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

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Mar 03, 2014, 02:10 ET

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	3	(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	-	-	-			5	-
	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 reservesand 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	135,661	157,035	542,726	452,538
Property acquisition	1,603	7,586	-	9,189	106,184
Corporate acquisition	27,500	-	74,947	27,500	74,947
Payment of amount due pursuant to acquisition	-	-	134,307	-	134,307
Acquisitions	29,103	7,586	209,254	36,689	315,438

	Three Months Ended			Year Ended
By category	Dec 31,	Sept 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2013	2013	2012	2013	2012
Land	2,676	(4,450)	462	3,662	46,508
Seismic	1,942	5,284	3,963	16,608	8,742
Drilling and completion	68,993	63,590	76,774	279,003	215,261
Production equipment and facilities	63,420	47,665	64,232	201,846	150,396
Recompletions	3,309	15,650	5,040	27,600	12,044
Other	8,138	7,922	6,564	22,634	19,587
Dispositions	-	-	-	(8,627)	-
Capital expenditures	148,478	135,661	157,035	542,726	452,538
Acquisitions	29,103	7,586	209,254	36,689	315,438
Total capital expenditures and acquisitions	177,581	143,247	366,289	579,415	767,976

	Three Months Ended			Year Ended
By country	Dec 31,	Sept 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2013	2013	2012	2013	2012
Canada	78,848	69,856	82,844	250,386	271,843
France	31,899	23,664	95,905	100,378	228,444
Netherlands	43,198	8,316	8,118	56,043	21,324
Australia	8,420	5,880	25,257	77,931	49,389
Ireland	14,472	35,028	152,400	90,898	193,071
Corporate	744	503	1,765	3,779	3,905
Total capital expenditures and acquisitions	177,581	143,247	366,289	579,415	767,976

Supplemental Table 4: Production

		Q4/13	Q3/13	Q2/13	Q1/13	Q4/12	Q3/12	Q2/12	Q1/12	Q4/11	Q3/11	Q2/11	Q1/11
Canada
	Crude oil (bbls/d)	8,719	7,969	8,885	7,966	7,983	7,322	7,757	7,574	6,591	4,526	3,856	3,801
	NGLs (bbls/d)	1,699	1,897	1,725	1,335	1,106	1,204	1,321	1,302	1,246	1,305	1,353	1,285
	Natural gas (mmcf/d)	41.43	43.40	43.69	41.04	31.41	35.54	41.32	41.83	43.96	42.94	43.30	43.31
	Total (boe/d)	17,322	17,099	17,892	16,140	14,323	14,449	15,965	15,848	15,163	12,987	12,426	12,304
	% of consolidated	43%	41%	42%	41%	40%	40%	40%	40%	41%	38%	35%	36%
France
	Crude oil (bbls/d)	11,131	11,625	10,390	10,330	9,843	9,767	9,931	10,270	7,819	7,946	8,273	8,411
	Natural gas (mmcf/d)	-	5.23	4.19	4.21	3.91	3.39	3.57	3.48	0.94	0.97	0.88	1.02
	Total (boe/d)	11,131	12,496	11,088	11,032	10,495	10,333	10,526	10,850	7,976	8,108	8,419	8,582
	% of consolidated	27%	30%	26%	29%	29%	28%	27%	28%	22%	23%	24%	25%
Netherlands
	NGLs (bbls/d)	62	48	50	96	70	41	84	72	66	64	54	46
	Natural gas (mmcf/d)	37.53	28.78	38.52	36.91	33.03	34.59	33.74	35.08	34.58	33.15	33.77	29.96
	Total (boe/d)	6,318	4,845	6,470	6,248	5,574	5,806	5,707	5,919	5,829	5,589	5,682	5,039
	% of consolidated	15%	12%	15%	16%	15%	16%	15%	15%	16%	16%	16%	15%
Australia
	Crude oil (bbls/d)	6,189	7,070	7,363	5,287	5,873	5,958	6,970	6,648	7,686	7,992	8,692	8,309
	% of consolidated	15%	17%	17%	14%	16%	16%	18%	17%	21%	23%	25%	24%
Consolidated
	Crude oil & NGLs (bbls/d)	27,800	28,609	28,413	25,014	24,875	24,292	26,063	25,866	23,408	21,833	22,228	21,852
	% of consolidated	68%	69%	66%	65%	69%	66%	67%	66%	64%	63%	63%	64%
	Natural gas (mmcf/d)	78.96	77.41	86.40	82.16	68.34	73.52	78.63	80.39	79.48	77.06	77.95	74.29
	% of consolidated	32%	31%	34%	35%	31%	34%	33%	34%	36%	37%	37%	36%
	Total (boe/d)	40,960	41,510	42,813	38,707	36,265	36,546	39,168	39,265	36,654	34,676	35,219	34,234

