Vermilion Energy Inc. Announces Results for the Three and Six Months Ended June 30, 2014

CALGARY, July 31, 2014 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three and six months ended June 30, 2014.

HIGHLIGHTS

  • Achieved average production of 52,089 boe/d during the second quarter of 2014, an increase of 12% as compared to 46,677 boe/d in the prior quarter and an increase of 22% compared to 42,813 boe/d in the second quarter of 2013.  Increased production was largely attributable to a 27% increase in Canadian production versus the prior quarter, led by robust performance in both our Mannville condensate-rich natural gas and Cardium light-oil development programs, which achieved production increases of 50% and 17% respectively.  Canadian volumes also increased due to approximately two months of production contribution from our S.E. Saskatchewan acquisition, which we closed at the end of April 2014.  European volumes benefitted from a full quarter of contribution from our German acquisition, which we closed in February 2014.

  • Based on the continued strength of our operations during the second quarter of 2014, we are increasing our full-year 2014 production guidance from the current range of 48,000-49,000 boe/d to 48,500-49,500 boe/d.

  • Generated fund flows from operations(1) in the second quarter of 2014 of $216.1 million ($2.05/basic share), as compared to $205.4 million ($2.01/basic share) in the prior quarter and $174.6 million ($1.73/basic share) in the second quarter of 2013.  The increase was primarily attributable to improved oil pricing and significantly higher volumes in Canada.

  • On April 29, 2014, we announced completion of our acquisition of Elkhorn Resources Inc., a private S.E. Saskatchewan producer, for total consideration of approximately $427 million.  The assets consist of high netback, light oil producing assets in the Northgate region of southeast Saskatchewan and include approximately 57,000 net acres of land (approximately 80% undeveloped), seven oil batteries, and preferential access to 50% or greater capacity at a solution gas facility that is currently under construction.

  • On May 22, 2014, we announced the completion of tunnel boring operations beneath Sruwaddacon Bay at our Corrib project in Ireland.  The tunnel boring machine has been demobilized from the tunnel, and the remaining tunnel outfitting, gas plant preparation and offshore well work activities are progressing.  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.

  • We are celebrating our 20th Anniversary as a publicly traded company in 2014.  This has been a rewarding period of growth and achievement for Vermilion, 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 June 30, 2014, of 36.8% per annum since our inception.  Looking forward, with the consistent strength of our operations, our extensive opportunity base, and anticipated growth of our fund flows from operations in the current commodity environment, we will strive to provide continued strong financial performance, and a reliable and growing dividend stream to investors.

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

Vermilion Energy Inc. Second Quarter 2014 Conference Call and Audio Webcast Details

Vermilion will discuss these results in a conference call to be held on Thursday, July 31, 2014 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 65722904.  The replay will be available until midnight eastern time on August 7, 2014.

You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=813553&s=1&k=D1BE33AF46B4AC5B296C96983A231587 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
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

HIGHLIGHTS            

      Three Months Ended   Six Months Ended
($M except as indicated)     Jun 30,   Mar 31,   Jun 30,   Jun 30,   Jun 30,
Financial     2014   2014   2013   2014   2013
Petroleum and natural gas sales     387,684   381,183   311,966   768,867   621,542
Fund flows from operations (1)     216,076   205,363   174,592   421,439   338,221
  Fund flows from operations ($/basic share)     2.05   2.01   1.73   4.05   3.38
  Fund flows from operations ($/diluted share)     2.01   1.97   1.71   3.99   3.33
Net earnings     53,993   102,788   106,198   156,781   158,335
  Net earnings ($/basic share)     0.51   1.00   1.05   1.51   1.58
Capital expenditures     135,073   196,375   78,118   331,448   258,587
Acquisitions     381,139   178,227   -   559,366   -
Asset retirement obligations settled     2,381   2,651   2,370   5,032   3,758
Cash dividends ($/share)     0.645   0.645   0.600   1.290   1.200
Dividends declared     68,710   66,007   60,776   134,717   120,388
  % of fund flows from operations     32%   32%   35%   32%   36%
Net dividends (1)     49,561   47,122   42,146   96,683   86,226
  % of fund flows from operations     23%   23%   24%   23%   25%
Payout (1)     187,015   246,148   122,634   433,163   348,571
  % of fund flows from operations     87%   120%   70%   103%   103%
  % of fund flows from operations (excluding the Corrib project)     73%   111%   55%   92%   90%
Net debt (1)     1,168,998   966,310   674,368   1,168,998   674,368
Ratio of net debt to annualized fund flows from operations (1)     1.4   1.2   1.0   1.4   1.0
Operational                      
Production                      
  Crude oil (bbls/d)     30,184   27,318   26,638   28,759   25,119
  NGLs (bbls/d)     2,892   2,140   1,775   2,518   1,604
  Natural gas (mmcf/d)     114.08   103.32   86.40   108.73   84.29
  Total (boe/d)     52,089   46,677   42,813   49,398   40,772
Average realized prices                      
  Crude oil and NGLs ($/bbl)     109.89   111.62   98.95   110.73   101.42
  Natural gas ($/mcf)     6.19   7.99   7.22   7.04   7.00
Production mix (% of production)                      
  % priced with reference to WTI     30%   25%   25%   27%   24%
  % priced with reference to AECO     18%   17%   17%   18%   18%
  % priced with reference to TTF     18%   19%   17%   19%   17%
  % priced with reference to Dated Brent     34%   39%   41%   36%   41%
Netbacks ($/boe) (1)                      
  Operating netback     59.52   63.20   59.30   61.29   59.24
  Fund flows from operations netback     46.24   47.76   44.90   46.98   44.40
  Operating expenses     12.46   13.49   12.36   12.95   13.21
Average reference prices                      
  WTI (US $/bbl)     102.99   98.68   94.22   100.84   94.30
  Edmonton Sweet index (US $/bbl)     96.85   90.43   90.56   93.65   88.99
  Dated Brent (US $/bbl)     109.63   108.22   102.44   108.93   107.50
  AECO ($/GJ)     4.44   5.42   3.35   4.93   3.19
  TTF ($/GJ)     7.91   10.19   10.14   9.02   10.23
Average foreign currency exchange rates                      
  CDN $/US $     1.09   1.10   1.02   1.10   1.02
  CDN $/Euro     1.50   1.51   1.34   1.50   1.33
Share information ('000s)                      
Shares outstanding - basic     106,620   102,453   101,418   106,620   101,418
Shares outstanding - diluted (1)     109,371   105,167   103,735   109,371   103,735
Weighted average shares outstanding - basic     105,577   102,278   100,964   103,936   100,137
Weighted average shares outstanding - diluted (1)     107,330   104,171   102,223   105,531   101,578

(1)  The above table includes additional GAAP and non-GAAP financial measures which may not be comparable to other companies. 
Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.

MESSAGE TO SHAREHOLDERS

In 2014, we are celebrating Vermilion's 20th anniversary as a publicly traded company.  It has been a demanding, but also tremendously rewarding 20 years.  During this time, 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.  During this time, we have remained committed to stewarding our Company in the best interests of our shareholders.  We are pleased that our efforts have been both recognized and supported by our shareholders, resulting in a compound average total return including dividends, as of June 30, 2014, of 36.8% per annum since inception.  We are also proud of the consistency of those returns.  Over the last one, three, five, ten and 15 calendar-year periods, we have reliably delivered double-digit compound average total returns of 24.6%, 14.5%, 24.0%, 18.6% and 25.5%, respectively.

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

While we are confident that the assets in our current portfolio contain significant opportunity for growth for years to come, we also find ourselves uniquely positioned to advantageously grow and further diversify our opportunity base through potential acquisition activity in both North American and international markets.  In North America, we are faced with an active asset market and we continue to see technology unlocking new opportunities for development.  With Vermilion's access to relatively low cost capital, our conservative balance sheet, and significant near-term free cash flow(1) growth on the horizon (including from Corrib, which is slated to come on production in mid-2015), we are uniquely positioned to compete and transact should suitable opportunities arise.  While international asset markets remain substantially less liquid than in North America, we similarly find ourselves well-positioned for assets that do become available in our selective regions of interest.

The second quarter of 2014 marks another quarter of high activity and effective operational execution for our Company.  We achieved significant quarter-over-quarter production growth largely attributable to strong results from our successful Mannville condensate-rich gas and Cardium light-oil development programs in Canada.   Production volumes from our Mannville development program averaged more than 4,600 boe/d,  an increase of 50% during the second quarter, while Cardium production averaged more than 12,000 boe/d, an increase of 17% from the prior quarter.  Operating netbacks(1) for our Cardium production averaged more than $70/boe in the second quarter.  Our strong Cardium results reflect continued improvements in completions design and better-than-forecasted production volumes on several of our two-mile extended reach horizontal Cardium wells.  With improving efficiencies and productivity, we will require less capital and approximately five fewer Cardium wells than originally anticipated to meet our objectives for our 2014 Cardium program.  As a result, we are diverting a portion of our previously planned Cardium expenditures to our Mannville development program which also generates very robust economics.  With the incremental capital, we now plan to drill approximately 15 (9 net) Mannville wells in 2014, up from eight (5.7 net) wells in our original budget.  Looking forward, we anticipate our Mannville drilling activity will continue to increase in future years as we develop our substantial inventory of highly economic prospects.

We continue to appraise our position in the Duvernay condensate-rich resource play, where we have amassed 317 net sections at the relatively low cost of approximately $76 million ($375/acre).  Our position comprises three largely contiguous blocks in the Edson, West Pembina and Niton areas.  To date, we have drilled three vertical stratigraphic test wells, and have completed drilling operations on two horizontal appraisal wells.  The first horizontal appraisal well is located in the downdip part of our Edson block where condensate yields are expected to be lower than the average in our overall land position.  We selected this location because of its proximity to one of our vertical stratigraphic test wells, allowing us to conduct microseismic monitoring in the stratigraphic test well when we frac the horizontal well (expected later in the third quarter of 2014).  Our second horizontal appraisal well, which we operate at a 34.8% working interest, is located along a shared lease-line in the Pembina block to allow partner participation.  Completion of this second well, also employing microseismic monitoring, is expected during the third quarter.  During drilling operations, both the Edson and West Pembina wells encountered stability issues in the build section of the wellbore near the heel of the horizontal well.  Both wells were ultimately sidetracked to reach total measured depths of slightly more than 4,700 metres.  Drilling operations lasted approximately 100 days per well, double our original estimate.  The longer-than-expected drilling time took us past break-up, resulting in wet lease conditions and further contributed to higher costs.  As a result of these drilling challenges, we are now forecasting total net well costs for the two horizontal wells of approximately $40 million, including completion, equip and tie-in, microseismic and related monitoring-well workovers.  Our development-phase target for well costs (including drill, complete, equip and tie-in) is $12 to $15 million.  We believe that development-phase savings will be achievable through learning-curve improvements, lower lease construction costs, economies of scale in procurement and lower evaluation expenditures (such as the elimination of microseismic monitoring).  We anticipate that the production results and interpreted fracture geometries from the microseismic data on these appraisal wells will assist us in optimizing completions on future development-phase horizontal wells.  We are confident that we will be able to project the appraisal well results to higher condensate yield locations as we move to the northeast in our acreage position, which encompasses the entire breadth of the condensate-rich window.  Our Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational, and timing advantages if we progress to full development of the Duvernay resource play.  In combination, our Cardium, Mannville, and Duvernay positions provide us with exploration and development opportunities in our core Canadian operating region that have the potential to deliver strong production and reserve growth into the latter half of the decade.

On April 29, 2014, we announced the completion of our acquisition of Elkhorn Resources Inc., a private southeast Saskatchewan producer, for total consideration of $427 million.  The assets consist of high netback, light oil producing assets in the Northgate region of southeast Saskatchewan and include approximately 57,000 net acres of land (approximately 80% undeveloped), seven oil batteries, and preferential access to 50% or greater capacity at a solution gas facility that is currently under construction.  More than 90% of the current production base is operated by Vermilion.  Production from the assets was moderately impacted by recent flooding in S.E. Saskatchewan and are projected to average approximately 3,750 boe/d (97% crude oil) during the remainder of 2014.  We have currently identified approximately 175 (152 net) potential drilling locations targeting the Midale, Frobisher, Bakken, and Three Forks/Torquay formations.  We began a two-rig, 13-well Midale drilling program in June 2014.

We were also active in Europe during the second quarter of 2014 with drilling operations in both France and the Netherlands.  In France, we drilled two of five planned wells in Champotran in follow-up to our highly successful 2013 drilling campaign.  These first two wells have been put on production during July at initial rates averaging 275 bbls/d per well.  The remaining three wells at Champotran will be drilled before the end of the third quarter.  Our first well in the Parentis field has been put on production at a rate of 20 bbls/d.  A new pool exploratory test at Cazaux North has been evaluated as dry and will be abandoned.  We currently plan a seven-well drilling program in France during 2014, with two previously planned wells deferred to later-year programs to optimize surface access and reduce rig move costs.  During the second quarter of 2014, we advanced preparations for the phased transfer of our shut-in Vic Bihl natural gas production from the Lacq gas processing facility where it was previously handled to a new third party facility.  Delays in receiving required permit transfers have pushed our original plans to bring approximately 850 mcf/d of solution gas back on-stream from the third quarter of 2014 to early 2015.  The remainder of the shut-in gas production, approximately 3,400 mcf/d of gas cap gas, is expected to be back on production in late-2015.

In the Netherlands, we drilled two additional wells during the second quarter of 2014.  The Havelte-01 well in the Steenwijk concession in Friesland (50% working interest) came in low to prognosis and was plugged and abandoned.  However, as part of the Havelte-01 project, we will tie-in a previously-stranded gas discovery at Eesveen-01. First gas is anticipated to occur from Eesveen in early 2015 at an anticipated rate of 3 mmcf/d net to Vermilion.  The Lambertschaag-02 well was non-commercial in its primary objective but did encounter other zones of interest with significant gas shows that will be further evaluated during the third quarter of 2014.  There are three wells remaining in our 2014 Netherlands drilling program with one planned during the third quarter and two in the fourth quarter.  Late in the second quarter, we initiated production from the Zechstein carbonate formation of the previously-idle DeHoeve-01 well (42% working interest), at a rate of 3 mmcf/d, net to Vermilion.  Our undeveloped land base in the Netherlands now totals more than 800,000 net acres, and it is our intention to generally increase annual activity levels to maintain a rolling inventory of projects so that each year's capital program will involve a combination of drilling new wells and the tie-in of previous successes.

In Germany, we have now established an office in Berlin, placed an experienced Managing Director, and are progressing well with recruiting a supporting technical team to oversee both our existing assets and potential new opportunities.  Our current position in Germany enables us to participate, on a non-operated basis, in the exploration, development, production and transportation of natural gas from four gas producing fields across 11 production licenses. The assets are expected to contribute approximately 2,300 boe/d of production for calendar 2014, and include both exploration and production licenses that comprise a total of 207,000 gross acres, of which 85% is in the exploration license.  Germany is a producing region with a long history of oil and gas development activity, low political risk, and strong marketing fundamentals.  Our position provides us with entry into this sizable market, in the form of free cash flow(1) generating, low-decline assets with near-term development inventory in addition to longer-term, low-permeability gas prospectivity.  We believe that our conventional and unconventional expertise, coupled with new access to proprietary technical data, will position us for future development and expansion opportunities in both Germany and the greater European region.  During the first quarter of 2014, we participated in the drilling of one (0.25 net) development well in Germany.  This well logged 81 metres of net pay and is expected to be tested and put on production during the second half of 2014.

