Vermilion Energy Inc. Announces Strong Production and Reserves Growth in 2013

CALGARY, March 3, 2014 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and audited financial results for the fourth quarter and year ended December 31, 2013.

HIGHLIGHTS

  • We achieved record average annual production of 41,005 boe/d during 2013, an increase of 8% as compared to 37,803 boe/d in 2012.  Approximately 75% of our year-over-year production growth was achieved organically through continued development of our Cardium and Mannville resource plays in Canada, and successful conventional drilling programs in France and Australia. The remaining 25% of production growth came from our December 2012 acquisition in France and our October 2013 acquisition in the Netherlands.

  • Strong operational and drilling execution underpinned our ability to deliver organic growth in production and reserves in each of our producing business units in 2013.  Reliable operational performance in all regions enabled us to increase production guidance three times during the year and to achieve production levels at the top end of our final guidance range.

  • We grew both proved ("1P") and proved plus probable ("2P") reserves by more than 20% in 2013, our highest level of reserves growth in more than 10 years.  Our independent GLJ 2013 Reserves Evaluation(1) assessed an increase of 23% in total 1P reserves to 129.0(1) mmboe, while total 2P reserves increased 20% to 198.6(1) mmboe.

  • After-tax net present value discounted at 10% ("NPV10") of 2P reserves increased 29% to $3.9 billion in the GLJ 2013 Reserves Evaluation from $3.0 billion in GLJ 2012 Reserves Evaluation(2).

  • Our independent GLJ 2013 Resource Assessment(3) indicates low, best, and high estimates for contingent resources of 74.4(3) mmboe, 233.5(3) mmboe, and 351.7(3) mmboe, a decrease of 11% and an increase of 45% and 52%, respectively, compared to our GLJ 2012 Resource Assessment(4).  Prospective resources were assessed at low, best and high estimates of 59.4(3) mmboe, 498.7(3) mmboe, and 818.8(3) mmboe, an increase of 518%, 100%, and 51%, respectively versus our GLJ 2012 Resource Assessment.  Importantly, the GLJ 2013 Resource Assessment reflects a significant increase in the assessment of best estimate contingent and prospective resources across our Canadian and European business units.

  • GLJ 2013 Resource Assessment estimated after-tax NPV10 of low, best and high estimate contingent resources of $0.4 billion, $1.3 billion, and $2.6 billion, respectively.  GLJ 2013 Resource Assessment estimated after-tax NPV10 of low, best and high estimate prospective resources of $0.2 billion, $1.8 billion, and $5.3 billion, respectively.

  • We generated record fund flows from operations(5) in 2013 of $667.5 million ($6.61/basic share), an increase of 20% as compared to $557.7 million ($5.69/basic share) in 2012.  The increase was primarily attributable to higher production volumes in all regions.  Fund flows from operations in 2013 also benefitted from higher price realizations for our North American oil and gas production as well as our European gas.

  • In 2013, improved pricing in Canada for both oil and gas production resulted in higher company-total realized prices as compared to 2012.  WTI pricing improved 4% year-over-year to US$97.97/bbl, while Edmonton Sweet Index pricing, against which the majority of our Canadian-based crude production is priced, increased nearly 5% to US$90.40/bbl in 2013.  Average AECO index pricing, against which our Canadian natural gas production is priced, increased by 33% in 2013 to $3.01/GJ compared to $2.26/GJ in 2012.

  • We remain advantaged by our international exposure to Brent-based crude oil and European natural gas pricing.  Our Brent-based crude production represents 43% of total oil-equivalent production (67% of total crude oil production) and continues to attract a consolidated premium to the quoted Dated Brent reference price.  This premium provides further support to our comparative price advantage over North American producers as Dated Brent continued to trade at an average premium in 2013 of US$10.69/bbl and US$18.26/bbl versus WTI and the Edmonton Sweet Index pricing, respectively.  Our European gas production also continues to attract strong relative pricing.  During 2013, our Netherlands gas production received an average of $10.29/GJ, an increase of over 8% relative to 2012, and a premium of $7.28/GJ compared to Canadian-based AECO gas pricing.

  • In October 2013, we completed our acquisition from Northern Petroleum PLC, of interests in nine concessions in the Netherlands.  The acquisition added approximately 100 boe/d of annualized production in 2013 and is expected to add average production of approximately 400 boe/d in 2014.  The acquisition added 2.4(1) mmboe of 2P reserves and 298,500 net acres of land, of which 98% is currently undeveloped.  This accretive acquisition brings operating synergies with our legacy assets, helps consolidate our position in the northeast Netherlands, and opens up new development opportunities in the central region of the Netherlands.

  • In November 2013, we announced an agreement to acquire a 25% contractual participation interest in a four partner consortium in Germany from GDF Suez S.A.  The acquisition enables us to participate in the exploration, development, production and transportation of natural gas from the assets, which include four gas producing fields across 11 production licenses.  The acquisition closed in February 2014.  We are guiding to a contribution of approximately 2,300 boe/d of production from our new German assets in 2014.  In addition to the production licenses, a surrounding exploration license was also acquired pursuant to the acquisition.  The exploration and production licenses comprise 204,000 gross acres, of which 85% is in the exploration license.

  • In Ireland, Corrib tunneling operations are more than 70% completed with approximately 1.4 kilometres of tunneling remaining.  Based on the current deterministic schedule for remaining construction and commissioning activities, we anticipate first gas from Corrib in approximately mid-2015.  Successful 2013 subsea well operations conducted on one of the production wells facilitated an increase to our peak production estimate at Corrib from 54 mmcf/d (9,000 boe/d) to approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.

  • Subsequent to the end of 2013, we were conditionally awarded the Battonya South concession in Hungary, subject to successful execution of a definitive agreement acceptable to both Vermilion and the Hungarian Ministry of National Development. The concession consists of 116,000 gross acres located in the southern part of Hungary.  The term of the concession is for 20 years, subject to continuation of development in a manner acceptable to both parties.

  • In early 2014, we informed the Moroccan government of our intention to relinquish our rights to the Haouz block in central Morocco.  Based on our analysis of seismic data, we concluded that due to the structural complexity of the block, we would be unable to pursue a definitive appraisal and exploration program that would fit within the constraints of our predetermined new venture capital and risk parameters.  The relinquishment terminates our activities in Morocco after cumulative spending of $0.9 million to evaluate the 2.3 million acre block.

  • In 2013, we provided our shareholders with a total return, including dividends, of 24.6%.  Over the last three, five, ten and 15 years we have provided our shareholders with a compound average total return of 14.5%, 24.0%, 18.6% and 25.5%, respectively.  Since our inception in 1994, we have provided a compound average total return to our shareholders of 35.8% per year.

  • In keeping with our objective of providing reliable and growing dividends, in November 2013 we announced a 7.5% increase to our monthly cash dividend to $0.215 per share ($2.58 per year) beginning in 2014.  This followed a previous 5.3% increase announced in November 2012.

  • Our Board of Directors has approved an amendment to our Dividend Reinvestment Plan ("DRIP") to decrease the amount of additional shares participants in the DRIP are eligible to receive to 3% of their cash dividends from the current level of 5%.  All other terms and conditions related to participation in our DRIP remain unchanged.  This amendment is expected to be effective for the April dividend payable on May 15, 2014.  The record date for the April dividend is April 30, 2014.

(1) Estimated proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 4, 2014 with an effective date of December 31, 2013 (the "2013 GLJ Reserves Evaluation")
(2) Estimated proved plus probable reserves attributable to the assets as evaluated by GLJ in a report dated February 14, 2013 with an effective date of December 31, 2012 (the "2012 GLJ Reserves Evaluation")
(3) Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2013 (the "GLJ 2013 Resource Assessment")
(4) Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2012 (the "GLJ 2012 Resource Assessment")
(5) Additional GAAP Financial Measure.  Please see the "Additional and Non-GAAP Financial Measures" section of Management's Discussion and Analysis.    
       

Reserves and resources information in this news release is a summary only and is subject to the reserves and resources information set forth in Vermilion's annual information form for the year ended December 31, 2013, a summary of which is set forth in Vermilion's news release dated March 3, 2014 entitled "Vermilion Energy Inc. Announces 2013 Year-end Summary Reserves and Resource Information", which will be filed and available on SEDAR at www.sedar.com and on the SEC's EDGAR system at www.sec.gov.

ORGANIZATIONAL UPDATE

President and Chief Operating Officer Appointment

Vermilion is pleased to announce the appointment of Anthony Marino to the position of President and Chief Operating Officer effective March 3, 2014. This appointment is in consideration of Mr. Marino's significant contributions towards Vermilion's success over the last two years since joining the organization.

Mr. Marino and the rest of the executive team will continue to report to Lorenzo Donadeo in his capacity as Chief Executive Officer. Our management team looks forward to leading the organization to achieve the objectives we have set out in our long range plan, which seeks to provide sustainable production growth and a reliable and growing dividend.

Mr. Marino is an accomplished senior executive with a proven track record of high performance during his 30-year career in the energy industry. Mr. Marino joined Vermilion in June, 2012 as Chief Operating Officer. Prior to this, Mr. Marino held the position of President and Chief Executive Officer of Baytex Energy Corporation, after initially serving as Baytex's Chief Operating Officer. Prior to joining Baytex, Mr. Marino held the role of President and Chief Executive Officer of Dominion Exploration Canada Ltd. Earlier in his career, Mr. Marino held a variety of technical and management positions with AEC Oil and Gas (USA) Inc., Santa Fe Snyder Corp. and Atlantic Richfield Company. Mr. Marino brings strong experience in production operations and the development of oil and gas resource plays to Vermilion. In addition to his operating experience, Mr. Marino also has an extensive background in business development and oil and gas marketing.

Mr. Marino has a Bachelor of Science degree with Highest Distinction in Petroleum Engineering from the University of Kansas and a Master of Business Administration degree from California State University at Bakersfield. He is a registered professional engineer and holds the Chartered Financial Analyst designation.

Conference Call and Audio Webcast Details

Vermilion will discuss these results in a conference call to be held on Monday, March 3, 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 39159856.  The replay will be available until midnight eastern time on March 10, 2014.

You may also listen to the audio webcast by clicking  http://event.on24.com/r.htm?e=742286&s=1&k=23F1F279149D62557A72E55CA7C5400A 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; 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 and information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct.  Financial outlooks are provided for the purpose of understanding Vermilion's financial strength and business objectives and the information may not be appropriate for other purposes.  Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information.  These risks and uncertainties include but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids and natural gas prices, foreign currency exchange rates and interest rates; health, safety and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.

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

All oil and natural gas reserve information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.  The actual oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.  The estimated future net revenue from the production of the disclosed oil and natural gas reserves does not represent the fair market value of these reserves.  Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.  Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation.  A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.

ABBREVIATIONS

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

MESSAGE TO SHAREHOLDERS

Dear Shareholders:

By all accounts, 2013 was a year of significant achievement for Vermilion.  We realized organic growth across all of our operating business units, attained record company-total production levels, generated record fund flows from operations, achieved record drilling results in Australia, recorded our highest level of reserves growth since converting to a distribution/dividend paying business model, provided a 24.6% total return to our shareholders, and announced a 7.5% increase to our monthly cash dividend.