		2013	2012	2011	2010	2009	2008
Canada
	Crude oil (bbls/d)	8,387	7,659	4,701	2,778	2,137	2,620
	NGLs (bbls/d)	1,666	1,232	1,297	1,427	1,518	1,551
	Natural gas (mmcf/d)	42.39	37.50	43.38	43.91	47.85	51.15
	Total (boe/d)	17,117	15,142	13,227	11,524	11,629	12,696
	% of consolidated	41%	40%	38%	36%	37%	38%
France
	Crude oil (bbls/d)	10,873	9,952	8,110	8,347	8,246	8,514
	Natural gas (mmcf/d)	3.40	3.59	0.95	0.92	1.05	1.17
	Total (boe/d)	11,440	10,550	8,269	8,501	8,421	8,710
	% of consolidated	28%	28%	23%	26%	27%	27%
Netherlands
	NGLs (bbls/d)	64	67	58	35	23	24
	Natural gas (mmcf/d)	35.42	34.11	32.88	28.31	21.06	27.23
	Total (boe/d)	5,967	5,751	5,538	4,753	3,533	4,562
	% of consolidated	15%	15%	16%	15%	11%	14%
Australia
	Crude oil (bbls/d)	6,481	6,360	8,168	7,354	7,812	6,773
	% of consolidated	16%	17%	23%	23%	25%	21%
Consolidated
	Crude oil & NGLs (bbls/d)	27,471	25,270	22,334	19,941	19,735	19,483
	% of consolidated	67%	67%	63%	62%	63%	60%
	Natural gas (mmcf/d)	81.21	75.20	77.21	73.14	69.96	79.55
	% of consolidated	33%	33%	37%	38%	37%	40%
	Total (boe/d)	41,005	37,803	35,202	32,132	31,395	32,741

Supplemental Table 5: Segmented Financial Results

	Three Months Ended December 31, 2013
($M)	Canada	France	Netherlands	Australia	Ireland	Corporate	Total
Oil and gas sales to external customers	97,367	110,757	39,451	77,533	-	-	325,108
Royalties	(11,039)	(6,577)	-	-	-	-	(17,616)
Revenue from external customers	86,328	104,180	39,451	77,533	-	-	307,492
Transportation expense	(4,102)	(4,622)	-	-	(357)	-	(9,081)
Operating expense	(13,218)	(15,524)	(6,179)	(13,219)	-	-	(48,140)
General and administration	(2,478)	(5,080)	(1,553)	(1,442)	(482)	(2,919)	(13,954)
Corporate income taxes	-	(28,024)	(8,267)	(6,210)	-	(564)	(43,065)
PRRT	-	-	-	(17,173)	-	-	(17,173)
Interest expense	-	-	-	-	-	(10,049)	(10,049)
Realized loss on derivative instruments	-	-	-	-	-	(1,300)	(1,300)
Realized foreign exchange loss	-	-	-	-	-	(1,294)	(1,294)
Realized other income	-	-	-	-	-	224	224
Fund flows from operations	66,530	50,930	23,452	39,489	(839)	(15,902)	163,660

	Year Ended December 31, 2013
($M)	Canada	France	Netherlands	Australia	Ireland	Corporate	Total
Total assets	1,212,056	901,582	228,869	322,773	747,882	295,557	3,708,719
Drilling and development	232,858	96,479	28,543	77,931	90,898	2,228	528,937
Exploration and evaluation	8,339	3,899	-	-	-	1,551	13,789
Oil and gas sales to external customers	382,005	453,315	139,570	298,945	-	-	1,273,835
Royalties	(40,891)	(27,045)	-	-	-	-	(67,936)
Revenue from external customers	341,114	426,270	139,570	298,945	-	-	1,205,899
Transportation expense	(12,254)	(12,505)	-	-	(4,165)	-	(28,924)
Operating expense	(55,804)	(66,997)	(20,617)	(51,625)	-	-	(195,043)
General and administration	(12,979)	(19,657)	(2,724)	(5,752)	(1,442)	(7,356)	(49,910)
Corporate income taxes	-	(94,524)	(34,132)	(31,735)	-	(1,403)	(161,794)
PRRT	-	-	-	(56,565)	-	-	(56,565)
Interest expense	-	-	-	-	-	(38,183)	(38,183)
Realized loss on derivative instruments	-	-	-	-	-	(7,082)	(7,082)
Realized foreign exchange loss	-	-	-	-	-	(1,866)	(1,866)
Realized other income	-	-	-	-	-	994	994
Fund flows from operations	260,077	232,587	82,097	153,268	(5,607)	(54,896)	667,526

ADDITIONAL AND NON-GAAP FINANCIAL MEASURES

Fund flows from operations: We define fund flows from operations as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a measure of our ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. As we have presented fund flows from operations in the "Segmented Information" note of our audited consolidated financial statements for the year ended December 31, 2013, we consider fund flows from operations to be an additional GAAP financial measure.

