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

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 20th 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 20th 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 5th 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 13th 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 10th 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

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 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