Solid operational and drilling execution was the foundation for delivering strong organic growth in both production and reserves in 2013.  Reliable operational performance across all of our business units allowed us to actively manage the composition of our produced volumes, increase production guidance three times during the year, and achieve the top end of our final guidance of 41,000 boe/d.

Canada

We remained focused on the continued development of our successful Cardium light oil play. Well performance remains predictable, reflective of the high quality, consistent nature of the reservoir underlying our land position in the West Pembina region.  Since entering the play in 2009, we have brought a total of 223 (158.9 net) Cardium wells on production and grown Cardium related production volumes to more than 9,000 boe/d as at the end of 2013.  Entering 2014, we have an inventory of nearly 200 net economic one-mile equivalent wells remaining to be drilled.  In addition, we continue to review our significant inventory of more than 120 additional locations that may become economic as we expand our use of extended reach horizontal wells (greater than one mile in length) and further optimize completion technology and well design. We have also initiated a water injection pilot to test applicability of water-flooding to this reservoir as a means to increase potential recoveries. During 2014, we anticipate drilling more than 30 net Cardium wells.

In addition to the Cardium, we have also begun development of our significant inventory of Mannville condensate-rich natural gas wells in the West Pembina area.  In 2013, we drilled a total of six (3.7 net) condensate-rich gas wells.  Drilling results to-date have exceeded our initial expectations with respect to both gas production rates and associated liquids yields.  This has resulted in robust economics and anticipated rates of return in excess of 100%.  Results from our 2013 drilling activities, and those of other operators, demonstrated the strong economics and prospectivity of the Mannville, allowing GLJ, our independent reserves evaluator, to recognize significant additional reserves.  Our year-end 2013 2P reserves report includes an additional 40 (28.4 net) undeveloped  drilling locations and increased reserves of 19.8(1) mmboe attributable to our Mannville condensate-rich play, including upward technical revisions.  In 2014, we plan to drill 8 (5.7 net) Mannville wells, and we expect drilling activity to increase in future years as we continue to develop the play and expand our inventory of economic prospects.

We are also appraising our position in the Duvernay condensate-rich resource play, where we have amassed 317 net sections at the relatively low cost of approximately $76 million ($375/acre).  Our position comprises three largely contiguous blocks in the Edson, Drayton Valley and Niton areas.  To date, we have drilled three vertical stratigraphic test wells, and are currently drilling our first horizontal well.  The first horizontal test is in the down-dip part of our Edson block, where condensate yields are expected to be lower than the average in our overall land position.  We selected this location because of its proximity to one of our vertical stratigraphic test wells, allowing us to conduct micro-seismic monitoring while we frac the horizontal well after break-up.  We anticipate that the horizontal well production results and fracture geometries from the micro-seismic data will assist us in optimizing completions on future horizontal wells.  We are confident we will be able to project the results to higher condensate yield drilling locations as we move to the northeast in our acreage position, which encompasses the entire breadth of the condensate-rich window.  Our Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational, and timing advantages if we progress to full development of the Duvernay resource play.  In combination, our Cardium, Mannville, and Duvernay positions provide us with exploration and development opportunities in our core Canadian operating region that have the potential to deliver strong production and reserve growth into the latter half of the decade.

France

We completed a highly successful five-well drilling campaign in the Champotran field in the Paris Basin in 2013, adding nearly 5.5(1) mmboe of 2P reserves and confirming 20 potential well locations for future drilling.  During the fourth quarter of 2013, the five wells produced at an average rate per well of 250 bbls/d at an average water cut of only 3%.  Late in 2013, we converted a previous producing well at Champotran to water injection to add additional injection capacity to our previously-existing waterflood program in the field.  Based on positive initial results from this most recent conversion to injection, we believe that expanded waterflooding may lead to significantly improved recoveries from the Champotran field over time.  In late September, 2013 the third-party Lacq gas processing facility, which processed our gas production from the Vic Bihl field in the Aquitaine Basin, was permanently shut-in.  As a result, we have temporarily shut-in natural gas production of approximately 700 boe/d from the field while we complete preparations for a phased transfer of our production to an alternative third party facility.  We currently anticipate approximately 140 boe/d of our Vic Bihl gas production will be back on-steam in the third quarter of 2014.  The remainder of the shut-in gas production at Vic Bihl is not expected to be back on production until late 2015.  With the full integration of our 2012 acquisitions complete, our French business is now positioned as a key organic oil growth asset featuring low base decline rates, high netbacks from Brent-based production, strong cash flow generation and high capital efficiencies on development projects.  As a result, we have been actively increasing our France-based technical staff to identify and execute additional investment opportunities in these large, complex, conventional light oil fields in both the Paris and Aquitaine Basins.

Netherlands

In 2013, we continued permitting and drilling preparations in advance of a six-well drilling campaign for 2014 that was initiated in January 2014.  We also completed a debottlenecking project at Garijp and construction and commissioning of surface facilities for our multi-zone Langezwaag-1 well (42% working interest) in 2013.  Early in the fourth quarter of 2013, we closed our acquisition of Northern Petroleum Plc's operating interests in the Netherlands.  The acquisition added interests in nine operated onshore concessions (six concessions on production or in development and three exploration concessions) and a non-operated interest in one offshore concession.  This accretive acquisition brings synergies with our legacy assets and consolidates our position in northeast Netherlands, while also opening up new development opportunities in the central part of the Netherlands.  Production from the acquired assets is expected to average approximately 400 boe/d in 2014.  The assets added 2.4(2) mmboe of 2P reserves and 298,500 net acres of land, of which 98% is currently undeveloped.  Subsequent to year-end 2013, we were awarded the Ijsselmuiden exploration concession, which consists of approximately 110,500 net undeveloped acres, further increasing our undeveloped land base in the Netherlands to more than 800,000 net acres.  We have identified several development opportunities on the new assets that increase our already significant inventory of investment projects in the Netherlands.  Given our increased land position and our continued drilling success in the Netherlands, we now view our Netherlands Business Unit as an organic growth business.  We are increasing our technical staff in the Netherlands to support our efforts to convert our substantial inventory of prospect leads into drillable projects.  Beginning in 2014, we intend to increase activity levels in the Netherlands each year to maintain a rolling inventory of projects so that each year's capital program will involve a combination of drilling new wells and the tie-in of previous successes.

Ireland

Construction of the five-kilometre land-based portion of the onshore pipeline, offshore umbilical-laying, seismic acquisition and workover activities were conducted in 2013.  Construction of the 4.9 kilometre tunnel portion of the onshore pipeline is more than 70% complete with approximately 1.4 kilometres of tunneling remaining.  Based on review of the current deterministic schedule for remaining construction and commissioning activities, we continue to anticipate first gas from Corrib in approximately mid-2015.  Following successful subsea well operations conducted during the third quarter of 2013, we increased our peak production estimate at Corrib from 54 mmcf/d (9,000 boe/d) to approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.

Australia

Vermilion drilled two sidetracks off existing wells during the first half of 2013.  The program included the drilling of a 3,400 metre horizontal leg, the longest horizontal section drilled to-date at Wandoo. The 2013 drilling program has been our most successful effort yet in Australia.  Both sidetracks were brought on production at restricted rates in April, demonstrating initial productive capacities in excess of 6,000 bbls/d and 3,000 bbls/d, respectively.  To meet current marketing agreements and provide long-term certainty to our customers, our current plan is to maintain field-total production levels within our prior guidance of between 6,000 bbls/d and 8,000 bbls/d.  We anticipate maintaining these production levels in Australia for the foreseeable future with drilling programs approximately every two years.  Our next drilling program is expected to occur in 2015. Wandoo's oil currently garners a premium of approximately US$7.00 to the Dated Brent index and incurs no transportation cost as production is sold directly at the platform, leading to high netbacks.

Germany

In November, 2013, we announced an agreement to acquire a 25% contractual participation interest in a four-partner consortium in Germany from GDF Suez S.A.  The acquisition was subsequently completed in February of 2014, and will enable us to participate in the exploration, development, production and transportation of natural gas from the assets held by the consortium.  The assets are comprised of four gas producing fields across eleven production licenses and are characterized by a low effective decline rate of approximately 16% annually.  The acquired assets are expected to contribute approximately 2,300 boe/d of production in 2014, and include both exploration and production licenses that comprise a total of 204,000 gross acres, of which 85% is in the exploration license.  Germany is a producing region with a long history of oil and gas development activity, low political risk, and strong marketing fundamentals.  The acquisition provides us with entry into this sizable market, in the form of free cash flow(3) generating, low-decline assets with near-term development inventory in addition to longer-term, low-permeability gas prospectivity.  Entry into Germany is in keeping with our European focus, and will increase our exposure to the strong fundamentals and pricing of European natural gas markets.  We believe that our conventional and unconventional expertise, coupled with new access to proprietary technical data, will position us strongly for future development and expansion opportunities in both Germany and the greater European region.

General Outlook

Development capital for 2014 is currently estimated at $555 million. Our operations continue to perform strongly, generating organic production growth in a capital-efficient manner. With the contribution of production associated with both our Netherlands and Germany acquisitions, we are guiding to full year 2014 average annual production volumes of 45,000 to 46,000 boe/d.  Assuming commodity prices remain near current levels for the remainder of 2014, the Company anticipates that it will fully fund its net dividends(3) and development capital expenditures (excluding capital investment at Corrib) with fund flows from operations(3) during 2014.

We believe we remain positioned to deliver strong operational and financial performance over the next several years.  We continue to target annual organic production growth of approximately 5-7% along with providing reliable and growing dividends.  Near term production and fund flows from operations(3) 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 growth and free cash flow(3) growth is expected from Corrib beginning approximately mid-2015 with the first full year of production from the project in 2016.  Our Australian Business Unit is expected to provide steady production as well as significant free cash flow(3).

With the anticipated growth of fund flows from operations(3), the continued strength of our operations and our expansive opportunity base, we are confident we can achieve our future growth objectives and continue to provide reliable growth and a growing dividend stream to investors.  We believe the Company's balance sheet remains well positioned to execute its capital-efficient growth-and-income model and fund Corrib development through to first gas while remaining within an acceptable net debt-to-fund flows from operations(3) ratio.  Corrib is expected to provide a further significant increase to the Company's projected free cash flow(3) upon first gas production.

The management and directors of Vermilion continue to hold approximately 8% of the outstanding shares and remain committed to delivering superior rewards to all stakeholders.  Continuing to be acknowledged for excellence in our business practices, Vermilion was recognized for the fourth consecutive year by the Great Place to Work® Institute in both Canada and France in 2013.  We ranked as the 22nd Best Workplace in Canada among more than 315 companies. Our French unit ranked as the 27th Best Workplace in the country.

(signed "Lorenzo Donadeo")

Lorenzo Donadeo
Chief Executive Officer
March 3, 2014

(1) Estimated proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 4, 2014 , with an effective date of December 31, 2013 (the "2013 GLJ Reserves Evaluation").
(2) Estimated proved plus probable reserves attributable to the assets as evaluated by GLJ in a report dated September 16, 2013, with an effective date of December 31, 2012.
(3) 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.

