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Vermilion Energy Inc. Announces Results for the Year Ended December 31, 2014

February 27, 2015

CALGARY, Feb. 27, 2015 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and audited financial results for the year ended December 31, 2014.

HIGHLIGHTS

  • Strong operational execution resulted in annual production that exceeded the top end of our guidance range following three upward revisions during the year.  Average annual production for 2014 was 49,573 boe/d, an increase of 21% as compared to 41,005 boe/d in 2013.  Production for Q4 2014 averaged 49,571 boe/d, down slightly from 49,920 boe/d in the prior quarter.  Full year Canadian production volumes grew 34% year-over-year.  Canadian production growth was attributable to a 20% increase in average production from our Cardium light oil resource play, a near tripling of Mannville condensate-rich gas production and the addition of approximately 1,900 boe/d of production (based on a late April 2014 closing) from our southeast Saskatchewan assets. In Europe, full year production growth of 8% in the Netherlands and the addition of approximately 2,500 boe/d (based on a February 2014 closing) from our Germany acquisition also contributed meaningfully.

  • Increased fund flows from operations ("FFO")(1) in 2014 by 21% to $804.9 million ($7.63/basic share), as compared to $667.5 million ($6.61/basic share) in 2013. Year-over-year growth in FFO was largely attributable to the growth in production as well as a higher liquids weighting compared to 2013, partially offset by generally weaker pricing overall.  Q4 2014 FFO was $185.5 million ($1.73/basic share) down from $197.9 million ($1.85/basic share) in the prior quarter.  The quarter-over-quarter decrease was primarily attributable to substantially lower commodity pricing during Q4 2014 compared to the prior quarter, partially offset by lower corporate income taxes and higher realized hedging gains.

  • Achieved growth in both proved ("1P") and proved plus probable ("2P") reserves in 2014.  Our independent GLJ 2014 Reserves Evaluation(2) assessed an increase of 18% in 1P reserves to 151.5(2) mmboe, while 2P reserves increased by 24% to 246.9(2) mmboe.   This represents year-over-year 1P and 2P per share reserves growth of 12% and 18%, respectively. (For additional reserves information see today's separate news release entitled "Vermilion Energy Inc. Announces 2014 Year-End Summary Reserves and Resource Information").

  • Finding and Development ("F&D") and Finding, Development and Acquisition ("FD&A") costs, including Future Development Capital ("FDC") for 2014 on a 2P basis were $17.37/boe and $22.38/boe, respectively.  Similarly, our three-year F&D and FD&A, including FDC, on a 2P basis were $19.26/boe and $20.83/boe, respectively.

  • Our independent GLJ 2014 Resource Assessment(3) indicates low, best, and high estimates for contingent resources of 103.1(3) mmboe, 293.4(3) mmboe, and 408.0(3) mmboe, an increase of 39%, 26% and 16%, respectively, compared to our GLJ 2013 Resource Assessment(4).  Prospective resources were assessed at low, best and high estimates of 308.3(3) mmboe, 601.6(3) mmboe, and 900.3(3) mmboe, an increase of 419%, 21%, and 10%, respectively versus our GLJ 2013 Resource Assessment.  Importantly, the GLJ 2014 Resource Assessment reflects a significant increase in the most conservative "Low Estimate" for both contingent resources and prospective resources in Canada, as well as incremental increases across our European asset base.  (For additional resource information please see today's separate news release entitled "Vermilion Energy Inc. Announces 2014 Year-End Summary Reserves and Resource Information").

  • During the year we realized successful entry into new asset areas in Germany, Hungary, Southeastern Saskatchewan and the United States.  Each asset addition adheres to our strategy of balanced and diversified growth, increasing our exposure to both European natural gas and light-oil development opportunities.

  • Concluded a highly successful seven (4.7 net) well drilling program in the Netherlands.  In addition, we were awarded the Ijsselmuiden exploration concession consisting of approximately 110,500 gross (66,300 net) undeveloped acres, increasing our undeveloped land base in the Netherlands to more than 800,000 net acres.  The Sonnega-2 exploration well (50% working interest), drilled in Q4 2014, encountered natural gas in the Vlieland formation and achieved a stabilized flow rate of 15.8 mmcf/d on a 52/64 inch choke with a flowing well head pressure of 1,060 psi during a seven-hour flow test(5).  This well is expected to be brought on production during Q2 2015.

  • Completed our first two (1.35 net) Duvernay horizontal appraisal wells during 2014.  Our Pembina well (35% working interest), which is located along a shared lease-line, has a 1,280 metre long horizontal leg and was brought on production subsequent to the end of the third quarter.  The raw gas rate over the first 30 days of production averaged 1.8 mmcf/d (sales gas rate of 1.6 mmcf/d after liquids shrink and plant fuel) with a hydrocarbon liquids rate of approximately 180 bbls/d (approximately 50% pentanes plus).  Our second Duvernay horizontal appraisal well (100% working interest), located in the Edson block, was brought on production late in Q4 2014.  The raw gas rate over the first 30 days of production averaged 2.9 mmcf/d (sales gas rate of 2.5 mmcf/d after liquids shrink and plant fuel) with a hydrocarbon liquids rate of approximately 145 bbls/d (approximately 40% pentanes plus).

  • Our Corrib project in Ireland has continued to progress on schedule following the completion of tunnel boring operations in May 2014.  During the remainder of 2014, project operator Shell Exploration & Production Ireland Ltd. successfully completed offshore workover and pipeline operations as well as outfitting of the 4.9 km tunnel, including installation of flow and umbilical lines, hydro-testing and dewatering, with the final weld completed in December 2014.  Grouting of the tunnel was completed subsequent to year end 2014.  Natural gas from the national sales grid was safely introduced into the processing facility in Q4 2014 as part of the commencement of operations at the plant. Remaining work includes the testing of all systems and processes required for the safe operation of the Bellanaboy gas processing terminal and the finalization of operating permits.  We anticipate first gas from Corrib in approximately mid-2015, with peak production estimated at approximately 58 mmcf/d (approximately 9,700 boe/d), net to Vermilion.

  • In response to continued weakness in commodity prices, we are revising our previous 2015 capital expenditure guidance to reflect a further reduction in planned expenditures of approximately $110 million.  This will reduce our planned 2015 capital expenditures to $415 million from the original $525 million announced in December 2014, a 40% reduction as compared to 2014.  The reduction in capital reflects both lower planned activity levels, including the deferral of our Australian drilling campaign, as well as strong results-to-date from our company-wide Profitability Enhancement Program ("PEP") which was launched in November 2014 to support Vermilion's long-term profitability.  This is the third installment of our PEP program in our 20-year history with the prior two initiatives having achieved strong results in both the 1998 industry downturn and during the financial crisis of 2008-2009.  Our PEP program ensures that our people remain acutely focused on enhancing revenues, and reducing capital costs, operating expenses and general and administrative outlays, as well as improving efficiencies to maximize profitability throughout our organization.  Despite the reduction in our capital budget, we are maintaining our previous production guidance of 55,000-57,000 boe/d.

  • Vermilion ended 2014 with a net debt-to-2014 FFO ratio of 1.6 times.  Subsequent to year-end 2014, Vermilion exercised its option to expand its available credit under its revolving credit facility to $1.75 billion, the maximum available under the existing agreement.  Following the expansion of the revolving credit facility, Vermilion has approximately $730 million of borrowing capacity available.  The facility, which matures in May 2017, is fully revolving up to the date of maturity and subject to standard form covenants (discussed in the notes to the Consolidated Financial Statements).  Vermilion expects it will continue to be in compliance with all applicable debt covenants and to maintain our current dividend of $0.215 per share per month ($2.58 per share per year).

  • Subsequent to year end 2014, Vermilion was awarded a recovery of costs resulting from an oil spill at the Ambes oil terminal in France that occurred in 2007. The French court awarded Vermilion approximately €25 million (before taxes), of which 50% is due now, 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 confident that the award will be upheld.  

  • To preserve our financial flexibility while conservatively exercising our access to equity capital, we have amended our existing Dividend Reinvestment Plan to include a Premium Dividend™ Component.  Under the new Premium Dividend™ and Dividend Reinvestment Plan (the "Plan")(6), Eligible Shareholders who elect to participate in the Dividend Reinvestment Component can continue to reinvest their dividends in common shares at an effective 3% discount to the Average Market Price (with no broker commissions or trading costs), as in our previous Dividend Reinvestment Plan.  With the addition of a new Premium Dividend™ Component, Eligible Shareholders will also have the option to receive a premium cash payment equal to 101.5% of the reinvested dividends.  Shareholders who have not elected to participate in the Plan will continue to receive their regular dividends in the usual manner. The total cost of equity to Vermilion under each component of the Plan will be 3% and 3.5%, respectively.  The Premium Dividend™ Component, when combined with the Dividend Reinvestment Component, is expected to  increase our access to the lowest cost sources of equity capital available. We believe the Premium Dividend™  represents the most prudent approach to preserving near-term balance sheet strength and is expected to reduce cash dividends by approximately $55 million during the remainder of 2015.  We view implementation of a Premium Dividend™ as a short term measure to maintain our financial strength, and both components of our program can be suspended or prorated 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.

  • We celebrated our 20th Anniversary as a publicly traded company in 2014.  This has been a rewarding period of growth and achievement for our company, and we are proud of our progress to date.  Most importantly, we are honored to have provided our shareholders with a compound average total return including dividends, as of December 31, 2014, of 33.6% per annum since our inception.  As of December 31, 2014, Vermilion has distributed dividends of $26.43 per share since initiating the first monthly payment in March 2003.  Vermilion has increased the dividend three times, and has never cut its dividend.  With the consistent strength of our operations, an extensive and diversified opportunity base, a strong balance sheet and continued access to capital, we are well positioned to exit the current cycle stronger than when we entered it.  We will strive to provide continued operational and financial performance, and a reliable and growing dividend stream to investors, as we proceed with our company's growth plans.
(1)      Additional GAAP Financial Measure.  Please see the "Additional and Non-GAAP Financial Measures" section of Management's Discussion and Analysis.
(2)      Estimated proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 6, 2015 with an effective date of December 31, 2014 (the "2014 GLJ Reserves Evaluation")
(3)      Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2014 (the "GLJ 2014 Resource Assessment")
(4)      Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2013 (the "GLJ 2013 Resource Assessment")
(5)      Test results are not necessarily indicative of long-term production performance or of ultimate recovery.

ORGANIZATIONAL CHANGES

Vermilion is pleased to announce the appointment of Mr. Kevin Reinhart and Ms. Cathy Williams to our Board of Directors effective March 2, 2015.

Mr. Reinhart brings over 20 years of oil and gas industry experience, with an extensive background in leadership, strategy and growth, finance, international activities, exploration, sustainability, corporate relations and marketing. In 2012, Mr. Reinhart was named interim President and CEO as well as Director of Nexen Inc. Following the sale of Nexen Inc. in 2013, he was promoted to the role of President and CEO (for Nexen Energy, a CNOOC Limited Company), a position he held up until his retirement in 2014.  Prior to 2012, Mr. Reinhart had held the roles of Executive Vice President and CFO (2009-2012) and Senior Vice President, Corporate Planning and Business Development (2002-2009).  Prior to 2002, Mr. Reinhart served in various capacities as a member of Nexen's executive management team including Controller, Director of Risk Management and Treasurer. From 2005 to 2010, Mr. Reinhart served as a Director of Canexus Ltd. Mr. Reinhart holds a Bachelor of Commerce degree from Saint Mary's University in Halifax. He earned his Chartered Accountant designation in 1985 and is a member of Institute of Chartered Accountants of Alberta.

Ms. Williams brings 30 years of oil and gas industry experience, with an extensive background in finance and business management. Ms. Williams is currently the Owner and Managing Director of Options Canada Ltd. (since 2007) and serves as a Board member of Enbridge Inc. (since 2007) and Chairs their Human Resources and Compensation Committee (since 2010). She was a Board member of Alberta Investment Management Corporation from 2009 to 2014 and Tim Hortons Inc. from 2009 to 2012. From 2003 to 2007, Ms. Williams held the role of Chief Financial Officer for Shell Canada Ltd., prior to which she held various positions with Shell Canada Limited, Shell Europe Oil Products, Shell Canada Oil Products and Shell International (1984 to 2003). Ms. Williams has a Bachelor of Arts degree from University of Western Ontario and a Masters in Business Administration from Queen's University.

Further, Mr. Kenneth Davidson has advised that he will not be standing for re-election to Vermilion's Board of Directors in 2015.  Mr. Davidson has been a Director since December 2005.  We wish to thank Mr. Davidson for his contribution to the Board and for his service as Chair of Vermilion's Audit Committee and as a member of the Governance and Human Resources Committee since 2007.

PREMIUM DIVIDEND™ AND DIVIDEND REINVESTMENT PLAN 

To preserve our financial flexibility and conservatively exercise our access to capital, we have amended our existing Dividend Reinvestment Plan to include a Premium Dividend™ Component.  Under the new Premium Dividend™ and Dividend Reinvestment Plan (the "Plan"), Eligible Shareholders who elect to participate in the Dividend Reinvestment Component can continue to reinvest their dividends in common shares at an effective 3% discount to the Average Market Price (with no broker commissions or trading costs), similar to our previous Dividend Reinvestment Plan (Vermilion's Amended and Restated Dividend Reinvestment Plan dated effective September 1, 2010 as amended effective February 27, 2014 (the "Previous DRIP").

With the addition of a new Premium Dividend™ Component, Eligible Shareholders will also have the option to reinvest their dividends in new common shares which will be exchanged for a premium cash payment equal to 101.5% of the reinvested dividends.  Under the Premium Dividend™ Component, shares will be issued at a 3.5% discount to the Average Market Price.  The shares will be presold at prevailing market prices by the Plan Broker (Canaccord Genuity Corporation), who will then provide participating Shareholders with a premium cash payment equal to 101.5% of their dividends, while the Plan Broker retains the balance of the discount as its fee.

Eligible Shareholders are not required to participate in the Plan.  Eligible Shareholders who have not elected to participate in the Plan will continue to receive their regular cash dividends in the usual manner.

The total cost of equity issuance to Vermilion under the Dividend Reinvestment Component and the Premium Dividend™ Component of the Plan will be 3% and 3.5%, respectively.  The Premium Dividend™ Component, when combined with the Dividend Reinvestment Component, is expected to increase our access to the lowest cost sources of equity capital available.  While the Premium Dividend™ is expected to result in a modest amount of equity issuance (estimated to be less than 1% of shares outstanding in 2015), we believe it represents the most prudent approach to preserving near-term balance sheet strength.  We expect the Premium Dividend™ to reduce cash dividends by approximately $55 million during the remainder of 2015.  We view implementation of a Premium Dividend™ as a short term measure to maintain our financial strength.  Both components of our program can be suspended or prorated 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.

To effect the change, Vermilion's Board of Directors has approved amendments to the Previous DRIP to include a Premium Dividend™ Component.  The new Plan will allow Eligible Shareholders to elect to participate in the Plan, commencing with the March distribution, payable to Shareholders on April 15, 2015 (the "March Dividend").  The March Dividend will have a Dividend Record Date of March 31, 2015, however all Dividend Record Dates for subsequent 2015 dividend payments will be adjusted, from those previously published, to facilitate the operation of the Premium DividendTM Component of the Plan.  The amended Dividend Record Dates are now published and available on Vermilion's website at www.vermilionenergy.com (under the heading "Investor Relations" subheading "Dividends") and will be included in the applicable news release announcing the approval and declaration of any future dividend payments by Vermilion's Board of Directors.

Each component of the Plan, which is explained in greater detail in the complete Plan document available on Vermilion's corporate website at www.vermilionenergy.com (under the heading "Investor Relations" subheading "DRIP"), is subject to eligibility restrictions, applicable withholding taxes, prorating as provided for in the Plan, and other limitations on the availability of common shares to be issued or purchased in certain events. Only Canadian-resident Shareholders may participate in the Premium DividendTM Component of the Plan. The Dividend Reinvestment Component of the Plan is available to Canadian residents and non-U.S. resident foreign Shareholders who meet certain eligibility criteria as set forth in the complete Plan. U.S. resident Shareholders are not currently permitted to participate in either component of the Plan.  This is due to the requirement, under U.S. securities regulations, to maintain a continuous shelf registration for issuance of new equity to U.S. Shareholders.  At this time, Vermilion has not put in place the required shelf registration due to the  high cost of establishing and maintaining such a shelf registration.  We will continue to monitor the relative cost-benefit of such a registration as we go forward.

In order to participate in either the Premium Dividend™ Component or the Dividend Reinvestment Component, an Eligible Shareholder must enroll, or be deemed to have enrolled (in the case of the Dividend Reinvestment Component), in the Plan at least five business days prior to the relevant Dividend Record Date directly (in the case of registered Shareholders) or indirectly through the broker, investment dealer, financial institution or other nominee who holds common shares on the Eligible Shareholder's behalf.

A registered Eligible Shareholder who was enrolled in the Previous DRIP will automatically be deemed to be a participant in the Dividend Reinvestment Component of the Plan, without any further action on their part. A beneficial owner of common shares (i.e., a holder of common shares that are not registered in the beneficial owner's name but are instead held through a broker, investment dealer, financial institution or other nominee) who was validly enrolled, through the nominee holder, in the Previous DRIP should contact such nominee holder to confirm continued participation in the Dividend Reinvestment Component of the Plan.

For more information on the Plan, defined meanings for capitalized terms above, eligibility restrictions and enrollment information among other details of the Plan, please refer to the complete copy of the Plan as well as a related series of Questions and Answers available on Vermilion's website at www.vermilionenergy.com (under the heading "Investor Relations" subheading "DRIP").

™ denotes trademark of Canaccord Genuity Capital Corporation.

Conference Call and Audio Webcast Details

Vermilion will discuss these results in a conference call to be held on Monday, March 2, 2015 at 9:00 AM MST (11:00 AM EST).  To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area).  The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 66942576.  The replay will be available until midnight mountain time on March 9, 2015.

You may also listen to the audio webcast by clicking  http://event.on24.com/r.htm?e=925534&s=1&k=AC0268657BEFCE6AEC7F0AB205FB2A4F or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.

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 

Dear Shareholders:

The upstream energy environment continues to be challenging following the dramatic decline in global crude oil prices that began in mid-2014.  While both West Texas Intermediate ("WTI") blend and to a greater extent Brent based crudes have realized modest rebounds from their respective lows reached in January 2015, we are in a new commodity cycle that may feature lower crude oil prices for an extended period of time.  We have always believed that our strategy, to build a global asset base with diversified commodity exposures and project fundamentals, is the best and most balanced approach to reducing risk and providing the necessary flexibility to adapt to changing commodity cycles and ensure the long-term sustainability of our Company.

Today, more than ever, we believe that our global asset base and diversified commodity exposure, particularly our growing exposure to the strong fundamentals and pricing of European natural gas markets, leaves us competitively advantaged compared to the majority of our North American peers.  In 2014 we actively expanded this exposure with our entry into Germany, a producing region with a long history of crude oil and natural gas development activity, low political risk, and strong market fundamentals.  Our Germany acquisition increased our existing European natural gas production base by nearly 50% in 2014.  Looking to mid-2015, with production forthcoming from our Corrib project in Ireland, we believe European gas may represent approximately 25% of our total oil-equivalent production and generate as much as 35% of our 2015 FFO based on recent strip pricing.  In 2016, with a full year of Corrib production and assuming constant pricing, European natural gas may generate as much as 45% of Vermilion's FFO(1).  Today's fundamentals and outlook for European natural gas markets remain robust with current prices approximately triple those in North America.  We will continue to consider further opportunities to profitably increase our European natural gas exposure.

During 2014, we realized successful entry into four new areas within our existing core regions.  As previously mentioned, in February we announced our entry into Germany, expanding our exposure to European natural gas markets and establishing a strong foundation for organic growth and possible future acquisitions.  In April, we closed the purchase of a private company with light-oil assets in Southeast Saskatchewan.  We believe we can add significant value to these assets by applying our expertise from horizontal development of our Cardium project.  The transaction established a new light-oil focused core area in Canada for organic growth and land expansion.  To that end, subsequent to the transaction, we expanded our land base by leasing an additional 15,000 net acres of undeveloped land at an average cost of $1,860 per acre.  In September, we announced a small entry into the United States with the purchase of assets located in the Powder River Basin in northeastern Wyoming for $11.1 million.  This accretive acquisition provides a significant undeveloped land block for horizontal development of a promising Turner Sand light oil target.  Finally during 2014, we announced the establishment of a significant land position in Hungary that offers potential for long-term natural gas development with minimal near-term capital commitments.

