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Vermilion Energy Inc. Announces Results for the Three Months Ended March 31, 2015

May 8, 2015

CALGARY, May 8, 2015 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three months ended March 31, 2015.

HIGHLIGHTS

  • Achieved average production of 50,386 boe/d during the first quarter of 2015, an increase of 2% as compared to 49,571 boe/d in the prior quarter, and 8% versus 46,677 boe/d during the first quarter of 2014.  Production increased in Canada, France and the Netherlands from the previous quarter due to successful drilling, workover and tie-in activity, more than offsetting mid-stream restrictions in Canada and modest decreases in production in other business units.  We continue to manage Australian production to maximize proceeds during this period of lower oil prices.        

  • Fund flows from operations ("FFO")(1) for Q1 2015 of $120.8 million ($1.12/basic share) represented a decrease of 35% quarter-over-quarter and 41% year-over-year.  The decrease in FFO was attributable to lower commodity prices and inventory builds (due to the timing of crude liftings in France and Australia), partially offset by lower operating expenses from our ongoing cost reduction program and a recovery of costs in France.

  • Concluded the successful drilling of a four (4.0 net) well program in France at our Champotran field in the Paris Basin.  Subsequent to Q1 2015, all four wells have been tied-in and are currently producing at a combined average production rate of approximately 980 bbls/d.  This was our third successive drilling program since 2013, comprising a total of 13 wells at Champotran, with a 100% drilling success rate.   

  • Initiated production from our Langezwaag-02 well in the Netherlands at a facility-limited rate of 4.0 mmcf/d from the Zechstein formation.  This discovery well on the Gorredijk concession was part of our 2014 drilling program.  Subsequent to the end of the Q1 2015, we reached total depth and logged the first well in our 2015 Netherlands drilling program.  Based on electric logs, the Slootdorp-06 well in the province of North Holland (93% working interest), is a field-extending discovery, logging 71 metres of gross gas column in the Rotliegend Sand.  Production from the Slootdorp-06 well is expected to commence in the second half of 2015.

  • Our Corrib project in Ireland has continued to progress as expected.  Project operator Shell E&P Ireland Limited ("SEPIL") is systematically preparing gas compression and other systems at the Bellanaboy gas processing terminal for the processing of offshore gas production from the field.  The Irish Environmental Protection Agency issued its Proposed Determination for the Corrib Industrial Emissions License ("IEL") in April.  Based on remaining terminal activities and typical approval timelines for the final form of the IEL, we estimate that the most likely date for start-up is approximately mid-year, with a modest range of outcomes around that estimate.  Production at Corrib is expected to increase over the first few months toward peak production levels estimated at approximately 58 mmcf/d (approximately 9,700 boe/d), net to Vermilion.

  • Despite a 40% reduction in planned capital spending for 2015 as compared to 2014, we are maintaining our original production guidance of between 55,000 and 57,000 boe/d. There is also no change to our 2015 capital spending guidance of $415 million.

  • To further enhance the long-term and sustainable profitability of our business in the current environment, we are also directing considerable focus to our Profitability Enhancement Program ("PEP") initiative.  Prior installments of PEP achieved strong results in both the 1998 industry downturn and the financial crisis of 2008-2009.  Based on savings identified to-date, our third installment of PEP will result in cost reductions estimated at between $50 and $60 million for full-year 2015 in capital spending, operating expense and G&A.  This is reflected in unit operating expense for Q1 2015 that is down 15% quarter-over-quarter, and down 22% year-over-year.

  • Subsequent to Q1 2015, we negotiated a further expansion and extension of our existing revolving credit facilities from $1.75 billion to $2 billion.  In Q1 2015, we had previously increased our credit facility from $1.5 billion to $1.75 billion.  After the most recent expansion to our credit facility, we have approximately $820 million of borrowing capacity available.  The facility, which matures in May 2019, is fully revolving up to the date of maturity and is subject to standard form covenants.  We are, and expect to continue to be, in compliance with all applicable debt covenants and maintain our current dividend of $0.215 per share per month ($2.58 per share per year).

  • During Q1 2015, Vermilion was awarded a judgment in the amount of €25 million for the costs incurred as a result of an oil spill at the Ambès oil terminal in France that occurred in 2007.  Vermilion expects to receive 50% of the judgment in Q2 2015, with the remainder due upon conclusion of the appeal process.  Based on the recent court decision and the conclusions of the expert engaged by the French court, Vermilion is highly confident that the award will be upheld.

  • Subsequent to Q1 2015, Vermilion was recognized by the Great Place to Work® Institute as a Best Workplace in Canada and France for the sixth consecutive year.  Vermilion was also recognized for a second consecutive year as a Best Workplace in the Netherlands in 2015, after becoming eligible for ranking in 2014.  Vermilion is the only energy company in the medium sized category to rank on the Best Workplaces lists in Canada and the Netherlands, and the highest scoring energy company on the Best Workplaces list in France. These Great Place to Work awards are a reflection of Vermilion's strong corporate culture which is a key driver of Vermilion's long-term strong corporate performance.

  • In addition, Vermilion was recently ranked 15th by Corporate Knights on the Future 40 Responsible Corporate Leaders in Canada list (the highest ranking for an oil and gas company, and an increase over the Company's debut ranking of 32nd last year), as well as being named Top International Producer of the year by The Explorers and Producers Association of Canada.  This recognition reflects Vermilion's continued focus on financial results combined with exemplary environmental, social and governance performance. Strong workplace practices and a culture that respects both people and communities are key elements in our success. Please refer to our Sustainability Report at http://sustainability.vermilionenergy.com/ for more information about our environmental and social stewardship.
(1)  Additional GAAP Financial Measure.  Please see the "Additional and Non-GAAP Financial Measures" section of Management's Discussion and Analysis.

ANNUAL GENERAL MEETING WEBCAST

As Vermilion's Annual General Shareholders Meeting is being held today, May 8, 2015 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=975216&s=1&k=8EF642AF4951C1D3776D76241E30DC52  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 position and business objectives and the information may not be appropriate for other purposes.  Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information.  These risks and uncertainties include but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids and natural gas prices, foreign currency exchange rates and interest rates; health, safety and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.

The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.

All oil and natural gas reserve information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.  The actual 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

$M    thousand dollars
$MM    million dollars
AECO    the daily average benchmark price for natural gas at the AECO 'C' hub in southeast Alberta
bbl(s)    barrel(s)
bbls/d    barrels per day
bcf    billion cubic feet
boe    barrel of oil equivalent, including: crude oil, natural gas liquids and natural gas (converted on the basis of one boe for
    six mcf of natural gas)
boe/d    barrel of oil equivalent per day
GJ    gigajoules
HH    Henry Hub, a reference price paid for natural gas in US dollars at Erath, Louisiana
mbbls    thousand barrels
mboe    thousand barrel of oil equivalent
mcf    thousand cubic feet
mcf/d    thousand cubic feet per day
mmboe    million barrel of oil equivalent
mmcf    million cubic feet
mmcf/d    million cubic feet per day
MWh    megawatt hour
NGLs    natural gas liquids
PRRT    Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia
TTF    the day-ahead price for natural gas in the Netherlands, quoted in MWh of natural gas, at the Title Transfer Facility
    Virtual Trading Point operated by Dutch TSO Gas Transport Services
WTI    West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma

MESSAGE TO SHAREHOLDERS   

While crude oil indices have risen from the 5-year lows reached during Q1 2015, the global price environment for crude oil remained depressed as we exited the first quarter of 2015.  Although this price environment poses significant challenges for many energy sector participants, Vermilion remains comparatively well-positioned given our disciplined approach to financial management and our commodity diversification. In particular, our exposure to European natural gas markets, where fundamentals and pricing remain strong, is a key advantage differentiating Vermilion from its competitors.

Current European natural gas prices are more than triple those in North America, and our planned 2015 capital activities will allow us to continue to take advantage of this opportunity.  In 2014, we expanded our European natural gas business with our entry into Germany, a producing region with a long history of development activity and strong market fundamentals. This acquisition increased our existing European natural gas production base by nearly 50% in 2014.  With continued organic growth in our Netherlands gas production combined with additional gas production from our Corrib project in Ireland, we expect that European gas will comprise nearly 35% of total production by Q4 2015.  In 2016, with a full year of Corrib production and assuming no changes in commodity pricing, European natural gas may generate as much as 45% of Vermilion's FFO(1).

Notwithstanding the general weakness in crude prices globally, the advantages of international crude exposure in fiscally competitive regions like France and Australia were also evident during Q1 2015. The operating netback from our Brent-based crude oil sales in Australia and France was a blended $44.76/boe, as compared to operating netbacks of $31.68/boe from WTI-based crude oil sales in North America.

In response to the depressed crude oil and North American natural gas price environment, we previously announced a reduction in our 2015 exploration and development program to $415 million, representing a 40% decrease versus 2014.  With this reduction, assuming average WTI pricing for 2015 in the mid-$50 range, we would expect our cash inflows to nearly match our net cash outflows (excluding Corrib related capital expenditures).  Despite this significant reduction in planned capital expenditures, we remain on target to achieve the lower end our original full year 2015 production guidance of 55,000 to 57,000 boe/d. This represents year-over-year production growth exceeding 10%, and we expect to achieve consolidated organic production growth in each quarter of 2015.

To further enhance the long-term and sustainable profitability of our business, we reinstated our Profitability Enhancement Program ("PEP").  Prior installments of PEP achieved strong results in both the 1998 industry downturn and the financial crisis of 2008-2009.  Based on savings identified to-date, our third installment of PEP is expected to result in cost reductions estimated at between $50 and $60 million for full-year 2015 capital spending, operating expense and G&A. This is reflected in Q1 2015 operating expense per unit, which is 15% lower than Q4 2014 and 22% lower than Q1 2014.

Our European capital programs remain robust.  In France, we completed a successful four (4.0 net) well drilling program at Champotran during Q1 2015.  Subsequent to Q1 2015, all four wells were tied-in and are currently producing at a combined average rate of 980 bbls/d.   This was our third successive drilling program since 2013, comprising a cumulative 13 wells at Champotran, with a 100% drilling success rate. After-tax rates of return associated with our Champotran oil drilling program remain in excess of 100%(2) at today's oil prices.  The remainder of our 2015 capital expenditures in France will target highly economic workovers and optimization projects, as well as infrastructure and facility maintenance.  During the second quarter, we expect to restore approximately 2 mmcf/d of shut-in natural gas production from our Vic Bilh field.

In the Netherlands, we plan to drill three (2.4 net) wells during Q2 2015 with volumes from these wells, if successful, expected to be on-stream during the second half of 2015.   Subsequent to the end of Q1 2015, we reached total depth and logged the first well in our 2015 Netherlands drilling program, the Slootdorp-06 well in the province of North Holland (93% working interest).  Based on electric logs, this well is a field-extending discovery, logging 71 m of gross gas column in the Rotliegend Sand.  Production from the Slootdorp-06 well is expected to begin during the second half of 2015.

In Germany, our operating partner is drilling one (0.25 net) well in 2015, which was spudded late in Q1 2015.  If successful, production from this well should be on-stream in mid-Q3 2015.

Our Corrib project in Ireland has continued to progress as expected.  Remaining work includes the ongoing testing of all systems and processes required for the safe operation of the Bellanaboy gas processing terminal.  The Irish Environmental Protection Agency issued its Proposed Determination for the Corrib Industrial Emissions License  ("IEL") in April 2015.  Based on remaining terminal activities and typical approval timelines for the final form of the IEL, we estimate that the most likely date for start-up is approximately mid-year, with a modest range of outcomes around that estimate.  Production at Corrib is expected to increase over the first few months toward peak production levels estimated at approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.

With strong fundamentals in our international operations and the significant flexibility offered by our Canadian asset base, we reduced our 2015 investment activity as compared to prior years.  In our Cardium light-oil resource play, economics remain robust with capital investment rates of return in excess of 30%(2) . Results to-date have been strong, with better-than-forecasted production volumes on our two-mile extended reach horizontal wells. In Q1 2015, we participated in the drilling of only seven (3.1 net) Cardium wells in the quarter, which represents our planned Cardium drilling activities for 2015 (compared to 30 to 50 net wells in previous years). For the remainder of 2015, we will be focused predominately on the completion and tie-in of previously drilled wells. Our Mannville condensate-rich conventional natural gas play remains the most economic play in our Canadian portfolio with current rates of return in excess of 85%(2).   During Q1 2015, we participated in drilling 13 (8.9 net) wells, representing approximately half of our planned 28 (16.0 net) well program for 2015. In Saskatchewan, we reduced our drilling activity to five (4.1 net) wells in 2015, all of which were drilled in Q1 2015. New well results in our downdip Midale play in Saskatchewan have been better than we expected at the time we entered this region in 2014.  Duvernay drilling activities have been deferred to beyond 2015 as we monitor the performance of our two appraisal wells drilled in 2014. We achieved increased Canadian production despite having approximately 1,600 boe/d of production offline as a result of plant capacity restrictions and interruptible service curtailments on the NGTL system.

Our balance sheet remains a further source of strength.  Subsequent to Q1 2015, we negotiated with our lenders for a further expansion and extension of our existing revolving credit facilities from $1.75 billion to $2 billion, which was previously increased from $1.5 billion in Q1 2015. Taking into account the most recent expansion to our credit facility, we have approximately $820 million of borrowing capacity available.  The facility, which matures in May 2019, is fully revolving up to the date of maturity and subject to standard form covenants (discussed in the "Financial Position Review" section of our MD&A).  We are, and expect to continue to be, in compliance with all applicable debt covenants, and expect to maintain our current dividend of $0.215 per share per month ($2.58 per share per year).  With a nearly balanced budget at current commodity prices, we currently anticipate our balance sheet leverage to remain at current levels assuming current commodity prices, and then to naturally de-lever with the addition of FFO from our Corrib asset in the second half of 2015. While this represents higher financial leverage than we would normally carry, it is lower than the debt ratios of the majority of our peers, and should allow us the flexibility to manage our business effectively by providing continued growth and returns for shareholders in the current price environment.