HIGHLIGHTS

  Three Months Ended     Year Ended
($M except as indicated) Dec 31, Sept 30, Dec 31,     Dec 31, Dec 31,
Financial 2013  2013  2012      2013  2012 
Petroleum and natural gas sales 325,108  327,185  241,233      1,273,835  1,083,103 
Fund flows from operations (1) 163,660  165,645  141,737      667,526  557,728 
  Fund flows from operations ($/basic share) 1.61  1.63  1.43      6.61  5.69 
  Fund flows from operations ($/diluted share) 1.58  1.61  1.41      6.51  5.62 
Net earnings 101,510  67,796  56,914      327,641  190,622 
  Net earnings per share ($/basic share) 1.00  0.67  0.58      3.24  1.94 
Capital expenditures 148,478  135,661  157,035      542,726  452,538 
Acquisitions 29,103  7,586  209,254      36,689  315,438 
Asset retirement obligations settled 5,426  2,738  8,424      11,922  13,739 
Cash dividends ($/share) 0.60  0.60  0.57      2.40  2.28 
Dividends declared 61,208  61,003  56,435      242,599  223,717 
  % of fund flows from operations 37% 37% 40%     36% 40%
Net dividends (1) 42,433  41,649  37,967      170,308  151,659 
  % of fund flows from operations 26% 25% 27%     26% 27%
Payout (1) 196,337  180,048  203,426      724,956  617,936 
  % of fund flows from operations 120% 109% 144%     109% 111%
  % of fund flows from operations (excluding the Corrib project) 111% 87% 129%     94% 99%
Net debt (1) 749,685  700,286  677,231      749,685  677,231 
Ratio of net debt to annualized fund flows from operations (1) 1.1  1.1  1.2      1.1  1.2 
Operational
Production              
  Crude oil (bbls/d) 26,039  26,664  23,699      25,741  23,971 
  NGLs (bbls/d) 1,761  1,945  1,176      1,730  1,299 
  Natural gas (mmcf/d) 78.96  77.41  68.34      81.21  75.20 
  Total (boe/d) 40,960  41,510  36,265      41,005  37,803 
Average realized prices              
  Crude oil and NGLs ($/bbl) 106.00  108.87  96.74      104.46  101.07 
  Natural gas ($/mcf) 7.29  6.00  7.15      6.83  6.17 
Production mix (% of production)              
  % priced with reference to WTI 25% 24% 25%     25% 24%
  % priced with reference to AECO 17% 17% 14%     16% 16%
  % priced with reference to TTF 15% 14% 17%     16% 17%
  % priced with reference to Dated Brent 43% 45% 44%     43% 43%
Netbacks ($/boe) (1)              
  Operating netback 61.35  61.91  57.54      60.43  55.48 
  Fund flows from operations netback 43.32  43.60  46.07      43.94  40.96 
  Operating expenses 12.74  12.17  14.18      12.84  13.10 
Average reference prices              
  WTI (US $/bbl) 97.46  105.82  88.18      97.97  94.20 
  Edmonton Sweet index (US $/bbl) 82.53  101.10  84.86      90.40  86.42 
  Dated Brent (US $/bbl) 109.27  110.37  110.02      108.66  111.58 
  AECO ($/GJ) 3.35  2.31  3.05      3.01  2.26 
  TTF ($/GJ) 10.65  9.94  9.78      10.29  9.51 
Average foreign currency exchange rates              
  CDN $/US $ 1.05  1.04  0.99      1.03  1.00 
  CDN $/Euro 1.43  1.38  1.29      1.37  1.29 
Share information ('000s)
Shares outstanding - basic 102,123  101,787  99,135      102,123  99,135 
Shares outstanding - diluted (1) 104,869  104,195  101,913      104,869  101,913 
Weighted average shares outstanding - basic 101,961  101,613  98,944      100,969  98,016 
Weighted average shares outstanding - diluted (1) 103,426  102,763  100,425      102,467  99,294 

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 

The following is Management's Discussion and Analysis ("MD&A"), dated February 27, 2014, of Vermilion Energy Inc.'s ("Vermilion", "we", "our", "us" or the "Company") operating and financial results as at and for the three months and year ended December 31, 2013 compared with the corresponding periods in the prior year.

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

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

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

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

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

VERMILION'S BUSINESS

Vermilion is a Calgary, Alberta based international oil and gas producer focused on the acquisition, development and optimization of producing properties in 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: Includes revenues and expenditures related directly to our assets in Alberta.
  • France business unit: Relates to our operations in France in the Paris and Aquitaine Basins.
  • Australia business unit: Relates to our operations in the Wandoo offshore crude oil field.
  • Netherlands business unit: Relates to our operations in the Netherlands.
  • Ireland business unit: Relates to our 18.5% non-operated interest in the offshore Corrib natural gas 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.

NEW COUNTRY ENTRY

In November, 2013, we announced an agreement to acquire a 25% contractual participation interest in a four-partner consortium in Germany from GDF Suez S.A.  The acquisition was subsequently completed in February of 2014, and will enable us to participate in the exploration and development, production and transportation of natural gas from the assets held by the consortium.  The assets are comprised of four gas producing fields across eleven production licenses and are characterized by a low effective decline rate of approximately 16% annually.  The acquired assets are expected to contribute approximately 2,300 boe/d of production in 2014, and include both exploration and production licenses that comprise a total of 204,000 gross acres, of which 85% is in the exploration license.  The acquisition represents Vermilion's entry into the German exploration and production business, a producing region with a long history of oil and gas development activity, low political risk, and strong marketing fundamentals.  The acquisition provides us with entry into this sizable market, in the form of free cash flow generating, low-decline assets with near-term development inventory in addition to longer-term, low-permeability gas prospectivity.  Entry into Germany is in keeping with our European focus, and will increase our exposure to the strong fundamentals and pricing of European natural gas markets.  We believe that our conventional and unconventional expertise, coupled with new access to proprietary technical data, will position us strongly for future development and expansion opportunities in both Germany and the greater European region.

2013 REVIEW AND 2014 GUIDANCE

On November 7, 2013, concurrent with our release of 2014 guidance and our announcement of the dividend increase, we updated our 2013 capital expenditure guidance to $530 million. This represented an increase of approximately $45 million from our original guidance of $485 million.  The increase was attributable primarily to the impact of a weaker Canadian dollar as compared to foreign exchange rates at the time of our original guidance, a delay in the timing of rig arrival for our Australian drill program (originally anticipated to occur in late 2012), and minor additions to our capital work scope during 2013 (such as the addition of the Champotran southern extension well in France). The difference between 2013 guidance of $530 million and 2013 actual capital expenditures of $543 million was largely due to increased Cardium activity partially offset by activity delays in the Netherlands.

Following both the first and second quarters, we increased our original production guidance of 39,000-40,500 boe/d to guidance of 39,500-40,500 boe/d and 40,500-41,000 boe/d, respectively. The guidance increases were primarily driven by better-than-expected results from our capital program. 

The following table summarizes our 2013 actual results compared to guidance and our 2014 guidance:

        Date Capital Expenditures ($MM) Production (boe/d)
2013 Guidance     November 14, 2012 485  39,000 to 40,500
2013 Guidance - Update     May 1, 2013 485  39,500 to 40,500
2013 Guidance - Update     August 1, 2013 485  40,500 to 41,000
2013 Guidance - Update     November 7, 2013 530  40,500 to 41,000
2013 Actual     February 27, 2014 543  41,005 
2014 Guidance     November 7, 2013 555  45,000 to 46,000

SHAREHOLDER RETURN

Vermilion strives to provide investors with reliable and growing dividends in addition to sustainable, global production growth.  The following table, as of December 31, 2013, 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 $2.40   $6.96   $11.52
Capital appreciation per Vermilion share $10.38   $16.13   $37.16
Total return per Vermilion share 24.6%   50.0%   193.3%
Annualized total return per Vermilion share 24.6%   14.5%   24.0%
Annualized total return on the S&P TSX High Income Energy Index 13.8%   (6.1%)   5.9%

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

CONSOLIDATED RESULTS OVERVIEW

    Three Months Ended   % change       Year Ended   % change
    Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
    2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
Production                        
  Crude oil (bbls/d) 26,039  26,664  23,699    (2%) 10%     25,741  23,971    7%
  NGLs (bbls/d) 1,761  1,945  1,176    (9%) 50%     1,730  1,299    33%
  Natural gas (mmcf/d) 78.96  77.41  68.34    2% 16%     81.21  75.20    8%
  Total (boe/d) 40,960  41,510  36,265    (1%) 13%     41,005  37,803    8%
  Build (draw) in inventory (bbl) (10,192) 18,946  259,481            (228,954) 213,472     
Financial metrics                        
  Fund flows from operations ($M) 163,660  165,645  141,737    (1%) 15%     667,526  557,728    20%
     Per share ($/basic share) 1.61  1.63  1.43    (1%) 13%     6.61  5.69    16%
  Net earnings ($M) 101,510  67,796  56,914    50% 78%     327,641  190,622    72%
     Per share ($/basic share) 1.00  0.67  0.58    49% 72%     3.24  1.94    67%
  Cash flows from operating activities ($M) 177,003  158,236  99,907    12% 77%     705,025  496,580    42%
  Net debt ($M) 749,685  700,286  677,231    7% 11%     749,685  677,231    11%
  Cash dividends ($/share) 0.60  0.60  0.57    5%     2.40  2.28    5%
Activity                        
  Capital expenditures ($M) 148,478  135,661  157,035    9% (5%)     542,726  452,538    20%
  Acquisitions ($M) 29,103  7,586  209,254            36,689  315,438     
  Gross wells drilled 21.00  21.00  26.00            76.00  78.00     
  Net wells drilled 16.65  16.26  17.70            64.21  56.10     

Operational review

  • Recorded average production of 41,005 boe/d during 2013, reflecting production growth in all of our producing regions and year-over-year consolidated production growth of 8%.  Production growth was achieved through continued development in the Cardium and Mannville plays in Canada, production additions from the 2013 drilling programs in France and Australia, and incremental production in the Netherlands from our Q4 2013 acquisition.
  • Activity during the year included capital expenditures of $542.7 million and acquisitions of $36.7 million.  The majority of the capital expenditures related to continued development of the Cardium and Mannville plays in Canada, successful drilling campaigns in France and Australia, and tunneling in Ireland.  In addition, during Q4 2013, Vermilion completed a small acquisition in the Netherlands for $27.5 million which included nine operated onshore concessions (six in production or development and three exploration) and a non-operated interest in one offshore concession.

Financial review

Net earnings

  • For the three months and year ended December 31, 2013, consolidated net earnings was $101.5 million ($1.00/basic share) and $327.6 million ($3.24/basic share), an increase of 78% and 72% versus the same periods in 2012.
  • The year-over-year increases resulted primarily from higher production in all our producing business units, draws in inventory during the year, stronger Canadian pricing for crude oil and natural gas, unrealized foreign exchange gains, and an impairment recovery.  These increases were partially offset by increased current income taxes as a result of increased taxable income combined with tax provisions recorded for tax assessments in France.
  • Net earnings for Q4 2013 increased by approximately 50% versus Q3 2013.  The quarter-over-quarter increase occurred despite relatively consistent operating results due to increased unrealized foreign exchange gains and the aforementioned impairment recovery, partially offset by increased equity based compensation and deferred tax expense.
  • Unrealized foreign exchange gains of $22.3 million and $52.0 million for the three months and year ended December 31, 2013 were the result of the Euro strengthening significantly versus the Canadian dollar and the resulting impact on our Euro denominated financial assets.
  • The impairment recovery recognized during Q4 2013 of $47.4 million related to impairment charges previously recognized in 2011 and 2012.  The impairment recovery resulted from increased proved and probable reserves of natural gas and natural gas liquids, due primarily to the successful application of horizontal drilling and multi-stage fracturing technology to the previously impaired cash generating unit.