In December 2014, we announced our initial 2015 capital budget of $525 million, a 24% reduction from our 2014 capital expenditures.  In view of continued weakness in oil prices since that time,  we are now further reducing our planned capital activity levels in 2015 by an additional $110 million to $415 million, a reduction of approximately 40% as compared to 2014.  These capital budget activities include reductions in planned spending in our Canadian and French business units, and the deferral and potential cancellation of our 2015 Australian drilling program.  We are also directing considerable focus to our PEP initiative to support Vermilion's long-term and sustainable profitability.  Prior installments of PEP achieved strong results in both the 1998 industry downturn and the financial crisis of 2008-2009.  Despite the significant reduction in planned capital expenditures, we are maintaining our previous 2015 production guidance of 55,000 - 57,000 boe/d.

For 2015, our Canadian operational plans reflect a significant reduction in activity levels as we seek to preserve our financial flexibility and balance sheet strength.  While our conventional plays in Canada continue to generate strong returns, the dynamic nature of Canada's service sector and the limited expiry profile of our Canadian asset base provide significant flexibility to moderate near-term capital spending.  As a result, our 2015 Canadian capital activities will be focused predominately on only those activities required to maintain the net asset value of our existing asset base as we work with our vendors to drive down costs across our business.  Our Cardium light-oil resource play continues to generate strong rates of return in excess of 30%(2), reflecting our relatively low operating costs, continued improvements in completions design and better-than-forecasted production volumes on our two-mile extended reach horizontal wells.  Nevertheless, given limited expiries and our high level of operatorship in the play, we have the flexibility to reduce capital investment levels.  In 2015, we expect to drill or participate in only eight (3.0 net) wells, a significant reduction from previous activity levels of 30 to 50 wells per year.  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). For 2015, we anticipate drilling or participating in 28 (16.0 net) wells, up from 20 (10.6 net) wells in 2014.  Our Saskatchewan land base has limited expiries, allowing us to reduce drilling activity on these assets to five (4.1 net) wells in 2015.  In our Duvernay unconventional liquids-rich gas play, we will monitor the performance of our two appraisal wells that we drilled in 2014.  We have deferred further Duvernay drilling activities to beyond 2015.

In France, we have maintained plans for our four-well drilling program at Champotran during Q1 2015 as after-tax rates of return remain robust at more than 100%(2).  The remainder of our capital expenditures in France will target highly economic workovers and optimization projects, as well as infrastructure and facilities maintenance.  We continue to anticipate that a portion of our 4 mmcf/d of shut-in natural gas production at Vic Bilh will be back on-stream by mid-2015.  In the Netherlands, we are planning for a three (2.4 net) well drilling campaign that is expected to begin in Q2 2015.  The fundamentals and pricing for European gas remain robust, and we will continue to focus significant attention on identifying profitable opportunities to increase our exposure to this market.  In Germany, our operating partner is planning a one (0.25 net) well program.  In Ireland, our Corrib project has continued to progress on schedule following the completion of tunnel boring operations in May 2014.  During 2014, project operator Shell Exploration & Production Ireland Ltd. successfully completed offshore workover and pipeline operations as well as outfitting of the 4.9 km tunnel, including installation of flow and umbilical lines, hydro-testing and dewatering, with the final weld completed in December.  Grouting of the tunnel was concluded in January 2015.  Natural gas from the national sales grid was safely introduced into the processing facility in November 2014 as part of the commissioning process for the gas plant.  Remaining work includes the completion of gas plant commissioning activities and the finalization of operating permits.  We anticipate first gas from Corrib in approximately mid-2015, with peak production estimated at approximately 58 mmcf/d (approximately 9,700 boe/d), net to Vermilion.

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.

Our balance sheet remains a source of strength.  We have recently exercised our option to expand our credit facilities to $1.75 billion, giving us approximately $730 million of available capacity on our bank line.  In a further step to preserve our financial flexibility and conservatively exercise our access to capital, we have also announced an amendment to our existing DRIP to include a Premium Dividend™ Component.  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.

In 2014, we celebrated Vermilion's 20th anniversary as a publicly traded company.  It was a demanding, but also a tremendously rewarding, twenty years during which we have experienced previous commodity cycles that were not wholly unlike today's.  Over the years, we have witnessed significant change and encountered many challenges to the industry, and we are particularly proud of our demonstrated ability to effectively navigate those challenges to the benefit of our shareholders.  The recent decline in crude prices creates yet another opportunity for us to demonstrate the sustainability of our business model and the advantages of our diversified portfolio.  Vermilion's relative performance during this period has once again demonstrated the stable and defensive nature of our business, our strong positioning within the industry, and our shareholders' continued confidence in our ability to prosper.

Reflecting on Vermilion's record, we are pleased that our previous efforts have resulted in a compound average total return including dividends, as of December 31, 2014, of 33.6% per annum since inception. We are also proud of the consistency of those returns over longer periods.  Over the last  three, five, ten and 15 calendar-year periods, we have reliably delivered double-digit compound average total returns of 12.3%, 16.2%, 14.7% and 21.6%, respectively.

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.  Continuing to be acknowledged for excellence in our business practices, Vermilion was recognized for the fifth consecutive year by the Great Place to Work® Institute in both Canada and France in 2014.  In Canada, Vermilion was ranked 5th Best Workplace in its category for 2014.  More than 300 Canadian companies participated in the survey and Vermilion was the only energy company in Canada to be recognized as a Best Workplace.  In France, Vermilion received a special award for corporate social responsibility and was ranked 13th Best Workplace in its category for 2014.  Vermilion's Netherlands business unit became eligible to participate in the competition for the first time in 2014 and was ranked 10th Best Workplace in its category, the highest score of any energy company in the survey.  Vermilion was ranked second out of 13 in our peer group by the Carbon Disclosure Project (CDP) for our disclosure in 2014, our inaugural year of participation, with  Vermilion scoring 87 out of 100 (10 points higher than any peer group company achieved in its inaugural year of participation).

(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     Year Ended
($M except as indicated)       Dec 31,   Sep 30,     Dec 31,     Dec 31,   Dec 31,
Financial       2014   2014     2013     2014   2013
Petroleum and natural gas sales       306,073   344,688     325,108     1,419,628   1,273,835
Fund flows from operations (1)       185,528   197,898     163,660     804,865   667,526
  Fund flows from operations ($/basic share)       1.73   1.85     1.61     7.63   6.61
  Fund flows from operations ($/diluted share)       1.71   1.83     1.58     7.51   6.51
Net earnings       58,642   53,903     101,510     269,326   327,641
  Net earnings ($/basic share)       0.55   0.50     1.00     2.55   3.24
Capital expenditures       166,243   190,033     148,478     687,724   542,726
Acquisitions       1,652   40,847     29,103     601,865   36,689
Asset retirement obligations settled       6,247   4,677     5,426     15,956   11,922
Cash dividends ($/share)       0.645   0.645     0.600     2.580   2.400
Dividends declared       69,119   68,896     61,208     272,732   242,599
  % of fund flows from operations       37%   35%     37%     34%   36%
Net dividends (1)       48,139   48,480     42,433     193,302   170,308
  % of fund flows from operations       26%   24%     26%     24%   26%
Payout (1)       220,629   243,190     196,337     896,982   724,956
  % of fund flows from operations       119%   123%     120%     111%   109%
  % of fund flows from operations (excluding the Corrib project)       106%   107%     111%     99%   94%
Net debt (1)       1,265,650   1,243,438     749,685     1,265,650   749,685
Ratio of net debt to annualized fund flows from operations (1)       1.7   1.6     1.1     1.6   1.1
Operational                            
Production                            
  Crude oil (bbls/d)       28,846   29,147     26,039     28,879   25,741
  NGLs (bbls/d)       2,822   2,354     1,761     2,553   1,730
  Natural gas (mmcf/d)       107.42   110.52     78.96     108.85   81.21
  Total (boe/d)       49,571   49,920     40,960     49,573   41,005
Average realized prices                            
  Crude oil and NGLs ($/bbl)       78.64   102.49     106.00     100.06   104.46
  Natural gas ($/mcf)       5.90   5.74     7.29     6.42   6.83
Production mix (% of production)                            
  % priced with reference to WTI       28%   28%     25%     28%   25%
  % priced with reference to AECO       20%   18%     17%     18%   16%
  % priced with reference to TTF       16%   18%     15%     18%   16%
  % priced with reference to Dated Brent       36%   36%     43%     36%   43%
Netbacks ($/boe) (1)                            
  Operating netback       45.85   54.25     61.35     55.50   60.43
  Fund flows from operations netback       38.67   44.08     43.32     44.09   43.94
  Operating expenses       12.48   12.53     12.74     12.72   12.84
Average reference prices                            
  WTI (US $/bbl)       73.15   97.17     97.46     93.00   97.97
  Edmonton Sweet index (US $/bbl)       66.79   89.24     82.53     85.83   90.40
  Dated Brent (US $/bbl)       76.27   101.85     109.27     98.99   108.66
  AECO ($/GJ)       3.41   3.81     3.35     4.27   3.01
  TTF ($/GJ)       8.69   7.26     10.65     8.50   10.29
Average foreign currency exchange rates                            
  CDN $/US $       1.14   1.09     1.05     1.10   1.03
  CDN $/Euro       1.42   1.44     1.43     1.47   1.37
Share information ('000s)                            
Shares outstanding - basic       107,303   106,921     102,123     107,303   102,123
Shares outstanding - diluted (1)       110,334   109,749     104,869     110,334   104,869
Weighted average shares outstanding - basic       107,102   106,768     101,961     105,448   100,969
Weighted average shares outstanding - diluted (1)       108,646   108,290     103,426     107,187   102,467

(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 February 27, 2015, of Vermilion Energy Inc.'s ("Vermilion", "we", "our", "us" or the "Company") operating and financial results as at and for the three months and year ended December 31, 2014 compared with the corresponding periods in the prior year.

This discussion should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2014 and 2013, together with the 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 audited consolidated financial statements for the year ended December 31, 2014 and comparative information have been prepared in Canadian dollars, except where another currency has been indicated, and in accordance with International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") as issued by the International Accounting Standards Board.

This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by IFRS.  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.

NEW COUNTRY ENTRIES

In February 2014, we acquired a 25% contractual participation interest in a four-partner consortium in Germany from GDF Suez S.A.  The acquisition enables us to participate in the exploration and development, production and transportation of natural gas from the assets held by the consortium.  The assets are comprised of four gas producing fields across eleven production licenses and are characterized by a low effective decline rate of approximately 11% annually.  The acquired assets include both exploration and production licenses that comprise a total of 204,000 gross acres, of which 85% is in the exploration license.  The acquisition represented Vermilion's entry into the German exploration and production business, a producing region with a long history of oil and gas development activity, low political risk, and strong marketing fundamentals.  The acquisition provides us with entry into this sizable market, in the form of free cash flow generating, low-decline assets with near-term development inventory in addition to longer-term, low-permeability gas prospectivity.  Entry into Germany is in keeping with our European focus, and increases our exposure to the strong fundamentals and pricing of European natural gas markets.  We believe that our conventional and unconventional expertise, coupled with new access to proprietary technical data, will position us strongly for future development and expansion opportunities in both Germany and the greater European region.

On November 10, 2014, we announced an acquisition of assets in the Powder River Basin of northeastern Wyoming for $11.1 million.  The assets cover approximately 68,000 acres of land (98% undeveloped) with current working interest production of approximately 200 bbls/d (100% crude oil).  The land base includes 53,000 net acres at an average operated working interest of 70% in a promising tight oil project in the Turner Sand at a depth of approximately 1,500 metres.  The acquisition represented a low-cost entry into the prolific Powder River Basin and Vermilion's entry into the sizable United States exploration and production market.  Looking ahead we see continued opportunity for expansion, with an active asset market in North America where technology continues to unlock new opportunities for development.  We have established an office in Denver, Colorado as the operating headquarters for our new United States business unit and have hired to staff this subsidiary.

2014 REVIEW AND 2015 GUIDANCE

We first issued 2014 capital expenditure guidance of $555 million on November 7, 2013.  We subsequently increased our 2014 capital expenditure guidance to $590 million on March 18, 2014, to reflect an additional $35 million of 2014 development capital expected to be incurred in association with our acquisition of Elkhorn Resources Inc.

Concurrent with the release of our first quarter 2014 financial and operating results on May 2, 2014, we further updated our 2014 capital expenditure guidance to $635 million, reflecting the expected full-year rise in the cost to Vermilion, in Canadian dollar terms, of both actual and anticipated international capital expenditures as a result of the devaluation of the Canadian dollar against both the U.S. dollar and the Euro, and the addition of approximately $15 million of anticipated spending associated with drilling activities.  We also increased our original production guidance from 47,500-48,500 boe/d to 48,000-49,000 boe/d.

Based on the continued strength of our operations during the second quarter of 2014, we further increased our full-year 2014 production and capital expenditure guidance to 48,500-49,500 boe/d and $650 million, respectively. The increase in capital expenditures was attributed to increased Mannville development drilling and higher than anticipated costs associated with the Duvernay development program.

Concurrent with the release of our third quarter 2014 financial and operating results on November 10, 2014, we further revised our 2014 full year production guidance from the previous range of 48,500-49,500 boe/d to a range of 49,000-49,500 boe/d and announced the expectation of achieving production near the upper end of the range for 2014.

We provided updated 2014 capital expenditure guidance concurrent with the release of our initial 2015 production and capital expenditure guidance on December 8, 2014.  The increase in 2014 capital expenditures resulted from a shift in capital priorities, previously unplanned spending and foreign exchange movements.

The following table summarizes our 2014 actual results compared to guidance and our 2015 guidance:

        Date           Capital Expenditures ($MM)           Production (boe/d)
2014 - Guidance                                
2014 Guidance       November 7, 2013           555           45,000 to 46,000
2014 - Guidance Updates                                
2014 Guidance - Update       March 18, 2014           590           47,500 to 48,500
2014 Guidance - Update       May 2, 2014           635           48,000 to 49,000
2014 Guidance - Update       July 31, 2014           650           48,500 to 49,500
2014 Guidance - Update       November 10, 2014           650           49,000 to 49,500
2014 Guidance - Update       December 8, 2014           675           49,000 to 49,500
2014 - Actual Production                                
2014 Actual       February 27, 2015           688           49,573
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 December 31, 2014, reflects our trailing one, three, and five year performance:

Total return (1)     Trailing One Year       Trailing Three Year       Trailing Five Year
Dividends per Vermilion share     $2.58       $7.26       $11.82
Capital appreciation per Vermilion share     -$5.35       $11.63       $24.58
Total return per Vermilion share     -4.4%       41.6%       112.3%
Annualized total return per Vermilion share     -4.4%       12.3%       16.2%
Annualized total return on the S&P TSX High Income Energy Index     -13.6%       -3.3%       1.3%

(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   Year Ended   % change
        Dec 31,   Sep 30,     Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,     Dec 31,   2014 vs.
        2014   2014     2013   Q3/14   Q4/13   2014     2013   2013
Production                                      
  Crude oil (bbls/d)     28,846   29,147     26,039   (1%)   11%   28,879     25,741   12%
  NGLs (bbls/d)     2,822   2,354     1,761   20%   60%   2,553     1,730   48%
  Natural gas (mmcf/d)     107.42   110.52     78.96   (3%)   36%   108.85     81.21   34%
  Total (boe/d)     49,571   49,920     40,960   (1%)   21%   49,573     41,005   21%
  Build (draw) in inventory (mbbl)     (238)   104     (10)           (164)     (229)    
Financial metrics                                      
  Fund flows from operations ($M)     185,528   197,898     163,660   (6%)   13%   804,865     667,526   21%
     Per share ($/basic share)     1.73   1.85     1.61   (6%)   7%   7.63     6.61   15%
  Net earnings ($M)     58,642   53,903     101,510   9%   (42%)   269,326     327,641   (18%)
     Per share ($/basic share)     0.55   0.50     1.00   10%   (45%)   2.55     3.24   (21%)
  Cash flows from operating activities ($M)     229,146   235,010     177,003   (2%)   29%   791,986     705,025   12%
  Net debt ($M)     1,265,650   1,243,438     749,685   2%   69%   1,265,650     749,685   69%
  Cash dividends ($/share)     0.645   0.645     0.600   -   8%   2.580     2.400   8%
Activity                                      
  Capital expenditures ($M)     166,243   190,033     148,478   (13%)   12%   687,724     542,726   27%
  Acquisitions ($M)     1,652   40,847     29,103   (96%)   (94%)   601,865     36,689   1,540%
  Gross wells drilled     26.00   26.00     21.00           89.00     76.00    
  Net wells drilled     16.58   20.31     16.65           62.43     64.21    

Operational review

  • Recorded consolidated average production of 49,571 boe/d during Q4 2014, which was consistent with Q3 2014.
  • Increased consolidated average production for the three months and year ended December 31, 2014 by 21% versus the comparable periods in 2013, primarily due to growth in Canada, the Netherlands, and incremental production from our acquisitions in Germany, southeast Saskatchewan and the United States.  In Canada, production growth of 38% and 34% for the three months and year ended December 31, 2014, respectively, versus the comparable periods in 2013, resulted from our 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. In the Netherlands, production growth of 8% for the year ended December 31, 2014 versus the comparable period in 2013 resulted from incremental production from our acquisition in the Netherlands in Q4 2013, increased volumes following completion of the Middenmeer Treatment Centre retrofit in the latter part of 2013, and ongoing recompletion and production optimization activities. These production increases were partially offset by decreased production in France due primarily to the temporary shut-in of natural gas production from the Vic Bilh field for the entirety of 2014.
  • Activity during the quarter included capital expenditures totalling $166.2 million, incurred primarily in Canada, France, and Ireland.  In Canada, capital expenditures totalling $85.4 million were 12% lower than the $97.4 million incurred in Q3 2014 and related to the drilling of 15.16 net wells compared to 16.86 net wells in Q3 2014. In France, capital expenditures of $37.2 million related to workovers, seismic activity, various facility projects, and the drilling of one (0.5 net) well in the Tamaris field. In Ireland, $20.9 million of capital expenditures were incurred related to offshore workover and pipeline operations, as well as outfitting the 4.9 km tunnel.
  • Acquisition expenditures for the quarter totalling $1.7 million related to crown land sales, primarily in southeast Saskatchewan.

Financial review

Net earnings

  • Net earnings for Q4 2014 were $58.6 million ($0.55/basic share) as compared to $53.9 million ($0.50/basic share) for Q3 2014.  Quarter-over-quarter net earnings were relatively consistent as lower petroleum and natural gas sales ("sales") and operating income were offset by gains on derivative instruments (including $17.2 million of unrealized gains due to lower forecasted pricing for 2015 and the impact on the valuation of our crude oil and natural gas derivative positions).
  • Net earnings for the three months and year ended December 31, 2014 were 42% and 18% lower versus the respective comparable periods in 2013 due to a decrease in realized prices and foreign exchange losses, partially offset by the aforementioned gains on derivative instruments.  For the three months ended December 31, 2014, revenue decreased by 6% driven by lower commodity prices. Revenue increased by 11% for the year ended December 31, 2014 as the decrease in realized prices was offset by incremental production and a decrease in crude inventory as compared to the same periods in 2013. Unrealized foreign exchange losses of $4.0 million and $17.6 million for the three months and year ended December 31, 2014 were the result of the Euro weakening versus the Canadian dollar and the resulting impact on our Euro denominated financial assets.  In addition, both periods were affected by the absence of the $47.4 million impairment recovery recognized in 2013.

Cash flows from operating activities

  • Cash flows from operations decreased 2% as compared to Q3 2014 as lower sales were offset by higher realized gains on derivative instruments and timing differences pertaining to working capital.
  • Cash flow from operations increased by 29% and 12% for the three months and year ended December 31, 2014 compared to the same periods in 2013. For the three months ended December 31, 2014, the increase primarily related to timing differences pertaining to working capital, partially offset by lower revenues due to lower commodity prices. For the year ended December 31, 2014, the increase primarily related to increased revenues driven by incremental production related to our Germany and Saskatchewan acquisitions, partially offset by timing differences pertaining to working capital.

Fund flows from operations

  • Generated fund flows from operations of $185.5 million during Q4 2014, a decrease of $12.4 million (6%) versus Q3 2014. This quarter-over-quarter decrease was the result of lower sales partially offset by increased realized derivative gains and decreases in corporate income taxes and general and administration expenses. Lower sales were driven by weaker commodity pricing coupled with a decrease in Netherlands production, as production in that country is managed to optimize facility use and regulate declines.
  • Fund flows from operations increased by 13% and 21% for the three months and year ended December 31, 2014, respectively, versus the comparable periods in 2013. These increases were primarily the result of increased sales volumes in Canada coupled with incremental production following our Q1 2014 acquisition in Germany, our Q2 2014 acquisition in southeast Saskatchewan, and a draw in Australia inventory in both periods.