Vermilion was recently ranked 15th by Corporate Knights on the Future 40 Responsible Corporate Leaders in Canada list (the highest ranking for an oil and gas company, and improved from our debut ranking of 32nd last year). We were also named Top International Producer of the year by The Explorers and Producers Association of Canada.  This recognition reflects Vermilion's continued focus on achieving robust shareholder returns combined with environmental, social and governance performance. Our non-financial initiatives and performance are also articulated in the company's first annual CDP submission and sustainability report in 2014. Strong workplace practices and a culture that respects both people and communities are key elements in our success.

Subsequent to Q1 2015, Vermilion was pleased to announce that for a sixth consecutive year, it has been recognized by the Great Place to Work® Institute as a Best Workplace in Canada and FranceVermilion was also recognized for a second consecutive year as a Best Workplace in the Netherlands in 2015, after becoming eligible for ranking in 2014.  Vermilion is the only energy company in its category to rank on the Best Workplaces lists in Canada and the Netherlands, and the highest scoring energy company on the Best Workplaces list in France.

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

(1) The above discussion includes additional GAAP and non-GAAP measures which may not be comparable to other companies.  Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.
(2)  Economics calculated using the following commodity price deck assumptions:  $55/bbl WTI; $60/bbl Dated Brent; $2.75/mmbtu AECO; US$3.00/mmbtu Nymex; $9.00/mmbtu Title Transfer Facility (Netherlands); CAD/USD 1.20; CAD/EUR 1.40

HIGHLIGHTS

      Three Months Ended
($M except as indicated)     Mar 31,     Dec 31,     Mar 31,
Financial     2015     2014     2014
Petroleum and natural gas sales     195,885     306,073     381,183
Fund flows from operations (1)     120,795     185,528     205,363
  Fund flows from operations ($/basic share)     1.12     1.73     2.01
  Fund flows from operations ($/diluted share)     1.11     1.71     1.97
Net earnings     1,275     58,642     102,788
  Net earnings ($/basic share)     0.01     0.55     1.00
Capital expenditures     174,311     166,243     196,375
Acquisitions     35     1,652     178,227
Asset retirement obligations settled     3,107     6,247     2,651
Cash dividends ($/share)     0.645     0.645     0.645
Dividends declared     69,390     69,119     66,007
  % of fund flows from operations     57%     37%     32%
Net dividends (1)     48,012     48,139     47,122
  % of fund flows from operations     40%     26%     23%
Payout (1)     225,430     220,629     246,148
  % of fund flows from operations     187%     119%     120%
  % of fund flows from operations (excluding the Corrib project)     173%     106%     111%
Net debt (1)     1,388,603     1,265,650     966,310
Ratio of net debt to annualized fund flows from operations (1)     2.9     1.7     1.2
Operational                  
Production                  
  Crude oil (bbls/d)     28,181     28,846     27,318
  NGLs (bbls/d)     3,039     2,822     2,140
  Natural gas (mmcf/d)     115.00     107.42     103.32
  Total (boe/d)     50,386     49,571     46,677
Average realized prices                  
  Crude oil and NGLs ($/bbl)     58.25     78.64     111.62
  Natural gas ($/mcf)     5.26     5.90     7.99
Production mix (% of production)                  
  % priced with reference to WTI     28%     28%     25%
  % priced with reference to AECO     20%     20%     17%
  % priced with reference to TTF     18%     16%     19%
  % priced with reference to Dated Brent     34%     36%     39%
Netbacks ($/boe) (1)                  
  Operating netback     31.30     45.85     63.20
  Fund flows from operations netback     29.07     38.67     47.76
  Operating expenses     10.56     12.48     13.49
Average reference prices                  
  WTI (US $/bbl)     48.63     73.15     98.68
  Edmonton Sweet index (US $/bbl)     41.83     66.79     90.43
  Dated Brent (US $/bbl)     53.97     76.27     108.22
  AECO ($/GJ)     2.60     3.41     5.42
  TTF ($/GJ)     8.25     8.69     10.19
Average foreign currency exchange rates                  
  CDN $/US $     1.24     1.14     1.10
  CDN $/Euro     1.40     1.42     1.51
Share information ('000s)                  
Shares outstanding - basic     107,718     107,303     102,453
Shares outstanding - diluted(1)     110,761     110,334     105,167
Weighted average shares outstanding - basic     107,513     107,102     102,278
Weighted average shares outstanding - diluted     109,305     108,646     104,171

(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.


MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is Management's Discussion and Analysis ("MD&A"), dated May 7, 2015, of Vermilion Energy Inc.'s ("Vermilion", "We", "Our", "Us" or the "Company") operating and financial results as at and for the three months ended March 31, 2015 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, 2015 and the audited consolidated financial statements for the year ended December 31, 2014 and 2013, together with accompanying notes.  Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

The unaudited condensed consolidated interim financial statements for the three months ended March 31, 2015 and comparative information have been prepared in Canadian dollars, except where another currency is indicated, and in accordance with IAS 34, "Interim Financial Reporting", as issued by the International Accounting Standard Board ("IASB").

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

  • Fund flows from operations: This additional GAAP financial measure is calculated as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled.  We analyze fund flows from operations both on a consolidated basis and on a business unit basis in order to assess the contribution of each business unit to our ability to generate cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments.
  • Netbacks: These non-GAAP financial measures are per boe and per mcf measures used in the analysis of operational activities.  We assess netbacks both on a consolidated basis and on a business unit basis in order to compare and assess the operational and financial performance of each business unit versus other business units and third party crude oil and natural gas producers.

For a full description of these and other non-GAAP financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES".

VERMILION'S BUSINESS

Vermilion is a Calgary, Alberta based international oil and gas producer focused on the acquisition, development and optimization of producing properties in North America, Europe, and Australia.  We manage our business through our Calgary head office and our international business unit offices.

This MD&A separately discusses each of our business units in addition to our corporate segment.

  • Canada business unit: Relates to our assets in Alberta and Saskatchewan.
  • France business unit: Relates to our operations in France in the Paris and Aquitaine Basins.
  • Netherlands business unit: Relates to our operations in the Netherlands.
  • Germany business unit: Relates to our 25% contractual participation interest in a four-partner consortium in Germany.
  • Ireland business unit: Relates to our 18.5% non-operated interest in the Corrib offshore natural gas field.
  • Australia business unit: Relates to our operations in the Wandoo offshore crude oil field.
  • United States business unit: Relates to our operations in Wyoming in the Powder River Basin.
  • Corporate: Includes expenditures related to our global hedging program, financing expenses, and general and administration expenses, primarily incurred in Canada and not directly related to the operations of a specific business unit.

GUIDANCE

We first issued 2015 capital expenditure guidance of $525 million on December 8, 2014.  We subsequently adjusted our 2015 capital expenditure guidance to $415 million on February 27, 2015, in response to the continued weakness in commodity prices. The $110 million reduction in capital reflects lower planned activity levels, including the deferral of our Australian drilling campaign. Despite the reduction in our capital budget, we are maintaining our previous production guidance of 55,000-57,000 boe/d.

The following table summarizes our 2015 guidance:

          Date           Capital Expenditures ($MM)           Production (boe/d)
2015 - Guidance                                
2015 Guidance       December 8, 2014           525           55,000 to 57,000
2015 Guidance       February 27, 2015           415           55,000 to 57,000
                                   

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, 2015, reflects our trailing one, three, and five year performance:

Total return (1)     Trailing One Year       Trailing Three Year       Trailing Five Year
Dividends per Vermilion share     $2.58       $7.34       $11.90
Capital appreciation per Vermilion share     -$15.80       $7.24       $17.86
Total return per Vermilion share     -19.1%       31.7%       84.1%
Annualized total return per Vermilion share     -19.1%       9.6%       13.0%
Annualized total return on the S&P TSX High Income Energy Index     -22.1%       -3.6%       0.2%

(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,     Q1/15 vs.     Q1/15 vs.
      2015     2014     2014     Q4/14     Q1/14
Production                                
  Crude oil (bbls/d)     28,181     28,846     27,318     (2%)     3%
  NGLs (bbls/d)     3,039     2,822     2,140     8%     42%
  Natural gas (mmcf/d)     115.00     107.42     103.32     7%     11%
  Total (boe/d)     50,386     49,571     46,677     2%     8%
  Build (draw) in inventory (mbbl)     383     (238)     (98)            
Financial metrics                                
  Fund flows from operations ($M)     120,795     185,528     205,363     (35%)     (41%)
    Per share ($/basic share)     1.12     1.73     2.01     (35%)     (44%)
  Net earnings ($M)     1,275     58,642     102,788     (98%)     (99%)
    Per share ($/basic share)     0.01     0.55     1.00     (98%)     (99%)
  Cash flows from operating activities ($M)     22,647     229,146     178,238     (90%)     (87%)
  Net debt ($M)     1,388,603     1,265,650     966,310     10%     44%
  Cash dividends ($/share)     0.645     0.645     0.645     -     -
Activity                                
  Capital expenditures ($M)     174,311     166,243     196,375     5%     (11%)
  Acquisitions ($M)     35     1,652     178,227     (98%)     (100%)
  Gross wells drilled     29.00     26.00     24.00            
  Net wells drilled     20.04     16.58     18.83            


Operational review

  • Recorded consolidated average production of 50,386 boe/d during Q1 2015, which was a 2% increase above Q4 2014 production.
  • Recorded a build in crude oil inventory in Australia (281,000 bbls) and France (102,000 bbls), which resulted in lower sold volumes versus the comparable quarters.
  • Increased consolidated average production from Q1 2014 by 8%, primarily driven by incremental production from our acquisitions in southeast Saskatchewan in Q2 2014 and Germany, which was acquired with an effective date of February 1, 2014. In Canada, production growth of 22% compared to Q1 2014 resulted from continued development of the Cardium and Mannville plays in Alberta, coupled with incremental production from southeast Saskatchewan following our acquisition in April 2014 of Elkhorn Resources Inc.  These production increases were partially offset by decreased production in the Netherlands, which was managed throughout the quarter to optimize facility use and regulate declines.  Production in Australia also decreased due to active management to control inventory levels and meet marketing schedules.
  • Activity during the quarter included capital expenditures totalling $174.3 million, incurred primarily in Canada, France, and Ireland. In Canada, capital expenditures totalling $114.8 million were 34% higher than the $85.4 million incurred in Q4 2014 and included costs related to facility work and the drilling of 16.04 net wells compared to 15.16 net wells in Q4 2014. In France, capital expenditures of $34.1 million related to the drilling of 4.0 net wells and workovers. In Ireland, $13.0 million of capital expenditures were incurred, the majority of which related primarily to facility commissioning activities, as well as the completion of the 4.9 km tunnel.

Financial review

Net earnings

  • Net earnings for Q1 2015 were $1.3 million ($0.01/basic share) as compared to $58.6 million ($0.55/basic share) for Q4 2014. The decrease quarter-over-quarter is primarily attributable to lower petroleum and natural gas sales driven by lower commodity prices and lower sales volumes, as well as a $13.7 million loss on derivative instruments, compared to a $40.0 million gain in the prior quarter. The decrease in sales was partially offset by lower operating costs and royalties, as well as the awarded recovery of costs resulting from the oil spill at the Ambès terminal that occurred in 2007.
  • Net earnings for Q1 2015 were lower as compared to Q1 2014 primarily due to the decrease in sales as a result of lower commodity prices, an unrealized loss of $20.0 million on derivative instruments, and a loss on foreign exchange of $1.5 million (compared to gains of $3.9 million and $20.0 million, respectively, in the prior year). This was partially offset by a decrease in operating costs, a realized gain on derivative instruments of $6.3 million, and the previously mentioned recovery in France.

Cash flows from operating activities

  • Cash flows from operating activities decreased by 90% and 87% as compared to Q4 2014 and Q1 2014, respectively. The decrease is primarily related to lower sales and timing differences pertaining to working capital, partially offset by lower operating expenses and royalties.

Fund flows from operations

  • Generated fund flows from operations of $120.8 million during Q1 2015, a decrease of $64.7 million (35%) versus Q4 2014. This quarter-over-quarter decrease was the result of lower sales and lower realized gains on derivative instruments. This was partially offset by lower royalties and operating expenses, as well as the previously mentioned recovery in France.
  • Fund flows from operations decreased by $84.6 million (41%) versus Q1 2014. This decrease was primarily the result of commodity price decreases and lower volumes sold in Australia and France (due to inventory builds in the period). This was partially offset by higher sales volumes in Canada, Germany, and the United States due to incremental production from acquisitions occurring in 2014, as well as lower royalties, operating expenses, and the previously mentioned recovery in France.

Net debt

  • Net debt increased by $123.0 million to $1.39 billion as at March 31, 2015, due to capital expenditures in Canada and Ireland coupled with the decrease in fund flows from operations, which was driven by weak commodity prices and lower sales volumes.

Dividends

  • Declared dividends remained consistent at $0.215 per common share per month during the first quarter of 2015, totalling $0.645 per common share for the quarter.


