2014-05-02 | TSX:VET | Press Release

CALGARY, May 2, 2014 /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 months ended March 31, 2014.

HIGHLIGHTS

Achieved average production of 46,677 boe/d during the first quarter of 2014, an increase of 14% as compared to 40,960 boe/d in the prior quarter and 21% compared to 38,707 boe/d in the first quarter of 2013. The increase versus the prior quarter was largely attributable to robust performance from our Mannville condensate-rich natural gas drilling program and continued Cardium related additions in Canada, strong operational performance in the Netherlands and Australia, as well as the addition of volumes related to our German acquisition. The year-over-year increase was attributable to strong growth in Canada, the Netherlands and Australia, in addition to incremental volumes associated with our October 2013 acquisition in the Netherlands and the previously mentioned German acquisition.
Based on the strength of operations during the first quarter of 2014, we are increasing our full-year 2014 production guidance from the current range of 47,500-48,500 boe/d to 48,000-49,000 boe/d.
Generated fund flows from operations⁽¹⁾ in the first quarter of 2014 of $205.4 million ($2.01/basic share), an increase of more than 25% as compared to $163.7 million ($1.61/basic share) in the prior quarter and $163.6 million ($1.65/basic share) in the first quarter of 2013. The increase was primarily attributable to significantly higher consolidated sales volumes. The quarter-over-quarter increase was further attributable to meaningfully improved pricing in Canada for both oil and gas related production, partially offset by moderately weaker realized pricing for production in the Netherlands.
We continued to benefit from our diversified commodity production mix in the first quarter of 2014. During the first quarter, the Dated Brent (Brent) crude index continued to trade at an average premium of US$9.54/boe above the West Texas Intermediate (WTI) index and US$17.79/boe above Edmonton Sweet index pricing. In addition, our exposure to Canadian natural gas enabled us to take advantage of a 62% increase in AECO natural gas pricing during the quarter. While Title Transfer Facility (TTF) index pricing softened modestly quarter-over-quarter, it remained strong relative to North American natural gas prices. Our European gas production, which is priced against TTF, received an average realized price of $10.29/mcf ($9.75/GJ).
Continued devaluation of the Canadian dollar further contributed to growth in fund flows from operations, due to its positive impact on our U.S. dollar and Euro denominated commodity exposures. This contributed to a quarter-over-quarter increase in our realized consolidated crude and NGLs price of 5.3% and a 9.6% increase in our realized consolidated natural gas price, as expressed in Canadian dollars.
While devaluation of the Canadian dollar results in a positive, outsized impact on fund flows from operations, thereby improving our overall payout ratio, it increases our foreign denominated capital expenditures in Canadian dollar terms. To-date in 2014, devaluation of the Canadian dollar has translated to an increase in actual and anticipated capital expenditures for full-year 2014, as measured in Canadian dollars, of approximately $30 million. Combined with an additional $15 million of drilling-related spending, we are now forecasting full-year 2014 exploration and development ("E&D") capital expenditures of approximately $635 million (inclusive of anticipated E&D capital spending attributable to our acquisition of Elkhorn Resources Inc.) as compared to previous guidance of $590 million.
Effective February, 2014, we acquired a 25% contractual participation interest in a four-partner consortium in Germany. The acquisition enables us to participate in the exploration, development, production and transportation of natural gas from the assets, which include four gas producing fields across 11 production licenses. The acquisition is expected to contribute approximately 2,300 boe/d of production in 2014. In addition to the production licenses, a surrounding exploration license was also acquired pursuant to the acquisition. The exploration and production licenses comprise 207,000 gross acres, of which 85% is in the exploration license.
On March 18, 2014, we announced that we had entered into an arrangement agreement to acquire Elkhorn Resources Inc., a private southeast Saskatchewan producer. On April 29, 2014, we announced completion of the acquisition for total consideration of $427 million. Total consideration comprised the assumption of an estimated $42 million of debt, $180 million of cash, and the issuance of 2.8 million common shares of Vermilion valued at approximately $205 million (based on the closing price per Vermilion common share of $72.50 on the Toronto Stock Exchange on April 29, 2014). The assets consist of high netback, light oil producing assets in the Northgate region of southeast Saskatchewan and include approximately 57,000 net acres of land (approximately 80% undeveloped), seven oil batteries, and preferential access to 50% or greater capacity at a solution gas facility that is currently under construction. Production from the assets is projected to average approximately 3,750 boe/d (97% crude oil) during 2014.
In Ireland, Corrib tunneling operations are approximately 95% completed, with approximately 300 metres of tunneling remaining. Based on the current deterministic schedule for remaining construction and commissioning activities, we anticipate first gas from Corrib in approximately mid-2015. Peak production at Corrib is estimated at approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.
In 2014, we are celebrating our 20^th Anniversary as a publicly traded company. This has been a rewarding period of growth and achievement for our company, and we are proud of our progress to date. Most importantly, we are honored to have provided our shareholders with a compound average total return including dividends, as of April 30, 2014, of 36.6% per annum since our inception. As we look forward, with the anticipated growth of our fund flows from operations in the current commodity environment, the continued strength of our operations, and our extensive opportunity base, we will redouble our efforts to provide continued strong operational and financial performance, and a reliable and growing dividend stream to investors.
In keeping with our objective of providing reliable and growing dividends, we increased our monthly cash dividend by 7.5% to $0.215 per share ($2.58 per year), effective for the January dividend that was paid on February 15, 2014.
As previously announced, we amended our Dividend Reinvestment Plan ("DRIP") to decrease the amount of additional shares participants in the DRIP are eligible to receive to 3% of their cash dividends, previously 5%. All other provisions of our DRIP are unchanged. The amendment is effective for the April dividend payable on May 15, 2014. The record date for the April dividend was April 30, 2014.

⁽¹⁾	Additional GAAP Financial Measure. Please see the "Additional and Non-GAAP Financial Measures" section of Management's Discussion and Analysis.

ORGANIZATIONAL UPDATE

Vermilion is pleased to announce the appointment of Michael Kaluza to the position of Vice President, Canada Business Unit, effective May 1, 2014. This appointment is in consideration of Mr. Kaluza's continued contribution to the strong operational performance and growth of the Canadian Business Unit. Mr. Kaluza joined Vermilion in February, 2013 as Director, Canada Business Unit. Mr. Kaluza has over 30 years of operations and executive management experience, and has a Bachelor of Science Petroleum Engineering (Honors) from Montana College of Mineral, Science and Technology (1985).

ANNUAL GENERAL MEETING WEBCAST

As Vermilion's Annual General Shareholders Meeting is being held today, May 2, 2014 at 10:00 AM MST at the Metropolitan Centre, 333 - 4th Avenue S.W., Calgary, Alberta, there will not be a first quarter conference call, however, a presentation will be given by Mr. Lorenzo Donadeo, Chief Executive Officer, concluding the formal business portion of the meeting.

Please visit http://event.on24.com/r.htm?e=767750&s=1&k=C4F147D23B8BF55755DD4BEA2DAA9D3F or Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm and click on webcast under the upcoming events to view the webcast which will commence at approximately 10:15 AM MST.

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 strength 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 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 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

bbl(s)		barrel(s)
mbbls		thousand barrels
bbls/d		barrels per day
mcf		thousand cubic feet
mmcf		million cubic feet
bcf		billion cubic feet
mcf/d		thousand cubic feet per day
mmcf/d		million cubic feet per day
GJ		gigajoules
MWh		megawatt hour
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)
mboe		thousand barrel of oil equivalent
mmboe		million barrel of oil equivalent
boe/d		barrel of oil equivalent per day
NGLs		natural gas liquids
WTI		West Texas Intermediate, the reference price paid for crude oil of standard grade in U.S. dollars at Cushing, Oklahoma
AECO		the daily average benchmark price for natural gas at the AECO 'C' hub in southeast Alberta
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
$M		thousand dollars
$MM		million dollars
PRRT		Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia

HIGHLIGHTS

		Three Months Ended
($M except as indicated)		Mar 31,	Dec 31,	Mar 31,
Financial		2014	2013	2013
Petroleum and natural gas sales		381,183	325,108	309,576
Fund flows from operations⁽¹⁾		205,363	163,660	163,629
	Fund flows from operations ($/basic share)	2.01	1.61	1.65
	Fund flows from operations ($/diluted share)	1.97	1.58	1.61
Net earnings		102,788	101,510	52,137
	Net earnings ($/basic share)	1.00	1.00	0.53
Capital expenditures		196,375	148,478	180,469
Acquisitions		178,227	29,103	-
Asset retirement obligations settled		2,651	5,426	1,388
Cash dividends ($/share)		0.645	0.600	0.600
Dividends declared		66,007	61,208	59,612
	% of fund flows from operations	32%	37%	36%
Net dividends⁽¹⁾		47,122	42,433	44,080
	% of fund flows from operations	23%	26%	27%
Payout⁽¹⁾		246,148	196,337	225,937
	% of fund flows from operations	120%	120%	138%
	% of fund flows from operations (excluding the Corrib project)	111%	111%	127%
Net debt⁽¹⁾		966,310	749,685	744,762
Ratio of net debt to annualized fund flows from operations⁽¹⁾		1.2	1.1	1.1
Operational
Production
	Crude oil (bbls/d)	27,318	26,039	23,583
	NGLs (bbls/d)	2,140	1,761	1,431
	Natural gas (mmcf/d)	103.32	78.96	82.16
	Total (boe/d)	46,677	40,960	38,707
Average realized prices
	Crude oil and NGLs ($/bbl)	111.62	106.00	103.98
	Natural gas ($/mcf)	7.99	7.29	6.77
Production mix (% of production)
	% priced with reference to WTI	25%	25%	24%
	% priced with reference to AECO	17%	17%	18%
	% priced with reference to TTF	19%	15%	18%
	% priced with reference to Dated Brent	39%	43%	40%
Netbacks ($/boe)⁽¹⁾
	Operating netback	63.20	61.35	59.18
	Fund flows from operations netback	47.76	43.32	43.89
	Operating expenses	13.49	12.74	14.10
Average reference prices
	WTI (US $/bbl)	98.68	97.46	94.37
	Edmonton Sweet index (US $/bbl)	90.43	82.53	87.42
	Dated Brent (US $/bbl)	108.22	109.27	112.55
	AECO ($/GJ)	5.42	3.35	3.03
	TTF ($/GJ)	10.19	10.65	10.40
Average foreign currency exchange rates
	CDN $/US $	1.10	1.05	1.01
	CDN $/Euro	1.51	1.43	1.33
Share information ('000s)
Shares outstanding - basic		102,453	102,123	99,462
Shares outstanding - diluted⁽¹⁾		105,167	104,869	102,380
Weighted average shares outstanding - basic		102,278	101,961	99,301
Weighted average shares outstanding - diluted⁽¹⁾		104,171	103,426	101,349

⁽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.

MESSAGE TO SHAREHOLDERS

In 2014, we are celebrating Vermilion's 20^th anniversary as a publicly traded company. It has been a demanding, but also a tremendously rewarding, time to be a publicly traded oil and gas company in Canada. During the last 20 years, the Canadian oil and gas industry has encountered numerous challenges and we are particularly proud of our demonstrated ability to navigate those challenges to the benefit of our shareholders. In spite of the evolutionary changes our Company has undertaken over the years to respond to those challenges, the one thing that has remained constant, since our inception, is our commitment to stewarding our Company in the best interests of our shareholders. We are pleased that our efforts have been both recognized and supported by our shareholders, resulting in a compound average total return including dividends, as of April 30, 2014, of 36.6% per annum since inception. We are also proud of the consistency of those returns for our shareholders. Over the last one, three, five, ten and 15 calendar-year periods, we have reliably delivered double-digit compound average total returns of 24.6%, 14.5%, 24.0%, 18.6% and 25.5%, respectively.

Perhaps more important to both our current and prospective shareholders, we currently believe Vermilion is better situated for continued growth and success that at any other time in our history. With the anticipated growth of fund flows from operations⁽¹⁾, the continued strength of our operations and our expansive and growing opportunity base, we remain confident that we are positioned to deliver continued strong operational and financial performance in the future, while continuing to provide a reliable and growing dividend stream to our shareholders.

While we are confident that the assets in our current portfolio contain significant opportunity for growth for years to come, we also find ourselves uniquely positioned to advantageously grow and further diversify our opportunity base through potential acquisition activity in both Canadian and international markets. In Canada, we are faced with an over-supplied asset market with few well-capitalized acquirers. Volatile commodity pricing, rising capital costs and limited access to capital have forced many Canadian oil and gas companies to place quality assets on the market in hopes of repositioning their businesses. With Vermilion's access to relatively low cost capital, a conservative balance sheet with significant borrowing capacity, and significant near-term free cash flow⁽¹⁾ growth on the horizon with Corrib slated to come on production in mid-2015, we are uniquely positioned to compete and transact should suitable opportunities arise. We believe we are similarly positioned in global markets. While international asset markets remain substantially less liquid than in Canada, we find ourselves well-positioned and facing limited competition for assets that may come available in our selective regions of interest.

