d)			12,917			11,463			11,133			11,111			11,025			10,771					11,131			12,496			11,088			11,032			10,495			10,333
	% of consolidated			25%			23%			22%			22%			21%			23%					27%			30%			26%			29%			29%			28%
Netherlands
	NGLs (bbls/d)			112			63			81			63			96			69					62			48			50			96			70			41
	Natural gas (mmcf/d)			32.43			36.41			31.35			38.07			40.35			43.15					37.53			28.78			38.52			36.91			33.03			34.59
	Total (boe/d)			5,517			6,132			5,306			6,407			6,822			7,260					6,318			4,845			6,470			6,248			5,574			5,806
	% of consolidated			11%			12%			11%			13%			13%			16%					15%			12%			15%			16%			15%			16%
Germany
	Natural gas (mmcf/d)			16.18			16.80			17.71			15.38			16.13			10.64					-			-			-			-			-			-
	Total (boe/d)			2,696			2,801			2,952			2,563			2,689			1,773					-			-			-			-			-			-
	% of consolidated			5%			6%			6%			5%			5%			4%					-			-			-			-			-			-
Australia
	Crude oil (bbls/d)			5,865			5,672			6,134			6,567			6,483			7,110					6,189			7,070			7,363			5,287			5,873			5,958
	% of consolidated			11%			11%			12%			13%			12%			15%					15%			17%			17%			14%			16%			16%
United States
	Crude oil (bbls/d)			123			153			195			-			-			-					-			-			-			-			-			-
Consolidated
	Crude oil & NGLs (bbls/d)			32,783			31,220			31,668			31,501			33,076			29,458					27,800			28,609			28,413			25,014			24,875			24,292
	% of consolidated			63%			62%			64%			63%			63%			63%					68%			69%			66%			65%			69%			66%
	Natural gas (mmcf/d)			114.29			115.00			107.42			110.52			114.08			103.32					78.96			77.41			86.40			82.16			68.34			73.52
	% of consolidated			37%			38%			36%			37%			37%			37%					32%			31%			34%			35%			31%			34%
	Total (boe/d)			51,831			50,386			49,571			49,920			52,089			46,677					40,960			41,510			42,813			38,707			36,265			36,546
				YTD 2015			2014			2013			2012			2011			2010
Canada
	Crude oil (bbls/d)			10,535			11,248			8,387			7,659			4,701			2,778
	NGLs (bbls/d)			3,367			2,476			1,666			1,232			1,297			1,427
	Natural gas (mmcf/d)			63.23			55.67			42.39			37.50			43.38			43.91
	Total (boe/d)			24,441			23,001			17,117			15,142			13,227			11,524
	% of consolidated			48%			47%			41%			40%			38%			36%
France
	Crude oil (bbls/d)			12,108			11,011			10,873			9,952			8,110			8,347
	Natural gas (mmcf/d)			0.52			-			3.40			3.59			0.95			0.92
	Total (boe/d)			12,194			11,011			11,440			10,550			8,269			8,501
	% of consolidated			24%			22%			28%			28%			23%			26%
Netherlands
	NGLs (bbls/d)			88			77			64			67			58			35
	Natural gas (mmcf/d)			34.41			38.20			35.42			34.11			32.88			28.31
	Total (boe/d)			5,823			6,443			5,967			5,751			5,538			4,753
	% of consolidated			11%			13%			15%			15%			16%			15%
Germany
	Natural gas (mmcf/d)			16.49			14.99			-			-			-			-
	Total (boe/d)			2,748			2,498			-			-			-			-
	% of consolidated			5%			5%			-			-			-			-
Australia
	Crude oil (bbls/d)			5,769			6,571			6,481			6,360			8,168			7,354
	% of consolidated			11%			13%			16%			17%			23%			23%
United States
	Crude oil (bbls/d)			138			49			-			-			-			-
Consolidated
	Crude oil & NGLs (bbls/d)			32,005			31,432			27,471			25,270			22,334			19,941
	% of consolidated			63%			63%			67%			67%			63%			62%
	Natural gas (mmcf/d)			114.64			108.85			81.21			75.20			77.21			73.14
	% of consolidated			37%			37%			33%			33%			37%			38%
	Total (boe/d)			51,113			49,573			41,005			37,803			35,202			32,132