COMMODITY PRICES

      Three Months Ended   % change
      Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
      2015     2014     2014     Q4/14     Q1/14
Average reference prices                              
WTI (US $/bbl)     48.63     73.15     98.68     (34%)     (51%)
Edmonton Sweet index (US $/bbl)     41.83     66.79     90.43     (37%)     (54%)
Dated Brent (US $/bbl)     53.97     76.27     108.22     (29%)     (50%)
AECO ($/GJ)     2.60     3.41     5.42     (24%)     (52%)
TTF ($/GJ)     8.25     8.69     10.19     (5%)     (19%)
TTF (€/GJ)     5.91     6.12     6.75     (3%)     (12%)
Average foreign currency exchange rates                              
CDN $/US $     1.24     1.14     1.10     9%     13%
CDN $/Euro     1.40     1.42     1.51     (1%)     (7%)
Average realized prices ($/boe)                              
Canada     35.81     51.27     69.26     (30%)     (48%)
France     64.33     79.25     117.54     (19%)     (45%)
Netherlands     48.60     52.07     63.60     (7%)     (24%)
Germany     45.21     49.19     55.85     (8%)     (19%)
Australia     83.80     90.37     127.26     (7%)     (34%)
United States     48.79     74.08     -       (34%)     100%
Consolidated     47.17     63.79     88.67     (26%)     (47%)
Production mix (% of production)                              
% priced with reference to WTI     28%     28%     25%            
% priced with reference to AECO     20%     20%     17%            
% priced with reference to TTF     18%     16%     19%            
% priced with reference to Dated Brent     34%     36%     39%            

Reference prices

  • The first quarter of 2015 proved to be a challenging period for energy prices, particularly crude oil. For the three months ended March 31, 2015, the average price for Dated Brent was US$53.97/bbl, a decrease of 29% from Q4 2014 and 50% lower than Q1 2014.
  • Downward pressure was even greater for North American crude grades as inventory builds and robust production left little fundamental support.  During Q1 2015, WTI averaged US$48.63/bbl versus US$73.15/bbl in Q4 2014 and US$98.68/bbl in Q1 2014.  Edmonton Sweet Index averaged US$41.83/bbl in Q1 2015, down 37% and 54% versus Q4 2014 and Q1 2014, respectively.
  • AECO natural gas declined by 24% versus Q4 2014 and 52% versus Q1 2014 as warmer weather in Western Canada kept the supply/demand balance at a lower equilibrium.
  • Despite lower quarter-over-quarter and year-over-year results, European natural gas performed relatively well due to both geopolitical and fundamental support.  Compared to the previous quarter, TTF decreased 5% in Canadian dollar terms and 3% in Euro terms, whereas on a year-over-year basis, Q1 2015 TTF decreased 19% in Canadian dollar terms and 12% in Euro terms.
  • US dollar strength was a highlight for the first quarter, posting sizeable gains against major currency pairs such as the Canadian dollar and the Euro.  For the three months ended March 31, 2015, CDN $/US $ increased 9% and 13% as compared to Q4 2014 and Q1 2014, respectively.

Realized prices

  • Consolidated realized price for Q1 2015 decreased by 26% and 47% as compared to Q4 2014 and Q1 2014, respectively. The decreases were the result of weaker crude oil and natural gas prices, partially offset by a weaker Canadian dollar versus the US dollar during Q1 2015 versus the comparable quarters.

FUND FLOWS FROM OPERATIONS

  Three Months Ended
      Mar 31, 2015     Dec 31, 2014     Mar 31, 2014
      $M     $/boe     $M     $/boe     $M     $/boe
Petroleum and natural gas sales     195,885     47.17     306,073     63.79     381,183     88.67
Royalties     (16,424)     (3.95)     (25,963)     (5.41)     (24,024)     (5.59)
Petroleum and natural gas revenues     179,461     43.22     280,110     58.38     357,159     83.08
Transportation expense     (9,540)     (2.30)     (9,489)     (1.98)     (9,861)     (2.29)
Operating expense     (43,851)     (10.56)     (59,881)     (12.48)     (57,986)     (13.49)
General and administration     (13,560)     (3.27)     (13,236)     (2.76)     (14,467)     (3.37)
PRRT     (2,354)     (0.57)     (13,568)     (2.83)     (20,239)     (4.71)
Corporate income taxes     (17,623)     (4.24)     (8,304)     (1.73)     (38,603)     (8.98)
Interest expense     (13,298)     (3.20)     (12,943)     (2.70)     (11,460)     (2.67)
Realized gain on derivative instruments     6,257     1.51     22,816     4.76     2,640     0.61
Realized foreign exchange gain (loss)     3,306     0.78     (179)     (0.03)     (2,041)     (0.47)
Realized other income     31,997     7.70     202     0.04     221     0.05
Fund flows from operations     120,795     29.07     185,528     38.67     205,363     47.76

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

($M)     Q1/15 vs. Q4/14     Q1/15 vs. Q1/14
Fund flows from operations - Comparative period     185,528     205,363
Sales volume variance:            
  Canada     (2,893)     26,315
  France     (8,789)     (8,235)
  Netherlands     3,268     (6,434)
  Germany     (951)     5,172
  Australia     (50,175)     (60,690)
United States     (310)     672
Pricing variance on sold volumes:            
  WTI     (27,784)     (57,543)
  AECO     (4,281)     (14,068)
  Dated Brent     (15,390)     (59,493)
  TTF     (2,883)     (10,994)
Changes in:            
  Royalties     9,539     7,600
  Transportation     (51)     321
  Operating expense     16,030     14,135
  General and administration     (324)     907
  PRRT     11,214     17,885
  Corporate income taxes     (9,319)     20,980
  Interest     (355)     (1,838)
  Realized derivatives     (16,559)     3,617
  Realized foreign exchange     3,485     5,347
  Realized other income     31,795     31,776
Fund flows from operations - Current period     120,795     120,795


Fund flows from operations of $120.8 million during Q1 2015 represent a decrease of $64.7 million (35%) versus Q4 2014.  This quarter-over-quarter decrease was principally the result of lower sales volumes and weaker commodity pricing.  The decrease in sales included $50.3 million of pricing variance, of which $43.2 million was due to a decrease in crude oil prices, as well as a $59.9 million sales volume variance, of which $59.0 million related to Australia and France (due to inventory builds in the period).  The decrease in royalties and operating expenses is consistent with decreased sales in the quarter, and the increase in other income is related to the previously mentioned recovery in France.

On a year-over-year basis, fund flows from operations decreased 41% for the three months ended March 31, 2015, versus the comparable period in 2014.  The decreases were primarily the result of a $185.3 million decrease in sales, including a $142.1 million pricing variance driven by a $117.0 million variance attributable to declines in crude oil prices.  The decrease also included a $43.2 million sales volume variance, of which $68.9 million related to Australia and France (due to inventory builds in the period) and was partially offset by a $31.5 million positive variance related to production from Canada and Germany.  Lower revenue was partially offset by decreases in operating expenses and taxes, as well as the previously mentioned recovery in France.

Fluctuations in fund flows from operations (and correspondingly net earnings and cash flows from operating activities) may occur as a result of changes in commodity prices and costs to produce petroleum and natural gas.  In addition, fund flows from operations may be highly affected by the timing of crude oil shipments in Australia and France.  When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on the balance sheet.  When the crude oil inventory is subsequently drawn down, the related expenses are recognized in fund flows from operations.

CANADA BUSINESS UNIT

Overview

  • Production and assets focused in West Pembina near Drayton Valley, Alberta and Northgate in southeast Saskatchewan.
  • Potential for three significant resource plays sharing the same surface infrastructure in the West Pembina region:
    • Cardium light oil (1,800m depth) - in development phase
    • Mannville condensate-rich gas (2,400 - 2,700m depth) - in development phase
    • Duvernay condensate-rich gas (3,200 - 3,400m depth) - in appraisal phase
  • Canadian cash flows are fully tax-sheltered for the foreseeable future.

Operational review

      Three Months Ended   % change
      Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
Canada business unit     2015     2014     2014     Q4/14     Q1/14
Production                              
  Crude oil (bbls/d)     10,893     11,384     9,437     (4%)     15%
  NGLs (bbls/d)     2,976     2,741     2,071     9%     44%
  Natural gas (mmcf/d)     61.78     58.36     49.53     6%     25%
  Total (boe/d)     24,165     23,851     19,763     1%     22%
Production mix (% of total)                              
  Crude oil     45%     48%     48%            
  NGLs     12%     11%     10%            
  Natural gas     43%     41%     42%            
Activity                              
  Capital expenditures ($M)     114,849     85,442     114,939     34%     -
  Acquisitions ($M)     35     1,671     4,768            
  Gross wells drilled     25.00     23.00     20.00            
  Net wells drilled     16.04     15.16     14.97            


Production

  • Production in Canada increased by 1% quarter-over-quarter and by 22% year-over year. The year-over-year increase in average production volumes was primarily attributable to strong organic production growth in our Mannville condensate-rich gas resource play. We achieved increased Canadian production despite having approximately 1,600 boe/d of production offline as a result of plant capacity restrictions and interruptible service curtailments on the NGTL system.
  • Cardium production averaged more than 9,800 boe/d in Q1 2015, a 2% decrease quarter-over-quarter. Some non-operated volume is currently constrained due to pipeline restrictions.
  • Mannville production averaged approximately 4,850 boe/d in Q1 2015, a 12% increase quarter-over-quarter.  As with Cardium production, non-operated Mannville volume was constrained due to pipeline restrictions.
  • Production from our southeast Saskatchewan assets averaged approximately 2,800 boe/d in Q1 2015, a 5% decrease quarter-over-quarter.  The North Portal Gas Plant was commissioned late in Q1. The plant will enable the processing of approximately 6,000 mcf/d (5,500 mcf/d net) of gas which was previously being flared.

Activity review

  • Vermilion drilled a total of 14 (11.8 net) operated wells during Q1 2015.

Cardium

  • We participated in a total of seven (3.1 net) wells, including drilling one (1.0 net) operated well and brought 10 (9.3 net) operated wells on production during Q1 2015.
  • Since 2009, we have drilled or participated in 285 (201.9 net) wells.
  • In 2015, we plan to drill or participate in the seven (3.1 net) wells executed in Q1, and complete, equip and tie-in an additional 8.2 net wells which were drilled in 2014.

Mannville

  • During Q1 2015, we participated in a total of 13 (8.9 net) wells, including eight (6.7 net) operated wells and brought three (2.5 net) operated wells on production.
  • In 2015, we expect to drill or participate in approximately 28 (16.0 net) wells and complete, equip and tie-in an additional 1.0 net well which was drilled in 2014.

Saskatchewan

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

Financial review

      Three Months Ended   % change
Canada business unit     Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
($M except as indicated)     2015     2014     2014     Q4/14     Q1/14
  Sales     77,884     112,494     123,180     (31%)     (37%)
  Royalties     (8,592)     (15,626)     (12,663)     (45%)     (32%)
  Transportation expense     (3,942)     (3,455)     (3,098)     14%     27%
  Operating expense     (19,099)     (19,315)     (16,610)     (1%)     15%
  General and administration     (4,015)     (2,840)     (2,868)     41%     40%
  Fund flows from operations     42,236     71,258     87,941     (41%)     (52%)
Netbacks ($/boe)                              
  Sales     35.81     51.27     69.26     (30%)     (48%)
  Royalties     (3.95)     (7.12)     (7.12)     (45%)     (45%)
  Transportation expense     (1.81)     (1.57)     (1.74)     15%     4%
  Operating expense     (8.78)     (8.80)     (9.34)     -     (6%)
  General and administration     (1.85)     (1.29)     (1.61)     43%     15%
  Fund flows from operations netback     19.42     32.49     49.45     (40%)     (61%)
Reference prices                              
  WTI (US $/bbl)     48.63     73.15     98.68     (34%)     (51%)
  Edmonton Sweet index (US $/bbl)     41.83     66.79     90.43     (37%)     (54%)
  Edmonton Sweet index ($/bbl)     51.92     75.85     99.79     (32%)     (48%)
  AECO ($/GJ)     2.60     3.41     5.42     (24%)     (52%)


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 decreased by 30% quarter-over-quarter as a result of a 37% decrease in Edmonton Sweet index pricing and a 24% decrease in AECO pricing.  This decrease, coupled with relatively consistent production volumes, resulted in a 31% decrease in sales.
  • On a year-over-year basis, sales per boe decreased by 48% for the three months ended March 31, 2015 versus the same period in 2014.  Lower commodity prices were partially offset by a 22% increase in production due to production growth in the Cardium and Mannville resource plays and incremental production from our Saskatchewan acquisition, resulting in a 37% decrease in sales.

Royalties

  • Royalty expense as a percentage of sales for Q1 2015 decreased to 11.0% versus the 13.9% for Q4 2014 as a result of the impact of lower prices on the sliding scale used to determine royalty rates.
  • Royalty expense as a percentage of sales for Q1 2015 was relatively consistent with Q1 2014 (10.3%) despite lower pricing due to fewer wells benefiting from incentive royalty rates in the current quarter versus Q1 2014.

Transportation

  • Transportation expense relates to the delivery of crude oil and natural gas production to major pipelines where legal title transfers.
  • Transportation expense for Q1 2015 was higher than Q4 2014 as a result of higher crude oil production subject to transportation costs coupled with a prior period amendment received from a pipeline.
  • On a year-over-year basis, transportation expense for Q1 2015 was higher than Q1 2014 as a result of incremental trucking costs from Vermilion's Saskatchewan properties, which were acquired in Q2 2014.

Operating expense

  • On a per boe and dollar basis, operating expenses were relatively unchanged quarter-over-quarter.
  • Year-over-year, operating expense increased on a dollar basis due to incremental operating expenses associated with Vermilion's Saskatchewan properties.  This dollar increase was offset by a wide range of cost reduction initiatives undertaken in response to commodity price weakness and an increase in production volumes resulting in reduced operating expense on a per boe basis.

General and administration

  • General and administration expense in Canada was higher in Q1 2015 as compared to Q4 2014.  This resulted from expenditure timing as well as higher allocations of shared costs to Vermilion's other operating jurisdictions in the prior quarter.
  • Year-over-year, the increase in general and administration expense for Q1 2015 as compared to Q1 2014 is primarily associated with higher staffing levels required to support Vermilion's organic growth initiatives as well as the 2014 Saskatchewan acquisition.

FRANCE BUSINESS UNIT

Overview

  • Entered France in 1997 and completed three subsequent acquisitions, including two in 2012.
  • Largest oil producer in France.
  • 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,     Q1/15 vs.     Q1/15 vs.
France business unit     2015     2014     2014     Q4/14     Q1/14
Production                              
  Crude oil (bbls/d)     11,463     11,133     10,771     3%     6%
Inventory (mbbls)                              
  Opening crude oil inventory     197     214     269            
  Crude oil production     1,032     1,024     969            
  Crude oil sales     (930)     (1,041)     (1,000)            
  Closing crude oil inventory     299     197     238            
Activity                              
  Capital expenditures ($M)     34,114     37,189     37,967     (8%)     (10%)
  Gross wells drilled     4.00     1.00     2.00            
  Net wells drilled     4.00     0.50     2.00            


Production

  • Quarter-over-quarter and year-over-year production growth of 3% and 6%, respectively.
  • In late September 2013, the third party Lacq processing facility that processed our Vic Bilh gas production was permanently closed.  As a result, our Vic Bilh gas production has been temporarily shut-in while preparations to transfer to an alternative facility are completed.  As a result of the shut-in, current production volumes remain 100% weighted to Brent-based crude.