Diversification across our product mix has been one of the keys to our success and the consistency of our performance since we first entered France in 1997. During the first quarter, we remained advantaged by our balanced exposure to a diversified portfolio of commodities and pricing dynamics. Over and above the positive price differentials we received for our Dated Brent-based crude and European gas production, we also benefited from the continued devaluation of the Canadian dollar against both the U.S. dollar and the Euro. Our crude volumes in France and Australia continue to attract a meaningful consolidated premium to the Dated Brent crude index, which in turn has traded persistently above the West Texas Intermediate (WTI) index. With the added benefit of the weak Canadian dollar, our French and Australian crude volumes realized a consolidated average Canadian price of $121.57/boe (US$110.52/boe) versus a WTI reference price of $108.55/boe (US$98.68/boe), a positive differential of $13.02/boe (US$11.83/boe). Our Canadian crude volumes also benefited quarter-over-quarter from the weaker Canadian dollar, as well as from strong U.S. Midwest refining demand, pipeline takeaway capacity improvements, and growing crude-by-rail volumes, which helped to narrow the differential between Edmonton Sweet index prices and WTI. Our average realized price for Canadian crude production increased from $86.87/boe in the fourth quarter of 2013 to $95.25/boe in the first quarter of 2014. Our ongoing exposure to Canadian natural gas also enabled us to benefit, during the first quarter of 2014, from the meaningful increase in AECO index pricing to $5.21/GJ in the first quarter of 2014 as compared to $3.51/GJ in the prior quarter. Moreover, our Canadian natural gas exposure grew during the first quarter of 2014, in part due to the success of our Mannville condensate-rich natural gas drilling program. While Title Transfer Facility (TTF) index pricing softened modestly quarter-over-quarter, it remained strong relative to North American natural gas prices. Our European gas production, which originates from the Netherlands and Germany and is priced against TTF, received an average realized price of $10.29/mcf ($9.75/GJ).

While devaluation of the Canadian dollar results in a positive, outsized impact on fund flows from operations, thereby improving our overall payout ratio, it does increase the cost of our foreign denominated capital expenditures in Canadian dollar terms. To-date in 2014, devaluation of the Canadian dollar has translated to an increase in actual and anticipated capital expenditures for full-year 2014, as measured in Canadian dollars, of approximately $30 million. Combined with an additional $15 million of anticipated drilling-related capital spending, we are now forecasting full-year 2014 E&D capital expenditures of approximately $635 million (inclusive of anticipated E&D capital spending attributable to our acquisition of Elkhorn Resources Inc.).

The first quarter of 2014 marks another quarter of high activity and effective operational execution for our Company. We achieved significant quarter-over-quarter production growth in the first quarter of 2014, largely attributable to an active and successful drilling and completions program in Canada. Our Cardium production averaged more than 10,400 boe/d in the first quarter, and hit a new monthly record of approximately 11,300 boe/d in the month of March. Cardium production levels grew 12% over fourth quarter 2013 levels due to an active capital program that included 14 (13.3 net) new Cardium wells brought on production, and better-than-forecasted production volumes from several of our two-mile extended reach horizontal Cardium wells. Operating netbacks⁽¹⁾ related to our Cardium development averaged more than $70/boe in the first quarter. During 2014, we anticipate drilling more than 30 net Cardium wells. With respect to natural gas, we also continue to achieve better-than-forecasted results from our Mannville condensate-rich development program. Production volumes from Mannville development wells drilled in 2013 and 2014 averaged more than 3,000 boe/d during the first quarter of 2014. In 2014, we plan to drill eight (5.7 net) Mannville wells, and we expect drilling activity to increase in future years as we continue to develop the play and expand our inventory of economic prospects.

We continue to appraise our position in the Duvernay condensate-rich resource play, where we have amassed 317 net sections at the relatively low cost of approximately $76 million ($375/acre). Our position comprises three largely contiguous blocks in the Edson, West Pembina and Niton areas. To date, we have drilled three vertical stratigraphic test wells, and are currently drilling our first two horizontal appraisal wells. The first horizontal appraisal well is located in the down-dip part of our Edson block, where condensate yields are expected to be lower than the average in our overall land position. We selected this location because of its proximity to one of our vertical stratigraphic test wells, allowing us to conduct micro-seismic monitoring while we frac the horizontal well in the third quarter of 2014. Our second horizontal appraisal well, which we operate at a 34.8% working interest, is located along a shared lease-line in the Pembina block to allow partner participation. Completion of this second well, also employing micro-seismic monitoring, is also expected to occur during the third quarter. We anticipate that the horizontal well production results and interpreted fracture geometries from the micro-seismic data on both horizontal appraisal wells will assist us in optimizing completions on future horizontal wells. We are confident that we will be able to project the results to higher condensate yield drilling locations as we move to the northeast in our acreage position, which encompasses the entire breadth of the condensate-rich window. Our Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational, and timing advantages if we progress to full development of the Duvernay resource play. In combination, our Cardium, Mannville, and Duvernay positions provide us with exploration and development opportunities in our core Canadian operating region that have the potential to deliver strong production and reserve growth into the latter half of the decade.

On March 18, 2014, we announced that we had entered into an arrangement agreement to acquire Elkhorn Resources Inc., a private southeast Saskatchewan producer. On April 29, 2014, we announced completion of the acquisition for total consideration of $427 million. Total consideration comprised the assumption of an estimated $42 million of debt, $180 million of cash, and the issuance of 2.8 million common shares of Vermilion valued at approximately $205 million (based on the closing price per Vermilion common share of $72.50 on the Toronto Stock Exchange on April 29, 2014). The assets consist of high netback, light oil producing assets in the Northgate region of southeast Saskatchewan and include approximately 57,000 net acres of land (approximately 80% undeveloped), seven oil batteries, and preferential access to 50% or greater capacity at a solution gas facility that is currently under construction. Production from the assets is projected to average approximately 3,750 boe/d (97% crude oil) during 2014. More than 90% of the current production base is operated by Vermilion. We have currently identified approximately 175 (152 net) potential drilling locations targeting the Midale, Frobisher, Bakken, and Three Forks/Torquay formations.

We were also active in our European operations during the first quarter of 2014. In France, we kicked off our 2014-drilling program during the first quarter of 2014 with the drilling of our Parentis-224 (PS-224) well. We are currently evaluating results from the PS-224 well, which was the first of a nine-well drilling program that will target drilling in the Champotran, Cazaux, Parentis and Tamaris fields in France in 2014. We also continued to complete preparations for the phased transfer of our Vic Bihl natural gas production, which is currently shut-in, from the Lacq gas processing facility, where it was previously handled, to an alternative third party facility. We currently anticipate approximately 850 mcf/d of our Vic Bihl gas production will be back on-stream in the third quarter of 2014. The remainder of the shut-in gas production, approximately 3,400 mcf/d, at Vic Bihl is not expected to be back on production until late-2015. With our continued expansion in France, our French business has become well positioned to be an organic oil growth asset featuring low base decline rates, high netbacks from Dated Brent-based production, strong cash flow generation and high capital efficiencies on development projects.

In the Netherlands, we drilled the first two wells (Leeuwarden-102 and Hempens-01) of our planned seven-well 2014 drilling program during the first quarter. The Leeuwarden-102 well is being tested in a partially-depleted Vlieland sand interval, and it is unclear at this point whether it will warrant tie-in. The Hempens-01 well was wet on open-hole logs and was plugged and abandoned. During the first quarter of 2014, we were awarded the Ijsselmuiden exploration concession, which consists of approximately 110,500 net undeveloped acres, further increasing our undeveloped land base in the Netherlands to more than 800,000 net acres. We have identified several new development opportunities on the recently awarded concessions and on the lands acquired in the fourth quarter of 2013, increasing our already significant inventory of investment projects in the Netherlands. Beginning with the 2014-drilling program, it is our intention to methodically increase annual activity levels in the Netherlands to maintain a rolling inventory of projects so that each year's capital program will involve a combination of drilling new wells and the tie-in of previous successes.

In Germany, we successfully closed the acquisition of a 25% contractual participation interest in a four-partner consortium. The acquisition was completed with an effective date for production of February 1, 2014. The acquisition enables us to participate in the exploration, development, production and transportation of natural gas from the assets held by the consortium. The assets are comprised of four gas producing fields across 11 production licenses. The acquired assets are expected to contribute approximately 2,300 boe/d of production for calendar 2014, and include both exploration and production licenses that comprise a total of 207,000 gross acres, of which 85% is in the exploration license. Germany is a producing region with a long history of oil and gas development activity, low political risk, and strong marketing fundamentals. Our position provides us with entry into this sizable market, in the form of free cash flow generating, low-decline assets with near-term development inventory in addition to longer-term, low-permeability gas prospectivity. Vermilion's position in Germany aligns with our European focus, and increases our exposure to the strong fundamentals and pricing of European natural gas markets. We believe that our conventional and unconventional expertise, coupled with new access to proprietary technical data, will position us strongly for future development and expansion opportunities in both Germany and the greater European region. During the first quarter, we participated in the drilling of one (0.25 net) development well in Germany. This well logged 81 metres of net pay and is expected to be tested and put on production during the second quarter of 2014.

In Ireland, boring operations related to the 4.9 kilometre tunnel required to complete construction of the onshore pipeline are nearing completion. As of April 30, 2014, the tunnel was approximately 95% complete with less than 300 metres of tunnel remaining to be bored. Based on review of the current deterministic schedule for remaining construction and commissioning activities, we continue to anticipate first gas from Corrib in approximately mid-2015. Peak production rates at Corrib are currently estimated at approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.

In Australia, a number of maintenance projects, engineering studies and operating activities were carried out during the first quarter. In the first half of 2013, we drilled two sidetracks off existing wells in the Wandoo field. Our next drilling program is expected to occur in 2015. In 2014, we remain focused on completing preparations for the 2015 drilling program, as well as re-lifing and maintenance projects on our two platforms. In order to meet current marketing agreements and provide long-term certainty to our customers, our current plan is to maintain field-total production levels within our prior guidance of between 6,000 bbls/d and 8,000 bbls/d. We anticipate maintaining these production levels in Australia for the foreseeable future with drilling programs approximately every two years. Wandoo's oil currently garners a premium of approximately US$7.00 to the Dated Brent index and incurs no transportation cost as production is sold directly at the platform.

Our operations continue to perform strongly, generating organic production growth in a capital-efficient manner. Given the strength of our operations, we have elected to increase our original full year 2014 average annual production guidance from the current level of 47,500 to 48,500 boe/d to between 48,000 and 49,000 boe/d. Assuming commodity prices remain near current levels for the remainder of 2014, we anticipate that we can fully fund our net dividends⁽¹⁾and development capital expenditures (excluding capital investment at Corrib) with fund flows from operations during 2014.

We believe we remain positioned to deliver strong operational and financial performance over the next several years. We continue to target annual organic production growth of approximately 5% to 7% along with providing reliable and growing dividends. Near term production and fund flows from operations growth is expected to be driven by continued Cardium and Mannville development in Canada, oil development activities in France, and high-netback natural gas drilling in the Netherlands. A significant increment of production, fund flows from operations and free cash flow growth is expected from Corrib beginning in approximately mid-2015 with the first full year of production from the project in 2016. Our Australian and German Business Units are expected to provide relatively steady production as well as significant free cash flow.

The management and directors of Vermilion continue to hold approximately 8% of the outstanding shares and remain committed to delivering superior rewards to all stakeholders. Continuing to be acknowledged for excellence in our business practices, Vermilion was recognized for the fifth consecutive year by the Great Place to Work® Institute in both Canada and France in 2014. In Canada, Vermilion was ranked 5^th Best Workplace in its category for 2014. More than 300 Canadian companies participated in the survey and Vermilion was the only energy company in Canada to be recognized as a Best Workplace. In France, Vermilion received a special award for corporate social responsibility and was ranked 13^th Best Workplace in its category for 2014. Vermilion's Netherlands business unit became eligible to participate in the competition for the first time in 2014 and was ranked 10^th Best Workplace in its category, the highest score of any energy company in the survey.

⁽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.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is Management's Discussion and Analysis ("MD&A"), dated May 1, 2014, of Vermilion Energy Inc.'s ("Vermilion" or the "Company") operating and financial results as at and for the three months ended March 31, 2014 compared with the corresponding period in the prior year.

This discussion should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three months ended March 31, 2014 and the audited consolidated financial statements for the year ended December 31, 2013 and 2012, 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 months ended March 31, 2014 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.

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 Western Canada, 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 producing assets in Alberta.
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 offshore Corrib natural gas field.
Australia business unit: Relates to our operations in the Wandoo offshore crude oil field.
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.

Prior to December 31, 2013, Vermilion combined the operating and financial results of the Canada business unit and the Corporate segment and presented the combined results as Canada.

CORPORATE ACQUISITION

The acquired assets include approximately 57,000 net acres of land (approximately 80% undeveloped), seven oil batteries, and preferential access to 50% or greater capacity at a solution gas facility that is currently under construction. Production from the assets is primarily high netback, low base decline, light oil from the Northgate region of southeast Saskatchewan and is projected to be approximately 3,750 boe/d (97% crude oil) during 2014. More than 90% of the current production base is operated by Vermilion.

Total proved ("1P") and proved plus probable ("2P") reserves attributed to the assets at February 28, 2014 are 10.3⁽¹⁾ mmboe (81% crude oil and natural gas liquids) and 16.5⁽¹⁾ mmboe (81% crude oil and natural gas liquids), respectively, based on an independent evaluation by GLJ Petroleum Consultants Ltd. We have currently identified approximately 175 (152 net) potential drilling locations targeting the Midale, Frobisher, Bakken, and Three Forks/Torquay formations. Approximately 45% of the locations remain unbooked and are not reflected in the GLJ Report. The majority of production and development drilling opportunities are from the Midale formation, with additional opportunities identified in the Frobisher, Bakken and Three Forks/Torquay formations.

⁽¹⁾

Estimated total proved and proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated March 17, 2014 with an effective date of February 28, 2014, in accordance with National Instrument 51-101 - Standards for Disclosure for Oil and Gas Activities of the Canadian Securities Administrators, using the GLJ (2014-01) price forecast (the "GLJ Report")

GUIDANCE

We first issued 2014 capital expenditure guidance of $555 million on November 7, 2013. We subsequently increased our 2014 capital expenditure guidance to $590 million on March 18, 2014, to reflect an additional $35 million of 2014 development capital expected to be incurred in association with our acquisition of Elkhorn Resources Inc. Concurrent with the release of our first quarter 2014 financial and operating results on May 2, 2014, we are further updating our 2014 capital expenditure guidance to $635 million, an increase of $45 million from prior guidance. The increase largely reflects the expected full-year rise in the cost to Vermilion, in Canadian dollar terms, of both actual and anticipated international capital expenditures as a result of the continued devaluation of the Canadian dollar against both the U.S. dollar and the Euro. It further reflects the addition of approximately $15 million of anticipated spending associated with drilling activities.