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

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

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

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

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

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

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

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

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

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

	Three Months Ended			Year Ended
	Dec 31,	Sept 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2013	2013	2012	2013	2012
Cash flows from operating activities	177,003	158,236	99,907	705,025	496,580
Changes in non-cash operating working capital	(18,769)	4,671	33,406	(49,421)	47,409
Asset retirement obligations settled	5,426	2,738	8,424	11,922	13,739
Fund flows from operations	163,660	165,645	141,737	667,526	557,728
Expenses related to Corrib	839	876	2,023	5,607	8,902
Fund flows from operations (excluding Corrib)	164,499	166,521	143,760	673,133	566,630


	Three Months Ended			Year Ended
	Dec 31,	Sept 30,	Dec 31,	Dec 31,	Dec 31,
($M)	2013	2013	2012	2013	2012
Dividends declared	61,208	61,003	56,435	242,599	223,717
Issuance of shares pursuant to the dividend reinvestment plan	(18,775)	(19,354)	(18,468)	(72,291)	(72,058)
Net dividends	42,433	41,649	37,967	170,308	151,659
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
Asset retirement obligations settled	5,426	2,738	8,424	11,922	13,739
Payout	196,337	180,048	203,426	724,956	617,936
Payout relating to Corrib	(14,472)	(35,028)	(18,092)	(90,898)	(58,666)
Payout (excluding Corrib)	181,865	145,020	185,334	634,058	559,270

	As At
	Dec 31,	Sept 30,	Dec 31,
('000s of shares)	2013	2013	2012
Shares outstanding	102,123	101,787	99,135
Potential shares issuable pursuant to the VIP	2,746	2,408	2,778
Diluted shares outstanding	104,869	104,195	101,913

MANAGEMENT'S REPORT TO SHAREHOLDERS

Management's Responsibility for Financial Statements

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

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

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

Management's Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the criteria established in "Internal Control - Integrated Framework (1992)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has assessed the effectiveness of Vermilion's internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Management concluded that Vermilion's internal control over financial reporting was effective as of December 31, 2013. The effectiveness of Vermilion's internal control over financial reporting as of December 31, 2013 has been audited by Deloitte LLP, the Company's Independent Registered Public Accounting Firm, who also audited the Company's consolidated financial statements for the year ended December 31, 2013.

("Lorenzo Donadeo")				("Curtis W. Hicks")

Lorenzo Donadeo				Curtis W. Hicks
Chief Executive Officer				Chief Financial Officer
February 27, 2014

Report of Independent Registered Public Accounting Firm

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

We have audited the internal control over financial reporting of Vermilion Energy Inc. and subsidiaries (the "Company") as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as at and for the year ended December 31, 2013 of the Company and our report dated February 27, 2014 expressed an unqualified opinion on those financial statements.

("Deloitte LLP")
Chartered Accountants

February 27, 2014
Calgary, Canada

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying consolidated financial statements of Vermilion Energy Inc. and subsidiaries (the "Company"), which comprise the consolidated balance sheets as at December 31, 2013 and 2012, and the consolidated statements of net earnings and comprehensive income, consolidated statements of changes in shareholders' equity and consolidated statements of cash flows for the years then ended, and notes to the consolidated financial statements.

Management's Responsibility for the Consolidated Financial Statements

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

Auditor's Responsibility

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

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

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

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Vermilion Energy Inc. and subsidiaries as at December 31, 2013 and 2012, and their financial performance and their cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matter

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2014 expressed an unqualified opinion on the Company's internal control over financial reporting.

("Deloitte LLP")
Chartered Accountants

February 27, 2014
Calgary, Canada

CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS)

		December 31,		December 31,
	Note		2013		2012
ASSETS
Current
Cash and cash equivalents	17		389,559		102,125
Accounts receivable			167,618		180,064
Crude oil inventory			17,143		25,719
Derivative instruments	13		2,285		2,086
Prepaid expenses			11,178		10,508
			587,783		320,502

Deferred taxes	9		184,832		193,354
Exploration and evaluation assets	6		136,259		117,161
Capital assets	5		2,799,845		2,445,240
			3,708,719		3,076,257

LIABILITIES
Current
Accounts payable and accrued liabilities			267,832		300,682
Dividends payable	10		20,425		18,836
Derivative instruments	13		3,572		8,484
Income taxes payable	9		55,615		27,709
			347,444		355,711

Long-term debt	8		990,024		642,022
Asset retirement obligations	7		326,162		371,063
Deferred taxes	9		328,714		288,815
			1,992,344		1,657,611

SHAREHOLDERS' EQUITY
Shareholders' capital	10		1,618,443		1,481,345
Contributed surplus			75,427		69,581
Accumulated other comprehensive income (loss)			47,142		(32,409)
Deficit			(24,637)		(99,871)
			1,716,375		1,418,646
			3,708,719		3,076,257

APPROVED BY THE BOARD

(Signed "Kenneth Davidson")						(Signed "Lorenzo Donadeo")
W. Kenneth Davidson, Director						Lorenzo Donadeo, Director

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

		Year Ended
		December 31,	December 31,
	Note	2013	2012
REVENUE
Petroleum and natural gas sales		1,273,835	1,083,103
Royalties		(67,936)	(52,084)
Petroleum and natural gas revenue		1,205,899	1,031,019

EXPENSES
Operating	21	195,043	178,442
Transportation		28,924	24,113
Equity based compensation	11	60,845	47,104
Loss on derivative instruments	13	1,971	6,986
Interest expense		38,183	27,586
General and administration	21	49,910	43,773
Foreign exchange (gain) loss		(50,162)	1,546
Other expense	4	457	8,751
Accretion	7	24,565	23,040
Depletion and depreciation	5, 6	322,386	295,943
Impairment (recovery)	5	(47,400)	65,800
Gain on acquisition	4	-	(45,309)
		624,722	677,775
EARNINGS BEFORE INCOME TAXES		581,177	353,244