Activity review

  • Vermilion drilled four (4.0 net) wells in the Champotran field in the Paris Basin in Q1 2015, completing our planned France drilling program for 2015.
  • In 2015, additional activity includes an 18-well workover program and the resumption of sales from a portion of our shut-in natural gas at Vic Bilh.

Financial review

      Three Months Ended   % change  
France business unit     Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
($M except as indicated)     2015     2014     2014     Q4/14     Q1/14
    Sales     59,832     82,499     117,560     (27%)     (49%)
    Royalties     (5,102)     (6,319)     (7,351)     (19%)     (31%)
    Transportation expense     (3,011)     (4,096)     (4,753)     (26%)     (37%)
    Operating expense     (10,826)     (13,544)     (16,420)     (20%)     (34%)
    General and administration     (5,111)     (3,765)     (5,194)     36%     (2%)
    Other income     31,775     -       -       100%     100%
    Current income taxes     (14,281)     (6,132)     (25,264)     133%     (43%)
    Fund flows from operations     53,276     48,643     58,578     10%     (9%)
Netbacks ($/boe)                              
    Sales     64.33     79.25     117.54     (19%)     (45%)
    Royalties     (5.49)     (6.07)     (7.35)     (10%)     (25%)
    Transportation expense     (3.24)     (3.94)     (4.75)     (18%)     (32%)
    Operating expense     (11.64)     (13.01)     (16.42)     (11%)     (29%)
    General and administration     (5.49)     (3.62)     (5.19)     52%     6%
    Other income     34.16     -       -       100%     100%
    Current income taxes     (15.35)     (5.89)     (25.26)     161%     (39%)
    Fund flows from operations netback     57.28     46.72     58.57     23%     (2%)
Reference prices                              
    Dated Brent (US $/bbl)     53.97     76.27     108.22     (29%)     (50%)
    Dated Brent ($/bbl)     66.98     86.62     119.42     (23%)     (44%)

Sales

  • Crude oil production in France is priced with reference to Dated Brent.
  • Sales per boe decreased by 19% quarter-over-quarter, consistent with a 29% decrease in the Dated Brent reference price. This decrease, coupled with an increase in ending inventory of 102,000 bbls, resulted in a 27% decrease in sales.
  • On a year-over-year basis, sales per boe decreased by 45% for the three months ended March 31, 2015, as compared to the same period in 2014. This decrease was primarily driven by the 50% decrease in the Dated Brent reference price, and, combined with a build in inventory, resulted in a 49% decrease in sales.

Royalties

  • Royalties in France relate to two components: RCDM (levied on units of production and not subject to changes in commodity prices) and R31 (based on a percentage of revenue).
  • Royalties as a percentage of sales was 8.5% in Q1 2015, an increase over both Q4 2014 (7.7%) and Q1 2014 (6.3%) due to the impact of fixed RCDM royalties coupled with lower realized pricing.

Transportation

  • Transportation expense decreased for Q1 2015 as compared to Q4 2014 primarily as a result of a reduced number of shipments from the Ambès terminal during the current quarter due to unusually high tides at the end of March coupled with reduced trucking activity.
  • Transportation expense for Q1 2015 was $1.7 million lower than Q1 2014.  This decrease related to reduced maintenance and project activity at the Ambès terminal coupled with cost savings associated with fewer shipments at the terminal due to the usage of larger shipping vessels.

Operating expense

  • Operating expense was lower in Q1 2015 as compared to both Q4 2014 and Q1 2014 due to cost reduction initiatives undertaken in response to commodity price weakness including lower costs on downhole and other activities, lower labour usage and costs, and savings from service contract renegotiations.  In addition, operating expense also decreased due to the impact of deferring costs following a build in crude oil inventory related to the aforementioned unusually high tides at the end of March.
  • On a year-over-year basis, operating expenses further benefited from a favorable foreign exchange impact of a strengthening of the Canadian dollar versus the Euro.

General and administration

  • General and administration expense for Q1 2015 was higher than Q4 2014 due to the timing of expenditures.  On a year-over-year basis, Q1 2015 general and administration expense was relatively unchanged.

Other income

  • During Q1 2015, Vermilion was awarded a judgment pertaining to costs incurred as a result of an oil spill at the Ambès oil terminal in France that occurred in 2007.  As a result of the award $31.8 million (before taxes) was recognized as other income.

Current income taxes

  • Current income taxes in France are applied to taxable income, after eligible deductions, at a statutory rate of 34.4% for 2015.  In addition, a 10.7% temporary surtax is applicable for tax year 2015 if annual revenue exceeds €250 million.  For 2015, the effective rate on current income taxes is expected to be between approximately 20% and 22%.  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 for Q1 2015 increased compared to Q4 2014 due to the accelerated depletion on certain assets in the prior year.
  • Current income taxes for Q1 2015 decreased compared to Q1 2014.  The decrease was the result of lower funds from operations as a result of the decline in the Dated Brent reference price.

NETHERLANDS BUSINESS UNIT

Overview

  • Entered the Netherlands in 2004.
  • Second largest onshore gas producer.
  • Interests include 16 licenses in the northeast region, five licenses in the central region, and two offshore licenses.
  • Licenses include more than 800,000 net acres of undeveloped land.
  • High impact natural gas drilling and development.
  • Natural gas produced in the Netherlands is priced off the TTF index, which receives a significant premium over North American gas prices.

Operational review

      Three Months Ended   % change
      Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
Netherlands business unit     2015     2014     2014     Q4/14     Q1/14
Production                              
  NGLs (bbls/d)     63     81     69     (22%)     (9%)
  Natural gas (mmcf/d)     36.41     31.35     43.15     16%     (16%)
  Total (boe/d)     6,132     5,306     7,260     16%     (16%)
Activity                              
  Capital expenditures ($M)     4,333     10,022     20,118     (57%)     (78%)
  Gross wells drilled     -     2.00     2.00            
  Net wells drilled     -     0.92     1.86            


Production

  • Production increased 16% quarter-over-quarter due to increased production from our Langezwaag-02 well which was tied in January 23, 2015 and partially offset by the anticipated loss of production from our Middenmeer-3 well, which was fully depleted and taken off production in February 2015.
  • Year-over-year production decreased 16%, as production volumes in Q1 2014 benefited from the increased throughput capacity following a retrofit at our Middenmeer Treatment Centre completed in late 2013.
  • Production in the Netherlands is actively managed to optimize facility use and regulate declines.

Activity review

  • Langezwaag-02 well (42% working interest), drilled in the Gorredijk concession during Q4 2014, was placed on production in Q1 2015 with an average rate of production from the Zechstein formation of 4.0 mmcf/d (with surface facility constraints).
  • In 2015, we are planning a three-well development drilling program and expect to equip and tie-in four previous discovery wells.

Financial review

        Three Months Ended   % change
Netherlands business unit     Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
($M except as indicated)     2015     2014     2014     Q4/14     Q1/14
  Sales     26,818     25,420     41,554     5%     (35%)
  Royalties     (926)     (1,171)     (2,208)     (21%)     (58%)
  Operating expense     (5,826)     (6,200)     (6,042)     (6%)     (4%)
  General and administration     (737)     (2,489)     (598)     (70%)     23%
  Current income taxes     (2,388)     2,124     (3,788)     (212%)     (37%)
  Fund flows from operations     16,941     17,684     28,918     (4%)     (41%)
Netbacks ($/boe)                              
  Sales     48.60     52.07     63.60     (7%)     (24%)
  Royalties     (1.68)     (2.40)     (3.38)     (30%)     (50%)
  Operating expense     (10.56)     (12.70)     (9.25)     (17%)     14%
  General and administration     (1.34)     (5.10)     (0.91)     (74%)     47%
  Current income taxes     (4.33)     4.35     (5.80)     (200%)     (25%)
  Fund flows from operations netback     30.69     36.22     44.26     (15%)     (31%)
Reference prices                              
  TTF ($/GJ)     8.25     8.69     10.19     (5%)     (19%)
  TTF (€/GJ)     5.91     6.12     6.75     (3%)     (12%)


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.
  • The 5% increase in sales quarter-over-quarter primarily related to a 16% increase in production, offset by a 7% decrease in sales per boe which is consistent with the 5% decrease in the Canadian dollar equivalent of the TTF reference price.
  • On a year-over-year basis, sales per boe declined by 24% for the three months ended March 31, 2015, versus the comparable period in 2014. This was consistent with a 19% decrease in the TTF reference price in Canadian dollar terms, and, coupled with a 16% decrease in production, resulted in a 35% decrease in sales.

Royalties

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

Transportation expense

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

Operating expense

  • Operating expense decreased for Q1 2015 as compared to both Q4 2014 and Q1 2014.  The decrease from Q4 2014 was largely the result of reduced project work, including the absence of an emergency response exercise conducted in Q4 2014.  This decrease, coupled with increased volumes quarter-over-quarter, resulted in a decrease in operating expense per boe.
  • The decrease in operating expense from Q1 2014 was largely driven by a strengthening of the Canadian dollar versus the Euro.  Operating expense per boe increased from the same quarter of the prior year due to lower production.

General and administration

  • On a quarter-over-quarter basis, general and administration expenses decreased in Q1 2015 versus Q4 2014 as the fourth quarter included higher allocations from Vermilion's Corporate segment. On a year-over-year basis, general and administration expense for Q1 2015 was relatively consistent with Q1 2014.

Current income taxes

  • Current income taxes in the Netherlands apply to taxable income after eligible deductions at a statutory tax rate of approximately 46%.  For 2015, the effective rate on current taxes is expected to be between approximately 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 in Q1 2015 were higher than Q4 2014.  This increase was a result of higher tax deductions for depletion on two unsuccessful wells in Q4 2014, combined with accelerated tax deductions for certain capital expenditures and other eligible in-country tax adjustments also taken in Q4 2014.
  • Current income taxes in Q1 2015 were lower than Q1 2014 as a result of decreased revenues from lower TTF reference prices.

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 include four gas producing fields across 11 production licenses and an exploration license in surrounding fields.
  • Total license area comprises 204,000 gross acres, of which 85% is in the exploration license.

Operational review

      Three Months Ended   % change  
        Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
Germany business unit     2015     2014     2014     Q4/14     Q1/14
Production                              
  Natural gas (mmcf/d)     16.80     17.71     10.64     (5%)     58%
  Total (boe/d)     2,801     2,952     1,773     (5%)     58%
Activity                              
  Capital expenditures ($M)     968     563     196     72%     394%
  Acquisitions ($M)     -     -     172,871            


Production

  • Q1 2015 production of 2,801 boe/d represented a decrease of 5% as compared to the prior quarter. Year-over-year production increased 58%, due to Q1 2014 volumes only reflecting production from the acquisition's effective date of February 1, 2014.

Activity review

  • Participating in the drilling of the Burgmoor Z3a sidetrack well (25% working interest), which was spud in Q1 2015.  The well is expected to be tied in and placed on production in Q3 2015.

Financial review

      Three Months Ended   % change
Germany business unit     Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
($M except as indicated)     2015     2014     2014     Q4/14     Q1/14
  Sales     11,395     13,359     8,915     (15%)     28%
  Royalties     (1,598)     (2,481)     (1,802)     (36%)     (11%)
  Transportation expense     (894)     (218)     (422)     310%     112%
  Operating expense     (1,999)     (2,862)     (1,554)     (30%)     29%
  General and administration     (1,608)     (2,200)     (568)     (27%)     183%
  Current income taxes     -     1,145     (537)     (100%)     (100%)
  Fund flows from operations     5,296     6,743     4,032     (21%)     31%
Netbacks ($/boe)                              
  Sales     45.21     49.19     55.85     (8%)     (19%)
  Royalties     (6.34)     (9.13)     (11.29)     (31%)     (44%)
  Transportation expense     (3.55)     (0.80)     (2.64)     344%     34%
  Operating expense     (7.93)     (10.54)     (9.74)     (25%)     (19%)
  General and administration     (6.38)     (8.10)     (3.56)     (21%)     79%
  Current income taxes     -     4.21     (3.36)     (100%)     (100%)
  Fund flows from operations netback     21.01     24.83     25.26     (15%)     (17%)
Reference prices                              
  TTF ($/GJ)     8.25     8.69     10.19     (5%)     (19%)
  TTF (€/GJ)     5.91     6.12     6.75     (3%)     (12%)


Sales

  • The price of our natural gas in Germany is based on the TTF month-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees.
  • The 15% decrease in sales quarter-over-quarter is due to an 8% decrease in sales per boe, consistent with the 5% decrease in the Canadian dollar equivalent of the TTF reference price, and a 5% decrease in production.
  • On a year-over-year basis, sales per boe declined by 19%, consistent with a 19% decrease in the Canadian dollar equivalent of the TTF reference price. This was offset by a 58% increase in recorded production following the Q1 2014 acquisition, resulting in a 28% increase in sales.

Royalties expense

  • Our production in Germany is subject to state and private royalties on sales after certain eligible deductions.  As a percentage of sales, royalties are expected to range from 15% to 20% in 2015.
  • Q1 2015 royalties as a percentage of sales of 14.0% was lower than the 18.6% for Q4 2014 and 20.2% for Q1 2014, primarily as a result of lower state royalty rates for 2015.

Transportation expense

  • Transportation expense in Germany relates to costs incurred to deliver natural gas from the processing facility to the customer.
  • Transportation expense for Q1 2015 was higher than Q4 2014 as the first quarter included a higher level of seasonal maintenance activity on transportation infrastructure.  Q1 2014 included two months of costs due to the timing of our Germany acquisition and as such, was lower than the current quarter.

Operating expense

  • Operating expenses for Germany are billed monthly by the joint venture operator and primarily relate to tariffs charged for gas processing.
  • Q1 2015 had lower operating expense on both a dollar and per boe basis as compared to Q4 2014 due to gas processing tariff adjustments recorded in Q4 2014.
  • Q1 2015 had higher operating expenses on a dollar basis than Q1 2014 as the first quarter of 2014 included two months of costs.  On a per boe basis, the year-over-year decrease resulted from reduced gas processing tariffs in 2015.

General and administration

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

Current income taxes

  • Current income taxes in Germany apply to taxable income after eligible deductions at a statutory tax rate of approximately 24%.  As a function of Germany's tax pools, the company does not presently pay taxes in Germany.