Net debt

  • As a result of funding our 2014 acquisitions in Germany, Canada, and the United States, net debt increased to $1.27 billion or 1.6 times fund flows from operations for the year ended December 31, 2014.

Dividends

  • Declared dividends of $0.215 per common share per month during 2014, totalling $0.645 per common share for the quarter and $2.58 per common share for the year ended December 31, 2014.  Dividends were higher in the 2014 periods versus the comparable periods in 2013 due to our increase in dividends per share starting with the January 31, 2014 dividend paid on February 18, 2014.

COMMODITY PRICES

    Three Months Ended   % change   Year Ended   % change
    Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
    2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
Average reference prices                                
WTI (US $/bbl)   73.15   97.17   97.46   (25%)   (25%)   93.00   97.97   (5%)
Edmonton Sweet index (US $/bbl)   66.79   89.24   82.53   (25%)   (19%)   85.83   90.40   (5%)
Dated Brent (US $/bbl)   76.27   101.85   109.27   (25%)   (30%)   98.99   108.66   (9%)
AECO ($/GJ)   3.41   3.81   3.35   (10%)   2%   4.27   3.01   42%
TTF ($/GJ)   8.69   7.26   10.65   20%   (18%)   8.50   10.29   (17%)
TTF (€/GJ)   6.12   5.04   7.45   21%   (18%)   5.79   7.51   (23%)
Average foreign currency exchange rates                                
CDN $/US $   1.14   1.09   1.05   5%   9%   1.10   1.03   7%
CDN $/Euro   1.42   1.44   1.43   (1%)   (1%)   1.47   1.37   7%
Average realized prices ($/boe)                                
Canada   51.27   64.85   61.10   (21%)   (16%)   64.06   61.14   5%
France   79.25   107.99   112.84   (27%)   (30%)   105.43   106.26   (1%)
Netherlands   52.07   45.73   67.88   14%   (23%)   52.65   64.08   (18%)
Germany   49.19   36.43   -     35%   100%   46.03   -     100%
Australia   90.37   119.07   124.63   (24%)   (27%)   113.80   119.38   (5%)
United States   74.08   -     -     100%   100%   74.08   -     100%
Consolidated   63.79   76.80   86.04   (17%)   (26%)   77.75   83.83   (7%)
Production mix (% of production)                                
% priced with reference to WTI   28%   28%   25%           28%   25%    
% priced with reference to AECO   20%   18%   17%           18%   16%    
% priced with reference to TTF   16%   18%   15%           18%   16%    
% priced with reference to Dated Brent   36%   36%   43%           36%   43%    

Reference prices

  • The growing global surplus of crude oil put considerable downside pressure on global crude oil prices in the fourth quarter of 2014, with Dated Brent falling 25% quarter-over-quarter and 9% year-over-year.
  • North American crude oil prices were not immune to the global oversupply situation as both WTI and Edmonton Sweet index declined by 25% quarter-over-quarter and 5% year-over-year.
  • Natural gas prices at AECO suffered a 10% quarter-over-quarter decline as weather-driven demand was not sufficient to tighten the fundamental balance; however, on a year-over-year basis, AECO increased by 42%.
  • European natural gas prices recovered from a weaker summer.  Aided by both seasonality and concerns over winter supplies from Russia, TTF saw a 20% quarter-over-quarter gain, but with ample gas-in-storage and little weather demand during the early stages of the winter season, the TTF price was down 17% year-over-year.
  • A weak crude oil market and general strengthening of the US dollar saw the Canadian dollar weaken throughout the quarter, but against the Euro, the Canadian dollar was relatively unchanged.

Realized prices

  • Consolidated realized price decreased by 17% for Q4 2014 as compared to Q3 2014 and 26% as compared to Q4 2013.  These decreases were primarily the result of weaker crude oil prices, partially offset by stronger TTF pricing and a weaker Canadian dollar versus the US dollar during Q4 2014 versus the comparable quarters.
  • Consolidated realized price for the year ended December 31, 2014 decreased by 7% as compared to the prior year. This decrease was driven by weaker crude oil and TTF pricing, partially offset by stronger AECO pricing and a weaker Canadian dollar.

FUND FLOWS FROM OPERATIONS

    Three Months Ended   Year Ended
    Dec 31, 2014   Sep 30, 2014   Dec 31, 2013   Dec 31, 2014   Dec 31, 2013
    $M   $/boe   $M   $/boe   $M   $/boe   $M   $/boe   $M   $/boe
Petroleum and natural gas sales   306,073   63.79   344,688   76.80   325,108   86.04   1,419,628   77.75   1,273,835   83.83
Royalties   (25,963)   (5.41)   (29,000)   (6.46)   (17,616)   (4.66)   (108,000)   (5.92)   (67,936)   (4.47)
Petroleum and natural gas revenues   280,110   58.38   315,688   70.34   307,492   81.38   1,311,628   71.83   1,205,899   79.36
Transportation expense   (9,489)   (1.98)   (10,979)   (2.45)   (9,081)   (2.40)   (42,361)   (2.32)   (28,924)   (1.90)
Operating expense   (59,881)   (12.48)   (56,227)   (12.53)   (48,140)   (12.74)   (232,307)   (12.72)   (195,043)   (12.84)
General and administration   (13,236)   (2.76)   (16,262)   (3.62)   (13,954)   (3.69)   (61,727)   (3.38)   (49,910)   (3.28)
PRRT   (13,568)   (2.83)   (13,834)   (3.08)   (17,173)   (4.55)   (60,340)   (3.30)   (56,565)   (3.72)
Corporate income taxes   (8,304)   (1.73)   (17,454)   (3.89)   (43,065)   (11.40)   (96,996)   (5.31)   (161,794)   (10.65)
Interest expense   (12,943)   (2.70)   (12,918)   (2.88)   (10,049)   (2.66)   (49,655)   (2.72)   (38,183)   (2.51)
Realized gain (loss) on derivative instruments   22,816   4.76   8,837   1.97   (1,300)   (0.34)   36,712   2.01   (7,082)   (0.47)
Realized foreign exchange (loss) gain   (179)   (0.03)   812   0.17   (1,294)   (0.34)   (821)   (0.04)   (1,866)   (0.12)
Realized other income   202   0.04   235   0.05   224   0.06   732   0.04   994   0.07
Fund flows from operations   185,528   38.67   197,898   44.08   163,660   43.32   804,865   44.09   667,526   43.94

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

($M)       Q4/14 vs. Q3/14     Q4/14 vs. Q4/13     2014 vs. 2013
Fund flows from operations - Comparative period       197,898     163,660     667,526
Sales volume variance:                    
  Canada       3,545     35,366     136,832
  France       5,839     6,706     (9,302)
  Netherlands       (4,524)     (6,216)     11,132
  Germany       1,297     13,359     41,962
  Australia       29,803     20,345     (1,564)
  United States       1,330     1,330     1,330
Pricing variance on sold volumes:                    
  WTI       (26,146)     (20,454)     (4,007)
  AECO       (3,758)     215     22,959
  Dated Brent       (52,457)     (61,872)     (26,662)
  TTF       6,456     (7,814)     (26,887)
Changes in:                    
  Royalties       3,037     (8,347)     (40,064)
  Transportation       1,490     (408)     (13,437)
  Operating expense       (3,654)     (11,741)     (37,264)
  General and administration       3,026     718     (11,817)
  PRRT       266     3,605     (3,775)
  Corporate income taxes       9,150     34,761     64,798
  Interest       (25)     (2,894)     (11,472)
  Realized derivatives       13,979     24,116     43,794
  Realized foreign exchange       (991)     1,115     1,045
  Realized other income       (33)     (22)     (262)
Fund flows from operations - Current Period       185,528     185,528     804,865

Fund flows from operations of $185.5 million during Q4 2014 represented a decrease of $12.4 million (6%) versus Q3 2014.  This quarter-over-quarter decrease was the result of a $38.6 million decrease in sales, partially offset by a $14.0 million increase in hedging proceeds (following weaker commodity prices during the quarter) and a $9.2 million decrease in corporate income taxes.  The decrease in sales included $75.9 million of pricing variance primarily due to a decrease in crude oil prices, partially offset by $37.3 million of sales volume variance primarily due to higher volumes in Australia (due to inventory draws in the period). The decrease in corporate income taxes was due to lower taxable income resulting from decreased sales.

On a year-over-year basis, fund flows from operations increased 13% and 21% for the three months and year ended December 31, 2014, respectively, versus the comparable periods in 2013.  These increases were primarily the result of favorable sales volume variances in Canada coupled with incremental production following our Q1 2014 acquisition in Germany.  The impact of increased AECO pricing, hedging proceeds and lower income taxes also contributed favorably to fund flows from operations.  These favorable increases were partially offset by weaker crude oil and TTF pricing.

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   Year Ended   % change
          Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
Canada business unit       2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
Production                                    
  Crude oil (bbls/d)       11,384   11,469   8,719   (1%)   31%   11,248   8,387   34%
  NGLs (bbls/d)       2,741   2,291   1,699   20%   61%   2,476   1,666   49%
  Natural gas (mmcf/d)       58.36   57.07   41.43   2%   41%   55.67   42.39   31%
  Total (boe/d)       23,851   23,272   17,322   2%   38%   23,001   17,117   34%
Production mix (% of total)                                    
  Crude oil       48%   49%   50%           49%   49%    
  NGLs       11%   10%   10%           11%   10%    
  Natural gas       41%   41%   40%           40%   41%    
Activity                                    
  Capital expenditures ($M)       85,442   97,393   77,245   (12%)   11%   334,742   241,197   39%
  Acquisitions ($M)       1,671   27,883   1,603           415,648   9,189    
  Gross wells drilled       23.00   22.00   21.00           74.00   69.00    
  Net wells drilled       15.16   16.86   16.65           50.27   57.21    

Production

  • The year-over-year increase in full year average production volumes was primarily attributable to strong organic production growth in each of our Cardium light crude oil resource play and Mannville condensate-rich gas play as well as incremental production volumes from our southeast Saskatchewan assets acquired in April 2014.
  • Cardium production averaged more than 10,000 boe/d in Q4 2014 and more than 10,800 boe/d in 2014.  The 20% increase in average annual production volumes was driven by better-than-forecasted production from long-reach wells and improved completion design.
  • Mannville production averaged more than 4,300 boe/d in Q4 2014, a 17% increase quarter-over-quarter.  Full year 2014 production averaged in excess of 3,900 boe/d.
  • Production from our southeast Saskatchewan assets averaged approximately 3,000 boe/d in Q4 2014, an increase of 15% over Q3 2014.  Full year 2014 production averaged approximately 1,900 boe/d taking into account a closing date for the acquisition of April 29, 2014.

Activity review

  • Vermilion drilled a total of 18 (13.6 net) operated wells during Q4 2014 and 53 (44.8 net) operated wells during 2014.

Cardium

  • We drilled 13 (9.9 net) operated wells and brought 10 (7.0 net) operated wells on production during Q4 2014.  During 2014, we drilled 30 (25.9 net) operated wells and brought 30 (27.0 net) operated wells on production, of which 17 were long-reach wells with horizontal lengths greater than one mile.
  • Since 2009, we have drilled or participated in 278 (198.8 net) wells.
  • Operating netbacks averaged approximately $62.50/boe in 2014.
  • In 2015, we plan to drill or participate in approximately eight (3.0 net) wells and complete, equip and tie-in an additional 8.2 net wells which were drilled in 2014.

Mannville

  • During Q4 2014, we drilled four (3.0 net) operated wells and brought three (2.5 net) operated wells on production.  In 2014, we drilled 10 (7.7 net) operated wells and brought eight (6.2 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.

Duvernay

  • During the second half of 2014 we drilled two (1.3 net) horizontal wells.  One (0.3 net) well was completed and brought on production during Q3 2014.  The second well was completed and brought on production during Q4 2014.

Saskatchewan

  • We drilled one (0.7 net) operated Midale well and brought three (2.6 net) operated wells on production during Q4 2014.
  • In 2014, we drilled or participated in 12 (10.4 net) Midale wells.
  • In 2015, we plan to drill or participate in five (4.1 net) wells in Saskatchewan.

Financial review

        Three Months Ended   % change   Year Ended   % change
Canada business unit     Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
($M except as indicated)     2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
  Sales     112,494   138,853   97,367   (19%)   16%   537,788   382,005   41%
  Royalties     (15,626)   (19,034)   (11,039)   (18%)   42%   (65,563)   (40,891)   60%
  Transportation expense     (3,455)   (4,048)   (4,102)   (15%)   (16%)   (14,625)   (12,254)   19%
  Operating expense     (19,315)   (19,074)   (13,218)   1%   46%   (76,178)   (55,804)   37%
  General and administration     (2,840)   (4,523)   (2,478)   (37%)   15%   (16,791)   (12,979)   29%
  Fund flows from operations     71,258   92,174   66,530   (23%)   7%   364,631   260,077   40%
Netbacks ($/boe)                                  
  Sales     51.27   64.85   61.10   (21%)   (16%)   64.06   61.14   5%
  Royalties     (7.12)   (8.89)   (6.93)   (20%)   3%   (7.81)   (6.55)   19%
  Transportation expense     (1.57)   (1.89)   (2.57)   (17%)   (39%)   (1.74)   (1.96)   (11%)
  Operating expense     (8.80)   (8.91)   (8.29)   (1%)   6%   (9.07)   (8.93)   2%
  General and administration     (1.29)   (2.11)   (1.60)   (39%)   (19%)   (2.00)   (2.24)   (11%)
  Fund flows from operations netback     32.49   43.05   41.71   (25%)   (22%)   43.44   41.46   5%
Reference prices                                  
  WTI (US $/bbl)     73.15   97.17   97.46   (25%)   (25%)   93.00   97.97   (5%)
  Edmonton Sweet index (US $/bbl)     66.79   89.24   82.53   (25%)   (19%)   85.83   90.40   (5%)
  Edmonton Sweet index ($/bbl)     75.85   97.21   86.64   (22%)   (12%)   94.82   93.12   2%
  AECO ($/GJ)     3.41   3.81   3.35   (10%)   2%   4.27   3.01   42%

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 21% quarter-over-quarter as a result of a 25% decrease in Edmonton Sweet index pricing and a 10% decrease in AECO pricing.  This decrease coupled with relatively consistent production volumes resulted in a 19% decrease in sales.
  • On a year-over-year basis, sales per boe decreased by 16% for the three months ended December 31, 2014 and increased by 5% for the year ended December 31, 2014 versus the same periods in 2013.  Sales increased for the current year periods despite the decline in the Edmonton Sweet index price that occurred in the latter half of 2014 due to higher production, including incremental production from our Saskatchewan acquisition and production growth in the Cardium and Mannville resource plays, and higher AECO pricing.

Royalties

  • Royalty expense as a percentage of sales increased to 13.9% and 12.2% for the three months and year ended December 31, 2014 (versus 11.3% and 10.7% for the comparable periods in 2013).  The increase is associated with wells coming off of incentive royalty rates after reaching specified production thresholds, increased natural gas prices, and slightly higher average royalty rates associated with Vermilion's Saskatchewan production.
  • On a quarter-over-quarter basis, royalties as a percentage of sales for Q4 2014 was unchanged versus Q3 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 Q4 2014 was lower than Q3 2014 and Q4 2013 as a result of lower crude oil production subject to transportation costs.
  • Transportation expense increased for 2014 as compared to 2013 due to incremental trucking costs from Vermilion's Saskatchewan properties, which were acquired in Q2 2014.

Operating expense

  • On a per boe basis, operating expenses were relatively unchanged quarter-over-quarter and year-over-year.  In dollar terms, the year-over-year increase is a result of increased facilities maintenance expenditures and gas processing costs coupled with incremental operating expenses associated with Vermilion's Saskatchewan properties.

General and administration

  • Year-over-year, the increase in general and administration expense is associated with incremental expense associated with the Saskatchewan acquisition and higher staffing levels. The quarter-over-quarter decrease relates to the timing of expenditures.

FRANCE BUSINESS UNIT

Overview

  • Entered France in 1997 and completed three subsequent acquisitions, including two in 2012.
  • Largest oil producer 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   Year Ended   % change
          Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
France business unit       2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
Production                                    
  Crude oil (bbls/d)       11,133   11,111   11,131   -   -   11,011   10,873   1%
  Natural gas (mmcf/d)       -   -   -   -   -   -   3.40   (100%)
  Total (boe/d)       11,133   11,111   11,131   -   -   11,011   11,440   (4%)
Inventory (mbbls)                                    
  Opening crude oil inventory       214   179   226           269   354    
  Adjustments       -   -   -           -   5    
  Crude oil production       1,024   1,022   1,024           4,019   3,969    
  Crude oil sales       (1,041)   (987)   (981)           (4,091)   (4,059)    
  Closing crude oil inventory       197   214   269           197   269    
Production mix (% of total)                                    
  Crude oil       100%   100%   100%           100%   95%    
  Natural gas       -   -   -           -   5%    
Activity                                    
  Capital expenditures ($M)       37,189   35,082   31,899   6%   17%   147,852   100,378   47%
  Gross wells drilled       1.00   3.00   -           8.00   5.00    
  Net wells drilled       0.50   3.00   -           7.50   5.00    

Production

  • Q4 production was essentially flat quarter-over-quarter and year-over-year.  Full year 2014 average production was 4% lower versus full year average production in 2013 due to the shut-in of produced gas volumes at Vic Bilh.
  • 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.  We currently expect a portion of the Vic Bilh production (approximately 850 mcf/d) will be back on-stream in mid-2015.  As a result of the shut-in, current production volumes remain 100% weighted to Brent-based crude.

Activity review

  • Vermilion drilled one (0.5 net) well in the Tamaris field in the Aquitaine Basin in Q4 2014.
  • During Q4 2014, the 160 km2 Champotran 3D seismic project was completed ahead of schedule and under budget.  The final processing of the data is expected to be completed in Q1 2015.
  • During 2014, we drilled eight (7.5 net) wells in France, including the completion of a five-well drilling program in the Champotran field.  Additional activities in 2014 included a number of workovers, as well as seismic and facility integrity projects.
  • In 2015, we are planning a four-well drilling program in the Champotran field, an 18-well workover program and the resumption of sales of approximately 850 mcf/d of solution gas at Vic Bilh.

Financial review

        Three Months Ended   % change   Year Ended   % change
France business unit     Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
($M except as indicated)     2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
  Sales     82,499   106,576   110,757   (23%)   (26%)   431,252   453,315   (5%)
  Royalties     (6,319)   (6,978)   (6,577)   (9%)   (4%)   (28,444)   (27,045)   5%
  Transportation expense     (4,096)   (4,741)   (4,622)   (14%)   (11%)   (18,975)   (12,505)   52%
  Operating expense     (13,544)   (15,215)   (15,524)   (11%)   (13%)   (61,729)   (66,997)   (8%)
  General and administration     (3,765)   (6,411)   (5,080)   (41%)   (26%)   (20,929)   (19,657)   6%
  Current income taxes     (6,132)   (10,744)   (28,024)   (43%)   (78%)   (66,901)   (94,524)   (29%)
  Fund flows from operations     48,643   62,487   50,930   (22%)   (4%)   234,274   232,587   1%
Netbacks ($/boe)                                  
  Sales     79.25   107.99   112.84   (27%)   (30%)   105.43   106.26   (1%)
  Royalties     (6.07)   (7.07)   (6.70)   (14%)   (9%)   (6.95)   (6.34)   10%
  Transportation expense     (3.94)   (4.80)   (4.71)   (18%)   (16%)   (4.64)   (2.93)   58%
  Operating expense     (13.01)   (15.42)   (15.82)   (16%)   (18%)   (15.09)   (15.70)   (4%)
  General and administration     (3.62)   (6.50)   (5.18)   (44%)   (30%)   (5.12)   (4.61)   11%
  Current income taxes     (5.89)   (10.89)   (28.55)   (46%)   (79%)   (16.36)   (22.16)   (26%)
  Fund flows from operations netback     46.72   63.31   51.88   (26%)   (10%)   57.27   54.52   5%
Reference prices                                  
  Dated Brent (US $/bbl)     76.27   101.85   109.27   (25%)   (30%)   98.99   108.66   (9%)
  Dated Brent ($/bbl)     86.62   110.95   114.71   (22%)   (24%)   109.36   111.93   (2%)

Sales

  • Crude oil production in France is priced with reference to Dated Brent.
  • Sales per boe decreased by 27% quarter-over-quarter, consistent with the 25% decrease in the Dated Brent reference price. This decrease, partially offset by a decrease in inventory, resulted in a 23% decrease in sales.
  • On a year-over-year basis, sales per boe decreased by 30% and 1% for the three months and year ended December 31, 2014, respectively, as compared to the same periods in 2013.  This decrease was primarily driven by 30% and 9% decreases in the Dated Brent reference price for the three months and year ended December 31, 2014, respectively. For the three months ended December 31, 2014, this was partially offset by a 6% increase in sales volumes, resulting in a 26% decrease in sales. On a yearly basis, the decrease in crude pricing coupled with consistent sales volumes resulted in a 5% 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).
  • As a percentage of sales, royalties remained relatively consistent at 6.6% in 2014 (2013 - 6.0%).  As a percentage of sales, royalties increased from 6.5% in Q3 2014 to 7.7% in Q4 2014 due to the impact of fixed RCDM royalties coupled with lower realized pricing.