On May 22, 2014, we announced the completion of tunnel boring operations beneath Sruwaddacon Bay at our Corrib project in Ireland.  The tunnel boring machine has now been demobilized and the project is progressing well with respect to several key activities that remain to be completed prior to initial production at Corrib.  These activities include the installation of flow and umbilical lines within the tunnel, grouting of the tunnel, certain offshore well workover activities, and receipt of final authorizations for start-up of the Bellanaboy gas facility. The most significant remaining offshore workover activity at our Corrib field was successfully completed subsequent to the end of the quarter.  The Corrib P6 well was flow tested for 24 hours at a final flow rate of 112 mmcf/d at a flowing bottom hole pressure of 3260 psi, representing an approximate 44 percent drawdown from reservoir pressure.  The test rates were within expectations, reconfirming previous test rates.  The well was still "cleaning up" at the end of the test, exhibiting an increasing flow rate at increasing flowing bottom hole pressure when the test period ended.  The P6 test confirms that all five wells required for start-up at Corrib are ready to flow. Based on the current deterministic schedule for the project, 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 Australia, we remain focused on completing preparations for the 2015 drilling program, as well as re-lifing and maintenance projects on our two platforms.  In order to meet current marketing agreements and provide long-term certainty to our customers, our current plan is to maintain field-total production levels within our prior guidance of between 6,000 bbls/d and 8,000 bbls/d.  We anticipate maintaining these production levels in Australia for the foreseeable future with drilling programs approximately every two years. Our Australian oil currently garners a premium of approximately US $7.00 to the Dated Brent index and incurs no transportation cost as production is sold directly at the platform.

Our operations continue to perform strongly, generating organic production growth in a capital-efficient manner.  Given the strength of our operations, we have elected to increase our previous 2014 average annual production guidance from a range of 48,000-49,000 boe/d to a range of 48,500-49,500 boe/d.  Assuming commodity prices remain near current levels for the remainder of 2014, we anticipate that we can fully fund our net dividends(1) and development capital expenditures (excluding capital investment at Corrib) with fund flows from operations during 2014.  With the shifts in capital spending outlined previously, we currently anticipate full year 2014 capital expenditure to total approximately $650 million, an increase from our previous guidance of $635 million.  This increase largely reflects a shift in spending to increase Mannville development drilling as well as higher costs for our Duvernay appraisal wells.

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

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.

(1)   The above discussion includes additional GAAP and non-GAAP measures which may not be comparable to other companies.  Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is Management's Discussion and Analysis ("MD&A"), dated July 30, 2014, of Vermilion Energy Inc.'s ("Vermilion" or the "Company") operating and financial results as at and for the three and six months ended June 30, 2014 compared with the corresponding periods in the prior year.

This discussion should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2014 and the audited consolidated financial statements for the year ended December 31, 2013 and 2012, together with accompanying notes.  Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

The unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2014 and comparative information have been prepared in Canadian dollars, except where another currency is indicated, and in accordance with IAS 34, "Interim financial reporting", as issued by the International Accounting Standard Board ("IASB").

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

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

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

VERMILION'S BUSINESS

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

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

  • Canada business unit: Relates to our 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 offshore Corrib natural gas field.
  • Australia business unit: Relates to our operations in the Wandoo offshore crude oil field.
  • Corporate: Includes expenditures related to our global hedging program, financing expenses, and general and administration expenses, primarily incurred in Canada and not directly related to the operations of a specific business unit.

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

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 are further increasing 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 is due to increased Mannville development drilling and higher than anticipated costs associated with the Duvernay appraisal program.

The following table summarizes our 2014 guidance:

        Date           Capital Expenditures ($MM)           Production (boe/d)
2014 Guidance       November 7, 2013           555           45,000 to 46,000
2014 Guidance - Update       March 18, 2014           590           47,500 to 48,500
2014 Guidance - Update       May 2, 2014           635           48,000 to 49,000
2014 Guidance - Update       July 31, 2014           650           48,500 to 49,500

SHAREHOLDER RETURN

Vermilion strives to provide investors with reliable and growing dividends in addition to sustainable, global production growth.  The following table, as of June 30, 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     $2.49       $7.11       $11.67
Capital appreciation per Vermilion share     $22.84       $23.25       $45.02
Total return per Vermilion share     49.3%       59.5%       193.9%
Annualized total return per Vermilion share     49.3%       16.8%       24.1%
Annualized total return on the S&P TSX High Income Energy Index     29.3%       6.2%       11.5%

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

CONSOLIDATED RESULTS OVERVIEW

    Three Months Ended   % change   Six Months Ended   % change
      Jun 30,   Mar 31,   Jun 30,   Q2/14 vs.   Q2/14 vs.   Jun 30,   Jun 30,   2014 vs.
      2014   2014   2013   Q1/14   Q2/13   2014   2013   2013
Production                                
  Crude oil (bbls/d)   30,184   27,318   26,638   10%   13%   28,759   25,119   14%
  NGLs (bbls/d)   2,892   2,140   1,775   35%   63%   2,518   1,604   57%
  Natural gas (mmcf/d)   114.08   103.32   86.40   10%   32%   108.73   84.29   29%
  Total (boe/d)   52,089   46,677   42,813   12%   22%   49,398   40,772   21%
  Build (draw) in inventory (mbbl)   67   (98)   6           (31)   (238)    
Financial metrics                                
  Fund flows from operations ($M)   216,076   205,363   174,592   5%   24%   421,439   338,221   25%
    Per share ($/basic share)   2.05   2.01   1.73   2%   18%   4.05   3.38   20%
  Net earnings ($M)   53,993   102,788   106,198   (47%)   (49%)   156,781   158,335   (1%)
    Per share ($/basic share)   0.51   1.00   1.05   (49%)   (51%)   1.51   1.58   (4%)
  Cash flows from operating activities ($M)   149,592   178,238   179,074   (16%)   (16%)   327,830   369,786   (11%)
  Net debt ($M)   1,168,998   966,310   674,368   21%   73%   1,168,998   674,368   73%
  Cash dividends ($/share)   0.645   0.645   0.600   -   8%   1.290   1.200   8%
Activity                                
  Capital expenditures ($M)   135,073   196,375   78,118   (31%)   73%   331,448   258,587   28%
  Acquisitions ($M)   381,139   178,227   -   114%   100%   559,366   -   100%
  Gross wells drilled   13.00   24.00   6.00           37.00   34.00    
  Net wells drilled   6.72   18.83   4.86           25.55   31.36    

Operational review

  • Recorded consolidated average production of 52,089 boe/d during Q2 2014, a 12% increase compared to Q1 2014 and a 22% increase as compared to Q2 2013.  The growth quarter-over-quarter and year-over-year was primarily driven by production growth in Canada, resulting from our continued development of the Cardium and Mannville plays in Alberta coupled with approximately two months of incremental production from southeast Saskatchewan (approximately 2,000 boe/d during the quarter) following our acquisition of Elkhorn Resources Inc. and a full quarter of incremental production from our acquisition in Germany.
  • Recorded consolidated average production of 49,398 boe/d for the six months ended June 30, 2014, a 21% increase versus the same period in 2013 as a result of production growth in Canada and the Netherlands.  In Canada, production growth of 32% year-over-year was achieved through continued development of the Cardium and Mannville plays in Alberta, coupled with two months of incremental production from southeast Saskatchewan.  In the Netherlands, production increased to 7,040 boe/d resulting from incremental production from our acquisition in the Netherlands in Q4 2013 and increased volumes following completion of the Middenmeer Treatment Centre retrofit in the latter part of 2013.  In addition, we maintained Australia production at 6,795 boe/d year-to-date and added incremental volumes from our acquisition in Germany, which closed in February of 2014.  These increases were partially offset by a 1% decrease in production in France, which occurred despite a 5% increase in crude oil production volumes, due to the temporary shut-in of natural gas production.
  • Activity during the quarter included capital expenditures totalling $135.1 million incurred primarily in Canada, France, the Netherlands, and Ireland.  In Canada, capital expenditures of $37.0 million were significantly lower than the $114.9 million from Q1 2014 due to spring breakup and were related to the drilling of 3.29 net wells.  In France, $37.6 million of capital expenditures were incurred during the quarter relating to the drilling of 2.0 net wells in the Champotran field in Paris.  In the Netherlands, $21.5 million of capital expenditures were incurred during the quarter relating to the drilling of 1.4 net wells.  In Ireland, $27.2 million of capital expenditures were incurred relating to the completion of tunnel boring operations, offshore well workover and various facility activities.
  • Acquisition expenditures for the quarter totalling $381.1 million related primarily to our acquisition of Elkhorn Resources Inc. on April 29, 2014.  This included approximately $205.0 million attributed to approximately 2.8 million Vermilion common shares issued to Elkhorn's shareholders.  Acquisitions in the year-to-date period also included our acquisition in Germany, which closed in February of 2014, for total cash consideration of $172.9 million.

Financial review

Net earnings

  • Net earnings for Q2 2014 were $54.0 million ($0.51/basic share) as compared to net earnings of $102.8 million ($1.00/basic share) in Q1 2014 and $106.2 million ($1.05/basic share) in Q2 2013.  The decrease to net earnings quarter-over-quarter and year-over-year occurred despite production and sales growth, due largely to the reversal of unrealized foreign exchange gains recognized during Q1 2014 and Q2 2013.  The unrealized foreign exchange gains recognized during the comparable quarters related to the Euro strengthening versus the Canadian dollar and the resulting impact on our Euro denominated financial assets.  In Q1 2014 and Q2 2013, the Euro strengthened by approximately 4% and 5%, respectively, versus a 4% weakening in the current quarter.
  • Net earnings for the six months ended June 30, 2014 decreased by 1% (4% per share).  This slight decrease occurred as increased sales were offset by the absence of unrealized foreign exchange gains and increased depreciation expense.

Cash flows from operating activities

  • Cash flow from operations decreased by 16% and 11% for the three and six months ended June 30, 2014 as compared to the same periods in 2013.  These decreases occurred despite increased production and favourable Canadian dollar commodity prices due to the offsetting impacts of timing differences pertaining to working capital.

Fund flows from operations

  • Generated fund flows from operations of $216.1 million ($2.05/basic share) during Q2 2014, an increase of $10.7 million (5%) versus Q1 2014.  This quarter-over-quarter increase was largely driven by increased sales volumes in Canada, following production growth in the Cardium, Mannville, and incremental production in southeast Saskatchewan.
  • Fund flows from operations increased by 24% and 25% for the three and six months ended June 30, 2014, respectively, versus the comparable periods in 2013.  These increases in fund flows from operations resulted from increased sales volumes in Canada, incremental volumes from our Germany acquisition, coupled with favorable Canadian dollar crude oil and Canadian natural gas pricing, partially offset by lower sales volumes in Australia and a decline in TTF pricing. Impacting fund flows from operations, and included in general and administration costs for 2014, are charges relating to our acquisitions in Canada ($1.1 million) and Germany ($0.8 million).

Net debt

  • As a result of funding our 2014 acquisitions in Germany and Saskatchewan, net debt increased to $1.2 billion as at June 30, 2014.  As year-to-date fund flows from operations includes only two months of contribution from the acquisition in Saskatchewan, the ratio of net debt to annualized fund flows from operations increased to 1.4 times.

Dividends

  • Declared dividends of $0.215 per common share per month during 2014, totalling $0.645 per common share over the quarter, an increase of 7.5% versus the 2013 comparable periods.

COMMODITY PRICES

    Three Months Ended   % change   Six Months Ended   % change
    Jun 30,   Mar 31,   Jun 30,   Q2/14 vs.   Q2/14 vs.   Jun 30,   Jun 30,   2014 vs.
    2014   2014   2013   Q1/14   Q2/13   2014   2013   2013
Average reference prices                                
WTI (US $/bbl)   102.99   98.68   94.22   4%   9%   100.84   94.30   7%
Edmonton Sweet index (US $/bbl)   96.85   90.43   90.56   7%   7%   93.65   88.99   5%
Dated Brent (US $/bbl)   109.63   108.22   102.44   1%   7%   108.93   107.50   1%
AECO ($/GJ)   4.44   5.42   3.35   (18%)   33%   4.93   3.19   55%
TTF ($/GJ)   7.91   10.19   10.14   (22%)   (22%)   9.02   10.23   (12%)
TTF (€/GJ)   5.27   6.75   7.57   (22%)   (30%)   6.01   7.69   (22%)
Average foreign currency exchange rates                                
CDN $/US $   1.09   1.10   1.02   (1%)   7%   1.10   1.02   8%
CDN $/Euro   1.50   1.51   1.34   (1%)   12%   1.50   1.33   13%
Average realized prices ($/boe)                                
Canada   71.56   69.26   62.00   3%   15%   70.55   59.93   18%
France   117.29   117.54   98.04     20%   117.41   102.84   14%
Netherlands   48.14   63.60   65.08   (24%)   (26%)   56.06   63.19   (11%)
Germany   45.36   55.85   -   (19%)   100%   49.50   -   100%
Australia   126.87   127.26   111.54     14%   127.11   115.89   10%
Consolidated   82.96   88.67   80.21   (6%)   3%   85.70   81.60   5%
Production mix (% of production)                                
% priced with reference to WTI   30%   25%   25%           27%   24%    
% priced with reference to AECO   18%   17%   17%           18%   18%    
% priced with reference to TTF   18%   19%   17%           19%   17%    
% priced with reference to Dated Brent   34%   39%   41%           36%   41%    

Reference prices

  • Oil outperformed natural gas in Q2 2014 as a result of heightened geopolitical tensions and a generally tighter fundamental balance.  Averaging the quarter at US $109.63/bbl, Dated Brent was 1% higher quarter-over-quarter and 7% above the same period last year.
  • WTI's advance quarter-over-quarter was more pronounced, up 4% from Q1 2014 and 9% higher than Q2 2013. Sliding oil inventories at Cushing, Oklahoma and elevated refining demand contributed to the oil benchmark's advance. Edmonton Sweet prices also increased in Q2 2014, up 7% from both Q1 2014 and Q2 2013.
  • AECO natural gas fell 18% quarter-over-quarter to average C$4.44/GJ in Q2. While seasonal factors weighed heavily on a quarter-over-quarter basis, AECO still managed to post a strong 33% increase over the same quarter last year and a 55% increase for the first half of 2014 over the first half of 2013 from a colder-than-normal winter.
  • Increased storage levels and weaker seasonal demand led TTF to fall 22% in Q2 versus Q1, averaging C$7.91/GJ, and down 30% versus the same quarter last year.
  • The Canadian dollar posted a small increase versus both the US dollar and Euro in Q2 2014 versus Q1 2014, however, versus the same period last year the Canadian dollar has weakened by 7% versus the US dollar and 12% versus the Euro.