IRELAND BUSINESS UNIT

Overview

  • 18.5% non-operating interest in the offshore Corrib gas field located approximately 83 km off the northwest coast of Ireland.
  • Project comprises six offshore wells, offshore and onshore sales and transportation pipeline segments as well as a natural gas processing facility.
  • Corrib is expected to produce approximately 58 mmcf/d (9,700 boe/d) net to Vermilion at peak production rates.

Operational and financial review

      Three Months Ended   % change
Ireland business unit     Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
($M)     2015     2014     2014     Q4/14     Q1/14
  Transportation expense     (1,693)     (1,720)     (1,588)     (2%)     7%
  General and administration     (512)     (579)     (282)     (12%)     82%
  Fund flows from operations     (2,205)     (2,299)     (1,870)     (4%)     18%
Activity                              
  Capital expenditures     12,955     20,932     16,236     (38%)     (20%)


Activity review

  • Our Corrib project in Ireland has continued to progress as expected.  Project operator Shell E&P Ireland Limited is systematically preparing gas compression and other systems at the Bellanaboy gas processing terminal for safe and reliable processing of gas production.  The Irish Environmental Protection Agency issued its Proposed Determination for the Corrib Industrial Emissions License ("IEL") in April 2015.  Based on remaining terminal activities and typical approval timelines for the final form of the IEL, we estimate that the most likely date for start-up is approximately mid-year, with a modest range of outcomes around that estimate.
  • Production at Corrib is expected to increase over the first few months toward peak production levels estimated at approximately 58 mmcf/d (approximately 9,700 boe/d), net to Vermilion.

Transportation expense

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


AUSTRALIA BUSINESS UNIT

Overview

  • Entered Australia in 2005.
  • Hold a 100% operated working interest in the Wandoo field, located approximately 80 km offshore on the northwest shelf of Australia.
  • Production is operated from two off-shore platforms, and originates from 21 producing well bores.
  • Wells that utilize horizontal legs (ranging in length from 500 to 3,000 plus metres) are located 600 metres below the seabed in approximately 55 metres of water depth.
  • Contracted crude oil production is priced with reference to Dated Brent.


Operational review

      Three Months Ended   % change
        Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
Australia business unit     2015     2014     2014     Q4/14     Q1/14
Production                              
  Crude oil (bbls/d)     5,672     6,134     7,110     (8%)     (20%)
Inventory (mbbls)                              
  Opening crude oil inventory     37     258     130            
  Crude oil production     511     564     640            
  Crude oil sales     (230)     (785)     (707)            
  Closing crude oil inventory     318     37     63            
Activity                              
  Capital expenditures ($M)     6,455     11,616     5,691     (44%)     13%


Production

  • Quarterly production decreased 8% quarter-over-quarter and 20% year-over-year.  Production volumes are managed within corporate targets while meeting customer demands and the requirements of long-term supply agreements.
  • We continue to plan for long-term production levels of between 6,000 and 8,000 bbls/d.

Activity review

  • In Q1 2015, efforts were largely focused on facilities enhancement and engineering studies, including inspection work relating to platform life extension and pigging of the export line.
  • With the deferral of the drilling program, 2015 planned activities include ongoing facilities maintenance, enhancement, and refurbishment, as well as preparation and permitting activities in advance of our next drilling program.


Financial review

      Three Months Ended   % change  
Australia business unit     Mar 31,     Dec 31,     Mar 31,     Q1/15 vs.     Q1/15 vs.
($M except as indicated)     2015     2014     2014     Q4/14     Q1/14
  Sales     19,284     70,971     89,974     (73%)     (79%)
  Operating expense     (5,886)     (17,719)     (17,360)     (67%)     (66%)
  General and administration     (1,454)     (1,628)     (1,206)     (11%)     21%
  PRRT     (2,354)     (13,568)     (20,239)     (83%)     (88%)
  Corporate income taxes     (577)     (4,799)     (8,841)     (88%)     (93%)
  Fund flows from operations     9,013     33,257     42,328     (73%)     (79%)
Netbacks ($/boe)                              
  Sales     83.80     90.37     127.26     (7%)     (34%)
  Operating expense     (25.58)     (22.56)     (24.55)     13%     4%
  General and administration     (6.32)     (2.07)     (1.71)     205%     270%
  PRRT     (10.23)     (17.28)     (28.63)     (41%)     (64%)
  Corporate income taxes     (2.51)     (6.11)     (12.51)     (59%)     (80%)
  Fund flows from operations netback     39.16     42.35     59.86     (8%)     (35%)
Reference prices                              
  Dated Brent (US $/bbl)     53.97     76.27     108.22     (29%)     (50%)
  Dated Brent ($/bbl)     66.98     86.62     119.42     (23%)     (44%)


Sales

  • Our production in Australia currently receives a premium to Dated Brent.
  • During Q1 2015, inventory increased by 281,000 bbls versus a 221,000 bbls draw in Q4 2014 and a 67,000 bbls draw in Q1 2014.
  • Sales per boe for Q1 2015 decreased by 7% versus Q4 2014 as a result of the 23% decrease in the Dated Brent reference price in Canadian dollar terms. This decrease was coupled with the aforementioned build in inventory, resulting in a 73% decrease in sales.
  • Sales per boe for the three months ended March 31, 2015 decreased 34% versus the same period in 2014, consistent with a 44% decrease in the Dated Brent reference price in Canadian dollar terms. Combined with an increase in inventory, this resulted in a 79% decrease in sales.

Royalties and transportation expense

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

Operating expense

  • The decrease in operating expense for Q1 2015 as compared to Q4 2014 and Q1 2014 was largely the result of a build in inventory during the quarter.
  • Absent the impact of inventory adjustments, operating expenses on a dollar basis decreased for Q1 2015 as compared to both Q4 2014 and Q1 2014 as a result of savings from a wide range of cost reduction initiatives undertaken in response to commodity price weakness including reduced vessel usage and lower diesel consumption.  On a per boe basis, these cost reductions were offset by lower production volumes causing increased per barrel costs.

General and administration

  • General and administration expense for 2015 was relatively unchanged versus the comparative 2014 periods.  The timing of expenditures resulted in variances from quarter-to-quarter.

PRRT and corporate income taxes

  • In Australia, current income taxes include both PRRT and corporate income taxes.  PRRT is a profit based tax applied at a rate of 40% on sales less eligible expenditures, including operating expenses and capital expenditures.  Corporate income taxes are applied at a rate of 30% on taxable income after eligible deductions, which include PRRT.
  • For 2015, the combined corporate income tax and PRRT effective rate is expected to be between approximately 25% and 27%.  This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.
  • Combined corporate income taxes and PRRT for Q1 2015 were lower relative to both comparable periods in 2014.  The decrease was consistent with lower sales.


UNITED STATES BUSINESS UNIT

Overview

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

Operational and financial review

      Three Months Ended     % change
United States business unit     Mar 31,     Dec 31,     Q1/15 vs.
($M except as indicated)     2015     2014     Q4/14
  Sales     672     1,330     (49%)
  Royalties     (206)     (366)     (44%)
  Operating expense     (215)     (241)     (11%)
  General and administration     (1,080)     (959)     13%
  Fund flows from operations     (829)     (236)     251%
Netbacks ($/boe)                  
  Sales     48.79     74.08     (34%)
  Royalties     (14.98)     (20.38)     (26%)
  Operating expense     (15.61)     (13.44)     16%
  General and administration     (78.41)     (53.44)     47%
  Fund flows from operations netback     (60.21)     (13.18)     357%
Reference prices                  
  WTI (US $/bbl)     48.63     73.15     (34%)
  WTI ($/bbl)     60.35     83.08     (27%)
Production                  
  Crude oil (bbls/d)     153     195     (22%)
Activity                  
  Capital expenditures     637     460     38%


Activity review

  • The most recently completed well on this land block (70% working interest) is currently producing approximately 130 bbls/d of oil in its tenth month of production, from an approximately 1,100 metre hydraulically-fractured horizontal lateral.
  • Drilling commenced subsequent to the end of Q1 for the one well planned in the East Finn prospect for 2015.

Sales

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

Royalties expense

  • Our production in the United States is subject to federal and private royalties, severance tax, and ad valorem tax at a combined rate of approximately 27.5% of sales.

Operating expense

  • Operating expense was consistent with the prior quarter.

General and administration

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

CORPORATE

Overview

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

Financial review

      Three Months Ended
      Mar 31,     Dec 31,     Mar 31,
($M)     2015     2014     2014
General and administration     957     1,224     (3,751)
Current income taxes     (377)     (642)     (173)
Interest expense     (13,298)     (12,943)     (11,460)
Realized gain on derivatives     6,257     22,816     2,640
Realized foreign exchange gain (loss)     3,306     (179)     (2,041)
Realized other income     222     202     221
Fund flows from operations     (2,933)     10,478     (14,564)

General and administration

  • General and administration expense for Q1 2015 was consistent with Q4 2014.
  • On a year-over-year basis, the decrease in general and administration costs for the three months ended March 31, 2015, as compared to 2014 is due to a decrease in staff-related expenditures, general cost saving initiatives in response to declining crude prices, and increased salary allocations to the various segments.

Current income taxes

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

Interest expense

  • Interest expense is incurred on our senior unsecured notes and on borrowings under our revolving credit facility.  The increase in Q1 2015 versus Q4 2014 and Q1 2014 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) 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 2015 related primarily to amounts received on our TTF, AECO, and Dated Brent derivatives, partially offset by payments made on our foreign exchange derivatives.
  • A listing of derivative positions as at March 31, 2015 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)   2015   2014   2014   2014   2014   2013   2013   2013
Petroleum and natural gas sales   195,885   306,073   344,688   387,684   381,183   325,108   327,185   311,966
Net earnings   1,275   58,642   53,903   53,993   102,788   101,510   67,796   106,198
Net earnings per share                                
  Basic   0.01   0.55   0.50   0.51   1.00   1.00   0.67   1.05
  Diluted   0.01   0.54   0.50   0.50   0.99   0.98   0.66   1.04

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

($M)     Q1/15 vs. Q4/14     Q1/15 vs. Q1/14
Net earnings - Comparative period     58,642     102,788
Changes in:            
Fund flows from operations     (64,733)     (84,568)
Equity based compensation     (647)     (2,568)
Unrealized gain or loss on derivative instruments     (37,127)     (23,905)
Unrealized foreign exchange gain or loss     (859)     (26,845)
Unrealized other expense     484     (7)
Accretion     512     37
Depletion and depreciation     26,224     8,495
Deferred tax     18,779     27,848
Net earnings - Current period     1,275     1,275

The fluctuations in net earnings from quarter-to-quarter and from year-to-year are caused by changes in both cash and non-cash based income and charges.  Cash based items are reflected in fund flows from operations and include: sales, royalties, operating expenses, transportation, general and administration expense, current tax expense, interest expense, realized gains and losses on derivative instruments, and realized foreign exchange gains and losses.  Non-cash items include: equity based compensation expense, unrealized gains and losses on derivative instruments, unrealized foreign exchange gains and losses, accretion, depletion and depreciation expense, and deferred taxes.  In addition, non-cash items may also include amounts resulting from acquisitions or charges resulting from impairment or impairment recoveries.

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

Equity based compensation expense in Q1 2015 was relatively consistent as compared to Q4 2014.  The increase of $2.6 million (16%) as compared to Q1 2014 is due to a higher number of VIP awards outstanding, as well as an upward revision of future performance condition assumptions that occurred in Q2 2014.

Unrealized gain or loss on derivative instruments
Unrealized gain or loss on derivative instruments arise as a result of changes in forecasted future commodity prices.  As Vermilion uses derivative instruments to manage the commodity price exposure of our future crude oil and natural gas production, we will normally recognize unrealized gains on derivative instruments when forecasted future commodity prices decline and vice-versa.

For the three months ended March 31, 2015, we recognized an unrealized loss on derivative instruments of $20.0 million, relating primarily to our TTF and US dollar swaps and collars. As at March 31, 2015, we have a net derivative asset position of $4.8 million.

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

Unrealized foreign exchange gains and losses are the result of translating monetary assets and liabilities held in non-functional currencies to the respective functional currencies of Vermilion and its subsidiaries.  Unrealized foreign exchange primarily results from the translation of Euro denominated financial assets.  As such, an appreciation in the Euro against the Canadian dollar will result in an unrealized foreign exchange gain, and vice-versa.

For the three months ended March 31, 2015, the Canadian dollar strengthened slightly versus the Euro, which partially offset by a weakening of the Canadian dollar versus the US dollar, resulting in an unrealized foreign exchange loss of $4.8 million.

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

Q1 2015 accretion expense was relatively consistent compared to Q4 2014 and Q1 2014.

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

Depletion and depreciation on a per boe basis of $21.90 in Q1 2015 was lower as compared to $24.42 in Q4 2014 and $23.13 in Q1 2014. The decrease is due to increased production from the Mannville condensate-rich gas play in Canada and natural gas properties in the Netherlands, which have lower per boe depletion expense as compared to 2014.

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

FINANCIAL POSITION REVIEW

Balance sheet strategy
We believe that our balance sheet supports our defined growth initiatives and our focus is on managing and maintaining a conservative balance sheet.  To ensure that our balance sheet continues to support our defined growth initiatives, we regularly review whether forecasted fund flows from operations is sufficient to finance planned capital expenditures, dividends, and abandonment and reclamation expenditures.  To the extent that forecasted fund flows from operations is not expected to be sufficient to fulfill such expenditures, we will evaluate our ability to finance any excess with debt (including borrowing using the unutilized capacity of our existing revolving credit facility) or issue equity.

To ensure that we maintain a conservative balance sheet, we monitor the ratio of net debt to fund flows from operations and typically strive to maintain an internally targeted ratio of approximately 1.0 to 1.3 in a normalized commodity price environment. Where prices trend higher, we may target a lower ratio and conversely, in a lower commodity price environment, the acceptable ratio may be higher.  At times, we will use our balance sheet to finance acquisitions and, in these situations, we are prepared to accept a higher ratio in the short term but will implement a strategy to reduce the ratio to acceptable levels within a reasonable period of time, usually considered to be no more than 12 to 24 months.  This plan could potentially include an increase in hedging activities, a reduction in capital expenditures, an issuance of equity or the utilization of excess fund flows from operations to reduce outstanding indebtedness.