Transportation

  • Historically, transportation expense in France related to shipments of crude oil by tanker from the Aquitaine Basin to third party refineries.  As a result of the closure of the Lacq processing facility in Q3 2013, Vermilion began incurring additional transportation charges to ship Vic Bilh crude oil production to market.  Accordingly, transportation expense for the year ended December 31, 2014 is higher than the prior year.

Operating expense

  • Operating expense was lower in Q4 2014 as compared to both Q3 2014 and Q4 2013 on both a spend and on a per boe basis due to reduced facilities maintenance and repairs costs in the current quarter.  For the year ended December 31, 2014, operating expense per boe remained consistent with the prior year.

General and administration

  • General and administration expense for 2014 was 6% higher than in 2013 as a result of increased staffing costs and the weaker Canadian dollar relative to the Euro.  On a quarterly basis, general and administration expense fluctuates as a result of timing of expenditures and allocations from Vermilion's Corporate segment.

Current income taxes

  • Current income taxes in France are applied to taxable income after eligible deductions at a statutory rate of 34.4% for 2014.  In addition, a 10.7% temporary surtax is applicable for tax year 2014 and 2015 if annual revenue exceeds €250 million.  The France business unit is not subject to the 10.7% surtax for 2014.
  • Current income taxes for the three months and year ended December 31, 2014 were lower than the comparable periods in 2013 due to accelerated depletion on certain assets as a result of the impact of the declining 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   Year Ended   % change
          Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
Netherlands business unit       2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
Production                                    
  NGLs (bbls/d)       81   63   62   29%   31%   77   64   20%
  Natural gas (mmcf/d)       31.35   38.07   37.53   (18%)   (16%)   38.20   35.42   8%
  Total (boe/d)       5,306   6,407   6,318   (17%)   (16%)   6,443   5,967   8%
Activity                                    
  Capital expenditures ($M)       10,022   10,087   15,698   (1%)   (36%)   61,740   28,543   116%
  Acquisitions ($M)       -   -   27,500           -   27,500    
  Gross wells drilled       2.00   1.00   -           7.00   -    
  Net wells drilled       0.92   0.45   -           4.66   -    

Production

  • Achieved record annual production of 6,443 boe/d.
  • Production was 17% lower quarter-over-quarter while full year 2014 average production grew 8% versus 2013.  Production volumes in 2014 benefited from the addition of production from the DeHoeve-01 well during Q2 2014 and 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

  • Vermilion drilled the Langezwaag-02 well (42% working interest), in the Gorredijk concession, during Q4 2014.  The primary targets were the Vlieland (Cretaceous sandstone) and the Zechstein 2 (Permian carbonate) formations.  A ten hour clean-up test conducted on the Zechstein 2 formation delivered a stabilized flow rate of 14 mmcf/d of gas on a 48/64 inch choke with a flowing wellhead pressure of 1,378 psi(1).  This well was drilled from an existing lease site (Langezwaag-01) and is expected to be tied into existing facilities and on production in Q1 2015.
  • The final well of our seven-well 2014 drilling program, Sonnega-2, was drilled in the Steenwijk concession in Q4 2014.  A seven hour clean-up test conducted on the Vlieland formation delivered a stabilized flow rate of 15.8 mmcf/d on a 52/64 inch choke with a flowing wellhead pressure of 1,059 psi(1).  This well was drilled from an existing lease site and is expected to be tied into existing facilities and on production in Q2 2015.
  • In 2015, we are planning a three-well development drilling program and expect to equip and tie-in four previous discovery wells.

(1)  Test results are not necessarily indicative of long-term performance or of ultimate recovery.

Financial review

        Three Months Ended   % change   Year Ended   % change
Netherlands business unit     Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
($M except as indicated)     2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
  Sales     25,420   26,960   39,451   (6%)   (36%)   123,815   139,570   (11%)
  Royalties     (1,171)   (942)   -   24%   100%   (5,014)   -   100%
  Operating expense     (6,200)   (5,409)   (6,179)   15%   -   (24,041)   (20,617)   17%
  General and administration     (2,489)   (204)   (1,553)   1,120%   60%   (3,617)   (2,724)   33%
  Current income taxes     2,124   (1,189)   (8,267)   (279%)   (126%)   (4,154)   (34,132)   (88%)
  Fund flows from operations     17,684   19,216   23,452   (8%)   (25%)   86,989   82,097   6%
Netbacks ($/boe)                                  
  Sales     52.07   45.73   67.88   14%   (23%)   52.65   64.08   (18%)
  Royalties     (2.40)   (1.60)   -   50%   100%   (2.13)   -   100%
  Operating expense     (12.70)   (9.18)   (10.63)   38%   19%   (10.22)   (9.47)   8%
  General and administration     (5.10)   (0.35)   (2.67)   1,357%   91%   (1.54)   (1.25)   23%
  Current income taxes     4.35   (2.02)   (14.22)   (315%)   (131%)   (1.77)   (15.67)   (89%)
  Fund flows from operations netback     36.22   32.58   40.36   11%   (10%)   36.99   37.69   (2%)
Reference prices                                  
  TTF ($/GJ)     8.69   7.26   10.65   20%   (18%)   8.50   10.29   (17%)
  TTF (€/GJ)     6.12   5.04   7.45   21%   (18%)   5.79   7.51   (23%)

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 6% decrease in sales quarter-over-quarter is primarily related to a 17% decrease in production, partially offset by a 14% increase in sales per boe consistent with the 20% increase in the Canadian dollar equivalent of the TTF reference price.
  • On a year-over-year basis, sales per boe declined by 23% and 18% for the three months and year ended December 31, 2014, respectively.  This was consistent with the decrease in the TTF reference price over the same periods in 2013. On a quarterly basis, lower pricing coupled with a 16% decrease in production volumes resulted in a 36% decrease in sales. On a yearly basis, weaker pricing was partially offset by an 8% increase in production volumes, resulting in an 11% decrease in sales.

Royalties

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

Transportation expense

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

Operating expense

  • Operating expense per boe increased in Q4 2014 from Q3 2014 as additional project work was performed in Q4 2014.
  • Operating expense per boe for 2014 increased as compared to the prior year due to the strengthening of the Euro versus the Canadian dollar, as well as higher salary costs associated with increased staffing levels supporting the continued organic growth in the Netherlands business unit.

General and administration

  • On a year-over-year basis, general and administration expenses increased as a result of additional staffing and administration costs associated with Vermilion's continued organic growth in the Netherlands.  In addition, on a quarter-over-quarter basis, Q4 2014 general and administration expenses were higher than the comparable quarters due to the timing of allocations from Vermilion's Corporate segment.

Current income taxes

  • Current income taxes in the Netherlands apply to taxable income after eligible deductions at a statutory tax rate of approximately 46%.
  • Current income taxes decreased for the year ended December 31, 2014 as compared to the same period in 2013 as a result of decreased revenues from lower TTF reference prices, and an increase in tax deductions for depletion on two unsuccessful wells during the current year.
  • The effective rate is lower compared to the statutory rate due to accelerated tax deductions from certain capital expenditures and other eligible in-country tax adjustments resulting from the corporate acquisition completed in Q4 2013.

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.
  • Production licenses comprise 207,000 gross acres, of which 85% is in the exploration license.

Operational review

              Three Months Ended     % change     Year Ended
              Dec 31, Sep 30,     Q4/14 vs.     Dec 31,
Germany business unit           2014 2014     Q3/14     2014
Production                          
  Natural gas (mmcf/d)           17.71 15.38     15%     14.99
  Total (boe/d)           2,952 2,563     15%     2,498
Activity                          
  Capital expenditures ($M)           563 1,358     (59%)     2,747
  Acquisitions ($M)           - -           172,871

Production

  • Achieved Q4 2014 production of 2,952 boe/d, an increase of 15% as compared to 2,563 boe/d in the prior quarter, largely attributable to the Deblinghausen Z7a well being brought on production. Full year 2014 production averaged 2,498 boe/d taking into account an effective date for production of February 1, 2014.

Activity review

  • During the first quarter of 2014, we participated in the drilling of the Deblinghausen Z7a development well (25% working interest).
  • Continued the integration of the German business unit and commenced planning with our working interest partners for future drilling operations.
  • Hired a Managing Director for the German business unit and opened an office outside of Berlin.
  • In 2015, we are participating in the Burgmoor Z3a sidetrack well which spud in Q1 2015.

Financial review

              Three Months Ended     % change     Year Ended
Germany business unit           Dec 31, Sep 30,     Q4/14 vs.     Dec 31,
($M except as indicated)           2014 2014     Q3/14     2014
  Sales           13,359 8,591     55%     41,962
  Royalties           (2,481) (2,046)     21%     (8,613)
  Transportation expense           (218) (675)     (68%)     (2,367)
  Operating expense           (2,862) (2,227)     29%     (8,686)
  General and administration           (2,200) (1,090)     102%     (4,688)
  Current income taxes           1,145 (146)     (884%)     (44)
  Fund flows from operations           6,743 2,407     180%     17,564
Netbacks ($/boe)                          
  Sales           49.19 36.43     35%     46.03
  Royalties           (9.13) (8.68)     5%     (9.45)
  Transportation expense           (0.80) (2.86)     (72%)     (2.60)
  Operating expense           (10.54) (9.44)     12%     (9.53)
  General and administration           (8.10) (4.62)     75%     (5.14)
  Current income taxes           4.21 (0.62)     (779%)     (0.05)
  Fund flows from operations netback           24.83 10.21     143%     19.26
Reference prices                          
  TTF ($/GJ)           8.69 7.26     20%     8.50
  TTF (€/GJ)           6.12 5.04     21%     5.79

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.
  • Sales per boe increased by 35% from Q3 2014 due to an increase in the TTF reference price. This increase, coupled with higher production volumes, resulted in a 55% increase in sales quarter-over-quarter.

Royalties expense

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

Transportation expense

  • Transportation expense relates to costs incurred to deliver natural gas from the processing facility to the customer.
  • Transportation expense decreased for Q4 2014 as compared to Q3 2014 as a result of prior period adjustments recorded in the current quarter.

Operating expense

  • Operating expenses for Germany are billed monthly by the joint venture operator and are similar on a per boe basis to our Netherlands business unit.

General and administration

  • General and administration expense increased quarter-over-quarter as a result of increased 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 23%.
  • Current income taxes for Q4 2014 were lower compared to Q3 2014 due to the finalization of tax deductions related to the acquisition.

IRELAND BUSINESS UNIT

Overview

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

Operational and financial review

          Three Months Ended   % change   Year Ended   % change
Ireland business unit       Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
($M)       2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
  Transportation expense       (1,720)   (1,515)   (357)   14%   382%   (6,394)   (4,165)   54%
  General and administration       (579)   (334)   (482)   73%   20%   (1,447)   (1,442)   0%
  Fund flows from operations       (2,299)   (1,849)   (839)   24%   174%   (7,841)   (5,607)   40%
Activity                                    
  Capital expenditures       20,932   30,050   14,472   (30%)   45%   94,439   90,898   4%

Activity review

  • Our Corrib project in Ireland has continued to progress on schedule following the completion of tunnel boring operations in May 2014.  During the remainder of 2014, project operator Shell Exploration & Production Ireland Ltd. (SEPIL) successfully completed offshore workover and pipeline operations as well as outfitting of the 4.9 km tunnel including installation of flow and umbilical lines, hydro-testing and dewatering with the final weld completed in December.  The grouting of the tunnel was completed subsequent to year end 2014.  Natural gas from the sales grid was safely introduced into the processing facility in Q4 2014 as part of the commencement of operations at the plant. Remaining work includes the testing of all systems and processes required for the safe operation of the Bellanaboy gas processing terminal and the finalization of operating permits.
  • Based on the current schedule for remaining commissioning activities, we anticipate first gas in approximately mid-2015 with peak production of approximately 58 mmcf/d (9,700 boe/d), net to Vermilion.

Transportation expense

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

AUSTRALIA BUSINESS UNIT

Overview

  • Entered Australia in 2005.
  • Hold 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 sea bed in approximately 55 metres of water depth.
  • Contracted crude oil production is priced with reference to Dated Brent.

Operational review

          Three Months Ended   % change   Year Ended   % change
          Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
Australia business unit       2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
Production                                    
  Crude oil (bbls/d)       6,134   6,567   6,189   (7%)   (1%)   6,571   6,481   1%
Inventory (mbbls)                                    
  Opening crude oil inventory       258   189   183           130   268    
  Crude oil production       564   604   569           2,398   2,366    
  Crude oil sales       (785)   (535)   (622)           (2,491)   (2,504)    
  Closing crude oil inventory       37   258   130           37   130    
Activity                                    
  Capital expenditures ($M)       11,616   15,985   8,420   (27%)   38%   44,283   77,931   (43%)
  Gross wells drilled       -   -   -           -   2.00    
  Net wells drilled       -   -   -           -   2.00    

Production

  • Quarterly production decreased 7% quarter-over-quarter. Full year 2014 production increased 1% versus full year 2013.
  • Production volumes are managed within corporate targets while meeting customer demands and the requirements of long-term supply agreements.   We continue to plan for production levels of between 6,000 and 8,000 bbls/d.

Activity review

  • In Q4 2014, efforts were largely focused on facilities enhancement and engineering studies, including the expansion of accommodation quarters on the Wandoo B platform, as well as pre-drill activities for a two-well drilling program that was initially planned for Q1 2015 but which was subsequently deferred. 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   Year Ended   % change
Australia business unit     Dec 31,   Sep 30,   Dec 31,   Q4/14 vs.   Q4/14 vs.   Dec 31,   Dec 31,   2014 vs.
($M except as indicated)     2014   2014   2013   Q3/14   Q4/13   2014   2013   2013
  Sales     70,971   63,708   77,533   11%   (8%)   283,481   298,945   (5%)
  Operating expense     (17,719)   (14,302)   (13,219)   24%   34%   (61,432)   (51,625)   19%
  General and administration     (1,628)   (1,378)   (1,442)   18%   13%   (5,873)   (5,752)   2%
  PRRT     (13,568)   (13,834)   (17,173)   (2%)   (21%)   (60,340)   (56,565)   7%
  Corporate income taxes     (4,799)   (5,148)   (6,210)   (7%)   (23%)   (24,477)   (31,735)   (23%)
  Fund flows from operations     33,257   29,046   39,489   14%   (16%)   131,359   153,268   (14%)
Netbacks ($/boe)                                  
  Sales     90.37   119.07   124.63   (24%)   (27%)   113.80   119.38   (5%)
  Operating expense     (22.56)   (26.73)   (21.25)   (16%)   6%   (24.66)   (20.62)   20%
  General and administration     (2.07)   (2.58)   (2.32)   (20%)   (11%)   (2.36)   (2.30)   3%
  PRRT     (17.28)   (25.86)   (27.60)   (33%)   (37%)   (24.22)   (22.59)   7%
  Corporate income taxes     (6.11)   (9.62)   (9.98)   (36%)   (39%)   (9.83)   (12.67)   (22%)
  Fund flows from operations netback     42.35   54.28   63.48   (22%)   (33%)   52.73   61.20   (14%)
Reference prices                                  
  Dated Brent (US $/bbl)     76.27   101.85   109.27   (25%)   (30%)   98.99   108.66   (9%)
  Dated Brent ($/bbl)     86.62   110.95   114.71   (22%)   (24%)   109.36   111.93   (2%)

Sales

  • Our production in Australia currently receives a premium to Dated Brent.
  • Sales per boe for Q4 2014 decreased by 24% versus Q3 2014 as a result of a decrease in the Dated Brent reference price.  This decrease was offset by higher sales volumes, resulting in an 11% increase in sales.
  • Sales per boe for the three months and year ended December 31, 2014 versus the same periods in 2013 reflect the decrease in the Dated Brent reference price by 30% and 9%, respectively, partially offset by the weakening of the Canadian dollar versus the US dollar.  On a quarterly basis, this was partially offset by an increase in sales volumes, resulting in an 8% decrease in sales. On a yearly basis, the weaker pricing was coupled with consistent sales volumes, resulting in a 5% 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

  • On a quarter-over-quarter basis, operating expense for Q4 2014 was higher than Q3 2014 as a result of a large draw in inventory during the current quarter (221,000 bbls) versus a build in the previous quarter (69,000 bbls).  On a per barrel basis, operating expense decreased quarter-over-quarter as a result of lower diesel usage in the current quarter.
  • On a year-over-year basis, the three months and year ended December 31, 2014 had higher operating expense on a dollar and barrel basis as a result of increased diesel usage.

General and administration

  • General and administration expense for 2014 was relatively unchanged versus 2013.  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.
  • Combined corporate income taxes and PRRT movements for the three months and year ended December 31, 2014 versus the comparable periods in 2013 were largely consistent with the fluctuations in sales.  On a year-over-year basis, PRRT for 2014 increased versus the 2013 periods as a result of the lower capital spending in 2014.

UNITED STATES BUSINESS UNIT

Overview

  • Entered the United States in September 2014 with $11.1 million acquisition.
  • 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
United States business unit                     Dec 31,
($M except as indicated)                     2014
  Sales                     1,330
  Royalties                     (366)
  Operating expense                     (241)
  General and administration                     (959)
  Fund flows from operations                     (236)
Netbacks ($/boe)                      
  Sales                     74.08
  Royalties                     (20.38)
  Operating Expense                     (13.44)
  General and administration                     (53.44)
  Fund flows from operations netback                     (13.18)
Production                      
  Crude oil (bbls/d)                     195
  Total (boe/d)                     195
Activity                      
  Capital expenditures                     460
Reference prices                      
  WTI (US $/bbl)                     73.15
  WTI ($/bbl)                     83.08

Activity review

  • The most recently completed well on this land block (70% working interest) is currently producing approximately 150 bbls/d of oil in its seventh month of production, from an approximately 1,100 metre hydraulically-fractured horizontal lateral.
  • We plan to drill one well in the East Finn prospect in 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 represents costs incurred by the contract operators of our current wells in the United States.

General and administration

  • General and administration expense for Q4 2014 relate to the initial costs incurred to establish an office in Denver, Colorado.

CORPORATE

Overview

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

Financial review

                Three Months Ended     Year Ended
                Dec 31,     Sep 30,     Dec 31,     Dec 31,     Dec 31,
($M)               2014     2014     2013     2014     2013
General and administration               1,224     (2,322)     (2,919)     (7,423)     (7,356)
Current income taxes               (642)     (227)     (564)     (1,420)     (1,403)
Interest expense               (12,943)     (12,918)     (10,049)     (49,655)     (38,183)
Realized gain (loss) on derivatives               22,816     8,837     (1,300)     36,712     (7,082)
Realized foreign exchange (loss) gain               (179)     812     (1,294)     (821)     (1,866)
Realized other income               202     235     224     732     994
Fund flows from operations               10,478     (5,583)     (15,902)     (21,875)     (54,896)

General and administration

  • The decrease in general and administration costs in Q4 2014 as compared to Q3 2014 and Q4 2013 is largely 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.
  • On a year-over-year basis, general and administration costs for the year ended December 31, 2014 as compared to 2013 remained relatively consistent. The change is primarily due to cost saving initiatives and increased salary allocations to the various segments, partially offset by certain outstanding Vermilion Incentive Plan ("VIP") awards to be settled partially in cash.

Current income taxes

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

Interest expense

  • Interest expense is incurred on our senior unsecured notes and on borrowings under our revolving credit facility.  As compared to Q3 2014, Q4 2014 interest expense remained consistent. The increase in the three months and year ended December 31, 2014 versus the comparable periods in 2013 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 2014 related primarily to amounts received on our TTF and Dated Brent derivatives, partially offset by payments made on our AECO derivatives.
  • A listing of derivative positions as at December 31, 2014 is included in "Supplemental Table 2" in this MD&A.