Realized prices

  • Consolidated realized price decreased by 6% for Q2 2014 as compared to Q1 2014.  This decrease was the result of a change in Vermilion's production mix coupled with a 22% decrease in TTF pricing.  Quarter-over-quarter, production growth in Alberta and incremental production from our Q2 2014 acquisition in Saskatchewan increased our percentage of WTI priced production from 25% to 30% of consolidated production.  As WTI continues to trade at a discount to Dated Brent, this resulted in an overall decrease to our consolidated realized price.
  • Consolidated realized price for the three and six months ended June 30, 2014 increased by 3% and 5% as compared to the same periods in the prior year.  These increases were the result of stronger crude oil and Canadian natural gas pricing coupled with the weakness of the Canadian dollar.  These increases were partially offset by the aforementioned changes in production mix and TTF pricing.

FUND FLOWS FROM OPERATIONS

    Three Months Ended   Six Months Ended
    Jun 30, 2014   Mar 31, 2014   Jun 30, 2013   Jun 30, 2014   Jun 30, 2013
    $M   $/boe   $M   $/boe   $M   $/boe   $M   $/boe   $M   $/boe
Petroleum and natural gas sales   387,684   82.96   381,183   88.67   311,966   80.21   768,867   85.70   621,542   81.60
Royalties   (29,013)   (6.21)   (24,024)   (5.59)   (15,800)   (4.06)   (53,037)   (5.91)   (31,590)   (4.15)
Petroleum and natural gas revenues   358,671   76.75   357,159   83.08   296,166   76.15   715,830   79.79   589,952   77.45
Transportation expense   (12,032)   (2.57)   (9,861)   (2.29)   (6,653)   (1.71)   (21,893)   (2.44)   (13,294)   (1.75)
Operating expense   (58,213)   (12.46)   (57,986)   (13.49)   (48,082)   (12.36)   (116,199)   (12.95)   (100,657)   (13.21)
General and administration   (17,762)   (3.80)   (14,467)   (3.37)   (11,313)   (2.91)   (32,229)   (3.59)   (23,923)   (3.14)
Corporate income taxes   (32,635)   (6.98)   (38,603)   (8.98)   (36,719)   (9.44)   (71,238)   (7.94)   (72,276)   (9.49)
PRRT   (12,699)   (2.72)   (20,239)   (4.71)   (12,590)   (3.24)   (32,938)   (3.67)   (23,743)   (3.12)
Interest expense   (12,334)   (2.64)   (11,460)   (2.67)   (9,336)   (2.40)   (23,794)   (2.65)   (18,025)   (2.37)
Realized gain (loss) on derivative instruments   2,419   0.52   2,640   0.61   1,770   0.46   5,059   0.56   (1,017)   (0.13)
Realized foreign exchange gain (loss)   587   0.12   (2,041)   (0.47)   1,272   0.33   (1,454)   (0.16)   655   0.09
Realized other income   74   0.02   221   0.05   77   0.02   295   0.03   549   0.07
Fund flows from operations   216,076   46.24   205,363   47.76   174,592   44.90   421,439   46.98   338,221   44.40

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

($M)     Q2/14 vs. Q1/14   Q2/14 vs. Q2/13   2014 vs. 2013
Fund flows from operations - Comparative period     205,363   174,592   338,221
Sales volume variance:              
   Canada     39,771   44,135   63,154
   France     7,323   6,669   (4,579)
   Netherlands     (1,936)   2,166   7,799
   Germany     4,751   11,097   20,012
   Australia     (30,964)   (20,562)   (6,516)
Pricing variance on sold volumes:              
   WTI     5,026   14,192   24,876
   AECO     (4,717)   3,983   13,772
   Dated Brent     (447)   24,639   37,907
   TTF     (12,306)   (10,601)   (9,100)
Changes in:              
   Realized derivatives     (221)   649   6,076
   Royalties     (4,989)   (13,213)   (21,447)
   Operating expense     (227)   (10,131)   (15,542)
   Transportation     (2,171)   (5,379)   (8,599)
   Interest     (874)   (2,998)   (5,769)
   General and administration     (3,295)   (6,449)   (8,306)
   Realized other income     (147)   (3)   (254)
   Realized foreign exchange     2,628   (685)   (2,109)
   Corporate income taxes     5,968   4,084   1,038
   PRRT     7,540   (109)   (9,195)
Fund flows from operations - Current Period     216,076   216,076   421,439

Fund flows from operations of $216.1 million during Q2 2014 was an increase of $10.7 million (5%) versus Q1 2014.  The majority of this increase resulted from $6.5 million of increased sales.  The increase in sales was due to favourable sales volume variances, partially offset by unfavourable pricing variances.  Sales volume variances included $39.8 million relating to higher production volumes in Canada following continued development of the Cardium and Mannville plays in Alberta and incremental production from our southeast Saskatchewan acquisition and $7.3 million relating to a draw in inventory in France.  These favourable sales volume variances were partially offset by a $31.0 million unfavourable variance relating to a build in inventory in Australia.  The unfavourable pricing variance was the result of a quarter-over-quarter decline in natural gas prices, offset partially by an increase in the WTI reference price.

Fund flows from operations increased by 24% and 25% for the three and six months ended June 30, 2014, respectively, versus the comparable periods in 2013.  These increases in fund flows from operations resulted primarily from the combined impacts of favourable sales volume and pricing variances. Favourable sales volume variances occurred primarily in Canada (contributing an additional $44.1 million in Q2 2014 and $63.2 million year-to-date 2014 versus the comparable periods) and were aided by incremental production in Germany (contributing $11.1 million in the quarter and $20.0 million in the year-to-date period).

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

CANADA BUSINESS UNIT

Overview

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

Operational review

    Three Months Ended   % change   Six Months Ended   % change
      Jun 30,   Mar 31,   Jun 30,   Q2/14 vs.   Q2/14 vs.   Jun 30,   Jun 30,   2014 vs.
Canada business unit   2014   2014   2013   Q1/14   Q2/13   2014   2013   2013
Production                                
  Crude oil (bbls/d)   12,676   9,437   8,885   34%   43%   11,065   8,428   31%
  NGLs (bbls/d)   2,796   2,071   1,725   35%   62%   2,435   1,531   59%
  Natural gas (mmcf/d)   57.59   49.53   43.69   16%   32%   53.58   42.37   26%
  Total (boe/d)   25,070   19,763   17,892   27%   40%   22,430   17,021   32%
Production mix (% of total)                                
  Crude oil   51%   48%   50%           49%   50%    
  NGLs   11%   10%   10%           11%   9%    
  Natural gas   38%   42%   40%           40%   41%    
Activity                                
  Capital expenditures ($M)   36,968   114,939   16,553   (68%)   123%   151,907   101,682   49%
  Acquisitions ($M)   381,326   4,768   -           386,094   -    
  Gross wells drilled   9.00   20.00   3.00           29.00   27.00    
  Net wells drilled   3.29   14.97   1.86           18.26   24.36    

Production

  • Production in Canada increased by 27% quarter-over-quarter and by 40% year-over-year.
  • Quarter-over-quarter and year-over-year increases were largely attributable to production additions from our southeast Saskatchewan acquisition, supplemented by strong production from our Mannville program and continued development in the Cardium.
  • Cardium production averaged more than 12,100 boe/d in Q2 2014.
  • Mannville production averaged more than 4,600 boe/d in Q2 2014.
  • Saskatchewan production averaged approximately 2,000 boe/d in Q2 2014, taking into account an effective acquisition date of April 29, 2014.

Activity review

  • Vermilion drilled nine (3.3 net) wells during Q2 2014.

Cardium

  • In the Cardium, we drilled one (1.0 net) operated well and brought five (5.0 net) operated wells on production during Q2 2014, all of which were long reach wells with horizontal lengths between 1.5 and 2.0 miles. Year-to-date we have drilled 12 (11.5 net) operated wells and brought 18 (18.0 net) operated wells on production.
  • Since 2009, we have drilled or participated in 258 (183.7 net) wells in the Cardium.
  • Operating netbacks averaged approximately $70/boe year-to-date for Cardium production.
  • In 2014, we plan to drill or participate in 37 (24.5 net) Cardium wells.

Mannville

  • During Q2 2014, in the Mannville, we brought two (1.5 net) operated wells on production that were drilled in the previous quarter.  Year-to-date we have drilled and brought on production five (3.7 net) operated wells.
  • In 2014, we plan to drill 15 (9 net) Mannville wells.

Duvernay

  • We drilled two (1.3 net) horizontal Duvernay wells, with completion of the wells anticipated for Q3 2014.

Saskatchewan

  • We spud two wells in the second quarter, with completions scheduled for Q3 2014.
  • A 13 well Midale program is planned for 2014.

Financial review

    Three Months Ended   % change   Six Months Ended   % change
Canada business unit   Jun 30,   Mar 31,   Jun 30,   Q2/14 vs.   Q2/14 vs.   Jun 30,   Jun 30,   2014 vs.
($M except as indicated)   2014   2014   2013   Q1/14   Q2/13   2014   2013   2013
  Sales   163,261   123,180   100,950   33%   62%   286,441   184,638   55%
  Royalties   (18,240)   (12,663)   (9,707)   44%   88%   (30,903)   (18,696)   65%
  Transportation expense   (4,024)   (3,098)   (2,611)   30%   54%   (7,122)   (4,880)   46%
  Operating expense   (21,179)   (16,610)   (15,975)   28%   33%   (37,789)   (29,816)   27%
  General and administration   (6,560)   (2,868)   (3,948)   129%   66%   (9,428)   (7,017)   34%
  Fund flows from operations   113,258   87,941   68,709   29%   65%   201,199   124,229   62%
Netbacks ($/boe)                                
  Sales   71.56   69.26   62.00   3%   15%   70.55   59.93   18%
  Royalties   (7.99)   (7.12)   (5.96)   12%   34%   (7.61)   (6.07)   25%
  Transportation expense   (1.76)   (1.74)   (1.60)   1%   10%   (1.75)   (1.58)   11%
  Operating expense   (9.28)   (9.34)   (9.81)   (1%)   (5%)   (9.31)   (9.68)   (4%)
  General and administration   (2.88)   (1.61)   (2.42)   79%   19%   (2.32)   (2.28)   2%
  Fund flows from operations netback   49.65   49.45   42.21     18%   49.56   40.32   23%
Reference prices                                
  WTI (US $/bbl)   102.99   98.68   94.22   4%   9%   100.84   94.30   7%
  Edmonton Sweet index (US $/bbl)   96.85   90.43   90.56   7%   7%   93.65   88.99   5%
  AECO ($/GJ)   4.44   5.42   3.35   (18%)   33%   4.93   3.19   55%

Sales

  • The realized price for our crude oil production in Canada is directly linked to WTI but is subject to market conditions in Western Canada.  These market conditions can result in fluctuations in the pricing differential, as reflected by the Edmonton Sweet index price.  The realized price of our NGLs in Canada is based on product specific differentials pertaining to trading hubs in the United States.  The realized price of our natural gas in Canada is based on the AECO spot price in Canada.
  • Sales per boe increased by 3% quarter-over-quarter as a result of a 7% increase in Edmonton Sweet index pricing, partially offset by an 18% decrease in AECO pricing.
  • On a year-over-year basis, sales per boe increased by 15% and 18% for the three and six months ended June 30, 2014, largely as a result of the strengthening of the Edmonton Sweet index and AECO reference price, coupled with a higher mix of crude oil and NGL production.
  • The increases in the Edmonton Sweet index combined with incremental production from our Saskatchewan acquisition and production growth in the Cardium and Mannville resource plays resulted in a 33% and 62% increase in sales for Q2 2014 versus Q1 2014 and Q2 2013, respectively.

Royalties

  • Royalty expense as a percentage of sales increased to 11.2% for Q2 2014 from 9.6% in Q2 2013 and 10.3% in Q1 2014.  Royalty expense as a percentage of sales increased to 10.8% for the six months ended June 30, 2014 as compared to 10.1% for the same period of the prior year.
  • All periods are affected by the timing of placing wells on production due to royalty incentives on initial production volumes.  Royalties as a percentage of sales were slightly higher in the second quarter partially as a result of slightly higher average royalty rates associated with Vermilion's Saskatchewan production.  In addition, increased commodity prices have contributed to the year-over-year increases in royalty rates as a percentage of sales.

Transportation

  • Transportation expense relates to the delivery of crude oil and natural gas production to major pipelines where legal title transfers.
  • Transportation expense per boe remained consistent between Q2 2014 and Q1 2014 as higher trucking costs in the second quarter associated with Vermilion's Saskatchewan acquisition offset trucking costs incurred in the first quarter which were related to a Pembina pipeline outage.
  • Transportation expense per boe increased for the three and six months ended June 30, 2014 as compared to the same periods of the prior year due to trucking costs associated with Vermilion's recently acquired Saskatchewan assets as well as pipeline tariff increases.

Operating expense

  • Operating expense per boe was lower for the three and six months ended June 30, 2014 as compared to the prior periods presented due to a larger increase in production volumes than expenditures.

General and administration

  • General and administration expense increased in the current quarter as compared to the prior quarter largely due to  higher legal and consultant costs related to the Saskatchewan acquisition ($1.1MM), additional salary allocations from our Corporate segment  to our Canadian Business Unit to reflect internal integration effort associated with the Saskatchewan acquisition ($0.7MM), lower third party overhead recoveries as a result of less capital activity in the second quarter due to spring break-up ($1.0MM) as well as higher salary costs quarter-over-quarter resulting from increased staffing levels. These same items are the significant drivers for the year-over-year increases in general and administration expense for the periods presented, partially offset by expenditure timing.

FRANCE BUSINESS UNIT

Overview

  • Entered France in 1997 and completed three subsequent acquisitions, including two in 2012.
  • Largest oil producer by volume.
  • Producing assets include large conventional fields with high working interests located in the Aquitaine and Paris Basins with an identified inventory of workover, infill drilling, and secondary recovery opportunities.
  • Production is characterized by Brent-based crude pricing and low base decline rates.

Operational review

    Three Months Ended   % change   Six Months Ended   % change
      Jun 30,   Mar 31,   Jun 30,   Q2/14 vs.   Q2/14 vs.   Jun 30,   Jun 30,   2014 vs.
France business unit   2014   2014   2013   Q1/14   Q2/13   2014   2013   2013
Production                                
  Crude oil (bbls/d)   11,025   10,771   10,390   2%   6%   10,899   10,360   5%
  Natural gas (mmcf/d)   -   -   4.19   -   (100%)   -   4.20   (100%)
  Total (boe/d)   11,025   10,771   11,088   2%   (1%)   10,899   11,060   (1%)
Inventory (mbbls)                                
  Opening crude oil inventory   238   269   218           269   354    
  Adjustments   -   -   -           -   5    
  Crude oil production   1,003   969   945           1,973   1,875    
  Crude oil sales   (1,062)   (1,000)   (961)           (2,063)   (2,032)    
  Closing crude oil inventory   179   238   202           179   202    
Production mix (% of total)                                
  Crude oil   100%   100%   94%           100%   94%    
  Natural gas   -   -   6%           -   6%    
Activity                                
  Capital expenditures ($M)   37,614   37,967   23,223   (1%)   62%   75,581   44,815   69%
  Gross wells drilled   2.00   2.00   3.00           4.00   5.00    
  Net wells drilled   2.00   2.00   3.00           4.00   5.00    

Production

  • Quarter-over-quarter production increased 2% and year-over-year production decreased 1%. Year-over-year production of crude oil increased 6%.
  • In late September 2013, the third party Lacq processing facility that processed our Vic Bihl gas production was permanently closed.  As a result, our Vic Bihl gas production has been temporarily shut-in while preparations to transfer to an alternative facility are completed.  We expect approximately 850 mcf/d will be back on-stream in early 2015, with the remaining approximately 3,400 mcf/d not anticipated to be back on production until late-2015.
  • Production remains 100% weighted to Brent crude due to the shut-in of Vic Bihl gas production.