Cash flows from operating activities

  • Increased cash flow from operating activities by 42% year-over year.  This increase resulted from increased production in all of Vermilion's producing regions, stronger Canadian pricing for crude oil and natural gas, and timing differences pertaining to working capital.
  • Increased cash flow from operating activities for Q4 2013 by 77% as compared to Q4 2012.  The year-over-year increase was primarily the result of higher production in all our producing business units, increases in all relevant commodity prices, timing differences pertaining to working capital, and the absence of a large build in inventory which occurred in Q4 2012.

Fund flows from operations

  • Generated fund flows from operations of $667.5 million ($6.61/basic share) during 2013, an increase of 20% year-over-year.  This increase in fund flows from operations resulted from increased production in all of Vermilion's producing regions coupled with stronger Canadian pricing for crude oil and natural gas.

Net debt

  • Maintained a strong balance sheet with closing net debt of $749.7 million, representing 1.1 times fund flows from operations.  The year-over-year increase in net debt was primarily a result of our aforementioned acquisition in the Netherlands coupled with current year development capital expenditures in Ireland.

Dividends

  • Paid a dividend of $0.20 per common share per month during 2013 and in November 2013 announced a 7.5% increase in the monthly dividend to $0.215 per common share per month (effective for the January 2014 dividend paid on February 17, 2014).  This was our second consecutive annual dividend increase.

COMMODITY PRICES

  Three Months Ended   % change     Year Ended   % change
  Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
  2013 2013  2012   Q3/13 Q4/12     2013  2012    2012 
Average reference prices                        
WTI (US $/bbl) 97.46  105.82  88.18    (8%) 11%     97.97  94.20    4%
Edmonton Sweet index (US $/bbl) 82.53  101.10  84.86    (18%) (3%)     90.40  86.42    5%
Dated Brent (US $/bbl) 109.27  110.37  110.02    (1%) (1%)     108.66  111.58    (3%)
AECO ($/GJ) 3.35  2.31  3.05    45% 10%     3.01  2.26    33%
TTF ($/GJ) 10.65  9.94  9.78    7% 9%     10.29  9.51    8%
TTF (€/GJ) 7.45  7.20  7.58    3% (2%)     7.51  7.37    2%
Average realized prices ($/boe)                        
Canada 61.10  63.56  58.80    (4%) 4%     61.14  54.89    11%
France 112.84  107.08  102.26    5% 10%     106.26  105.13    1%
Netherlands 67.88  61.44  60.96    10% 11%     64.08  58.69    9%
Australia 124.63  120.95  115.22    3% 8%     119.38  117.03    2%
Consolidated 86.04  86.10  78.40    10%     83.83  79.51    5%
Production mix (% of production)                        
% priced with reference to WTI 25% 24% 25%           25% 24%    
% priced with reference to AECO 17% 17% 14%           16% 16%    
% priced with reference to TTF 15% 14% 17%           16% 17%    
% priced with reference to Dated Brent 43% 45% 44%           43% 43%    
                         

Reference prices

  • Dated Brent remained relatively consistent from Q3 2013 to Q4 2013 while WTI and the Edmonton Sweet index decreased by 8% and 18%, respectively.  The decreases in WTI and the Edmonton Sweet index were attributable to refinery outages and increasing supply.
  • AECO increased 45% from Q3 2013 to Q4 2013 as a result of strong winter demand  for natural gas in North America.
  • TTF in Canadian dollar terms increased by 7% from Q3 2013 to Q4 2013, benefiting from the strengthening of the Euro.

Realized prices

  • Our consolidated realized price remained relatively consistent quarter-over-quarter at $86.04/boe.  While North American crude oil pricing decreased in Q4 2013, the impact of this decrease was mostly offset by higher pricing for our Canadian and Netherlands natural gas production and continued strong pricing for our crude oil production in Australia.
  • Our consolidated realized price increased by 5% for 2013 as compared to 2012.  This increase was primarily due to stronger North American crude oil and natural gas pricing coupled with foreign exchange benefits resulting from the weakening of the Canadian dollar versus both the Euro and the US dollar.

FUND FLOWS FROM OPERATIONS

  Three Months Ended     Year Ended
  Dec 31, 2013   Sept 30, 2013   Dec 31, 2012     Dec 31, 2013   Dec 31, 2012
  $M $/boe   $M $/boe   $M $/boe     $M $/boe   $M $/boe
Petroleum and natural gas sales 325,108  86.04    327,185  86.10    241,233  78.40      1,273,835  83.83    1,083,103  79.51 
Royalties (17,616) (4.66)   (18,730) (4.93)   (11,938) (3.88)     (67,936) (4.47)   (52,084) (3.82)
Petroleum and natural gas revenues 307,492  81.38    308,455  81.17    229,295  74.52      1,205,899  79.36    1,031,019  75.69 
Transportation expense (9,081) (2.40)   (6,549) (1.72)   (5,458) (1.77)     (28,924) (1.90)   (24,113) (1.77)
Operating expense (48,140)  (12.74)   (46,246)  (12.17)   (43,634)  (14.18)     (195,043) (12.84)   (178,442)  (13.10)
General and administration (13,954) (3.69)   (12,033) (3.17)   (8,888) (2.89)     (49,910) (3.28)   (43,773) (3.21)
Corporate income taxes (43,065) (11.40)   (46,453) (12.22)   (21,470) (6.98)     (161,794)  (10.65)   (121,843) (8.94)
PRRT (17,173) (4.55)   (15,649) (4.12)   (1,598) (0.52)     (56,565) (3.72)   (60,070) (4.41)
Interest expense (10,049) (2.66)   (10,109) (2.66)   (7,656) (2.49)     (38,183) (2.51)   (27,586) (2.03)
Realized loss on derivative instruments (1,300) (0.34)   (4,765) (1.25)   (1,559) (0.51)     (7,082) (0.47)   (12,737) (0.93)
Realized foreign exchange (loss) gain (1,294) (0.34)   (1,227) (0.32)   2,459  0.81      (1,866) (0.12)   2,804  0.21 
Realized other income (expense) 224  0.06    221  0.06    246  0.08      994  0.07    (7,531) (0.55)
Fund flows from operations 163,660  43.32    165,645  43.60    141,737  46.07      667,526  43.94    557,728  40.96 

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

($M) Q4/13 vs. Q3/13 Q4/13 vs. Q4/12 2013 vs. 2012
Fund flows from operations - Comparative period 165,645  141,737  557,728 
Sales volume variance:      
   Canada 4,476  13,090  38,747 
   France (15,471) 12,675  60,108 
   Netherlands 8,324  4,113  4,215 
   Australia (3,984) 26,888  26,091 
Pricing variance on sold volumes:      
   WTI (10,805) 6,136  25,464 
   AECO 3,696  665  13,592 
   Dated Brent 7,942  16,230  10,688 
   TTF 3,745  4,078  11,827 
Changes in:      
   Realized derivatives 3,465  259  5,655 
   Royalties 1,114  (5,678) (15,852)
   Operating expense (1,894) (4,506) (16,601)
   Transportation (2,532) (3,623) (4,811)
   Interest 60  (2,393) (10,597)
   General and administration (1,921) (5,066) (6,137)
   Realized other income (22) 8,525 
   Realized foreign exchange (67) (3,753) (4,670)
   Corporate income taxes 3,388  (21,595) (39,951)
   PRRT (1,524) (15,575) 3,505 
Fund flows from operations - Current Period 163,660  163,660  667,526 

Fund flows from operations for Q4 2013 was approximately 1% ($2.0 million) lower than Q3.  This slight decrease occurred as a result of declines in the Edmonton Sweet index, which was partially offset by increased pricing for natural gas and for our crude oil production in Australia.

Fund flows from operations for the three months and year ended December 31, 2013 was approximately 15% ($21.9 million) and 20% ($109.8 million) higher, respectively, than the same periods in 2012.  These increases were primarily the result of higher production in all our producing business units, large draws in inventory during the quarter and full year periods, and increases in all relevant commodity prices.  These increases were partially offset by increased current income taxes as a result of increased taxable income combined with tax provisions recorded for tax assessments in France.

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

CANADA BUSINESS UNIT

Overview

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

Operational review

    Three Months Ended   % change       Year Ended   % change
    Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
Canada business unit 2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
Production                        
  Crude oil (bbls/d) 8,719  7,969  7,983    9% 9%     8,387  7,659    10%
  NGLs (bbls/d) 1,699  1,897  1,106    (10%) 54%     1,666  1,232    35%
  Natural gas (mmcf/d) 41.43  43.40  31.41    (5%) 32%     42.39  37.50    13%
  Total (boe/d) 17,322  17,099  14,323    1% 21%     17,117  15,142    13%
Production mix (% of total)                        
  Crude oil 50% 47% 56%           49% 51%    
  NGLs 10% 11% 8%           10% 8%    
  Natural gas 40% 42% 36%           41% 41%    
Activity                        
  Capital expenditures ($M) 77,245  62,270  82,844    24% (7%)     241,197  271,774    (11%)
  Acquisitions ($M) 1,603  7,586            9,189  69     
  Gross wells drilled 21.00  21.00  26.00            69.00  76.00     
  Net wells drilled 16.65  16.26  17.70            57.21  54.70     

Production

  • Production in Canada increased by 1% quarter-over-quarter and by 13% year-over-year.
  • Year-over-year increase was largely attributable to continued development in the Cardium, supplemented by Mannville wells brought on production during the year.

Activity review

  • Vermilion drilled 21 (16.6 net) wells during Q4 2013.
  • In 2013, Vermilion drilled 69 (57.2 net) wells.

Cardium

  • In the Cardium, we drilled 19 (15.6 net) wells and brought 16 gross operated wells on production during Q4 2013.  Eight of the wells drilled during Q4 2013 were long reach wells (four 1.5-mile, three 2-mile, and one 2.3-mile long well).
  • Since 2009, we have drilled or participated in 238 (170.9 net) wells in the Cardium.
  • Average well costs, normalized on a per section basis, are approximately $3.0 million per section (2009 - $5.0 million per section).
  • Per boe operating costs are less than $5.25/boe for operated production.
  • In 2014, we plan to drill or participate in 36 (30.3 net) Cardium wells.
  • Cardium expenditures are expected to represent approximately 60% of planned Canadian development expenditures in 2014.

Mannville

  • During Q4 2013, in the Mannville, we drilled two (1.0 net) wells and brought 1.2 net wells on production.  In 2013, we drilled and placed on production six (3.7 net) Mannville wells.
  • In 2014, we plan to drill eight (5.7 net) Mannville wells.
  • Mannville expenditures are expected to represent approximately 20% of planned Canadian development expenditures in 2014.