FINANCIAL PERFORMANCE REVIEW

                            Year Ended
                            Dec 31,   Dec 31,   Dec 31,
($M except per share)                         2014   2013   2012
Total assets                         4,386,091   3,708,719   3,076,257
Long-term debt                         1,238,080   990,024   642,022
Petroleum and natural gas sales                         1,419,628   1,273,835   1,083,103
Net earnings                         269,326   327,641   190,622
Net earnings per share                                  
  Basic                         2.55   3.24   1.94
  Diluted                         2.51   3.20   1.92
Cash dividends ($/share)                         2.58   2.40   2.28
                                     
        Three Months Ended
        Dec 31,   Sep 30,   Jun 30,   Mar 31,   Dec 31,   Sep 30,   Jun 30,   Mar 31,
($M except per share)     2014   2014   2014   2014   2013   2013   2013   2013
Petroleum and natural gas sales     306,073   344,688   387,684   381,183   325,108   327,185   311,966   309,576
Net earnings     58,642   53,903   53,993   102,788   101,510   67,796   106,198   52,137
Net earnings per share                                  
  Basic     0.55   0.50   0.51   1.00   1.00   0.67   1.05   0.53
  Diluted     0.54   0.50   0.50   0.99   0.98   0.66   1.04   0.51

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

($M)           Q4/14 vs. Q3/14     Q4/14 vs. Q4/13       2014 vs. 2013
Net earnings - Comparative period           53,903     101,510       327,641
Changes in:                          
Fund flows from operations           (12,370)     21,868       137,339
Equity based compensation           (3,673)     2,813       (6,957)
Unrealized gain or loss on derivative instruments           9,357     15,885       22,260
Unrealized foreign exchange gain or loss           7,881     (26,276)       (69,627)
Unrealized other expense           (148)     (323)       (41)
Accretion           (123)     340       652
Depletion and depreciation           (13,022)     (33,487)       (103,308)
Deferred tax           16,837     23,712       8,767
Impairment recovery           -     (47,400)       (47,400)
Net earnings - Current Period           58,642     58,642       269,326

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.

For the year ended December 31, 2014, equity based compensation expense was higher than the same period in 2013 as a result of an upward revision of future performance condition assumptions during Q2 2014.  Equity based compensation expense was higher for Q4 2014 as compared to Q3 2014 due to a higher number of VIP awards outstanding.  Equity based compensation expense in Q4 2014 was lower than Q4 2013 as the 2013 period included an upward revision of future performance condition assumptions.

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.

In the year ended December 31, 2014, we recognized an unrealized gain on derivative instruments of $27.4 million, relating primarily to our TTF and crude oil swaps and collars.  As at December 31, 2014, we have a net derivative asset position of $24.8 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 and year ended December 31, 2014, the Canadian dollar strengthened versus the Euro resulting in unrealized foreign exchange losses of $4.0 million and $17.6 million, respectively.

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

Q4 2014 accretion expense was relatively consistent as compared to Q3 2014 and the comparable periods in 2013.

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 $24.42 in Q4 2014 was higher as compared to $23.21 in Q3 2014. Depletion and depreciation on a per boe basis increased for the three months and year ended December 31, 2014 to $24.42/boe and $23.31/boe, respectively, as compared to the same periods in 2013 of $22.15/boe and $21.22/boe, respectively. The increase on a per boe basis was largely due to Vermilion's increased capital and acquisition activity which resulted in higher per boe amounts when compared to legacy producing assets.

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.

TAXES

Corporate income tax rates
Vermilion pays corporate income taxes in France, the Netherlands, Germany, and Australia.  In addition, Vermilion pays PRRT in Australia.  PRRT is a profit based tax applied at a rate of 40% on sales less operating expenses, capital expenditures, and other eligible expenditures.  PRRT is deductible in the calculation of taxable income in Australia.

Taxable income was subject to corporate income tax at the following rates:

Jurisdiction                               2014       2013
Canada                               25.5%       25.0%
France                               34.4%       38.0%
Netherlands                               46.0%       46.0%
Germany                               22.8%       -
Ireland                               25.0%       25.0%
Australia                               30.0%       30.0%
United States                               35.0%       -

France tax legislation
In December 2013, the France government enacted corporate tax legislation that will lead to increases in current tax for companies operating in France, including a temporary surtax of 10.7% (with the surtax levied as a percent of base corporate income tax payable). The new surtax rate is applicable for companies which have annual revenue in excess of €250 million and if applicable to Vermilion's France Operations would effectively increase the statutory rate applicable to our French operations to 38.1% for applicable years.  The surtax has been extended to tax years ending up to December 31, 2016. The French operations were not subject to the surcharge in 2014 and are not expected to be subject to the surcharge for 2015 at current commodity prices.

In 2012, the France government enacted a new 3% tax on dividend distributions made by entities subject to corporate income tax in France. The tax applies to any dividends paid on or after April 17, 2012 and is not recovered by any tax treaties or deductible for French corporate income tax purposes. Vermilion did not pay any dividends from its French entities in 2014.

Tax pools
As at December 31, 2014, we had the following tax pools:

($M)               Oil & Gas Assets     Tax Losses 4         Other       Total
Canada               1,128,614 (1)     326,300         6,299       1,461,213
France               403,201 (2)     -         -       403,201
Netherlands               59,032 (3)     -         -       59,032
Germany               134,550 (2)     17,348         17,004       168,902
Ireland               897,528 (4)     332,140         -       1,229,668
Australia               219,273 (1)     -         -       219,273
United States               12,072 (1)     395         -       12,467
Total               2,854,270     676,183         23,303       3,553,756

(1) Deduction calculated using various declining balance rates
(2) Deduction calculated using a combination of straight-line over the assets life and unit of production method
(3) Deduction calculated using a unit of production method
(4) Development expenditures and losses are deductible at 100% against taxable income

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 accepted 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
                Dec 31, Dec 31,     Dec 31,       Dec 31,
($M)               2014 2013     2014       2013
Revolving credit facility               3.1% 3.3%     1,014,067       766,898
Senior unsecured notes               6.5% 6.5%     224,013       223,126
Long-term debt               3.8% 4.2%     1,238,080       990,024

Revolving Credit Facility
On January 30, 2015, Vermilion exercised its option to increase its credit facility to $1.75 billion.  The facility bears interest at rates applicable to demand loans plus applicable margins.  The following table outlines the terms of our revolving credit facility:

                      As At
                      Dec 31,       Dec 31,
                      2014       2013
Total facility amount                     $1.75 billion       $1.20 billion
Amount drawn                     $1.0 billion       $766.9 million
Letters of credit outstanding                     $8.6 million       $8.1 million
Facility maturity date                     31-May-17       31-May-16

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

                    As At
                    Dec 31,       Dec 31,
Financial covenant           Limit       2014       2013
Consolidated total debt to consolidated EBITDA           4.0       1.21       1.06
Consolidated total senior debt to consolidated EBITDA           3.0       0.99       0.82
Consolidated total senior debt to total capitalization           55%       31%       28%

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

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

Subsequent to February 10, 2015, 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
                  Dec 31,     Dec 31,
($M)                 2014     2013
Long-term debt                 1,238,080     990,024
Current liabilities                 365,729     347,444
Current assets                 (338,159)     (587,783)
Net debt                 1,265,650     749,685
                         
Ratio of net debt to fund flows from operations                 1.6     1.1

Long-term debt as at December 31, 2014 increased to $1.24 billion from $990.0 million as at December 31, 2013 as a result of draws on the revolving credit facility during the current year to fund our acquisitions in Germany and Saskatchewan coupled with the assumption of $47.5 million of long-term debt pursuant to the latter acquisition. This increase in long-term debt resulted in an increase to net debt from $749.7 million to $1.27 billion.  As a result of this increase to long-term debt, the ratio of net debt to fund flows from operations increased from 1.1 as at December 31, 2013 to 1.6 as at December 31, 2014.

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

During the year ended December 31, 2014, we maintained monthly dividends at $0.215 per share and declared dividends totalled $272.7 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.  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, 2013           102,123       1,618,443
Shares issued pursuant to corporate acquisition           2,827       204,960
Issuance of shares 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

As at December 31, 2014, there were approximately 1.8 million VIP awards outstanding.  As at February 27, 2015, there were approximately 107.6 million common shares issued and outstanding.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

As at December 31, 2014, we had the following contractual obligations and commitments:

($M)     Less than 1 year     1 - 3 years     3 - 5 years     After 5 years     Total
Long-term debt     14,625     1,240,691     -       -       1,255,316
Operating lease obligations     14,782     19,030     16,328     18,549     68,689
Ship or pay agreement relating to the Corrib project     6,807     9,128     7,461     40,152     63,548
Purchase obligations     25,257     8,911     27     -       34,195
Drilling and service agreements     24,884     21,153     -       -       46,037
Total contractual obligations and commitments     86,355     1,298,913     23,816     58,701     1,467,785

ASSET RETIREMENT OBLIGATIONS

As at December 31, 2014, asset retirement obligations were $350.8 million compared to $326.2 million as at December 31, 2013.

The increase in asset retirement obligations is largely attributable to accretion, additions from new wells drilled during the year, and abandonment obligations associated with the assets acquired in Germany, the United States, and Canada.  

RISKS AND UNCERTAINTIES

Crude oil and natural gas exploration, production, acquisition and marketing operations involve a number of risks and uncertainties including financial risks and uncertainties.  These include fluctuations in commodity prices, exchange rates and interest rates as well as uncertainties associated with reserve and resource volumes, sales volumes and government regulatory and income tax regime changes.  These and other related risks and uncertainties are discussed in additional detail below.

Commodity prices
Our operational results and financial condition is dependent on the prices received for crude oil and natural gas production. Crude oil and natural gas prices have fluctuated significantly during recent years and are determined by supply and demand factors, including weather and general economic conditions as well as conditions in other crude oil and natural gas producing regions.

Exchange rates
Much of our revenue stream is priced in U.S. dollars and as such an increase in the strength of the Canadian dollar relative to the U.S. dollar may result in the receipt of fewer Canadian dollars with respect to our production. In addition, we incur expenses and capital costs in U.S. dollars, Euros and Australian dollars and accordingly, the Canadian dollar equivalent of these expenditures as reported in our financial results is impacted by the prevailing foreign currency exchange rates at the time the transaction occurs. We monitor risks associated with exchange rates and, when appropriate, use derivative financial instruments to manage our exposure to these risks.

Production and sales volumes
The operation of crude oil and natural gas wells and facilities involves a number of operating and natural hazards which may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damage to us and possible liability to third parties.  We maintain liability insurance, where available, in amounts consistent with industry standards. Business interruption insurance may also be purchased for selected operations, to the extent that such insurance is commercially viable. We may become liable for damages arising from such events against which we cannot insure or against which we may elect not to insure because of high premium costs or other reasons.  Costs incurred to repair such damage or pay such liabilities may materially impact our financial results.

Continuing production from a property, and to some extent the marketing of produced volumes, is largely dependent upon the ability of the operator of the property. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat our claim to certain properties. Such circumstances could negatively affect our financial results.

An increase in operating costs or a decline in our production level could have an adverse effect on our financial results. The level of production may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond our control. A significant decline in production could result in materially lower revenues.

Interest rates
An increase in interest rates could result in a significant increase in the amount we pay to service debt.

Reserve volumes
Our reserve volumes and related reserve values support the carrying value of our crude oil and natural gas assets on the consolidated balance sheets and provide the basis to calculate the depletion of those assets. There are numerous uncertainties inherent in estimating quantities of reserves and future net revenues to be derived therefrom, including many factors beyond our control. These include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of crude oil, NGLs and natural gas, operating expenses, well abandonment and salvage values, royalties and any government levies that may be imposed over the producing life of the reserves. These assumptions were based on estimated prices in use at the date the evaluation was prepared, and many of these assumptions are subject to change and are beyond our control.  Actual production and income derived therefrom will vary from these evaluations, and such variations could be material.

Asset retirement obligations
Our asset retirement obligations are based on environmental regulations and estimates of future costs and the timing of expenditures.  Changes in environmental regulations, the estimated costs associated with reclamation activities and the related timing may impact our financial position and results of operations.

Government regulation and income tax regime
Our operations are governed by many levels of government, including municipal, state, provincial and federal governments, in Canada, France, the Netherlands, Australia, Germany, Ireland and the United States.  We are subject to laws and regulations regarding environment, health and safety issues, lease interests, taxes and royalties, among others. Failure to comply with the applicable laws can result in significant increases in costs, penalties and even losses of operating licences. The regulatory process involved in each of the countries in which we operate is not uniform and regulatory regimes vary as to complexity, timeliness of access to, and response from, regulatory bodies and other matters specific to each jurisdiction.  If regulatory approvals or permits are delayed or not obtained, there can also be delays or abandonment of projects and decreases in production and increases in costs, potentially resulting in us being unable to fully execute our strategy. Governments may also amend or create new legislation and regulatory bodies may also amend regulations or impose additional requirements which could result in increased capital, operating and compliance costs.

There can be no assurance that income tax laws and government incentive programs relating to the crude oil and natural gas industry in Canada and the foreign jurisdictions in which we operate, will not be changed in a manner which adversely affects the results of our operations.

A change in the royalty regime resulting in an increase in royalties would reduce our net earnings and could make future capital expenditures or our operations uneconomic and could, in the event of a material increase in royalties, make it more difficult to service and repay outstanding debt. Any material increase in royalties would also significantly reduce the value of the associated assets.

FINANCIAL RISK MANAGEMENT

To mitigate the aforementioned risks whenever possible, we seek to hire personnel with experience in specific areas. In addition, we provide continued training and development to staff to further develop their skills. When appropriate, we use third party consultants with relevant experience to augment our internal capabilities with respect to certain risks.

We consider our commodity price risk management program as a form of insurance that protects our cash flow and rate of return. The primary objective of the risk management program is to support our dividends and our internal capital development program. The level of commodity price risk management that occurs is highly dependent on the amount of debt that is carried. When debt levels are higher, we will be more active in protecting our cash flow stream through our commodity price risk management strategy.

When executing our commodity price risk management programs, we use derivative financial instruments encompassing over-the-counter financial structures as well as fixed/collar structures to economically hedge a part of our physical crude oil and natural gas production. We have strict controls and guidelines in relation to these activities and contract principally with counterparties that have investment grade credit ratings.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies.  These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made.  As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on our consolidated financial statements or financial performance.  Estimates are reviewed by management on an ongoing basis, and as a result, certain estimates may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction in which we operate, the critical accounting estimates may affect one or more jurisdictions.

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

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

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

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

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

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

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

OFF BALANCE SHEET ARRANGEMENTS

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

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

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

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

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

IFRS 15 "Revenue from Contracts with Customers"
On May 28, 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers", a new standard that specifies recognition requirements for revenue as well as requiring entities to provide the users of financial statements with more informative and relevant disclosures.  The standard replaces IAS 11 "Construction Contracts" and IAS 18 "Revenue" as well as a number of revenue-related interpretations.  Vermilion will adopt the standard for reporting periods beginning January 1, 2017.

HEALTH, SAFETY AND ENVIRONMENT

We are committed to ensuring we conduct our activities in a manner that will protect the health and safety of our employees, contractors and the public.  Our health, safety and environment vision is to fully integrate health, safety and environment into our business, where our culture is recognized as a model by industry and stakeholders, resulting in a workplace free of incidents. Our mantra is HSE: Everywhere. Everyday. Everyone.

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

In 2014, we remained committed to the principles of the Responsible Canadian Energy™ program set out by the Canadian Association of Petroleum Producers.  Responsible Canadian Energy™ is an association-wide performance reporting program to demonstrate progress in environmental, health, safety, and social performance.

We uphold our commitment to keep our people safe and to reduce impacts to land, water and air, as policies and procedures demonstrating leadership in these areas, were maintained and further developed in 2014.  Examples of our accomplishments during the year included:

  • Clear priorities around 5 key focus areas of HSE Culture, Communication and Knowledge Management, Technical Safety Management, Incident Prevention and Operational Stewardship & Sustainability;
  • Reviewed and updated our HSE Policy to reflect our HSE maturity advances;
  • Completed and published our first Corporate Sustainability Report;
  • Submitted our first report to the Carbon Disclosure Project (CDP);
  • Introduced a Fair Culture Policy to ensure transparency in our processes;
  • Developed a robust risk mitigation program around our top fatal risk exposures;
  • Advanced the completion of our Process Safety and Asset Integrity Management Systems;
  • Updated various key Corporate HSE Standards such as the Event Management Practice;
  • Reducing long-term environmental liabilities through decommissioning, abandoning and reclaiming well leases and facilities;
  • Continuous auditing, management inspections and workforce observations to identify potential hazards and apply risk reduction measures;
  • Development, communication and measurement against leading and lagging HSE key performance indicators;
  • Further enhancement of our competency and training programs;
  • Managing our waste products by reducing, recycling and recovering; and
  • Continuing risk management efforts in addition to detailed emergency-response planning.

We are a member of several organizations concerned with environment, health and safety, including numerous regional co-operatives and synergy groups.  In the area of stakeholder relations, we work to build long-term relationships with environmental stakeholders and communities.

CORPORATE GOVERNANCE

We are committed to a high standard of corporate governance practices, a dedication that begins at the Board level and extends throughout the Company.  We believe good corporate governance is in the best interest of our shareholders, and that successful companies are those that deliver growth and a competitive return along with a commitment to the environment, to the communities where they operate and to their employees.

We comply with the objectives and guidelines relating to corporate governance adopted by the Canadian Securities Administrators and the Toronto Stock Exchange.  In addition, the Board monitors and considers the implementation of corporate governance standards proposed by various regulatory and non-regulatory authorities in Canada.  A discussion of corporate governance policies will be provided in our Management Proxy Circular, which will be filed on SEDAR (www.sedar.com) and mailed to all shareholders on April 10, 2015.

A summary of the significant differences between the governance practices of the Company and those required of U.S. domestic companies under the New York Stock Exchange listing standards can be found in the Governance section of the Company's website at http://www.vermilionenergy.com/about/governance.cfm.

DISCLOSURE CONTROLS AND PROCEDURES

Our officers have established and maintained disclosure controls and procedures and evaluated the effectiveness of these controls in conjunction with our filings.

As of December 31, 2014, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures.  Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded and certified that our disclosure controls and procedures are effective.

