LinkedIn Contact UsContact Us
Menu

News

The information contained in news releases posted to this website was accurate at the time of posting, but may be superseded by subsequent news releases.

Vermilion Energy Inc. Announces Results for the Three and Nine Months Ended September 30, 2014

November 10, 2014

CALGARY, Nov. 10, 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 nine months ended September 30, 2014.

HIGHLIGHTS

  • Achieved average production of 49,920 boe/d during Q3 2014, a decrease of 4% as compared to 52,089 boe/d in the prior quarter and an increase of 20% compared to 41,510 boe/d in Q3 2013.  Lower quarter-over-quarter production was primarily due to a 7% decrease in Canada resulting from lower levels of drilling and completions activity during spring breakup, and managed production in Australia and the Netherlands consistent with overall corporate production targets.  Quarter-over-quarter declines from lower Canadian activity were partially offset by inclusion of a full quarter of production from our southeast Saskatchewan acquisition, which closed in late April 2014.  Q3 production volumes in the Netherlands were also affected by unscheduled downtime at our Garijp treating facility.

  • Generated fund flows from operations(1) in Q3 2014 of $197.9 million ($1.85/basic share), as compared to $216.1 million ($2.05/basic share) in the prior quarter and $165.6 million ($1.63/basic share) in Q3 2013.  The quarter-over-quarter decrease was primarily attributable to lower commodity pricing during Q3 2014, and a combined build in crude oil inventories in France and Australia of approximately 104,000 bbls.

  • Completed our first Duvernay horizontal appraisal well (35% working interest), which is located along a shared lease-line in the Pembina block.  This three-quarter mile long well was brought on production subsequent to the end of the third quarter and has produced for 16 days.  Raw gas rate has averaged 2.2 mmcf/d (expected sales gas rate of 1.8 mmcf/d after liquids shrink and plant fuel) with an estimated hydrocarbon liquids rate of approximately 180 bbls/d (approximately 60% pentanes plus).  The well is producing at restricted rates using a 12/64 inch downhole choke to generate an estimated flowing bottomhole pressure of 4,200 psi (approximately 55% drawdown).  Our second Duvernay horizontal appraisal well (100% working interest), located in the Edson block, is expected to be brought on production late in Q4 2014.

  • Drilled our first well in the Netherlands on lands acquired in October 2013.  The Diever-02 exploration well (45% working interest), in the Drenthe IIIb concession, encountered two well-developed gas bearing intervals (Akkrum and Slochteren) with a net pay thickness of approximately 36 metres.  A three-hour clean-up test was conducted on the Slochteren formation which delivered 25.7 mmcf/d of gas on a 40/64 inch choke with 2,615 psi flowing tubing pressure with no indications of pressure drop during the test(3).  The flow rate was limited by the 3.5 inch diameter of the tubing and the capacity of the test equipment.  The well is expected to be tied-in with production from the Slochteren formation in Q4 2015 at an estimated rate of approximately 1,000 boe/d, net to Vermilion.  The Akkrum formation will be perforated at a later date once the Slochteren formation has been fully produced.

  • Subsequent to the end of the third quarter, drilled a gas discovery well in the Netherlands at the Langezwaag-02 location (42.3% working interest) in the Gorredijk concession.  This extended reach well recorded significant gas shows in two metres of Vlieland Sandstone and 21 metres of Zechstein-2 Carbonate.  Open hole logs could not be run in the highly deviated well.  The Langezwaag-02 well was first flow tested from the Zechstein-2 Carbonate at 12.4 mmcf/d through a 48/64 inch choke at a flowing tubing pressure of approximately 1,300 psi. A second flow test in the Vlieland Sandstone yielded rates of 2.7 mmcf/d through a 32/64 inch choke at a flowing tubing pressure of approximately 960 psi.

  • Subsequent to the end of the third quarter, recorded first production from the Deblinghausen Z7a well (25% working interest) in Germany.  This well was drilled earlier in 2014 by operator ExxonMobil Production Deutschland GmbH, and encountered 81 metres of Zechstein Carbonate pay.  Initial gross production rates are approximately 16.5 mmcf/d of raw gas at a flowing tubing pressure of approximately 1,300 psi.

  • Successfully expanded our southeast Saskatchewan land base through the purchase at Crown land sales of an additional approximately 15,000 net acres of undeveloped land to the northwest of our existing lands at an average cost of approximately $1,860 per acre.

  • Completed our first acquisition in the United States at a cost of approximately $11.1 million. Through the transaction, we acquired approximately 68,000 acres of land (98% undeveloped) in the Powder River basin of northeastern Wyoming with current working interest production of approximately 200 bbls/d (100% oil), proved plus probable reserves estimated at 2.22 million boe (82% oil) and contingent resource of 10.02 million boe (82% oil). Transaction metrics, with no deduction for land value, equate to approximately $56,000 per boe/d and $20.98 per boe, including future development costs of approximately $35.3 million. The land base includes 53,000 net acres at an average operated working interest of 70% in a promising tight oil project in the Turner Sand at a depth of approximately 1,500 metres.

  • Our Corrib project in Ireland has continued to progress on schedule following the completion of tunnel boring operations in May 2014.  Project operator Shell Exploration & Production Ireland Ltd. (SEPIL) successfully completed offshore workover and pipeline operations during the third quarter.  SEPIL also significantly advanced tunnel outfitting, which is now estimated to be approximately 95% complete.  Remaining activities include completion of tunnel outfitting and grouting, commissioning of the gas processing facility, and finalization of operating permits.  We anticipate first gas from Corrib in approximately mid-2015, with peak production estimated at approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.

  • We are revising our 2014 average annual production guidance from the previous range of 48,500-49,500 boe/d to a range of 49,000-49,500 boe/d, and expect full year production to be near the upper end of this new range.  We currently anticipate providing 2015 production and capital expenditure guidance in early December 2014.

  • We celebrated our 20th Anniversary as a publicly traded company in 2014.  This has been a rewarding period of growth and achievement for our company, and we are proud of our progress to date.  Most importantly, we are honored to have provided our shareholders with a compound average total return including dividends, as of September 30, 2014, of 36.4% per annum since our inception.  With the consistent strength of our operations and our extensive opportunity base, 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.
(2)     Estimated proved plus probable reserves and contingent resources attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated October 28, 2014, with an effective date of July 1, 2014, using the GLJ (2014-07) price forecast.
(3)     Test results are not necessarily indicative of long-term production performance or of ultimate recovery.

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

Vermilion will discuss these results in a conference call to be held on Monday, November 10, 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 6117964.  The replay will be available until midnight eastern time on November 17, 2014.

You may also listen to the audio webcast at http://event.on24.com/r.htm?e=852632&s=1&k=79DE9E8E7910A2E76368C9BFBF328E76 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     Nine Months Ended
($M except as indicated)       Sep 30,   Jun 30,     Sep 30,     Sep 30,     Sep 30,
Financial       2014   2014     2013     2014     2013
Petroleum and natural gas sales       344,688   387,684     327,185     1,113,555     948,727
Fund flows from operations (1)       197,898   216,076     165,645     619,337     503,866
  Fund flows from operations ($/basic share)       1.85   2.05     1.63     5.90     5.01
  Fund flows from operations ($/diluted share)       1.83   2.01     1.61     5.81     4.94
Net earnings       53,903   53,993     67,796     210,684     226,131
  Net earnings ($/basic share)       0.50   0.51     0.67     2.01     2.25
Capital expenditures       190,033   135,073     135,661     521,481     394,248
Acquisitions       40,847   381,139     7,586     600,213     7,586
Asset retirement obligations settled       4,677   2,381     2,738     9,709     6,496
Cash dividends ($/share)       0.645   0.645     0.600     1.935     1.800
Dividends declared       68,896   68,710     61,003     203,613     181,391
  % of fund flows from operations       35%   32%     37%     33%     36%
Net dividends (1)       48,480   49,561     41,649     145,163     127,875
  % of fund flows from operations       24%   23%     25%     23%     25%
Payout (1)       243,190   187,015     180,048     676,353     528,619
  % of fund flows from operations       123%   87%     109%     109%     105%
  % of fund flows from operations (excluding the Corrib project)       107%   73%     87%     97%     89%
Net debt (1)       1,243,438   1,168,998     700,286     1,243,438     700,286
Ratio of net debt to annualized fund flows from operations (1)       1.6   1.4     1.1     1.5     1.0
Operational                              
Production                              
  Crude oil (bbls/d)       29,147   30,184     26,664     28,890     25,640
  NGLs (bbls/d)       2,354   2,892     1,945     2,463     1,719
  Natural gas (mmcf/d)       110.52   114.08     77.41     109.33     81.97
  Total (boe/d)       49,920   52,089     41,510     49,574     41,020
Average realized prices                              
  Crude oil and NGLs ($/bbl)       102.49   109.89     108.87     108.02     103.95
  Natural gas ($/mcf)       5.74   6.19     6.00     6.60     6.68
Production mix (% of production)                              
  % priced with reference to WTI       28%   30%     24%     27%     24%
  % priced with reference to AECO       18%   18%     17%     18%     17%
  % priced with reference to TTF       18%   18%     14%     18%     16%
  % priced with reference to Dated Brent       36%   34%     45%     37%     43%
Netbacks ($/boe) (1)                              
  Operating netback       54.25   59.52     61.91     58.95     60.12
  Fund flows from operations netback       44.08   46.24     43.60     46.02     44.13
  Operating expenses       12.53   12.46     12.17     12.81     12.87
Average reference prices                              
  WTI (US $/bbl)       97.17   102.99     105.82     99.61     98.14
  Edmonton Sweet index (US $/bbl)       89.24   96.85     101.10     92.17     93.03
  Dated Brent (US $/bbl)       101.85   109.63     110.37     106.57     108.45
  AECO ($/GJ)       3.81   4.44     2.31     4.56     2.89
  TTF ($/GJ)       7.26   7.91     9.94     8.41     10.17
Average foreign currency exchange rates                              
  CDN $/US $       1.09   1.09     1.04     1.09     1.02
  CDN $/Euro       1.44   1.50     1.38     1.48     1.35
Share information ('000s)                              
Shares outstanding - basic       106,921   106,620     101,787     106,921     101,787
Shares outstanding - diluted (1)       109,749   109,371     104,195     109,749     104,195
Weighted average shares outstanding - basic       106,768   105,577     101,613     104,891     100,634
Weighted average shares outstanding - diluted (1)       108,290   107,330     102,763     106,582     102,083

(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 celebrated Vermilion's 20th anniversary as a publicly traded company.  It has been a demanding, but also a 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.  Today's environment is no different.  The recent volatility in the capital markets, and more particularly in the energy sector (due to a rapid fall in commodity prices and near term price expectations), creates yet another opportunity for us to demonstrate the sustainability of our business model and the advantages of our diversified portfolio.  Vermilion's relative performance during this period has once again demonstrated the stable and defensive nature of our business, our strong positioning within the industry, and our shareholders' continued confidence in our ability to prosper.  Our balance sheet remains strong and we believe our longer-term focus, combined with our conservative approach and patience, will allow us to create further opportunity for our shareholders in the current environment.

Reflecting on Vermilion's record, we are pleased that our previous efforts have resulted in a compound average total return including dividends, as of September 30, 2014, of 36.4% 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.

In spite of current commodity price weakness, we continue to believe that Vermilion is better situated for continued growth than at any other time in our history.  With the consistent performance 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 also providing a reliable and growing dividend stream to our shareholders.

We are confident that the assets in our current portfolio contain significant opportunity for growth for years to come.  In the current environment, we also find ourselves positioned to enhance growth in shareholder value and further diversify our opportunity base through acquisition activity in both North American and international markets.

In February 2014 we announced our entry into GermanyGermany has a long history of oil and gas development activity, low political risk and strong marketing fundamentals.  The acquisition provides us with entry into this sizable market, in the form of free cash flow(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.

In late April 2014 we announced the completion of our acquisition of Elkhorn Resources Inc., a private southeast Saskatchewan producer.  The acquired assets consist of high netback, light oil production 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.

In addition, we recently completed an $11.1 million transaction which marks our first acquisition in the United States, representing a low-cost entry position in the prolific Powder River Basin of northeastern Wyoming. The transaction provides a promising tight oil development project, and we have put in place the human resources necessary to support future organic growth and acquisitions in the region. Through the transaction, we acquired approximately 68,000 acres of land (98% undeveloped) with current working interest production of approximately 200 bbls/d (100% oil), proved plus probable reserves estimated at 2.2(2) million boe (82% oil) and contingent resource of 10.0(2) million boe (82% oil). Transaction metrics, with no deduction for land value, equate to approximately $56,000 per boe/d and $20.98 per boe, including future development costs of approximately $35.3 million. The land base includes 53,000 net acres at a 70% operated working interest in a promising tight oil project in the Turner Sand at a depth of approximately 1,500 metres. The most recently completed well on this land block (70% working interest) is currently producing approximately 220 bbls/d of oil in its fourth month of production, from an approximately 1,100 metre hydraulically-fractured horizontal lateral.

Looking ahead we see continued opportunity for expansion.  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 growth on the horizon (including from Corrib, which is expected to commence production in mid-2015), we are well 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 third quarter of 2014 marks another quarter of consistent operational execution for our Company.  We continue to achieve strong results from our successful Mannville condensate-rich gas and Cardium light-oil development programs in Canada.  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 than originally anticipated to meet our development objectives for the Cardium.  As a result, we are able to increase our current focus on development of our extensive Mannville resource base which has generated very robust economics to-date.  Looking forward, we anticipate our Mannville drilling activity will continue to increase in future years as we continue to develop our substantial inventory of highly economic prospects.  During the quarter we also initiated a two-rig, 12-well Midale drilling program in southeast Saskatchewan.  We have currently identified approximately 190 net potential drilling locations targeting the Midale, Frobisher, Bakken, and Three Forks/Torquay formations on our southeast Saskatchewan lands.  In addition, we have expanded our southeast Saskatchewan land base during the quarter through the purchase at Crown land sales of approximately 15,000 net acres of undeveloped land to the northwest of our existing lands, adding an estimated 60 new development locations.