Duvernay

  • To date, we have drilled three vertical stratigraphic test wells, which confirmed our placement inside the condensate-rich window.
  • In 2014, we plan to drill two horizontal Duvernay wells, the first of which is currently in progress.

Financial review

    Three Months Ended   % change       Year Ended   % change
Canada business unit Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
($M except as indicated) 2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
  Sales 97,367  100,000  77,476    (3%) 26%     382,005  304,202    26%
  Royalties (11,039) (11,156) (7,401)   (1%) 49%     (40,891) (31,667)   29%
  Transportation expense (4,102) (3,272) (1,922)   25% 113%     (12,254) (8,321)   47%
  Operating expense (13,218) (12,770) (14,514)   4% (9%)     (55,804) (55,418)   1%
  General and administration (2,478) (2,675) (1,765)   (7%) 40%     (12,979) (12,344)   5%
  Fund flows from operations 66,530  70,127  51,874    (5%) 28%     260,077  196,452    32%
Netbacks ($/boe)                        
  Sales 61.10  63.56  58.80    (4%) 4%     61.14  54.89    11%
  Royalties (6.93) (7.09) (5.62)   (2%) 23%     (6.55) (5.71)   15%
  Transportation expense (2.57) (2.08) (1.46)   24% 76%     (1.96) (1.50)   31%
  Operating expense (8.29) (8.12) (11.01)   2% (25%)     (8.93) (10.00)   (11%)
  General and administration (1.60) (2.04) (1.34)   (22%) 19%     (2.24) (2.23)  
  Fund flows from operations netback 41.71  44.23  39.37    (6%) 6%     41.46  35.45    17%
Reference prices                        
  WTI (US $/bbl) 97.46  105.82  88.18    (8%) 11%     97.97  94.20    4%
  Edmonton Sweet index (US $/bbl) 82.53  101.10  84.86    (18%) (3%)     90.40  86.42    5%
  AECO ($/GJ) 3.35  2.31  3.05    45% 10%     3.01  2.26    33%

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 U.S.  The realized price of our natural gas in Canada is based on the AECO spot price in Canada.
  • The decrease in sales per boe for Q4 2013 as compared to Q3 2013 was primarily the result of 18% lower Edmonton Sweet index pricing, partially offset by a 45% increase in the AECO reference price.
  • The increase in sales per boe for the three months and year ended December 31, 2013 as compared to the same periods in 2012 was primarily the result of a 10% and 33% increase, respectively, in the AECO reference price.

Royalties

  • Royalty expense as a percentage of sales was consistent quarter-over-quarter.
  • The increase in royalty expense as a percentage of sales from 10% to 11% for the three months and year ended December 31, 2013 as compared to the same periods in 2012 was the result of the timing of placing Cardium wells on production due to the associated royalty incentive on initial production volumes.

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 three months and year ended December 31, 2013 compared to the same periods in 2012 as a result of increased crude oil production subject to transportation costs.

Operating expense

  • Operating expense per boe was lower for the year ended December 31, 2013 as operating expense remained relatively stable while production increased by 13% year-over-year.
  • Operating expense for Q4 2013 was lower than Q4 2012 as the 2012 period operating expense included higher turnaround activity and downhole work.

General and administration

  • Year-over-year, general and administration expense per boe remained steady. Fluctuations in the presented quarters relates primarily to the timing of expenditures.

FRANCE BUSINESS UNIT

Overview

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

Operational review

    Three Months Ended   % change       Year Ended   % change
  Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
France business unit 2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
Production                        
  Crude oil (bbls/d) 11,131  11,625  9,843    (4%) 13%     10,873  9,952    9%
  Natural gas (mmcf/d) 5.23  3.91    (100%) (100%)     3.40  3.59    (5%)
  Total (boe/d) 11,131  12,496  10,495    (11%) 6%     11,440  10,550    8%
Inventory (mbbls)                        
  Opening crude oil inventory 226  202  246            354  187     
  Adjustments              
  Crude oil production 1,024  1,069  906            3,969  3,642     
  Crude oil sales (981) (1,045) (798)           (4,059) (3,475)    
  Closing crude oil inventory 269  226  354            269  354     
Production mix (% of total)                        
  Crude oil 100% 93% 94%           95% 94%    
  Natural gas 7% 6%           5% 6%    
Activity                        
  Capital expenditures ($M) 31,899  23,664  20,958    35% 52%     100,378  47,382    112%
  Acquisitions ($M) 74,947            181,062     
  Gross wells drilled           5.00     
  Net wells drilled           5.00     

Production

  • Quarter-over-quarter production decrease of 11% and year-over-year production growth of 8%.
  • Q4 2013 vs. Q3 2013 decrease was mainly due to our gas production being shut-in at Vic Bihl. In late September 2013, the third party Lacq processing facility, which processed our Vic Bihl production of approximately 700 boe/d, was permanently shut in. As a result, our Vic Bihl gas production has been temporarily shut in while preparations to transfer an alternative facility are completed. We expect approximately 140 boe/d will be back on-stream in Q3, with the remainder not anticipated to be back on production until late-2015.
  • Year-over-year growth driven by production from our five-well drilling program in Champotran, which was brought on late in the second quarter, and production additions from the ZaZa acquisition at the end of 2012.
  • The five wells drilled in 2013 produced at an average rate per well of 250 bbls/d with minimal water during the fourth quarter of 2013.
  • Production remained predominately weighted to Brent crude at approximately 95% of production for 2013, and 100% in Q4 2013.

Activity review

  • During Q4 2013, we converted a previous producing well to an injection well to add additional injection capacity to our waterflood program at Champotran.
  • During Q4 2013, we also completed a number of workovers, pipeline and facility integrity projects, and prepared for our 2014 capital program.
  • In 2013, we started increasing our France-based technical staff to identify and execute additional investment opportunities.
  • In 2013, we completed a successful five-well drilling campaign in the Champotran field, adding significant production, reserves, and confirming 20 potential future drilling locations.
  • In 2014, we are planning a nine-well drilling program in the Champotran, Cazaux, Parentis, and Tamaris fields.  In addition, we are planning an estimated 18-well workover program.

Financial review

    Three Months Ended   % change       Year Ended   % change  
France business unit Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
($M except as indicated) 2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
  Sales 110,757  120,574  87,702    (8%) 26%     453,315  388,410    17%
  Royalties (6,577) (7,574) (4,537)   (13%) 45%     (27,045) (20,417)   32%
  Transportation expense (4,622) (2,713) (1,854)   70% 149%     (12,505) (8,236)   52%
  Operating expense (15,524) (14,599) (13,699)   6% 13%     (66,997) (54,907)   22%
  General and administration (5,080) (4,964) (4,779)   2% 6%     (19,657) (15,009)   31%
  Current income taxes (28,024) (31,717) (13,335)   (12%) 110%     (94,524) (63,006)   50%
  Fund flows from operations 50,930  59,007  49,498    (14%) 3%     232,587  226,835    3%
Netbacks ($/boe)                        
  Sales 112.84  107.08  102.26    5% 10%     106.26  105.13    1%
  Royalties (6.70) (6.73) (5.29)   27%     (6.34) (5.53)   15%
  Transportation expense (4.71) (2.41) (2.16)   95% 118%     (2.93) (2.23)   31%
  Operating expense (15.82) (12.97) (15.97)   22% (1%)     (15.70) (14.86)   6%
  General and administration (5.18) (4.41) (5.57)   17% (7%)     (4.61) (4.06)   14%
  Current income taxes (28.55) (28.17) (15.55)   1% 84%     (22.16) (17.05)   30%
  Fund flows from operations netback 51.88  52.39  57.72    (1%) (10%)     54.52  61.40    (11%)
Reference prices                        
  Dated Brent (US $/bbl) 109.27  110.37  110.02    (1%) (1%)     108.66  111.58    (3%)

Sales

  • Crude oil production in France is priced with reference to Dated Brent.
  • Sales for the three months and year ended December 31, 2013 increased versus the same periods in 2012, despite a decrease in the Dated Brent reference price, due to an increase in sold volumes resulting from new production brought on from the 2013 drilling campaign in addition to the weakening of the Canadian dollar.

Royalties

  • Royalties in France relate to two components: RCDM (levied on units of production and not subject to changes in commodity prices) and R31 (based on a percentage of revenue).
  • The increase in royalties expense for the three months and year ended December 31, 2013 versus the same periods in 2012 was primarily the result of increased R31 royalties associated with incremental production from our Q4 2012 acquisition as well as production from wells drilled during our 2013 drilling campaign.

Transportation

  • Transportation expense in France pertains to the shipments of crude oil by tanker from the Aquitaine Basin to third party refineries.
  • The increase in transportation expense per boe for the three months and year ended December 31, 2013 versus the comparable periods resulted from an increased number of shipments from the Aquitaine Basin.

Operating expense

  • The increase in operating expense per boe from Q3 to Q4 2013 was primarily the result of lower production.  Overall operating expense was 6% higher from Q3 to Q4 2013 primarily as a result of higher electricity prices.
  • On a year-over-year basis, operating expense per boe increased by 6% largely as a result of the foreign exchange impact of a weakening Canadian dollar versus the Euro.  Overall operating expense increased by 22% year-over-year due to the aforementioned foreign exchange impacts and increased activity associated with higher production.

General and administration

  • General and administration expense per boe for the three months and year ended December 31, 2013 increased versus the same periods in 2012 due to additional staffing levels, including staff from our Q4 2012 acquisition as well as additional technical staff to support our growing operational activities in France.

Current income taxes

  • The year-over-year increase in current income taxes for the three months and year ended December 31, 2013 as compared to the same periods in 2012 was the result of the increase in fund flows from operations combined with provisions recognized relating to tax assessments from tax authorities for prior period tax positions.

NETHERLANDS BUSINESS UNIT

Overview

  • Entered the Netherlands in 2004.
  • Second largest onshore gas producer by volume.
  • Interests includes 16 licenses in the northeast region, 5 licenses in the central region, and 2 offshore licenses.
  • Licenses include more than 780,000 net acres of undeveloped land.
  • High impact natural gas drilling and development with royalty-free production.
  • Natural gas produced in the Netherlands is priced off the TTF index, which receives a significant premium over North American gas prices.

Operational review

    Three Months Ended   % change       Year Ended   % change
    Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
Netherlands business unit 2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
Production                        
  NGLs (bbls/d) 62  48  70    29% (11%)     64  67    (4%)
  Natural gas (mmcf/d) 37.53  28.78  33.03    30% 14%     35.42  34.11    4%
  Total (boe/d) 6,318  4,845  5,574    30% 13%     5,967  5,751    4%
Activity                        
  Capital expenditures ($M) 15,698  8,316  8,118    89% 93%     28,543  21,324    34%
  Acquisitions ($M) 27,500            27,500     
  Gross wells drilled           2.00     
  Net wells drilled           1.40     

Production

  • Achieved record annual production with 5,967 boe/d.
  • Quarter-over-quarter production growth of 30% and year-over-year production growth of 4%.
  • Q4 2013 vs. Q3 2013 increase in production was mainly attributable to completion of the retrofit of the Middenmeer Treatment Centre and the associated volumes processed through the 35 mmcf/d facility.