INTERNAL CONTROL OVER FINANCIAL REPORTING

A company's internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

The Chief Executive Officer and the Chief Financial Officer of Vermilion have assessed the effectiveness of Vermilion's internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. The assessment was based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Chief Executive Officer and the Chief Financial Officer of Vermilion have concluded that Vermilion's internal control over financial reporting was effective as of December 31, 2014. The effectiveness of Vermilion's internal control over financial reporting as of December 31, 2014 has been audited by Deloitte LLP, as reflected in their report included in the 2014 audited annual financial statements filed with the US Securities and Exchange Commission. No changes were made to Vermilion's internal control over financial reporting during the year ended December 31, 2014, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Supplemental Table 1: Netbacks

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

    Three Months Ended December 31, 2014   Year Ended December 31, 2014   Three Months
Ended
December 31,
2013
  Year Ended
December 31,
2013
    Oil & NGLs   Natural Gas     Total   Oil & NGLs   Natural Gas     Total   Total   Total
    $/bbl   $/mcf     $/boe   $/bbl   $/mcf     $/boe   $/boe   $/boe
Canada                                    
Sales   71.13   3.74     51.27   88.98   4.53     64.06   61.10   61.14
Royalties   (11.00)   (0.25)     (7.12)   (11.78)   (0.32)     (7.81)   (6.93)   (6.55)
Transportation   (2.03)   (0.15)     (1.57)   (2.25)   (0.16)     (1.74)   (2.57)   (1.96)
Operating   (10.40)   (1.08)     (8.80)   (9.91)   (1.31)     (9.07)   (8.29)   (8.93)
Operating netback   47.70   2.26     33.78   65.04   2.74     45.44   43.31   43.70
General and administration             (1.29)             (2.00)   (1.60)   (2.24)
Fund flows from operations netback             32.49             43.44   41.71   41.46
France                                    
Sales   79.25   -     79.25   105.43   -     105.43   112.84   106.26
Royalties   (6.07)   -     (6.07)   (6.95)   -     (6.95)   (6.70)   (6.34)
Transportation   (3.94)   -     (3.94)   (4.64)   -     (4.64)   (4.71)   (2.93)
Operating   (13.01)   -     (13.01)   (15.09)   -     (15.09)   (15.82)   (15.70)
Operating netback   56.23   -     56.23   78.75   -     78.75   85.61   81.29
General and administration             (3.62)             (5.12)   (5.18)   (4.61)
Current income taxes             (5.89)             (16.36)   (28.55)   (22.16)
Fund flows from operations netback             46.72             57.27   51.88   54.52
Netherlands                                    
Sales   76.40   8.62     52.07   91.33   8.70     52.65   67.88   64.08
Royalties   -   (0.41)     (2.40)   -   (0.36)     (2.13)   -   -
Operating   -   (2.15)     (12.70)   -   (1.72)     (10.22)   (10.63)   (9.47)
Operating netback   76.40   6.06     36.97   91.33   6.62     40.30   57.25   54.61
General and administration             (5.10)             (1.54)   (2.67)   (1.25)
Current income taxes             4.35             (1.77)   (14.22)   (15.67)
Fund flows from operations netback             36.22             36.99   40.36   37.69
Germany                                    
Sales   -   8.20     49.19   -   7.67     46.03   -   -
Royalties   -   (1.52)     (9.13)   -   (1.57)     (9.45)   -   -
Transportation   -   (0.13)     (0.80)   -   (0.43)     (2.60)   -   -
Operating   -   (1.76)     (10.54)   -   (1.59)     (9.53)   -   -
Operating netback   -   4.79     28.72   -   4.08     24.45   -   -
General and administration             (8.10)             (5.14)   -   -
Current income taxes             4.21             (0.05)   -   -
Fund flows from operations netback             24.83             19.26   -   -
Australia                                    
Sales   90.37   -     90.37   113.80   -     113.80   124.63   119.38
Operating   (22.56)   -     (22.56)   (24.66)   -     (24.66)   (21.25)   (20.62)
PRRT (1)   (17.28)   -     (17.28)   (24.22)   -     (24.22)   (27.60)   (22.59)
Operating netback   50.53   -     50.53   64.92   -     64.92   75.78   76.17
General and administration             (2.07)             (2.36)   (2.32)   (2.30)
Corporate income taxes             (6.11)             (9.83)   (9.98)   (12.67)
Fund flows from operations netback             42.35             52.73   63.48   61.20
United States                                    
Sales   74.08   -     74.08   74.08   -     74.08   -   -
Royalties   (20.38)   -     (20.38)   (20.38)   -     (20.38)   -   -
Operating   (13.44)   -     (13.44)   (13.44)   -     (13.44)   -   -
Operating netback   40.26   -     40.26   40.26   -     40.26   -   -
General and administration             (53.44)             (53.44)   -   -
Fund flows from operations netback             (13.18)             (13.18)   -   -
Total Company                                    
Sales   78.64   5.90     63.79   100.06   6.42     77.75   86.04   83.83
Realized hedging gain (loss)   7.17   0.02     4.76   2.21   0.28     2.01   (0.34)   (0.47)
Royalties   (6.66)   (0.50)     (5.41)   (7.55)   (0.51)     (5.92)   (4.66)   (4.47)
Transportation   (2.14)   (0.28)     (1.98)   (2.60)   (0.30)     (2.32)   (2.40)   (1.90)
Operating   (14.29)   (1.50)     (12.48)   (14.87)   (1.49)     (12.72)   (12.74)   (12.84)
PRRT (1)   (4.31)   -     (2.83)   (5.19)   -       (3.30)   (4.55)   (3.72)
Operating netback   58.41   3.64     45.85   72.06   4.40     55.50   61.35   60.43
General and administration             (2.76)             (3.38)   (3.69)   (3.28)
Interest expense             (2.70)             (2.72)   (2.66)   (2.51)
Realized foreign exchange loss             (0.03)             (0.04)   (0.34)   (0.12)
Other income             0.04             0.04   0.06   0.07
Corporate income taxes (1)             (1.73)             (5.31)   (11.40)   (10.65)
Fund flows from operations netback             38.67             44.09   43.32   43.94

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

Supplemental Table 2: Hedges

The following tables outline Vermilion's outstanding risk management positions as at December 31, 2014:

            Note       Volume       Strike Price(s)
Crude Oil                            
WTI - Collar                            
January 2015 - March 2015                   500 bbl/d       76.25 - 92.15 US $
January 2015 - June 2015           1       250 bbl/d       75.00 - 82.75 US $
Dated Brent - Collar                            
January 2015 - March 2015                   500 bbl/d       78.75 - 89.63 US $
Dated Brent - Swap                            
January 2015           2       500 bbl/d       101.55 US $
January 2015 - March 2015           3       250 bbl/d       91.95 US $
February 2015           4       500 bbl/d       103.80 US $
March 2015           5       250 bbl/d       110.40 US $
MSW - Fixed Price Differential (Physical)                            
November 2014 - March 2015                   1,042 bbl/d       WTI less 6.85 US $
January 2015 - March 2015                   2,098 bbl/d       WTI less 7.39 US $
LSB - Fixed Price Differential (Physical)                            
October 2014 - March 2015                   830 bbl/d       WTI less 10.00 US $
January 2015 - March 2015                   524 bbl/d       WTI less 8.60 US $
                             
North American Natural Gas                            
AECO - Collar                            
April 2014 - March 2015                   2,500 GJ/d       3.60 - 4.08 CAD $
November 2014 - March 2015                   2,500 GJ/d       3.60 - 4.27 CAD $
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 Basis - Fixed Price Differential                            
January 2015 - December 2015                   5,000 mmbtu/d       Nymex HH less 0.68 US $
Nymex HH - Collar                            
November 2014 - March 2015                   10,000 mmbtu/d       3.50 - 5.00 US $
January 2015 - March 2015                   10,000 mmbtu/d       3.70 - 5.10 US $
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 $
Nymex HH - Swap                            
January 2015                   2,500 mmbtu/d       4.53 US $
January 2015 - March 2015                   5,000 mmbtu/d       4.38 US $
                             
European Natural Gas                            
TTF - Collar                            
January 2015 - December 2015                   2,592 GJ/d       6.11 - 6.83 EUR €
TTF - Swap                            
January 2015 - March 2015                   4,392 GJ/d       6.47 EUR €
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                   2,592 GJ/d       6.46 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 €

(1) The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price.
(2)  On March 31, 2015, the counterparty has the option to extend the swap for the period of April to June 2015 for 1,000 boe/d at the contracted price.
(3)  On March 31, 2015, the counterparty has the option to extend the swap for the period of April to June 2015 for 500 boe/d at the contracted price.
(4)  On June 30, 2015, the counterparty has the option to extend the swap for the period of July to September 2015 for 1,000 boe/d at the contracted price.
(5)  On September 30, 2015, the counterparty has the option to extend the swap for the period of October to December 2015 for 500 boe/d at the contracted price.
   

                      Note       Volume       Strike Price(s)
Electricity                                      
AESO - Swap (Physical)                                      
January 2013 - December 2015                             72.0 MWh/d       53.17 CAD $
                                       
US Dollar                                      
USD - Collar                                      
January 2015 - March 2015                             7,000,000 US $/month       1.140 - 1.184 CAD $
January 2015 - March 2015                     1       15,500,000 US $/month       1.140 - 1.157 CAD $

(1)  Vermilion has upside participation on this hedge up to the limit price of 1.222 CAD; above which, settlement will occur at the conditional call level of 1.157 CAD.

Supplemental Table 3: Capital Expenditures

            Three Months Ended     Year Ended
By classification           Dec 31,     Sep 30,     Dec 31,     Dec 31,     Dec 31,
($M)           2014     2014     2013     2014     2013
Drilling and development           151,395     180,479     147,929     618,689     537,564
Dispositions           -     -     -     -     (8,627)
Exploration and evaluation           14,848     9,554     549     69,035     13,789
Capital expenditures           166,243     190,033     148,478     687,724     542,726
Property acquisition           1,652     40,847     1,603     220,726     9,189
Corporate acquisition           -     -     27,500     381,139     27,500
Acquisitions           1,652     40,847     29,103     601,865     36,689
                                     
            Three Months Ended     Year Ended
By category           Dec 31,     Sep 30,     Dec 31,     Dec 31,     Dec 31,
($M)           2014     2014     2013     2014     2013
Land           1,457     2,346     2,676     9,506     3,662
Seismic           7,598     6,135     1,942     19,034     16,608
Drilling and completion           69,691     93,386     68,993     311,696     279,003
Production equipment and facilities           77,272     68,964     63,420     275,538     201,846
Recompletions           7,696     10,853     3,309     36,234     27,600
Other           2,529     8,349     8,138     35,716     22,634
Dispositions           -     -     -     -     (8,627)
Capital expenditures           166,243     190,033     148,478     687,724     542,726
Acquisitions           1,652     40,847     29,103     601,865     36,689
Total capital expenditures and acquisitions           167,895     230,880     177,581     1,289,589     579,415
                                     
            Three Months Ended     Year Ended
By country           Dec 31,     Sep 30,     Dec 31,     Dec 31,     Dec 31,
($M)           2014     2014     2013     2014     2013
Canada           87,113     125,276     78,848     750,390     250,386
France           37,189     35,082     31,899     147,852     100,378
Netherlands           10,022     10,087     43,198     61,740     56,043
Germany           563     1,358     -     175,618     -  
Ireland           20,932     30,050     14,472     94,439     90,898
Australia           11,616     15,985     8,420     44,283     77,931
United States           460     11,175     -     11,635     -  
Corporate           -     1,867     744     3,632     3,779
Total capital expenditures and acquisitions           167,895     230,880     177,581     1,289,589     579,415

Supplemental Table 4: Production

      Q4/14   Q3/14   Q2/14   Q1/14   Q4/13   Q3/13   Q2/13   Q1/13   Q4/12   Q3/12   Q2/12   Q1/12
Canada                                                
  Crude oil (bbls/d)   11,384   11,469   12,676   9,437   8,719   7,969   8,885   7,966   7,983   7,322   7,757   7,574
  NGLs (bbls/d)   2,741   2,291   2,796   2,071   1,699   1,897   1,725   1,335   1,106   1,204   1,321   1,302
  Natural gas (mmcf/d)   58.36   57.07   57.59   49.53   41.43   43.40   43.69   41.04   31.41   35.54   41.32   41.83
  Total (boe/d)   23,851   23,272   25,070   19,763   17,322   17,099   17,892   16,140   14,323   14,449   15,965   15,848
  % of consolidated   49%   47%   49%   42%   43%   41%   42%   41%   40%   40%   40%   40%
France                                                
  Crude oil (bbls/d)   11,133   11,111   11,025   10,771   11,131   11,625   10,390   10,330   9,843   9,767   9,931   10,270
  Natural gas (mmcf/d)   -   -   -   -   -   5.23   4.19   4.21   3.91   3.39   3.57   3.48
  Total (boe/d)   11,133   11,111   11,025   10,771   11,131   12,496   11,088   11,032   10,495   10,333   10,526   10,850
  % of consolidated   22%   22%   21%   23%   27%   30%   26%   29%   29%   28%   27%   28%
Netherlands                                                
  NGLs (bbls/d)   81   63   96   69   62   48   50   96   70   41   84   72
  Natural gas (mmcf/d)   31.35   38.07   40.35   43.15   37.53   28.78   38.52   36.91   33.03   34.59   33.74   35.08
  Total (boe/d)   5,306   6,407   6,822   7,260   6,318   4,845   6,470   6,248   5,574   5,806   5,707   5,919
  % of consolidated   11%   13%   13%   16%   15%   12%   15%   16%   15%   16%   15%   15%
Germany                                                
  Natural gas (mmcf/d)   17.71   15.38   16.13   10.64   -   -   -   -   -   -   -   -
  Total (boe/d)   2,952   2,563   2,689   1,773   -   -   -   -   -   -   -   -
  % of consolidated   6%   5%   5%   4%   -   -   -   -   -   -   -   -
Australia                                                
  Crude oil (bbls/d)   6,134   6,567   6,483   7,110   6,189   7,070   7,363   5,287   5,873   5,958   6,970   6,648
  % of consolidated   12%   13%   12%   15%   15%   17%   17%   14%   16%   16%   18%   17%
United States                                                
  Crude oil (bbls/d)   195   -   -   -   -   -   -   -   -   -   -   -
  Total (boe/d)   195   -   -   -   -   -   -   -   -   -   -   -
Consolidated                                                
  Crude oil & NGLs (bbls/d)   31,668   31,501   33,076   29,458   27,800   28,609   28,413   25,014   24,875   24,292   26,063   25,866
  % of consolidated   64%   63%   63%   63%   68%   69%   66%   65%   69%   66%   67%   66%
  Natural gas (mmcf/d)   107.42   110.52   114.08   103.32   78.96   77.41   86.40   82.16   68.34   73.52   78.63   80.39
  % of consolidated   36%   37%   37%   37%   32%   31%   34%   35%   31%   34%   33%   34%
  Total (boe/d)   49,571   49,920   52,089   46,677   40,960   41,510   42,813   38,707   36,265   36,546   39,168   39,265
                                                   
      2014   2013   2012   2011   2010   2009                        
Canada                                                
  Crude oil (bbls/d)   11,248   8,387   7,659   4,701   2,778   2,137                        
  NGLs (bbls/d)   2,476   1,666   1,232   1,297   1,427   1,518                        
  Natural gas (mmcf/d)   55.67   42.39   37.50   43.38   43.91   47.85                        
  Total (boe/d)   23,001   17,117   15,142   13,227   11,524   11,629                        
  % of consolidated   47%   41%   40%   38%   36%   37%                        
France                                                
  Crude oil (bbls/d)   11,011   10,873   9,952   8,110   8,347   8,246                        
  Natural gas (mmcf/d)   -   3.40   3.59   0.95   0.92   1.05                        
  Total (boe/d)   11,011   11,440   10,550   8,269   8,501   8,421                        
  % of consolidated   22%   28%   28%   23%   26%   27%                        
Netherlands                                                
  NGLs (bbls/d)   77   64   67   58   35   23                        
  Natural gas (mmcf/d)   38.20   35.42   34.11   32.88   28.31   21.06                        
  Total (boe/d)   6,443   5,967   5,751   5,538   4,753   3,533                        
  % of consolidated   13%   15%   15%   16%   15%   11%                        
Germany                                                
  Natural gas (mmcf/d)   14.99   -   -   -   -   -                        
  Total (boe/d)   2,498   -   -   -   -   -                        
  % of consolidated   5%   -   -   -   -   -                        
Australia                                                
  Crude oil (bbls/d)   6,571   6,481   6,360   8,168   7,354   7,812                        
  % of consolidated   13%   16%   17%   23%   23%   25%                        
United States                                                
  Crude oil (bbls/d)   49   -   -   -   -   -                        
  Total (boe/d)   49   -   -   -   -   -                        
Consolidated                                                
  Crude oil & NGLs (bbls/d)   31,432   27,471   25,270   22,334   19,941   19,735                        
  % of consolidated   63%   67%   67%   63%   62%   63%                        
  Natural gas (mmcf/d)   108.85   81.21   75.20   77.21   73.14   69.96                        
  % of consolidated   37%   33%   33%   37%   38%   37%                        
  Total (boe/d)   49,573   41,005   37,803   35,202   32,132   31,395

Supplemental Table 5: Segmented Financial Results

    Three Months Ended December 31, 2014
($M)   Canada   France   Netherlands   Germany   Ireland   Australia     United
States
  Corporate   Total
Drilling and development   75,186   36,455   6,183   563   20,932   11,616     460   -   151,395
Exploration and evaluation   10,256   734   3,839   -   -   -     -   19   14,848
Oil and gas sales to external customers   112,494   82,499   25,420   13,359   -   70,971     1,330   -   306,073
Royalties   (15,626)   (6,319)   (1,171)   (2,481)   -   -     (366)   -   (25,963)
Revenue from external customers   96,868   76,180   24,249   10,878   -   70,971     964   -   280,110
Transportation expense   (3,455)   (4,096)   -   (218)   (1,720)   -     -   -   (9,489)
Operating expense   (19,315)   (13,544)   (6,200)   (2,862)   -   (17,719)     (241)   -   (59,881)
General and administration   (2,840)   (3,765)   (2,489)   (2,200)   (579)   (1,628)     (959)   1,224   (13,236)
PRRT   -   -   -   -   -   (13,568)     -   -   (13,568)
Corporate income taxes   -   (6,132)   2,124   1,145   -   (4,799)     -   (642)   (8,304)
Interest expense   -   -   -   -   -   -     -   (12,943)   (12,943)
Realized gain on derivative instruments   -   -   -   -   -   -         22,816   22,816
Realized foreign exchange loss   -   -   -   -   -   -         (179)   (179)
Realized other income   -   -   -   -   -   -         202   202
Fund flows from operations   71,258   48,643   17,684   6,743   (2,299)   33,257     (236)   10,478   185,528
                                       
    Year Ended December 31, 2014
($M)   Canada   France   Netherlands   Germany   Ireland   Australia     United
States
  Corporate   Total
Total assets   1,865,942   874,163   220,100   170,237   822,756   240,614     14,731   177,548   4,386,091
Drilling and development   291,046   136,019   49,695   2,747   94,439   44,283     460   -   618,689
Exploration and evaluation   43,696   11,833   12,045   -   -   -     -   1,461   69,035
Oil and gas sales to external customers   537,788   431,252   123,815   41,962   -   283,481     1,330   -   1,419,628
Royalties   (65,563)   (28,444)   (5,014)   (8,613)   -   -     (366)   -   (108,000)
Revenue from external customers   472,225   402,808   118,801   33,349   -   283,481     964   -   1,311,628
Transportation expense   (14,625)   (18,975)   -     (2,367)   (6,394)   -     -   -   (42,361)
Operating expense   (76,178)   (61,729)   (24,041)   (8,686)   -   (61,432)     (241)   -   (232,307)
General and administration   (16,791)   (20,929)   (3,617)   (4,688)   (1,447)   (5,873)     (959)   (7,423)   (61,727)
PRRT   -   -   -   -   -   (60,340)     -   -   (60,340)
Corporate income taxes   -   (66,901)   (4,154)   (44)   -   (24,477)     -   (1,420)   (96,996)
Interest expense   -   -   -   -   -   -     -   (49,655)   (49,655)
Realized gain on derivative instruments   -   -   -   -   -   -         36,712   36,712
Realized foreign exchange loss   -   -   -   -   -   -         (821)   (821)
Realized other income   -   -   -   -   -   -         732   732
Fund flows from operations   364,631   234,274   86,989   17,564   (7,841)   131,359     (236)   (21,875)   804,865

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 audited consolidated financial statements for the year ended December 31, 2014, we consider fund flows from operations to be an additional GAAP financial measure.

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

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

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

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

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

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

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

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

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

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

          Three Months Ended     Year Ended
          Dec 31,     Sep 30,     Dec 31,     Dec 31,     Dec 31,
($M)         2014     2014     2013     2014     2013
Cash flows from operating activities         229,146     235,010     177,003     791,986     705,025
Changes in non-cash operating working capital         (49,865)     (41,789)     (18,769)     (3,077)     (49,421)
Asset retirement obligations settled         6,247     4,677     5,426     15,956     11,922
Fund flows from operations         185,528     197,898     163,660     804,865     667,526
Expenses related to Corrib         2,299     1,849     839     7,841     5,607
Fund flows from operations (excluding Corrib)         187,827     199,747     164,499     812,706     673,133
                                   
          Three Months Ended     Year Ended
            Dec 31,     Sep 30,     Dec 31,     Dec 31,     Dec 31,
($M)         2014     2014     2013     2014     2013
Dividends declared         69,119     68,896     61,208     272,732     242,599
Issuance of shares pursuant to the dividend reinvestment plan         (20,980)     (20,416)     (18,775)     (79,430)     (72,291)
Net dividends         48,139     48,480     42,433     193,302     170,308
Drilling and development         151,395     180,479     147,929     618,689     537,564
Dispositions         -     -     -     -     (8,627)
Exploration and evaluation         14,848     9,554     549     69,035     13,789
Asset retirement obligations settled         6,247     4,677     5,426     15,956     11,922
Payout         220,629     243,190     196,337     896,982     724,956
Corrib drilling and development         (20,932)     (30,050)     (14,472)     (94,439)     (90,898)
Payout (excluding Corrib)         199,697     213,140     181,865     802,543     634,058
                                   
                      As At
                      Dec 31,     Sep 30,     Dec 31,
('000s of shares)                     2014     2014     2013
Shares outstanding                     107,303     106,921     102,123
Potential shares issuable pursuant to the VIP                     3,031     2,828     2,746
Diluted shares outstanding                     110,334     109,749     104,869

MANAGEMENT'S REPORT TO SHAREHOLDERS

Management's Responsibility for Financial Statements

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

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

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

Management's Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the criteria established in "Internal Control - Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on this evaluation, management has assessed the effectiveness of Vermilion's internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings.  Management concluded that Vermilion's internal control over financial reporting was effective as of December 31, 2014. The effectiveness of Vermilion's internal control over financial reporting as of December 31, 2014 has been audited by Deloitte LLP, the Company's Independent Registered Public Accounting Firm, who also audited the Company's consolidated financial statements for the year ended December 31, 2014.