Supplemental Table 5: Segmented Financial Results

	Three Months Ended June 30, 2015
($M)	Canada		France		Netherlands		Germany		Ireland		Australia		United States		Corporate		Total
Drilling and development	21,881		16,697		18,885		3,231		20,267		6,468		2,744		-		90,173
Oil and gas sales to external customers	91,284		81,627		23,913		10,626		-		56,204		677		-		264,331
Royalties	(5,768)		(6,620)		(1,294)		(2,238)		-		-		(191)		-		(16,111)
Revenue from external customers	85,516		75,007		22,619		8,388		-		56,204		486		-		248,220
Transportation expense	(4,469)		(3,526)		-		(1,240)		(1,648)		-		-		-		(10,883)
Operating expense	(21,534)		(12,102)		(5,414)		(1,373)		-		(18,083)		(110)		-		(58,616)
General and administration	(5,510)		(4,874)		(454)		(1,435)		(628)		(1,141)		(963)		500		(14,505)
PRRT	-		-		-		-		-		(3,371)		-		-		(3,371)
Corporate income taxes	-		(9,316)		(2,347)		-		-		(5,134)		-		(547)		(17,344)
Interest expense	-		-		-		-		-		-		-		(14,550)		(14,550)
Realized gain on derivative instruments	-		-		-		-		-		-		-		3,081		3,081
Realized foreign exchange loss	-		-		-		-		-		-		-		(2,740)		(2,740)
Realized other income	-		-		-		-		-		-		-		204		204
Fund flows from operations	54,003		45,189		14,404		4,340		(2,276)		28,475		(587)		(14,052)		129,496
	Six Months Ended June 30, 2015
($M)	Canada		France		Netherlands		Germany		Ireland		Australia		United States		Corporate		Total
Total assets	1,931,640		854,608		211,587		163,069		856,739		233,956		18,785		158,430		4,428,814
Drilling and development	136,730		50,811		23,218		4,199		33,222		12,923		3,381		-		264,484
Oil and gas sales to external customers	169,168		141,459		50,731		22,021		-		75,488		1,349		-		460,216
Royalties	(14,360)		(11,722)		(2,220)		(3,836)		-		-		(397)		-		(32,535)
Revenue from external customers	154,808		129,737		48,511		18,185		-		75,488		952		-		427,681
Transportation expense	(8,411)		(6,537)		-		(2,134)		(3,341)		-		-		-		(20,423)
Operating expense	(40,633)		(22,928)		(11,240)		(3,372)		-		(23,969)		(325)		-		(102,467)
General and administration	(9,525)		(9,985)		(1,191)		(3,043)		(1,140)		(2,595)		(2,043)		1,457		(28,065)
PRRT	-		-		-		-		-		(5,725)		-		-		(5,725)
Corporate income taxes	-		(23,597)		(4,735)		-		-		(5,711)		-		(924)		(34,967)
Interest expense	-		-		-		-		-		-		-		(27,848)		(27,848)
Realized gain on derivative instruments	-		-		-		-		-		-		-		9,338		9,338
Realized foreign exchange gain	-		-		-		-		-		-		-		566		566
Realized other income	-		31,775		-		-		-		-		-		426		32,201
Fund flows from operations	96,239		98,465		31,345		9,636		(4,481)		37,488		(1,416)		(16,985)		250,291

ADDITIONAL AND NON-GAAP FINANCIAL MEASURES

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

Fund flows from operations:  We define fund flows from operations as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled.  Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a measure of our ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. As we have presented fund flows from operations in the "Segmented Information" note of our unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2015, we consider fund flows from operations to be an additional GAAP financial measure.

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 (an additional GAAP financial measure) and payout in order to assess our ability to generate cash and finance organic growth from our current producing assets.

Net debt:  We define net debt as the sum of long-term debt and working capital.  Management uses net debt, and the ratio of net debt to fund flows from operations, to analyze our financial position and leverage.  Please refer to the preceding "Net Debt" section for a reconciliation of the net debt non-GAAP financial measure.

