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

March 3, 2014

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

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