("Lorenzo Donadeo")                             ("Curtis W. Hicks")
                       
Lorenzo Donadeo                              Curtis W. Hicks
Chief Executive Officer                             Executive Vice President & Chief Financial Officer
February 27, 2015

Report of Independent Registered Public Accounting Firm

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

We have audited the internal control over financial reporting of Vermilion Energy Inc. and subsidiaries (the "Company") as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting.  Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013)  issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and our report dated February 27, 2015 expressed an unqualified opinion on those financial statements.

("Deloitte LLP")

Chartered Accountants
February 27, 2015
Calgary, Canada

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying consolidated financial statements of Vermilion Energy Inc. and subsidiaries (the "Company"), which comprise the consolidated balance sheets as at December 31, 2014 and 2013, and the consolidated statements of net earnings and comprehensive income, consolidated statements of changes in shareholders' equity and consolidated statements of cash flows for the years then ended, and a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

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

Auditor's Responsibility

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

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

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

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2014 and 2013, and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matter

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2015 expressed an unqualified opinion on the Company's internal control over financial reporting.

("Deloitte LLP")

Chartered Accountants
February 27, 2015
Calgary, Canada

CONSOLIDATED BALANCE SHEETS                                
(THOUSANDS OF CANADIAN DOLLARS)                                
                                 
                          December 31,     December 31,
                  Note       2014     2013
ASSETS                                
Current                                
Cash and cash equivalents                 17       120,405     389,559
Accounts receivable                         171,820     167,618
Crude oil inventory                         9,510     17,143
Derivative instruments                 13       23,391     2,285
Prepaid expenses                         13,033     11,178
                          338,159     587,783
                                 
Derivative instruments                 13       1,403     -
Deferred taxes                 9       154,816     184,832
Exploration and evaluation assets                 6       380,621     136,259
Capital assets                 5       3,511,092     2,799,845
                          4,386,091     3,708,719
                                 
LIABILITIES                                
Current                                
Accounts payable and accrued liabilities                         298,196     267,832
Dividends payable                 10       23,070     20,425
Derivative instruments                 13       -     3,572
Income taxes payable                 9       44,463     55,615
                          365,729     347,444
                                 
Long-term debt                 8       1,238,080     990,024
Asset retirement obligations                 7       350,753     326,162
Deferred taxes                 9       410,183     328,714
                          2,364,745     1,992,344
                                 
SHAREHOLDERS' EQUITY                                
Shareholders' capital                 10       1,959,021     1,618,443
Contributed surplus                         92,188     75,427
Accumulated other comprehensive income                         5,722     47,142
Deficit                         (35,585)     (24,637)
                          2,021,346     1,716,375
                          4,386,091     3,708,719

APPROVED BY THE BOARD

                       
(Signed "Joseph F. Killi")                           (Signed "Lorenzo Donadeo")
                       
Joseph F. Killi, Director                            Lorenzo Donadeo, Director
                       

CONSOLIDATED STATEMENTS OF NET EARNINGS AND COMPREHENSIVE INCOME
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS)
                           
                    Year Ended
                    December 31,     December 31,
            Note       2014     2013
REVENUE                          
Petroleum and natural gas sales                   1,419,628     1,273,835
Royalties                   (108,000)     (67,936)
Petroleum and natural gas revenue                   1,311,628     1,205,899
                           
EXPENSES                          
Operating           21       232,307     195,043
Transportation                   42,361     28,924
Equity based compensation           11       67,802     60,845
(Gain) loss on derivative instruments           13       (64,083)     1,971
Interest expense                   49,655     38,183
General and administration           21       61,727     49,910
Foreign exchange loss (gain)                   18,420     (50,162)
Other expense                   760     457
Accretion           7       23,913     24,565
Depletion and depreciation           5, 6       425,694     322,386
Impairment (recovery)           5       -     (47,400)
                    858,556     624,722
EARNINGS BEFORE INCOME TAXES                   453,072     581,177
                           
INCOME TAXES           9              
Deferred                   26,410     35,177
Current                   157,336     218,359
                    183,746     253,536
                           
NET EARNINGS                   269,326     327,641
                           
OTHER COMPREHENSIVE (LOSS) INCOME                          
Currency translation adjustments                   (41,420)     79,551
COMPREHENSIVE INCOME                   227,906     407,192
                           
NET EARNINGS PER SHARE           12              
Basic                       2.55     3.24
Diluted                   2.51     3.20
                           
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)           12              
Basic                   105,448     100,969
Diluted                   107,187     102,467
                           

CONSOLIDATED STATEMENTS OF CASH FLOWS                      
(THOUSANDS OF CANADIAN DOLLARS)                      
                       
                Year Ended
                December 31,     December 31,
        Note       2014     2013
OPERATING                      
Net earnings               269,326     327,641
Adjustments:                      
  Accretion       7       23,913     24,565
  Depletion and depreciation       5, 6       425,694     322,386
  Impairment (recovery)       5       -     (47,400)
  Unrealized gain on derivative instruments       13       (27,371)     (5,111)
  Equity based compensation       11       67,802     60,845
  Unrealized foreign exchange loss (gain)               17,599     (52,028)
  Unrealized other expense               1,492     1,451
  Deferred taxes       9       26,410     35,177
Asset retirement obligations settled       7       (15,956)     (11,922)
Changes in non-cash operating working capital       14       3,077     49,421
Cash flows from operating activities               791,986     705,025
                       
INVESTING                      
Drilling and development       5       (618,689)     (537,564)
Exploration and evaluation       6       (69,035)     (13,789)
Property acquisitions       4, 5, 6       (220,726)     (9,189)
Dispositions       5       -     8,627
Corporate acquisitions, net of cash acquired       4       (176,179)     (24,124)
Changes in non-cash investing working capital       14       12,365     (41,691)
Cash flows used in investing activities               (1,072,264)     (617,730)
                       
FINANCING                      
Increase in long-term debt       8       196,387     347,284
Cash dividends       10       (190,657)     (168,719)
Cash flows from financing activities               5,730     178,565
Foreign exchange gain on cash held in foreign currencies               5,394     21,574
                       
Net change in cash and cash equivalents               (269,154)     287,434
Cash and cash equivalents, beginning of year               389,559     102,125
Cash and cash equivalents, end of year       17       120,405     389,559
                       
Supplementary information for operating activities - cash payments                      
  Interest paid               50,801     37,562
  Income taxes paid               166,993     192,865
                         

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

            Accumulated      
              Other   Total
    Shareholders' Contributed Comprehensive   Shareholders'
  Note Capital Surplus   Income Deficit Equity
Balances as at January 1, 2013     1,481,345   69,581   (32,409)   (99,871)   1,418,646
Net earnings     -   -   -   327,641   327,641
Currency translation adjustments     -   -   79,551   -   79,551
Equity based compensation expense 11   -   60,216   -   -   60,216
Dividends declared 10   -   -   -   (242,599)   (242,599)
Shares issued pursuant to the                      
   dividend reinvestment plan 10   72,291   -   -   -   72,291
Vesting of equity based awards 10, 11   54,370   (54,370)   -   -   -  
Share-settled dividends                      
   on vested equity based awards 10, 11   9,808   -   -   (9,808)   -  
Shares issued pursuant to the bonus plan 10   629   -   -   -   629
Balances as at December 31, 2013     1,618,443   75,427   47,142   (24,637)   1,716,375
                       
            Accumulated      
            Other   Total
  Shareholders' Contributed Comprehensive   Shareholders'
Note Capital Surplus   Income Deficit Equity
Balances as at January 1, 2014     1,618,443   75,427   47,142   (24,637)   1,716,375
Net earnings     -   -   -   269,326   269,326
Currency translation adjustments     -   -   (41,420)   -   (41,420)
Equity based compensation expense 11   -   67,081   -   -   67,081
Dividends declared 10   -   -   -   (272,732)   (272,732)
Shares issued pursuant to the                      
   dividend reinvestment plan 10   79,430   -   -   -   79,430
Shares issued pursuant to                      
   corporate acquisition 4, 10   204,960   -   -   -   204,960
Modification of equity based awards 11   -   (2,395)           (2,395)
Vesting of equity based awards 10, 11   47,925   (47,925)   -   -   -  
Share-settled dividends                      
   on vested equity based awards 10, 11   7,542   -   -   (7,542)   -  
Shares issued pursuant to the bonus plan 10   721   -   -   -   721
Balances as at December 31, 2014     1,959,021   92,188   5,722   (35,585)   2,021,346
                       

DESCRIPTION OF EQUITY RESERVES

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

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

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

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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2014 AND 2013
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS)

1. BASIS OF PRESENTATION

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

These consolidated financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on February 27, 2015.

2. SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Assessment of Impairments or Recovery of Previous Impairments
Impairment tests are performed at a CGU level.  CGUs are determined based on management's judgment of the lowest level at which there is identifiable cash inflows that are largely independent of the cash inflows of other groups of assets or properties.  The factors used by Vermilion to determine CGUs may vary by country due to the unique operating and geographic circumstances in each country.  However, in general, Vermilion will assess the following factors in determining whether a group of assets generate largely independent cash inflows: geographic proximity of the assets within a group to one another, geographic proximity of the group of assets to other groups of assets, homogeneity of the production from the group of assets and the sharing of infrastructure used to process and/or transport production.

The calculation of the recoverable amount of the CGUs is based on market factors, estimates of PNG reserves and future costs required to develop reserves.  Vermilion's reserve estimates and the related future cash flows are subject to measurement uncertainty, and the impact on the consolidated financial statements of future periods could be material.  Considerable management judgment is used in determining the recoverable amount of PNG assets, including determining the quantity of reserves, the time horizon to develop and produce such reserves and the estimated revenues and expenditures of such production.

Income Taxes
Tax interpretations, regulations, and legislation in the various jurisdictions in which Vermilion and its subsidiaries operate are subject to change and interpretation.  Such changes can affect the timing of the reversal of temporary tax differences, the tax rates in effect when such differences reverse and Vermilion's ability to use tax losses and other tax pools in the future.  The Company's income tax filings are subject to audit by taxation authorities in numerous jurisdictions and the results of such audits may increase or decrease our tax liability.  The determination of current and deferred tax amounts recognized in the consolidated financial statements are based on management's assessment of the tax positions, which includes consideration of their technical merits, communications with tax authorities and management's view of the most likely outcome.

3. CHANGES TO ACCOUNTING PRONOUNCEMENTS

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

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

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

Accounting pronouncements not yet adopted

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

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

IFRS 15 "Revenue from Contracts with Customers"
On May 28, 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers", a new standard that specifies recognition requirements for revenue as well as requiring entities to provide the users of financial statements with more informative and relevant disclosures.  The standard replaces IAS 11 "Construction Contracts" and IAS 18 "Revenue" as well as a number of revenue-related interpretations.  Vermilion will adopt the standard for reporting periods beginning January 1, 2017.

4. BUSINESS COMBINATIONS

Property acquisition:

Germany

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

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

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

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

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

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

Corporate acquisitions:

a)  Elkhorn Resources Inc.

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

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

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

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

($M) Consideration
Cash paid to shareholders of Elkhorn Resources Inc.   180,353
Shares issued pursuant to corporate acquisition   204,960
Total consideration   385,313
     
($M)    Allocation of Consideration
Petroleum and natural gas assets   390,523
Exploration and evaluation   138,264
Asset retirement obligations assumed   (5,974)
Deferred tax liabilities   (89,437)
Long-term debt assumed   (47,526)
Cash acquired   4,174
Acquired non-cash working capital deficiency   (4,711)
Net assets acquired   385,313
     

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

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

b) Netherlands

On October 10, 2013, Vermilion acquired, through its wholly-owned subsidiary, 100% of the shares of Northern Petroleum Nederland B.V., a subsidiary of UK-based Northern Petroleum Plc. ("Northern") for total consideration of $27.5 million.  The acquisition represented a complementary addition to the existing Netherlands asset base, including interests in six onshore licences in production or development, three onshore exploration licenses, and one offshore production license in the NetherlandsVermilion funded this acquisition from cash on hand.

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

($M) Consideration
Cash paid to vendor   27,500
Total consideration   27,500
     
($M)     Allocation of Consideration
Petroleum and natural gas assets   47,743
Asset retirement obligations assumed   (12,439)
Deferred tax liabilities   (10,412)
Cash acquired   3,376
Acquired non-cash working capital   (768)
Net assets acquired   27,500
     

The results of operations from the assets acquired have been included in Vermilion's consolidated financial statements beginning October 10, 2013 and have contributed revenues of $2.7 million and operating income of $1.0 million for the year ended December 31, 2013.

Had the acquisition occurred on January 1, 2013, management estimates that consolidated revenues would have increased by an additional $13.5 million and consolidated operating income would have increased by $6.3 million for the year ended December 31, 2013.  In determining the pro-forma amounts, management has assumed that the fair value adjustments, determined provisionally, that arose at the date of acquisition would have been the same if the acquisition had occurred on January 1, 2013.  It is impracticable to derive all amounts necessary to determine the impact on net earnings from the acquired working interests as operations were immediately merged with Vermilion's operations.

5. CAPITAL ASSETS

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

    Petroleum and   Furniture and   Total
($M)   Natural Gas Assets   Office Equipment   Capital Assets
Balance at January 1, 2013   2,430,121   15,119   2,445,240
Additions   531,760   5,804   537,564
Transfers from exploration and evaluation assets   1,508   -   1,508
Corporate acquisitions   47,743   -   47,743
Dispositions   (8,627)   -   (8,627)
Changes in estimate for asset retirement obligations   (91,527)   -   (91,527)
Depletion and depreciation   (310,370)   (6,138)   (316,508)
Impairment recovery   47,400   -   47,400
Effect of movements in foreign exchange rates   136,626   426   137,052
Balance at December 31, 2013   2,784,634   15,211   2,799,845
Additions   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
               
Cost   3,938,986   43,932   3,982,918
Accumulated depletion and depreciation   (1,154,352)   (28,721)   (1,183,073)
Carrying amount at December 31, 2013   2,784,634   15,211   2,799,845
               
Cost   5,114,188   54,723   5,168,911
Accumulated depletion and depreciation   (1,622,993)   (34,826)   (1,657,819)
Carrying amount at December 31, 2014   3,491,195   19,897   3,511,092
             

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

Capitalized overhead
During the year ended December 31, 2014, Vermilion capitalized $7.7 million (2013 - $8.5 million) of overhead costs directly attributable to PNG activities.

Impairments and recovery of previous impairments
On a quarterly basis, Vermilion performs an assessment as to whether any CGUs have indicators of impairment or recovery of previous impairments.  When indicators of impairment or recovery of previous impairments are identified, Vermilion assesses the recoverable amount of the applicable CGU based on the estimated fair value less costs to sell as at the reporting date.  The estimated fair value takes into account the most recent commodity price forecasts, expected production and estimated costs of development.

In the fourth quarter of 2013, Vermilion identified indicators of impairment recovery for a Canadian CGU where impairment charges were previously recorded for the three months ended December 31, 2011 and March 31, 2012.  The impairment recovery resulted from increased proved and probable reserves of natural gas and NGLs, due primarily to the successful application of horizontal drilling and multi-stage fracturing technology to the previously impaired cash generating unit.

Benchmark prices used in the calculations of recoverable amounts were determined by multiplying the mix of oil, natural gas and NGLs inherent in the reserves of the conventional deep natural gas and shallow coal bed methane CGUs by the price forecasts for each year.  The blended price per barrel of oil equivalent (BOE) forecasts were:

$/BOE       December 31, 2013
2014       42.09
2015       44.18
2016       45.39
2017       45.41
2018       45.43
2019       45.50
2020         45.86
2021        46.78
Average increase thereafter       2.0%
         

6. EXPLORATION AND EVALUATION ASSETS

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

($M)   Exploration and Evaluation Assets
Balance at January 1, 2013   117,161
Additions   13,789
Property acquisitions   9,189
Transfers to petroleum and natural gas assets   (1,508)
Depreciation   (3,712)
Effect of movements in foreign exchange rates   1,340
Balance at December 31, 2013   136,259
Additions   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
         
Cost   149,175
Accumulated depreciation   (12,916)
Carrying amount at December 31, 2013   136,259
         
Cost   399,348
Accumulated depreciation   (18,727)
Carrying amount at December 31, 2014   380,621
     
     

7. ASSET RETIREMENT OBLIGATIONS

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

($M)     Asset Retirement Obligations  
Balance at January 1, 2013     371,063  
Additional obligations recognized     15,655  
Changes in estimates for asset retirement obligations     (21,068)  
Obligations settled     (11,922)  
Accretion     24,565  
Changes in discount rates     (73,675)  
Effect of movements in foreign exchange rates     21,544  
Balance at December 31, 2013     326,162  
Additional obligations recognized     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  
         

Vermilion has estimated the net present value of its asset retirement obligations to be $350.8 million as at December 31, 2014 (2013 - $326.2 million) based on a total undiscounted future liability, after inflation adjustment, of $1.3 billion (2013 - $1.3 billion).  These payments are expected to be made between 2014 and 2064.  Vermilion calculated the present value of the obligations using discount rates between 5.7% and 7.9% (2013 - between 6.4% and 8.3%) to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates.  Inflation rates used in determining the cash flow estimates were between 0.8% and 2.4% (2013 - between 1.1% and 2.5%).

Vermilion reviews annually its estimates of the expected costs to reclaim the net interest in its wells and facilities.  The resulting changes are categorized as changes in estimates for existing obligations in the preceding table. The increase in the liability for the year ended December 31, 2014 primarily resulted from an overall decrease in the discount rates applied to the abandonment obligations, accretion, and additions from new wells drilled during the year and abandonment obligations associated with the assets acquired in Germany and Canada.

8. LONG-TERM DEBT

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

  As At
($M)   Dec 31, 2014         Dec 31, 2013
Revolving credit facility   1,014,067         766,898
Senior unsecured notes   224,013         223,126
Long-term debt   1,238,080         990,024
               

Revolving Credit Facility

At December 31, 2014, Vermilion had in place a bank revolving credit facility totalling $1.5 billion, of which approximately $1.01 billion was drawn.  In addition, Vermilion may, by adding lenders or seeking an increase to an existing lender's commitment, increase the total committed facility amount to no more than $1.75 billion.  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 year ended December 31, 2014, the interest rate on the revolving credit facility was approximately 3.1% (2013 - 3.3%).

The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $8.6 million as at December 31, 2014 (December 31, 2013 - $8.1 million).

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

  • A ratio of total bank borrowings (defined as consolidated total debt), to consolidated net earnings before interest, income taxes, depreciation, accretion and other certain non-cash items (defined as consolidated EBITDA) of not greater than 4.0.
  • 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" and "Shareholders' Equity" on the balance sheet) of less than 50%.

As at December 31, 2014, Vermilion was in compliance with all financial covenants.

On January 30, 2015, Vermilion exercised its option to increase its credit facility to $1.75 billion.

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.

Subsequent to February 10, 2015, 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%.

9. INCOME TAXES

Deferred taxes

The net deferred income tax liability at December 31, 2014 and 2013 is comprised of the following:

      Year Ended
($M)   Dec 31, 2014   Dec 31, 2013
Deferred income tax liabilities:        
  Derivative contracts   (5,965)   -  
  Capital assets   (445,457)   (332,740)
  Asset retirement obligations   (96,616)   (87,888)
  Basis difference of investments   (39)   (189)
  Unrealized foreign exchange   (14,468)   (13,017)
  Other   (13,164)   (12,383)
Deferred income tax assets:        
  Derivative contracts   -     323
  Capital assets   72,821   75,352
  Non-capital losses   178,222   170,625
  Asset retirement obligations   65,760   54,037
  Unrealized foreign exchange   720   -  
  Other   2,819   1,998
Net deferred income tax liability   (255,367)   (143,882)
Comprised of:        
  Deferred income tax assets   154,816   184,832
  Deferred income tax liability   (410,183)   (328,714)
Net deferred income tax liability   (255,367)   (143,882)
         

Income tax expense differs from the amount that would have been expected if the reported earnings had been subject only to the statutory Canadian income tax rate of 25.5% (2013 - 25.0%), as follows:

    Year Ended
($M)   Dec 31, 2014   Dec 31, 2013
Earnings before income taxes   453,072   581,177
Canadian corporate tax rate   25.5%   25.0%
Expected tax expense   115,533   145,294
Increase (decrease) in taxes resulting from:        
  Petroleum resource rent tax rate (PRRT) differential (1)   37,035   50,585
  Foreign tax rate differentials (1), (2)   3,492   1,875
  Equity based compensation expense   17,290   15,211
  Amended returns and changes to estimated tax pools and tax positions   (7,512)   38,197
  Changes in statutory tax rates and the estimated reversal rates associated with temporary differences   16,429   5,299
  Other non-deductible items   1,479   (2,925)
Provision for income taxes   183,746   253,536
     
(1) In Australia, current taxes included both corporate income tax rates and PRRT. Corporate income tax rates were applied at a rate of 30% and PRRT was applied at a rate of 40%.
(2)  The combined tax rate was 34.4% in France, 46.0% in the Netherlands, 22.8% in Germany and 25% in Ireland.
   