INCOME TAXES	9
Deferred		35,177	(19,291)
Current		218,359	181,913
		253,536	162,622

NET EARNINGS		327,641	190,622

OTHER COMPREHENSIVE INCOME
Currency translation adjustments		79,551	978
COMPREHENSIVE INCOME		407,192	191,600

NET EARNINGS PER SHARE	12
Basic		3.24	1.94
Diluted		3.20	1.92

WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)	12
Basic		100,969	98,016
Diluted		102,467	99,294

CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS)

			Year Ended
			December 31,	December 31,
		Note	2013	2012
OPERATING
Net earnings			327,641	190,622
Adjustments:
	Accretion	7	24,565	23,040
	Depletion and depreciation	5, 6	322,386	295,943
	Impairment (recovery)	5	(47,400)	65,800
	Gain on acquisition	4	-	(45,309)
	Unrealized gain on derivative instruments	13	(5,111)	(5,751)
	Equity based compensation	11	60,845	47,104
	Unrealized foreign exchange (gain) loss		(52,028)	4,350
	Unrealized other expense		1,451	1,220
	Deferred taxes	9	35,177	(19,291)
Asset retirement obligations settled		7	(11,922)	(13,739)
Changes in non-cash operating working capital		14	49,421	(47,409)
Cash flows from operating activities			705,025	496,580

INVESTING
Drilling and development		5	(537,564)	(413,221)
Exploration and evaluation		6	(13,789)	(39,317)
Property acquisitions		4, 6	(9,189)	(106,184)
Dispositions		5	8,627	-
Corporate acquisitions, net of cash acquired		4	(24,124)	(63,482)
Payment of amount due pursuant to acquisition			-	(134,307)
Changes in non-cash investing working capital		14	(41,691)	16,588
Cash flows used in investing activities			(617,730)	(739,923)

FINANCING
Increase in long-term debt		8	347,284	265,395
Issuance of shares pursuant to the dividend reinvestment plan		10	-	36,339
Cash dividends		10	(168,719)	(187,484)
Cash flows from financing activities			178,565	114,250
Foreign exchange gain (loss) on cash held in foreign currencies			21,574	(3,289)

Net change in cash and cash equivalents			287,434	(132,382)
Cash and cash equivalents, beginning of year			102,125	234,507
Cash and cash equivalents, end of year		17	389,559	102,125

Supplementary information for operating activities - cash payments
	Interest paid		37,562	30,792
	Income taxes paid		192,865	190,611

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

						Accumulated
							Other			Total
		Shareholders'		Contributed		Comprehensive				Shareholders'
	Note	Capital		Surplus			Loss	Deficit		Equity
Balances as at January 1, 2012			1,368,145		56,468		(33,387)		(59,625)		1,331,601
Net earnings			-		-		-		190,622		190,622
Currency translation adjustments			-		-		978		-		978
Equity based compensation expense	11		-		46,468		-		-		46,468
Dividends declared	10		-		-		-		(223,717)		(223,717)
Issuance of shares pursuant to the dividend reinvestment plan	10		72,058		-		-		-		72,058
Vesting of equity based awards	10, 11		33,355		(33,355)		-		-		-
Share-settled dividends on vested equity based awards	10, 11		7,151		-		-		(7,151)		-
Shares issued pursuant to the bonus plan	10		636		-		-		-		636
Balances as at December 31, 2012			1,481,345		69,581		(32,409)		(99,871)		1,418,646

						Accumulated
							Other			Total
		Shareholders'		Contributed		Comprehensive				Shareholders'
	Note	Capital		Surplus			Income	Deficit		Equity
Balances as at January 1, 2013			1,481,345		69,581		(32,409)		(99,871)		1,418,646
Net earnings			-		-		-		327,641		327,641
Currency translation adjustments			-		-		79,551		-		79,551
Equity based compensation expense	11		-		60,216		-		-		60,216
Dividends declared	10		-		-		-		(242,599)		(242,599)
Issuance of shares pursuant to the dividend reinvestment plan	10		72,291		-		-		-		72,291
Vesting of equity based awards	10, 11		54,370		(54,370)		-		-		-
Share-settled dividends on vested equity based awards	10, 11		9,808		-		-		(9,808)		-
Shares issued pursuant to the bonus plan	10		629		-		-		-		629
Balances as at December 31, 2013			1,618,443		75,427		47,142		(24,637)		1,716,375

DESCRIPTION OF EQUITY RESERVES

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

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

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

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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2013 AND 2012
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS)

1. BASIS OF PRESENTATION

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

These consolidated financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on February 27, 2014.

2. SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

3. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

On January 1, 2013, Vermilion adopted the following pronouncements as issued by the IASB. The adoption of these standards did not have a material impact on Vermilion's consolidated financial statements.