Activity review

  • Vermilion drilled two (2.0 net) wells in the Champotran field in the Paris Basin during Q2 2014, with production from these wells anticipated to come on-line in Q3.
  • During Q2 2014, we also completed a number of seismic and facility integrity projects.
  • Our Parentis (PS-224) well, drilled in Q2 2014, is producing 20 bbls/d.  The Cazaux North well drilled in Q1 2014 is dry and will be abandoned.
  • In 2014, we are planning a seven-well drilling program in the Champotran, Cazaux, and Parentis fields.

Financial review

      Three Months Ended   % change   Six Months Ended   % change
France business unit     Jun 30,   Mar 31,   Jun 30,   Q2/14 vs.   Q2/14 vs.   Jun 30,   Jun 30,   2014 vs.
($M except as indicated)     2014   2014   2013   Q1/14   Q2/13   2014   2013   2013
  Sales     124,617   117,560   100,418   6%   24%   242,177   221,984   9%
  Royalties     (7,796)   (7,351)   (6,093)   6%   28%   (15,147)   (12,894)   17%
  Transportation expense     (5,385)   (4,753)   (2,416)   13%   123%   (10,138)   (5,170)   96%
  Operating expense     (16,550)   (16,420)   (16,935)   1%   (2%)   (32,970)   (36,874)   (11%)
  General and administration     (5,559)   (5,194)   (3,927)   7%   42%   (10,753)   (9,613)   12%
  Current income taxes     (24,761)   (25,264)   (16,124)   (2%)   54%   (50,025)   (34,783)   44%
  Fund flows from operations     64,566   58,578   54,923   10%   18%   123,144   122,650  
Netbacks ($/boe)                                  
  Sales     117.29   117.54   98.04     20%   117.41   102.84   14%
  Royalties     (7.34)   (7.35)   (5.95)     23%   (7.34)   (5.97)   23%
  Transportation expense     (5.07)   (4.75)   (2.36)   7%   115%   (4.91)   (2.39)   105%
  Operating expense     (15.58)   (16.42)   (16.53)   (5%)   (6%)   (15.98)   (17.08)   (6%)
  General and administration     (5.24)   (5.19)   (3.83)   1%   37%   (5.21)   (4.45)   17%
  Current income taxes     (23.30)   (25.26)   (15.74)   (8%)   48%   (24.25)   (16.11)   51%
  Fund flows from operations netback     60.76   58.57   53.63   4%   13%   59.72   56.84   5%
Reference prices                                  
  Dated Brent (US $/bbl)     109.63   108.22   102.44   1%   7%   108.93   107.50   1%

Sales

  • Crude oil production in France is priced with reference to Dated Brent.
  • Sales per boe for Q2 2014 was relatively unchanged versus Q1 2014 as the 1% increase in the US dollar Dated Brent reference price was largely offset by a 1% strengthening of the Canadian dollar.
  • Sales per boe for the three and six months ended June 30, 2014 were 20% and 14% higher than the respective periods in the previous year.  This increase was primarily the result of increases in the Dated Brent reference price and the weakening of the Canadian dollar.  These changes, coupled with increased crude oil production, resulted in increased sales for both the three and six month periods ended June 30, 2014 of 24% and 9%, respectively.

Royalties

  • Royalties in France relate to two components: RCDM (levied on units of production and not subject to changes in commodity prices) and R31 (based on a percentage of revenue).
  • As a percentage of sales, royalties for the periods presented remained relatively constant.

Transportation

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

Operating expense

  • Operating expense for Q2 2014 was consistent with the Q1 2014 and Q2 2013 expense.  The decrease in the expense per boe for Q2 2014 as compared to the prior periods is associated with higher volumes in the current period.

General and administration

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

Current income taxes

  • Current income taxes in France apply to taxable income after eligible deductions at a statutory rate of 38.1% for 2014.  Following the expiration of a temporary surtax, the statutory tax rate is expected to decrease to 34.4% for the tax year 2016.  For 2014, the effective rate on current taxes is expected to be between approximately 28% and 31%. This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.
  • Current income taxes for Q2 2014 was slightly lower versus Q1 2014 as increased pre-tax fund flows from operations was offset by an increase in eligible tax deductions for depreciation.
  • On a year-over-year basis, current taxes increased by 54% and 44% for the three and six months ended June 30, 2014 versus the same periods in 2013.  These increases were the result of the absence of certain interest deductions, lower depletion for tax purposes, and higher tax rates following a December 2013 corporate tax legislation enacted by the France government which increased the rate of a temporary surtax.

NETHERLANDS BUSINESS UNIT

Overview

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

Operational review

      Three Months Ended   % change   Six Months Ended   % change
        Jun 30,   Mar 31,   Jun 30,   Q2/14 vs.   Q2/14 vs.   Jun 30,   Jun 30,   2014 vs.
Netherlands business unit     2014   2014   2013   Q1/14   Q2/13   2014   2013   2013
Production                                  
  NGLs (bbls/d)     96   69   50   39%   92%   83   73   14%
  Natural gas (mmcf/d)     40.35   43.15   38.52   (6%)   5%   41.74   37.72   11%
  Total (boe/d)     6,822   7,260   6,470   (6%)   5%   7,040   6,360   11%
Activity                                  
  Capital expenditures ($M)     21,513   20,118   4,157   7%   418%   41,631   4,529   819%
  Gross wells drilled     2.00   2.00   -           4.00   -    
  Net wells drilled     1.43   1.86   -           3.29   -    

Production

  • Quarter-over-quarter production decrease of 6% and year-over-year production growth of 5%.
  • Production in the Netherlands is currently being managed to meet corporate targets, optimize facility use and regulate declines.

Activity review

  • Vermilion drilled two (1.4 net) wells during Q2 2014. The Havelte-01 well (50% working interest) had no gas shows from the Zechstein and Vlieland targets, however the lease site of the Havelte-01 well will enable the tie in of Eesveen-01, a well located in a previously stranded gas field discovered in 1986. The Lambertschaag-02 well (93% working interest) in the Slootdorp concession was determined to be not gas bearing in its primary target zone. Lambertschaag-02 did encounter secondary zones of interest with gas shows which will be further evaluated in Q3 2014.
  • Late during Q2 2014, we initiated production from the Zechstein carbonate formation of the DeHoeve-01 well at a rate of 3 mmcf/d net to Vermilion. The DeHoeve well was drilled in 2009 and had previously produced from the Slochteren sandstone (Rotliegend).
  • An additional three wells are planned for the 2014 drilling program in the Netherlands, one is planned for the third quarter and the remaining two wells are planned for the fourth quarter. The drilling program will include our first new well on the lands acquired in October 2013.

Financial review

      Three Months Ended   % change     Six Months Ended   % change
Netherlands business unit     Jun 30,   Mar 31,   Jun 30,   Q2/14 vs.   Q2/14 vs.     Jun 30,   Jun 30,   2014 vs.
($M except as indicated)     2014   2014   2013   Q1/14   Q2/13     2014   2013   2013
  Sales     29,881   41,554   38,316   (28%)   (22%)     71,435   72,737   (2%)
  Royalties     (693)   (2,208)   -   (69%)   100%     (2,901)   -   100%
  Operating expense     (6,390)   (6,042)   (5,260)   6%   21%     (12,432)   (9,229)   35%
  General and administration     (326)   (598)   (426)   (45%)   (23%)     (924)   (838)   10%
  Current income taxes     (1,301)   (3,788)   (9,621)   (66%)   (86%)     (5,089)   (19,055)   (73%)
  Fund flows from operations     21,171   28,918   23,009   (27%)   (8%)     50,089   43,615   15%
Netbacks ($/boe)                                    
  Sales     48.14   63.60   65.08   (24%)   (26%)     56.06   63.19   (11%)
  Royalties     (1.12)   (3.38)   -   (67%)   100%     (2.28)   -   100%
  Operating expense     (10.29)   (9.25)   (8.93)   11%   15%     (9.76)   (8.02)   22%
  General and administration     (0.53)   (0.91)   (0.72)   (42%)   (26%)     (0.73)   (0.73)   -
  Current income taxes     (2.10)   (5.80)   (16.34)   (64%)   (87%)     (3.99)   (16.55)   (76%)
  Fund flows from operations netback     34.10   44.26   39.09   (23%)   (13%)     39.30   37.89   4%
Reference prices                                    
  TTF ($/GJ)     7.91   10.19   10.14   (22%)   (22%)     9.02   10.23   (12%)
  TTF (€/GJ)     5.27   6.75   7.57   (22%)   (30%)     6.01   7.69   (22%)

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 decreases in sales and sales per boe in Q2 2014 versus Q1 2014 and Q2 2013 were largely in-line with the change in the Canadian dollar TTF reference price.
  • On a year-over-year basis, sales declined by 2% as a result of the 12% decrease in the TTF reference price offset by an 11% increase in production.

Royalties

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

Transportation expense

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

Operating expense

  • Operating expense increased in Q2 2014 from Q1 2014 due to the timing of major project expense.  Lower volumes quarter-over-quarter also contributed to the increase in operating costs on a per boe basis.
  • Year-over-year, operating expense increased for both the quarter and year to date periods due to the strengthening of the Euro versus the Canadian dollar as well as higher salary costs associated with continued organic growth in the Netherlands business unit.

General and administration

  • General and administration expense decreased in Q2 2014 from Q1 2014 due to a reduction in project-related consultant costs.  As compared to the prior year, general and administration expense for the current quarter and year to date periods remained consistent.

Current income taxes

  • Current income taxes in the Netherlands apply to taxable income after eligible deductions at a statutory tax rate of approximately 46%. For 2014, the effective rate on current taxes is expected to be between approximately 6% and 8%. This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.
  • Current income taxes decreased as compared to both Q1 2014 and Q2 2013 as a result of decreased revenues, lower TTF reference prices and an increase in tax deductions for depletion during the current quarter.

GERMANY BUSINESS UNIT

Overview

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

Operational review

                        Three Months Ended     % change     Six Months Ended
                        Jun 30, Mar 31,     Q2/14 vs.     Jun 30,
Germany business unit                     2014 2014     Q1/14     2014
Production                                    
  Natural gas (mmcf/d)                     16.13 10.64     52%     13.40
  Total (boe/d)                     2,689 1,773     52%     2,234
Activity                                    
  Capital expenditures ($M)                     630 196     221%     826
  Acquisitions ($M)                     - 172,871           172,871

Production

  • Achieved Q2 2014 production of 2,689 boe/d, an increase of 52% as compared to 1,773 boe/d in Q1 2014, taking into account an effective date for production of February 1, 2014.

Activity review

  • Continued the integration of the German business with our working interest partners and have commenced planning for future wells.
  • In Q1 2014, we participated in the drilling of one (0.25 net) development well, which logged 81 metres of net pay and is expected to be tested and put on production during the second half of 2014.
  • We have hired a Managing Director for the German business unit and have opened an office outside of Berlin, which we are currently outfitting and staffing.

Financial review

        Three Months Ended     % change     Six Months Ended
Germany business unit     Jun 30, Mar 31,     Q2/14 vs.     Jun 30,
($M except as indicated)     2014 2014     Q1/14     2014
  Sales     11,097 8,915     24%     20,012
  Royalties     (2,284) (1,802)     27%     (4,086)
  Transportation expense     (1,052) (422)     149%     (1,474)
  Operating expense     (2,043) (1,554)     31%     (3,597)
  General and administration     (830) (568)     46%     (1,398)
  Current income taxes     (506) (537)     (6%)     (1,043)
  Fund flows from operations     4,382 4,032     9%     8,414
Netbacks ($/boe)                    
  Sales     45.36 55.85     (19%)     49.50
  Royalties     (9.34) (11.29)     (17%)     (10.11)
  Transportation expense     (4.30) (2.64)     63%     (3.65)
  Operating expense     (8.35) (9.74)     (14%)     (8.90)
  General and administration     (3.39) (3.56)     (5%)     (3.46)
  Current income taxes     (2.07) (3.36)     (38%)     (2.58)
  Fund flows from operations netback     17.91 25.26     (29%)     20.80
Reference prices                    
  TTF ($/GJ)     7.91 10.19     (22%)     9.02
  TTF (€/GJ)     5.27 6.75     (22%)     6.01

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 for Q2 2014 were 24% higher due to the inclusion of a full quarter of production in Q2 2014 versus two months of production in Q1 2014.
  • Sales per boe decreased by 19% from Q1 2014 due to a decrease in the TTF reference price.

Royalties expense

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

Transportation expense

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

Operating expense

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

General and administration

  • Included in general and administration costs are expenditures totalling $0.8 million relating to legal and consulting costs associated with the acquisition.

Current income taxes

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

IRELAND BUSINESS UNIT

Overview

  • 18.5% non-operating interest in the offshore Corrib gas field located approximately 83km off the northwest coast of Ireland.
  • Project comprises six offshore wells, both offshore and onshore pipeline segments as well as a natural gas processing facility.
  • Production from Corrib is expected to increase Vermilion's volumes by approximately 58 mmcf/d (9,700 boe/d) once the field reaches peak production.

Operational and financial review

        Three Months Ended   % change     Six Months Ended   % change
Ireland business unit       Jun 30,     Mar 31,     Jun 30,   Q2/14 vs.   Q2/14 vs.     Jun 30,     Jun 30,   2014 vs.
($M)       2014     2014     2013   Q1/14   Q2/13     2014     2013   2013
  Transportation expense       (1,571)     (1,588)     (1,626)   (1%)   (3%)     (3,159)     (3,244)   (3%)
  General and administration       (252)     (282)     (410)   (11%)   (39%)     (534)     (647)   (17%)
  Fund flows from operations       (1,823)     (1,870)     (2,036)   (3%)   (10%)     (3,693)     (3,891)   (5%)
Activity                                            
  Capital expenditures       27,221     16,236     24,878   68%   9%     43,457     41,398   5%

Activity review

  • Completed tunnel boring operations beneath Sruwaddacon Bay on May 21, 2014. The tunnel boring machine has been demobilized and we are progressing with remaining activities to bring the project on production, including the installation of flow and umbilical lines within the tunnel, grouting of the tunnel, and certain offshore well workover activities.
  • Based on our deterministic schedule for remaining construction and commissioning activities, we anticipate first gas in approximately mid-2015 with peak production of approximately 58 mmcf/d (9,700 boe/d), net to Vermilion.