In the current low commodity price environment, Vermilion's net debt to fund flows ratio is expected to be higher than the longer term target ratio. During this period, Vermilion will remain focused on maintaining a strong balance sheet and will manage the business accordingly.

Long-term debt
Our long-term debt consists of our revolving credit facility and our senior unsecured notes.  The applicable annual interest rates and the balances recognized on our balance sheet are as follows:

      Annual Interest Rate     As At
      Mar 31,     Dec 31,     Mar 31,     Dec 31,
($M)     2015     2014     2015     2014
Revolving credit facility     3.0%     3.1%     1,168,614     1,014,067
Senior unsecured notes (1)     6.5%     6.5%     224,235     224,013
Long-term debt     3.6%     3.8%     1,392,849     1,238,080

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

Revolving Credit Facility
On January 30, 2015, Vermilion exercised its option to increase its credit facility from $1.5 billion to $1.75 billion.  Subsequent to Q1 2015, we negotiated a further expansion and extension of our existing revolving credit facilities from $1.75 billion to $2 billion with a maturity of May 2019.  The facility bears interest at rates applicable to demand loans plus applicable margins.  The following table outlines the terms of our revolving credit facility:

            As At
            Mar 31,     Dec 31,
            2015     2014
Total facility amount           $1.75 billion     $1.50 billion
Amount drawn           $1.2 billion     $1.0 billion
Letters of credit outstanding           $9.8 million     $8.6 million
Facility maturity date           31-May-17     31-May-17

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

          As At
            Mar 31,     Dec 31,
Financial covenant     Limit     2015     2014
Consolidated total debt to consolidated EBITDA     4.0     1.55     1.21
Consolidated total senior debt to consolidated EBITDA     3.0     1.30     0.99
Consolidated total senior debt to total capitalization     50%     35%     31%

Our covenants include financial measures defined within our revolving credit facility agreement that are not defined under GAAP.  These financial measures are defined by our revolving credit facility agreement as follows:

  • Consolidated total debt: Includes all amounts classified as "Long-term debt" on our balance sheet, including the current portion.
  • Consolidated total senior debt: Defined as consolidated total debt excluding unsecured and subordinated debt.
  • Consolidated EBITDA: Defined as consolidated net earnings before interest, income taxes, depreciation, accretion and certain other non-cash items.
  • Total capitalization: Includes all amounts on our balance sheet classified as "Long-term debt", including the current portion, and "Shareholders' equity".

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

Senior Unsecured Notes
We have outstanding senior unsecured notes that are senior unsecured obligations and rank pari passu with all our other present and future unsecured and unsubordinated indebtedness.  The following table outlines the terms of these notes:

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

Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest.  The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

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

      As At
      Mar 31,     Dec 31,
($M)     2015     2014
Long-term debt     1,168,614     1,238,080
Current liabilities(1)     549,580     365,729
Current assets     (329,591)     (338,159)
Net debt     1,388,603     1,265,650
             
Ratio of net debt to annualized fund flows from operations     2.9     1.6

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

Long term debt, including the current portion, as at March 31, 2015 increased to $1.39 billion from $1.24 billion as at December 31, 2014 as a result of draws on the revolving credit facility during the current year to fund capital expenditures, particularly relating to development expenditures in Canada and Ireland. The increase in long-term debt resulted in an increase to net debt from $1.27 billion to $1.39 billion. As a result of this increase to long-term debt and weak commodity prices, the ratio of net debt to fund flows from operations increased from 1.6 times as at December 31, 2014 to 2.9 times as at March 31, 2015.

Shareholders' capital
During the three months ended March 31, 2015, we maintained monthly dividends at $0.215 per share and declared dividends which totalled $69.4 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
January 2014 to Present           $0.215

Our policy with respect to dividends is to be conservative and maintain a low ratio of dividends to fund flows from operations.  During low 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.  In a further step to preserve our financial flexibility and conservatively exercise our access to capital, an amendment to our existing DRIP to include a Premium Dividend™ Component was announced in February 2015.  The Premium Dividend™ Component, when combined with our continuing Dividend Reinvestment Component, is expected to increase our access, at the election of shareholders, to the lowest cost sources of equity capital available.  While the Premium Dividend™ is expected to result in a modest amount of equity issuance, we believe it represents the most prudent approach to preserving near-term balance sheet strength.  We view implementation of a Premium Dividend™ as a short-term measure to maintain our financial flexibility while we continue to lower our unit costs and await further clarity on the direction of commodity prices.  Both components of our program can be turned off at the company's discretion, offering considerable flexibility.  We will actively monitor our ongoing needs and manage our continued use of each component as circumstances dictate.  It is not currently expected that Vermilion will be required to change its dividend in 2015.

Although we currently expect to be able to maintain our current dividend, fund flows from operations may not be sufficient during this period to fund cash dividends, capital expenditures and asset retirement obligations.  We will evaluate our ability to finance any shortfalls with debt, issuances of equity or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.

The following table reconciles the change in shareholders' capital:

Shareholders' Capital     Number of Shares ('000s)     Amount ($M)
Balance as at December 31, 2014     107,303     1,959,021
Issuance of shares pursuant to the dividend reinvestment plan     405     21,378
Shares issued pursuant to the bonus plan     10     532
Balance as at March 31, 2015     107,718     1,980,931

As at March 31, 2015, there were approximately 1.8 million VIP awards outstanding.  As at May 7, 2015, there were approximately 109.3 million common shares issued and outstanding.

ASSET RETIREMENT OBLIGATIONS

As at March 31, 2015, asset retirement obligations were $377.0 million compared to $350.8 million as at December 31, 2014.

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

OFF BALANCE SHEET ARRANGEMENTS

We have certain lease agreements that are entered into in the normal course of operations, including operating leases for which no asset or liability value has been assigned to the consolidated balance sheet as at March 31, 2015.

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

RISK MANAGEMENT

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

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies.  These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made.  As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on Vermilion's consolidated financial statements.  Estimates are reviewed by management on an ongoing basis and as a result may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction that Vermilion operates in, the critical accounting estimates may affect one or more jurisdictions.  There have been no changes to our critical accounting estimates used in applying accounting policies for the three months ended March 31, 2015.  Further information, including a discussion of critical accounting estimates, can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2014, available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

INTERNAL CONTROL OVER FINANCIAL REPORTING

There was no change in Vermilion's internal control over financial reporting that occurred during the period covered by this MD&A that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

Supplemental Table 1: Netbacks

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

      Three Months Ended March 31, 2015     Three Months Ended March 31, 2014
      Oil & NGLs     Natural Gas     Total     Oil & NGLs     Natural Gas     Total
      $/bbl     $/mcf     $/boe     $/bbl     $/mcf     $/boe
Canada                                    
Sales     49.15     2.97     35.81     95.25     5.50     69.26
Royalties     (5.87)     (0.23)     (3.95)     (10.75)     (0.34)     (7.12)
Transportation     (2.42)     (0.16)     (1.81)     (2.27)     (0.17)     (1.74)
Operating     (9.02)     (1.41)     (8.78)     (10.99)     (1.17)     (9.34)
Operating netback     31.84     1.17     21.27     71.24     3.82     51.06
General and administration                 (1.85)                 (1.61)
Fund flows from operations netback                 19.42                 49.45
France                                    
Sales     64.33     -     64.33     117.54     -     117.54
Royalties     (5.48)     -     (5.49)     (7.35)     -     (7.35)
Transportation     (3.24)     -     (3.24)     (4.75)     -     (4.75)
Operating     (11.64)     -     (11.64)     (16.42)     -     (16.42)
Operating netback     43.97     -     43.96     89.02     -     89.02
General and administration                 (5.49)                 (5.19)
Other income                 34.16                 -  
Current income taxes                 (15.35)                 (25.26)
Fund flows from operations netback                 57.28                 58.57
Netherlands                                    
Sales     52.93     8.09     48.60     106.96     10.53     63.60
Royalties     -     (0.28)     (1.68)     -     (0.57)     (3.38)
Operating     -     (1.78)     (10.56)     -     (1.56)     (9.25)
Operating netback     52.93     6.03     36.36     106.96     8.40     50.97
General and administration                 (1.34)                 (0.91)
Current income taxes                 (4.33)                 (5.80)
Fund flows from operations netback                 30.69                 44.26
Germany                                    
Sales     -     7.53     45.21     -     9.31     55.85
Royalties     -     (1.06)     (6.34)     -     (1.88)     (11.29)
Transportation     -     (0.59)     (3.55)     -     (0.44)     (2.64)
Operating     -     (1.32)     (7.93)     -     (1.62)     (9.74)
Operating netback     -     4.56     27.39     -     5.37     32.18
General and administration                 (6.38)                 (3.56)
Current income taxes                 -                 (3.36)
Fund flows from operations netback                 21.01                 25.26
Australia                                    
Sales     83.80     -     83.80     127.26     -     127.26
Operating     (25.58)     -     (25.58)     (24.55)     -     (24.55)
PRRT (1)     (10.23)     -     (10.23)     (28.63)     -     (28.63)
Operating netback     47.99     -     47.99     74.08     -     74.08
General and administration                 (6.32)                 (1.71)
Corporate income taxes                 (2.51)                 (12.51)
Fund flows from operations netback                 39.16                 59.86
United States                                    
Sales     48.79     -     48.79     -     -     -
Royalties     (14.98)     -     (14.98)     -     -     -
Operating     (15.61)     -     (15.61)     -     -     -
Operating netback     18.20     -     18.20     -     -     -
General and administration                 (78.41)                 -
Fund flows from operations netback                 (60.21)                 -
Total Company                                    
Sales     58.25     5.26     47.17     111.62     7.99     88.67
Realized hedging gain     0.75     0.43     1.51     0.26     0.21     0.61
Royalties     (5.21)     (0.37)     (3.95)     (6.72)     (0.60)     (5.59)
Transportation     (2.49)     (0.34)     (2.30)     (2.58)     (0.30)     (2.29)
Operating     (11.61)     (1.51)     (10.56)     (16.43)     (1.38)     (13.49)
PRRT (1)     (0.97)     -     (0.57)     (7.36)     -     (4.71)
Operating netback     38.72     3.47     31.30     78.79     5.92     63.20
General and administration                 (3.27)                 (3.37)
Interest expense                 (3.20)                 (2.67)
Realized foreign exchange gain (loss)                 0.78                 (0.47)
Other income                 7.70                 0.05
Corporate income taxes (1)                 (4.24)                 (8.98)
Fund flows from operations netback                 29.07                 47.76

(1)    Vermilion considers Australian PRRT to be an operating item and accordingly has included PRRT in the calculation of operating netbacks.  Current income taxes presented above excludes PRRT.


Supplemental Table 2: Hedges

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

      Note     Volume     Strike Price(s)
Crude Oil                  
WTI - Collar                  
January 2015 - June 2015     1     250 bbl/d     75.00 - 82.75 US $
March 2015 - May 2015           1,000 bbl/d     48.00 - 59.23 US $
April 2015 - June 2015     2     500 bbl/d     54.50 - 66.28 US $
Dated Brent - Collar                  
March 2015 - May 2015           1,000 bbl/d     52.00 - 62.21 US $
March 2015 - June 2015           250 bbl/d     58.00 - 69.35 US $
April 2015 - September 2015     1     250 bbl/d     60.00 - 74.15 US $
                   
North American Natural Gas                  
AECO - Collar                  
April 2015 - October 2015           2,500 GJ/d     2.75 - 3.52 CAD $
April 2015 - December 2015           2,500 GJ/d     2.75 - 3.52 CAD $
AECO - Swap                  
April 2015 - October 2015     3     10,000 GJ/d     2.98 CAD $
April 2015 - December 2015     4     2,500 GJ/d     2.99 CAD $
AECO Basis - Fixed Price Differential                  
January 2015 - December 2015           5,000 mmbtu/d     Nymex HH less 0.68 US $
April 2015 - October 2015           7,500 mmbtu/d     Nymex HH less 0.62 US $
Nymex HH - Collar                  
April 2015 - October 2015           10,000 mmbtu/d     3.36 - 4.01 US $
April 2015 - December 2015           2,500 mmbtu/d     3.50 - 4.11 US $
November 2015 - March 2016     5     5,000 mmbtu/d     3.25 - 3.86 US $

(1)  The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price.
(2)  The contracted volumes increase to 1,500 boe/d for any monthly settlement periods above the contracted ceiling price.
(3)  On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 10,000 GJ/d at the contracted price, for the following month.
(4)  On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 2,500 GJ/d at the contracted    price, for the following month.
(5)  The contracted volumes increase to 10,000 mmbtu/d for any monthly settlement periods above the contracted ceiling price.

                   
European Natural Gas                  
NBP - Swap                  
July 2015 - March 2016           2,592 GJ/d     6.42 EUR €
October 2015 - March 2016           10,368 GJ/d     6.54 EUR €
January 2016 - June 2016           2,592 GJ/d     6.32 EUR €
January 2016 - June 2016           2,592 GJ/d     6.82 US $
TTF - Collar                  
January 2015 - December 2015           2,592 GJ/d     6.11 - 6.83 EUR €
TTF - Swap                  
January 2015 - December 2015           11,664 GJ/d     6.45 EUR €
January 2015 - March 2016           5,184 GJ/d     6.40 EUR €
January 2015 - June 2016           2,592 GJ/d     6.07 EUR €
February 2015 - March 2016           5,184 GJ/d     6.24 EUR €
April 2015 - December 2015           2,592 GJ/d     6.30 EUR €
April 2015 - March 2016           5,832 GJ/d     6.18 EUR €
October 2015 - December 2015           2,592 GJ/d     5.69 EUR €
October 2015 - March 2016           2,592 GJ/d     6.64 EUR €
                   
                   
Electricity                  
AESO - Swap                  
January 2016 - December 2016           31.2 MWh/d     39.00 CAD $
AESO - Swap (Physical)                  
January 2013 - December 2015           72.0 MWh/d     53.17 CAD $
                   
US Dollar                  
USD - Collar                  
January 2015 - June 2015     1     5,000,000 US $/month     1.162 - 1.181 CAD $
February 2015 - December 2015           2,500,000 US $/month     1.180 - 1.223 CAD $
USD - Forward                  
February 2015 - December 2015           2,500,000 US $/month     1.198 CAD $

(1)  Vermilion has upside participation on this hedge up to the limit price of 1.253 CAD; above which, settlement will occur at the conditional call level of 1.181 CAD.