Activity

  • In October 2013, we acquired additional operating interests in nine operated onshore concessions (six in production or development and three exploration) and a non-operated interest in one offshore concession in the Netherlands for approximately $27.5 million.
    • Four of the onshore concessions are located in the northeastern part of the Netherlands, adjacent to or in close proximity to our existing concessions.  The remaining onshore licenses provide new opportunities for Vermilion in the central region of the Netherlands.
    • Production from the acquired assets is expected to average approximately 400 boe/d in 2014. The production is comprised of 99% natural gas.
    • The acquisition also added 2.4(1) mmboe of proved plus probable reserves and 298,500 net acres of land, of which approximately 98% is currently undeveloped.
  • We are currently planning and preparing for a six-well drilling program in the Netherlands in 2014. The drilling program will include our first new well on the lands acquired in October 2013.
  • Subsequent to year-end 2013, we were awarded the Ijsselmuiden exploration concession consisting of approximately 110,500 net undeveloped acres, increasing our total position in the country to over 800,000 net undeveloped acres.

(1) Estimated proved plus probable reserves attributable to the assets as evaluated by GLJ in a report dated September 16, 2013, with an effective date of December 31, 2012.

Financial review

    Three Months Ended   % change       Year Ended   % change
Netherlands business unit Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
($M except as indicated) 2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
  Sales 39,451  27,382  31,260    44% 26%     139,570  123,528    13%
  Operating expense (6,179) (5,209) (5,713)   19% 8%     (20,617) (19,149)   8%
  General and administration (1,553) (333) (625)   366% 148%     (2,724) (1,329)   105%
  Current income taxes (8,267) (6,810) (1,102)   21% 650%     (34,132) (25,648)   33%
  Fund flows from operations 23,452  15,030  23,820    56% (2%)     82,097  77,402    6%
Netbacks ($/boe)                        
  Sales 67.88  61.44  60.96    10% 11%     64.08  58.69    9%
  Operating expense (10.63) (11.69) (11.14)   (9%) (5%)     (9.47) (9.10)   4%
  General and administration (2.67) (0.75) (1.22)   256% 119%     (1.25) (0.63)   98%
  Current income taxes (14.22) (15.28) (2.15)   (7%) 561%     (15.67) (12.18)   29%
  Fund flows from operations netback 40.36  33.72  46.45    20% (13%)     37.69  36.78    2%
Reference prices                        
  TTF ($/GJ) 10.65  9.94  9.78    7% 9%     10.29  9.51    8%
  TTF (€/GJ) 7.45  7.20  7.58    3% (2%)     7.51  7.37    2%

Sales

  • As of January 1, 2013, 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. Prior to 2013, the natural gas price we received in the Netherlands was calculated using a formula based on the trailing average of Dated Brent and natural gas prices from European trading hubs.
  • The increase in sales per boe for the three months and year ended December 31, 2013 versus the comparable periods was due to the strengthening of the Euro against the Canadian dollar, resulting in translation to higher Canadian dollar TTF reference prices.

Royalties and transportation expense

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

Operating expense

  • Operating expense per boe for Q4 2013 was lower than Q3 2013 and Q4 2012 as a result of increased production volumes on largely fixed operating expense.
  • Overall operating expense for the three months and year ended December 31, 2013 versus the same periods in 2012 increased primarily as a result of the stronger Euro versus the Canadian dollar.

General and administration

  • Fluctuations in general and administration expense per boe for the quarters presented were driven by the timing of expenditures and partner recoveries.  The increase for Q4 2013 was primarily driven by the aforementioned acquisition during the quarter.
  • On a year-over-year basis, the increase in general and administration expense was primarily the result of increased technical staffing in the Netherlands in support of the development of our inventory of undeveloped acreage in addition to the aforementioned acquisition.

Current income taxes

  • Current income taxes in the Netherlands apply to taxable income after eligible deductions at an effective tax rate of approximately 46%.
  • Current income taxes per boe increased for the three months and year ended December 31, 2013 as compared to the same periods in 2012 due to a change in deductions for asset retirement obligations and depletion recorded during the 2012 period as compared to 2013.

AUSTRALIA BUSINESS UNIT

Overview

  • Entered Australia in 2005.
  • Hold title to a 100% working interest in Wandoo field, located approximately 80km northwest of Australia.
  • Production is operated from two off-shore platforms, and originates from 21 producing well bores.
  • Wells are located 600m below the sea bed with 500 to 3,000 plus meter horizontal lengths.
  • Contracted crude oil production is priced with reference to Dated Brent.

Operational review

    Three Months Ended   % change       Year Ended   % change
    Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
Australia business unit 2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
Production                        
  Crude oil (bbls/d) 6,189  7,070  5,873    (12%) 5%     6,481  6,360    2%
Inventory (mbbls)                        
  Opening crude oil inventory 183  187  117            268  222     
  Crude oil production 569  650  540            2,366  2,328     
  Crude oil sales (622) (654) (389)           (2,504) (2,282)    
  Closing crude oil inventory 130  183  268            130  268     
Activity                        
  Capital expenditures ($M) 8,420  5,880  25,257    43% (67%)     77,931  49,389    58%
  Gross wells drilled           2.00     
  Net wells drilled           2.00     

Production

  • Quarter-over-quarter production decreased by 12% and year-over-year production growth of 2%.
  • Q4 2013 production impacted by planned shutdown in October for platform maintenance and due to impacts from Cyclone Christine in late December.
  • Production volumes are managed to meet customer demands and long term supply agreements, and we continue to plan to produce between 6,000 and 8,000 bbls/d.
  • 2013 production reflects strong well results, more than offsetting natural declines, and we continue to produce the wells at restricted rates below their demonstrated productive capacity.

Activity review

  • Drilled two sidetracks off existing wells during the first half of 2013, including the longest horizontal section to date at Wandoo at 3,400 metres.
  • In Q4 2013, efforts were focused on facilities repairs and engineering studies.
  • In 2014, planned activities include ongoing facilities maintenance, enhancement and refurbishment along with preparation and permitting activities in advance of our planned 2015 drilling program.

Financial review

    Three Months Ended   % change       Year Ended   % change
Australia business unit Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
($M except as indicated) 2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
  Sales 77,533  79,229  44,795    (2%) 73%     298,945  266,963    12%
  Operating expense (13,219) (13,668) (9,708)   (3%) 36%     (51,625) (48,968)   5%
  General and administration (1,442) (1,414) (619)   2% 133%     (5,752) (3,715)   55%
  PRRT (17,173) (15,649) (1,598)   10% 975%     (56,565) (60,070)   (6%)
  Corporate income taxes (6,210) (7,666) (6,774)   (19%) (8%)     (31,735) (31,607)  
  Fund flows from operations 39,489  40,832  26,096    (3%) 51%     153,268  122,603    25%
Netbacks ($/boe)                        
  Sales 124.63  120.95  115.22    3% 8%     119.38  117.03    2%
  Operating expense (21.25) (20.86) (24.97)   2% (15%)     (20.62) (21.47)   (4%)
  General and administration expense (2.32) (2.16) (1.59)   7% 46%     (2.30) (1.63)   41%
  PRRT (27.60) (23.89) (4.11)   16% 572%     (22.59) (26.33)   (14%)
  Corporate income taxes (9.98) (11.70) (17.42)   (15%) (43%)     (12.67) (13.86)   (9%)
  Fund flows from operations netback 63.48  62.34  67.13    2% (5%)     61.20  53.74    14%
Reference prices                        
  Dated Brent (US $/bbl) 109.27  110.37  110.02    (1%) (1%)     108.66  111.58    (3%)

Sales

  • Our production in Australia currently receives a premium to Dated Brent.  This premium, coupled with the weakening of the Canadian dollar versus the US dollar, resulted in an increase in sales per boe despite slight declines in Dated Brent.

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 the three months and year ended December 31, 2013 was relatively consistent with the three months ended September 30, 2013 and the year ended December 31, 2012.
  • The year-over-year decrease in operating expense per boe was primarily the result of an increase in produced volumes resulting in lower fixed operating expense per bbl.

General and administration

  • The increase in general and administration expense for the three months and year ended December 31, 2013 as compared to the same periods in 2012 was primarily the result of increased staffing expenditures to support operational requirements.

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 approximately 30% on taxable income after eligible deductions, which include PRRT.
  • PRRT for Q4 2013 was significantly higher than Q4 2012 as the 2012 period included higher capital expenditures, which related to preparation for the 2013 Australian drilling campaign.  The expenditures relating to the drilling campaign, which were primarily incurred during Q1 2013, resulted in a decrease in PRRT for the year ended December 31, 2013 as compared to the same period in 2012.

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.
  • Acquired interest on July 30, 2009 for cash consideration of $136.8 million.  Pursuant to the terms of the acquisition agreement, Vermilion made an additional payment to the vendor of $134.3 million (US$135 million) at the end of 2012.
  • 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.
  • The Corrib field is expected to constitute 95% of Ireland's natural gas production and approximately 60% to 65% of Ireland's domestic gas consumption.

Operational and financial review

    Three Months Ended   % change       Year Ended   % change
Ireland business unit Dec 31, Sept 30, Dec 31,   Q4/13 vs. Q4/13 vs.     Dec 31, Dec 31,   2013 vs.
($M)  2013  2013  2012    Q3/13 Q4/12     2013  2012    2012 
  Transportation expense (357) (564) (1,682)   (37%) (79%)     (4,165) (7,556)   (45%)
  General and administration (482) (313) (341)   54% 41%     (1,442) (1,346)   7%
  Fund flows from operations (839) (877) (2,023)   (4%) (59%)     (5,607) (8,902)   (37%)
Activity                        
  Capital expenditures 14,472  35,028  18,093    (59%) (20%)     90,898  58,764    55%

Activity review

  • Various onshore and offshore activities have progressed over 2013, including umbilical lays to the offshore wells, onshore pipelining in segments that are not within the tunnel, construction of the tunnel boring machine reception site and gas plant pre-commissioning, in addition to the tunneling process.
  • To date, the land-based onshore pipeline is complete (approximately 5km), and there is approximately 1.4km of the 4.9km tunnel beneath Sruwaddacon Bay remaining to be tunneled.
  • Tunneling operations were re-started on November 3, 2013 after being suspended following an industrial accident, which resulted in a fatality at the project worksite on September 8, 2013.
  • Onshore pipelining, offshore umbilical lays, seismic processing and workover activities for our Corrib project were not impacted by the suspension.
  • Based on an early review of our deterministic schedule for remaining construction and commissioning activities, we revised our expectations for timing of first gas to approximately mid-2015 from earlier expectations for start-up at the end of 2014 or early 2015.
  • Following successful subsea well operations conducted on one of the production wells during the third quarter of 2013, we increased our peak production estimate at Corrib from 54 mmcf/d (9,000 boe/d) to approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.

Transportation expense

  • Transportation expense in Ireland relates to payments under a ship or pay agreement related to the Corrib project.  Required payments under this agreement were lower year-over-year.