IFRS 10 "Consolidated Financial Statements"
IFRS 10 replaced Standing Interpretations Committee 12, "Consolidation - Special Purpose Entities" and the consolidation requirements of IAS 27 "Consolidated and Separate Financial Statements". The new standard replaces the existing risk and rewards based approaches and establishes control as the determining factor when determining whether an interest in another entity should be included in the consolidated financial statements.

IFRS 11 "Joint Arrangements"
IFRS 11 replaced IAS 31 "Interests in Joint Ventures". The new standard focuses on the rights and obligations of an arrangement, rather than its legal form. The standard redefines joint operations and joint ventures and requires joint operations to be proportionately consolidated and joint ventures to be equity accounted.

IFRS 12 "Disclosure of Interests in Other Entities"
IFRS 12 provides comprehensive disclosure requirements for interests in other entities, including joint arrangements, associates, and special purpose entities. The new disclosures are intended to assist financial statement users in evaluating the nature, risks and financial effects of an entity's interest in subsidiaries and joint arrangements.

IFRS 13 "Fair Value Measurement"
IFRS 13 provides a common definition of fair value within IFRS. The new standard provides measurement and disclosure guidance and applies when another IFRS requires or permits an item to be measured at fair value, with limited exceptions.

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:

4. BUSINESS COMBINATIONS

Property acquisition:

France

On January 19, 2012, Vermilion acquired, through its wholly owned subsidiaries, working interests in six producing fields located in the Paris and Aquitaine Basins in France, for total consideration of $106.1 million before closing adjustments. The acquired working interests expanded Vermilion's existing interests and was a natural addition to the Company's existing France asset base.

The acquired assets include land, wells, facilities, and inventory located in the Company's core producing basins in France. The fair value of the acquired identifiable assets and liabilities assumed at the date of acquisition was $151.4 million. A gain of $45.3 million was recognized as a result of an 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.

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

($M)	Consideration
Cash paid to vendor		106,115
Total consideration		106,115

($M)	Allocation of Consideration
Petroleum and natural gas assets		206,191
Asset retirement obligations assumed		(27,518)
Deferred tax liabilities		(23,151)
Acquired non-cash working capital deficiencies		(4,098)
Net assets acquired		151,424
Gain on acquisition		(45,309)
Net assets acquired, net of gain on acquisition		106,115

Transfer taxes associated with this acquisition totalling $8.5 million have been excluded from the consideration and have been recognized as an expense in the year ended December 31, 2012 within "Other expense" in the consolidated statements of net earnings and comprehensive income.

Corporate acquisitions:

a) Netherlands

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

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

($M)	Consideration
Cash paid to vendor		27,500
Total consideration		27,500

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

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

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

b) France

On December 21, 2012, Vermilion acquired, through its wholly owned subsidiaries, 100% of the shares of ZaZa Energy France S.A.S for total consideration of $74.9 million. The acquired company holds operating interests covering approximately 24,300 acres with 100% working interests in the Saint Firmin, Chateaurenard, Courtenay, Chuelles, and Charmottes fields in the Paris Basin. The acquired company expands Vermilion's existing operations in France and is aligned with Vermilion's objective to consolidate assets within the Company's core operating areas.

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

($M)	Consideration
Cash paid to vendor		74,947
Total consideration		74,947

($M)	Allocation of Consideration
Petroleum and natural gas assets		136,297
Asset retirement obligations assumed		(22,623)
Deferred tax liabilities		(40,046)
Cash acquired		11,465
Acquired non-cash working capital		(10,146)
Net assets acquired		74,947

5. CAPITAL ASSETS

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

	Petroleum and		Furniture and		Total
($M)	Natural Gas Assets		Office Equipment		Capital Assets
Balance at January 1, 2012		2,016,611		15,071	2,031,682
Additions		407,973		5,248	413,221
Transfers from exploration and evaluation assets		10,528		-	10,528
Property acquisitions		206,260		-	206,260
Corporate acquisitions		136,297		-	136,297
Borrowing costs capitalized		9,994		-	9,994
Changes in estimate for asset retirement obligations		1,334		-	1,334
Depletion and depreciation		(289,194)		(5,165)	(294,359)
Impairments		(65,800)		-	(65,800)
Effect of movements in foreign exchange rates		(3,882)		(35)	(3,917)
Balance at December 31, 2012		2,430,121		15,119	2,445,240
Additions		531,760		5,804	537,564
Transfers from exploration and evaluation assets		1,508		-	1,508
Corporate acquisitions		47,743		-	47,743
Dispositions		(8,627)		-	(8,627)
Changes in estimate for asset retirement obligations		(91,527)		-	(91,527)
Depletion and depreciation		(310,370)		(6,138)	(316,508)
Impairment recovery		47,400		-	47,400
Effect of movements in foreign exchange rates		136,626		426	137,052
Balance at December 31, 2013		2,784,634		15,211	2,799,845

Cost		3,260,772		35,268	3,296,040
Accumulated depletion and depreciation		(830,651)		(20,149)	(850,800)
Carrying amount at December 31, 2012		2,430,121		15,119	2,445,240

Cost		3,938,986		43,932	3,982,918
Accumulated depletion and depreciation		(1,154,352)		(28,721)	(1,183,073)
Carrying amount at December 31, 2013		2,784,634		15,211	2,799,845

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

Capitalized overhead
During the year ended December 31, 2013, Vermilion capitalized $8.5 million (2012 - $4.8 million) of overhead costs directly attributable to PNG activities.