With the strength of operations during the first quarter of 2014, we are also increasing our original production guidance of 47,500-48,500 boe/d to revised guidance of 48,000-49,000 boe/d.

The following table summarizes our 2014 guidance:

Date

Capital Expenditures ($MM)

Production (boe/d)

2014 Guidance

November 7, 2013

555

45,000 to 46,000

2014 Guidance - Update

March 18, 2014

590

47,500 to 48,500

2014 Guidance - Update

May 2, 2014

635

48,000 to 49,000

SHAREHOLDER RETURN

Vermilion strives to provide investors with reliable and growing dividends in addition to sustainable, global production growth. The following table, as of March 31, 2014, 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	$2.45	$7.04	$11.60
Capital appreciation per Vermilion share	$16.45	$18.52	$42.15
Total return per Vermilion share	35.9%	50.6%	199.8%
Annualized total return per Vermilion share	35.9%	14.6%	24.6%
Annualized total return on the S&P TSX High Income Energy Index	19.8%	(5.1%)	8.9%

⁽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
		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
		2014	2013	2013	Q4/13	Q1/13
Production
	Crude oil (bbls/d)	27,318	26,039	23,583	5%	16%
	NGLs (bbls/d)	2,140	1,761	1,431	22%	50%
	Natural gas (mmcf/d)	103.32	78.96	82.16	31%	26%
	Total (boe/d)	46,677	40,960	38,707	14%	21%
	Build (draw) in inventory (bbl)	(97,843)	(10,192)	(239,162)
Financial metrics
	Fund flows from operations ($M)	205,363	163,660	163,629	25%	26%
	Per share ($/basic share)	2.01	1.61	1.65	25%	22%
	Net earnings ($M)	102,788	101,510	52,137	1%	97%
	Per share ($/basic share)	1.00	1.00	0.53	-	89%
	Cash flows from operating activities ($M)	178,238	177,003	190,712	1%	(7%)
	Net debt ($M)	966,310	749,685	744,762	29%	30%
	Cash dividends ($/share)	0.645	0.600	0.600	8%	8%
Activity
	Capital expenditures ($M)	196,375	148,478	180,469	32%	9%
	Acquisitions ($M)	178,227	29,103	-	512%	100%
	Gross wells drilled	24.00	21.00	28.00
	Net wells drilled	18.83	16.65	26.50

Operational review

Recorded average production of 46,677 boe/d during Q1 2014, a 14% increase as compared to Q4 2013 and a 21% increase as compared to Q1 2013. The growth quarter-over-quarter and year-over-year was largely the result of production growth in both Canada and the Netherlands. In Canada, production growth of 14% quarter-over-quarter (including a 22% growth in NGL production) and 22% year-over-year (including a 55% growth in NGL production) was achieved through continued development of the Cardium and Mannville plays in Canada. In the Netherlands, production increased to 7,260 boe/d resulting from incremental production from our acquisition in the Netherlands in Q4 2013 and increased volumes following completion of the Middenmeer Treatment Centre retrofit in the latter part of 2013. In addition, we grew production in Australia to 7,110 boe/d, a 15% quarter-over-quarter increase and a 34% year-over-year increase and added 1,773 boe/d of incremental volumes from our acquisition in Germany, which closed in February of 2014. On a year-over-year basis, these increases were partially offset by a 3% decrease in production in France, largely the result of the temporary shut-in of natural gas production.
Activity during the quarter included capital expenditures of $196.4 million, the majority of which, $114.9 million, was incurred in Canada primarily relating to the drilling of 15.0 net wells in the Cardium and Mannville. The remaining capital expenditures were incurred in drilling two net wells in France, 1.9 net wells in the Netherlands, and ongoing tunnelling and facilities activities in Ireland.
Acquisitions totalling $178.2 million was largely related to our acquisition in Germany, which closed in February of 2014, for total cash consideration of $172.9 million.

Financial review

Net earnings

Net earnings for Q1 2014 were $102.8 million ($1.00/basic share) as compared to net earnings in Q4 2013 of $101.5 million ($1.00/basic share). Net earnings remained consistent quarter-over-quarter despite increased sales volumes, favorable foreign exchange and favorable Canadian commodity pricing, due to the impact of an impairment recovery recorded in Q4 2013.
Net earnings for Q1 2014 increased by 97% (89% on a per basic share basis) as compared to Q1 2013 due primarily to increased sales driven by production growth in most of our operating regions, foreign exchange impacts, and stronger pricing for Canadian crude oil and natural gas. The increases included a $22.0 million unrealized foreign exchange gain due to the Euro continuing to strengthen versus the Canadian dollar and the resulting impact on our Euro denominated financial assets.

Cash flows from operating activities

Increased cash flow from operating activities by approximately 29% quarter-over-quarter and 30% year-over year as a result of increased sales volumes and favorable Canadian dollar commodity prices. On a year-over-year basis, these favorable variances were partially offset by timing differences pertaining to working capital.

Fund flows from operations

Generated fund flows from operations of $205.4 million ($2.01/basic share) during Q1 2014, an increase of 25% quarter-over-quarter and 26% year-over-year. The increase in fund flows from operations resulted from increased production in the majority of our producing regions, strong pricing for Canadian crude oil and natural gas, and the favorable impacts of the weakening Canadian dollar versus the US dollar and the Euro.

Net debt

Maintained a strong balance sheet with closing net debt of $966.3 million, representing 1.2 times annualized fund flows from operations. The increase in net debt versus the comparative periods was largely driven by the aforementioned acquisition in Germany coupled with current year development capital expenditures in Ireland.

Dividends

Declared dividends of $0.215 per common share per month during 2014, totalling $0.645 per common share over the quarter, an increase of 8% versus Q4 and Q1 2013.

COMMODITY PRICES

	Three Months Ended			% change
	Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
	2014	2013	2013	Q4/13	Q1/13
Average reference prices
WTI (US $/bbl)	98.68	97.46	94.37	1%	5%
Edmonton Sweet index (US $/bbl)	90.43	82.53	87.42	10%	3%
Dated Brent (US $/bbl)	108.22	109.27	112.55	(1%)	(4%)
AECO ($/GJ)	5.42	3.35	3.03	62%	79%
TTF ($/GJ)	10.19	10.65	10.40	(4%)	(2%)
TTF (€/GJ)	6.75	7.45	7.81	(9%)	(14%)
Average foreign currency exchange rates
CDN $/US $	1.10	1.05	1.01	5%	9%
CDN $/Euro	1.51	1.43	1.33	6%	14%
Average realized prices ($/boe)
Canada	69.26	61.10	57.61	13%	20%
France	117.54	112.84	107.17	4%	10%
Netherlands	63.60	67.88	61.21	(6%)	4%
Germany	55.85	-	-	100%	100%
Australia	127.26	124.63	120.76	2%	5%
Consolidated	88.67	86.04	83.04	3%	7%
Production mix (% of production)
% priced with reference to WTI	25%	25%	24%
% priced with reference to AECO	17%	17%	18%
% priced with reference to TTF	19%	15%	18%
% priced with reference to Dated Brent	39%	43%	40%

Reference prices

For Q1 2014, both Dated Brent and WTI were largely unchanged from Q4 2013, with Dated Brent averaging US$108.22/bbl (down 1% quarter-over-quarter) and WTI averaging US$98.68/bbl, up 1% over Q4 2013. While a relatively tight fundamental balance and the emergence of geopolitical unrest in Ukraine helped support oil prices throughout the quarter, weather factors along with concerns of weaker emerging market demand growth and more restrictive central bank policies kept upside price advances limited.
Edmonton Sweet averaged US$90.43/bbl in Q1 2014, up 10% from the previous quarter and 3% higher than the same quarter last year. Favourable market conditions including stronger US Midwest refining demand, pipeline takeaway capacity improvements, and growing crude-by-rail helped lift Edmonton prices and tighten the differential to WTI.
AECO natural gas averaged $5.42/GJ in Q1 2014, which was 62% higher than Q4 2013 and 79% increase over the same quarter last year. During Q1 2014, there was a significant increase in weather driven demand for heating fuel that led gas-in-storage to decline dramatically and a tighter supply/demand balance.
Conversely, Q1 2014 saw TTF prices average 6.75 €/GJ, or 9% lower than Q4 2013 and 14% below the same period last year. Warmer-than-normal winter weather decreased demand and caused gas-in-storage levels to remain elevated. However, geopolitical tensions between Russia and Ukraine limited the downside as Ukraine is still a major conduit for Russian natural gas exports to Europe.
Canadian dollar weakness relative to both the US dollar and the Euro in Q1 2014 was largely on the back of an accommodative Bank of Canada monetary policy, weaker-than-expected Canadian economic data and shrinking capital inflow. However, stronger US dollar buying interest due in part to reduced asset purchases by the US Fed, and reduced peripheral sovereign risk concerns in Europe also contributed to the Q1 Canadian dollar weakness versus the US dollar and the Euro.

Realized prices

Consolidated realized price increased by 3% for Q1 2014 as compared to Q4 2013 primarily as a result of stronger Canadian crude oil and natural gas pricing and the weakness of the Canadian dollar versus the US dollar. These increases were partially offset by a 4% decrease in Canadian dollar TTF pricing quarter-over-quarter and an increased weighting towards TTF priced production due to production growth in the Netherlands and incremental production from our acquisition of working interests in Germany.
Consolidated realized price increased by 7% for Q1 2014 as compared to Q1 2013 primarily resulting from increased AECO pricing coupled with the impact of the weakening Canadian dollar on US dollar and Euro denominated commodities.

FUND FLOWS FROM OPERATIONS

	Three Months Ended
	Mar 31, 2014		Dec 31, 2013		Mar 31, 2013
	$M	$/boe	$M	$/boe	$M	$/boe
Petroleum and natural gas sales	381,183	88.67	325,108	86.04	309,576	83.04
Royalties	(24,024)	(5.59)	(17,616)	(4.66)	(15,790)	(4.24)
Petroleum and natural gas revenues	357,159	83.08	307,492	81.38	293,786	78.80
Transportation expense	(9,861)	(2.29)	(9,081)	(2.40)	(6,641)	(1.78)
Operating expense	(57,986)	(13.49)	(48,140)	(12.74)	(52,575)	(14.10)
General and administration	(14,467)	(3.37)	(13,954)	(3.69)	(12,610)	(3.38)
Corporate income taxes	(38,603)	(8.98)	(43,065)	(11.40)	(35,557)	(9.54)
PRRT	(20,239)	(4.71)	(17,173)	(4.55)	(11,153)	(2.99)
Interest expense	(11,460)	(2.67)	(10,049)	(2.66)	(8,689)	(2.33)
Realized gain (loss) on derivative instruments	2,640	0.61	(1,300)	(0.34)	(2,787)	(0.75)
Realized foreign exchange loss	(2,041)	(0.47)	(1,294)	(0.34)	(617)	(0.17)
Realized other income	221	0.05	224	0.06	472	0.13
Fund flows from operations	205,363	47.76	163,660	43.32	163,629	43.89

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

($M)		Q1/14 vs. Q4/13	Q1/14 vs. Q1/13
Fund flows from operations - Comparative period		163,660	163,629
Sales volume variance:
	Canada	9,111	19,472
	France	2,101	(12,007)
	Netherlands	4,886	5,399
	Germany	8,915	8,915
	Australia	10,581	15,477
Pricing variance on sold volumes:
	WTI	8,679	10,347
	AECO	8,024	9,673
	Dated Brent	6,560	12,597
	TTF	(2,782)	1,734
Changes in:
	Realized derivatives	3,940	5,427
	Royalties	(6,408)	(8,234)
	Operating expense	(9,846)	(5,411)
	Transportation	(780)	(3,220)
	Interest	(1,411)	(2,771)
	General and administration	(513)	(1,857)
	Realized other income	(3)	(251)
	Realized foreign exchange	(747)	(1,424)
	Corporate income taxes	4,462	(3,046)
	PRRT	(3,066)	(9,086)
Fund flows from operations - Current Period		205,363	205,363

Fund flows from operations for Q1 2014 was approximately 25% ($41.7 million) higher than Q4 2013. This increase was driven by a $35.6 million positive sales volume variance coupled with a $20.5 million positive pricing variance, partially offset by a $14.4 million increase in expenditures following higher levels of operational activity. The $35.6 million sales volume variance was primarily driven by production growth in Canada, the Netherlands, and Australia and incremental production from our Germany acquisition. The $14.4 million pricing variance was largely driven by strong Canadian crude oil and natural gas pricing and favorable foreign exchange impacts on US dollar priced crude oil but was partially offset by lower TTF pricing as a result of warmer winter weather in Europe.

Fund flows from operations for Q1 2014 was approximately 26% ($41.7 million) higher than Q1 2013. This increase was driven by a $37.3 million positive sales volume variance coupled with a $34.4 million positive pricing variance, partially offset by a $30.0 million increase in expenditures following higher levels of operational activity. The $37.3 million sales volume variance was primarily driven by increased production in Canada, the Netherlands, and Australia in addition to incremental production from our Germany acquisition. These increases were partially offset by an unfavorable $12.0 million sales volume variance in France resulting from an approximately 71,000 bbl decrease in volumes sold due to the timing of inventory movements and a $4.2 million sales volume variance resulting from the temporary shut-in of natural gas production. The $34.4 million pricing variance was driven by increases in all Canadian dollar translated reference prices, including a 79% increase in AECO pricing which contributed a $9.7 million price variance.