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.

Netbacks: Per boe and per mcf measures used in the analysis of operational activities.

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, net dividends, payout, and diluted shares outstanding to their most directly comparable GAAP measures as presented in our financial statements:

		Three Months Ended									Six Months Ended
		Jun 30,			Mar 31,			Jun 30,			Jun 30,			Jun 30,
($M)		2015			2015			2014			2015			2014
Cash flows from operating activities		134,668			22,647			149,592			157,315			327,830
Changes in non-cash operating working capital		(6,390)			95,041			64,103			88,651			88,577
Asset retirement obligations settled		1,218			3,107			2,381			4,325			5,032
Fund flows from operations		129,496			120,795			216,076			250,291			421,439
Expenses related to Corrib		2,276			2,205			1,823			4,481			3,693
Fund flows from operations (excluding Corrib)		131,772			123,000			217,899			254,772			425,132
		Three Months Ended									Six Months Ended
		Jun 30,			Mar 31,			Jun 30,			Jun 30,			Jun 30,
($M)		2015			2015			2014			2015			2014
Dividends declared		70,976			69,390			68,710			140,366			134,717
Issuance of shares pursuant to the dividend reinvestment and Premium Dividend^TM
	plans	(42,301)			(21,378)			(19,149)			(63,679)			(38,034)
Net dividends		28,675			48,012			49,561			76,687			96,683
Drilling and development		90,173			174,311			117,975			264,484			286,815
Exploration and evaluation		-			-			17,098			-			44,633
Asset retirement obligations settled		1,218			3,107			2,381			4,325			5,032
Payout		120,066			225,430			187,015			345,496			433,163
Corrib drilling and development		(20,267)			(12,955)			(27,221)			(33,222)			(43,457)
Payout (excluding Corrib)		99,799			212,475			159,794			312,274			389,706
								As at
								Jun 30,			Mar 31,			Jun 30,
('000s of shares)								2015			2015			2014
Shares outstanding								109,806			107,718			106,620
Potential shares issuable pursuant to the VIP								2,820			3,043			2,751
Diluted shares outstanding								112,626			110,761			109,371

CONSOLIDATED BALANCE SHEETS (THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
				June 30,			December 31,
	Note			2015			2014
ASSETS
Current
Cash and cash equivalents				98,038			120,405
Accounts receivable				154,843			171,820
Crude oil inventory				20,559			9,510
Derivative instruments				11,098			23,391
Prepaid expenses				17,485			13,033
				302,023			338,159
Derivative instruments				-			1,403
Deferred taxes				163,997			154,816
Exploration and evaluation assets	3			376,051			380,621
Capital assets	2			3,586,743			3,511,092
				4,428,814			4,386,091
LIABILITIES
Current
Accounts payable and accrued liabilities				203,519			298,196
Current portion of long-term debt	5			224,457			-
Dividends payable	6			23,608			23,070
Derivative instruments				2,169			-
Income taxes payable				26,095			44,463
				479,848			365,729
Long-term debt	5			1,200,077			1,238,080
Finance lease obligation	2			25,710			-
Asset retirement obligations	4			351,291			350,753
Deferred taxes				394,806			410,183
				2,451,732			2,364,745
SHAREHOLDERS' EQUITY
Shareholders' capital	6			2,087,932			1,959,021
Contributed surplus				71,443			92,188
Accumulated other comprehensive (loss) income				(6,869)			5,722
Deficit				(175,424)			(35,585)
				1,977,082			2,021,346
				4,428,814			4,386,091