Transportation expense

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

AUSTRALIA BUSINESS UNIT

Overview

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

Operational review

        Three Months Ended   % change     Six Months Ended   % change
          Jun 30,     Mar 31,     Jun 30,   Q2/14 vs.   Q2/14 vs.     Jun 30,     Jun 30,   2014 vs.
Australia business unit       2014     2014     2013   Q1/14   Q2/13     2014     2013   2013
Production                                            
  Crude oil (bbls/d)       6,483     7,110     7,363   (9%)   (12%)     6,795     6,331   7%
Inventory (mbbls)                                            
  Opening crude oil inventory       63     130     165             130     268    
  Crude oil production       590     640     670             1,230     1,146    
  Crude oil sales       (464)     (707)     (648)             (1,171)     (1,227)    
  Closing crude oil inventory       189     63     187             189     187    
Activity                                            
  Capital expenditures ($M)       10,991     5,691     8,282   93%   33%     16,682     63,631   (74%)
  Gross wells drilled       -     -     -             -     2.00    
  Net wells drilled       -     -     -             -     2.00    

Production

  • Wandoo production decreased by 9% quarter-over-quarter and 12% year-over-year.
  • Production volumes are managed to meet customer demands and long-term supply agreements.  We continue to plan for production levels of between 6,000 and 8,000 bbls/d.
  • Production continues to reflect strong well results from the 2013 drilling program, more than offsetting natural declines.  We continue to produce the wells at restricted rates below their demonstrated productive capacity.

Activity review

  • In Q2 2014, efforts were focused on facilities repairs and engineering studies, including the expansion of accommodation quarters on the Wandoo B platform and repair of the A5 conductor on Wandoo A.
  • 2014 planned activities include ongoing facilities maintenance, enhancement, and refurbishment along with preparation and permitting activities in advance of our planned 2015 drilling program.

Financial review

      Three Months Ended   % change   Six Months Ended   % change
Australia business unit     Jun 30,   Mar 31,   Jun 30,   Q2/14 vs.   Q2/14 vs.   Jun 30,   Jun 30,   2014 vs.
($M except as indicated)     2014   2014   2013   Q1/14   Q2/13   2014   2013   2013
  Sales     58,828   89,974   72,282   (35%)   (19%)   148,802   142,183   5%
  Operating expense     (12,051)   (17,360)   (9,912)   (31%)   22%   (29,411)   (24,738)   19%
  General and administration     (1,661)   (1,206)   (1,378)   38%   21%   (2,867)   (2,896)   (1%)
  Corporate income taxes     (5,689)   (8,841)   (10,646)   (36%)   (47%)   (14,530)   (17,859)   (19%)
  PRRT     (12,699)   (20,239)   (12,590)   (37%)   1%   (32,938)   (23,743)   39%
  Fund flows from operations     26,728   42,328   37,756   (37%)   (29%)   69,056   72,947   (5%)
Netbacks ($/boe)                                  
  Sales     126.87   127.26   111.54   -   14%   127.11   115.89   10%
  Operating expense     (25.99)   (24.55)   (15.30)   6%   70%   (25.12)   (20.16)   25%
  General and administration     (3.58)   (1.71)   (2.13)   109%   68%   (2.45)   (2.36)   4%
  Corporate income taxes     (12.27)   (12.51)   (16.43)   (2%)   (25%)   (12.41)   (14.56)   (15%)
  PRRT     (27.39)   (28.63)   (19.43)   (4%)   41%   (28.14)   (19.35)   45%
  Fund flows from operations netback     57.64   59.86   58.25   (4%)   (1%)   58.99   59.46   (1%)
Reference prices                                  
  Dated Brent (US $/bbl)     109.63   108.22   102.44   1%   7%   108.93   107.50   1%

Sales

  • Our production in Australia currently receives a premium to Dated Brent.
  • Sales per boe increased for the three and six months ended June 30, 2014 versus the comparable periods in the prior year as a result of an increase in the Dated Brent reference price combined with the impact of the weakening Canadian dollar.
  • Sales increased for the six months ended June 30, 2014 versus 2013, despite slightly lower sold volumes, primarily as a result of the impacts of the weakening of the Canadian dollar, which resulted in a 10% increase in sales per boe.
  • Sales for Q2 2014 versus Q1 2014 and Q2 2013 were 35% and 19% lower, respectively, primarily as a result of a build in crude oil inventory (126,000 bbl) during Q2 2014.

Royalties and transportation expense

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

Operating expense

  • Operating expense per boe for Q2 2014 remained consistent with the expense for Q1 2014.
  • Operating expense per boe for the three and six months ended June 30, 2014 was higher than the expense for the comparative periods in the prior year due to increased diesel usage and higher salary costs.

General and administration

  • General and administration expense increased slightly during Q2 2014 as compared to Q1 2014 and Q2 2013 due to timing of expenditures.
  • For the year to date period ended June 30, 2014, general and administration expense remained consistent with the expense for the same period of the prior year.

PRRT and corporate income taxes

  • In Australia, current income taxes include both PRRT and corporate income taxes. PRRT is a profit based tax applied at a rate of 40% on sales less eligible expenditures, including operating expenses and capital expenditures.  Corporate income taxes are applied at a rate of 30% on taxable income after eligible deductions, which include PRRT.
  • For 2014, the combined corporate income tax and PRRT effective rate is expected to be between approximately 38% and 42%.  This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.
  • Combined corporate income taxes and PRRT movements for the three and six months ended June 30, 2014 versus the comparable periods was 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.

CORPORATE

Overview

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

Financial review

        Three Months Ended   Six Months Ended
        Jun 30,     Mar 31,     Jun 30,   Jun 30,     Jun 30,
($M)       2014     2014     2013   2014     2013
General and administration       (2,574)     (3,751)     (1,224)   (6,325)     (2,912)
Current income taxes       (378)     (173)     (328)   (551)     (579)
Interest expense       (12,334)     (11,460)     (9,336)   (23,794)     (18,025)
Realized gain (loss) on derivatives       2,419     2,640     1,770   5,059     (1,017)
Realized foreign exchange gain (loss)       587     (2,041)     1,272   (1,454)     655
Realized other income       74     221     77   295     549
Fund flows from operations       (12,206)     (14,564)     (7,769)   (26,770)     (21,329)

General and administration

  • The decrease in general and administration costs for Q2 2014 versus Q1 2014 was primarily the result of the Q1 2014 impact of certain outstanding VIP awards to be settled partially in cash.
  • On a year-over-year basis, the increase in general and administration costs for the six months ended June 30, 2013 to the same period in 2014 was a result of the impact of certain outstanding VIP awards to be settled partially in cash.

Current income taxes

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

Interest expense

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

Hedging

  • The nature of our operations results in exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates.  We monitor and, when appropriate, use derivative financial instruments to manage our exposure to these fluctuations.  All transactions of this nature entered into are related to an underlying financial position or to future crude oil and natural gas production. We do not use derivative financial instruments for speculative purposes.  We have elected not to designate any of our derivative financial instruments as accounting hedges and thus account for changes in fair value in net earnings at each reporting period.  We have not obtained collateral or other security to support our financial derivatives as we review the creditworthiness of our counterparties prior to entering into derivative contracts.
  • Our hedging philosophy is to hedge solely for the purposes of risk mitigation.  Our approach is to hedge centrally to manage our global risk (typically with an outlook of 12 to 18 months) with a goal of securing pricing for up to 50% of net of royalty volumes through a portfolio of forward collars, swaps, and physical fixed price arrangements.
  • We believe that our hedging philosophy and approach increases the stability of revenues, cash flows and future dividends while assisting in the execution of our capital and development plans.
  • The realized gain in 2014 related primarily to amounts received on our TTF derivatives, partially offset by payments made on our crude oil and AECO derivatives.
  • A listing of derivative positions as at June 30, 2014 is included in "Supplemental Table 2" in this MD&A.

FINANCIAL PERFORMANCE REVIEW

        Three Months Ended
          Jun 30,   Mar 31,   Dec 31,   Sep 30,   Jun 30,   Mar 31,   Dec 31,   Sep 30,
($M except per share)       2014   2014   2013   2013   2013   2013   2012   2012
Petroleum and natural gas sales       387,684   81,183   325,108   327,185   311,966   309,576   241,233   284,838
Net earnings       53,993   102,788   101,510   67,796   106,198   52,137   56,914   30,798
Net earnings per share                                    
  Basic       0.51   1.00   1.00   0.67   1.05   0.53   0.58   0.31
  Diluted       0.50   0.99   0.98   0.66   1.04   0.51   0.57   0.31

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

($M)           Q2/14 vs. Q1/14       Q2/14 vs. Q2/13         2014 vs. 2013
Net earnings - Comparative period           102,788       106,198         158,335
Changes in:                              
Fund flows from operations           10,713       41,484         83,218
Equity based compensation           (1,745)       (7,493)         (7,829)
Unrealized gain or loss on derivative instruments           (5,456)       (10,172)         (5,124)
Unrealized foreign exchange gain or loss           (45,746)       (51,771)         (27,252)
Unrealized other income           358       452         603
Accretion           (238)       50         162
Depletion and depreciation           (5,450)       (26,484)         (44,488)
Deferred tax           (1,231)       1,729         (844)
Net earnings - Current Period           53,993       53,993         156,781

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

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

Equity based compensation expense for the three and six months ended June 30, 2014 was higher than the same periods in 2013 as a result of an upward revision of future performance condition assumptions during Q2 2014.  Equity based compensation expense is also higher for Q2 2014 as compared to Q1 2014 as the impact of the revision in future performance condition assumptions was partially offset by awards vested during Q2 2014.

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

In the six months ended June 30, 2014, we recognized an unrealized gain of $2.4 million, relating primarily to our TTF derivative instruments, partially offset by our crude oil and Canadian natural gas derivative instruments.  As at June 30, 2014, we have a net current derivative liability of approximately $0.2 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 and six months ended June 30, 2014, the Canadian dollar strengthened versus the Euro resulting in unrealized foreign exchange losses of $23.7 million and $1.7 million, respectively.

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

Q2 2014 accretion expense was relatively consistent as compared to Q1 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.

Q2 2014 production as compared to Q1 2014 and the comparable periods in 2013 increased by 12%, 22% and 21%, respectively, resulting in higher depletion and depreciation expense of 5%, 33% and 28%, respectively.

Depletion and depreciation on a per boe basis for Q2 2014 of $22.45/boe was lower as compared to Q1 2014 of $23.13/boe as a result of increased production in Canada.  Depletion and depreciation on a per boe basis increased for the three and six month periods ended June 30, 2014 to $22.45/boe and $22.78/boe, respectively, as compared to the same periods in 2013 of $20.16/boe and $20.99/boe, respectively.  The increase on a per boe basis was largely due to Vermilion's increased capital and acquisition activity which results in higher per boe amounts as 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.

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 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.

Absent additional material acquisitions, Vermilion currently expects the net debt to fund flows ratio to return to our internally targeted ratio over the next 12 to 24 months as a result of incremental cash flows from Corrib and our acquisitions in Germany and Canada.

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

            Annual Interest Rate     As At
            Jun 30,   Dec 31,     Jun 30,   Dec 31,
($M)           2014   2013     2014   2013
Revolving credit facility           3.3%   3.3%     975,297   766,898
Senior unsecured notes           6.5%   6.5%     223,569   223,126
Long-term debt           3.9%   4.7%     1,198,866   990,024

Revolving Credit Facility

Our revolving credit facility bears interest at rates applicable to demand loans plus applicable margins.  The following table outlines the terms of our revolving credit facility:

            As At
            Jun 30,   Dec 31,
            2014    2013 
Total facility amount 1           $1.50 billion   $1.20 billion
Amount drawn           $975.3 million   $766.9 million
Letters of credit outstanding           $10.2 million   $8.1 million
Facility maturity date           31-May-17   31-May-16

(1)    We 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.

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

             As At
                Jun 30,     Dec 31,
Financial covenant       Limit       2014      2013 
Consolidated total debt to consolidated EBITDA       4.0       1.17     1.06
Consolidated total senior debt to consolidated EBITDA       3.0       0.95     0.82
Consolidated total senior debt to total capitalization       50%       30%     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

We may redeem all or part of the notes at fixed redemption prices plus in each case, accrued and unpaid interest, if any, to the applicable redemption date.  The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

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

        As At
        Jun 30,   Dec 31,
($M)       2014   2013
Long-term debt       1,198,866   990,024
Current liabilities       377,710   347,444
Current assets       (407,578)   (587,783)
Net debt        1,168,998   749,685
             
Ratio of net debt to annualized fund flows from operations       1.4   1.1

Long-term debt as at June 30, 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 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 $1.2 billion.

As the increase to long-term debt occurred to fund acquisitions, which contributed to fund flows from operations for only a portion of 2014, the year-to-date ratio of net debt to annualized fund flows from operations increased from 1.1 as at December 31, 2013 to 1.4 as at June 30, 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 six months ended June 30, 2014, we maintained monthly dividends at $0.215 per share and declared dividends totalled $134.7 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
Beginning January 2014           $0.215

Our policy with respect to dividends is to be conservative and maintain a low ratio of dividends to fund flows from operations.  During low price commodity cycles, we will initially maintain dividends and allow the ratio to rise.  Should low commodity price cycles remain for an extended period of time, we will evaluate the necessity of changing the level of dividends, taking into consideration capital development requirements, debt levels and acquisition opportunities.

Over the next two years, we anticipate that Corrib, Cardium and other exploration and development activities will require significant capital investment.  Although we currently expect to be able to maintain our current dividend, fund flows from operations may not be sufficient during this period to fund cash dividends, capital expenditures and asset retirement obligations.  We will evaluate our ability to finance any shortfalls with debt, issuances of equity or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.

The following table reconciles the change in shareholders' capital:

Shareholders' Capital       Number of Shares ('000s)       Amount ($M)
Balance as at December 31, 2013       102,123       1,618,443
Shares issued pursuant to corporate acquisition       2,827       204,960
Issuance of shares pursuant to the dividend reinvestment plan       601       38,034
Vesting of equity based awards       950       47,657
Share-settled dividends on vested equity based awards       108       7,519
Shares issued pursuant to the bonus plan       11       721
Balance as at June 30, 2014       106,620       1,917,334

As at June 30, 2014, there were approximately 1.7 million VIP awards outstanding.  As at July 30, 2014, there were approximately 106.7 million shares outstanding.

ASSET RETIREMENT OBLIGATIONS

As at June 30, 2014, asset retirement obligations were $390.1 million compared to $326.2 million as at December 31, 2013.

The increase in asset retirement obligations is largely attributable to an overall decrease in the discount rates applied to the abandonment obligations, accretion, and additions from new wells drilled during the year and abandonment obligations associated with the assets acquired in Germany and Canada.  

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 June 30, 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 impact of the adoption of the following pronouncement is currently being evaluated.

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.