The appraisal of our position in the Duvernay condensate-rich resource play continues. To-date, we have amassed 317 net sections at the relatively low cost of $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 drilled (1,180 meters horizontal length) is located in the downdip part of our Edson block where condensate yields are expected to be lower than the average of 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 to occur during the fourth quarter of 2014). Our second horizontal appraisal well (1,280 meters horizontal length), 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 activities on the Pembina well, including microseismic monitoring, were completed during the third quarter. The well was brought on production in October 2014 and has produced for 16 days. Raw gas rate has averaged 2.2 mmcf/d (expected sales gas rate of 1.8 mmcf/d after liquids shrink and plant fuel) with an estimated hydrocarbon liquids rate of approximately 180 bbls/d (approximately 60% pentanes plus). The well is producing at restricted rates using a 12/64 inch downhole choke to generate an estimated flowing bottomhole pressure of 4,200 psi (approximately 55% drawdown). Our Edson Duvernay horizontal appraisal well (100% working interest) is expected to be brought on production late in Q4 2014.

Our development-phase target for Duvernay 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 condensate-rich 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 next decade.

We were also active in Europe during the third quarter of 2014 with ongoing drilling operations in both France and the Netherlands.  In France, we completed our five-well Champotran drilling campaign in the Paris Basin during the quarter.  The five wells were brought on production at various times during the third quarter and are producing at oil rates averaging approximately 200 bbls/d per well.  The final well of our 2014 drilling campaign in France (Tamaris in the Aquitaine Basin) is anticipated to be drilled and completed during the fourth quarter.  During the third quarter of 2014, we furthered preparations for the phased transfer of our shut-in Vic Bilh 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 early 2016.

In the Netherlands, we drilled the Diever-02 exploratory well (45% working interest) during the third quarter in the Drenthe IIIb concession on lands acquired in October 2013.  This well primarily targeted the Rotliegend Group (Permian sandstones) and encountered two well-developed gas bearing intervals (Akkrum and Slochteren) with a net pay thickness of approximately 36 metres.  A three-hour clean-up test was conducted on the Slochteren formation which delivered 25.7 mmcf/d of gas on a 40/64 inch choke with 2,615 psi flowing tubing pressure with no indications of pressure drop during the test(3).  The flow rate was limited by the 3.5 inch diameter of the tubing and the capacity of the test equipment.  The well is expected to be tied-in with production from the Slochteren formation in Q4 2015 at an estimated rate of approximately 1,000 boe/d, net to Vermilion.  The Akkrum formation is anticipated to be perforated at a later date once the Slochteren formation has been fully produced.

Subsequent to the end of the third quarter, we drilled a gas discovery well in the Netherlands at the Langezwaag-02 location (42.3% working interest) in the Gorredijk concession.  This extended reach well recorded significant gas shows in two metres of Vlieland Sandstone and 21 metres of Zechstein-2 Carbonate.  Open hole logs could not be run in the highly deviated well.  The Langezwaag-02 well was first flow tested from the Zechstein-2 Carbonate at 12.4 mmcf/d through a 48/64 inch choke at a flowing tubing pressure of approximately 1,300 psi.  A second flow test in the Vlieland Sandstone yielded rates of 2.7 mmcf/d through a 32/64 inch choke at a flowing tubing pressure of approximately 960 psi. The remaining well of the 2014 drilling campaign is expected to be drilled and completed during the fourth quarter of 2014.

Our newly acquired 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 include both exploration and production licenses that comprise a total of 207,000 gross acres, of which 85% is in the exploration license.  During the first quarter of 2014, we participated in the drilling of the Deblinghausen Z7a development well (25% working interest) in Germany.  The well logged 81 metres of net pay in the Zechstein Carbonate, and was tested in late September 2014 for a period of 17 days.  During production testing, the well produced at an average rate of 10.2 mmcf/d at a flowing tubing pressure of 1,840 psi(3).  Subsequent to the end of the quarter, this well was placed on production at an initial gross production rate of 16.5 mmcf/d of raw gas at a flowing tubing pressure of approximately 1,300 psi.

Our Corrib project in Ireland has continued to progress on schedule following the completion of tunnel boring operations in May 2014.  Project operator Shell Exploration & Production Ireland Ltd. (SEPIL) successfully completed offshore workover and pipeline operations during the third quarter and the wells are ready for operation.  SEPIL also significantly advanced tunnel outfitting, which is now estimated to be approximately 95% complete following installation of flow and umbilical lines in the 4.9 km tunnel.  Remaining activities include final cable installation, hydro-testing and grouting, as well as commissioning of the gas processing facility and finalization of operating permits.  We anticipate first gas from Corrib in approximately mid-2015, with peak production estimated at approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.

In Australia, we remain focused on completing preparations for a two-well drilling program in 2015, as well as re-lifing and maintenance projects on our two platforms.  In order to provide long-term certainty to purchasers of the high-value oil from Wandoo, 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 up to 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.  We are moving up our 2014 average annual production guidance from the previous range of 48,500-49,500 boe/d to a range of 49,000-49,500 boe/d, and expect full year production to be near the upper end of this refined range.   Assuming commodity prices remain near current levels for the remainder of 2014, we continue to anticipate that we can fully fund our net dividends(1) and development capital expenditures (excluding capital investment at Corrib) with fund flows from operations(1) during 2014.

We believe we remain positioned to deliver strong operational and financial performance over the next several years.  We continue to target annual organic production growth of 5% to 7% while 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.

In keeping with our strategy of pursuing long-term growth in our three core regions in North America, Europe and Australia, we have established two new offices led by locally-experienced management with strong track records of success.  As the operating headquarters of our new U.S. Business Unit, we have opened an office in Denver, ColoradoDaniel Anderson has joined Vermilion as Managing Director for our U.S. subsidiary.  Mr. Anderson has 30 years of experience in the upstream and midstream energy sectors throughout the U.S.  He was formerly President of Baytex Energy USA, with previous management and technical roles at Berry Petroleum, Williams Companies, Santa Fe Snyder and ConocoPhillips.  Mr. Anderson has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines.  Further strengthening our capabilities for growth in the U.S., Timothy Morris has joined Vermilion as Director of U.S. Business Development.  Mr. Morris has more than 30 years of experience in land management and business development in the U.S.  He was formerly Vice President of U.S. Business Development for Baytex Energy Corporation, with previous management and land roles at Berco Resources, Santa Fe Snyder and Sohio.  Mr. Morris has a Bachelor of Science degree in Minerals Land Management from the University of Colorado and is a Certified Petroleum Landman.

As the operating headquarters of our German Business Unit, we have established an office in Berlin.  Albrecht Möhring has been appointed Managing Director of Vermilion's German Business Unit.  Mr. Möhring brings 30 years of diverse experience in the energy business to Vermilion.  He was formerly Managing Director for Germany with GDF Suez, with previous roles as Group Exploration and Operations Manager in Paris for GDF Suez and in management with Preussag Energie in Germany (the predecessor of GDF Suez in Germany).  Mr. Möhring has a Master of Science degree in Petroleum Engineering from the University of Clausthal.

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.  In October 2014 Vermilion was ranked second out of 13 in our peer group by the Carbon Disclosure Project (CDP) for our disclosure in 2014, our inaugural year of participation with  Vermilion scoring 87 out of 100 (10 points higher than any peer group company achieved in its inaugural year of participation).

(1)   The above discussion includes additional GAAP and non-GAAP measures which may not be comparable to other companies.  Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.
(2)  Estimated proved plus probable reserves and contingent resources attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated October 28, 2014, with an effective date of July 1, 2014, using the GLJ (2014-07) price forecast.
(3)  Test results are not necessarily indicative of long-term production performance or of ultimate recovery.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is Management's Discussion and Analysis ("MD&A"), dated November 6, 2014, of Vermilion Energy Inc.'s ("Vermilion" or the "Company") operating and financial results as at and for the three and nine months ended September 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 nine months ended September 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 nine months ended September 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 further increased our full-year 2014 production and capital expenditure guidance to 48,500-49,500 boe/d and $650 million, respectively. The increase in capital expenditures was attributed to increased Mannville development drilling and higher than anticipated costs associated with the Duvernay development program.

We are further revising our 2014 full year production guidance from the previous range of 48,500-49,500 boe/d to a range of 49,000-49,500 boe/d and currently expect to achieve production near the upper end of this refined range for 2014.

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
2014 Guidance - Update       November 10, 2014           650           49,000 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 September 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     $2.54       $7.19       $11.75
Capital appreciation per Vermilion share     $11.56       $24.14       $38.60
Total return per Vermilion share     24.9%       71.1%       170.2%
Annualized total return per Vermilion share     24.9%       19.6%       22.0%
Annualized total return on the S&P TSX High Income Energy Index     13.2%       7.6%       7.5%

(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   Nine Months Ended   % change
        Sep 30,   Jun 30,     Sep 30,   Q3/14 vs.   Q3/14 vs.   Sep 30,     Sep 30,   2014 vs.
        2014   2014     2013   Q2/14   Q3/13   2014     2013   2013
Production                                      
  Crude oil (bbls/d)     29,147   30,184     26,664   (3%)   9%   28,890     25,640   13%
  NGLs (bbls/d)     2,354   2,892     1,945   (19%)   21%   2,463     1,719   43%
  Natural gas (mmcf/d)     110.52   114.08     77.41   (3%)   43%   109.33     81.97   33%
  Total (boe/d)     49,920   52,089     41,510   (4%)   20%   49,574     41,020   21%
  Build (draw) in inventory (mbbl)     104   67     20           74     (218)    
Financial metrics                                      
  Fund flows from operations ($M)     197,898   216,076     165,645   (8%)   19%   619,337     503,866   23%
     Per share ($/basic share)     1.85   2.05     1.63   (10%)   13%   5.90     5.01   18%
  Net earnings ($M)     53,903   53,993     67,796   -   (20%)   210,684     226,131   (7%)
     Per share ($/basic share)     0.50   0.51     0.67   (2%)   (25%)   2.01     2.25   (11%)
  Cash flows from operating activities ($M)     235,010   149,592     158,236   57%   49%   562,840     528,022   7%
  Net debt ($M)     1,243,438   1,168,998     700,286   6%   78%   1,243,438     700,286   78%
  Cash dividends ($/share)     0.645   0.645     0.600   -   8%   1.935     1.800   8%
Activity                                      
  Capital expenditures ($M)     190,033   135,073     135,661   41%   40%   521,481     394,248   32%
  Acquisitions ($M)     40,847   381,139     7,586   (89%)   438%   600,213     7,586   7,812%
  Gross wells drilled     26.00   13.00     21.00           63.00     55.00    
  Net wells drilled     20.31   6.72     16.26           45.86     47.62    

Operational review

  • Recorded consolidated average production of 49,920 boe/d during Q3 2014, a 4% decrease as compared to Q2 2014.  This decrease was primarily driven by a 7% quarter-over-quarter decrease in production in Canada following reduced activity during spring breakup in Q2 2014.
  • Increased consolidated average production for the three and nine months ended September 30, 2014 by approximately 20% versus the comparable periods in 2013, primarily due to growth in Canada, the Netherlands, and incremental production from our acquisition in Germany.  In Canada, production growth of 36% and 33% for the three and nine months ended September 30, 2014 versus the comparable periods in 2013 resulted from our continued development of the Cardium and Mannville plays in Alberta coupled with incremental production from southeast Saskatchewan following our acquisition in April 2014 of Elkhorn Resources Inc. (1,524 boe/d in the year-to-date period).  In the Netherlands, production growth of 32% and 17% for the three and nine months ended September 30, 2014 versus the comparable periods in 2013 resulted from incremental production from our acquisition in the Netherlands in Q4 2013, increased volumes following completion of the Middenmeer Treatment Centre retrofit in the latter part of 2013, and ongoing recompletion and production optimization activities.  These production increases were partially offset by decreased production in France due primarily to the temporary shut-in of natural gas production from the Vic Bilh field for the entirety of 2014.
  • Activity during the quarter included capital expenditures totalling $190.0 million, incurred primarily in Canada, France, and Ireland.  In Canada, capital expenditures totalling $97.4 million were significantly higher than the $37.0 million incurred in Q2 2014 and related to the drilling of 16.86 net wells (3.29 net wells in Q2 2014), with activity influenced by spring breakup in Q2 2014.  In France, capital expenditures of $35.1 million related to the drilling of 3.0 net wells in the Champotran field.  In Ireland, $30.1 million of capital expenditures were incurred relating to various tunnel outfitting and offshore workover activities.
  • Acquisition expenditures for the quarter totalling $40.8 million related to our acquisition in the U.S. and crown land sales, primarily in southeast Saskatchewan, with the purchase of approximately 15,000 net acres.

Financial review

Net earnings

  • Net earnings for Q3 2014 was $53.9 million ($0.50/basic share) as compared to $54.0 million ($0.51/basic share) for Q2 2014.  Quarter-over-quarter net earnings were relatively consistent as lower petroleum and natural gas sales ("sales") and operating income were offset by gains on derivative instruments (including $7.8 million of unrealized gains due to lower forecasted pricing for the remainder of 2014 and the impact on the valuation of our crude oil derivative positions) and lower unrealized foreign exchange losses.  Unrealized foreign exchange losses primarily resulted from the weakening of the Euro versus the Canadian dollar and the resulting impact on our Euro denominated financial assets.  In Q3 2014, the Euro weakened by 3% versus 4% in Q2 2014.
  • Net earnings for the three and nine months ended September 30, 2014 were 20% and 7% lower versus the respective comparable periods in 2013.  These decreases occurred despite significantly increased revenue due to the impact of the aforementioned unrealized foreign exchange losses, increased depletion expense associated with higher production, and higher deferred tax expense due to the utilization of tax losses in Canada.

Cash flows from operating activities

  • Cash flow from operations increased by 49% and 7% for the three and nine months ended September 30, 2014 as compared to the same period in 2013.  Both increases were the result of higher produced volumes and the resulting increase in fund flows from operations.  For the nine months ended September 30, 2014, this increase in fund flows from operations was partially offset by timing differences pertaining to working capital balances.