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 our 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 Alberta at West Pembina near Drayton Valley, Slave Lake and Central Alberta.
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 (3,400m depth) - in appraisal phase

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

Operational review

		Three Months Ended			% change
		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
Canada business unit		2014	2013	2013	Q4/13	Q1/13
Production
	Crude oil (bbls/d)	9,437	8,719	7,966	8%	18%
	NGLs (bbls/d)	2,071	1,699	1,335	22%	55%
	Natural gas (mmcf/d)	49.53	41.43	41.04	20%	21%
	Total (boe/d)	19,763	17,322	16,140	14%	22%
Production mix (% of total)
	Crude oil	48%	50%	49%
	NGLs	10%	10%	8%
	Natural gas	42%	40%	43%
Activity
	Capital expenditures ($M)	114,939	77,245	92,129	49%	25%
	Acquisitions ($M)	4,768	1,603	-
	Gross wells drilled	20.00	21.00	24.00
	Net wells drilled	14.97	16.65	22.50

Production

Production in Canada increased by 14% quarter-over-quarter and by 22% year-over-year.
Year-over-year increase was largely attributable to strong production from our Mannville program and continued development in the Cardium.
Cardium production averaged more than 10,400 boe/d in Q1 2014 and reached a record monthly high of nearly 11,300 boe/d in March.
Mannville production averaged more than 3,000 boe/d in Q1 2014.

Activity review

Vermilion drilled 20 (15.0 net) wells during Q1 2014.

Cardium

In the Cardium, we drilled 11 (10.5 net) operated wells and brought 13 (13 net) operated wells on production during Q1 2014. Ten of the 13 wells that came on production in Q1 2014 were long reach wells.
Since 2009, we have drilled or participated in 252 (181.9 net) wells in the Cardium.
Operating netbacks averaged more than $70/boe in Q1 2014 for Cardium related production.
In 2014, we plan to drill or participate in 36 (30.3 net) Cardium wells.

Mannville

During Q1 2014, in the Mannville, we drilled five (3.7 net) operated wells and brought three (2.2 net) operated wells on production.
In 2014, we plan to drill eight (5.7 net) Mannville wells.
Operating netbacks averaged more than $40/boe in Q1 2014 for Mannville related production.

Duvernay

We have begun drilling two (1.4 net) horizontal Duvernay wells, with completion of the wells anticipated for Q3 2014.

Financial review

		Three Months Ended			% change
Canada business unit		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
($M except as indicated)		2014	2013	2013	Q4/13	Q1/13
	Sales	123,180	97,367	83,688	27%	47%
	Royalties	(12,663)	(11,039)	(8,989)	15%	41%
	Transportation expense	(3,098)	(4,102)	(2,269)	(24%)	37%
	Operating expense	(16,610)	(13,218)	(13,841)	26%	20%
	General and administration	(2,868)	(2,478)	(3,069)	16%	(7%)
	Fund flows from operations	87,941	66,530	55,520	32%	58%
Netbacks ($/boe)
	Sales	69.26	61.10	57.61	13%	20%
	Royalties	(7.12)	(6.93)	(6.19)	3%	15%
	Transportation expense	(1.74)	(2.57)	(1.56)	(32%)	12%
	Operating expense	(9.34)	(8.29)	(9.53)	13%	(2%)
	General and administration	(1.61)	(1.60)	(2.11)	1%	(24%)
	Fund flows from operations netback	49.45	41.71	38.22	19%	29%
Reference prices
	WTI (US $/bbl)	98.68	97.46	94.37	1%	5%
	Edmonton Sweet index (US $/bbl)	90.43	82.53	87.42	10%	3%
	AECO ($/GJ)	5.42	3.35	3.03	62%	79%

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 and 20% year-over-year as a result of significantly increased AECO pricing (62% quarter-over-quarter and 79% year-over-year) coupled with stronger Edmonton Sweet index pricing.
The increase in commodity prices coupled with production growth in the Cardium and Mannville resource plays resulted in quarter-over-quarter and year-over-year increases in sales of 27% and 47%, respectively.

Royalties

Royalty expense as a percentage of sales decreased to 10.3% for Q1 2014 as compared to 11.3% for Q4 2013 as a result of the timing of placing Cardium wells on production due to the associated royalty incentive on initial production volumes.
Royalty expense as a percentage of sales for Q1 2014 as compared to Q1 2013 was consistent at 10.3% and 10.7%, respectively.

Transportation

Transportation expense relates to the delivery of crude oil and natural gas production to major pipelines where legal title transfers.
Transportation expense decreased in Q1 2014 as compared to Q4 2013 as that quarter included costs associated with trucking oil to a rail terminal. Vermilion did not have any similar sales agreements in place during the current quarter.
Transportation expense per boe increased for Q1 2014 as compared to Q1 2013 due to rate increases as well as clean oil trucking costs associated with a Pembina pipeline outage.

Operating expense

Operating expense was higher for Q1 2014 as compared to Q4 2013 due to higher maintenance expense associated with fire tube repairs at Vermilion's Cardium facility, increased trucking charges associated with temporary emulsion storage due to a Pembina pipeline outage and additional gas processing fees related to higher gas production. Operating expense per boe also increased quarter-over-quarter due to the additional expenses, partially offset by increased production.
Operating expense for Q1 2014 was higher than the expense for the same period of the prior year due to variable expenses associated with increased production volumes as well as the previously mentioned fire tube repairs and emulsion trucking charges. On a per boe basis, operating expense per boe decreased for the current period as compared to the first quarter of 2013 due to higher production volumes.

General and administration

Year-over-year, general and administration expense remained consistent. Fluctuations in the presented quarters relates primarily to the timing of expenditures.

FRANCE BUSINESS UNIT

Overview

Entered France in 1997 and completed three subsequent acquisitions, including two in 2012.
Largest oil producer by volume.
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
		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
France business unit		2014	2013	2013	Q4/13	Q1/13
Production
	Crude oil (bbls/d)	10,771	11,131	10,330	(3%)	4%
	Natural gas (mmcf/d)	-	-	4.21	-	(100%)
	Total (boe/d)	10,771	11,131	11,032	(3%)	(2%)
Inventory (mbbls)
	Opening crude oil inventory	269	226	354
	Adjustments	-	-	5
	Crude oil production	969	1,024	930
	Crude oil sales	(1,000)	(981)	(1,071)
	Closing crude oil inventory	238	269	218
Production mix (% of total)
	Crude oil	100%	100%	94%
	Natural gas	-	-	6%
Activity
	Capital expenditures ($M)	37,967	31,899	21,592	19%	76%
	Gross wells drilled	2.00	-	2.00
	Net wells drilled	2.00	-	2.00

Production

Quarter-over-quarter production decrease of 3% and year-over-year production decrease of 2%. Year-over-year production of crude oil increased 4%
In late September 2013, the third party Lacq processing facility that processed our Vic Bihl gas production was permanently closed. As a result, our Vic Bihl gas production has been temporarily shut-in while preparations to transfer to an alternative facility are completed. We expect approximately 850 mcf/d will be back on-stream in Q3 2014, with the remaining approximately 3,400 mcf/d not anticipated to be back on production until late-2015.
Production remains 100% weighted to Brent crude due to the shut-in of Vic Bihl gas production.

Activity review

Vermilion drilled two (2.0 net) wells in the Aquitaine Basin during Q1 2014, with production from these wells anticipated to come on-line in Q2.
During Q1 2014 we also completed a number of seismic and facility integrity projects.
In 2014, we are planning a nine-well drilling program in the Champotran, Cazaux, Parentis, and Tamaris fields. In addition, we are planning an estimated 18-well workover program.

Financial review

		Three Months Ended			% change
France business unit		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
($M except as indicated)		2014	2013	2013	Q4/13	Q1/13
	Sales	117,560	110,757	121,566	6%	(3%)
	Royalties	(7,351)	(6,577)	(6,801)	12%	8%
	Transportation expense	(4,753)	(4,622)	(2,754)	3%	73%
	Operating expense	(16,420)	(15,524)	(19,939)	6%	(18%)
	General and administration	(5,194)	(5,080)	(5,686)	2%	(9%)
	Current income taxes	(25,264)	(28,024)	(18,659)	(10%)	35%
	Fund flows from operations	58,578	50,930	67,727	15%	(14%)
Netbacks ($/boe)
	Sales	117.54	112.84	107.17	4%	10%
	Royalties	(7.35)	(6.70)	(6.00)	10%	23%
	Transportation expense	(4.75)	(4.71)	(2.43)	1%	95%
	Operating expense	(16.42)	(15.82)	(17.58)	4%	(7%)
	General and administration	(5.19)	(5.18)	(5.01)	-	4%
	Current income taxes	(25.26)	(28.55)	(16.45)	(12%)	54%
	Fund flows from operations netback	58.57	51.88	59.70	13%	(2%)
Reference prices
	Dated Brent (US $/bbl)	108.22	109.27	112.55	(1%)	(4%)

Sales

Crude oil production in France is priced with reference to Dated Brent.
Sales increased by 6% for Q1 2014 as compared to Q4 2013 as a result of higher sales volumes coupled with the aforementioned weakening of the Canadian dollar.
Sales decreased slightly for Q1 2014 as compared to Q1 2013 as a result of the temporary shut-in of gas production, which reduced sales by $4.2 million.
Sales per boe increased for Q1 2014 as compared to both Q4 and Q1 2013, despite a decline in the US dollar Dated Brent reference price, as a result of the impact of the weakening Canadian dollar.

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).
As a percentage of sales, royalties for the periods presented remained relatively constant.

Transportation

Historically, transportation expense in France related to the shipments of crude oil by tanker from the Aquitaine Basin to third party refineries. As a result of the closure of the Lacq processing facility in Q3 2013, Vermilion began incurring additional transportation charges to ship Vic Bihl production to market. Accordingly, transportation expense per boe for Q1 2014 and Q4 2013 is higher than the expense per boe for Q1 2013.

Operating expense

Operating expense per boe for Q1 2014 increased as compared to Q4 2013 as a result of the strengthening of the Euro versus the Canadian dollar and lower production volumes.
The decrease in operating expense per boe in Q1 2014 versus the same quarter in the prior year was primarily the result of less maintenance expense year-over-year partially offset by a weaker Canadian dollar.

General and administration

General and administration expense was consistent among the periods presented. Minor variances are largely attributable to the timing of expenditures.

Current income taxes

Current income taxes in France apply to taxable income after eligible deductions at a statutory rate of 38.1% for 2014. Following the expiration of a temporary surtax, the statutory tax rate is expected to decrease to 34.4% for the tax year 2015. For 2014, the effective rate on current taxes is expected to be between approximately 28% and 31%. 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 decreased by 10% for Q1 2014 as compared to Q4 2013. The decrease was the result of an increase in eligible deductions during Q1 2014, partially offset by increased fund flows from operations.
Current income taxes increased by 35% from Q1 2014 as compared to Q1 2013. The increase was the result of the absence of certain interest deductions, lower depletion for tax purposes, and higher tax rates following a December 2013 corporate tax legislation enacted by the France government which increased the rate of a temporary surtax.

NETHERLANDS BUSINESS UNIT

Overview

Entered the Netherlands in 2004.
Second largest onshore gas producer by volume.
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
		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
Netherlands business unit		2014	2013	2013	Q4/13	Q1/13
Production
	NGLs (bbls/d)	69	62	96	11%	(28%)
	Natural gas (mmcf/d)	43.15	37.53	36.91	15%	17%
	Total (boe/d)	7,260	6,318	6,248	15%	16%
Activity
	Capital expenditures ($M)	20,118	15,698	1,999	28%	906%
	Acquisitions ($M)	-	27,500	-
	Gross wells drilled	2.00	-	-
	Net wells drilled	1.86	-	-

Production

Achieved record quarterly production of 7,260 boe/d.
Quarter-over-quarter production growth of 15% and year-over-year production growth of 16%.
The increase in production was mainly attributable to strong, steady production from current wells and completion of the retrofit of the Middenmeer Treatment Centre in 2013 which allowed for associated volumes to be processed through the 35 mmcf/d facility.

Activity review

Vermilion drilled two (1.9 net) wells during Q1 2014. One well (Leeuwarden-102) is being tested and, at this point, it is unclear whether it will warrant tie-in. The other well (Hempens-01) was wet on open-hole logs, and was subsequently plugged and abandoned.
An additional four-to-five wells are planned for the 2014 drilling program in the Netherlands. The drilling program will include our first new well on the lands acquired in October 2013.
During Q1 2014, we were awarded the Ijsselmuiden exploration concession consisting of approximately 110,500 net undeveloped acres thereby increasing our total position in the country to over 800,000 net undeveloped acres.

Financial review

		Three Months Ended			% change
Netherlands business unit		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
($M except as indicated)		2014	2013	2013	Q4/13	Q1/13
	Sales	41,554	39,451	34,421	5%	21%
	Royalties	(2,208)	-	-	100%	100%
	Operating expense	(6,042)	(6,179)	(3,969)	(2%)	52%
	General and administration	(598)	(1,553)	(412)	(61%)	45%
	Current income taxes	(3,788)	(8,267)	(9,434)	(54%)	(60%)
	Fund flows from operations	28,918	23,452	20,606	23%	40%
Netbacks ($/boe)
	Sales	63.60	67.88	61.21	(6%)	4%
	Royalties	(3.38)	-	-	100%	100%
	Operating expense	(9.25)	(10.63)	(7.06)	(13%)	31%
	General and administration	(0.91)	(2.67)	(0.73)	(66%)	25%
	Current income taxes	(5.80)	(14.22)	(16.78)	(59%)	(65%)
	Fund flows from operations netback	44.26	40.36	36.64	10%	21%
Reference prices
	TTF ($/GJ)	10.19	10.65	10.40	(4%)	(2%)
	TTF (€/GJ)	6.75	7.45	7.81	(9%)	(14%)

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 increased in Q1 2014 as compared to both Q4 and Q1 2013, despite slightly lower Canadian dollar TTF pricing, due to an increase in natural gas production.