RISK MANAGEMENT

Vermilion is exposed to various market and operational risks.  For a detailed discussion of these risks, please see Vermilion's Annual Report for the year ended December 31, 2013.

CRITICAL ACCOUNTING ESTIMATES

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

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

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

INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Supplemental Table 1: Netbacks

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

    Three Months Ended June 30, 2014   Six Months Ended June 30, 2014   Three Months
Ended June
30, 2013
  Six Months
Ended June
30, 2013
    Oil & NGLs   Natural Gas   Total   Oil & NGLs   Natural Gas   Total   Total   Total
    $/bbl   $/mcf   $/boe   $/bbl   $/mcf   $/boe   $/boe   $/boe
Canada                                
Sales   98.82    4.60    71.56    97.30    5.02    70.55    62.00    59.93 
Royalties   (11.84)   (0.30)   (7.99)   (11.38)   (0.32)   (7.61)   (5.96)   (6.07)
Transportation   (2.22)   (0.17)   (1.76)   (2.24)   (0.17)   (1.75)   (1.60)   (1.58)
Operating   (9.29)   (1.55)   (9.28)   (10.01)   (1.37)   (9.31)   (9.81)   (9.68)
Operating netback   75.47    2.58    52.53    73.67    3.16    51.88    44.63    42.60 
General and administration           (2.88)           (2.32)   (2.42)   (2.28)
Fund flows from operations netback           49.65            49.56    42.21    40.32 
France                                
Sales   117.29      117.29    117.41      117.41    98.04    102.84 
Royalties   (7.34)     (7.34)   (7.34)     (7.34)   (5.95)   (5.97)
Transportation   (5.07)     (5.07)   (4.91)     (4.91)   (2.36)   (2.39)
Operating   (15.58)     (15.58)   (15.98)     (15.98)   (16.53)   (17.08)
Operating netback   89.30      89.30    89.18      89.18    73.20    77.40 
General and administration           (5.24)           (5.21)   (3.83)   (4.45)
Current income taxes           (23.30)           (24.25)   (15.74)   (16.11)
Fund flows from operations netback           60.76            59.72    53.63    56.84 
Netherlands                                
Sales   93.76    7.91    48.14    99.23    9.26    56.06    65.08    63.19 
Royalties     (0.19)   (1.12)     (0.38)   (2.28)    
Operating     (1.74)   (10.29)     (1.65)   (9.76)   (8.93)   (8.02)
Operating netback   93.76    5.98    36.73    99.23    7.23    44.02    56.15    55.17 
General and administration           (0.53)           (0.73)   (0.72)   (0.73)
Current income taxes           (2.10)           (3.99)   (16.34)   (16.55)
Fund flows from operations netback           34.10            39.30    39.09    37.89 
Germany                                
Sales     7.56    45.36      8.25    49.50     
Royalties     (1.56)   (9.34)     (1.68)   (10.11)    
Transportation     (0.72)   (4.30)     (0.61)   (3.65)    
Operating     (1.39)   (8.35)     (1.48)   (8.90)    
Operating netback     3.89    23.37      4.48    26.84     
General and administration           (3.39)           (3.46)    
Current income taxes           (2.07)           (2.58)    
Fund flows from operations netback           17.91            20.80     
Australia                                
Sales   126.87      126.87    127.11      127.11    111.54    115.89 
Operating   (25.99)     (25.99)   (25.12)     (25.12)   (15.30)   (20.16)
PRRT (1)   (27.39)     (27.39)   (28.14)     (28.14)   (19.43)   (19.35)
Operating netback   73.49      73.49    73.85      73.85    76.81    76.38 
General and administration           (3.58)           (2.45)   (2.13)   (2.36)
Corporate income taxes           (12.27)           (12.41)   (16.43)   (14.56)
Fund flows from operations netback           57.64            58.99    58.25    59.46 
Total Company                                
Sales   109.89    6.19    82.96    110.73    7.04    85.70    80.21    81.60 
Realized hedging (loss) gain   (0.66)   0.42    0.52    (0.21)   0.32    0.56    0.46    (0.13)
Royalties   (8.31)   (0.44)   (6.21)   (7.54)   (0.51)   (5.91)   (4.06)   (4.15)
Transportation   (2.89)   (0.34)   (2.57)   (2.74)   (0.32)   (2.44)   (1.71)   (1.75)
Operating   (14.16)   (1.59)   (12.46)   (15.26)   (1.49)   (12.95)   (12.36)   (13.21)
PRRT (1)   (4.32)     (2.72)   (5.79)     (3.67)   (3.24)   (3.12)
Operating netback   79.55    4.24    59.52    79.19    5.04    61.29    59.30    59.24 
General and administration           (3.80)           (3.59)   (2.91)   (3.14)
Interest expense           (2.64)           (2.65)   (2.40)   (2.37)
Realized foreign exchange gain (loss)           0.12            (0.16)   0.33    0.09 
Other income           0.02            0.03    0.02    0.07 
Corporate income taxes (1)           (6.98)           (7.94)   (9.44)   (9.49)
Fund flows from operations netback           46.24            46.98    44.90    44.40 

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

Supplemental Table 2: Hedges

The following table summarizes Vermilion's outstanding risk management positions as at June 30, 2014:

    Note   Volume   Strike Price(s)
Crude Oil            
WTI - Swap            
May 2014 - July 2014     500 bbl/d   101.12 CAD $
July 2014 - December 2014       750 bbl/d   99.00 USD $
July 2014       1,000 bbl/d   99.95 USD $
July 2014     1,000 bbl/d   103.63 USD $
July 2014 - September 2014       1,250 bbl/d   108.53 CAD $
July 2014 - September 2014     1,250 bbl/d   101.33 USD $
May 2014 - November 2014     250 bbl/d   97.25 CAD $
Dated Brent - Collar            
April 2014 - September 2014       1,000 bbl/d   105.00 - 112.00 USD $
April 2014 - December 2014       1,000 bbl/d   106.00 - 110.73 USD $
Dated Brent - Swap            
January 2014 - December 2014       500 bbl/d   108.28 USD $
July 2014 - September 2014       350 bbl/d   111.75 USD $
July 2014 - September 2014     1,000 bbl/d   110.00 USD $
July 2014 - December 2014       1,000 bbl/d   109.64 USD $
July 2014 - December 2014     500 bbl/d   109.40 USD $
ICE Brent less WTI - Fixed Spread            
July 2014 - September 2014       500 bbl/d   5.99 USD $
MSW - Fixed Price Differential (Physical)            
April 2014 - December 2014       1,030 bbl/d   WTI less 8.20 USD $
July 2014 - December 2014       2,052 bbl/d   WTI less 8.68 USD $
             
Canadian Natural Gas            
AECO - Collar            
January 2014 - December 2014       10,000 GJ/d   3.18 - 3.81 CAD $
April 2014 - December 2014       1,000 GJ/d   3.60 - 3.96 CAD $
April 2014 - March 2015       2,500 GJ/d   3.60 - 4.08 CAD $
November 2014 - March 2015       2,500 GJ/d   3.60 - 4.27 CAD $
AECO - Swap            
January 2014 - December 2014       5,000 GJ/d   3.71 CAD $
April 2014 - October 2014       8,000 GJ/d   4.00 CAD $
             
European Natural Gas            
TTF - Swap            
March 2014 - September 2014       5,400 GJ/d   6.62 EUR €
April 2014 - September 2014       16,200 GJ/d   6.74 EUR €
             
Electricity            
AESO - Swap            
January 2014 - December 2014       7.2 MWh/d   54.75 CAD $
AESO - Swap (Physical)            
January 2013 - December 2015       72.0 MWh/d   53.17 CAD $
             
US Dollar            
USD - Collar            
July 2014 - September 2014       5,000,000 USD $/month   1.070 - 1.116 CAD $
July 2014 - September 2014     4,500,000 USD $/month   1.077 - 1.099 CAD $

(1)  Assumed as part of Vermilion's April 29, 2014 acquisition of Elkhorn Resources Inc.
(2) Prior to the expiration of this swap, the counterparty has the option to extend the swap to August 31, 2014 at the contracted volume and price.
(3)  Prior to the expiration of this swap, the counterparty has the option to extend the swap to December 31, 2014 at the contracted volume and price.
(4)  Prior to the expiration of this swap, the counterparty has the option to extend the swap to June 30, 2015 at the contracted volume and price.
(5) Vermilion has upside participation on this hedge up to the limit price of 1.152 CAD; above which, settlement will occur at the conditional call level of 1.099CAD.

Supplemental Table 3: Capital Expenditures

    Three Months Ended   Six Months Ended
By classification   Jun 30, Mar 31, Jun 30,   Jun 30, Jun 30,
($M)   2014 2014 2013   2014 2013
Drilling and development   117,975 168,840 75,005   286,815 254,525
Dispositions   - - -   - (8,627)
Exploration and evaluation   17,098 27,535 3,113   44,633 12,689
Capital expenditures   135,073 196,375 78,118   331,448 258,587
Property acquisition   - 178,227 -   178,227 -
Corporate acquisition   381,139 - -   381,139 -
Acquisitions   381,139 178,227 -   559,366 -
               
    Three Months Ended   Six Months Ended
By category   Jun 30, Mar 31, Jun 30,   Jun 30, Jun 30,
($M)   2014 2014 2013   2014 2013
Land   950 4,753 2,307   5,703 5,436
Seismic   1,869 3,432 5,569   5,301 9,382
Drilling and completion   42,083 106,536 20,235   148,619 146,420
Production equipment and facilities   60,547 68,755 40,819   129,302 90,761
Recompletions   13,459 4,226 4,510   17,685 8,641
Other   16,165 8,673 4,678   24,838 6,574
Dispositions   - - -   - (8,627)
Capital expenditures   135,073 196,375 78,118   331,448 258,587
Acquisitions   381,139 178,227 -   559,366 -
Total capital expenditures and acquisitions   516,212 374,602 78,118   890,814 258,587
               
    Three Months Ended     Six Months Ended
By country   Jun 30, Mar 31, Jun 30,   Jun 30, Jun 30,
($M)   2014 2014 2013   2014 2013
Canada   418,294 119,707 16,553   538,001 101,682
France   37,614 37,967 23,223   75,581 44,815
Netherlands   21,513 20,118 4,157   41,631 4,529
Germany   630 173,067 -   173,697 -
Ireland   27,221 16,236 24,878   43,457 41,398
Australia   10,991 5,691 8,282   16,682 63,631
Corporate   (51) 1,816 1,025   1,765 2,532
Total capital expenditures and acquisitions   516,212 374,602 78,118   890,814 258,587

Supplemental Table 4: Production

      Q2/14   Q1/14   Q4/13   Q3/13   Q2/13   Q1/13   Q4/12   Q3/12   Q2/12   Q1/12   Q4/11   Q3/11
Canada                                                  
  Crude oil (bbls/d)   12,676    9,437    8,719    7,969    8,885    7,966    7,983    7,322    7,757    7,574    6,591    4,526 
  NGLs (bbls/d)   2,796    2,071    1,699    1,897    1,725    1,335    1,106    1,204    1,321    1,302    1,246    1,305 
  Natural gas (mmcf/d)   57.59    49.53    41.43    43.40    43.69    41.04    31.41    35.54    41.32    41.83    43.96    42.94 
  Total (boe/d)   25,070    19,763    17,322    17,099    17,892    16,140    14,323    14,449    15,965    15,848    15,163    12,987 
  % of consolidated   49%   42%   43%   41%   42%   41%   40%   40%   40%   40%   41%   38%
France                                                  
  Crude oil (bbls/d)   11,025    10,771    11,131    11,625    10,390    10,330    9,843    9,767    9,931    10,270    7,819    7,946 
  Natural gas (mmcf/d)         5.23    4.19    4.21    3.91    3.39    3.57    3.48    0.94    0.97 
  Total (boe/d)   11,025    10,771    11,131    12,496    11,088    11,032    10,495    10,333    10,526    10,850    7,976    8,108 
  % of consolidated   21%   23%   27%   30%   26%   29%   29%   28%   27%   28%   22%   23%
Netherlands                                                  
  NGLs (bbls/d)   96    69    62    48    50    96    70    41    84    72    66    64 
  Natural gas (mmcf/d)   40.35    43.15    37.53    28.78    38.52    36.91    33.03    34.59    33.74    35.08    34.58    33.15 
  Total (boe/d)   6,822    7,260    6,318    4,845    6,470    6,248    5,574    5,806    5,707    5,919    5,829    5,589 
  % of consolidated   13%   16%   15%   12%   15%   16%   15%   16%   15%   15%   16%   16%
Germany                                                  
  Natural gas (mmcf/d)   16.13    10.64                     
  Total (boe/d)   2,689    1,773                     
  % of consolidated   5%   4%                    
Australia                                                  
  Crude oil (bbls/d)   6,483    7,110    6,189    7,070    7,363    5,287    5,873    5,958    6,970    6,648    7,686    7,992 
  % of consolidated   12%   15%   15%   17%   17%   14%   16%   16%   18%   17%   21%   23%
Consolidated                                                  
  Crude oil & NGLs (bbls/d)   33,076    29,458    27,800    28,609    28,413    25,014    24,875    24,292    26,063    25,866    23,408    21,833 
  % of consolidated   63%   63%   68%   69%   66%   65%   69%   66%   67%   66%   64%   63%
  Natural gas (mmcf/d)   114.08    103.32    78.96    77.41    86.40    82.16    68.34    73.52    78.63    80.39    79.48    77.06 
  % of consolidated   37%   37%   32%   31%   34%   35%   31%   34%   33%   34%   36%   37%
  Total (boe/d)   52,089    46,677    40,960    41,510    42,813    38,707    36,265    36,546    39,168    39,265    36,654    34,676 
                                                   
      YTD 2014   2013   2012   2011   2010   2009                        
Canada                                                  
  Crude oil (bbls/d)   11,065    8,387    7,659    4,701    2,778    2,137                         
  NGLs (bbls/d)   2,435    1,666    1,232    1,297    1,427    1,518                         
  Natural gas (mmcf/d)   53.58    42.39    37.50    43.38    43.91    47.85                         
  Total (boe/d)   22,430    17,117    15,142    13,227    11,524    11,629                         
  % of consolidated   45%   41%   40%   38%   36%   37%                        
France                                                  
  Crude oil (bbls/d)   10,899    10,873    9,952    8,110    8,347    8,246                         
  Natural gas (mmcf/d)     3.40    3.59    0.95    0.92    1.05                         
  Total (boe/d)   10,899    11,440    10,550    8,269    8,501    8,421                         
  % of consolidated   22%   28%   28%   23%   26%   27%                        
Netherlands                                                  
  NGLs (bbls/d)   83    64    67    58    35    23                         
  Natural gas (mmcf/d)   41.74    35.42    34.11    32.88    28.31    21.06                         
  Total (boe/d)   7,040    5,967    5,751    5,538    4,753    3,533                         
  % of consolidated   14%   15%   15%   16%   15%   11%                        
Germany                                                  
  Natural gas (mmcf/d)   13.40                                   
  Total (boe/d)   2,234                                   
  % of consolidated   5%                                  
Australia                                                  
  Crude oil (bbls/d)   6,795    6,481    6,360    8,168    7,354    7,812                         
  % of consolidated   14%   16%   17%   23%   23%   25%                        
Consolidated                                                  
  Crude oil & NGLs (bbls/d)   31,277    27,471    25,270    22,334    19,941    19,735                         
  % of consolidated   63%   67%   67%   63%   62%   63%                        
  Natural gas (mmcf/d)   108.73    81.21    75.20    77.21    73.14    69.96                         
  % of consolidated   37%   33%   33%   37%   38%   37%                        
  Total (boe/d)   49,398    41,005    37,803    35,202    32,132    31,395                         