Supplemental Table 3: Capital Expenditures

      Three Months Ended
By classification     Mar 31,     Dec 31,     Mar 31,
($M)     2015     2014     2014
Drilling and development     174,311     151,395     168,840
Exploration and evaluation     -     14,848     27,535
Capital expenditures     174,311     166,243     196,375
Property acquisition     35     1,652     178,227
Acquisitions     35     1,652     178,227
                   
      Three Months Ended
By category     Mar 31,     Dec 31,     Mar 31,
($M)     2015     2014     2014
Land     742     1,457     4,753
Seismic     1,493     7,598     3,432
Drilling and completion     82,343     69,691     106,536
Production equipment and facilities     74,755     77,272     68,755
Recompletions     7,115     7,696     4,226
Other     7,863     2,529     8,673
Capital expenditures     174,311     166,243     196,375
Acquisitions     35     1,652     178,227
Total capital expenditures and acquisitions     174,346     167,895     374,602
                   
      Three Months Ended
By country     Mar 31,     Dec 31,     Mar 31,
($M)     2015     2014     2014
Canada     114,884     87,113     119,707
France     34,114     37,189     37,967
Netherlands     4,333     10,022     20,118
Germany     968     563     173,067
Ireland     12,955     20,932     16,236
Australia     6,455     11,616     5,691
United States     637     460     -
Corporate     -     -     1,816
Total capital expenditures and acquisitions     174,346     167,895     374,602

Supplemental Table 4: Production

      Q1/15   Q4/14   Q3/14   Q2/14   Q1/14   Q4/13   Q3/13   Q2/13   Q1/13   Q4/12   Q3/12   Q2/12
Canada                                                
  Crude oil (bbls/d)   10,893   11,384   11,469   12,676   9,437   8,719   7,969   8,885   7,966   7,983   7,322   7,757
  NGLs (bbls/d)   2,976   2,741   2,291   2,796   2,071   1,699   1,897   1,725   1,335   1,106   1,204   1,321
  Natural gas (mmcf/d)   61.78   58.36   57.07   57.59   49.53   41.43   43.40   43.69   41.04   31.41   35.54   41.32
  Total (boe/d)   24,165   23,851   23,272   25,070   19,763   17,322   17,099   17,892   16,140   14,323   14,449   15,965
  % of consolidated   48%   49%   47%   49%   42%   43%   41%   42%   41%   40%   40%   40%
France                                                
  Crude oil (bbls/d)   11,463   11,133   11,111   11,025   10,771   11,131   11,625   10,390   10,330   9,843   9,767   9,931
  Natural gas (mmcf/d)   -   -   -   -   -   -   5.23   4.19   4.21   3.91   3.39   3.57
  Total (boe/d)   11,463   11,133   11,111   11,025   10,771   11,131   12,496   11,088   11,032   10,495   10,333   10,526
  % of consolidated   23%   22%   22%   21%   23%   27%   30%   26%   29%   29%   28%   27%
Netherlands                                                
  NGLs (bbls/d)   63   81   63   96   69   62   48   50   96   70   41   84
  Natural gas (mmcf/d)   36.41   31.35   38.07   40.35   43.15   37.53   28.78   38.52   36.91   33.03   34.59   33.74
  Total (boe/d)   6,132   5,306   6,407   6,822   7,260   6,318   4,845   6,470   6,248   5,574   5,806   5,707
  % of consolidated   12%   11%   13%   13%   16%   15%   12%   15%   16%   15%   16%   15%
Germany                                                
  Natural gas (mmcf/d)   16.80   17.71   15.38   16.13   10.64   -   -   -   -   -   -   -
  Total (boe/d)   2,801   2,952   2,563   2,689   1,773   -   -   -   -   -   -   -
  % of consolidated   6%   6%   5%   5%   4%   -   -   -   -   -   -   -
Australia                                                
  Crude oil (bbls/d)   5,672   6,134   6,567   6,483   7,110   6,189   7,070   7,363   5,287   5,873   5,958   6,970
  % of consolidated   11%   12%   13%   12%   15%   15%   17%   17%   14%   16%   16%   18%
United States                                                
  Crude oil (bbls/d)   153   195   -   -   -   -   -   -   -   -   -   -
Consolidated                                                
  Crude oil & NGLs (bbls/d)   31,220   31,668   31,501   33,076   29,458   27,800   28,609   28,413   25,014   24,875   24,292   26,063
  % of consolidated   62%   64%   63%   63%   63%   68%   69%   66%   65%   69%   66%   67%
  Natural gas (mmcf/d)   115.00   107.42   110.52   114.08   103.32   78.96   77.41   86.40   82.16   68.34   73.52   78.63
    % of consolidated   38%   36%   37%   37%   37%   32%   31%   34%   35%   31%   34%   33%
  Total (boe/d)   50,386   49,571   49,920   52,089   46,677   40,960   41,510   42,813   38,707   36,265   36,546   39,168
                                                   
      2015   2014   2013   2012   2011   2010                        
Canada                                                
    Crude oil (bbls/d)   10,893   11,248   8,387   7,659   4,701   2,778                        
    NGLs (bbls/d)   2,976   2,476   1,666   1,232   1,297   1,427                        
    Natural gas (mmcf/d)   61.78   55.67   42.39   37.50   43.38   43.91                        
    Total (boe/d)   24,165   23,001   17,117   15,142   13,227   11,524                        
    % of consolidated   48%   47%   41%   40%   38%   36%                        
France                                                
    Crude oil (bbls/d)   11,463   11,011   10,873   9,952   8,110   8,347                        
    Natural gas (mmcf/d)   -     -     3.40   3.59   0.95   0.92                        
  Total (boe/d)   11,463   11,011   11,440   10,550   8,269   8,501                        
  % of consolidated   23%   22%   28%   28%   23%   26%                        
Netherlands                                                
    NGLs (bbls/d)   63   77   64   67   58   35                        
    Natural gas (mmcf/d)   36.41   38.20   35.42   34.11   32.88   28.31                        
    Total (boe/d)   6,132   6,443   5,967   5,751   5,538   4,753                        
  % of consolidated   12%   13%   15%   15%   16%   15%                        
Germany                                                
    Natural gas (mmcf/d)   16.80   14.99   -   -   -   -                        
    Total (boe/d)   2,801   2,498   -   -   -   -                        
    % of consolidated   6%   5%   -   -   -   -                        
Australia                                                
    Crude oil (bbls/d)   5,672   6,571   6,481   6,360   8,168   7,354                        
    % of consolidated   11%   13%   16%   17%   23%   23%                        
United States                                                
    Crude oil (bbls/d)   153   49   -   -   -   -                        
Consolidated                                                
    Crude oil & NGLs (bbls/d)   31,220   31,432   27,471   25,270   22,334   19,941                        
    % of consolidated   62%   63%   67%   67%   63%   62%                        
    Natural gas (mmcf/d)   115.00   108.85   81.21   75.20   77.21   73.14                        
    % of consolidated   38%   37%   33%   33%   37%   38%                        
  Total (boe/d)   50,386   49,573   41,005   37,803   35,202   32,132

Supplemental Table 5: Segmented Financial Results

  Three Months Ended March 31, 2015
($M) Canada   France   Netherlands   Germany   Ireland   Australia   United States   Corporate   Total
Drilling and development 114,849   34,114   4,333   968   12,955   6,455   637   -   174,311
Oil and gas sales to external customers 77,884   59,832   26,818   11,395   -   19,284   672   -   195,885
Royalties (8,592)   (5,102)   (926)   (1,598)   -   -   (206)   -   (16,424)
Revenue from external customers 69,292   54,730   25,892   9,797   -   19,284   466   -   179,461
Transportation expense (3,942)   (3,011)   -   (894)   (1,693)   -   -   -   (9,540)
Operating expense (19,099)   (10,826)   (5,826)   (1,999)   -   (5,886)   (215)   -   (43,851)
General and administration (4,015)   (5,111)   (737)   (1,608)   (512)   (1,454)   (1,080)   957   (13,560)
PRRT -   -   -   -   -   (2,354)   -   -   (2,354)
Corporate income taxes -   (14,281)   (2,388)   -   -   (577)   -   (377)   (17,623)
Interest expense -   -   -   -   -   -   -   (13,298)   (13,298)
Realized gain on derivative instruments -   -   -   -   -   -   -   6,257   6,257
Realized foreign exchange gain -   -   -   -   -   -   -   3,306   3,306
Realized other income -   31,775   -   -   -   -   -   222   31,997
Fund flows from operations 42,236   53,276   16,941   5,296   (2,205)   9,013   (829)   (2,933)   120,795


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, 2015, we consider fund flows from operations to be an additional GAAP financial measure.

Free cash flow: Represents fund flows from operations in excess of capital expenditures.  We consider free cash flow to be a key measure as it is used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures. 

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

Payout:  We define payout as net dividends plus drilling and development, exploration and evaluation, dispositions and asset retirement obligations settled.  Management uses payout to assess the amount of cash distributed back to shareholders and re-invested in the business for maintaining production and organic growth.

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

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

Diluted shares outstanding: Is the sum of shares outstanding at the period end plus outstanding awards under the VIP, based on current estimates of future performance factors and forfeiture rates.

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

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

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

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

      Three Months Ended
        Mar 31,     Dec 31,     Mar 31,
($M)     2015     2014     2014
Cash flows from operating activities     22,647     229,146     178,238
Changes in non-cash operating working capital     95,041     (49,865)     24,474
Asset retirement obligations settled     3,107     6,247     2,651
Fund flows from operations     120,795     185,528     205,363
Expenses related to Corrib     2,205     2,299     1,870
Fund flows from operations (excluding Corrib)     123,000     187,827     207,233
                   
      Three Months Ended
        Mar 31,     Dec 31,     Mar 31,
($M)     2015     2014     2014
Dividends declared     69,390     69,119     66,007
Issuance of shares pursuant to the dividend reinvestment plan     (21,378)     (20,980)     (18,885)
Net dividends     48,012     48,139     47,122
Drilling and development     174,311     151,395     168,840
Exploration and evaluation     -     14,848     27,535
Asset retirement obligations settled     3,107     6,247     2,651
Payout     225,430     220,629     246,148
Corrib drilling and development     (12,955)     (20,932)     (16,236)
Payout (excluding Corrib)     212,475     199,697     229,912
                   
      As At
      Mar 31,     Dec 31,     Mar 31,
('000s of shares)     2015     2014     2014
Shares outstanding     107,718     107,303     102,453
Potential shares issuable pursuant to the VIP     3,043     3,031     2,714
Diluted shares outstanding     110,761     110,334     105,167

CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

          March 31,     December 31,
    Note     2015     2014
ASSETS                
Current                
Cash and cash equivalents         88,192     120,405
Accounts receivable         169,378     171,820
Crude oil inventory         26,358     9,510
Derivative instruments         10,000     23,391
Income tax receivable         19,394     -  
Prepaid expenses         16,269     13,033
          329,591     338,159
                 
Derivative instruments         -       1,403
Deferred taxes         154,532     154,816
Exploration and evaluation assets   3     378,276     380,621
Capital assets   2     3,599,999     3,511,092
          4,462,398     4,386,091
                 
LIABILITIES                
Current                
Accounts payable and accrued liabilities         283,885     298,196
Current portion of long-term debt   5     224,235     -  
Dividends payable   6     23,159     23,070
Derivative instruments         5,176     -  
Income taxes payable         13,125     44,463
          549,580     365,729
                 
Long-term debt   5     1,168,614     1,238,080
Finance lease obligation   2     26,751     -  
Asset retirement obligations   4     377,003     350,753
Deferred taxes         386,935     410,183
          2,508,883     2,364,745
                 
SHAREHOLDERS' EQUITY                
Shareholders' capital   6     1,980,931     1,959,021
Contributed surplus         110,696     92,188
Accumulated other comprehensive (loss) income         (34,412)     5,722
Deficit         (103,700)     (35,585)
          1,953,515     2,021,346
          4,462,398     4,386,091

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

          Three Months Ended
          March 31,     March 31,
    Note     2015     2014
REVENUE                
Petroleum and natural gas sales         195,885     381,183
Royalties         (16,424)     (24,024)
Petroleum and natural gas revenue         179,461     357,159
                 
EXPENSES                
Operating         43,851     57,986
Transportation         9,540     9,861
Equity based compensation   7     19,040     16,472
Loss (gain) on derivative instruments         13,713     (6,575)
Interest expense         13,298     11,460
General and administration         13,560     14,467
Foreign exchange loss (gain)         1,539     (19,959)
Other (income) expense   11     (31,736)     33
Accretion   4     5,675     5,712
Depletion and depreciation   2, 3     90,957     99,452
          179,437     188,909
EARNINGS BEFORE INCOME TAXES         24     168,250
                 
INCOME TAXES                
Deferred         (21,228)     6,620
Current         19,977     58,842
          (1,251)     65,462
                 
NET EARNINGS         1,275     102,788
                 
OTHER COMPREHENSIVE (LOSS) INCOME                
Currency translation adjustments         (40,134)     45,535
COMPREHENSIVE (LOSS) INCOME         (38,859)     148,323
                 
NET EARNINGS PER SHARE                
Basic             0.01     1.00
Diluted         0.01     0.99
                 
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)                
Basic         107,513     102,278
Diluted         109,305     104,171

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

          Three Months Ended
          March 31,     March 31,
    Note     2015     2014
OPERATING                
Net earnings         1,275     102,788
Adjustments:                
  Accretion   4     5,675     5,712
  Depletion and depreciation   2, 3     90,957     99,452
  Unrealized loss (gain) on derivative instruments         19,970     (3,935)
  Equity based compensation   7     19,040     16,472
  Unrealized foreign exchange loss (gain)         4,845     (22,000)
  Unrealized other expense         261     254
  Deferred taxes         (21,228)     6,620
Asset retirement obligations settled   4     (3,107)     (2,651)
Changes in non-cash operating working capital         (95,041)     (24,474)
Cash flows from operating activities         22,647     178,238
                 