Fund flows from operations

  • Generated fund flows from operations of $197.9 million during Q3 2014, a decrease of $18.2 million (8%) versus Q2 2014.  This quarter-over-quarter decrease was the result of lower sales partially offset by increased realized derivative gains and decreases in corporate income taxes.  Lower sales were driven largely by weaker commodity pricing coupled with lower sold volumes in Canada and an inventory build in France, partially offset by increased sold volumes in Australia.  Lower corporate income taxes was the result of lower taxable income resulting from decreased sales and revisions to the estimated 2014 effective tax rate in France.
  • Fund flows from operations increased by 19% and 23% for the three and nine months ended September 30, 2014, respectively, versus the comparable periods in 2013.  These increases were primarily the result of increased sales volumes in Canada and the Netherlands coupled with incremental production following our Q1 2014 acquisition in Germany, partially offset by a build in inventory in Australia for both the three and nine months ended September 30, 2014.

Net debt

  • As a result of funding our 2014 acquisitions in Germany and Saskatchewan, net debt increased to $1.2 billion or 1.5 times annualized cash flow as at September 30, 2014.

Dividends

  • Declared dividends of $0.215 per common share per month during 2014, totalling $0.645 per common share for the quarter and $1.935 per common share for the year-to-date period.

COMMODITY PRICES

      Three Months Ended   % change   Nine Months Ended   % change
      Sep 30,     Jun 30,     Sep 30,   Q3/14 vs.   Q3/14 vs.   Sep 30,   Sep 30,   2014 vs.
      2014     2014     2013   Q2/14   Q3/13   2014   2013   2013
Average reference prices                                      
WTI (US $/bbl)     97.17     102.99     105.82   (6%)   (8%)   99.61   98.14   1%
Edmonton Sweet index (US $/bbl)     89.24     96.85     101.10   (8%)   (12%)   92.17   93.03   (1%)
Dated Brent (US $/bbl)     101.85     109.63     110.37   (7%)   (8%)   106.57   108.45   (2%)
AECO ($/GJ)     3.81     4.44     2.31   (14%)   65%   4.56   2.89   58%
TTF ($/GJ)     7.26     7.91     9.94   (8%)   (27%)   8.41   10.17   (17%)
TTF (€/GJ)     5.04     5.27     7.20   (4%)   (30%)   5.68   7.53   (25%)
Average foreign currency exchange rates                                      
CDN $/US $     1.09     1.09     1.04   -   5%   1.09   1.02   7%
CDN $/Euro     1.44     1.50     1.38   (4%)   4%   1.48   1.35   10%
Average realized prices ($/boe)                                      
Canada     64.85     71.56     63.56   (9%)   2%   68.58   61.16   12%
France     107.99     117.29     107.08   (8%)   1%   114.36   104.29   10%
Netherlands     45.73     48.14     61.44   (5%)   (26%)   52.80   62.70   (16%)
Germany     36.43     45.36     -   (20%)   100%   44.68   -   100%
Australia     119.07     126.87     120.95   (6%)   (2%)   124.59   117.65   6%
Consolidated     76.80     82.96     86.10   (7%)   (11%)   82.73   83.10   -
Production mix (% of production)                                      
% priced with reference to WTI     28%     30%     24%           27%   24%    
% priced with reference to AECO     18%     18%     17%           18%   17%    
% priced with reference to TTF     18%     18%     14%           18%   16%    
% priced with reference to Dated Brent     36%     34%     45%           37%   43%    

Reference prices

  • Weakening global oil fundamentals, marked by a growing supply surplus, prompted a decline in oil prices throughout Q3 2014.  Averaging the quarter at US $101.85/bbl, Dated Brent was 7% lower quarter-over-quarter and 8% below the same period last year.
  • WTI also suffered downward price pressure throughout Q3 2014 despite strong refining runs and averaged US $97.17/bbl or 6% lower than Q2 2014 and 8% lower year-over-year.
  • AECO natural gas fell 14% quarter-over-quarter to average $3.81/GJ in Q3 2014.  Even as seasonal factors weighed on prices on a quarter-over-quarter basis, low storage levels and relatively strong flows on export pipelines led prices up 65% year-over-year.
  • European natural gas continued to weaken over the quarter as above-normal storage levels, LNG weakness and modest summer demand led prices lower by 8% quarter-over-quarter and 27% versus the same period last year.
  • The Canadian dollar was relatively flat quarter-over-quarter but 5% weaker to the US dollar year-over-year.

Realized prices

  • Consolidated realized price decreased by 7% for Q3 2014 as compared to Q2 2014 and 11% as compared to Q3 2013.  These decreases were primarily the result of weaker commodity reference prices during Q3 2014 versus the comparable quarters.
  • Consolidated realized price for the nine months ended September 30, 2014 was relatively unchanged versus the same period in 2013 as the impact of weaker TTF pricing was offset by stronger AECO pricing and a weaker Canadian dollar.

FUND FLOWS FROM OPERATIONS

    Three Months Ended   Nine Months Ended
    Sep 30, 2014   Jun 30, 2014   Sep 30, 2013   Sep 30, 2014   Sep 30, 2013
    $M   $/boe   $M   $/boe   $M   $/boe   $M   $/boe   $M   $/boe
Petroleum and natural gas sales   344,688   76.80   387,684   82.96   327,185   86.10   1,113,555   82.73   948,727   83.10
Royalties   (29,000)   (6.46)   (29,013)   (6.21)   (18,730)   (4.93)   (82,037)   (6.09)   (50,320)   (4.41)
Petroleum and natural gas revenues   315,688   70.34   358,671   76.75   308,455   81.17   1,031,518   76.64   898,407   78.69
Transportation expense   (10,979)   (2.45)   (12,032)   (2.57)   (6,549)   (1.72)   (32,872)   (2.44)   (19,843)   (1.74)
Operating expense   (56,227)   (12.53)   (58,213)   (12.46)   (46,246)   (12.17)   (172,426)   (12.81)   (146,903)   (12.87)
General and administration   (16,262)   (3.62)   (17,762)   (3.80)   (12,033)   (3.17)   (48,491)   (3.60)   (35,956)   (3.15)
PRRT   (13,834)   (3.08)   (12,699)   (2.72)   (15,649)   (4.12)   (46,772)   (3.47)   (39,392)   (3.45)
Corporate income taxes   (17,454)   (3.89)   (32,635)   (6.98)   (46,453)   (12.22)   (88,692)   (6.59)   (118,729)   (10.40)
Interest expense   (12,918)   (2.88)   (12,334)   (2.64)   (10,109)   (2.66)   (36,712)   (2.73)   (28,134)   (2.46)
Realized gain (loss) on derivative instruments   8,837   1.97   2,419   0.52   (4,765)   (1.25)   13,896   1.03   (5,782)   (0.51)
Realized foreign exchange gain (loss)   812   0.17   587   0.12   (1,227)   (0.32)   (642)   (0.05)   (572)   (0.05)
Realized other income   235   0.05   74   0.02   221   0.06   530   0.04   770   0.07
Fund flows from operations   197,898   44.08   216,076   46.24   165,645   43.60   619,337   46.02   503,866   44.13

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

($M)       Q3/14 vs. Q2/14       Q3/14 vs. Q3/13       2014 vs. 2013
Fund flows from operations - Comparative period       216,076       165,645       503,866
Sales volume variance:                        
   Canada       (13,984)       38,597       101,499
   France       (8,863)       (11,373)       (15,669)
   Netherlands       (1,638)       8,838       16,748
   Germany       (398)       8,591       28,603
   Australia       9,052       (14,515)       (20,740)
Pricing variance on sold volumes:                        
   WTI       (9,583)       (8,722)       16,434
   AECO       (840)       8,979       22,723
   Dated Brent       (13,351)       (3,631)       33,703
   TTF       (3,391)       (9,261)       (18,473)
Changes in:                        
   Royalties       13       (10,270)       (31,717)
   Transportation       1,053       (4,430)       (13,029)
   Operating expense       1,986       (9,981)       (25,523)
   General and administration       1,500       (4,229)       (12,535)
   PRRT       (1,135)       1,815       (7,380)
   Corporate income taxes       15,181       28,999       30,037
   Interest       (584)       (2,809)       (8,578)
   Realized derivatives       6,418       13,602       19,678
   Realized foreign exchange       225       2,039       (70)
   Realized other income       161       14       (240)
Fund flows from operations - Current Period       197,898       197,898       619,337

Fund flows from operations of $197.9 million during Q3 2014 represented a decrease of $18.2 million (8%) versus Q2 2014.  This quarter-over-quarter decrease was the result of a $43.0 million decrease in sales, partially offset by a $6.4 million increase in hedging proceeds (following weaker commodity prices during the quarter) and a $15.2 million decrease in corporate income taxes.  The decrease in sales included $27.2 million of pricing variance due to a decrease in all relevant commodity prices and $15.8 million of sales volume variance due primarily to lower sales volumes in Canada (resulting from operational declines) and France (due to a build in inventory during Q3 2014), partially offset by higher produced and sold volumes in Australia.  The decrease in corporate income taxes was due to lower taxable income resulting from decreased sales and revisions to the estimated 2014 effective tax rate in France.

On a year-over-year basis, fund flows from operations increased 19% and 23% for the three and nine months ended September 30, 2014, respectively, versus the comparable periods in 2013.  These increases were primarily the result of favorable sales volume variances in Canada and the Netherlands coupled with incremental production following our Q1 2014 acquisition in Germany.   These favorable sales volume variances were partially offset by a build in inventory in Australia.  On a quarterly basis, the year-over-year change in fund flows from operations includes an unfavorable pricing variance of $12.6 million due to weaker crude oil and TTF pricing.  For the nine months ended September 30, 2014 versus the same period in 2013, fund flows from operations includes a favorable variance of $54.4 million due to the impact of the weakening Canadian dollar on crude oil pricing coupled with stronger AECO natural gas pricing, offset partially by lower TTF pricing.

Fluctuations in fund flows from operations (and correspondingly net earnings and cash flows from operating activities) may occur as a result of changes in commodity prices and costs to produce petroleum and natural gas.  In addition, fund flows from operations may be highly affected by the timing of crude oil shipments in Australia and France.  When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on 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   Nine Months Ended   % change
          Sep 30,     Jun 30,     Sep 30,   Q3/14 vs.   Q3/14 vs.   Sep 30, Sep 30,   2014 vs.
Canada business unit       2014     2014     2013   Q2/14   Q3/13   2014 2013   2013
Production                                      
  Crude oil (bbls/d)       11,469     12,676     7,969   (10%)   44%   11,202 8,274   35%
  NGLs (bbls/d)       2,291     2,796     1,897   (18%)   21%   2,387 1,654   44%
  Natural gas (mmcf/d)       57.07     57.59     43.40   (1%)   31%   54.76 42.72   28%
  Total (boe/d)       23,272     25,070     17,099   (7%)   36%   22,714 17,047   33%
Production mix (% of total)                                      
  Crude oil       49%     51%     47%           49% 49%    
  NGLs       10%     11%     11%           11% 10%    
  Natural gas       41%     38%     42%           40% 41%    
Activity                                      
  Capital expenditures ($M)       97,393     36,968     62,270   163%   56%   249,300 163,952   52%
  Acquisitions ($M)       27,883     381,326     7,586           413,977 7,586    
  Gross wells drilled       22.00     9.00     21.00           51.00 48.00    
  Net wells drilled       16.86     3.29     16.26           35.12 40.62    

Production

  • Production in Canada of 23,272 boe/d during Q3 2014 represented a decrease of 7% quarter-over-quarter and an increase of 36% year-over-year. Year-to-date average production of 22,714 boe/d represents an increase of 33% versus the same period in 2013.
  • Quarter-over-quarter decrease in production was largely due to the effect of lower activity levels during spring breakup.
  • The strong year-over-year increase was primarily attributable to production additions from our southeast Saskatchewan acquisition.  Production growth was further supplemented by strong volume additions from our Mannville and Cardium development programs over the same period.
  • Cardium production averaged more than 10,600 boe/d in Q3 2014, and more than 11,000 boe/d year-to-date 2014.
  • Mannville production averaged more than 3,700 boe/d in Q3 2014, and nearly 3,800 boe/d year-to-date 2014.
  • Saskatchewan production averaged approximately 2,600 boe/d in Q3 2014, a 31% increase over the Q2 2014, taking into account an effective acquisition date of April 29, 2014.

Activity review

  • Vermilion drilled a total of 16 (14.7 net) operated wells during Q3 2014.

Cardium

  • We drilled five (4.5 net) operated wells and brought two (2.0 net) operated wells on production during Q3 2014.  Year-to-date we have drilled 17 (16.0 net) operated wells and brought 20 (20.0 net) operated wells on production, of which 15 were long-reach wells with horizontal lengths greater than one mile.
  • Since 2009, we have drilled or participated in 264 (188.7 net) wells.
  • Operating netbacks have averaged approximately $67/boe year-to-date.
  • In 2014, we plan to drill or participate in approximately 40 (27.5 net) wells.

Mannville

  • During Q3 2014, we drilled one (1.0 net) well. Year-to-date we have drilled six (4.7 net) operated wells and brought on production five (3.7 net) operated wells.
  • In 2014, we expect to drill or participate in up to 20 (11.4 net) wells.

Duvernay

  • In Q2 2014, we drilled two (1.3 net) horizontal wells.  One (0.3 net) well was completed in Q3 2014, and the other is anticipated to be completed in Q4 2014. The first well was brought on production subsequent to the third quarter and the second well is anticipated to be on production prior to year-end 2014.

Saskatchewan

  • We drilled 10 (9.2 net) operated Midale wells in Saskatchewan and brought seven gross (6.3 net) operated wells on production during Q3 2014.
  • In 2014, we plan to drill or participate in 12 (10.4 net) Midale wells.