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

During the years ended December 31, 2013 and 2012, Vermilion performed assessments as to whether any cash generating units ("CGU") had indicators of impairment or recovery of previous impairment. In the fourth quarter of 2013, Vermilion identified indicators of impairment recovery for a Canadian CGU where impairment charges were previously recorded for the three months ended December 31, 2011 and March 31, 2012. The impairment recovery resulted from increased proved and probable reserves of natural gas and natural gas liquids, due primarily to the successful application of horizontal drilling and multi-stage fracturing technology to the previously impaired cash generating unit.

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

$/BOE	December 31, 2013	March 31, 2012	December 31, 2011
2014	42.09	35.78	37.12
2015	44.18	38.23	39.52
2016	45.39	40.68	41.95
2017	45.41	43.13	44.34
2018	45.43	45.61	45.82
2019	45.50	46.53	46.79
2020	45.86	47.51	47.72
2021	46.78	48.44	48.71
Average increase thereafter	2.0%	2.0%	2.0%

6. EXPLORATION AND EVALUATION ASSETS

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

($M)	Exploration and Evaluation Assets
Balance at January 1, 2012		92,301
Additions		39,317
Transfers to petroleum and natural gas assets		(10,528)
Depreciation		(3,485)
Effect of movements in foreign exchange rates		(444)
Balance at December 31, 2012		117,161
Additions		13,789
Property acquisitions		9,189
Transfers to petroleum and natural gas assets		(1,508)
Depreciation		(3,712)
Effect of movements in foreign exchange rates		1,340
Balance at December 31, 2013		136,259

Cost		125,165
Accumulated depreciation		(8,004)
Carrying amount at December 31, 2012		117,161

Cost		149,175
Accumulated depreciation		(12,916)
Carrying amount at December 31, 2013		136,259

7. ASSET RETIREMENT OBLIGATIONS

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

($M)	Asset Retirement Obligations
Balance at January 1, 2012		310,531
Additional obligations recognized		55,228
Changes in estimates for existing obligations		(26,560)
Obligations settled		(13,739)
Accretion		23,040
Changes in discount rates		22,807
Effect of movements in foreign exchange rates		(244)
Balance at December 31, 2012		371,063
Additional obligations recognized		15,655
Changes in estimates for existing obligations		(21,068)
Obligations settled		(11,922)
Accretion		24,565
Changes in discount rates		(73,675)
Effect of movements in foreign exchange rates		21,544
Balance at December 31, 2013		326,162

Vermilion has estimated the net present value of its asset retirement obligations to be $326.2 million as at December 31, 2013 (2012 - $371.1 million) based on a total undiscounted future liability, after inflation adjustment, of $1.3 billion (2012 - $1.3 billion). These payments are expected to be made between 2014 and 2063. Vermilion calculated the present value of the obligations using discount rates between 6.4% and 8.3% (2012 - between 5.8% and 7.5%) to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. Inflation rates used in determining the cash flow estimates were between 1.1% and 2.5% (2012 - between 1.4% and 2.5%).

Vermilion reviews annually its estimates of the expected costs to reclaim the net interest in its wells and facilities. The resulting changes are categorized as changes in estimates for existing obligations in the preceding table. The significant changes in the liability for the year ended December 31, 2013 primarily resulted from an overall decrease in the inflation rates applied to the abandonment obligations.

8. LONG-TERM DEBT

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

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

Revolving Credit Facility

At December 31, 2013, Vermilion had in place a bank revolving credit facility totalling $1.2 billion, of which approximately $766.9 million was drawn. The facility, which matures on May 31, 2016, is fully revolving up to the date of maturity.

The facility is extendable from time to time, but not more than once per year, for a period not longer than three years, at the option of the lenders and upon notice from Vermilion. If no extension is granted by the lenders, the amounts owing pursuant to the facility are repayable on the maturity date. This facility bears interest at a rate applicable to demand loans plus applicable margins. For the year ended December 31, 2013, the interest rate on the revolving credit facility was approximately 3.3% (2012 - 3.3%).

The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $8.1 million as at December 31, 2013 (2012 - $49.2 million).

The facility is secured by various fixed and floating charges against the subsidiaries of Vermilion. Under the terms of the facility, Vermilion must maintain a ratio of total bank borrowings (defined as consolidated total debt), to consolidated net earnings before interest, income taxes, depreciation, accretion and other certain non-cash items (defined as consolidated EBITDA) of not greater than 4.0. In addition, Vermilion must maintain a ratio of consolidated total senior debt (defined as consolidated total debt excluding unsecured and subordinated debt) to consolidated EBITDA of not greater than 3.0.

As at December 31, 2013, Vermilion was in compliance with its financial covenants.

Senior Unsecured Notes

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

Vermilion may, at its option, prior to February 10, 2014, redeem up to 35% of the notes with net proceeds of equity offerings by the Company at a redemption price equal to 106.5% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, to the applicable redemption date. Subsequently, Vermilion may, on or after February 10, 2014, 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%.