Supplemental Table 5: Segmented Financial Results

    Three Months Ended June 30, 2014
($M)   Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Drilling and development   26,071   34,828   18,234   630   27,221   10,991   -   117,975
Exploration and evaluation   10,897   2,786   3,279   -   -   -   136   17,098
Oil and gas sales to external customers   163,261   124,617   29,881   11,097   -   58,828   -   387,684
Royalties   (18,240)   (7,796)   (693)   (2,284)   -   -   -   (29,013)
Revenue from external customers   145,021   116,821   29,188   8,813   -   58,828   -   358,671
Transportation expense   (4,024)   (5,385)   -   (1,052)   (1,571)   -   -   (12,032)
Operating expense   (21,179)   (16,550)   (6,390)   (2,043)   -   (12,051)   -   (58,213)
General and administration   (6,560)   (5,559)   (326)   (830)   (252)   (1,661)   (2,574)   (17,762)
PRRT   -   -   -   -   -   (12,699)   -   (12,699)
Corporate income taxes   -   (24,761)   (1,301)   (506)   -   (5,689)   (378)   (32,635)
Interest expense   -   -   -   -   -   -   (12,334)   (12,334)
Realized gain on derivative instruments   -   -   -   -   -   -   2,419   2,419
Realized foreign exchange gain   -   -   -   -   -   -   587   587
Realized other income   -   -   -   -   -   -   74   74
Fund flows from operations   113,258   64,566   21,171   4,382   (1,823)   26,728   (12,206)   216,076

    Six Months Ended June 30, 2014
($M)   Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Total assets   1,854,501   916,712   235,723   174,735   799,394   277,624   125,726   4,384,415
Drilling and development   127,744   64,681   33,425   826   43,457   16,682   -   286,815
Exploration and evaluation   24,163   10,900   8,206   -   -   -   1,364   44,633
Oil and gas sales to external customers   286,441   242,177   71,435   20,012   -   148,802   -   768,867
Royalties   (30,903)   (15,147)   (2,901)   (4,086)   -   -   -   (53,037)
Revenue from external customers   255,538   227,030   68,534   15,926   -   148,802   -   715,830
Transportation expense   (7,122)   (10,138)   -   (1,474)   (3,159)   -   -   (21,893)
Operating expense   (37,789)   (32,970)   (12,432)   (3,597)   -   (29,411)   -   (116,199)
General and administration   (9,428)   (10,753)   (924)   (1,398)   (534)   (2,867)   (6,325)   (32,229)
PRRT   -   -   -   -   -   (32,938)   -   (32,938)
Corporate income taxes   -   (50,025)   (5,089)   (1,043)   -   (14,530)   (551)   (71,238)
Interest expense   -   -   -   -   -   -   (23,794)   (23,794)
Realized gain on derivative instruments   -   -   -   -   -   -   5,059   5,059
Realized foreign exchange loss   -   -   -   -   -   -   (1,454)   (1,454)
Realized other income   -   -   -   -   -   -   295   295
Fund flows from operations   201,199   123,144   50,089   8,414   (3,693)   69,056   (26,770)   421,439

ADDITIONAL AND NON-GAAP FINANCIAL MEASURES

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

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

      Jun 30,   Mar 31,   Jun 30,     Jun 30,   Jun 30,
($M)       2014   2014   2013     2014   2013
Cash flows from operating activities        149,592    178,238    179,074      327,830    369,786
Changes in non-cash operating working capital        64,103    24,474    (6,852)      88,577    (35,323)
Asset retirement obligations settled        2,381    2,651    2,370      5,032    3,758
Fund flows from operations        216,076    205,363    174,592      421,439    338,221
Expenses related to Corrib        1,823    1,870    2,036      3,693    3,891
Fund flows from operations (excluding Corrib)        217,899    207,233    176,628      425,132    342,112


 

 
Three Months Ended
 
Six Months Ended
    Jun 30, Mar 31, Jun 30,   Jun 30, Jun 30,
($M) 2014  2014  2013   2014 2013
Dividends declared  68,710  66,007   60,776     134,717  120,388
Issuance of shares pursuant to the dividend reinvestment plan  (19,149)  (18,885)  (18,630)    (38,034)  (34,162)
Net dividends  49,561  47,122   42,146     96,683  86,226 
Drilling and development  117,975   168,840   75,005     286,815  254,525 
Dispositions  -  -   -     -  (8,627)
Exploration and evaluation  17,098  27,535   3,113     44,633  12,689 
Asset retirement obligations settled  2,381  2,651   2,370     5,032  3,758 
Payout  187,015   246,148   122,634     433,163   348,571 
Corrib drilling and development  (27,221)  (16,236)  (24,878)    (43,457)  (41,398)
Payout (excluding Corrib)  159,794   229,912   97,756     389,706   307,173 

  As At

('000s of shares)
Jun 30,
2014 
Mar 31,
2014 
Jun 30,
2013 
Shares outstanding  106,620   102,453   101,418 
Potential shares issuable pursuant to the VIP  2,751   2,714   2,317 
Diluted shares outstanding  109,371   105,167   103,735 
       
       
   


CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)


  June 30, December 31,
  Note   2014    2013 
ASSETS          
Current          
Cash and cash equivalents      165,497     389,559 
Accounts receivable
   199,251     167,618 
Crude oil inventory      17,952     17,143 
Derivative instruments      7,624     2,285 
Prepaid expenses      17,254     11,178 
       407,578     587,783 
           
Deferred taxes      148,173     184,832 
Exploration and evaluation assets 5    332,122     136,259 
Capital assets 4    3,496,542     2,799,845 
       4,384,415     3,708,719 
     
 
LIABILITIES    
   
Current          
Accounts payable and accrued liabilities     264,249     267,832 
Dividends payable 8    22,923     20,425 
Derivative instruments      7,787     3,572 
Income taxes payable      82,751     55,615 
       377,710     347,444 
           
Long-term debt 7    1,198,866     990,024 
Asset retirement obligations 6    390,054     326,162 
Deferred taxes      401,317     328,714 
       2,367,947     1,992,344 
         
SHAREHOLDERS' EQUITY          
Shareholders' capital 8    1,917,334    1,618,443 
Contributed surplus      59,343     75,427 
Accumulated other comprehensive income      49,883     47,142 
Deficit      (10,092)    (24,637)
       2,016,468     1,716,375 
       4,384,415     3,708,719 
           
           


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


 

 

 

Three Months Ended

 

Six Months Ended
      Jun 30,   Jun 30,   Jun 30,   Jun 30,
  Note   2014    2013    2014    2013 
REVENUE                  
Petroleum and natural gas sales     387,684     311,966     768,867     621,542 
Royalties      (29,013)    (15,800)    (53,037)    (31,590)
Petroleum and natural gas revenue      358,671     296,166     715,830     589,952 
                   
EXPENSES
               
Operating      58,213     48,082     116,199     100,657 
Transportation      12,032     6,653     21,893     13,294 
Equity based compensation 9    18,217     10,724     34,689     26,860 
Gain on derivative instruments     (898)    (10,421)    (7,473)    (6,521)
Interest expense
   12,334     9,336     23,794     18,025 
General and administration
   17,762     11,313     32,229     23,923 
Foreign exchange loss (gain)
   23,159     (29,297)    3,200     (26,161)
Other (income) expense      (178)    271     (145)    204 
Accretion 6    5,950     6,000     11,662     11,824 
Depletion and depreciation 4, 5   104,902     78,418     204,354     159,866 
 
   251,493     131,079     440,402     321,971 
EARNINGS BEFORE INCOME TAXES      107,178     165,087 
 

 275,428 

 
 267,981 
                   
INCOME TAXES                  
Deferred      7,851     9,580     14,471     13,627 
Current      45,334     49,309     104,176     96,019 
       53,185     58,889     118,647     109,646 
                   
NET EARNINGS      53,993     106,198     156,781     158,335 
 


 
 
       
OTHER COMPREHENSIVE (LOSS) INCOME    
 
     
 
Currency translation adjustments      (42,794)    18,955     2,741     17,623 
COMPREHENSIVE INCOME      11,199     125,153     159,522     175,958 
                   
NET EARNINGS PER SHARE
               
Basic       0.51     1.05     1.51     1.58 
Diluted      0.50     1.04     1.49     1.56 
                   
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)                  
Basic      105,577     100,964     103,936     100,137 
Diluted      107,330     102,223     105,531     101,578 
                   
                   


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

   
 

Three Months Ended

 

Six Months Ended
 
  Jun 30,   Jun 30,   Jun 30,   Jun 30,
  Note
 
2014    2013    2014    2013 
OPERATING                  
Net earnings      53,993     106,198     156,781     158,335 
Adjustments:            
 
 
 
  Accretion 6    5,950     6,000     11,662     11,824 

Depletion and depreciation 4, 5    104,902     78,418     204,354     159,866 

Unrealized loss (gain) on derivative instruments
   1,521     (8,651)    (2,414)    (7,538)

Equity based compensation 9    18,217     10,724     34,689     26,860 

Unrealized foreign exchange loss (gain)
 

 
 23,746     (28,025)    1,746     (25,506)

Unrealized other (income) expense      (104)    348     150     753 

Deferred taxes      7,851     9,580     14,471     13,627 
Asset retirement obligations settled 6    (2,381)    (2,370)    (5,032)    (3,758)
Changes in non-cash operating working capital     (64,103)    6,852 
 (88,577)    35,323 
Cash flows from operating activities     149,592     179,074     327,830     369,786 
INVESTING            
 
   
Drilling and development 4    (117,975)    (75,005)    (286,815)    (254,525)
Exploration and evaluation 5    (17,098)    (3,113)    (44,633)    (12,689)
Property acquisitions 3, 4, 5    - 
 -     (178,227)    - 
Dispositions 4    -     -     -     8,627 
Corporate acquisitions, net of cash acquired 3    (176,179)    -     (176,179)    - 
Changes in non-cash investing working capital      (24,010)    (75,613)    15,463   
 (37,403)
Cash flows used in investing activities      (335,262)    (153,731)    (670,391)    (295,990)
                 
FINANCING
               
Increase in long-term debt      255,727     70,000     205,727     139,429 
Cash dividends      (48,665)    (41,754)    (94,185)    (84,778)
Cash flows from financing activities      207,062     28,246     111,542     54,651 
Foreign exchange (loss) gain on cash held in foreign currencies      (7,232)    5,496    6,957     5,026 
                 
Net change in cash and cash equivalents      14,160     59,085     (224,062)    133,473 
Cash and cash equivalents, beginning of period      151,337     176,513     389,559     102,125 
Cash and cash equivalents, end of period      165,497     235,598     165,497     235,598 
 
   
         
Supplementary information for operating activities - cash payments    
           

Interest paid      11,721     8,417     25,815     20,509 

Income taxes paid      56,486     18,669     77,560     51,304 
                     
                     

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

            Accumulated    
              Other   Total
    Shareholders' Contributed Comprehensive   Shareholders'
  Note Capital Surplus   Loss Deficit Equity
Balances as at January 1, 2013      1,481,345     69,581     (32,409)   (99,871)    1,418,646 
Net earnings      -     -     -     158,335     158,335 
Currency translation adjustments      -     -     17,623     -     17,623 
Equity based compensation expense 9     26,231         26,231 
Dividends declared 8    -     -     -     (120,388)    (120,388)
Shares issued pursuant to the        
     
   
dividend reinvestment plan 8    34,162     -     -     -     34,162 
Vesting of equity based awards 8, 9    54,370     (54,370)    -     -     - 
Share-settled dividends                      
on vested equity based awards 8, 9    9,808     -     -     (9,808)    - 
Shares issued pursuant to the bonus plan 8    629     -     -     -     629 
Balances as at June 30, 2013      1,580,314     41,442     (14,786)    (71,732)    1,535,238 
     
               
            Accumulated      
              Other   Total
    Shareholders' Contributed Comprehensive   Shareholders'
  Note Capital Surplus   Income Deficit Equity
Balances as at January 1, 2014      1,618,443     75,427     47,142     (24,637)    1,716,375 
Net earnings      -     -     -     156,781     156,781 
Currency translation adjustments  
 -     -     2,741     -     2,741 
Equity based compensation expense 9    -     33,968     -     -     33,968 
Dividends declared 8    -     -     -     (134,717)    (134,717)
Shares issued pursuant to the                      
dividend reinvestment plan 8    38,034     -     -     -     38,034 
Shares issued pursuant to                      
corporate acquisition 3    204,960     -     -     -     204,960 
Modification of equity based awards 9    -     (2,395)            (2,395)
Vesting of equity based awards 8, 9    47,657     (47,657)    -     -     - 
Share-settled dividends                      
on vested equity based awards 8, 9    7,519     -     -     (7,519)    - 
Shares issued pursuant to the bonus plan 8    721     -     -     -     721 
Balances as at June 30, 2014      1,917,334     59,343     49,883     (10,092)    2,016,468 
                       

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 CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2014 AND 2013
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS, UNAUDITED)

1.  BASIS OF PRESENTATION

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

These condensed consolidated interim financial statements are in compliance with IAS 34, "Interim financial reporting" and have been prepared using the same accounting policies and methods of computation as Vermilion's consolidated financial statements for the year ended December 31, 2013, except as discussed in Note 2. 

These condensed consolidated interim financial statements should be read in conjunction with Vermilion's consolidated financial statements for the year ended December 31, 2013, which are contained within Vermilion's Annual Report for the year ended December 31, 2013 and are available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com

These condensed consolidated interim financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on July 30, 2014.


2.  RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

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

IFRIC 21 "Levies"

On May 20, 2013, 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 is effective for annual periods beginning on or after January 1, 2014. 

IAS 36 "Impairment of Assets"

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

Accounting pronouncements not yet adopted

The impact of the adoption of the following pronouncement is currently being evaluated.

 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.


3.  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 revenues of $20.0 million and net earnings $0.4 million for the six months ended June 30, 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 six months ended June 30, 2014.

Corporate acquisition:

Elkhorn Resources Inc.

On April 29, 2014, Vermilion acquired Elkhorn Resources Inc., a private southeast Saskatchewan producer.  The acquisition creates 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 50% or greater capacity at a solution gas facility that is currently under construction.  Vermilion funded this acquisition with existing credit facilities.

Total consideration was comprised of $180.4 million of cash 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 (1)    385,313 
(1)  The above amounts are estimates made by management at the time of the preparation of these condensed consolidated interim financial statements based on information then available.  Amendments may be made as amounts subject to estimates are finalized.