Royalties

Historically, we have not paid royalties in the Netherlands, however, certain wells associated with an acquisition completed by Vermilion's Netherlands Business Unit in October 2013 have reached payout and are now subject to an overriding royalty.

Transportation expense

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

Operating expense

Despite the strengthening of the Euro versus the Canadian dollar, operating expense for Q1 2014 versus Q4 2013 remained relatively consistent. Due to higher production in Q1 2014 however, operating expenses per boe decreased quarter-over-quarter.
Q1 2014 operating expense increased as compared to Q1 2013 as a result of the stronger Euro versus the Canadian dollar, additional costs related to the October 2013 acquisition as well as increased staffing and facility maintenance work. These items increased operating expense on a per boe basis, partially offset by an increase in production year-over-year.

General and administration

Q4 2013 general and administration expense was higher than Q1 2014 and Q1 2013 due to additional expenses related to the previously mentioned acquisition that closed in October 2013.

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 2014, the effective rate on current taxes is expected to be between approximately 10% and 12%. 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 decreased as compared to both Q4 and Q1 2013 as a result of an increase in tax deductions for depletion during the current quarter.

GERMANY BUSINESS UNIT

Overview

Vermilion entered Germany in February 2014 with the purchase of a 25% participation interest in a four-partner consortium.
The assets of the four-partner consortium include four gas producing fields across 11 production licenses and an exploration license in surrounding fields.
Production licenses comprising 207,000 gross acres, of which 85% is in the exploration license.

Summary of results

Three Months Ended

Mar 31,

Germany business unit

2014

Production

Natural gas (mmcf/d)

10.64

Total (boe/d)

1,773

Activity

Capital expenditures ($M)

196

Acquisitions ($M)

172,871

Production

Q1 2014 production of 1,773 boe/d taking into account an effective date for production of February 1, 2014.
Anticipate average sales gas volume of 2,300 boe/d in 2014.

Activity review

Completed the acquisition of a 25% interest in a four-party consortium that enables us to participate in the exploration, development, production and transportation of natural gas from the assets, which include four gas producing fields across 11 production licenses.
We have opened a small office outside of Berlin, which we are outfitting and staffing.

Financial review

		Three Months Ended
Germany business unit		Mar 31,
($M except as indicated)		2014
	Sales	8,915
	Royalties	(1,802)
	Transportation expense	(422)
	Operating expense	(1,554)
	General and administration	(568)
	Current income taxes	(537)
	Fund flows from operations	4,032
Netbacks ($/boe)
	Sales	55.85
	Royalties	(11.29)
	Transportation expense	(2.64)
	Operating expense	(9.74)
	General and administration	(3.56)
	Current income taxes	(3.36)
	Fund flows from operations netback	25.26
Reference prices
	TTF ($/GJ)	10.19
	TTF (€/GJ)	6.75

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.

Royalties expense

Our production in Germany is subject to royalties at a rate of approximately 20% of natural gas sales revenue.

Transportation expense

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

Operating expense

Operating expenses for Germany is billed monthly by the joint venture operator and is expected to be similar to our Netherlands operating costs per boe.

Current income taxes

Current income taxes in Germany apply to taxable income after eligible deductions at a statutory tax rate of approximately 23%. For 2014, the effective rate on current taxes is expected to be between approximately 10% and 12%. This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.

IRELAND BUSINESS UNIT

Overview

18.5% non-operating interest in the offshore Corrib gas field located approximately 83km off the northwest coast of Ireland.
Project comprises six offshore wells, both offshore and onshore pipeline segments as well as a natural gas processing facility.
Acquired interest on July 30, 2009 for cash consideration of $136.8 million. Pursuant to the terms of the acquisition agreement, Vermilion made an additional payment to the vendor of $134.3 million (US$135 million) at the end of 2012.
Production from Corrib is expected to increase Vermilion's volumes by approximately 58 mmcf/d (9,700 boe/d) once the field reaches peak production.
The Corrib field is expected to constitute 95% of Ireland's natural gas production and approximately 60% to 65% of Ireland's domestic gas consumption.

Operational and financial review

		Three Months Ended			% change
Ireland business unit		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
($M)		2014	2013	2013	Q4/13	Q1/13
	Transportation expense	(1,588)	(357)	(1,618)	345%	(2%)
	General and administration	(282)	(482)	(237)	(41%)	19%
	Fund flows from operations	(1,870)	(839)	(1,855)	123%	1%
Activity
	Capital expenditures	16,236	14,472	16,520	12%	(2%)

Activity review

Tunneling operations continued in Q1 2014. Boring operations are nearly 95% complete with less than 300 metres of boring beneath Sruwaddacon Bay remaining. Preparations for the demobilization of the tunnel boring machine have commenced.
Based on our deterministic schedule for remaining construction and commissioning activities, we anticipate first gas in approximately mid-2015 with peak production of approximately 58 mmcf/d (9,700 boe/d), net to Vermilion.

Transportation expense

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

AUSTRALIA BUSINESS UNIT

Overview

Entered Australia in 2005.
Hold title to a 100% working interest in 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 are located 600 metres below the sea bed with 500 to 3,000 plus metre horizontal lengths.
Contracted crude oil production is priced with reference to Dated Brent.

Operational review

		Three Months Ended			% change
		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
Australia business unit		2014	2013	2013	Q4/13	Q1/13
Production
	Crude oil (bbls/d)	7,110	6,189	5,287	15%	34%
Inventory (mbbls)
	Opening crude oil inventory	130	183	268
	Crude oil production	640	569	476
	Crude oil sales	(707)	(622)	(579)
	Closing crude oil inventory	63	130	165
Activity
	Capital expenditures ($M)	5,691	8,420	55,349	(32%)	(90%)
	Gross wells drilled	-	-	2.0
	Net wells drilled	-	-	2.0

Production

Wandoo production increased by 15% quarter-over-quarter and 34% year-over-year.
Production volumes are managed to meet customer demands and long-term supply agreements. We continue to plan for production levels of between 6,000 and 8,000 bbls/d.
Production continues to reflect strong well results from the 2013 drilling program, more than offsetting natural declines. We continue to produce the wells at restricted rates below their demonstrated productive capacity.

Activity review

In Q1 2014, efforts were focused on facilities repairs and engineering studies, including the expansion of accommodation quarters on the Wandoo B platform and repair of the A5 conductor on Wandoo A.
2014 planned activities include ongoing facilities maintenance, enhancement, and refurbishment along with preparation and permitting activities in advance of our planned 2015 drilling program.

Financial review

		Three Months Ended			% change
Australia business unit		Mar 31,	Dec 31,	Mar 31,	Q1/14 vs.	Q1/14 vs.
($M except as indicated)		2014	2013	2013	Q4/13	Q1/13
	Sales	89,974	77,533	69,901	16%	29%
	Operating expense	(17,360)	(13,219)	(14,826)	31%	17%
	General and administration	(1,206)	(1,442)	(1,518)	(16%)	(21%)
	PRRT	(20,239)	(17,173)	(11,153)	18%	81%
	Corporate income taxes	(8,841)	(6,210)	(7,213)	42%	23%
	Fund flows from operations	42,328	39,489	35,191	7%	20%
Netbacks ($/boe)
	Sales	127.26	124.63	120.76	2%	5%
	Operating expense	(24.55)	(21.25)	(25.61)	16%	(4%)
	General and administration	(1.71)	(2.32)	(2.62)	(26%)	(35%)
	PRRT	(28.63)	(27.60)	(19.27)	4%	49%
	Corporate income taxes	(12.51)	(9.98)	(12.46)	25%	-
	Fund flows from operations netback	59.86	63.48	60.80	(6%)	(2%)
Reference prices
	Dated Brent (US $/bbl)	108.22	109.27	112.55	(1%)	(4%)

Sales

Our production in Australia currently receives a premium to Dated Brent. This premium, coupled with the weakening of the Canadian dollar versus the US dollar, resulted in an increase in sales per boe for Q1 2014 as compared to both Q4 and Q1 2013 despite slight decreases in the Dated Brent reference price.
Sales increased for Q1 2014 as compared to both Q4 and Q1 2013 due to the impact of the weakening of the Canadian dollar coupled with an increase in crude oil sales.

Royalties and transportation expense

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

Operating expense

Operating expense per boe for Q1 2014 was higher than Q4 2013 due to increased diesel usage and diesel transportation costs, coupled with higher maintenance costs due to inspection work being conducted in the current quarter.
Operating expense per boe for Q1 2014 was lower than the corresponding quarter in 2013 due to increased production volumes.

General and administration

General and administration expense remained relatively consistent for the periods presented with minor fluctuations related to 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 2014, the combined corporate income tax and PRRT effective rate is expected to be between approximately 38% and 42% This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.
Corporate income taxes increased 42% quarter-over-quarter and 23% year-over-year largely as a result of increased fund flows from operations.

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

Mar 31,

Dec 31,

Mar 31,

($M)

2014

2013

General and administration

(3,751)

(2,919)

(1,688)

Current income taxes

(173)

(564)

(251)

Interest expense

(11,460)

(10,049)

(8,689)

Realized gain (loss) on derivatives

2,640

(1,300)

(2,787)

Realized foreign exchange loss

(2,041)

(1,294)

(617)

Realized other income

221

224

472

Fund flows from operations

(14,564)

(15,902)

(13,560)

General and administration

The increase in general and administration costs for Q1 2014 versus Q4 and Q1 2013 was the result of increased business development acquisition activity coupled with the impact of certain outstanding VIP awards to be settled partially in cash.

Current income taxes

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

Interest expense

Interest expense is incurred on our senior unsecured notes and on borrowings under our revolving credit facility. The increase in 2014 versus the 2013 periods is due to increased borrowings under our revolving credit facility.

Hedging

The nature of our operations results in exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates. We monitor and, when appropriate, use derivative financial instruments to manage our exposure to these fluctuations. 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) with a goal of securing pricing for 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 Q1 2014 related primarily to amounts received on our Dated Brent and TTF derivatives, partially offset by payments made on our AECO derivatives.
A listing of derivative positions as at March 31, 2014 is included in "Supplemental Table 2" in this MD&A.

FINANCIAL PERFORMANCE REVIEW

		Three Months Ended
		Mar 31,	Dec 31,	Sep 30,	Jun 30,	Mar 31,	Dec 31,	Sep 30,	Jun 30,
($M except per share)		2014	2013	2013	2013	2013	2012	2012	2012
Petroleum and natural gas sales		381,183	325,108	327,185	311,966	309,576	241,233	284,838	246,544
Net earnings		102,788	101,510	67,796	106,198	52,137	56,914	30,798	37,816
Net earnings per share
	Basic	1.00	1.00	0.67	1.05	0.53	0.58	0.31	0.39
	Diluted	0.99	0.98	0.66	1.04	0.51	0.57	0.31	0.38

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

($M)	Q1/14 vs. Q4/13	Q1/14 vs. Q1/13
Net earnings - Comparative period	101,510	52,137
Changes in:
Fund flows from operations	41,703	41,734
Equity based compensation	4,734	(336)
Unrealized gain or loss on derivative instruments	2,663	5,048
Unrealized foreign exchange gain or loss	(290)	24,519
Unrealized other income	168	151
Accretion	815	112
Depletion and depreciation	(15,758)	(18,004)
Deferred tax	14,643	(2,573)
Impairment recovery	(47,400)	-
Net earnings - Current Period	102,788	102,788

The fluctuations in net earnings from quarter-to-quarter and from year-to-year are caused by changes in both cash and non-cash charges. Cash charges 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 charges 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 charges may also include non-recurring charges 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.

Fluctuations in equity based compensation expense primarily result from revisions in the future performance conditions related to the VIP, estimated forfeiture rates, and the overall number of VIP outstanding. In general, future performance conditions and estimated forfeiture rates are revised during the fourth quarter as information becomes more readily available relating to the Company's performance during the fiscal year.

Equity based compensation expense was lower in Q1 2014 as compared to Q4 2013 as the 2013 period included an upward revision of future performance condition assumptions. Equity based compensation expense for Q1 2014 was relatively consistent with the expense for Q1 2013.

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 vise-versa.

In Q1 2014, we recognized an unrealized gain on derivative instruments of $3.9 million relating primarily to our European crude oil and natural gas derivative instruments. As at March 31, 2014, we had a net current derivative asset of $2.6 million relating primarily to European crude oil and natural gas derivative instruments settling in Q2 and Q3 2014.

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 U.S. 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.

During Q1 2014, the Euro strengthened by 4% versus the Canadian dollar resulting in unrealized foreign exchange gains of $22.0 million.

Accretion
Fluctuations in accretion expense is primarily the result of changes in the balance of asset retirement obligations. Q1 2014 accretion expense was relatively consistent as compared to Q1 2013. The decrease in accretion expense for Q1 2014 as compared to Q4 2013 was primarily the result of a decrease in the discount rate used to calculate asset retirement obligations.

Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily the result of changes in produced crude oil and natural gas volumes.

Q1 2014 production as compared to the comparable periods in 2013 increased by 21% and 14%, respectively, resulting in higher depletion and depreciation expense of 22% and 19%, respectively.

Depletion and depreciation on a per boe basis for Q1 2014 of $23.13/boe was relatively consistent as compared to Q4 2013 depletion and depreciation of $22.15/boe. The increase on a per boe basis for Q1 2014 as compared to Q1 2013 ($21.85/boe) increased largely due to Vermilion's increased capital activity in the Cardium light oil and Mannville condensate-rich natural gas plays.

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.

Deferred tax expense decreased from $21.3 million for Q4 2013 to $6.6 million for Q1 2014. The decrease was largely the result of the absence of an increase in the temporary difference relating to asset retirement obligations which occurred in Q4 2013. The Q4 2013 increase was the result of an increase to asset retirement obligations for accounting purposes, due to a change in discount and inflation rates, with no corresponding change in the tax basis. On a year-over-year basis, deferred tax expense increased as the result of the increase in taxable income leading to the usage of tax losses.