Financial review

          Three Months Ended   % change   Nine Months Ended   % change
Canada business unit       Sep 30,   Jun 30,   Sep 30,   Q3/14 vs.   Q3/14 vs.   Sep 30, Sep 30,   2014 vs.
($M except as indicated)       2014   2014   2013   Q2/14   Q3/13   2014 2013   2013
  Sales       138,853   163,261   100,000   (15%)   39%   425,294 284,638   49%
  Royalties       (19,034)   (18,240)   (11,156)   4%   71%   (49,937) (29,852)   67%
  Transportation expense       (4,048)   (4,024)   (3,272)   1%   24%   (11,170) (8,152)   37%
  Operating expense       (19,074)   (21,179)   (12,770)   (10%)   49%   (56,863) (42,586)   34%
  General and administration       (4,523)   (6,560)   (3,484)   (31%)   30%   (13,951) (10,501)   33%
  Fund flows from operations       92,174   113,258   69,318   (19%)   33%   293,373 193,547   52%
Netbacks ($/boe)                                  
  Sales       64.85   71.56   63.56   (9%)   2%   68.58 61.16   12%
  Royalties       (8.89)   (7.99)   (7.09)   11%   25%   (8.05) (6.41)   26%
  Transportation expense       (1.89)   (1.76)   (2.08)   7%   (9%)   (1.80) (1.75)   3%
  Operating expense       (8.91)   (9.28)   (8.12)   (4%)   10%   (9.17) (9.15)   -
  General and administration       (2.11)   (2.88)   (2.21)   (27%)   (5%)   (2.25) (2.26)   -
  Fund flows from operations netback       43.05   49.65   44.06   (13%)   (2%)   47.31 41.59   14%
Reference prices                                  
  WTI (US $/bbl)       97.17   102.99   105.82   (6%)   (8%)   99.61 98.14   1%
  Edmonton Sweet index (US $/bbl)       89.24   96.85   101.10   (8%)   (12%)   92.17 93.03   (1%)
  AECO ($/GJ)       3.81   4.44   2.31   (14%)   65%   4.56 2.89   58%

Sales

  • The realized price for our crude oil production in Canada is directly linked to WTI but is subject to market conditions in Western Canada.  These market conditions can result in fluctuations in the pricing differential, as reflected by the Edmonton Sweet index price.  The realized price of our NGLs in Canada is based on product specific differentials pertaining to trading hubs in the United States.  The realized price of our natural gas in Canada is based on the AECO spot price in Canada.
  • Sales per boe decreased by 9% quarter-over-quarter as a result of an 8% decrease in Edmonton Sweet index pricing and a 14% decrease in AECO pricing.  This decrease coupled with lower production volumes resulting from reduced activity over spring breakup resulted in a 15% decrease in sales.
  • On a year-over-year basis, sales per boe increased by 2% and 12% for the three and nine months ended September 30, 2014 versus the same periods in 2013.  Sales increased despite declining Edmonton Sweet index pricing due to higher AECO pricing and increased production mix towards crude oil and NGLs.  These increases coupled with incremental production from our Saskatchewan acquisition and production growth in the Cardium and Mannville resource plays resulted in sales growth of 39% and 49% for the three and nine months ended September 30, 2014, respectively.

Royalties

  • Royalty expense as a percentage of sales increased to 13.7% for Q3 2014 from 11.2% in both Q3 2013 and Q2 2014.  Royalty expense as a percentage of sales increased to 11.7% for the year-to-date period ended Q3 2014 as compared to 10.5% for the same period of the prior year.
  • The quarter-over-quarter increase is largely associated with wells coming off of incentive royalty rates after reaching specified production thresholds.  In addition, the year-over-year increase in royalty rates as a percentage of sales is partially attributable to increased gas prices as well as slightly higher average royalty rates associated with Vermilion's Saskatchewan production.

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 increased for the year-to-date period ended Q3 2014 as compared to the same period in 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 for Q3 2014 was slightly lower than the prior quarter due to favorable equalization adjustments received in the current quarter.  The increase in operating expense per boe for the current quarter as compared to the same quarter in 2013 is attributable to higher operating expenses associated with the Saskatchewan properties Vermilion acquired in the second quarter of 2014.  Year-to-date operating expense per boe is consistent with the prior year due to project timing, partially offset by the higher costs associated with Vermilion's Saskatchewan production.

General and administration

  • General and administration expense decreased in the current quarter as compared to the prior quarter largely due to higher costs in the previous quarter related to the Saskatchewan acquisition including legal and consultant costs ($1.1MM) and additional salary allocations from our Corporate segment to our Canadian business unit associated with the integration process ($0.7MM).
  • Year-over-year, the increase in general and administration expense is associated with incremental expense associated with the Saskatchewan acquisition, higher staffing levels and the timing of expenditures.

FRANCE BUSINESS UNIT

Overview

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

Operational review

          Three Months Ended   % change   Nine Months Ended   % change
          Sep 30,     Jun 30,     Sep 30,   Q3/14 vs.   Q3/14 vs.   Sep 30,   Sep 30,   2014 vs.
France business unit       2014     2014     2013   Q2/14   Q3/13   2014   2013   2013
Production                                        
  Crude oil (bbls/d)       11,111     11,025     11,625   1%   (4%)   10,970   10,786   2%
  Natural gas (mmcf/d)       -     -     5.23   -   (100%)   -   4.54   (100%)
  Total (boe/d)       11,111     11,025     12,496   1%   (11%)   10,970   11,544   (5%)
Inventory (mbbls)                                        
  Opening crude oil inventory       179     238     202           268   354    
  Adjustments       -           -           -   5    
  Crude oil production       1,022     1,003     1,069           2,995   2,945    
  Crude oil sales       (987)     (1,062)     (1,045)           (3,049)   (3,078)    
  Closing crude oil inventory       214     179     226           214   226    
Production mix (% of total)                                        
  Crude oil       100%     100%     93%           100%   93%    
  Natural gas       -     -     7%           -   7%    
Activity                                        
  Capital expenditures ($M)       35,082     37,614     23,664   (7%)   48%   110,663   68,479   62%
  Gross wells drilled       3.00     2.00     -           7.00   5.00    
  Net wells drilled       3.00     2.00     -           7.00   5.00    

Production

  • Q3 production increased 1% on a quarter-over-quarter basis but remained 11% lower year-over-year.  Year-to-date production was 5% lower versus the same period of 2013.  Year-over-year and year-to-date production volumes were lower due to the shut-in of gas volumes at Vic Bilh.
  • In late September 2013, the third party Lacq processing facility that processed our Vic Bilh gas production was permanently closed.  As a result, our Vic Bilh gas production has been temporarily shut-in while preparations to transfer to an alternative facility are completed.  We currently expect 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 early 2016.
  • As a result, current production volumes remain 100% weighted to Brent-based crude.

Activity review

  • Vermilion drilled three (3.0 net) wells in the Champotran field in the Paris Basin during Q3 2014.
  • During Q3 2014, we also completed a number of workovers, as well as seismic and facility integrity projects.
  • The five wells drilled in the Champotran field in 2014 were brought on production at various times during the third quarter and are currently producing approximately 200 bbls/d per well.

Financial review

          Three Months Ended   % change   Nine Months Ended   % change
France business unit       Sep 30,     Jun 30,     Sep 30,   Q3/14 vs.   Q3/14 vs.   Sep 30,   Sep 30,   2014 vs.
($M except as indicated)       2014     2014     2013   Q2/14   Q3/13   2014   2013   2013
  Sales       106,576     124,617     120,574   (14%)   (12%)   348,753   342,558   2%
  Royalties       (6,978)     (7,796)     (7,574)   (10%)   (8%)   (22,125)   (20,468)   8%
  Transportation expense       (4,741)     (5,385)     (2,713)   (12%)   75%   (14,879)   (7,883)   89%
  Operating expense       (15,215)     (16,550)     (14,599)   (8%)   4%   (48,185)   (51,473)   (6%)
  General and administration       (6,411)     (5,559)     (4,964)   15%   29%   (17,164)   (14,577)   18%
  Current income taxes       (10,744)     (24,761)     (31,717)   (57%)   (66%)   (60,769)   (66,500)   (9%)
  Fund flows from operations       62,487     64,566     59,007   (3%)   6%   185,631   181,657   2%
Netbacks ($/boe)                                        
  Sales       107.99     117.29     107.08   (8%)   1%   114.36   104.29   10%
  Royalties       (7.07)     (7.34)     (6.73)   (4%)   5%   (7.26)   (6.23)   17%
  Transportation expense       (4.80)     (5.07)     (2.41)   (5%)   99%   (4.88)   (2.40)   103%
  Operating expense       (15.42)     (15.58)     (12.97)   (1%)   19%   (15.80)   (15.67)   1%
  General and administration       (6.50)     (5.24)     (4.41)   24%   47%   (5.63)   (4.44)   27%
  Current income taxes       (10.89)     (23.30)     (28.17)   (53%)   (61%)   (19.93)   (20.25)   (2%)
  Fund flows from operations netback       63.31     60.76     52.39   4%   21%   60.86   55.30   10%
Reference prices                                        
  Dated Brent (US $/bbl)       101.85     109.63     110.37   (7%)   (8%)   106.57   108.45   (2%)

Sales

  • Crude oil production in France is priced with reference to Dated Brent.
  • Sales per boe for Q3 2014 decreased by 8%, consistent with the 7% decrease in the Dated Brent reference price.  This decrease, coupled with a build in inventory during Q3 2014, resulted in a 14% decrease in sales.
  • On a year-over-year basis, sales per boe increased by 1% and 10% for the three and nine months ended September 30, 2014 as compared to the same periods in 2013.  This sales increase occurred despite an 8% and 2% decrease in Dated Brent reference price for the three and nine months ended September 30, 2014 due to the offsetting impact of the weakening of the Canadian dollar versus the US dollar.  On a year-to-date basis, the aforementioned increase in sales per boe was mostly offset by the shut-in of natural gas production, resulting in a 2% increase in sales.

Royalties

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

Transportation

  • Historically, transportation expense in France related to shipments of crude oil by tanker from the Aquitaine Basin to third party refineries.  As a result of the closure of the Lacq processing facility in Q3 2013, Vermilion began incurring additional transportation charges to ship Vic Bilh crude oil production to market.  Accordingly, transportation expense 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 per boe for Q3 2014 was consistent with the prior quarter.  The increases in operating expense per boe for the three and nine months ended September 30, 2014 versus the same periods in 2013 are related to a weaker Canadian dollar relative to the Euro in 2014 versus 2013 and the timing of expenditures.

General and administration

  • General and administration expense increased in Q3 2014 versus the prior quarter as a result of higher allocations from Vermilion's Corporate segment.  These higher allocations, coupled with increased staffing costs and the weaker Canadian dollar relative to the Euro, resulted in an increase in general and administrative expense for the three and nine months ended September 30, 2014.

Current income taxes

  • Current income taxes in France apply to taxable income after eligible deductions at a statutory rate of 34.4% for 2014.  In addition, a 10.7% temporary surtax is applicable for tax year 2014 and 2015 if annual revenue exceeds 250 million €.  For 2014, the effective rate on current taxes is expected to be between approximately 22% and 26% 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 Q3 2014 were lower than both Q2 2014 and Q3 2013 as Q3 2014 current income taxes reflects our revised expectation of the effective tax rate given the declining Dated Brent reference price.  Based on current expectations for Q4 2014 Dated Brent pricing, the France business unit is not expected to be subject to the 10.7% temporary surtax for 2014.
  • On a year-to-date basis, current income taxes for the nine months ended September 30, 2014 represents an effective tax rate of 25%.  This decrease versus the 27% effective tax rate for the nine months ended September 30, 2013 reflects our revised expectations on the effective tax rate given the declining Dated Brent reference price.

NETHERLANDS BUSINESS UNIT

Overview

  • Entered the Netherlands in 2004.
  • Second largest onshore gas producer.
  • Interests include 16 licenses in the northeast region, five licenses in the central region, and two offshore licenses.
  • Licenses include more than 820,000 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   Nine Months Ended   % change
          Sep 30,     Jun 30,     Sep 30,   Q3/14 vs.   Q3/14 vs.   Sep 30,   Sep 30,   2014 vs.
Netherlands business unit       2014     2014     2013   Q2/14   Q3/13   2014   2013   2013
Production                                        
  NGLs (bbls/d)       63     96     48   (34%)   31%   76   65   17%
  Natural gas (mmcf/d)       38.07     40.35     28.78   (6%)   32%   40.50   34.71   17%
  Total (boe/d)       6,407     6,822     4,845   (6%)   32%   6,827   5,849   17%
Activity                                        
  Capital expenditures ($M)       10,087     21,513     8,316   (53%)   21%   51,718   12,845   303%
  Gross wells drilled       1.00     2.00     -           5.00   -    
  Net wells drilled       0.45     1.43     -           3.74   -    

Production

  • Production was 6% lower quarter-over-quarter while year-over-year production growth exceeded 32%.  Year-to-date production volumes have increased 17% versus the same period of 2013.  Both year-over-year and year-to-date production volumes benefited from the addition of production from the DeHoeve-01 well during the second quarter and increased throughput capacity following a retrofit at our Middenmeer Treatment Centre completed in late 2013.
  • Production in the Netherlands is managed to meet corporate targets, optimize facility use and regulate declines.

Activity review

  • Vermilion drilled the Diever-02 well (45% working interest), in the Drenthe IIIb concession, during Q3 2014. The well primarily targeted the Rotliegend Group (Permian sandstones) where it encountered two well-developed gas bearing intervals (Akkrum and Slochteren) with a net pay thickness of approximately 36 metres.
  • A subsequent three hour clean-up test conducted on the Slochteren formation delivered 25.7 mmcf/d of gas on a 40/64 inch choke with 2,615 psi of wellhead flowing pressure with no indications of pressure drop during the test(1).  The flow rate was limited by the 3.5 inch diameter of the tubing and the capacity of the test equipment. The Akkrum formation is anticipated to be perforated at a later date once the Slochteren formation has been fully produced.
  • The Diever-02 well marked the first well drilled by Vermilion on the lands acquired in October 2013. 
  • An additional two wells (Langezwaag-02 and Sonnega-02) are planned for drilling during Q4 2014.