10. SHAREHOLDERS' CAPITAL

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

Shareholders' Capital       Number of Shares ('000s)       Amount ($M)
Balance as at January 1, 2013       99,135       1,481,345
Shares issued pursuant to the dividend reinvestment plan       1,402       72,291
Vesting of equity based awards       1,372       54,370
Share-settled dividends on vested equity based awards       202       9,808
Shares issued pursuant to the bonus plan       12       629
Balance as at December 31, 2013       102,123       1,618,443
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
                 

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

Dividends

Dividends declared to shareholders for the year ended December 31, 2014 were $272.7 million (2013 - $242.6 million).  Dividends are approved by the Board of Directors and are paid monthly.  Vermilion has a dividend reinvestment plan which allows eligible holders of common shares to purchase additional common shares at a 3% discount to market by reinvesting their cash dividends.  Subsequent to the end of the period and prior to the consolidated financial statements being authorized for issue on February 27, 2015, Vermilion declared dividends totalling $46.2 million or $0.215 per share for each of January and February of 2015.

11. EQUITY BASED COMPENSATION

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

Number of Awards ('000s)       2014       2013
Opening balance       1,665       1,690
Granted       707       832
Vested       (515)       (749)
Modified       (21)       -
Forfeited       (61)       (108)
Closing balance       1,775       1,665
                 

The fair value of a VIP award is determined on the grant date at the closing price of Vermilion's common shares on the Toronto Stock Exchange, adjusted by the estimated performance factor that will ultimately be achieved.  Dividends, which notionally accrue to the awards during the vesting period, are not included in the determination of grant date fair values.  For the year ended December 31, 2014, the awards granted had a weighted average fair value of $101.63 (2013 - $80.79).

The performance factor is determined by the Board of Directors after consideration of a number of key corporate performance measures including, but not limited to, shareholder return, capital efficiency metrics, production and reserves growth and health, safety and environment performance.

The expense recognized is based on the grant date fair value of the awards and incorporates an estimate of forfeiture rate based on historical vesting data.  For the year ended December 31, 2014, Vermilion incorporated an estimated forfeiture rate of 5.8% (2013 - 6.6%).  Equity based compensation expense of $67.1 million was recorded during the year ended December 31, 2014 (2013 - $60.2 million) related to the VIP.

12. PER SHARE AMOUNTS

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

        Year Ended
($M except per share amounts)     Dec 31, 2014   Dec 31, 2013
Net earnings [1]     269,326   327,641
Basic weighted average shares outstanding [2]     105,448   100,969
Dilutive impact of equity based awards     1,739   1,498
Diluted weighted average shares outstanding [3]     107,187   102,467
Basic earnings per share ([1] ÷ [2])     2.55   3.24
Diluted earnings per share ([1] ÷ [3])     2.51   3.20
           

13. DERIVATIVE INSTRUMENTS

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

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

The following tables summarize Vermilion's outstanding risk management positions as at December 31, 2014:

        Note       Volume       Strike Price(s)
Crude Oil                        
WTI - Collar                        
January 2015 - March 2015               500 bbl/d       76.25 - 92.15 US $
January 2015 - June 2015       1       250 bbl/d       75.00 - 82.75 US $
Dated Brent - Collar                        
January 2015 - March 2015               500 bbl/d       78.75 - 89.63 US $
Dated Brent - Swap                        
January 2015       2       500 bbl/d       101.55 US $
January 2015 - March 2015       3       250 bbl/d       91.95 US $
February 2015       4       500 bbl/d       103.80 US $
March 2015       5       250 bbl/d       110.40 US $
MSW - Fixed Price Differential (Physical)                        
November 2014 - March 2015               1,042 bbl/d       WTI less 6.85 US $
January 2015 - March 2015               2,098 bbl/d       WTI less 7.39 US $
LSB - Fixed Price Differential (Physical)                        
October 2014 - March 2015               830 bbl/d       WTI less 10.00 US $
January 2015 - March 2015               524 bbl/d       WTI less 8.60 US $
                         
North American Natural Gas                        
AECO - Collar                        
April 2014 - March 2015               2,500 GJ/d       3.60 - 4.08 CAD $
November 2014 - March 2015               2,500 GJ/d       3.60 - 4.27 CAD $
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 Basis - Fixed Price Differential                        
January 2015 - December 2015               5,000 mmbtu/d       Nymex HH less 0.68 US $
Nymex HH - Collar                        
November 2014 - March 2015               10,000 mmbtu/d       3.50 - 5.00 US $
January 2015 - March 2015               10,000 mmbtu/d       3.70 - 5.10 US $
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 $
Nymex HH - Swap                        
January 2015               2,500 mmbtu/d       4.53 US $
January 2015 - March 2015               5,000 mmbtu/d       4.38 US $
                         
European Natural Gas                        
TTF - Collar                        
January 2015 - December 2015               2,592 GJ/d       6.11 - 6.83 EUR €
TTF - Swap                        
January 2015 - March 2015               4,392 GJ/d       6.47 EUR €
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               2,592 GJ/d       6.46 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 €

(1) The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price.
(2)  On March 31, 2015, the counterparty has the option to extend the swap for the period of April to June 2015 for 1,000 boe/d at the contracted price.
(3)  On March 31, 2015, the counterparty has the option to extend the swap for the period of April to June 2015 for 500 boe/d at the contracted price.
(4)  On June 30, 2015, the counterparty has the option to extend the swap for the period of July to September 2015 for 1,000 boe/d at the contracted price.
(5)  On September 30, 2015, the counterparty has the option to extend the swap for the period of October to December 2015 for 500 boe/d at the contracted price.
   

      Note       Volume       Strike Price(s)
Electricity                      
AESO - Swap (Physical)                      
January 2013 - December 2015             72.0 MWh/d       53.17 CAD $
                       
US Dollar                      
USD - Collar                      
January 2015 - March 2015             7,000,000 US $/month       1.140 - 1.184 CAD $
January 2015 - March 2015     1       15,500,000 US $/month       1.140 - 1.157 CAD $
(1)  Vermilion has upside participation on this hedge up to the limit price of 1.222 CAD; above which, settlement will occur at the conditional call level of 1.157 CAD.

The following table reconciles the change in the fair value of Vermilion's derivative instruments:        
           
      Year ended
($M) Dec 31, 2014   Dec 31, 2013
Fair value of contracts, beginning of year   (1,287)   (6,398)
Reversal of opening contracts settled during the year   1,287   6,398
Acquired Derivative Contracts   (1,290)   -  
Realized gain (loss) on contracts settled during the year   36,712   (7,082)
Unrealized gain (loss) during the year on contracts outstanding at the end of the year   26,084   (1,287)
Net payment to counterparties on contract settlements during the year   (36,712)   7,082
Fair value of contracts, end of year   24,794   (1,287)
Comprised of:        
  Current derivative asset   23,391   2,285
  Current derivative liability   -     (3,572)
  Non-current derivative asset   1,403   -  
Fair value of contracts, end of year   24,794   (1,287)

The (gain) loss on derivative instruments for 2014 and 2013 are comprised of the following:

      Year Ended
($M)   Dec 31, 2014   Dec 31, 2013
Realized (gain) loss on contracts settled during the year   (36,712)   7,082
Reversal of opening contracts settled during the year   (1,287)   (6,398)
Unrealized (gain) loss during the year on contracts outstanding at the end of the year   (26,084)   1,287
(Gain) loss on derivative instruments   (64,083)   1,971
         

14. SUPPLEMENTAL CASH FLOW INFORMATION

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

  Year Ended
($M) Dec 31, 2014   Dec 31, 2013
Changes in:      
  Accounts receivable (4,202)   12,446
  Crude oil inventory 7,633   8,576
  Prepaid expenses 1,400   (840)
  Accounts payable and accrued liabilities and income taxes payable 19,212   (4,944)
  Movements in foreign exchange rates (8,601)   (7,508)
Changes in non-cash working capital 15,442   7,730
Changes in non-cash operating working capital 3,077   49,421
Changes in non-cash investing working capital 12,365   (41,691)
Changes in non-cash working capital 15,442   7,730
       
       

15. SEGMENTED INFORMATION

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

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

  Year Ended December 31, 2014
($M) Canada   France   Netherlands   Germany   Ireland   Australia   United
States
  Corporate   Total
Total assets 1,865,942   874,163   220,100   170,237   822,756   240,614   14,731   177,548   4,386,091
Drilling and development 291,046   136,019   49,695   2,747   94,439   44,283   460   -     618,689
Exploration and evaluation 43,696   11,833   12,045   -     -     -     -     1,461   69,035
Oil and gas sales to external customers 537,788   431,252   123,815   41,962   -     283,481   1,330   -     1,419,628
Royalties (65,563)   (28,444)   (5,014)   (8,613)   -     -     (366)   -     (108,000)
Revenue from external customers 472,225   402,808   118,801   33,349   -     283,481   964   -     1,311,628
Transportation expense (14,625)   (18,975)   -     (2,367)   (6,394)   -     -     -     (42,361)
Operating expense (76,178)   (61,729)   (24,041)   (8,686)   -     (61,432)   (241)   -     (232,307)
General and administration (16,791)   (20,929)   (3,617)   (4,688)   (1,447)   (5,873)   (959)   (7,423)   (61,727)
PRRT -     -     -     -     -     (60,340)   -     -     (60,340)
Corporate income taxes -     (66,901)   (4,154)   (44)   -     (24,477)   -     (1,420)   (96,996)
Interest expense -     -     -     -     -     -     -     (49,655)   (49,655)
Realized gain on derivative instruments -     -     -     -     -     -         36,712   36,712
Realized foreign exchange loss -     -     -     -     -     -         (821)   (821)
Realized other income -     -     -     -     -     -         732   732
Fund flows from operations 364,631   234,274   86,989   17,564   (7,841)   131,359   (236)   (21,875)   804,865
                                   
  Year Ended December 31, 2013
($M) Canada   France   Netherlands   Germany   Ireland   Australia   United
States
  Corporate   Total
Total assets 1,212,056   901,582   228,869   -     747,882   322,773   -     295,557   3,708,719
Drilling and development 232,858   96,479   28,543   -     90,898   77,931   -     2,228   528,937
Exploration and evaluation 8,339   3,899   -     -     -     -     -     1,551   13,789
Oil and gas sales to external customers 382,005   453,315   139,570   -     -     298,945   -     -     1,273,835
Royalties (40,891)   (27,045)   -     -     -     -     -     -     (67,936)
Revenue from external customers 341,114   426,270   139,570   -     -     298,945   -     -     1,205,899
Transportation expense (12,254)   (12,505)   -     -     (4,165)   -     -     -     (28,924)
Operating expense (55,804)   (66,997)   (20,617)   -     -     (51,625)   -     -     (195,043)
General and administration (12,979)   (19,657)   (2,724)   -     (1,442)   (5,752)   -     (7,356)   (49,910)
PRRT -     -     -     -     -     (56,565)   -     -     (56,565)
Corporate income taxes -     (94,524)   (34,132)   -     -     (31,735)   -     (1,403)   (161,794)
Interest expense -     -     -     -     -     -     -     (38,183)   (38,183)
Realized loss on derivative instruments -     -     -     -     -     -     -     (7,082)   (7,082)
Realized foreign exchange loss -     -     -     -     -     -     -     (1,866)   (1,866)
Realized other income -     -     -     -     -     -     -     994   994
Fund flows from operations 260,077   232,587   82,097   -     (5,607)   153,268   -     (54,896)   667,526
                                   

Reconciliation of fund flows from operations to net earnings

  Year Ended
  Dec 31, Dec 31,
($M) 2014 2013
Fund flows from operations 804,865 667,526
Equity based compensation   (67,802) (60,845)
Unrealized gain on derivative instruments 27,371 5,111
Unrealized foreign exchange (loss) gain (17,599) 52,028
Unrealized other expense (1,492) (1,451)
Accretion (23,913) (24,565)
Depletion and depreciation (425,694) (322,386)
Deferred taxes (26,410) (35,177)
Impairment (recovery) -   47,400
Net earnings 269,326 327,641

Vermilion has two major customers with revenues in excess of 10% within the France and Netherlands segments. All sales in the France and Netherlands segments for the years ended December 31, 2014 and 2013 were to one customer in each respective segment.

16. COMMITMENTS

Vermilion had the following future commitments associated with its operating leases as at December 31, 2014:

($M) Less than 1 year 1 - 3 years 4 - 5 years After 5 years Total
Payments by period 21,589 28,158 23,789 58,701 132,237

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

17. CASH AND CASH EQUIVALENTS

Cash and cash equivalents was comprised of the following:

($M) Dec 31, 2014 Dec 31, 2013
Money on deposit with financial institutions   116,643   379,936
Short-term investments   3,762   9,623
Cash and cash equivalents   120,405   389,559

18. CAPITAL DISCLOSURES

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

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

Additionally, Vermilion monitors the ratio of net debt  to fund flows from operations.  Vermilion typically strives to maintain an internally targeted ratio of net debt to fund flows from operations of 1.0 to 1.3 in a normalized commodity price environment. Where prices trend higher, Vermilion may target a lower ratio and conversely, in a lower commodity price environment, the acceptable ratio may be higher.  At times, Vermilion will use its balance sheet to finance acquisitions and, in these situations, Vermilion is prepared to accept a higher ratio in the short term but will implement a plan to reduce the ratio to acceptable levels within a reasonable period of time, usually considered to be no more than 12 to 18 months.  This plan could potentially include an increase in hedging activities, a reduction in capital expenditures, an issuance of equity or the utilization of excess fund flows from operations to reduce outstanding indebtedness.

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

  Year Ended
($M except as indicated) December 31, 2014 December 31, 2013
Long-term debt 1,238,080 990,024
Current liabilities 365,729 347,444
Current assets (338,159) (587,783)
Net debt [1] 1,265,650 749,685
Cash flows from operating activities 791,986 705,025
Changes in non-cash operating working capital (3,077) (49,421)
Asset retirement obligations settled 15,956 11,922
Fund flows from operations [2] 804,865 667,526
Ratio of net debt to fund flows from operations ([1] ÷ [2]) 1.6 1.1

Long-term debt as at December 31, 2014 increased to $1.2 billion from $990.0 million as at December 31, 2013 as a result of draws on the revolving credit facility during the current year to fund the acquisitions in Germany and Saskatchewan coupled with the assumption of $47.5 million of long-term debt pursuant to the Elkhorn acquisition.  This increase in long-term debt resulted in an increase to net debt from $749.7 million to $1.3 billion.

As year-to-date fund flows does not include a full year of fund flows from the acquisitions in Germany and Saskatchewan, the ratio of net debt to fund flows increased to 1.6.

19. FINANCIAL INSTRUMENTS

Classification of Financial Instruments

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

              As at Dec 31, 2014     As at Dec 31, 2013      
Class of financial instrument Consolidated balance sheet caption Accounting designation Related caption on Statement of Net
Earnings
    Carrying value ($M) Fair value ($M)     Carrying value ($M)   Fair value ($M)     Fair value measurement hierarchy
Cash Cash and cash equivalents HFT Gains and losses on foreign exchange are included in foreign exchange loss (gain)     120,405   120,405     389,559   389,559     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     171,820   171,820     167,618   167,618     Not applicable
Derivative assets Derivative instruments HFT (Gain) loss on derivative instruments     24,794   24,794     2,285   2,285     Level 2
Derivative liabilities Derivative instruments HFT (Gain) loss on derivative instruments     -     -       (3,572)   (3,572)     Level 2
Payables Accounts payable and accrued liabilities OTH Gains and losses on foreign exchange are included in foreign exchange loss (gain)     (321,266)   (321,266)     (288,257)   (288,257)     Not applicable
                                 
    Dividends payable                              
Long-term debt Long-term debt OTH Interest expense     (1,238,080)   (1,238,505)     (990,024)   (998,648)     Level 2

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

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

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

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

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

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

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

Determination of Fair Values

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

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

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

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

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

Nature and Extent of Risks Arising from Financial Instruments

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

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

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

Currency risk:
Vermilion conducts business in foreign currencies in addition to Canadian dollars and accordingly is subject to currency risk associated with changes in foreign exchange rates in relation to cash and cash equivalents, receivables, payables and derivative assets and liabilities.  The impact related to working capital is somewhat mitigated as a result of the offsetting effects of foreign exchange fluctuations on assets and liabilities.  Vermilion monitors its exposure to currency risk and reviews whether the use of derivative financial instruments is appropriate to manage potential fluctuations in foreign exchange rates.  During the period covered by these consolidated financial statements, Vermilion did not use derivative financial instruments to manage potential fluctuations in foreign exchange rates.

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

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

The nature of these risks and Vermilion's strategy for managing these risks has not changed significantly from the prior period.

Summarized Quantitative Data Associated with the Risks Arising from Financial Instruments

Credit risk:
As at December 31, 2014, Vermilion's maximum exposure to receivable credit risk was $196.6 million (December 31, 2013 - $169.9 million) which is the aggregate value of receivables and derivative assets at the balance sheet date.  Vermilion's receivables are primarily due from counterparties that have investment grade third party credit ratings or, in the absence of the availability of such ratings, have been satisfactorily reviewed by Vermilion for creditworthiness.  Additionally, cash and cash equivalents consist of moneys on deposit and short-term investments which may be subject to counterparty credit risk.  Vermilion mitigates this risk by transacting with North American institutions with high third party credit ratings.

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

Liquidity risk:
Vermilion's derivative financial instruments settle on a monthly basis.

The following table summarizes Vermilion's undiscounted non-derivative financial liabilities and their contractual maturities as at December 31, 2014 and December 31, 2013:

 
 
 
($M)
 
 
Due in
one month
Later than
one month and
not later than
three months
Later than
three months and
not later than
one year
Later than
one year and
not later than
five years
December 31, 2014 162,127 138,823 20,314 1,239,067
December 31, 2013 154,176 118,764 15,317 991,898

Market risk:
Vermilion's financial instruments are exposed to currency risk related to changes in foreign currency denominated financial instruments and commodity price risk related to outstanding derivative positions.  The following table summarizes what the impact on comprehensive income before tax would be for the year ended December 31, 2014 given changes in the relevant risk variables that Vermilion considers were reasonably possible at the balance sheet date.  The impact on comprehensive income before tax associated with changes in these risk variables for assets and liabilities that are not considered financial instruments are excluded from this analysis.  This analysis does not attempt to reflect any interdependencies between the relevant risk variables.

  Before tax effect on comprehensive
  income - increase (decrease)
Risk ($M) Description of change in risk variable Dec 31, 2014 Dec 31, 2013
Currency risk - Euro to Canadian Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates (4,030) (14,276)
       
  Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates 4,030 14,276
       
Currency risk - US $ to Canadian Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates (5,739) (4,420)
       
  Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates 5,739 4,420
       
Commodity price risk Increase in relevant oil reference price within option pricing models used to determine (1,072) (12,291)
  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 1,048 11,376
  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 (10,279) (2,624)
  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 10,085 2,624
  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 (9,032) (4,945)
       
  Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods 9,032 4,945

Reasonably possible changes in natural gas prices would not have had a material impact on comprehensive income for the years ended December 31, 2014 and 2013.

20. RELATED PARTY DISCLOSURES

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

The following table summarizes the compensation of directors and other members of key management personnel during the years ended December 31, 2014 and December 31, 2013:

    Year Ended
($M) Dec 31, 2014 Dec 31, 2013
Short-term benefits   5,684   6,308
Share-based payments   16,414   19,302
    22,098   25,610
Number of individuals included in the above amounts   18   17

21. WAGES AND BENEFITS

Included in operating expenses and general and administrative expenses for the year ended December 31, 2014 were $56.2 million and $47.2 million of wages and benefits, respectively (2013 - $53.2 million and $45.9 million, respectively).

22. SUBSEQUENT EVENTS

Subsequent to December 31, 2014, Vermilion was awarded a recovery of costs resulting from an oil spill at the Ambes oil terminal in France that occurred in 2007. The French court awarded Vermilion approximately €25 million (before taxes), of which 50% is due now 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's assessment is that the decision to award Vermilion its recovery of costs incurred 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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