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

						Three Months Ended					Six Months Ended
						June 30,		June 30,			June 30,		June 30,
			Note			2015		2014			2015		2014
REVENUE
Petroleum and natural gas sales						264,331		387,684			460,216		768,867
Royalties						(16,111)		(29,013)			(32,535)		(53,037)
Petroleum and natural gas revenue						248,220		358,671			427,681		715,830
EXPENSES
Operating						58,616		58,213			102,467		116,199
Transportation						10,883		12,032			20,423		21,893
Equity based compensation			7			17,886		18,217			36,926		34,689
(Gain) loss on derivative instruments						(7,186)		(898)			6,527		(7,473)
Interest expense						14,550		12,334			27,848		23,794
General and administration						14,505		17,762			28,065		32,229
Foreign exchange (gain) loss						(2,291)		23,159			(752)		3,200
Other expense (income)						-		(178)			(31,736)		(145)
Accretion			4			5,713		5,950			11,388		11,662
Depletion and depreciation			2, 3			111,146		104,902			202,103		204,354
						223,822		251,493			403,259		440,402
EARNINGS BEFORE INCOME TAXES						24,398		107,178			24,422		275,428
INCOME TAXES
Deferred						(3,130)		7,851			(24,358)		14,471
Current						20,715		45,334			40,692		104,176
						17,585		53,185			16,334		118,647
NET EARNINGS						6,813		53,993			8,088		156,781
OTHER COMPREHENSIVE INCOME (LOSS)
Currency translation adjustments						27,543		(42,794)			(12,591)		2,741
COMPREHENSIVE INCOME (LOSS)						34,356		11,199			(4,503)		159,522
NET EARNINGS PER SHARE
Basic						0.06		0.51			0.07		1.51
Diluted						0.06		0.50			0.07		1.49
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)
Basic						109,319		105,577			108,421		103,936
Diluted						110,746		107,330			109,792		105,531

CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

							Three Months Ended					Six Months Ended
							June 30,		June 30,			June 30,		June 30,
				Note			2015		2014			2015		2014
OPERATING
Net earnings							6,813		53,993			8,088		156,781
Adjustments:
	Accretion			4			5,713		5,950			11,388		11,662
	Depletion and depreciation			2, 3			111,146		104,902			202,103		204,354
	Unrealized (gain) loss on derivative instruments						(4,105)		1,521			15,865		(2,414)
	Equity based compensation			7			17,886		18,217			36,926		34,689
	Unrealized foreign exchange (gain) loss						(5,031)		23,746			(186)		1,746
	Unrealized other expense (income)						204		(104)			465		150
	Deferred taxes						(3,130)		7,851			(24,358)		14,471
Asset retirement obligations settled				4			(1,218)		(2,381)			(4,325)		(5,032)
Changes in non-cash operating working capital							6,390		(64,103)			(88,651)		(88,577)
Cash flows from operating activities							134,668		149,592			157,315		327,830
INVESTING
Drilling and development				2			(90,173)		(117,975)			(264,484)		(286,815)
Exploration and evaluation				3			-		(17,098)			-		(44,633)
Property acquisitions				2, 3			(480)		-			(515)		(178,227)
Corporate acquisitions, net of cash acquired							-		(176,179)			-		(176,179)
Changes in non-cash investing working capital							(39,305)		(24,010)			(27,162)		15,463
Cash flows used in investing activities							(129,958)		(335,262)			(292,161)		(670,391)
FINANCING
Increase in long-term debt							32,947		255,727			187,861		205,727
Cash dividends							(28,226)		(48,665)			(76,149)		(94,185)
Cash flows from financing activities							4,721		207,062			111,712		111,542
Foreign exchange gain (loss) on cash held in foreign currencies							415		(7,232)			767		6,957
Net change in cash and cash equivalents							9,846		14,160			(22,367)		(224,062)
Cash and cash equivalents, beginning of period							88,192		151,337			120,405		389,559
Cash and cash equivalents, end of period							98,038		165,497			98,038		165,497
Supplementary information for operating activities - cash payments
	Interest paid						12,510		11,721			30,755		25,815
	Income taxes paid (refunded)						(11,685)		56,486			58,828		77,560