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

Financial review

    Three Months Ended   % change       Nine Months Ended   % change  
Netherlands business unit Sep 30, Jun 30, Sep 30,   Q3/14 vs. Q3/14 vs.     Sep 30, Sep 30,   2014 vs.
($M except as indicated) 2014 2014 2013   Q2/14 Q3/13     2014 2013   2013
  Sales 26,960 29,881 27,382   (10%) (2%)     98,395 100,119   (2%)
  Royalties (942) (693) -     36% 100%     (3,843) -     100%
  Operating expense (5,409) (6,390) (5,209)   (15%) 4%     (17,841) (14,438)   24%
  General and administration (204) (326) (333)   (37%) (39%)     (1,128) (1,171)   (4%)
  Current income taxes (1,189) (1,301) (6,810)   (9%) (83%)     (6,278) (25,865)   (76%)
  Fund flows from operations 19,216 21,171 15,030   (9%) 28%     69,305 58,645   18%
Netbacks ($/boe)                        
  Sales 45.73 48.14 61.44   (5%) (26%)     52.80 62.70   (16%)
  Royalties (1.60) (1.12) -     43% 100%     (2.06) -     100%
  Operating expense (9.18) (10.29) (11.69)   (11%) (21%)     (9.57) (9.04)   6%
  General and administration (0.35) (0.53) (0.75)   (34%) (53%)     (0.61) (0.73)   (16%)
  Current income taxes (2.02) (2.10) (15.28)   (4%) (87%)     (3.37) (16.20)   (79%)
  Fund flows from operations netback 32.58 34.10 33.72   (4%) (3%)     37.19 36.73   1%
Reference prices                        
  TTF ($/GJ) 7.26 7.91 9.94   (8%) (27%)     8.41 10.17   (17%)
  TTF (€/GJ) 5.04 5.27 7.20   (4%) (30%)     5.68 7.53   (25%)

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 per boe in Q3 2014 versus Q2 2014 and Q3 2013 was largely in-line with the change in the Canadian dollar equivalent of the TTF reference price.
  • On a year-over-year basis, sales declined by 2% as a result of the 17% decrease in the TTF reference price offset by a 17% 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 per boe decreased in Q3 2014 from Q2 2014 due to the timing of project work.
  • Operating expense per boe decreased in Q3 2014 as compared to Q3 2013 due to significantly higher volumes year-over-year.
  • For the year-to-date period ended Q3 2014, operating expense per boe increased as compared to the prior year due to the strengthening of the Euro versus the Canadian dollar as well as higher salary costs associated with continued organic growth in the Netherlands business unit.

General and administration

  • General and administration expense remained relatively consistent for the periods presented, although the quarterly periods are impacted by the timing of expenditures.

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 for the nine months ended September 30, 2014 as compared to the same period in 2013 as a result of decreased revenues, lower TTF reference prices and an increase in tax deductions for depletion during the current year.

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       Nine Months Ended
    Sep 30, Jun 30,   Q3/14 vs.     Sep 30,
Germany business unit 2014 2014   Q2/14     2014
Production              
  Natural gas (mmcf/d) 15.38 16.13   (5%)     14.07
  Total (boe/d) 2,563 2,689   (5%)     2,345
Activity              
  Capital expenditures ($M) 1,358 630   116%     2,184
  Acquisitions ($M) -   -           172,871

Production

  • Achieved Q3 2014 production of 2,563 boe/d, a decrease of 5% as compared to 2,689 boe/d in Q2 2014.  Year-to-date production has averaged 2,345 boe/d, taking into account an effective date for production of February 1, 2014.

Activity review

  • Continued the integration of the German business unit and commenced planning with our working interest partners for future drilling operations.
  • During the first quarter of 2014, we participated in the drilling of the Deblinghausen Z7a development well (25% working interest) in Germany.  The well logged 81 metres of net pay in the Zechstein Carbonate, and was production tested by the operator in late September for a period of 17 days.  During the test, the Deblinghausen Z7a well produced raw gas at rates of 10.2 mmcf/d at a flowing tubing pressure of 1,840 psi(1).  Subsequent to the end of the quarter, this well was placed on production at an initial gross production rate of 16.5 mmcf/d of raw gas at a flowing tubing pressure of approximately 1,300 psi.
  • 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.
(1)      Test result is not necessarily indicative of long-term performance or of ultimate recovery.

Financial review

    Three Months Ended   % change       Nine Months Ended
Germany business unit Sep 30, Jun 30,   Q3/14 vs.     Sep 30,
($M except as indicated) 2014 2014   Q2/14     2014
  Sales 8,591 11,097   (23%)     28,603
  Royalties (2,046) (2,284)   (10%)     (6,132)
  Transportation expense (675) (1,052)   (36%)     (2,149)
  Operating expense (2,227) (2,043)   9%     (5,824)
  General and administration (1,090) (830)   31%     (2,488)
  Current income taxes (146) (506)   (71%)     (1,189)
  Fund flows from operations 2,407 4,382   (45%)     10,821
Netbacks ($/boe)              
  Sales 36.43 45.36   (20%)     44.68
  Royalties (8.68) (9.34)   (7%)     (9.58)
  Transportation expense (2.86) (4.30)   (33%)     (3.36)
  Operating expense (9.44) (8.35)   13%     (9.10)
  General and administration (4.62) (3.39)   36%     (3.89)
  Current income taxes (0.62) (2.07)   (70%)     (1.86)
  Fund flows from operations netback 10.21 17.91   (43%)     16.89
Reference prices              
  TTF ($/GJ) 7.26 7.91   (8%)     8.41
  TTF (€/GJ) 5.04 5.27   (4%)     5.68

Sales

  • The price of our natural gas in Germany is based on the TTF month-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees.
  • Sales per boe decreased by 20% from Q2 2014 due to a decrease in the TTF reference price.  This decrease, coupled with lower production volumes, resulted in a 23% quarter-over-quarter decrease in sales.

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

General and administration

  • General and administration expense increased quarter-over-quarter as a result of adding staff to the German business unit.

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 4% 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.

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       Nine Months Ended   % change  
Ireland business unit Sep 30, Jun 30, Sep 30,   Q3/14 vs. Q3/14 vs.     Sep 30, Sep 30,   2014 vs.
($M) 2014 2014 2013   Q2/14 Q3/13     2014 2013   2013
  Transportation expense (1,515) (1,571) (564)   (4%) 169%     (4,674) (3,808)   23%
  General and administration (334) (252) (312)   33% 7%     (868) (959)   (9%)
  Fund flows from operations (1,849) (1,823) (876)   1% 111%     (5,542) (4,767)   16%
Activity                        
  Capital expenditures 30,050 27,221 35,028   10% (14%)     73,507 76,426   (4%)

Activity review

  • Completed tunnel boring operations beneath Sruwaddacon Bay on May 21, 2014.  Installation of flow and umbilical lines has been completed in the 4.9 km tunnel, with remaining work including final cable installation, hydro-testing and grouting.  Offshore well and flow line activities are complete and the wells are ready for operation.
  • 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       Nine Months Ended   % change  
    Sep 30, Jun 30, Sep 30,   Q3/14 vs. Q3/14 vs.     Sep 30, Sep 30,   2014 vs.
Australia business unit 2014 2014 2013   Q2/14 Q3/13     2014 2013   2013
Production                        
  Crude oil (bbls/d) 6,567 6,483 7,070   1% (7%)     6,718 6,580   2%
Inventory (mbbls)                        
  Opening crude oil inventory 189 63 187           130 268    
  Crude oil production 604 590 650           1,834 1,796    
  Crude oil sales (535) (464) (654)           (1,706) (1,881)    
  Closing crude oil inventory 258 189 183           258 183    
Activity                        
  Capital expenditures ($M) 15,985 10,991 5,880   45% 172%     32,667 69,511   (53%)
  Gross wells drilled -   -   -             -   2.00    
  Net wells drilled -   -   -             -   2.00    

Production

  • Quarterly production increased 1% quarter-over-quarter and was 7% lower year-over-year. Year-to-date 2014 production has increased 2% versus the same period 2013.
  • 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 current productive capacity.

Activity review

  • In Q3 2014, efforts were largely focused on facilities repairs and engineering studies, including the expansion of accommodation quarters on the Wandoo B platform.
  • 2014 planned activities include ongoing facilities maintenance, enhancement, and refurbishment along with preparation and permitting activities in advance of our planned two-well 2015 drilling program.

Financial review

    Three Months Ended   % change       Nine Months Ended   % change  
Australia business unit Sep 30, Jun 30, Sep 30,   Q3/14 vs. Q3/14 vs.     Sep 30, Sep 30,   2014 vs.
($M except as indicated) 2014 2014 2013   Q2/14 Q3/13     2014 2013   2013
  Sales 63,708 58,828 79,229   8% (20%)     212,510 221,412   (4%)
  Operating expense (14,302) (12,051) (13,668)   19% 5%     (43,713) (38,406)   14%
  General and administration (1,378) (1,661) (1,414)   (17%) (3%)     (4,245) (4,310)   (2%)
  PRRT (13,834) (12,699) (15,649)   9% (12%)     (46,772) (39,392)   19%
  Corporate income taxes (5,148) (5,689) (7,666)   (10%) (33%)     (19,678) (25,525)   (23%)
  Fund flows from operations 29,046 26,728 40,832   9% (29%)     98,102 113,779   (14%)
Netbacks ($/boe)                        
  Sales 119.07 126.87 120.95   (6%) (2%)     124.59 117.65   6%
  Operating expense (26.73) (25.99) (20.86)   3% 28%     (25.63) (20.41)   26%
  General and administration (2.58) (3.58) (2.16)   (28%) 19%     (2.49) (2.29)   9%
  PRRT (25.86) (27.39) (23.89)   (6%) 8%     (27.42) (20.93)   31%
  Corporate income taxes (9.62) (12.27) (11.70)   (22%) (18%)     (11.54) (13.56)   (15%)
  Fund flows from operations netback 54.28 57.64 62.34   (6%) (13%)     57.51 60.46   (5%)
Reference prices                        
  Dated Brent (US $/bbl) 101.85 109.63 110.37   (7%) (8%)     106.57 108.45   (2%)

Sales

  • Our production in Australia currently receives a premium to Dated Brent.
  • Sales per boe for Q3 2014 decreased by 6% versus Q2 2014 as a result of a decrease in the Dated Brent reference price.  This decrease was offset by larger sales volumes resulting in an 8% increase in sales.
  • Sales per boe for the three and nine months ended September 30, 2014 versus the same periods in 2013 reflect the decrease in the Dated Brent reference price offset by the weakening of the Canadian dollar versus the US dollar.  These changes, coupled with lower sales volumes, resulted in a 20% and 4% decrease in sales in the three and nine months ended September 30, 2014 versus the same periods in 2013.

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 Q3 2014 remained consistent with the expense for Q2 2014.
  • Operating expense per boe for the three and nine months ended September 30, 2014 was higher than the expense for the comparative periods in the prior year due to increased diesel usage and higher salary costs.
  • Operating expense for the three and nine months ended September 30, 2014 were 5% and 14% higher, respectively, than the comparable periods in 2013 as a result of increased diesel usage and higher salary costs, partially offset by a build in inventory in the current periods.  When crude oil inventory is built up, the related operating expense is deferred and carried as inventory on our balance sheet.

General and administration

  • General and administration expense decreased slightly during Q3 2014 as compared to Q2 2014 and Q3 2013 due to timing of expenditures.  For the year-to-date period ended September 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 nine months ended September 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     Nine Months Ended
  Sep 30, Jun 30, Sep 30,     Sep 30, Sep 30,
($M) 2014 2014 2013     2014 2013
General and administration (2,322) (2,574) (1,526)     (8,647) (4,438)
Current income taxes (227) (378) (260)     (778) (839)
Interest expense (12,918) (12,334) (10,109)     (36,712) (28,134)
Realized gain (loss) on derivatives 8,837 2,419 (4,765)     13,896 (5,782)
Realized foreign exchange gain (loss) 812 587 (1,227)     (642) (572)
Realized other income 235 74 221     530 770
Fund flows from operations (5,583) (12,206) (17,666)     (32,353) (38,995)
               

General and administration

  • General and administration expense was largely consistent in Q3 2014 as compared to Q2 2014.
  • On a year-over-year basis, the increase in general and administration costs for the three and nine months ended September 30, 2014 as compared to the same period in 2013 was a result of the impact of certain outstanding Vermilion Incentive Plan ("VIP") awards to be settled partially in cash.

Current income taxes

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

Interest expense

  • Interest expense is incurred on our senior unsecured notes and on borrowings under our revolving credit facility.  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 also assisting us in the execution of our capital and development plans.
  • The realized gain in 2014 related primarily to amounts received on our TTF and Dated Brent derivatives, partially offset by payments made on our AECO derivatives.
  • A listing of derivative positions as at September 30, 2014 is included in "Supplemental Table 2" in this MD&A.

FINANCIAL PERFORMANCE REVIEW

    Three Months Ended
    Sep 30, Jun 30, Mar 31, Dec 31, Sep 30, Jun 30, Mar 31, Dec 31,
($M except per share) 2014 2014 2014 2013 2013 2013 2013 2012
Petroleum and natural gas sales 344,688 387,684 381,183 325,108 327,185 311,966 309,576 241,233
Net earnings 53,903 53,993 102,788 101,510 67,796 106,198 52,137 56,914
Net earnings per share                
  Basic 0.50 0.51 1.00 1.00 0.67 1.05 0.53 0.58
  Diluted 0.50 0.50 0.99 0.98 0.66 1.04 0.51 0.57

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

($M) Q3/14 vs. Q2/14 Q3/14 vs. Q3/13 2014 vs. 2013
Net earnings - Comparative period 53,993 67,796 226,131
Changes in:      
Fund flows from operations (18,178) 32,253 115,471
Equity based compensation 3,497 (1,941) (9,770)
Unrealized gain or loss on derivative instruments 9,321 11,499 6,375
Unrealized foreign exchange gain or loss 11,879 (16,099) (43,351)
Unrealized other income (701) (321) 282
Accretion (114) 150 312
Depletion and depreciation 743 (25,333) (69,821)
Deferred tax (6,537) (14,101) (14,945)
Net earnings - Current Period 53,903 53,903 210,684

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

Equity based compensation
Equity based compensation expense relates to non-cash compensation expense attributable to long-term incentives granted to directors, officers and employees under the 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 nine months ended September 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 was lower for Q3 2014 as compared to Q2 2014 due to aforementioned upward revision of future performance condition assumptions 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 nine months ended September 30, 2014, we recognized an unrealized gain on derivative instruments of $10.1 million, relating primarily to our crude oil swaps and collars.  As at September 30, 2014, we have a net derivative asset position of $7.6 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 nine months ended September 30, 2014, the Canadian dollar strengthened versus the Euro resulting in unrealized foreign exchange losses of $11.9 million and $13.6 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.