CORPORATE

Overview

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

Financial review

  Three Months Ended     Year Ended
  Dec 31, Sept 30, Dec 31,     Dec 31, Dec 31,
($M) 2013  2013  2012      2013  2012 
General and administration (2,919) (2,334) (759)     (7,356) (10,030)
Current income taxes (564) (260) (259)     (1,403) (1,582)
Interest expense (10,049) (10,109) (7,656)     (38,183)  (27,586)
Realized loss on derivatives (1,300) (4,765) (1,559)     (7,082) (12,737)
Realized foreign exchange (loss) gain (1,294) (1,227) 2,459      (1,866) 2,804 
Realized other income (expense) 224  221  246      994  (7,531)
Fund flows from operations (15,902) (18,474) (7,528)     (54,896) (56,662)

General and administration

  • On a year-over-year basis, general and administration expense incurred in the Corporate segment was lower as a result of an increase in the staff involved in the operational activity of our business units.

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 the 2013 periods versus the 2012 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 loss in the fourth quarter and full year 2013 relate primarily to payments on our crude oil derivatives.  In the current quarter, these payments were offset partially by realized gains on our natural gas derivative instruments while over the full year, these payments were further offset by realized gains on our crude oil derivatives during Q2 2013.
  • A listing of derivative positions as at December 31, 2013 is included in "Supplemental Table 2".

Other income

  • In 2012, other expense included $8.5 million of expense relating to transfer taxes resulting from our acquisition of certain working interests in the Paris and Aquitaine Basins in France.

FINANCIAL PERFORMANCE REVIEW

              Year Ended
              Dec 31, Dec 31, Dec 31,
($M except per share)           2013  2012  2011 
Total assets           3,708,719  3,076,257  2,735,187 
Long-term debt           990,024  642,022  373,436 
Petroleum and natural gas sales           1,273,835  1,083,103  1,031,570 
Net earnings           327,641  190,622  142,821 
Net earnings per share                
  Basic           3.24  1.94  1.57 
  Diluted           3.20  1.92  1.55 
Cash dividends ($/share)           2.40  2.28  2.28 
                 
    Three Months Ended
    Dec 31, Sept 30, Jun 30, Mar 31, Dec 31, Sept 30, Jun 30, Mar 31,
($M except per share) 2013  2013  2013  2013  2012  2012  2012  2012 
Petroleum and natural gas sales 325,108  327,185  311,966  309,576  241,233  284,838  246,544  310,488 
Net earnings 101,510  67,796  106,198  52,137  56,914  30,798  37,816  65,094 
Net earnings per share                
  Basic 1.00  0.67  1.05  0.53  0.58  0.31  0.39  0.67 
  Diluted 0.98  0.66  1.04  0.51  0.57  0.31  0.38  0.66 

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

($M) Q4/13 vs. Q3/13 Q4/13 vs. Q4/12 2013 vs. 2012
Net earnings - Comparative period 67,796  56,914  190,622 
Changes in:      
Fund flows from operations (1,985) 21,923  109,798 
Equity based compensation (8,427) (2,722) (13,741)
Unrealized gain or loss on derivative instruments 4,971  (3,524) (640)
Unrealized foreign exchange gain or loss 18,058  8,417  56,378 
Unrealized other income (146) 284  (231)
Accretion (313) (408) (1,525)
Depletion and depreciation (4,868) (17,052) (26,443)
Deferred tax (20,976) (9,722) (54,468)
Gain on acquisition (45,309)
Impairment (recovery) 47,400  47,400  113,200 
Net earnings - Current Period 101,510  101,510  327,641 

The fluctuations in net earnings from quarter-to-quarter and from year-to-year are caused by changes in both cash and non-cash charges.  Cash charges 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 charges 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 charges may also include non-recurring charges resulting from acquisitions or charges resulting from impairment or impairment recoveries.

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

Fluctuations in equity based compensation expense primarily result from revisions in the future performance conditions related to the VIP estimated forfeiture rates, and the overall number of VIP outstanding.  In general, future performance conditions and estimated forfeiture rates are revised during the fourth quarter as information becomes more readily available relating to the Company's performance during the fiscal year.

Equity based compensation expense increased in 2013 as compared to 2012 as a result of the revision of future performance condition assumptions in both Q4 2012 and Q4 2013.  Equity based compensation expense was higher for Q3 2013 as compared to Q4 2013 as the revision of performance condition assumptions was partially offset by an increase in the estimated forfeiture rate, from 5.37% to 6.61%.

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 vise-versa.

In the three months and year ended December 31, 2013, Vermilion recognized an unrealized gain on derivative instruments of $1.3 million and $5.1 million, respectively.  These unrealized gains on derivative instruments were primarily the result of the reversal of unrealized losses on contracts settled during the respective periods.  As at December 31, 2013, Vermilion had a net current derivative liability position of $1.3 million relating primarily to crude oil derivative instruments for the first half of 2014.

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 U.S. 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.

During the three months and year ended December 31, 2013, the Euro strengthened significantly versus the Canadian dollar resulting in unrealized foreign exchange gains of $22.3 million and $52.0 million, respectively.

Accretion
Fluctuations in accretion expense are primarily the result of changes in the balance of asset retirement obligations.  The increase in accretion expense for 2013 as compared to 2012 was primarily the result of accretion on new wells drilled during 2013 and on wells acquired in an acquisition in France late in 2012.

Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily the result of changes in produced crude oil and natural gas volumes.  For the three months and year ended December 31, 2013, production as compared to the same periods in 2012 increased by 13% and 8%, respectively, resulting in higher depletion and depreciation expense of 26% and 9%, respectively.

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 fluctuations in tax losses.  The year-over-year increase in deferred tax expense resulted primarily from an increase in the temporary differences relating to asset retirement obligations.  For accounting purposes, asset retirement obligations decreased due to a change in discount and inflation rates while there was no corresponding decrease in the tax basis.

Impairment (recovery)
During Q1 2012, we recorded impairment losses of $65.8 million pertaining to our conventional deep gas and shallow coal bed methane natural gas plays in Canada.  These impairment charges were the result of significant declines in the forward pricing assumptions for natural gas in Canada.

In 2013, we recognized a recovery of a portion of the impairment charges previously recorded.  The impairment recovery resulted from increased proved and probable reserves of natural gas and natural gas liquids, due primarily to the successful application of horizontal drilling and multi-stage fracturing technology to the previously impaired cash generating unit.

Gain on acquisition
During the 2012 period, we recognized a gain on acquisition of $45.3 million and other expense of $8.5 million relating to transfer taxes resulting from our acquisition of certain working interests in the Paris and Aquitaine Basins in France.  The gain on acquisition arose as a result of the increase in the fair value of the acquired petroleum and natural gas reserves from the time when the acquisition was negotiated to the acquisition date.  The increase resulted from a change in the underlying commodity price forecasts used to determine the fair value of the acquired reserves.

TAXES

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

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

Jurisdiction             2013             2012 
Canada             25.0%             25.0%
France             38.0%             36.1%
Netherlands             46.0%             46.0%
Australia             30.0%             30.0%
Ireland             25.0%             25.0%

France tax legislation
In December 2013, the France government enacted corporate tax legislation that will lead to increases in current tax for companies operating in France, including a temporary surtax of 10.7% (with the surtax levied as a percent of base corporate income tax payable). The new surtax rate is applicable for companies which have annual revenue in excess of €250 million and effectively increases the statutory rate applicable to our French operations to 38.0%, with retrospective application to January 1, 2013.  The surtax is only applicable to tax years ending up to December 30, 2015 and as a result our French operations tax rate will decrease to 34.4% for the tax year 2015.

In addition, the legislation adds a new test to the existing rules governing interest deductions for related party financing.  Under the legislation, interest deductions would be allowed only if the French borrower demonstrates that the lender is subject to corporate tax on interest income that equals 25% or more of the corporate tax that would otherwise be due under French tax rules.  This legislation, among other changes, may reduce the effectiveness of our existing international corporate financing structures and could result in a reduction of certain eligible deductions in our French operating companies.

Tax assessments
As at December 31, 2013, Income Taxes Payable includes a provision relating to tax assessments from tax authorities for prior period tax positions.  We have determined the provision based on our best estimate of the amount required to settle the tax assessments and we have classified the provision as a current liability.  The amounts ultimately paid and the timing of settlement could differ from our best estimate and, therefore, could have an impact on future net earnings and cash flows.

Tax pools

As at December 31, 2013, we had the following tax pools:

($M) Oil & Gas Assets     Tax Losses (4) Other Total
Canada 856,023 (1)   385,105 8,110 1,249,238
France 388,549 (2)   12,144 - 400,693
Netherlands 61,868 (3)   - - 61,868
Australia 217,069 (1)   - - 217,069
Ireland   844,761 (4)   272,201 - 1,116,962
Total 2,368,270     669,450  8,110  3,045,830

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

FINANCIAL POSITION REVIEW

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

To ensure that we maintain a conservative balance sheet, we monitor the ratio of net debt to fund flows from operations and typically strive to maintain a ratio of near 1.0.  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.

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

  Annual Interest Rate     As At
  Dec 31, Dec 31,     Dec 31, Dec 31,
($M) 2013  2012      2013  2012 
Revolving credit facility 3.3% 3.3%     766,898  419,784 
Senior unsecured notes 6.5% 6.5%     223,126  222,238 
Long-term debt 4.2% 4.7%     990,024  642,022 

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
  Dec 31, Dec 31,
  2013  2012 
Total facility amount $1.20 billion $0.95 billion
Amount drawn $766.9 million   $419.8 million
Letters of credit outstanding $8.1 million $49.2 million
Facility maturity date 31-May-16 31-May-15

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

    Year Ended
    Dec 31, Dec 31,
Financial covenant Limit 2013 2012
Consolidated total debt to consolidated EBITDA 4.0 1.06  0.83 
Consolidated total senior debt to consolidated EBITDA 3.0 0.82  0.54 

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.

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 amount         $225.0 million
Interest          6.5% per annum
Issued date         February 10, 2011
Maturity date         February 10, 2016

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

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

  As At
  Dec 31, Dec 31,
($M) 2013  2012 
Long-term debt 990,024  642,022 
Current liabilities 347,444  355,711 
Current assets (587,783)  (320,502)
Net debt 749,685  677,231 
     
Ratio of net debt to fund flows from operations 1.1  1.2 

Long-term debt as at December 31, 2013 increased to $990.0 million from $642.0 million as at December 31, 2012 as a result of increased borrowings on the revolving credit facility.  Additional borrowings were used to fund current year development capital expenditures in Ireland and also reflect borrowings in anticipation of the closing of our acquisition in Germany.  In Ireland, development activities related to tunneling, onshore pipelining, offshore umbilical-laying and offshore seismic acquisition activities.

As our acquisition in Germany did not close prior to year-end, borrowings on our revolving credit facility during the fourth quarter of 2013 were largely held as cash and cash equivalents, which increased $287.4 million to $389.6 million as at December 31, 2013.  As a result, the increase to net debt was limited to $72.5 million as compared to the $348.0 million increase in long-term debt.

Overall, we continue to maintain a strong financial position, with a net debt to fund flows from operations of 1.1.