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

												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						-			-			-			156,781			156,781
Currency translation adjustments						-			-			2,741			-			2,741
Equity based compensation expense						-			33,968			-			-			33,968
Dividends declared			6			-			-			-			(134,717)			(134,717)
Shares issued pursuant to the dividend reinvestment plan			6			38,034			-			-			-			38,034
Shares issued pursuant to corporate acquisition						204,960			-			-			-			204,960
Modification of equity based awards						-			(2,395)			-			-			(2,395)
Vesting of equity based awards			6, 7			47,657			(47,657)			-			-			-
Share-settled dividends on vested equity based awards			6, 7			7,519			-			-			(7,519)			-
Shares issued pursuant to the bonus plan			6			721			-			-			-			721
Balances as at June 30, 2014						1,917,334			59,343			49,883			(10,092)			2,016,468
												Accumulated
												Other						Total
						Shareholders'			Contributed			Comprehensive						Shareholders'
			Note			Capital			Surplus			Income (Loss)			Deficit			Equity
Balances as at January 1, 2015						1,959,021			92,188			5,722			(35,585)			2,021,346
Net earnings						-			-			-			8,088			8,088
Currency translation adjustments						-			-			(12,591)			-			(12,591)
Equity based compensation expense			7			-			36,110			-			-			36,110
Dividends declared			6			-			-			-			(140,366)			(140,366)
Shares issued pursuant to the dividend reinvestment and Premium Dividend^TM plans			6			63,679			-			-			-			63,679
Vesting of equity based awards			6, 7			56,855			(56,855)			-			-			-
Share-settled dividends on vested equity based awards			6, 7			7,561			-			-			(7,561)			-
Shares issued pursuant to the employee savings and bonus plans			6			816			-			-			-			816
Balances as at June 30, 2015						2,087,932			71,443			(6,869)			(175,424)			1,977,082

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 (loss) income
Represents the cumulative income and expenses which are not recorded immediately in net earnings and are accumulated until an event triggers recognition in net earnings.  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 less distributed earnings of Vermilion Energy Inc.

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2015 AND 2014
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS, UNAUDITED)

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 condensed consolidated interim financial statements are in compliance with IAS 34, "Interim financial reporting" and have been prepared using the same accounting policies and methods of computation as Vermilion's consolidated financial statements for the year ended December 31, 2014.

These condensed consolidated interim financial statements should be read in conjunction with Vermilion's consolidated financial statements for the year ended December 31, 2014, which are contained within Vermilion's Annual Report for the year ended December 31, 2014 and are available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

These condensed consolidated interim financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on August 6, 2015.

2. 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			263,466			1,018			264,484
Property acquisitions			515			-			515
Changes in estimate for asset retirement obligations			(5,773)			-			(5,773)
Depletion and depreciation			(201,193)			(2,335)			(203,528)
Recognition of finance lease obligation			31,028			-			31,028
Effect of movements in foreign exchange rates			(11,065)			(10)			(11,075)
Balance at June 30, 2015			3,568,173			18,570			3,586,743

As part of the Elkhorn acquisition in April of 2014, Vermilion assumed an agreement for the construction and use of a solution gas facility which was under construction at the time of acquisition. The substance of the arrangement has been determined to be a lease and has been classified as a finance lease.  The carrying amount of the asset and liability at the commencement date in the first quarter of 2015 was $31.0 million, with the liability being apportioned between current ($3.9 million) and long-term ($27.1 million).

3. 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						(21)
Depreciation						(4,117)
Effect of movements in foreign exchange rates						(432)
Balance at June 30, 2015						376,051

4. 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					3,395
Obligations settled					(4,325)
Accretion					11,388
Changes in discount rates					(9,189)
Effect of movements in foreign exchange rates					(731)
Balance at June 30, 2015					351,291

5. LONG-TERM DEBT

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

					As at
($M)					June 30, 2015			Dec 31, 2014
Revolving credit facility					1,200,077			1,014,067
Senior unsecured notes ^(1)					224,457			224,013
Long-term debt					1,424,534			1,238,080

^(1)	The senior unsecured notes, which will mature on February 10, 2016, are included in the current portion of long-term debt as at June 30, 2015.

Revolving Credit Facility

At June 30, 2015, Vermilion had in place a bank revolving credit facility totalling $2 billion, of which approximately $1.20 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 six months ended June 30, 2015, the interest rate on the revolving credit facility was approximately 3.0% (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 $26.5 million as at June 30, 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 bank borrowings (defined 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 "Long-term debt", "Current portion of long-term debt", "Finance lease obligation", and "Shareholders' equity" on the balance sheet) of less than 50%.