Q3 2014 accretion expense was relatively consistent as compared to Q2 2014 and the comparable periods in 2013.

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

Depletion and depreciation on a per boe basis for Q3 2014 of $23.21 was higher as compared to Q2 2014 of $22.45/boe as a result of lower production in Canada.  Depletion and depreciation on a per boe basis increased for the three and nine month periods ended September 30, 2014 to $23.21/boe and $22.92/boe, respectively, as compared to the same periods in 2013 of $20.74/boe and $20.91/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 when compared to legacy producing assets.

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

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
  Sep 30, Dec 31,     Sep 30, Dec 31,
($M) 2014 2013     2014 2013
Revolving credit facility 3.3% 3.3%     974,857 766,898
Senior unsecured notes 6.5% 6.5%     223,791 223,126
Long-term debt 3.9% 4.7%     1,198,648 990,024

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
  Sep 30, Dec 31,
  2014 2013
Total facility amount 1 $1.50 billion $1.20 billion
Amount drawn $974.9 million $766.9 million
Letters of credit outstanding $10.3 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
    Sep 30, Dec 31,
Financial covenant Limit 2014 2013
Consolidated total debt to consolidated EBITDA 4.0 1.16 1.06
Consolidated total senior debt to consolidated EBITDA 3.0 0.94 0.82
Consolidated total senior debt to total capitalization 50% 31% 28%

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

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

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

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

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

Prior to February 10, 2015, Vermilion may redeem all or part of the senior unsecured notes at 103.25% of their principal amount plus any accrued and unpaid interest.  Subsequent to February 10, 2015, Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest.  The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

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

  As At
  Sep 30, Dec 31,
($M) 2014 2013
Long-term debt 1,198,648 990,024
Current liabilities 431,175 347,444
Current assets (386,385) (587,783)
Net debt 1,243,438 749,685
     
Ratio of net debt to annualized fund flows from operations 1.5 1.1

Long-term debt as at September 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 a result of this increase to long-term debt, the year-to-date ratio of net debt to annualized fund flows from operations increased from 1.1 as at December 31, 2013 to 1.5 as at September 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 nine months ended September 30, 2014, we maintained monthly dividends at $0.215 per share and declared dividends totalled $203.6  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   902   58,450
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 September 30, 2014   106,921   1,937,750

As at September 30, 2014, there were approximately 1.7 million VIP awards outstanding.  As at November 6, 2014, there were approximately 107.0 million shares outstanding.

ASSET RETIREMENT OBLIGATIONS

As at September 30, 2014, asset retirement obligations were $397.9 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 September 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 pronouncements are currently being evaluated.

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

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

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 September 30, 2014   Nine Months Ended September 30, 2014     Three Months
Ended
September 30,
2013
  Nine Months
Ended
September 30,
2013
  Oil & NGLs Natural Gas Total   Oil & NGLs Natural Gas Total     Total   Total
  $/bbl $/mcf $/boe   $/bbl $/mcf $/boe     $/boe   $/boe
Canada                        
Sales 91.25 4.44 64.85   95.24 4.82 68.58     63.56   61.16
Royalties (13.37) (0.40) (8.89)   (12.06) (0.35) (8.05)     (7.09)   (6.41)
Transportation (2.50) (0.17) (1.89)   (2.33) (0.17) (1.80)     (2.08)   (1.75)
Operating (9.19) (1.42) (8.91)   (9.73) (1.39) (9.17)     (8.12)   (9.15)
Operating netback 66.19 2.45 45.16   71.12 2.91 49.56     46.27   43.85
General and administration     (2.11)       (2.25)     (2.21)   (2.26)
Fund flows from operations netback     43.05       47.31     44.06   41.59
France                        
Sales 107.99 -   107.99   114.36 -   114.36     107.08   104.29
Royalties (7.07) -   (7.07)   (7.25) -   (7.26)     (6.73)   (6.23)
Transportation (4.80) -   (4.80)   (4.88) -   (4.88)     (2.41)   (2.40)
Operating (15.42) -   (15.42)   (15.80) -   (15.80)     (12.97)   (15.67)
Operating netback 80.70 -   80.70   86.43 -   86.42     84.97   79.99
General and administration     (6.50)       (5.63)     (4.41)   (4.44)
Current income taxes     (10.89)       (19.93)     (28.17)   (20.25)
Fund flows from operations netback     63.31       60.86     52.39   55.30
Netherlands                        
Sales 90.01 7.55 45.73   96.66 8.72 52.80     61.44   62.70
Royalties -   (0.27) (1.60)   -   (0.35) (2.06)     -     -  
Operating -   (1.54) (9.18)   -   (1.61) (9.57)     (11.69)   (9.04)
Operating netback 90.01 5.74 34.95   96.66 6.76 41.17     49.75   53.66
General and administration     (0.35)       (0.61)     (0.75)   (0.73)
Current income taxes     (2.02)       (3.37)     (15.28)   (16.20)
Fund flows from operations netback     32.58       37.19     33.72   36.73
Germany                        
Sales -   6.07 36.43   -   7.45 44.68     -     -  
Royalties -   (1.45) (8.68)   -   (1.60) (9.58)     -     -  
Transportation -   (0.48) (2.86)   -   (0.56) (3.36)     -     -  
Operating -   (1.57) (9.44)   -   (1.52) (9.10)     -     -  
Operating netback -   2.57 15.45   -   3.77 22.64     -     -  
General and administration     (4.62)       (3.89)     -     -  
Current income taxes     (0.62)       (1.86)     -     -  
Fund flows from operations netback     10.21       16.89     -     -  
Australia                        
Sales 119.07 -   119.07   124.59 -   124.59     120.95   117.65
Operating (26.73) -   (26.73)   (25.63) -   (25.63)     (20.86)   (20.41)
PRRT (1) (25.86) -   (25.86)   (27.42) -   (27.42)     (23.89)   (20.93)
Operating netback 66.48 -   66.48   71.54 -   71.54     76.20   76.31
General and administration     (2.58)       (2.49)     (2.16)   (2.29)
Corporate income taxes     (9.62)       (11.54)     (11.70)   (13.56)
Fund flows from operations netback     54.28       57.51     62.34   60.46
Total Company                        
Sales 102.49 5.74 76.80   108.02 6.60 82.73     86.10   83.10
Realized hedging gain (loss) 1.57 0.44 1.97   0.37 0.36 1.03     (1.25)   (0.51)
Royalties (8.56) (0.50) (6.46)   (7.88) (0.51) (6.09)     (4.93)   (4.41)
Transportation (2.83) (0.30) (2.45)   (2.77) (0.31) (2.44)     (1.72)   (1.74)
Operating (14.73) (1.48) (12.53)   (15.08) (1.49) (12.81)     (12.17)   (12.87)
PRRT (1) (4.95) -   (3.08)   (5.51) -   (3.47)     (4.12)   (3.45)
Operating netback 72.99 3.90 54.25   77.15 4.65 58.95     61.91   60.12
General and administration     (3.62)       (3.60)     (3.17)   (3.15)
Interest expense     (2.88)       (2.73)     (2.66)   (2.46)
Realized foreign exchange gain (loss)     0.17       (0.05)     (0.32)   (0.05)
Other income     0.05       0.04     0.06   0.07
Corporate income taxes (1)     (3.89)       (6.59)     (12.22)   (10.40)
Fund flows from operations netback     44.08       46.02     43.60   44.13
                         
(1)    Vermilion considers Australian PRRT to be an operating item and accordingly has included PRRT in the calculation of operating netbacks.  Current income taxes presented above excludes PRRT.

Supplemental Table 2: Hedges

The following tables outline Vermilion's outstanding risk management positions as at September 30, 2014:

  Note Volume Strike Price(s)
Crude Oil      
WTI - Collar      
October 2014 - December 2014   250 bbl/d 90.00 - 101.10 US $
WTI - Swap      
May 2014 - November 2014 1 250 bbl/d 97.25 CAD $
July 2014 - December 2014   750 bbl/d 99.00 US $
September 2014 - October 2014 2 500 bbl/d 96.05 US $
October 2014 - November 2014 3 500 bbl/d 92.90 US $
October 2014 - December 2014 4 1,750 bbl/d 94.89 US $
MSW - Fixed Price Differential      
October 2014 - December 2014   1,000 bbl/d WTI less 8.40 US $
Dated Brent - Collar      
April 2014 - December 2014   1,000 bbl/d 106.00 - 110.73 US $
October 2014 - December 2014   800 bbl/d 95.00 - 121.60 US $
Dated Brent - Swap      
January 2014 - December 2014   500 bbl/d 108.28 US $
July 2014 - December 2014   1,000 bbl/d 109.64 US $
July 2014 - December 2014 5 500 bbl/d 109.40 US $
September 2014 - December 2014 5 500 bbl/d 108.08 US $
October 2014 - December 2014 4 700 bbl/d 104.48 US $
January 2015 6 250 bbl/d 107.45 US $
February 2015 7 250 bbl/d 109.00 US $
March 2015 8 250 bbl/d 110.40 US $
MSW - Fixed Price Differential (Physical)      
April 2014 - December 2014   1,030 bbl/d WTI less 8.20 US $
July 2014 - December 2014   2,052 bbl/d WTI less 8.68 US $
November 2014 - March 2015   1,042 bbl/d WTI less 6.85 US $
January 2015 - March 2015   1,573 bbl/d WTI less 7.43 US $
LSB - Fixed Price Differential (Physical)      
October 2014 - December 2014   513 bbl/d WTI less 9.00 US $
October 2014 - March 2015   830 bbl/d WTI less 10.00 US $
January 2015 - March 2015   524 bbl/d WTI less 8.60 US $
       
(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 December 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 January 31, 2015 at the contracted volume and price.
(4)  Prior to the expiration of this swap, the counterparty has the option to extend the swap to March 31, 2015 at the contracted volume and price.
(5)  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.
(6)  On March 31, 2015, the counterparty has the option to extend the swap for the period of April to June 2015 for 500 boe/d at the contracted price.
(7)  On June 30, 2015, the counterparty has the option to extend the swap for the period of July to September 2015 for 500 boe/d at the contracted price.
(8)  On September 30, 2015, the counterparty has the option to extend the swap for the period of October to December 2015 for 500 boe/d at the contracted price.

  Note Volume Strike Price(s)
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 - Collar      
October 2014 - December 2014   1,800 GJ/d 6.11 - 7.08 EUR €
TTF - Swap      
October 2014 - December 2014   3,600 GJ/d 6.71 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      
October 2014 - December 2014   1,500,000 USD $/month 1.075 - 1.145 CAD $
October 2014 - December 2014 1 7,500,000 USD $/month 1.092 - 1.114 CAD $
       
(1)  Vermilion has upside participation on this hedge up to the limit price of 1.176 CAD; above which, settlement will occur at the conditional call level of 1.114 CAD.

Supplemental Table 3: Capital Expenditures

  Three Months Ended     Nine Months Ended
By classification Sep 30, Jun 30, Sep 30,     Sep 30, Sep 30,
($M) 2014 2014 2013     2014 2013
Drilling and development 180,479 117,975 135,110     467,294 389,635
Dispositions -   -   -       -   (8,627)
Exploration and evaluation 9,554 17,098 551     54,187 13,240
Capital expenditures 190,033 135,073 135,661     521,481 394,248
Property acquisition 40,847 -   7,586     219,074 7,586
Corporate acquisition -   381,139 -       381,139 -  
Acquisitions 40,847 381,139 7,586     600,213 7,586
               
  Three Months Ended     Nine Months Ended
By category Sep 30, Jun 30, Sep 30,     Sep 30, Sep 30,
($M) 2014 2014 2013     2014 2013
Land 2,346 950 (4,450)     8,049 986
Seismic 6,135 1,869 5,284     11,436 14,666
Drilling and completion 93,386 42,083 63,590     242,005 210,010
Production equipment and facilities 68,964 60,547 47,665     198,266 138,426
Recompletions 10,853 13,459 15,650     28,538 24,291
Other 8,349 16,165 7,922     33,187 14,496
Dispositions -   -   -       -   (8,627)
Capital expenditures 190,033 135,073 135,661     521,481 394,248
Acquisitions 40,847 381,139 7,586     600,213 7,586
Total capital expenditures and acquisitions 230,880 516,212 143,247     1,121,694 401,834
               
  Three Months Ended     Nine Months Ended
By country Sep 30, Jun 30, Sep 30,     Sep 30, Sep 30,
($M) 2014 2014 2013     2014 2013
Canada 125,276 418,294 69,856     663,277 171,538
France 35,082 37,614 23,664     110,663 68,479
Netherlands 10,087 21,513 8,316     51,718 12,845
Germany 1,358 630 -       175,055 -  
Ireland 30,050 27,221 35,028     73,507 76,426
Australia 15,985 10,991 5,880     32,667 69,511
Corporate 13,042 (51) 503     14,807 3,035
Total capital expenditures and acquisitions 230,880 516,212 143,247     1,121,694 401,834