Shareholders' capital
During the year ended December 31, 2013, we maintained monthly dividends at $0.20 per share and declared dividends totalled $242.6 million.  In November of 2013, we announced a 7.5% increase in the monthly dividend to $0.215 per common share per month (effective for the January 2014 dividend and paid on February 17, 2014).  This dividend increase is our second consecutive annual increase.

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

As at December 31, 2013, there were 1.7 million VIP awards outstanding.  As at February 27, 2014, there were 102.3 million shares outstanding.

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:

  Number of Shares ('000s)   Amount ($M)
Balance as at December 31, 2012   99,135    1,481,345 
Issuance of shares 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 

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

As at December 31, 2013, we had the following contractual obligations and commitments:

($M) Less than 1 year  1 - 3 years  3 - 5 years  After 5 years Total
Long-term debt 13,406 1,008,148 - 1,021,554
Operating lease obligations 12,881 19,189 15,565 26,466 74,101
Ship or pay agreement relating to the Corrib project 6,157 10,300 8,354 35,745 60,556
Purchase obligations 25,775 18,456 15 - 44,246
Drilling and service agreements 13,648 16,152 - - 29,800
Total contractual obligations and commitments 71,867 1,072,245 23,934 62,211 1,230,257

ASSET RETIREMENT OBLIGATIONS

As at December 31, 2013, asset retirement obligations were $326.2 million compared to $371.1 million as at December 31, 2012.

The increase in asset retirement obligations is largely attributable to an overall decrease in the inflation rates applied to the abandonment obligations.

RISKS AND UNCERTAINTIES

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

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

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

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

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

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

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

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

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

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

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

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

FINANCIAL RISK MANAGEMENT

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

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

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

CRITICAL ACCOUNTING ESTIMATES

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

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

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

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

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

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

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

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

OFF BALANCE SHEET ARRANGEMENTS

We have certain lease agreements that are entered into in the normal course of operations, all of which are operating leases and accordingly no asset or liability value has been assigned to the consolidated balance sheet as at December 31, 2013.

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, but are not expected to have a material impact on Vermilion's consolidated financial statements:

IFRIC 21 "Levies"
On May 20, 2013, IASB issued guidance on IFRIC 21, which provides guidance 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.

IFRS 9 "Financial Instruments"
The IASB has undertaken a three-phase project to replace IAS 39, "Financial Instruments: Recognition and Measurement". The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. In February of 2014, the IASB confirmed that the mandatory effective date of IFRS 9 shall be January 1, 2018.

HEALTH, SAFETY AND ENVIRONMENT

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

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

In 2013, we remained committed to the principles of the Responsible Canadian Energy™ program set out by the Canadian Association of Petroleum Producers.  Responsible Canadian Energy™ is an association-wide performance reporting program to demonstrate progress in environmental, health, safety, and social performance.

We continued our commitment to reduce impacts to land, water and air, as policies and procedures demonstrating leadership in these areas, were maintained and further developed in 2013.  Examples of our accomplishments during the year included:

  • Receiving a National Ecology award in France for our tomato greenhouse partnership;
  • Clear priorities around 5 key focus areas of HSE Culture, Communication and Knowledge Management, Technical Safety Management, Incident Prevention and Operational Stewardship & Sustainability;
  • Completed a detailed, corporate wide HSE perception survey to ensure organizational engagement, define areas of strength and identify areas to focus on;
  • Reducing long-term environmental liabilities through decommissioning, abandoning and reclaiming well leases and facilities;
  • Continuous auditing and management inspections;
  • Development, communication and measurement against leading and lagging HSE key performance indicators;
  • Further enhancement of our competency and training programs;
  • Managing our waste products by reducing, recycling and recovering; and
  • Continuing risk management efforts in addition to detailed emergency-response planning.

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

CORPORATE GOVERNANCE

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

We comply with the objectives and guidelines relating to corporate governance adopted by the Canadian Securities Administrators and the Toronto Stock Exchange.  In addition, the Board monitors and considers the implementation of corporate governance standards proposed by various regulatory and non-regulatory authorities in Canada.  A discussion of corporate governance policies will be provided in our Management Proxy Circular, which will be filed on SEDAR (www.sedar.com) and mailed to all shareholders on April 8, 2014.

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

DISCLOSURE CONTROLS AND PROCEDURES

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

As of December 31, 2013, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures.  Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded and certified that our disclosure controls and procedures are effective.

INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

Supplemental Table 1: Netbacks

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

  Three Months Ended Dec 31, 2013   Year Ended Dec 31, 2013     Three Months
Ended Dec 31, 2012
  Year Ended
Dec 31, 2012
  Oil & NGLs Natural Gas Total   Oil & NGLs Natural Gas Total     Total   Total
  $/bbl $/mcf $/boe   $/bbl $/mcf $/boe     $/boe   $/boe
Canada                        
Sales 86.87  3.70  61.10    89.78  3.40  61.14      58.80    54.89 
Royalties (10.67) (0.21) (6.93)   (10.42) (0.17) (6.55)     (5.62)   (5.71)
Transportation (3.57) (0.18) (2.57)   (2.64) (0.17) (1.96)     (1.46)   (1.50)
Operating (10.50) (0.83) (8.29)   (9.24) (1.42) (8.93)     (11.01)   (10.00)
Operating netback 62.13  2.48  43.31    67.48  1.64  43.70      40.71    37.68 
General and administration     (1.60)       (2.24)     (1.34)   (2.23)
Fund flows from operations netback     41.71        41.46      39.37    35.45 
France                        
Sales 112.84  112.84    108.55  10.20  106.26      102.26    105.13 
Royalties (6.70) (6.70)   (6.57) (0.29) (6.34)     (5.29)   (5.53)
Transportation (4.71) (4.71)   (3.08) (2.93)     (2.16)   (2.23)
Operating (15.82) (15.82)   (16.04) (1.52) (15.70)     (15.97)   (14.86)
Operating netback 85.61  85.61    82.86  8.39  81.29      78.84    82.51 
General and administration     (5.18)       (4.61)     (5.57)   (4.06)
Current income taxes     (28.55)       (22.16)     (15.55)   (17.05)
Fund flows from operations netback     51.88        54.52      57.72    61.40 
Netherlands                        
Sales 111.00  11.24  67.88    100.49  10.61  64.08      60.96    58.69 
Operating (1.79) (10.63)   (1.59) (9.47)     (11.14)   (9.10)
Operating netback 111.00  9.45  57.25    100.49  9.02  54.61      49.82    49.59 
General and administration     (2.67)       (1.25)     (1.22)   (0.63)
Current income taxes     (14.22)       (15.67)     (2.15)   (12.18)
Fund flows from operations netback     40.36        37.69      46.45    36.78 
Australia                        
Sales 124.63  124.63    119.38  119.38      115.22    117.03 
Operating (21.25) (21.25)   (20.62) (20.62)     (24.97)   (21.47)
PRRT (1) (27.60) (27.60)   (22.59) (22.59)     (4.11)   (26.33)
Operating netback 75.78  75.78    76.17  76.17      86.14    69.23 
General and administration     (2.32)       (2.30)     (1.59)   (1.63)
Corporate income taxes     (9.98)       (12.67)     (17.42)   (13.86)
Fund flows from operations netback     63.48        61.20      67.13    53.74 
Total Company                        
Sales 106.00  7.29  86.04    104.46  6.83  83.83      78.40    79.51 
Realized hedging loss     (0.34)       (0.47)     (0.51)   (0.93)
Royalties (6.55) (0.11) (4.66)   (6.33) (0.10) (4.47)     (3.88)   (3.82)
Transportation (3.13) (0.14) (2.40)   (2.16) (0.23) (1.90)     (1.77)   (1.77)
Operating (15.11) (1.28) (12.74)   (14.69) (1.50) (12.84)     (14.18)   (13.10)
PRRT (1) (6.69) (4.55)   (5.52) (3.72)     (0.52)   (4.41)
Operating netback 74.52  5.76  61.35    75.76  5.00  60.43      57.54    55.48 
General and administration     (3.69)       (3.28)     (2.89)   (3.21)
Interest expense     (2.66)       (2.51)     (2.49)   (2.03)
Realized foreign exchange (loss) gain     (0.34)       (0.12)     0.81    0.21 
Other income (expense) 0.06        0.07      0.08    (0.55)
Corporate income taxes (1)     (11.40)       (10.65)     (6.98)   (8.94)
Fund flows from operations netback     43.32        43.94      46.07    40.96 

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

Supplemental Table 2: Hedges

The following table summarizes Vermilion's outstanding risk management positions as at December 31, 2013:

  Note       Daily Volume       Strike Price(s)
Crude Oil                  
WTI - Collar                  
January 2014 - March 2014         1,000 bbl/d       97.50 - 104.69 USD $
WTI - Swap                  
January 2014 - March 2014         500 bbl/d       101.22 USD $
January 2014 - March 2014 (1)        250 bbl/d       105.45 USD $
January 2014 - June 2014         250 bbl/d       100.05 USD $
January 2014 - June 2014 (2)        1,000 bbl/d       100.07 USD $
Dated Brent - Collar                  
January 2014 - March 2014         2,500 bbl/d       104.00 - 110.46 USD $
January 2014 - June 2014         1,250 bbl/d       103.20 - 110.24 USD $
April 2014 - June 2014         1,000 bbl/d       105.00 - 115.00 USD $
April 2014 - September 2014         1,000 bbl/d       105.00 - 112.00 USD $
April 2014 - December 2014         1,000 bbl/d       106.00 - 110.73 USD $
Dated Brent - Swap                  
January 2014 - March 2014         2,000 bbl/d       107.80 USD $
January 2014 - June 2014         1,000 bbl/d       107.25 USD $
January 2014 - June 2014 (2)        1,500 bbl/d       110.32 USD $
April 2014 - June 2014         1,250 bbl/d       109.74 USD $
January 2014 - December 2014         500 bbl/d       108.28 USD $
MSW - Fixed Price Sale (Physical)                  
January 2014 - March 2014         1,000 bbl/d       93.37 CAD $
April 2014 - June 2014         1,000 bbl/d       92.85 CAD $
Canadian Natural Gas                  
AECO - Collar                  
January 2014 - December 2014         10,000 GJ/d       3.18 - 3.81 CAD $
AECO - Swap                  
January 2014 - December 2014         5,000 GJ/d       3.71 CAD $
AECO - Collar (Physical) (3)                 
April 2012 - March 2014         5,500 GJ/d       2.60 - 3.78 CAD $
June 2012 - March 2014         3,000 GJ/d       2.30 - 3.75 CAD $
European Natural Gas                  
TTF - Swap                  
January 2014 - March 2014         16,200 GJ/d       7.88 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 $

(1) Prior to the expiration of this swap, the counterparty has the option to extend the swap to June 30, 2014 at the contracted volume and price.
(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) Physical AECO collars have a funded cost of $0.10/GJ.

Supplemental Table 3: Capital expenditures

  Three Months Ended     Year Ended
By classification Dec 31, Sept 30, Dec 31,     Dec 31, Dec 31,
($M) 2013 2013 2012     2013  2012 
Drilling and development 147,929  135,110  151,157      537,564  413,221 
Dispositions     (8,627)
Exploration and evaluation 549  551  5,878      13,789  39,317 
Capital expenditures 148,478 <