As at June 30, 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 will mature on February 10, 2016.  As direct senior unsecured obligations of Vermilion, the notes rank pari passu with all other present and future unsecured and unsubordinated indebtedness of the Company.  Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest.  The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

6. 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				1,195				63,679
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				15				816
Balance as at June 30, 2015				109,806				2,087,932

Dividends declared to shareholders for the six months ended June 30, 2015 were $140.4 million (2014 - $134.7 million).

Subsequent to the end of the period and prior to the condensed consolidated interim financial statements being authorized for issue on August 6, 2015, Vermilion declared dividends totalling $23.7 million or $0.215 per share.

7. EQUITY BASED COMPENSATION

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

				Six Months				Full Year
Number of Awards ('000s)				2015				2014
Opening balance				1,775				1,665
Granted				585				707
Vested				(587)				(515)
Modified				-				(21)
Forfeited				(44)				(61)
Closing balance				1,729				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.

8. 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.

		Three Months Ended June 30, 2015
($M)		Canada			France			Netherlands			Germany			Ireland			Australia			United States			Corporate			Total
Drilling and development		21,881			16,697			18,885			3,231			20,267			6,468			2,744			-			90,173
Oil and gas sales to external customers		91,284			81,627			23,913			10,626			-			56,204			677			-			264,331
Royalties		(5,768)			(6,620)			(1,294)			(2,238)			-			-			(191)			-			(16,111)
Revenue from external customers		85,516			75,007			22,619			8,388			-			56,204			486			-			248,220
Transportation expense		(4,469)			(3,526)			-			(1,240)			(1,648)			-			-			-			(10,883)
Operating expense		(21,534)			(12,102)			(5,414)			(1,373)			-			(18,083)			(110)			-			(58,616)
General and administration		(5,510)			(4,874)			(454)			(1,435)			(628)			(1,141)			(963)			500			(14,505)
PRRT		-			-			-			-			-			(3,371)			-			-			(3,371)
Corporate income taxes		-			(9,316)			(2,347)			-			-			(5,134)			-			(547)			(17,344)
Interest expense		-			-			-			-			-			-			-			(14,550)			(14,550)
Realized gain on derivative instruments		-			-			-			-			-			-			-			3,081			3,081
Realized foreign exchange loss		-			-			-			-			-			-			-			(2,740)			(2,740)
Realized other income		-			-			-			-			-			-			-			204			204
Fund flows from operations		54,003			45,189			14,404			4,340			(2,276)			28,475			(587)			(14,052)			129,496
		Three Months Ended June 30, 2014
($M)		Canada			France			Netherlands			Germany			Ireland			Australia			United States			Corporate			Total
Drilling and development		26,071			34,828			18,234			630			27,221			10,991			-			-			117,975
Exploration and evaluation		10,897			2,786			3,279			-			-			-			-			136			17,098
Oil and gas sales to external customers		163,261			124,617			29,881			11,097			-			58,828			-			-			387,684
Royalties		(18,240)			(7,796)			(693)			(2,284)			-			-			-			-			(29,013)
Revenue from external customers		145,021			116,821			29,188			8,813			-			58,828			-			-			358,671
Transportation expense		(4,024)			(5,385)			-			(1,052)			(1,571)			-			-			-			(12,032)
Operating expense		(21,179)			(16,550)			(6,390)			(2,043)			-			(12,051)			-			-			(58,213)
General and administration		(6,560)			(5,559)			(326)			(830)			(252)			(1,661)			-			(2,574)			(17,762)
PRRT		-			-			-			-			-			(12,699)			-			-			(12,699)
Corporate income taxes		-			(24,761)			(1,301)			(506)			-			(5,689)			-			(378)			(32,635)
Interest expense		-			-			-			-			-			-			-			(12,334)			(12,334)
Realized gain on derivative instruments		-			-			-			-			-			-			-			2,419			2,419
Realized foreign exchange gain		-			-			-			-			-			-			-			587			587