Impairment recovery
In Q4 2013, we recognized a recovery of a portion of impairment charges recorded in 2011. The impairment recovery resulted from increased proved and probable reserves of natural gas and natural gas liquids, due primarily to the successful application of horizontal drilling and multi-stage fracturing technology to the previously impaired cash generating unit.

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 a ratio of approximately 1.0 to 1.2. In a 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.

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

Mar 31,

Dec 31,

Mar 31,

Dec 31,

($M)

2014

2013

2014

2013

Revolving credit facility

3.3%

3.3%

720,762

766,898

Senior unsecured notes

6.5%

6.5%

223,347

223,126

Long-term debt

4.0%

4.7%

944,109

990,024

Revolving Credit Facility
Our revolving credit 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
	Mar 31,	Dec 31,
	2014	2013
Total facility amount	$1.20 billion	$1.20 billion
Amount drawn	$720.8 million	$766.9 million
Letters of credit outstanding	$8.4 million	$8.1 million
Facility maturity date	31-May-16	31-May-16

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

		As At
		Mar 31,	Dec 31,
Financial covenant	Limit	2014	2013
Consolidated total debt to consolidated EBITDA	4.0	0.96	1.06
Consolidated total senior debt to consolidated EBITDA	3.0	0.73	0.82

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" 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.

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

Subsequent to March 31, 2014, we amended our revolving credit facility agreement. The amended revolving credit facility increases the total committed facility amount to $1.50 billion and extends the facility maturity date to May 31, 2017. In addition, we may, by adding lenders or by seeking an increase to an existing lender's commitment, increase the total committed facility amount to no more than $1.75 billion. The amended revolving credit facility includes an additional financial covenant requiring that the ratio of consolidated total senior debt to total capitalization be less than 50%. Total capitalization includes all amounts on our balance sheet classified as "Long-term debt" and "Shareholders' Equity". As at March 31, 2014, Vermilion had a ratio of consolidated total senior debt to total capitalization of 25.9%.

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 amount

$225.0 million

Interest

6.5% per annum

Issued date

February 10, 2011

Maturity date

February 10, 2016

We may redeem all or part of the notes at fixed redemption prices plus in each case, accrued and unpaid interest, if any, to the applicable redemption date. 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
	Mar 31,	Dec 31,
($M)	2014	2013
Long-term debt	944,109	990,024
Current liabilities	409,070	347,444
Current assets	(386,869)	(587,783)
Net debt	966,310	749,685

Ratio of net debt to annualized fund flows from operations	1.2	1.1

Long-term debt as at March 31, 2014 decreased to $944.1 million from $990.0 million as a result of a repayment on the revolving credit facility of excess funds borrowed prior to December 31, 2013 in anticipation of the closing of our acquisition in Germany.

Net debt increased from $749.7 million to $966.3 million a result of the closing of our Germany acquisition in February of 2014 and current period capital expenditures. As fund flows from operations similarly increased, the ratio of net debt to annualized fund flows increased slightly to 1.2.

Shareholders' capital
Beginning with the January 2014 dividend paid on February 18, 2014, we increased our monthly dividend by 7.5%. This was our second consecutive annual increase.

During the three months ended March 31, 2014, we maintained monthly dividends at 0.215 per share and declared dividends totalled $66.0 million.

The following table outlines our dividend payment history:

Date											Monthly dividend per unit or share
January 2003 to December 2007											$0.17
January 2008 to December 2012											$0.19
January 2013 to December 31, 2013											$0.20
Beginning January 2014											$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 price commodity 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.

Over the next two years, we anticipate that Corrib, Cardium and other exploration and development activities will require significant capital investment. 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, 2013	102,123	1,618,443
Issuance of shares pursuant to the dividend reinvestment plan	319	18,885
Shares issued pursuant to the bonus plan	11	721
Balance as at March 31, 2014	102,453	1,638,049

As at March 31, 2014, there were approximately 1.6 million VIP awards outstanding. As at May 1, 2014, there were approximately 106.3 million shares outstanding.

ASSET RETIREMENT OBLIGATIONS

As at March 31, 2014, asset retirement obligations were $362.3 million compared to $326.2 million as at December 31, 2013.

The increase in asset retirement obligations is largely attributable to an overall decrease in the discount rates applied to the abandonment obligations and the impact of the weakening Canadian dollar on abandonment obligations denominated in foreign currencies.

OFF BALANCE SHEET ARRANGEMENTS

We have certain lease agreements that are entered into in the normal course of operations, all of which are operating leases and accordingly no asset or liability value has been assigned to the consolidated balance sheet as at March 31, 2014.

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, 2013.

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.

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

i.	Depletion and depreciation charges are based on estimates of total proven and probable reserves that Vermilion expects to recover in the future.
ii.	Asset retirement obligations are based on past experience and current economic factors which management believes are reasonable.
iii.	Impairment tests are performed at the cash generating unit (CGU) level, which is determined based on management's judgment. The calculation of the recoverable amount of a CGU is based on market factors as well as estimates of PNG reserves and future costs required to develop reserves.
iv.	Deferred tax amounts recognized in the consolidated financial statements are based on management's assessment of the tax positions at the end of each reporting period.

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 Mar 31, 2014			Three Months Ended Mar 31, 2013
	Oil & NGLs	Natural Gas	Total	Total
	$/bbl	$/mcf	$/boe	$/boe
Canada
Sales	95.25	5.50	69.26	57.61
Royalties	(10.75)	(0.34)	(7.12)	(6.19)
Transportation	(2.27)	(0.17)	(1.74)	(1.56)
Operating	(10.99)	(1.17)	(9.34)	(9.53)
Operating netback	71.24	3.82	51.06	40.33
General and administration			(1.61)	(2.11)
Fund flows from operations netback			49.45	38.22
France
Sales	117.54	-	117.54	107.17
Royalties	(7.35)	-	(7.35)	(6.00)
Transportation	(4.75)	-	(4.75)	(2.43)
Operating	(16.42)	-	(16.42)	(17.58)
Operating netback	89.02	-	89.02	81.16
General and administration			(5.19)	(5.01)
Current income taxes			(25.26)	(16.45)
Fund flows from operations netback			58.57	59.70
Netherlands
Sales	106.96	10.53	63.60	61.21
Royalties	-	(0.57)	(3.38)	-
Operating	-	(1.56)	(9.25)	(7.06)
Operating netback	106.96	8.40	50.97	54.15
General and administration			(0.91)	(0.73)
Current income taxes			(5.80)	(16.78)
Fund flows from operations netback			44.26	36.64
Germany
Sales	-	9.31	55.85	-
Royalties	-	(1.88)	(11.29)	-
Transportation	-	(0.44)	(2.64)	-
Operating	-	(1.62)	(9.74)	-
Operating netback	-	5.37	32.18	-
General and administration			(3.56)	-
Current income taxes			(3.36)	-
Fund flows from operations netback			25.26	-
Australia
Sales	127.26	-	127.26	120.76
Operating	(24.55)	-	(24.55)	(25.61)
PRRT⁽¹⁾	(28.63)	-	(28.63)	(19.27)
Operating netback	74.08	-	74.08	75.88
General and administration			(1.71)	(2.62)
Corporate income taxes			(12.51)	(12.46)
Fund flows from operations netback			59.86	60.80
Total Company
Sales	111.62	7.99	88.67	83.04
Realized hedging (loss) gain	0.26	0.21	0.61	(0.75)
Royalties	(6.72)	(0.60)	(5.59)	(4.24)
Transportation	(2.58)	(0.30)	(2.29)	(1.78)
Operating	(16.43)	(1.38)	(13.49)	(14.10)
PRRT⁽¹⁾	(7.36)	-	(4.71)	(2.99)
Operating netback	78.79	5.92	63.20	59.18
General and administration			(3.37)	(3.38)
Interest expense			(2.67)	(2.33)
Realized foreign exchange loss			(0.47)	(0.17)
Other income			0.05	0.13
Corporate income taxes⁽¹⁾			(8.98)	(9.54)
Fund flows from operations netback			47.76	43.89

⁽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 table summarizes Vermilion's outstanding risk management positions as at March 31, 2014:

Note

Volume

Strike Price(s)

Crude Oil

WTI - Swap

January 2014 - June 2014

250 bbl/d

100.05 USD $

January 2014 - June 2014

(1)

1,000 bbl/d

100.07 USD $

April 2014 - June 2014

2,500 bbl/d

108.13 CAD $

July 2014 - September 2014

1,250 bbl/d

108.53 CAD $

July 2014 - September 2014

(1)

250 bbl/d

99.55 USD $

Dated Brent - Collar

January 2014 - June 2014

1,250 bbl/d

103.20 - 110.24 USD $

April 2014 - June 2014

1,000 bbl/d

105.00 - 115.00 USD $

April 2014 - September 2014

1,000 bbl/d

105.00 - 112.00 USD $

April 2014 - December 2014

1,000 bbl/d

106.00 - 110.73 USD $

Dated Brent - Swap

January 2014 - June 2014

1,000 bbl/d

107.25 USD $

January 2014 - June 2014

(1)

1,500 bbl/d

110.32 USD $

April 2014 - June 2014

1,250 bbl/d

109.74 USD $

April 2014 - June 2014

(2)

350 bbl/d

111.75 USD $

January 2014 - December 2014

500 bbl/d

108.28 USD $

MSW - Fixed Price Differential (Physical)

April 2014 - June 2014

2,074 bbl/d

WTI less 7.38 USD $

April 2014 - December 2014

1,030 bbl/d

WTI less 8.20 USD $

July 2014 - December 2014

2,052 bbl/d

WTI less 8.68 USD $

MSW - Fixed Price Sale (Physical)

April 2014 - June 2014

1,000 bbl/d

92.85 CAD $

Canadian Natural Gas

AECO - Collar

January 2014 - December 2014

10,000 GJ/d

3.18 - 3.81 CAD $

April 2014 - December 2014

1,000 GJ/d

3.60 - 3.96 CAD $

April 2014 - March 2015

2,500 GJ/d

3.60 - 4.08 CAD $

November 2014 - March 2015

2,500 GJ/d

3.60 - 4.27 CAD $

AECO - Swap

April 2014 - October 2014

8,000 GJ/d

4.00 CAD $

January 2014 - December 2014

5,000 GJ/d

3.71 CAD $

European Natural Gas

TTF - Swap

February 2014 - June 2014

5,400 GJ/d

7.28 EUR €

March 2014 - September 2014

5,400 GJ/d

6.62 EUR €

April 2014 - September 2014

16,200 GJ/d

6.74 EUR €

Electricity

AESO - Swap

January 2014 - December 2014

7.2 MWh/d

54.75 CAD $

AESO - Swap (Physical)

January 2013 - December 2015

72.0 MWh/d

53.17 CAD $

US Dollar

USD - Collar

April 2014 - June 2014

2,000,000 USD $/month

1.080 - 1.167 CAD $

USD - Forward

April 2014 - June 2014

2,000,000 USD $/month

1.116 CAD $

⁽¹⁾	Prior to the expiration of this swap, the counterparty has the option to extend the swap to December 31, 2014 at the contracted volume and price.
⁽²⁾	Prior to the expiration of this swap, the counterparty has the option to extend the swap to September 30, 2014 at the contracted volume and price.

Supplemental Table 3: Capital expenditures

	Three Months Ended
By classification	Mar 31,	Dec 31,	Mar 31,
($M)	2014	2013	2013
Drilling and development	168,840	147,929	179,520
Dispositions	-	-	(8,627)
Exploration and evaluation	27,535	549	9,576
Capital expenditures	196,375	148,478	180,469
Property acquisition	178,227	1,603	-
Corporate acquisition	-	27,500	-
Acquisitions	178,227	29,103	-

	Three Months Ended
By category	Mar 31,	Dec 31,	Mar 31,
($M)	2014	2013	2013
Land	4,753	2,676	3,129
Seismic	3,432	1,942	3,813
Drilling and completion	106,536	68,993	126,185
Production equipment and facilities	68,755	63,420	49,942
Recompletions	4,226	3,309	4,131
Other	8,673	8,138	1,896
Dispositions	-	-	(8,627)
Capital expenditures	196,375	148,478	180,469
Acquisitions	178,227	29,103	-
Total capital expenditures and acquisitions	374,602	177,581	180,469

	Three Months Ended
By country	Mar 31,	Dec 31,	Mar 31,
($M)	2014	2013	2013
Canada	119,707	78,848	85,129
France	37,967	31,899	21,592
Netherlands	20,118	43,198	372
Germany	173,067	-	-
Ireland	16,236	14,472	16,520
Australia	5,691	8,420	55,349
Corporate	1,816	744	1,507
Total capital expenditures and acquisitions	374,602	177,581	180,469