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 $16.0 million and operating income of $13.0 million for the six months ended June 30, 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 six months ended June 30, 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 increase to net earnings from the acquisition as the acquired company was immediately merged with Vermilion's operations.


4.  CAPITAL ASSETS

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

    Petroleum and Furniture and   Total
 ($M) Natural Gas Assets Office Equipment   Capital Assets
 Balance at January 1, 2013    2,430,121     15,119     2,445,240 
 Additions    531,760     5,804     537,564 
 Transfers from exploration and evaluation assets    1,508         1,508 
 Corporate acquisitions    47,743         47,743 
 Dispositions    (8,627)        (8,627)
 Changes in estimate for asset retirement obligations    (91,527)        (91,527)
 Depletion and depreciation    (310,370)    (6,138)    (316,508)
 Impairments    47,400   
   47,400 
 Effect of movements in foreign exchange rates    136,626     426     137,052 
 Balance at December 31, 2013    2,784,634     15,211     2,799,845 
 Additions    284,616     2,199     286,815 
 Property acquisitions    163,599          163,599 
 Corporate acquisitions    390,523         390,523 
 Changes in estimate for asset retirement obligations    46,998         46,998 
 Depletion and depreciation    (199,050)    (1,908)    (200,958)
 Effect of movements in foreign exchange rates    9,632     88     9,720 
 Balance at June 30, 2014    3,480,952     15,590     3,496,542 

 

5.  EXPLORATION AND EVALUATION ASSETS

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

($M) Exploration and Evaluation Assets
Balance at January 1, 2013    117,161 
Additions    13,789 
Property acquisitions    9,189 
Transfers to petroleum and natural gas assets    (1,508)
Depreciation    (3,712)
Effect of movements in foreign exchange rates    1,340 
Balance at December 31, 2013    136,259 
Additions    44,633 
Changes in estimate for asset retirement obligations    85 
Property acquisitions    16,662 
Corporate acquisitions    138,264 
Depreciation    (3,098)
Effect of movements in foreign exchange rates    (683)
Balance at June 30, 2014    332,122 
     

6.  ASSET RETIREMENT OBLIGATIONS

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

($M) Asset Retirement Obligations
Balance at January 1, 2013      371,063 
Additional obligations recognized      15,655 
Changes in estimates for existing obligations      (21,068)
Obligations settled      (11,922)
Accretion      24,565 
Changes in discount rates      (73,675)
Effect of movements in foreign exchange rates      21,544 
Balance at December 31, 2013      326,162 
Additional obligations recognized      18,675 
Obligations settled      (5,032)
Accretion      11,662 
Changes in discount rates      36,412 
Effect of movements in foreign exchange rates      2,175 
Balance at June 30, 2014      390,054 

 

7.  LONG-TERM DEBT

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

  As At
($M) June 30, 2014 Dec 31, 2013
Revolving credit facility    975,297     766,898 
Senior unsecured notes    223,569     223,126 
Long-term debt    1,198,866     990,024 

 

Revolving Credit Facility

At June 30, 2014, Vermilion had in place a bank revolving credit facility totalling $1.5 billion, of which approximately $975.3 million 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 repayable on the maturity date.  This facility bears interest at a rate applicable to demand loans plus applicable margins.  For the six months ended June 30, 2014, the interest rate on the revolving credit facility was approximately 3.1%.

The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $10.2 million as at June 30, 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 June 30, 2014, Vermilion was in compliance with its financial covenants.

Senior Unsecured Notes

On February 10, 2011, Vermilion issued $225.0 million of senior unsecured notes at par.  The notes bear interest at a rate of 6.5% per annum and will mature on February 10, 2016.  As direct senior unsecured obligations of Vermilion, the notes rank pari passu with all other present and future unsecured and unsubordinated indebtedness of the Company. 

Vermilion may redeem all or part of the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the applicable redemption date.  The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

8.  SHAREHOLDERS' CAPITAL

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

Shareholders' Capital Number of Shares ('000s)   Amount ($M)
Balance as at January 1, 2013    99,135     1,481,345 
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    601     38,034 
Vesting of equity based awards    950     47,657 
Share-settled dividends on vested equity based awards    108     7,519 
Shares issued pursuant to the bonus plan    11     721 
Balance as at June 30, 2014    106,620     1,917,334 

Dividends declared to shareholders for the six months ended June 30, 2014 were $134.7 million (2013 - $120.4 million).

Subsequent to the end of the period and prior to the condensed consolidated interim financial statements being authorized for issue on July 30, 2014, Vermilion declared dividends totalling $22.9 million or $0.215 per share.

9.  EQUITY BASED COMPENSATION

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

Number of Awards ('000s) 2014    2013 
Opening balance  1,665     1,690 
Granted  563     832 
Vested  (512)    (749)
Modified  (21)    - 
Forfeited  (21)    (108)
Closing balance  1,674     1,665 

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

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

 10.  SEGMENTED INFORMATION

Vermilion has operations principally in Canada, France, the Netherlands, Germany, Ireland, and AustraliaVermilion's operating activities in each country relate solely to the exploration, development and production of petroleum and natural gas.  Vermilion has a Corporate head office located in Calgary, Alberta.  Costs incurred in the Corporate segment relate to Vermilion's global hedging program and expenses incurred in financing and managing our operating business units.

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

  Three Months Ended June 30, 2014
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Drilling and development  26,071     34,828     18,234     630     27,221     10,991     -     117,975 
Exploration and evaluation  10,897     2,786     3,279     -     -     -     136     17,098 
Oil and gas sales to external customers  163,261     124,617     29,881 
 11,097     -     58,828     -     387,684 
Royalties  (18,240)    (7,796)    (693)
 (2,284)    -     -     -     (29,013)
Revenue from external customers  145,021     116,821     29,188 
 8,813     -     58,828     -     358,671 
Transportation expense  (4,024)    (5,385)    - 
 (1,052)    (1,571)    -     -     (12,032)
Operating expense  (21,179)    (16,550)    (6,390)
 (2,043)    -     (12,051)    -     (58,213)
General and administration  (6,560)    (5,559)    (326)
 
 (830)    (252)    (1,661)    (2,574)    (17,762)
PRRT  -     -     -     -     -     (12,699)    -     (12,699)
Corporate income taxes  -     (24,761)    (1,301)    (506)    -     (5,689)    (378)    (32,635)
Interest expense  -     -     -     -     -     -     (12,334)    (12,334)
Realized gain on derivative instruments  -     -     -     -     -     -     2,419     2,419 
Realized foreign exchange gain  -     -     -     -     -     -     587     587 
Realized other income  -     -     -     -     -     -     74     74 
Fund flows from operations  113,258     64,566     21,171     4,382     (1,823)    26,728     (12,206)    216,076 
                               
  Three Months Ended June 30, 2013
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Drilling and development  14,059     23,223     4,157     -     24,878     8,282     406     75,005 
Exploration and evaluation  2,494         -     -     -     619     3,113 
Oil and gas sales to external customers  100,950     100,418     38,316     -     -     72,282     -     311,966 
Royalties  (9,707)    (6,093)    -     -     -     -     -     (15,800)
Revenue from external customers  91,243     94,325     38,316     -     -     72,282     -     296,166 
Transportation expense  (2,611)    (2,416)    -     -     (1,626)    -     -     (6,653)
Operating expense  (15,975)    (16,935)    (5,260)    -     -     (9,912)      (48,082)
General and administration  (3,948)    (3,927)    (426)    -     (410)    (1,378)    (1,224)    (11,313)
PRRT  -     -     -     -     -     (12,590)    -     (12,590)
Corporate income taxes  -     (16,124)    (9,621)    -     -     (10,646)    (328)    (36,719)
Interest expense  -     -     -     -     -     -     (9,336)    (9,336)
Realized gain on derivative instruments  -     -     -     -     -     -     1,770     1,770 
Realized foreign exchange gain  -     -     -     -     -     -     1,272     1,272 
Realized other income  -     -     -     -     -     -     77     77 
Fund flows from operations  68,709     54,923     23,009     -     (2,036)    37,756     (7,769)    174,592 
                               
  Six Months Ended June 30, 2014
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Total assets  1,854,501     916,712     235,723     174,735     799,394     277,624     125,726     4,384,415 
Drilling and development  127,744     64,681     33,425     826     43,457     16,682     -     286,815 
Exploration and evaluation  24,163     10,900     8,206     -     -     -     1,364     44,633 
Oil and gas sales to external customers  286,441     242,177     71,435     20,012     -     148,802     -     768,867 
Royalties  (30,903)    (15,147)    (2,901)    (4,086)    -     -     -     (53,037)
Revenue from external customers  255,538     227,030     68,534     15,926     -     148,802     -     715,830 
Transportation expense  (7,122)    (10,138)    -     (1,474)    (3,159)    -     -     (21,893)
Operating expense  (37,789)    (32,970)    (12,432)    (3,597)    -     (29,411)    -     (116,199)
General and administration  (9,428)    (10,753)    (924)    (1,398)    (534)    (2,867)    (6,325)    (32,229)
PRRT  -     -     -     -     -     (32,938)    -     (32,938)
Corporate income taxes  -     (50,025)    (5,089)    (1,043)    -     (14,530)    (551)    (71,238)
Interest expense  -     -     -     -     -     -     (23,794)    (23,794)
Realized gain on derivative instruments  -     -     -     -     -     -     5,059     5,059 
Realized foreign exchange loss  -     - 
 -     -     -     -     (1,454)    (1,454)
Realized other income  -     -     -     -     -     -     295     295 
Fund flows from operations  201,199     123,144     50,089     8,414     (3,693)    69,056     (26,770)    421,439 
                               

 
Six Months Ended June 30, 2013
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Total assets  1,105,026 
 873,242     142,317     -     646,366     311,415     220,641    3,299,007 
Drilling and development  96,800     44,815     6,156     -     41,398     63,631     1,725     254,525 
Exploration and evaluation  11,882     -     -     -     -     -     807     12,689 
Oil and gas sales to external customers  184,638     221,984     72,737     -     -     142,183     -     621,542 
Royalties  (18,696)    (12,894)    -     -     -     -     -     (31,590)
Revenue from external customers  165,942     209,090     72,737     -     -     142,183     -     589,952 
Transportation expense  (4,880)    (5,170)    -     -     (3,244)    -     -     (13,294)
Operating expense  (29,816)    (36,874)    (9,229)    -     -     (24,738)    -     (100,657)
General and administration  (7,017)    (9,613)    (838)    -     (647)    (2,896)    (2,912)    (23,923)
PRRT  -     -     -     -     -     (23,743)    -     (23,743)
Corporate income taxes  -     (34,783)    (19,055)    -     -     (17,859)    (579)    (72,276)
Interest expense  -     -     -     -     -     -     (18,025)    (18,025)
Realized loss on derivative instruments  -     -     -     -     -     -     (1,017)    (1,017)
Realized foreign exchange gain  -     -     -     -     -     -     655     655 
Realized other income  -     -     -     -     -     -     549     549 
Fund flows from operations  124,229     122,650     43,615     -     (3,891)    72,947     (21,329)    338,221 

 

Reconciliation of fund flows from operations to net earnings 

  Three Months Ended   Six Months Ended
  Jun 30, Jun 30,   Jun 30, Jun 30,
($M) 2014  2013 
 

2014 

2013 
Fund flows from operations  216,076   174,592     421,439   338,221 
Equity based compensation  (18,217)  (10,724)    (34,689)  (26,860)
Unrealized (loss) gain on derivative instruments  (1,521)  8,651     2,414   7,538 
Unrealized foreign exchange (loss) gain  (23,746)  28,025     (1,746)  25,506 
Unrealized other income (expense)  104   (348)    (150)  (753)
Accretion  (5,950)  (6,000)    (11,662)  (11,824)
Depletion and depreciation  (104,902)  (78,418)    (204,354)  (159,866)
Deferred taxes  (7,851)  (9,580)    (14,471)  (13,627)
Net earnings  53,993   106,198     156,781   158,335 
           

11.  CAPITAL DISCLOSURES

  Three Months Ended   Six Months Ended
($M except as indicated) June 30, 2014 June 30, 2013   June 30, 2014 June 30, 2013
Long-term debt  1,198,866  780,470     1,198,866  780,470 
Current liabilities  377,710  325,912     377,710  325,912 
Current assets  (407,578) (432,014)    (407,578) (432,014)
Net debt [1]  1,168,998  674,368     1,168,998  674,368 
           
Cash flows from operating activities  149,592  179,074     327,830  369,786 
Changes in non-cash operating working capital  64,103  (6,852)    88,577  (35,323)
Asset retirement obligations settled  2,381  2,370     5,032  3,758 
Fund flows from operations  216,076   174,592     421,439   338,221 
Annualized fund flows from operations [2]  864,304   698,368     842,878   676,442 
           
Ratio of net debt to annualized fund flows from operations ([1] ÷ [2]) 1.4  1.0    1.4  1.0 

Long-term debt as at June 30, 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 latter acquisition.  This increase in long-term debt resulted in an increase to net debt from $749.7 million to $1.2 billion

As year-to-date fund flows includes only 2 months of contribution from the acquisition in Saskatchewan, the ratio of net debt to annualized fund flows increased to 1.4.


12.  FINANCIAL INSTRUMENTS

 Classification of Financial Instruments

The following table summarizes information relating to Vermilion's financial instruments as at June 30, 2014 and December 31, 2013:


 

 
        As at Jun 30, 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)
  165,497     165,497     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
 
199,251 
 
 199,251 
 
 167,618
 
 167,618
 
Not applicable
Derivative assets Derivative instruments HFT Gain on derivative instruments
 
 7,624 
 
 7,624 
 
 2,285 
 
 2,285 
 
Level 2
Derivative liabilities Derivative instruments HFT Gain on derivative instruments    (7,787)    (7,787)    (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)

 
 (287,172)
 
 (287,172)
 
 (288,257)
 
 (288,257)
 
Not applicable
    Dividends payable
   
 
             
 
Long-term debt Long-term debt OTH Interest expense
 
(1,198,866)
 
(1,207,610)
 
 (990,024)
 
 (998,648)
 
Level 2

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

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

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

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

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

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

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

Determination of Fair Values

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

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

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

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

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

Nature and Extent of Risks Arising from Financial Instruments

Market risk:
Vermilion's financial instruments are exposed to currency risk related to changes in foreign currency denominated financial instruments and commodity price risk related to outstanding derivative positions.  The following table summarizes what the impact on comprehensive income before tax would be for the six months ended June 30, 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 June 30, 2014
Currency risk - Euro to Canadian Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates  (3,580)

 

 

 
  Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates  3,580 

 

 

 
Currency risk - US $ to Canadian Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates  (2,866)

 

 

 
  Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates
 2,866
     
     
Commodity price risk Increase in relevant oil reference price within option pricing models used to determine  (7,593)
  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 6,893
  the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates  
   
Interest rate risk Increase in average Canadian prime interest rate by 100 basis points during the relevant periods  (4,063)

 

 

 
  Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods  4,063 

 

 

SOURCE Vermilion Energy Inc.

For further information:

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

www.vermilionenergy.com