Realized other income		-			-			-			-			-			-			-			74			74
Fund flows from operations		113,258			64,566			21,171			4,382			(1,823)			26,728			-			(12,206)			216,076
		Six Months Ended June 30, 2015
($M)		Canada			France			Netherlands			Germany			Ireland			Australia			United States			Corporate			Total
Total assets		1,931,640			854,608			211,587			163,069			856,739			233,956			18,785			158,430			4,428,814
Drilling and development		136,730			50,811			23,218			4,199			33,222			12,923			3,381			-			264,484
Oil and gas sales to external customers		169,168			141,459			50,731			22,021			-			75,488			1,349			-			460,216
Royalties		(14,360)			(11,722)			(2,220)			(3,836)			-			-			(397)			-			(32,535)
Revenue from external customers		154,808			129,737			48,511			18,185			-			75,488			952			-			427,681
Transportation expense		(8,411)			(6,537)			-			(2,134)			(3,341)			-			-			-			(20,423)
Operating expense		(40,633)			(22,928)			(11,240)			(3,372)			-			(23,969)			(325)			-			(102,467)
General and administration		(9,525)			(9,985)			(1,191)			(3,043)			(1,140)			(2,595)			(2,043)			1,457			(28,065)
PRRT		-			-			-			-			-			(5,725)			-			-			(5,725)
Corporate income taxes		-			(23,597)			(4,735)			-			-			(5,711)			-			(924)			(34,967)
Interest expense		-			-			-			-			-			-			-			(27,848)			(27,848)
Realized gain on derivative instruments		-			-			-			-			-			-			-			9,338			9,338
Realized foreign exchange gain		-			-			-			-			-			-			-			566			566
Realized other income		-			31,775			-			-			-			-			-			426			32,201
Fund flows from operations		96,239			98,465			31,345			9,636			(4,481)			37,488			(1,416)			(16,985)			250,291
		Six Months Ended June 30, 2014
($M)		Canada			France			Netherlands			Germany			Ireland			Australia			United States			Corporate			Total
Total assets		1,854,501			916,712			235,723			174,735			799,394			277,624			-			125,726			4,384,415
Drilling and development		127,744			64,681			33,425			826			43,457			16,682			-			-			286,815
Exploration and evaluation		24,163			10,900			8,206			-			-			-			-			1,364			44,633
Oil and gas sales to external customers		286,441			242,177			71,435			20,012			-			148,802			-			-			768,867
Royalties		(30,903)			(15,147)			(2,901)			(4,086)			-			-			-			-			(53,037)
Revenue from external customers		255,538			227,030			68,534			15,926			-			148,802			-			-			715,830
Transportation expense		(7,122)			(10,138)			-			(1,474)			(3,159)			-			-			-			(21,893)
Operating expense		(37,789)			(32,970)			(12,432)			(3,597)			-			(29,411)			-			-			(116,199)
General and administration		(9,428)			(10,753)			(924)			(1,398)			(534)			(2,867)			-			(6,325)			(32,229)
PRRT		-			-			-			-			-			(32,938)			-			-			(32,938)
Corporate income taxes		-			(50,025)			(5,089)			(1,043)			-			(14,530)			-			(551)			(71,238)
Interest expense		-			-			-			-			-			-			-			(23,794)			(23,794)
Realized gain on derivative instruments		-			-			-			-			-			-			-			5,059			5,059
Realized foreign exchange loss		-			-			-			-			-			-			-			(1,454)			(1,454)
Realized other income		-			-			-			-			-			-			-			295			295
Fund flows from operations		201,199			123,144			50,089			8,414			(3,693)			69,056			-			(26,770)			421,439

Reconciliation of fund flows from operations to net earnings

				Three Months Ended						Six Months Ended
				June 30,			June 30,			June 30,			June 30,
($M)				2015			2014			2015			2014
Fund flows from operations				129,496			216,076			250,291			421,439
Equity based compensation				(17,886)			(18,217)			(36,926)			(34,689)
Unrealized gain (loss) on derivative instruments				4,105			(1,521)			(15,865)			2,414
Unrealized foreign exchange gain (loss)				5,031			(23,746)			186			(1,746)
Unrealized other (expense) income				(204)			104			(465)			(150)
Accretion				(5,713)			(5,950)			(11,388)			(11,662)
Depletion and depreciation				(111,146)			(104,902)			(202,103)			(204,354)
Deferred taxes				3,130			(7,851)			24,358			(14,471)
Net earnings				6,813			53,993			8,088			156,781