Supplemental Table 4: Production

		Q1/14	Q4/13	Q3/13	Q2/13	Q1/13	Q4/12	Q3/12	Q2/12	Q1/12	Q4/11	Q3/11	Q2/11
Canada
	Crude oil (bbls/d)	9,437	8,719	7,969	8,885	7,966	7,983	7,322	7,757	7,574	6,591	4,526	3,856
	NGLs (bbls/d)	2,071	1,699	1,897	1,725	1,335	1,106	1,204	1,321	1,302	1,246	1,305	1,353
	Natural gas (mmcf/d)	49.53	41.43	43.40	43.69	41.04	31.41	35.54	41.32	41.83	43.96	42.94	43.30
	Total (boe/d)	19,763	17,322	17,099	17,892	16,140	14,323	14,449	15,965	15,848	15,163	12,987	12,426
	% of consolidated	42%	43%	41%	42%	41%	40%	40%	40%	40%	41%	38%	35%
France
	Crude oil (bbls/d)	10,771	11,131	11,625	10,390	10,330	9,843	9,767	9,931	10,270	7,819	7,946	8,273
	Natural gas (mmcf/d)	-	-	5.23	4.19	4.21	3.91	3.39	3.57	3.48	0.94	0.97	0.88
	Total (boe/d)	10,771	11,131	12,496	11,088	11,032	10,495	10,333	10,526	10,850	7,976	8,108	8,419
	% of consolidated	23%	27%	30%	26%	29%	29%	28%	27%	28%	22%	23%	24%
Netherlands
	NGLs (bbls/d)	69	62	48	50	96	70	41	84	72	66	64	54
	Natural gas (mmcf/d)	43.15	37.53	28.78	38.52	36.91	33.03	34.59	33.74	35.08	34.58	33.15	33.77
	Total (boe/d)	7,260	6,318	4,845	6,470	6,248	5,574	5,806	5,707	5,919	5,829	5,589	5,682
	% of consolidated	16%	15%	12%	15%	16%	15%	16%	15%	15%	16%	16%	16%
Germany
	Natural gas (mmcf/d)	10.64	-	-	-	-	-	-	-	-	-	-	-
	Total (boe/d)	1,773	-	-	-	-	-	-	-	-	-	-	-
	% of consolidated	4%	-	-	-	-	-	-	-	-	-	-	-
Australia
	Crude oil (bbls/d)	7,110	6,189	7,070	7,363	5,287	5,873	5,958	6,970	6,648	7,686	7,992	8,692
	% of consolidated	15%	15%	17%	17%	14%	16%	16%	18%	17%	21%	23%	25%
Consolidated
	Crude oil & NGLs (bbls/d)	29,458	27,800	28,609	28,413	25,014	24,875	24,292	26,063	25,866	23,408	21,833	22,228
	% of consolidated	63%	68%	69%	66%	65%	69%	66%	67%	66%	64%	63%	63%
	Natural gas (mmcf/d)	103.32	78.96	77.41	86.40	82.16	68.34	73.52	78.63	80.39	79.48	77.06	77.95
	% of consolidated	37%	32%	31%	34%	35%	31%	34%	33%	34%	36%	37%	37%
	Total (boe/d)	46,677	40,960	41,510	42,813	38,707	36,265	36,546	39,168	39,265	36,654	34,676	35,219

		YTD 2014	2013	2012	2011	2010	2009
Canada
	Crude oil (bbls/d)	9,437	8,387	7,659	4,701	2,778	2,137
	NGLs (bbls/d)	2,071	1,666	1,232	1,297	1,427	1,518
	Natural gas (mmcf/d)	49.53	42.39	37.50	43.38	43.91	47.85
	Total (boe/d)	19,763	17,117	15,142	13,227	11,524	11,629
	% of consolidated	42%	41%	40%	38%	36%	37%
France
	Crude oil (bbls/d)	10,771	10,873	9,952	8,110	8,347	8,246
	Natural gas (mmcf/d)	-	3.40	3.59	0.95	0.92	1.05
	Total (boe/d)	10,771	11,440	10,550	8,269	8,501	8,421
	% of consolidated	23%	28%	28%	23%	26%	27%
Netherlands
	NGLs (bbls/d)	69	64	67	58	35	23
	Natural gas (mmcf/d)	43.15	35.42	34.11	32.88	28.31	21.06
	Total (boe/d)	7,260	5,967	5,751	5,538	4,753	3,533
	% of consolidated	16%	15%	15%	16%	15%	11%
Germany
	Natural gas (mmcf/d)	10.64	-	-	-	-	-
	Total (boe/d)	1,773	-	-	-	-	-
	% of consolidated	4%	-	-	-	-	-
Australia
	Crude oil (bbls/d)	7,110	6,481	6,360	8,168	7,354	7,812
	% of consolidated	15%	16%	17%	23%	23%	25%
Consolidated
	Crude oil & NGLs (bbls/d)	29,458	27,471	25,270	22,334	19,941	19,735
	% of consolidated	63%	67%	67%	63%	62%	63%
	Natural gas (mmcf/d)	103.32	81.21	75.20	77.21	73.14	69.96
	% of consolidated	37%	33%	33%	37%	38%	37%
	Total (boe/d)	46,677	41,005	37,803	35,202	32,132	31,395

Supplemental Table 5: Segmented Financial Results

	Three Months Ended March 31, 2014
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Total assets	1,287,169	955,096	237,795	181,130	799,381	298,306	132,261	3,891,138
Drilling and development	101,673	29,853	15,191	196	16,236	5,691	-	168,840
Exploration and evaluation	13,266	8,114	4,927	-	-	-	1,228	27,535
Oil and gas sales to external customers	123,180	117,560	41,554	8,915	-	89,974	-	381,183
Royalties	(12,663)	(7,351)	(2,208)	(1,802)	-	-	-	(24,024)
Revenue from external customers	110,517	110,209	39,346	7,113	-	89,974	-	357,159
Transportation expense	(3,098)	(4,753)	-	(422)	(1,588)	-	-	(9,861)
Operating expense	(16,610)	(16,420)	(6,042)	(1,554)	-	(17,360)	-	(57,986)
General and administration	(2,868)	(5,194)	(598)	(568)	(282)	(1,206)	(3,751)	(14,467)
PRRT	-	-	-	-	-	(20,239)	-	(20,239)
Corporate income taxes	-	(25,264)	(3,788)	(537)	-	(8,841)	(173)	(38,603)
Interest expense	-	-	-	-	-	-	(11,460)	(11,460)
Realized gain on derivative instruments	-	-	-	-	-	-	2,640	2,640
Realized foreign exchange loss	-	-	-	-	-	-	(2,041)	(2,041)
Realized other income	-	-	-	-	-	-	221	221
Fund flows from operations	87,941	58,578	28,918	4,032	(1,870)	42,328	(14,564)	205,363

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 months ended March 31, 2014, 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

Mar 31,

Dec 31,

Mar 31,

($M)

2014

2013

Cash flows from operating activities

178,238

177,003

190,712

Changes in non-cash operating working capital

24,474

(18,769)

(28,471)

Asset retirement obligations settled

2,651

5,426

1,388

Fund flows from operations

205,363

163,660

163,629

Expenses related to Corrib

1,870

839

1,855

Fund flows from operations (excluding Corrib)

207,233

164,499

165,484

Three Months Ended

Mar 31,

Dec 31,

Mar 31,

($M)

2014

2013

Dividends declared

66,007

61,208

59,612

Issuance of shares pursuant to the dividend reinvestment plan

(18,885)

(18,775)

(15,532)

Net dividends

47,122

42,433

44,080

Drilling and development

168,840

147,929

179,520

Dispositions

(8,627)

Exploration and evaluation

27,535

549

9,576

Asset retirement obligations settled

2,651

5,426

1,388

Payout

246,148

196,337

225,937

Payout relating to Corrib

(16,236)

(14,472)

(16,520)

Payout (excluding Corrib)

229,912

181,865

209,417

As At

Mar 31,

Dec 31,

Mar 31,

('000s of shares)

2014

2013

Shares outstanding

102,453

102,123

99,462

Potential shares issuable pursuant to the VIP

2,714

2,746

2,918

Diluted shares outstanding

105,167

104,869

102,380

CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

March 31,

December 31,

Note

2014

2013

ASSETS

Current

Cash and cash equivalents

151,337

389,559

Accounts receivable

199,606

167,618

Crude oil inventory

14,121

17,143

Derivative instruments

9,533

2,285

Prepaid expenses

12,272

11,178

386,869

587,783

Deferred taxes

181,800

184,832

Exploration and evaluation assets

179,380

136,259

Capital assets

3,143,089

2,799,845

3,891,138

3,708,719

LIABILITIES

Current

Accounts payable and accrued liabilities

283,008

267,832

Dividends payable

22,027

20,425

Derivative instruments

6,885

3,572

Income taxes payable

97,150

55,615

409,070

347,444

Long-term debt

944,109

990,024

Asset retirement obligations

362,261

326,162

Deferred taxes

344,046

328,714

2,059,486

1,992,344

SHAREHOLDERS' EQUITY

Shareholders' capital

1,638,049

1,618,443

Contributed surplus

88,782

75,427

Accumulated other comprehensive income

92,677

47,142

Retained earnings (deficit)

12,144

(24,637)

1,831,652

1,716,375

3,891,138

3,708,719

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

Three Months Ended

March 31,

Note

2014

2013

REVENUE

Petroleum and natural gas sales

381,183

309,576

Royalties

(24,024)

(15,790)

Petroleum and natural gas revenue

357,159

293,786

EXPENSES

Operating

57,986

52,575

Transportation

9,861

6,641

Equity based compensation

16,472

16,136

(Gain) loss on derivative instruments

(6,575)

3,900

Interest expense

11,460

8,689

General and administration

14,467

12,610

Foreign exchange (gain) loss

(19,959)

3,136

Other expense (income)

(67)

Accretion

5,712

5,824

Depletion and depreciation

4, 5

99,452

81,448

188,909

190,892

EARNINGS BEFORE INCOME TAXES

168,250

102,894

INCOME TAXES

Deferred

6,620

4,047

Current

58,842

46,710

65,462

50,757

NET EARNINGS

102,788

52,137

OTHER COMPREHENSIVE INCOME (LOSS)

Currency translation adjustments

45,535

(1,332)

COMPREHENSIVE INCOME

148,323

50,805

NET EARNINGS PER SHARE

Basic

1.00

0.53

Diluted

0.99

0.51

WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)

Basic

102,278

99,301

Diluted

104,171

101,349

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

Three Months Ended

March 31,

Note

2014

2013

OPERATING

Net earnings

102,788

52,137

Adjustments:

Accretion

5,712

5,824

Depletion and depreciation

4, 5

99,452

81,448

Unrealized (gain) loss on derivative instruments

(3,935)

1,113

Equity based compensation

16,472

16,136

Unrealized foreign exchange (gain) loss

(22,000)

2,519

Unrealized other expense

254

405

Deferred taxes

6,620

4,047

Asset retirement obligations settled

(2,651)

(1,388)

Changes in non-cash operating working capital

(24,474)

28,471

Cash flows from operating activities

178,238

190,712

INVESTING

Drilling and development

(168,840)

(179,520)

Exploration and evaluation

(27,535)

(9,576)

Property acquisitions

4, 5

(178,227)

Dispositions

8,627

Changes in non-cash investing working capital

39,473

38,210

Cash flows used in investing activities

(335,129)

(142,259)

FINANCING

(Decrease) increase in long-term debt

(50,000)

69,429

Cash dividends

(45,520)

(43,024)

Cash flows (used in) from financing activities

(95,520)

26,405

Foreign exchange gain (loss) on cash held in foreign currencies

14,189

(470)

Net change in cash and cash equivalents

(238,222)

74,388

Cash and cash equivalents, beginning of period

389,559

102,125

Cash and cash equivalents, end of period

151,337

176,513

Supplementary information for operating activities - cash payments

Interest paid

14,094

12,092

Income taxes paid

21,074

32,635

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

						Accumulated
							Other			Total
		Shareholders'		Contributed		Comprehensive				Shareholders'
	Note	Capital		Surplus			Loss	Deficit		Equity
Balances as at January 1, 2013			1,481,345		69,581		(32,409)		(99,871)		1,418,646
Net earnings			-		-		-		52,137		52,137
Currency translation adjustments			-		-		(1,332)		-		(1,332)
Equity based compensation expense	9		-		15,507		-		-		15,507
Dividends declared	8		-		-		-		(59,612)		(59,612)
Issuance of shares pursuant to the
dividend reinvestment plan	8		15,532		-		-		-		15,532
Shares issued pursuant to the bonus plan	8		629		-		-		-		629
Balances as at March 31, 2013			1,497,506		85,088		(33,741)		(107,346)		1,441,507

						Accumulated
							Other			Total
		Shareholders'		Contributed		Comprehensive		Retained		Shareholders'
	Note	Capital		Surplus			Income	Earnings		Equity
Balances as at January 1, 2014			1,618,443		75,427		47,142		(24,637)		1,716,375
Net earnings			-		-		-		102,788		102,788
Currency translation adjustments			-		-		45,535		-		45,535
Equity based compensation expense	9		-		15,751		-		-		15,751
Dividends declared	8		-		-		-		(66,007)		(66,007)
Issuance of shares pursuant to the
dividend reinvestment plan	8		18,885		-		-		-		18,885
Modification of equity based awards	9		-		(2,396)						(2,396)
Share-settled dividends
Shares issued pursuant to the bonus plan	8		721		-		-		-		721
Balances as at March 31, 2014			1,638,049		88,782		92,677		12,144		1,831,652

DESCRIPTION OF EQUITY RESERVES

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

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

Accumulated other comprehensive income
Represents the cumulative income and expenses which are not recorded immediately in net earnings 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.

Retained earnings (deficit)
Represents the cumulative net earnings less distributed earnings of Vermilion Energy Inc.

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013
(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, 2013, except as discussed in Note 2.

These condensed consolidated interim financial statements should be read in conjunction with Vermilion's consolidated financial statements for the year ended December 31, 2013, which are contained within Vermilion's Annual Report for the year ended December 31, 2013 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 May 1, 2014.

2. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

On January 1, 2014, Vermilion adopted the following pronouncements as issued by the IASB. The adoption of these standards did not have a material impact on Vermilion's consolidated financial statements.

IFRIC 21 "Levies"
On May 20, 2013, IASB issued guidance under IFRIC 21, which provides clarification on accounting for levies in accordance with the requirements of IAS 37, Provisions, Contingent Liabilities and Contingent Assets. The interpretation defines a levy as an outflow from an entity imposed by a government in accordance with legislation and confirms that a liability for a levy is recognized only when the triggering event specified in the legislation occurs. The interpretation is effective for annual periods beginning on or after January 1, 2014.