INVESTING                
Drilling and development   2     (174,311)     (168,840)
Exploration and evaluation   3     -     (27,535)
Property acquisitions   2, 3     (35)     (178,227)
Changes in non-cash investing working capital         12,143     39,473
Cash flows used in investing activities         (162,203)     (335,129)
                 
FINANCING                
Increase (decrease) in long-term debt         154,914     (50,000)
Cash dividends         (47,923)     (45,520)
Cash flows from (used in) financing activities         106,991     (95,520)
Foreign exchange gain on cash held in foreign currencies         352     14,189
                 
Net change in cash and cash equivalents         (32,213)     (238,222)
Cash and cash equivalents, beginning of period         120,405     389,559
Cash and cash equivalents, end of period         88,192     151,337
                 
Supplementary information for operating activities - cash payments                
  Interest paid         18,245     14,094
  Income taxes paid         70,513     21,074

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

                    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       -     15,751     -     -     15,751
Dividends declared 6     -     -     -     (66,007)     (66,007)
Shares issued pursuant to the                                
   dividend reinvestment plan 6     18,885     -     -     -     18,885
Modification of equity based awards       -     (2,396)     -     -     (2,396)
Shares issued pursuant to the bonus plan 6     721     -     -     -     721
Balances as at March 31, 2014       1,638,049     88,782     92,677     12,144     1,831,652
                                 
                    Accumulated            
                    Other           Total
        Shareholders'     Contributed     Comprehensive           Shareholders'
  Note     Capital     Surplus     Loss     Deficit     Equity
Balances as at January 1, 2015       1,959,021     92,188     5,722     (35,585)     2,021,346
Net earnings       -     -     -     1,275     1,275
Currency translation adjustments       -     -     (40,134)     -     (40,134)
Equity based compensation expense 7     -     18,508     -     -     18,508
Dividends declared 6     -     -     -     (69,390)     (69,390)
Shares issued pursuant to the                                
   dividend reinvestment plan 6     21,378     -     -     -     21,378
Shares issued pursuant to the bonus plan 6     532     -     -     -     532
Balances as at March 31, 2015       1,980,931     110,696     (34,412)     (103,700)     1,953,515

DESCRIPTION OF EQUITY RESERVES

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

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

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

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

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED MARCH 31, 2015 AND 2014
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS, UNAUDITED)

1. BASIS OF PRESENTATION

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

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

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

These condensed consolidated interim financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on May 7, 2015.

2. CAPITAL ASSETS

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

      Petroleum and     Furniture and     Total
($M)     Natural Gas Assets     Office Equipment     Capital Assets
Balance at January 1, 2014     2,784,634     15,211     2,799,845
Additions     608,709     9,980     618,689
Property acquisitions     176,625     -     176,625
Corporate acquisitions     390,523     -     390,523
Changes in estimate for asset retirement obligations     19,107     -     19,107
Depletion and depreciation     (412,768)     (5,072)     (417,840)
Effect of movements in foreign exchange rates     (75,635)     (222)     (75,857)
Balance at December 31, 2014     3,491,195     19,897     3,511,092
Additions     173,612     699     174,311
Property acquisitions     35     -     35
Changes in estimate for asset retirement obligations     29,006     -     29,006
Depletion and depreciation     (97,440)     (1,210)     (98,650)
Recognition of finance lease obligation     31,028     -     31,028
Effect of movements in foreign exchange rates     (46,674)     (149)     (46,823)
Balance at March 31, 2015     3,580,762     19,237     3,599,999

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

3. EXPLORATION AND EVALUATION ASSETS

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

($M)       Exploration and Evaluation Assets
Balance at January 1, 2014       136,259
Additions       69,035
Changes in estimate for asset retirement obligations       22
Property Acquisitions       46,135
Corporate acquisitions         138,264
Depreciation       (5,038)
Effect of movements in foreign exchange rates       (4,056)
Balance at December 31, 2014       380,621
Changes in estimate for asset retirement obligations       12
Depreciation       (956)
Effect of movements in foreign exchange rates       (1,401)
Balance at March 31, 2015       378,276

4. ASSET RETIREMENT OBLIGATIONS

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

($M)     Asset Retirement Obligations
Balance at January 1, 2014     326,162
Additional obligations recognized     22,565
Changes in estimates for asset retirement obligations     (3,434)
Obligations settled     (15,956)
Accretion     23,913
Changes in discount rates     9,404
Effect of movements in foreign exchange rates     (11,901)
Balance at December 31, 2014     350,753
Additional obligations recognized     681
Obligations settled     (3,107)
Accretion     5,675
Changes in discount rates     28,337
Effect of movements in foreign exchange rates     (5,336)
Balance at March 31, 2015     377,003

5. LONG-TERM DEBT

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

      As At
($M)     Mar 31, 2015     Dec 31, 2014
Revolving credit facility     1,168,614     1,014,067
Senior unsecured notes (1)     224,235     224,013
Long-term debt     1,392,849     1,238,080

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

Revolving Credit Facility

At March 31, 2015, Vermilion had in place a bank revolving credit facility totalling $1.75 billion, of which approximately $1.17 billion was drawn.  The facility, which matures on May 31, 2017, 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 due at the maturity date.  This facility bears interest at a rate applicable to demand loans plus applicable margins.  For the three months ended March 31, 2015, the interest rate on the revolving credit facility was approximately 3.0% (2014 - 3.1%).

The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $9.8 million as at March 31, 2015 (December 31, 2014 - $8.6 million).

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

  • A ratio of total bank borrowings (defined as consolidated total debt), to consolidated net earnings before interest, income taxes, depreciation, accretion and other certain non-cash items (defined as consolidated EBITDA) of not greater than 4.0.
  • A ratio of consolidated total senior debt (defined as consolidated total debt excluding unsecured and subordinated debt) to consolidated EBITDA of not greater than 3.0.
  • A ratio of consolidated total senior debt to total capitalization (defined as amounts classified as "Long-term debt", including the current portion, and "Shareholders' Equity" on the balance sheet) of less than 50%.

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

Subsequent to March 31, 2015, Vermilion negotiated a further expansion and extension of its existing revolving credit facilities from $1.75 billion to $2 billion, with a maturity of May 2019.

Senior Unsecured Notes

On February 10, 2011, Vermilion issued $225.0 million of senior unsecured notes at par.  The notes bear interest at a rate of 6.5% per annum and will mature on February 10, 2016.  As direct senior unsecured obligations of Vermilion, the notes rank pari passu with all other present and future unsecured and unsubordinated indebtedness of the Company.  Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest.  The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

6. SHAREHOLDERS' CAPITAL

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

Shareholders' Capital     Number of Shares ('000s)     Amount ($M)
Balance as at January 1, 2014     102,123     1,618,443
Shares issued pursuant to corporate acquisition     2,827     204,960
Shares issued pursuant to the dividend reinvestment plan     1,279     79,430
Vesting of equity based awards     955     47,925
Share-settled dividends on vested equity based awards     108     7,542
Shares issued pursuant to the bonus plan     11     721
Balance as at December 31, 2014     107,303     1,959,021
Shares issued pursuant to the dividend reinvestment plan     405     21,378
Shares issued pursuant to the bonus plan     10     532
Balance as at March 31, 2015     107,718     1,980,931

Dividends declared to shareholders for the three months ended March 31, 2015 were $69.4 million (2014 - $66.0 million).

Subsequent to the end of the period and prior to the condensed consolidated interim financial statements being authorized for issue on May 7, 2015, Vermilion declared dividends totalling $23.5 million or $0.215 per share.

7. EQUITY BASED COMPENSATION

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

Number of Awards ('000s)           2015     2014
Opening balance           1,775     1,665
Granted           -     707
Vested           -     (515)
Modified           -     (21)
Forfeited           (18)     (61)
Closing balance           1,757     1,775

The fair value of a VIP award is determined on the grant date at the closing price of Vermilion's common shares on the Toronto Stock Exchange, adjusted by the estimated performance factor that will ultimately be achieved.

8. SEGMENTED INFORMATION

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

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

  Three Months Ended March 31, 2015
($M) Canada   France   Netherlands   Germany   Ireland   Australia   United States   Corporate   Total
Drilling and development 114,849   34,114   4,333   968   12,955   6,455   637   -     174,311
Oil and gas sales to external customers 77,884   59,832   26,818   11,395   -     19,284   672   -     195,885
Royalties (8,592)   (5,102)   (926)   (1,598)   -     -     (206)   -     (16,424)
Revenue from external customers 69,292   54,730   25,892   9,797   -     19,284   466   -     179,461
Transportation expense (3,942)   (3,011)   -     (894)   (1,693)   -     -     -     (9,540)
Operating expense (19,099)   (10,826)   (5,826)   (1,999)   -     (5,886)   (215)   -     (43,851)
General and administration (4,015)   (5,111)   (737)   (1,608)   (512)   (1,454)   (1,080)   957   (13,560)
PRRT -     -     -     -     -     (2,354)   -     -     (2,354)
Corporate income taxes -     (14,281)   (2,388)   -     -     (577)   -     (377)   (17,623)
Interest expense -     -     -     -     -     -     -     (13,298)   (13,298)
Realized gain on derivative instruments -     -     -     -     -     -     -     6,257   6,257
Realized foreign exchange gain -     -     -     -     -     -     -     3,306   3,306
Realized other income -     31,775   -     -     -     -     -     222   31,997
Fund flows from operations 42,236   53,276   16,941   5,296   (2,205)   9,013   (829)   (2,933)   120,795
                                   
  Three Months Ended March 31, 2014
($M) Canada   France   Netherlands   Germany   Ireland   Australia   United States   Corporate   Total
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

Reconciliation of fund flows from operations to net earnings

      Three Months Ended
      Mar 31,     Mar 31,
($M)     2015     2014
Fund flows from operations     120,795     205,363
Equity based compensation       (19,040)     (16,472)
Unrealized (loss) gain on derivative instruments     (19,970)     3,935
Unrealized foreign exchange (loss) gain     (4,845)     22,000
Unrealized other expense     (261)     (254)
Accretion     (5,675)     (5,712)
Depletion and depreciation     (90,957)     (99,452)
Deferred taxes     21,228     (6,620)
Net earnings     1,275     102,788

9. CAPITAL DISCLOSURES

      Three Months Ended
($M except as indicated)     Mar 31, 2015     Mar 31, 2014
Long-term debt     1,168,614     944,109
Current liabilities(1)     549,580     409,070
Current assets     (329,591)     (386,869)
Net debt [1]     1,388,603     966,310
Cash flows from operating activities     22,647     178,238
Changes in non-cash operating working capital     95,041     24,474
Asset retirement obligations settled     3,107     2,651
Fund flows from operations     120,795     205,363
Annualized fund flows from operations [2]     483,180     821,452
Ratio of net debt to annualized fund flows from operations ([1] ÷ [2])     2.9     1.2

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

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

Due to this increase in net debt as well as the lower commodity price environment, lower sales volumes, and the aforementioned capital expenditures, the ratio of net debt to fund flows increased to 2.9.

10. FINANCIAL INSTRUMENTS

Classification of Financial Instruments

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

                          As at Mar 31, 2015     As at Dec 31, 2014      
Class of financial
instrument
    Consolidated balance
sheet caption
    Accounting
designation
    Related caption on
Statement of Net Earnings
    Carrying
value ($M)
    Fair value
($M)
    Carrying
value ($M)
    Fair value
($M)
    Fair value
measurement
hierarchy
Cash     Cash and cash
equivalents
    HFT     Gains and losses on foreign exchange
are included in foreign exchange loss
(gain)
    88,192     88,192     120,405     120,405     Level 1
Receivables     Accounts receivable     LAR     Gains and losses on foreign exchange
are included in foreign exchange loss
(gain) and impairments are recognized
as general and administration expense
    169,378     169,378     171,820     171,820     Not applicable
Derivative assets     Derivative instruments     HFT     Loss (gain) on derivative instruments     10,000     10,000     24,794     24,794     Level 2
Derivative liabilities     Derivative instruments     HFT     Loss (gain) on derivative instruments     (5,176)     (5,176)     -       -       Level 2
Payables     Accounts payable and
accrued liabilities
    OTH     Gains and losses on foreign exchange
are included in foreign exchange loss
(gain)
    (307,044)     (307,044)     (321,266)     (321,266)     Not applicable
      Dividends payable                                          
Long-term debt     Long-term debt     OTH     Interest expense     (1,392,849)     (1,394,739)     (1,238,080)     (1,238,505)     Level 2

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

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

LAR - "Loans and receivables" are initially recognized at fair value and are subsequently measured at amortized cost.  Impairments and foreign exchange gains and losses are recognized in net earnings.

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

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

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

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

Determination of Fair Values

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

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

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

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

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

Nature and Extent of Risks Arising from Financial Instruments

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

    Before tax effect on comprehensive
    income - increase (decrease)
Risk ($M) Description of change in risk variable Mar 31, 2015
Currency risk - Euro to Canadian Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates (3,466)
     
  Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates 3,466
     
Currency risk - US $ to Canadian Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates (5,770)
     
  Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates 5,770
     
Commodity price risk Increase in relevant oil reference price within option pricing models used to determine (1,038)
  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 1,175
  the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates  
     
  Increase in relevant TTF reference price within option pricing models used to determine (7,975)
  the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates  
     
  Decrease in relevant TTF reference price within option pricing models used to determine 8,459
  the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates  
     
Interest rate risk Increase in average Canadian prime interest rate by 100 basis points during the relevant periods (2,555)
     
  Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods 2,555

11. SIGNIFICANT TRANSACTIONS

During Q1 2015, Vermilion was awarded a recovery of costs resulting from an oil spill at the Ambès oil terminal in France that occurred in 2007. The French court awarded Vermilion approximately €25 million (before taxes), of which 50% is immediately due to Vermilion upon posting a surety bond. This payment is expected to be received in Q2 2015, with the remainder due upon conclusion of the appeal process.  Based on the recent court decision and the conclusions of an expert engaged by the French court, Vermilion is virtually certain that the award will be upheld.

 

 

 

SOURCE Vermilion Energy Inc.

Vermilion Energy Inc.
3500, 520 3rd Avenue SW
Calgary, Alberta T2P 0R3
Phone: 1-403-269-4884
Fax: 1-403-476-8100
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