Supplemental Table 4: Production

    Q3/14 Q2/14 Q1/14 Q4/13 Q3/13 Q2/13 Q1/13 Q4/12 Q3/12 Q2/12 Q1/12 Q4/11
Canada                        
  Crude oil (bbls/d) 11,469 12,676 9,437 8,719 7,969 8,885 7,966 7,983 7,322 7,757 7,574 6,591
  NGLs (bbls/d) 2,291 2,796 2,071 1,699 1,897 1,725 1,335 1,106 1,204 1,321 1,302 1,246
  Natural gas (mmcf/d) 57.07 57.59 49.53 41.43 43.40 43.69 41.04 31.41 35.54 41.32 41.83 43.96
  Total (boe/d) 23,272 25,070 19,763 17,322 17,099 17,892 16,140 14,323 14,449 15,965 15,848 15,163
  % of consolidated 47% 49% 42% 43% 41% 42% 41% 40% 40% 40% 40% 41%
France                        
  Crude oil (bbls/d) 11,111 11,025 10,771 11,131 11,625 10,390 10,330 9,843 9,767 9,931 10,270 7,819
  Natural gas (mmcf/d) -   -   -   -   5.23 4.19 4.21 3.91 3.39 3.57 3.48 0.94
  Total (boe/d) 11,111 11,025 10,771 11,131 12,496 11,088 11,032 10,495 10,333 10,526 10,850 7,976
  % of consolidated 22% 21% 23% 27% 30% 26% 29% 29% 28% 27% 28% 22%
Netherlands                        
  NGLs (bbls/d) 63 96 69 62 48 50 96 70 41 84 72 66
  Natural gas (mmcf/d) 38.07 40.35 43.15 37.53 28.78 38.52 36.91 33.03 34.59 33.74 35.08 34.58
  Total (boe/d) 6,407 6,822 7,260 6,318 4,845 6,470 6,248 5,574 5,806 5,707 5,919 5,829
  % of consolidated 13% 13% 16% 15% 12% 15% 16% 15% 16% 15% 15% 16%
Germany                        
  Natural gas (mmcf/d) 15.38 16.13 10.64 -   -   -   -   -   -   -   -   -  
  Total (boe/d) 2,563 2,689 1,773 -   -   -   -   -   -   -   -   -  
  % of consolidated 5% 5% 4% -   -   -   -   -   -   -   -   -  
Australia                        
  Crude oil (bbls/d) 6,567 6,483 7,110 6,189 7,070 7,363 5,287 5,873 5,958 6,970 6,648 7,686
  % of consolidated 13% 12% 15% 15% 17% 17% 14% 16% 16% 18% 17% 21%
Consolidated                        
  Crude oil & NGLs (bbls/d) 31,501 33,076 29,458 27,800 28,609 28,413 25,014 24,875 24,292 26,063 25,866 23,408
  % of consolidated 63% 63% 63% 68% 69% 66% 65% 69% 66% 67% 66% 64%
  Natural gas (mmcf/d) 110.52 114.08 103.32 78.96 77.41 86.40 82.16 68.34 73.52 78.63 80.39 79.48
  % of consolidated 37% 37% 37% 32% 31% 34% 35% 31% 34% 33% 34% 36%
  Total (boe/d) 49,920 52,089 46,677 40,960 41,510 42,813 38,707 36,265 36,546 39,168 39,265 36,654
                           
    YTD 2014 2013 2012 2011 2010 2009            
Canada                        
  Crude oil (bbls/d) 11,202 8,387 7,659 4,701 2,778 2,137            
  NGLs (bbls/d) 2,387 1,666 1,232 1,297 1,427 1,518            
  Natural gas (mmcf/d) 54.76 42.39 37.50 43.38 43.91 47.85            
  Total (boe/d) 22,714 17,117 15,142 13,227 11,524 11,629            
  % of consolidated 45% 41% 40% 38% 36% 37%            
France                        
  Crude oil (bbls/d) 10,970 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) 10,970 11,440 10,550 8,269 8,501 8,421            
  % of consolidated 22% 28% 28% 23% 26% 27%            
Netherlands                        
  NGLs (bbls/d) 76 64 67 58 35 23            
  Natural gas (mmcf/d) 40.50 35.42 34.11 32.88 28.31 21.06            
  Total (boe/d) 6,827 5,967 5,751 5,538 4,753 3,533            
  % of consolidated 14% 15% 15% 16% 15% 11%            
Germany                        
  Natural gas (mmcf/d) 14.07 -   -   -   -   -              
  Total (boe/d) 2,345 -   -   -   -   -              
  % of consolidated 5% -   -   -   -   -              
Australia                        
  Crude oil (bbls/d) 6,718 6,481 6,360 8,168 7,354 7,812            
  % of consolidated 14% 16% 17% 23% 23% 25%            
Consolidated                        
  Crude oil & NGLs (bbls/d) 31,353 27,471 25,270 22,334 19,941 19,735            
  % of consolidated 63% 67% 67% 63% 62% 63%            
  Natural gas (mmcf/d) 109.33 81.21 75.20 77.21 73.14 69.96            
  % of consolidated 37% 33% 33% 37% 38% 37%            
  Total (boe/d) 49,574 41,005 37,803 35,202 32,132 31,395            

Supplemental Table 5: Segmented Financial Results

   
  Three Months Ended September 30, 2014
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Drilling and development 88,116   34,883   10,087   1,358   30,050   15,985   -     180,479
Exploration and evaluation 9,277   199   -     -     -     -     78   9,554
Oil and gas sales to external customers 138,853   106,576   26,960   8,591   -     63,708   -     344,688
Royalties (19,034)   (6,978)   (942)   (2,046)   -     -     -     (29,000)
Revenue from external customers 119,819   99,598   26,018   6,545   -     63,708   -     315,688
Transportation expense (4,048)   (4,741)   -     (675)   (1,515)   -     -     (10,979)
Operating expense (19,074)   (15,215)   (5,409)   (2,227)   -     (14,302)   -     (56,227)
General and administration (4,523)   (6,411)   (204)   (1,090)   (334)   (1,378)   (2,322)   (16,262)
PRRT -     -     -     -     -     (13,834)   -     (13,834)
Corporate income taxes -     (10,744)   (1,189)   (146)   -     (5,148)   (227)   (17,454)
Interest expense -     -     -     -     -     -     (12,918)   (12,918)
Realized gain on derivative instruments -     -     -     -     -     -     8,837   8,837
Realized foreign exchange gain -     -     -     -     -     -     812   812
Realized other income -     -     -     -     -     -     235   235
Fund flows from operations 92,174   62,487   19,216   2,407   (1,849)   29,046   (5,583)   197,898
                               
                               
  Nine Months Ended September 30, 2014
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Total assets 1,857,012   894,060   237,070   164,025   809,296   269,959   206,305   4,437,727
Drilling and development 215,860   99,564   43,512   2,184   73,507   32,667   -     467,294
Exploration and evaluation 33,440   11,099   8,206   -     -     -     1,442   54,187
Oil and gas sales to external customers 425,294   348,753   98,395   28,603   -     212,510   -     1,113,555
Royalties (49,937)   (22,125)   (3,843)   (6,132)   -     -     -     (82,037)
Revenue from external customers 375,357   326,628   94,552   22,471   -     212,510   -     1,031,518
Transportation expense (11,170)   (14,879)   -     (2,149)   (4,674)   -     -     (32,872)
Operating expense (56,863)   (48,185)   (17,841)   (5,824)   -     (43,713)   -     (172,426)
General and administration (13,951)   (17,164)   (1,128)   (2,488)   (868)   (4,245)   (8,647)   (48,491)
PRRT -     -     -     -     -     (46,772)   -     (46,772)
Corporate income taxes -     (60,769)   (6,278)   (1,189)   -     (19,678)   (778)   (88,692)
Interest expense -     -     -     -     -     -     (36,712)   (36,712)
Realized gain on derivative instruments -     -     -     -     -     -     13,896   13,896
Realized foreign exchange loss -     -     -     -     -     -     (642)   (642)
Realized other income -     -     -     -     -     -     530   530
Fund flows from operations 293,373   185,631   69,305   10,821   (5,542)   98,102   (32,353)   619,337

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 nine months ended September 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     Nine Months Ended
    Sep 30, Jun 30, Sep 30,     Sep 30, Sep 30,
($M) 2014 2014 2013     2014 2013
Cash flows from operating activities 235,010 149,592 158,236     562,840 528,022
Changes in non-cash operating working capital (41,789) 64,103 4,671     46,788 (30,652)
Asset retirement obligations settled 4,677 2,381 2,738     9,709 6,496
Fund flows from operations 197,898 216,076 165,645     619,337 503,866
Expenses related to Corrib 1,849 1,823 876     5,542 4,767
Fund flows from operations (excluding Corrib) 199,747 217,899 166,521     624,879 508,633

    Three Months Ended     Nine Months Ended
    Sep 30, Jun 30, Sep 30,     Sep 30, Sep 30,
($M) 2014 2014 2013     2014 2013
Dividends declared 68,896 68,710 61,003     203,613 181,391
Issuance of shares pursuant to the dividend reinvestment plan (20,416) (19,149) (19,354)     (58,450) (53,516)
Net dividends 48,480 49,561 41,649     145,163 127,875
Drilling and development 180,479 117,975 135,110     467,294 389,635
Dispositions -   -   -       -   (8,627)
Exploration and evaluation 9,554 17,098 551     54,187 13,240
Asset retirement obligations settled 4,677 2,381 2,738     9,709 6,496
Payout 243,190 187,015 180,048     676,353 528,619
Corrib drilling and development (30,050) (27,221) (35,028)     (73,507) (76,426)
Payout (excluding Corrib) 213,140 159,794 145,020     602,846 452,193

  As At
  Sep 30, Jun 30, Sep 30,
('000s of shares) 2014 2014 2013
Shares outstanding 106,921 106,620 101,787
Potential shares issuable pursuant to the VIP 2,828 2,751 2,408
Diluted shares outstanding 109,749 109,371 104,195
       

CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

    September 30, December 31,
  Note   2014   2013
ASSETS          
Current          
Cash and cash equivalents     142,520   389,559
Accounts receivable     199,574   167,618
Crude oil inventory     19,781   17,143
Derivative instruments     9,341   2,285
Prepaid expenses     15,169   11,178
      386,385   587,783
           
Deferred taxes     148,124   184,832
Exploration and evaluation assets 5   380,266   136,259
Capital assets 4   3,522,952   2,799,845
      4,437,727   3,708,719
           
LIABILITIES          
Current          
Accounts payable and accrued liabilities     323,747   267,832
Dividends payable 8   22,988   20,425
Derivative instruments     1,704   3,572
Income taxes payable     82,736   55,615
      431,175   347,444
           
Long-term debt 7   1,198,648   990,024
Asset retirement obligations 6   397,920   326,162
Deferred taxes     409,516   328,714
      2,437,259   1,992,344
           
SHAREHOLDERS' EQUITY          
Shareholders' capital 8   1,937,750   1,618,443
Contributed surplus     74,063   75,427
Accumulated other comprehensive income     13,740   47,142
Deficit     (25,085)   (24,637)
      2,000,468   1,716,375
      4,437,727   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   Nine Months Ended
    Sep 30,   Sep 30,   Sep 30,   Sep 30,
Note 2014   2013   2014   2013
REVENUE                  
Petroleum and natural gas sales     344,688   327,185   1,113,555   948,727
Royalties     (29,000)   (18,730)   (82,037)   (50,320)
Petroleum and natural gas revenue     315,688   308,455   1,031,518   898,407
                   
EXPENSES                  
Operating     56,227   46,246   172,426   146,903
Transportation     10,979   6,549   32,872   19,843
Equity based compensation 9   14,720   12,779   49,409   39,639
(Gain) loss on derivative instruments     (16,637)   8,464   (24,110)   1,943
Interest expense     12,918   10,109   36,712   28,134
General and administration     16,262   12,033   48,491   35,956
Foreign exchange loss (gain)     11,055   (3,005)   14,255   (29,166)
Other expense     362   55   217   259
Accretion 6   6,064   6,214   17,726   18,038
Depletion and depreciation 4, 5   104,159   78,826   308,513   238,692
      216,109   178,270   656,511   500,241
EARNINGS BEFORE INCOME TAXES     99,579   130,185   375,007   398,166
                   
INCOME TAXES                  
Deferred     14,388   287   28,859   13,914
Current     31,288   62,102   135,464   158,121
      45,676   62,389   164,323   172,035
                   
NET EARNINGS     53,903   67,796   210,684   226,131
                   
OTHER COMPREHENSIVE (LOSS) INCOME                  
Currency translation adjustments     (36,143)   14,621   (33,402)   32,244
COMPREHENSIVE INCOME     17,760   82,417   177,282   258,375
                   
NET EARNINGS PER SHARE                  
Basic         0.50   0.67   2.01   2.25
Diluted     0.50   0.66   1.98   2.22
                   
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)                  
Basic     106,768   101,613   104,891   100,634
Diluted     108,290   102,763   106,582   102,083

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

      Three Months Ended   Nine Months Ended
      Sep 30,   Sep 30,   Sep 30,   Sep 30,
  Note   2014   2013   2014   2013
OPERATING                  
Net earnings     53,903   67,796   210,684   226,131
Adjustments:                  
      Accretion 6   6,064   6,214   17,726   18,038
      Depletion and depreciation 4, 5   104,159   78,826   308,513   238,692
      Unrealized (gain) loss on derivative instruments     (7,800)   3,699   (10,214)   (3,839)
      Equity based compensation 9   14,720   12,779   49,409   39,639
      Unrealized foreign exchange loss (gain)     11,867   (4,232)   13,613   (29,738)
      Unrealized other expense     597   276   747   1,029
      Deferred taxes     14,388   287   28,859   13,914
Asset retirement obligations settled 6   (4,677)   (2,738)   (9,709)   (6,496)
Changes in non-cash operating working capital     41,789   (4,671)   (46,788)   30,652
Cash flows from operating activities     235,010   158,236   562,840   528,022
                   
INVESTING                  
Drilling and development 4   (180,479)   (135,110)   (467,294)   (389,635)
Exploration and evaluation 5   (9,554)   (551)   (54,187)   (13,240)
Property acquisitions 3, 4, 5   (40,847)   (7,586)   (219,074)   (7,586)
Dispositions 4   -   -   -   8,627
Corporate acquisitions, net of cash acquired 3   -   -   (176,179)   -
Changes in non-cash investing working capital     24,539   44,876   40,002   7,473
Cash flows used in investing activities     (206,341)   (98,371)   (876,732)   (394,361)
                   
FINANCING                  
(Decrease) increase in long-term debt     (1,600)   -   204,127   139,429
Cash dividends     (48,415)   (41,576)   (142,600)   (126,354)
Cash flows (used in) from financing activities     (50,015)   (41,576)   61,527   13,075
Foreign exchange (loss) gain on cash held in foreign currencies     (1,631)   2,248   5,326   7,274
                   
Net change in cash and cash equivalents     (22,977)   20,537   (247,039)   154,010
Cash and cash equivalents, beginning of period     165,497   235,598   389,559   102,125
Cash and cash equivalents, end of period     142,520   256,135   142,520   256,135
                   
Supplementary information for operating activities - cash payments                  
   Interest paid     15,132   13,544   40,947   34,053
   Income taxes paid     28,617   50,203   106,177   101,507

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     -   -   -   226,131   226,131
Currency translation adjustments     -   -   32,244   -   32,244
Equity based compensation expense 9   -   39,010   -   -   39,010
Dividends declared 8   -   -   -   (181,391)   (181,391)
Shares issued pursuant to the dividend reinvestment plan 8   53,516   -   -   -   53,516
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 September 30, 2013     1,599,668   54,221   (165)   (64,939)   1,588,785
                       
            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     -   -   -   210,684   210,684
Currency translation adjustments     -   -   (33,402)   -   (33,402)
Equity based compensation expense 9   -   48,688   -   -   48,688
Dividends declared 8   -   -   -   (203,613)   (203,613)
Shares issued pursuant to the dividend reinvestment plan 8   58,450   -   -   -   58,450
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 September 30, 2014     1,937,750   74,063   13,740   (25,085)   2,000,468

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 NINE MONTHS ENDED SEPTEMBER 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 November 6, 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 pronouncements are currently being evaluated.