IAS 36 "Impairment of Assets"
On May 29, 2013, the IASB issued amendments to IAS 36 "Impairment of Assets" which reduce the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. This amendment is effective for annual periods beginning on or after January 1, 2014.

3. BUSINESS COMBINATIONS

Property acquisition:

Germany

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

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

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

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

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

The results of operations from the assets acquired have been included in Vermilion's consolidated financial statements beginning February of 2014 and have contributed revenues of $7.1 million and net earnings $0.2 million for the three months ended March 31, 2014.

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

4. 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, 2013	2,430,121	15,119	2,445,240
Additions	531,760	5,804	537,564
Transfers from exploration and evaluation assets	1,508	-	1,508
Corporate acquisitions	47,743	-	47,743
Dispositions	(8,627)	-	(8,627)
Changes in estimate for asset retirement obligations	(91,527)	-	(91,527)
Depletion and depreciation	(310,370)	(6,138)	(316,508)
Impairments	47,400	-	47,400
Effect of movements in foreign exchange rates	136,626	426	137,052
Balance at December 31, 2013	2,784,634	15,211	2,799,845
Additions	166,262	2,578	168,840
Property acquisitions	163,786	-	163,786
Changes in estimate for asset retirement obligations	17,940	-	17,940
Depletion and depreciation	(94,415)	(978)	(95,393)
Effect of movements in foreign exchange rates	87,758	313	88,071
Balance at March 31, 2014	3,125,965	17,124	3,143,089

5. 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, 2013						117,161
Additions						13,789
Property acquisitions						9,189
Transfers to petroleum and natural gas assets						(1,508)
Depreciation						(3,712)
Effect of movements in foreign exchange rates						1,340
Balance at December 31, 2013						136,259
Additions						27,535
Changes in estimate for asset retirement obligations						73
Property acquisitions						16,475
Depreciation						(2,076)
Effect of movements in foreign exchange rates						1,114
Balance at March 31, 2014						179,380

6. ASSET RETIREMENT OBLIGATIONS

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

($M)															Asset Retirement Obligations
Balance at January 1, 2013															371,063
Additional obligations recognized															15,655
Changes in estimates for existing obligations															(21,068)
Obligations settled															(11,922)
Accretion															24,565
Changes in discount rates															(73,675)
Effect of movements in foreign exchange rates															21,544
Balance at December 31, 2013															326,162
Additional obligations recognized															4,911
Obligations settled															(2,651)
Accretion															5,712
Changes in discount rates															15,132
Effect of movements in foreign exchange rates															12,995
Balance at March 31, 2014															362,261

7. LONG-TERM DEBT

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

As At

($M)

Mar 31, 2014

Dec 31, 2013

Revolving credit facility

720,762

766,898

Senior unsecured notes

223,347

223,126

Long-term debt

944,109

990,024

Revolving Credit Facility

At March 31, 2014, Vermilion had in place a bank revolving credit facility totalling $1.2 billion, of which approximately $720.8 million was drawn. The facility, which matures on May 31, 2016, 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 three 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 repayable on the maturity date. This facility bears interest at a rate applicable to demand loans plus applicable margins. For the three months ended March 31, 2014, the interest rate on the revolving credit facility was approximately 3.3%.

The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $8.4 million as at March 31, 2014 (December 31, 2013 - $8.1 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. In addition, Vermilion must maintain 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.

As at March 31, 2014, Vermilion was in compliance with its 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 notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the applicable redemption date. 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%.

8. 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, 2013	99,135	1,481,345
Issuance of shares pursuant to the dividend reinvestment plan	1,402	72,291
Vesting of equity based awards	1,372	54,370
Share-settled dividends on vested equity based awards	202	9,808
Shares issued pursuant to the bonus plan	12	629
Balance as at December 31, 2013	102,123	1,618,443
Issuance of shares pursuant to the dividend reinvestment plan	319	18,885
Shares issued pursuant to the bonus plan	11	721
Balance as at March 31, 2014	102,453	1,638,049

Dividends declared to shareholders for the three months ended March 31, 2014 were $66.0 million (2013 - $59.6 million).

Subsequent to the end of the period and prior to the condensed consolidated interim financial statements being authorized for issue on May 1, 2014, Vermilion declared dividends totalling $22.0 million or 0.215 per share.

9. EQUITY BASED COMPENSATION

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

Number of Awards ('000s)

2014

2013

Opening balance

1,665

1,690

Granted

832

Vested

(749)

Modified

(21)

Forfeited

(8)

(108)

Closing balance

1,636

1,665

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.

On March 31, 2014, Vermilion modified the accounting for certain outstanding VIP awards to be settled by purchasing Vermilion common shares on the Toronto Stock Exchange upon vesting rather than by issuing common shares through treasury. Pursuant to this modification, $2.4 million was reclassified from "Contributed surplus" to "Accounts payable and accrued liabilities". Subsequent period expense relating to these outstanding awards will be recognized in "General and administration expense".

10. SEGMENTED INFORMATION

Vermilion has operations principally in Canada, France, the Netherlands, Germany, Ireland, 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 our 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 March 31, 2014
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Total assets	1,287,169	955,096	237,795	181,130	799,381	298,306	132,261	3,891,138
Drilling and development	101,673	29,853	15,191	196	16,236	5,691	-	168,840
Exploration and evaluation	13,266	8,114	4,927	-	-	-	1,228	27,535
Oil and gas sales to external customers	123,180	117,560	41,554	8,915	-	89,974	-	381,183
Royalties	(12,663)	(7,351)	(2,208)	(1,802)	-	-	-	(24,024)
Revenue from external customers	110,517	110,209	39,346	7,113	-	89,974	-	357,159
Transportation expense	(3,098)	(4,753)	-	(422)	(1,588)	-	-	(9,861)
Operating expense	(16,610)	(16,420)	(6,042)	(1,554)	-	(17,360)	-	(57,986)
General and administration	(2,868)	(5,194)	(598)	(568)	(282)	(1,206)	(3,751)	(14,467)
PRRT	-	-	-	-	-	(20,239)	-	(20,239)
Corporate income taxes	-	(25,264)	(3,788)	(537)	-	(8,841)	(173)	(38,603)
Interest expense	-	-	-	-	-	-	(11,460)	(11,460)
Realized gain on derivative instruments	-	-	-	-	-	-	2,640	2,640
Realized foreign exchange loss	-	-	-	-	-	-	(2,041)	(2,041)
Realized other income	-	-	-	-	-	-	221	221
Fund flows from operations	87,941	58,578	28,918	4,032	(1,870)	42,328	(14,564)	205,363

	Three Months Ended March 31, 2013
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Total assets	1,159,807	842,756	140,269	-	588,777	342,107	130,081	3,203,797
Drilling and development	82,741	21,592	1,999	-	16,520	55,349	1,319	179,520
Exploration and evaluation	9,388	-	-	-	-	-	188	9,576
Oil and gas sales to external customers	83,688	121,566	34,421	-	-	69,901	-	309,576
Royalties	(8,989)	(6,801)	-	-	-	-	-	(15,790)
Revenue from external customers	74,699	114,765	34,421	-	-	69,901	-	293,786
Transportation expense	(2,269)	(2,754)	-	-	(1,618)	-	-	(6,641)
Operating expense	(13,841)	(19,939)	(3,969)	-	-	(14,826)	-	(52,575)
General and administration	(3,069)	(5,686)	(412)	-	(237)	(1,518)	(1,688)	(12,610)
PRRT	-	-	-	-	-	(11,153)	-	(11,153)
Corporate income taxes	-	(18,659)	(9,434)	-	-	(7,213)	(251)	(35,557)
Interest expense	-	-	-	-	-	-	(8,689)	(8,689)
Realized loss on derivative instruments	-	-	-	-	-	-	(2,787)	(2,787)
Realized foreign exchange loss	-	-	-	-	-	-	(617)	(617)
Realized other income	-	-	-	-	-	-	472	472
Fund flows from operations	55,520	67,727	20,606	-	(1,855)	35,191	(13,560)	163,629

Reconciliation of fund flows from operations to net earnings

Three Months Ended

($M)

Mar 31, 2014

Mar 31, 2013

Fund flows from operations

205,363

163,629

Equity based compensation

(16,472)

(16,136)

Unrealized gain (loss) on derivative instruments

3,935

(1,113)

Unrealized foreign exchange gain (loss)

22,000

(2,519)

Unrealized other expense

(254)

(405)

Accretion

(5,712)

(5,824)

Depletion and depreciation

(99,452)

(81,448)

Deferred taxes

(6,620)

(4,047)

Net earnings

102,788

52,137

11. CAPITAL DISCLOSURES

	Three Months Ended
($M except as indicated)	Mar 31, 2014	Mar 31, 2013
Long-term debt	944,109	712,763
Current liabilities	409,070	391,708
Current assets	(386,869)	(359,709)
Net debt [1]	966,310	744,762

Cash flows from operating activities	178,238	190,712
Changes in non-cash operating working capital	24,474	(28,471)
Asset retirement obligations settled	2,651	1,388
Fund flows from operations	205,363	163,629
Annualized fund flows from operations [2]	821,452	654,516

Ratio of net debt to annualized fund flows from operations ([1] ÷ [2])	1.2	1.1

The ratio of net debt to annualized fund flows from operations for the three months ended March 31, 2014 was relatively consistent with same period in 2013 as fund flows from operations increased proportionately with net debt.

The increase in net debt was the result of the current year capital expenditures pertaining to the Ireland assets, which are currently under development, and acquisitions in the Netherlands and Germany during the fourth quarter of 2013 and the first quarter of 2014.

12. FINANCIAL INSTRUMENTS

Classification of Financial Instruments

The following table summarizes information relating to Vermilion's financial instruments as at March 31, 2014 and December 31, 2013:

As at Mar 31, 2014

As at Dec 31, 2013

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

151,337

389,559

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

199,606

167,618

Not applicable

Derivative assets

Derivative instruments

HFT

(Gain) loss on derivative instruments

9,533

2,285

Level 2

Derivative liabilities

Derivative instruments

HFT

(Gain) loss on derivative instruments

(6,885)

(3,572)

Level 2

Payables

Accounts payable and
accrued liabilities

OTH

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

(305,035)

(288,257)

Not applicable

Dividends payable

Long-term debt

OTH

Interest expense

(944,109)

(953,075)

(990,024)

(998,648)

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 three months ended March 31, 2014 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	Mar 31, 2014
Currency risk - Euro to Canadian	Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates	(3,615)

	Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates	3,615

Currency risk - US $ to Canadian	Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates	(4,105)

	Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates	4,105

Commodity price risk	Increase in relevant oil reference price within option pricing models used to determine	(9,312)
	the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates

	Decrease in relevant oil reference price within option pricing models used to determine	8,731
	the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates

Interest rate risk	Increase in average Canadian prime interest rate by 100 basis points during the relevant periods	(1,920)

	Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods	1,920

13. SUBSEQUENT EVENTS

Arrangement agreement with a private southeast Saskatchewan producer

On March 18, 2014, Vermilion announced that it entered into an arrangement agreement to acquire Elkhorn Resources Inc., a private southeast Saskatchewan producer. On April 29, 2014, Vermilion announced completion of the acquisition for total consideration of $427 million. Total consideration comprised the assumption of an estimated $42 million of debt, $180 million of cash, and the issuance of 2.8 million common shares of Vermilion valued at approximately $205 million (based on the closing price per Vermilion common share of $72.50 on the Toronto Stock Exchange on April 29, 2014).

Given the recent timing of the acquisition, the Company has not yet completed the accounting for the acquisition and accordingly not all relevant disclosures are available for the business combination. The Company will report the purchase price allocation in the Company's condensed consolidated interim financial statements for the three and six months ended June 30, 2014.

Amendment of revolving credit facility agreement

Subsequent to March 31, 2014, Vermilion amended its revolving credit facility agreement. The amended revolving credit facility increases the total committed facility amount to $1.50 billion and extends the facility maturity date to May 31, 2017. In addition, Vermilion may, by adding lenders or by seeking an increase to an existing lender's commitment, increase the total committed facility amount to no more than $1.75 billion. The amended revolving credit facility includes an additional financial covenant requiring that the ratio of consolidated total senior debt to total capitalization be less than 50%. Total capitalization includes all amounts on Vermilion's balance sheet classified as "Long-term debt" and "Shareholders' Equity". As at March 31, 2014, Vermilion had a ratio of consolidated total senior debt to total capitalization of 25.9%.

SOURCE Vermilion Energy Inc.

Lorenzo Donadeo, Chief Executive Officer;
Anthony Marino, President & COO;
Curtis W. Hicks, Executive VP & CFO; and/or
Dean Morrison, Director Investor Relations
TEL (403) 269-4884
IR TOLL FREE 1-866-895-8101
investor_relations@vermilionenergy.com
www.vermilionenergy.com

Canada Newswire

May 2, 2014 - 2:10 AM EDT

Become a member today, It's free!

Vermilion Energy Inc. Announces Results for the Three Months Ended March 31, 2014

Related News

@ the Bell: Markets hover near all-time highs

@ the Bell: Dow Jones reaches 40,000 milestone

@ the Bell: U.S. markets hit record highs

Recent U.S. Press Releases

Genesis Land Development Corp. Announces Sale of 40% of Huxley Development in Calgary

Andora Completes Acquisition of Additional Sawn Lake Assets from Receivership

Dye & Durham Announces Commencement of Issuer Bid

Featured News Links

Drilling Approval Received for New Mexico Lithium Project

GameSquare Announces Formation of FaZe Media, Backed by $11M Investment

Xcyte Digital Corp. Releases "Xperience" Subscription Service

Become a member today, It's free!

Sign In

Send my password

Become a member today, It's free!

Vermilion Energy Inc. Announces Results for the Three Months Ended March 31, 2014

Related News

Recent U.S. Press Releases

Featured News Links