9. CAPITAL DISCLOSURES

			Three Months Ended						Six Months Ended
($M except as indicated)			June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014
Long-term debt			1,200,077			1,198,866			1,200,077			1,198,866
Current liabilities^(1)			479,848			377,710			479,848			377,710
Current assets			(302,023)			(407,578)			(302,023)			(407,578)
Net debt [1]			1,377,902			1,168,998			1,377,902			1,168,998
Cash flows from operating activities			134,668			149,592			157,315			327,830
Changes in non-cash operating working capital			(6,390)			64,103			88,651			88,577
Asset retirement obligations settled			1,218			2,381			4,325			5,032
Fund flows from operations			129,496			216,076			250,291			421,439
Annualized fund flows from operations [2]			517,984			864,304			500,582			842,878
Ratio of net debt to annualized fund flows from operations ([1] ÷ [2])			2.7			1.4			2.8			1.4

^(1)	Includes the current portion of long-term debt, which, as at June 30, 2015, represents the senior unsecured notes that will mature on February 10, 2016.

Long-term debt, including the current portion, as at June 30, 2015 increased to $1.42 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 six months ended June 30, 2015 were lower due to weakening crude oil and North American natural gas prices.  The increase in long-term debt resulted in an increase in net debt from $1.27 billion to $1.38 billion.

Due to this increase in net debt as well as the lower commodity price environment, lower sales volumes, and the aforementioned capital expenditures, the ratio of net debt to fund flows from operations increased to 2.8 for the six months ended June 30, 2015.

10. FINANCIAL INSTRUMENTS

Classification of Financial Instruments

The following table summarizes information relating to Vermilion's financial instruments as at June 30, 2015 and December 31, 2014:

As at Jun 30, 2015

As at Dec 31, 2014

Class of financial instrument

Consolidated balance sheet caption

Accounting designation

Related caption on Statement of Net Earnings

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

98,038

98,038

120,405

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

154,843

154,843

171,820

171,820

Not applicable

Derivative assets

Derivative instruments

HFT

(Gain) loss on derivative instruments

11,098

11,098

24,794

24,794

Level 2

Derivative liabilities

Derivative instruments

HFT

(Gain) loss on derivative instruments

(2,169)

(2,169)

-

-

Level 2

Payables

Accounts payable and accrued liabilities

OTH

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

(227,127)

(227,127)

(321,266)

(321,266)

Not applicable

Dividends payable

Long-term debt

Long-term debt

OTH

Interest expense

(1,424,534)

(1,425,921)

(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.

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.

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 using the effective interest method.  Foreign exchange gains and losses are recognized in net earnings.

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

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 six months ended June 30, 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			June 30, 2015
Currency risk - Euro to Canadian			Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates			(2,390)
			Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates			2,390
Currency risk - US $ to Canadian			Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates			(5,147)
			Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates			5,147
Commodity price risk			Increase in relevant oil reference price within option pricing models used to determine the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates			(1,742)
			Decrease in relevant oil reference price within option pricing models used to determine the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates			1,888
			Increase in relevant TTF reference price within option pricing models used to determine the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates			(8,404)
			Decrease in relevant TTF reference price within option pricing models used to determine the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates			8,399
Interest rate risk			Increase in average Canadian prime interest rate by 100 basis points during the relevant periods			(5,506)
			Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods			5,506

11. 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.

Lorenzo Donadeo, CEO;
Anthony Marino, President & COO;
Curtis W. Hicks, C.A., Executive VP & CFO; and/or
Dean Morrison, Director Investor Relations
TEL [phone]
IR TOLL FREE 1-866-895-8101
[email protected]
www.vermilionenergy.com