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

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

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 $22.5 million and net earnings $2.2 million for the nine months ended September 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 nine months ended September 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.

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

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

($M) Consideration
Cash paid to shareholders of Elkhorn Resources Inc.   180,353
Shares issued pursuant to corporate acquisition   204,960
Total consideration   385,313
     
($M) Allocation of Consideration
Petroleum and natural gas assets   390,523
Exploration and evaluation   138,264
Asset retirement obligations assumed   (5,974)
Deferred tax liabilities   (89,437)
Long-term debt assumed   (47,526)
Cash acquired   4,174
Acquired non-cash working capital deficiency   (4,711)
Net assets acquired (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 $34.7 million and operating income of $27.9 million for the nine months ended September 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 nine months ended September 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)
Impairment recovery   47,400   -   47,400
Effect of movements in foreign exchange rates   136,626   426   137,052
Balance at December 31, 2013   2,784,634   15,211   2,799,845
Additions   462,136   5,158   467,294
Property acquisitions   163,600   -   163,600
Corporate acquisitions   390,523   -   390,523
Changes in estimate for asset retirement obligations   63,400   -   63,400
Depletion and depreciation   (303,634)   (2,672)   (306,306)
Effect of movements in foreign exchange rates   (55,281)   (123)   (55,404)
Balance at September 30, 2014   3,505,378   17,574   3,522,952

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   54,187
Changes in estimate for asset retirement obligations   97
Property acquisitions   57,508
Corporate acquisitions   138,264
Depreciation   (4,076)
Effect of movements in foreign exchange rates   (1,973)
Balance at September 30, 2014   380,266

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     19,919
Obligations settled     (9,709)
Accretion     17,726
Changes in discount rates     51,582
Effect of movements in foreign exchange rates     (7,760)
Balance at September 30, 2014     397,920

7. LONG-TERM DEBT

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

  As At
($M) Sept 30, 2014 Dec 31, 2013
Revolving credit facility   974,857   766,898
Senior unsecured notes   223,791   223,126
Long-term debt   1,198,648   990,024

Revolving Credit Facility

At September 30, 2014, Vermilion had in place a bank revolving credit facility totalling $1.5 billion, of which approximately $974.9 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 nine months ended September 30, 2014, the interest rate on the revolving credit facility was approximately 3.2%.

The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $10.3 million as at September 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 September 30, 2014, Vermilion was in compliance with all 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.

Prior to February 10, 2015, Vermilion may redeem all or part of the senior unsecured notes at 103.25% of their principal amount plus any accrued and unpaid interest.  Subsequent to February 10, 2015, Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest.  The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

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   902   58,450
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 September 30, 2014   106,921   1,937,750

Dividends declared to shareholders for the nine months ended September 30, 2014 were $203.6  million (2013 - $181.4 million).

Subsequent to the end of the period and prior to the condensed consolidated interim financial statements being authorized for issue on November 6, 2014, Vermilion declared dividends totalling $23.0 million or $0.215 per share.

9. EQUITY BASED COMPENSATION

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

Number of Awards ('000s) 2014   2013
Opening balance 1,665   1,690
Granted 616   832
Vested (512)   (749)
Modified (21)   -
Forfeited (53)   (108)
Closing balance 1,695   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 September 30, 2014
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Drilling and development 88,116   34,883   10,087   1,358   30,050   15,985   -     180,479
Exploration and evaluation 9,277   199   -     -     -     -     78   9,554
Oil and gas sales to external customers 138,853   106,576   26,960   8,591   -     63,708   -     344,688
Royalties (19,034)   (6,978)   (942)   (2,046)   -     -     -     (29,000)
Revenue from external customers 119,819   99,598   26,018   6,545   -     63,708   -     315,688
Transportation expense (4,048)   (4,741)   -     (675)   (1,515)   -     -     (10,979)
Operating expense (19,074)   (15,215)   (5,409)   (2,227)   -     (14,302)   -     (56,227)
General and administration (4,523)   (6,411)   (204)   (1,090)   (334)   (1,378)   (2,322)   (16,262)
PRRT -     -     -     -     -     (13,834)   -     (13,834)
Corporate income taxes -     (10,744)   (1,189)   (146)   -     (5,148)   (227)   (17,454)
Interest expense -     -     -     -     -     -     (12,918)   (12,918)
Realized gain on derivative instruments -     -     -     -     -     -     8,837   8,837
Realized foreign exchange gain -     -     -     -     -     -     812   812
Realized other income -     -     -     -     -     -     235   235
Fund flows from operations 92,174   62,487   19,216   2,407   (1,849)   29,046   (5,583)   197,898
                               
                               
  Three Months Ended September 30, 2013
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Drilling and development 61,719   23,664   8,316   -     35,028   5,880   503   135,110
Exploration and evaluation 551   -     -     -     -     -     -     551
Oil and gas sales to external customers 100,000   120,574   27,382   -     -     79,229   -     327,185
Royalties (11,156)   (7,574)   -     -     -     -     -     (18,730)
Revenue from external customers 88,844   113,000   27,382   -     -     79,229   -     308,455
Transportation expense (3,272)   (2,713)   -     -     (564)   -     -     (6,549)
Operating expense (12,770)   (14,599)   (5,209)   -     -     (13,668)   -     (46,246)
General and administration (3,484)   (4,964)   (333)   -     (312)   (1,414)   (1,526)   (12,033)
PRRT -     -     -     -     -     (15,649)   -     (15,649)
Corporate income taxes -     (31,717)   (6,810)   -     -     (7,666)   (260)   (46,453)
Interest expense -     -     -     -     -     -     (10,109)   (10,109)
Realized loss on derivative instruments -     -     -     -     -     -     (4,765)   (4,765)
Realized foreign exchange loss -     -     -     -     -     -     (1,227)   (1,227)
Realized other income -     -     -     -     -     -     221   221
Fund flows from operations 69,318   59,007   15,030   -     (876)   40,832   (17,666)   165,645
                               
                               
  Nine Months Ended September 30, 2014
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Total assets 1,857,012   894,060   237,070   164,025   809,296   269,959   206,305   4,437,727
Drilling and development 215,860   99,564   43,512   2,184   73,507   32,667   -     467,294
Exploration and evaluation 33,440   11,099   8,206   -     -     -     1,442   54,187
Oil and gas sales to external customers 425,294   348,753   98,395   28,603   -     212,510   -     1,113,555
Royalties (49,937)   (22,125)   (3,843)   (6,132)   -     -     -     (82,037)
Revenue from external customers 375,357   326,628   94,552   22,471   -     212,510   -     1,031,518
Transportation expense (11,170)   (14,879)   -     (2,149)   (4,674)   -     -     (32,872)
Operating expense (56,863)   (48,185)   (17,841)   (5,824)   -     (43,713)   -     (172,426)
General and administration (13,951)   (17,164)   (1,128)   (2,488)   (868)   (4,245)   (8,647)   (48,491)
PRRT -     -     -     -     -     (46,772)   -     (46,772)
Corporate income taxes -     (60,769)   (6,278)   (1,189)   -     (19,678)   (778)   (88,692)
Interest expense -     -     -     -     -     -     (36,712)   (36,712)
Realized gain on derivative instruments -     -     -     -     -     -     13,896   13,896
Realized foreign exchange loss -     -     -     -     -     -     (642)   (642)
Realized other income -     -     -     -     -     -     530   530
Fund flows from operations 293,373   185,631   69,305   10,821   (5,542)   98,102   (32,353)   619,337
                               
                               
  Nine Months Ended September 30, 2013
($M) Canada   France   Netherlands   Germany   Ireland   Australia   Corporate   Total
Total assets 1,141,499   930,568   144,813   -     697,120   301,350   209,075   3,424,425
Drilling and development 158,519   68,479   14,472   -     76,426   69,511   2,228   389,635
Exploration and evaluation 12,433   -     -     -     -     -     807   13,240
Oil and gas sales to external customers 284,638   342,558   100,119   -     -     221,412   -     948,727
Royalties (29,852)   (20,468)   -     -     -     -     -     (50,320)
Revenue from external customers 254,786   322,090   100,119   -     -     221,412   -     898,407
Transportation expense (8,152)   (7,883)   -     -     (3,808)   -     -     (19,843)
Operating expense (42,586)   (51,473)   (14,438)   -     -     (38,406)   -     (146,903)
General and administration (10,501)   (14,577)   (1,171)   -     (959)   (4,310)   (4,438)   (35,956)
PRRT -     -     -     -     -     (39,392)   -     (39,392)
Corporate income taxes -     (66,500)   (25,865)   -     -     (25,525)   (839)   (118,729)
Interest expense -     -     -     -     -     -     (28,134)   (28,134)
Realized loss on derivative instruments -     -     -     -     -     -     (5,782)   (5,782)
Realized foreign exchange loss -     -     -     -     -     -     (572)   (572)
Realized other income -     -     -     -     -     -     770   770
Fund flows from operations 193,547   181,657   58,645   -     (4,767)   113,779   (38,995)   503,866

Reconciliation of fund flows from operations to net earnings

  Three Months Ended   Nine Months Ended
  Sep 30, Sep 30,   Sep 30, Sep 30,
($M) 2014 2013   2014 2013
Fund flows from operations 197,898 165,645   619,337 503,866
Equity based compensation   (14,720) (12,779)   (49,409) (39,639)
Unrealized gain (loss) on derivative instruments 7,800 (3,699)   10,214 3,839
Unrealized foreign exchange (loss) gain (11,867) 4,232   (13,613) 29,738
Unrealized other expense (597) (276)   (747) (1,029)
Accretion (6,064) (6,214)   (17,726) (18,038)
Depletion and depreciation (104,159) (78,826)   (308,513) (238,692)
Deferred taxes (14,388) (287)   (28,859) (13,914)
Net earnings 53,903 67,796   210,684 226,131

11. CAPITAL DISCLOSURES

  Three Months Ended   Nine Months Ended
($M except as indicated) September 30,
2014
September 30,
2013
  September 30,
2014
September 30,
2013
Long-term debt 1,198,648 781,074   1,198,648 781,074
Current liabilities 431,175 389,757   431,175 389,757
Current assets (386,385) (470,545)   (386,385) (470,545)
Net debt [1] 1,243,438 700,286   1,243,438 700,286
           
Cash flows from operating activities 235,010 158,236   562,840 528,022
Changes in non-cash operating working capital (41,789) 4,671   46,788 (30,652)
Asset retirement obligations settled 4,677 2,738   9,709 6,496
Fund flows from operations 197,898 165,645   619,337 503,866
Annualized fund flows from operations [2] 791,592 662,580   825,783 671,821
           
Ratio of net debt to annualized fund flows from operations ([1] ÷ [2]) 1.6 1.1   1.5 1.0

Long-term debt as at September 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 does not include a full year of fund flows from the acquisitions in Germany and Saskatchewan, the ratio of net debt to annualized fund flows increased to 1.5.

12. FINANCIAL INSTRUMENTS

Classification of Financial Instruments

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

              As at Sep 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)     142,520   142,520     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     199,574   199,574     167,618   167,618     Not applicable
Derivative assets Derivative instruments HFT (Gain) loss on derivative instruments     9,341   9,341     2,285   2,285     Level 2
Derivative liabilities Derivative instruments HFT (Gain) loss on derivative instruments     (1,704)   (1,704)     (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)     (346,735)   (346,735)     (288,257)   (288,257)     Not applicable
                                   
    Dividends payable                              
Long-term debt Long-term debt OTH Interest expense     (1,198,648)   (1,199,295)     (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 nine months ended September 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 September 30, 2014
Currency risk - Euro to Canadian Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates (4,565)
     
  Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates 4,565
     
Currency risk - US $ to Canadian Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates (4,029)
     
  Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates 4,029
     
Commodity price risk Increase in relevant oil reference price within option pricing models used to determine (5,015)
  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 4,686
  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 (6,519)
     
  Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods 6,519

SOURCE Vermilion Energy Inc.

Vermilion Energy Inc.
3500, 520 3rd Avenue SW
Calgary, Alberta T2P 0R3
Phone: 1-403-269-4884
Fax: 1-403-476-8100
Investor Relations
Whistleblower
Community Investment
Emergency Contacts