9. INCOME TAXES

Deferred taxes

The net deferred income tax liability at December 31, 2013 and 2012 is comprised of the following:

		Year Ended
($M)		Dec 31, 2013		Dec 31, 2012
Deferred income tax liabilities:
	Capital assets		(332,740)		(322,620)
	Asset retirement obligations		(87,888)		(45,362)
	Basis difference of investments		(189)		(330)
	Unrealized foreign exchange		(13,017)		(22,603)
	Other		(12,383)		(11,502)
Deferred income tax assets:
	Derivative contracts		323		1,600
	Capital assets		75,352		67,310
	Non-capital losses		170,625		167,230
	Asset retirement obligations		54,037		69,359
	Other		1,998		1,457
Net deferred income tax liability			(143,882)		(95,461)
Comprised of:
	Deferred income tax assets		184,832		193,354
	Deferred income tax liability		(328,714)		(288,815)
Net deferred income tax liability			(143,882)		(95,461)

Income tax expense differs from the amount that would have been expected if the reported earnings had been subject only to the statutory Canadian income tax rate of 25.0% (2012 - 25.0%), as follows:

		Year Ended
($M)		Dec 31, 2013		Dec 31, 2012
Earnings before income taxes			581,177		353,244
Canadian corporate tax rate			25.0%		25.0%
Expected tax expense			145,294		88,311
Increase (decrease) in taxes resulting from:
	Petroleum resource rent tax rate (PRRT) differential ⁽¹⁾		50,585		44,605
	Foreign tax rate differentials^{(1) (2)}		1,875		18,539
	Equity based compensation expense		15,211		11,776
	Amended returns and changes to estimated tax pools and tax positions		38,197		3,478
	Changes in statutory tax rates and the estimated reversal rates associated with temporary differences		5,299		7,506
	Gain on acquisition		-		(12,389)
	Other non-deductible items		(2,925)		796
Provision for income taxes			253,536		162,622

⁽¹⁾In Australia, current taxes included both corporate income tax rates and PRRT. Corporate income tax rates were applied at a rate of 30% and PRRT was applied at a rate of 40%.
⁽²⁾The effective corporate tax rate was 38.0% in France, 46.0% in the Netherlands and 25.0% in Ireland.

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. Vermilion has determined the provision based on management's best estimate of the amount required to settle the tax assessments and has 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.

10. SHAREHOLDERS' CAPITAL

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

Shareholders' Capital	Number of Shares ('000s)		Amount ($M)
Balance as at January 1, 2012		96,430	1,368,145
Issuance of shares pursuant to the dividend reinvestment plan		1,631	72,058
Vesting of equity based awards		904	33,355
Share-settled dividends on vested equity based awards		157	7,151
Shares issued pursuant to the bonus plan		13	636
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

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

Dividends

Dividends declared to shareholders for the year ended December 31, 2013 were $242.6 million (2012 - $223.7 million). Dividends are approved by the Board of Directors and are paid monthly. Vermilion has a dividend reinvestment plan which allows eligible holders of common shares to purchase additional common shares at a 5% discount to market by reinvesting their cash dividends. Subsequent to the end of the period and prior to the consolidated financial statements being authorized for issue on February 27, 2014, Vermilion declared dividends totalling $44.0 million or $0.215 per share for each of January and February of 2014.

11. EQUITY BASED COMPENSATION

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

Number of Awards ('000s)	2013	2012
Opening balance	1,690	1,750
Granted	832	681
Vested	(749)	(596)
Forfeited	(108)	(145)
Closing balance	1,665	1,690

The fair value of a VIP award is determined on the grant date at the closing price of Vermilion's common shares on the Toronto Stock Exchange, adjusted by the estimated performance factor that will ultimately be achieved. Dividends, which notionally accrue to the awards during the vesting period, are not included in the determination of grant date fair values. For the year ended December 31, 2013, the awards granted had a weighted average fair value of $80.79 (2012 - $61.08).

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

The expense recognized is based on the grant date fair value of the awards and incorporates an estimate of forfeiture rate based on historical vesting data. For the year ended December 31, 2013, Vermilion incorporated an estimated forfeiture rate of 6.61% (2012 - 5.37%). Equity based compensation expense of $60.2 million was recorded during the year ended December 31, 2013 (2012 - $46.5 million) related to the VIP.

12. PER SHARE AMOUNTS

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

	Year Ended
($M except per share amounts)	Dec 31, 2013	Dec 31, 2012
Net earnings [1]	327,641		190,622
Basic weighted average shares outstanding [2]	100,969		98,016
Dilutive impact of equity based award plans	1,498		1,278
Diluted weighted average shares outstanding [3]	102,467		99,294
Basic earnings per share ([1] ÷ [2])	3.24		1.94
Diluted earnings per share ([1] ÷ [3])	3.20		1.92

13. DERIVATIVE INSTRUMENTS

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

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

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

The following table reconciles the change in the fair value of Vermilion's derivative instruments:

			Year ended
($M)		Dec 31, 2013		Dec 31, 2012
Fair value of contracts, beginning of year			(6,398)		(12,149)
Reversal of opening contracts settled during the year			6,398		12,149
Realized loss on contracts settled during the year			(7,082)		(12,737)
Unrealized loss during the year on contracts outstanding at the end of the year			(1,287)		(6,398)
Net payment to counterparties on contract settlements during the year			7,082		12,737
Fair value of contracts, end of year			(1,287)		(6,398)
Comprised of:
	Current derivative asset		2,285		2,086
	Current derivative liability		(3,572)		(8,484)
Fair value of contracts, end of year			(1,287)		(6,398)

The loss on derivative instruments for 2013 and 2012 are comprised of the following:

		Year Ended
($M)	Dec 31, 2013		Dec 31, 2012
Realized loss on contracts settled during the year		7,082		12,737
Reversal of opening contracts settled during the year		(6,398)		(12,149)
Unrealized loss during the year on contracts outstanding at the end of the year		1,287		6,398
Loss on derivative instruments		1,971		6,986

14. SUPPLEMENTAL CASH FLOW INFORMATION

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

		Year Ended
($M)		Dec 31, 2013	Dec 31, 2012
Changes in:
	Accounts receivable	12,446	(818)
	Crude oil inventory	8,576	(11,661)
	Prepaid expenses	(840)	2,375
	Accounts payable and accrued liabilities and income taxes payable	(4,944)	(18,836)
	Movements in foreign exchange rates	(7,508)	(1,881)
Changes in non-cash working capital		7,730	(30,821)
Changes in non-cash operating working capital		49,421	(47,409)
Changes in non-cash investing working capital		(41,691)	16,588
Changes in non-cash working capital		7,730	(30,821)

15. SEGMENTED INFORMATION

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

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

Prior to the year ended December 31, 2013, Vermilion's segmented disclosure provided a breakdown by country of operating income, which excluded general and administration expense, current income taxes, interest expense, realized foreign exchange, and realized other income. In addition, the prior year disclosure presented the results of the Canada and Corporate segments as a combined segment. The 2013 presentation is now expanded to reflect all of the directly attributable revenue and expenditures for each of Vermilion's business units in addition to the newly segregated corporate segment.

	Year Ended December 31, 2013
($M)	Canada	France	Netherlands	Australia	Ireland	Corporate	Total
Total assets	1,212,056	901,582	228,869	322,773	747,882	295,557	3,708,719
Drilling and development	232,858	96,479	28,543	77,931	90,898	2,228	528,937
Exploration and evaluation	8,339	3,899	-	-	-	1,551	13,789
Oil and gas sales to external customers	382,005	453,315	139,570	298,945	-	-	1,273,835
Royalties	(40,891)	(27,045)	-	-	-	-	(67,936)
Revenue from external customers	341,114	426,270	139,570	298,945	-	-	1,205,899
Transportation expense	(12,254)	(12,505)	-	-	(4,165)	-	(28,924)
Operating expense	(55,804)	(66,997)	(20,617)	(51,625)	-	-	(195,043)
General and administration	(12,979)	(19,657)	(2,724)	(5,752)	(1,442)	(7,356)	(49,910)
Corporate income taxes	-	(94,524)	(34,132)	(31,735)	-	(1,403)	(161,794)
PRRT	-	-	-	(56,565)	-	-	(56,565)
Interest expense	-	-	-	-	-	(38,183)	(38,183)
Realized loss on derivative instruments	-	-	-	-	-	(7,082)	(7,082)
Realized foreign exchange loss	-	-	-	-	-	(1,866)	(1,866)
Realized other income	-	-	-	-	-	994	994
Fund flows from operations	260,077	232,587	82,097	153,268	(5,607)	(54,896)	667,526



	Year Ended December 31, 2012
($M)	Canada	France	Netherlands	Australia	Ireland	Corporate	Total
Total assets	1,112,335	868,300	156,620	296,169	576,904	65,929	3,076,257
Drilling and development	232,903	47,382	21,052	49,389	58,764	3,731	413,221
Exploration and evaluation	38,871	-	272	-	-	174	39,317
Oil and gas sales to external customers	304,202	388,410	123,528	266,963	-	-	1,083,103
Royalties	(31,667)	(20,417)	-	-	-	-	(52,084)
Revenue from external customers	272,535	367,993	123,528	266,963	-	-	1,031,019
Transportation expense	(8,321)	(8,236)	-	-	(7,556)	-	(24,113)
Operating expense	(55,418)	(54,907)	(19,149)	(48,968)	-	-	(178,442)
General and administration	(12,344)	(15,009)	(1,329)	(3,715)	(1,346)	(10,030)	(43,773)
Corporate income taxes	-	(63,006)	(25,648)	(31,607)	-	(1,582)	(121,843)
PRRT	-	-	-	(60,070)	-	-	(60,070)
Interest expense	-	-	-	-	-	(27,586)	(27,586)
Realized loss on derivative instruments	-	-	-	-	-	(12,737)	(12,737)
Realized foreign exchange gain	-	-	-	-	-	2,804	2,804
Realized other expense	-	-	-	-	-	(7,531)	(7,531)
Fund flows from operations	196,452	226,835	77,402	122,603	(8,902)	(56,662)	557,728

Reconciliation of fund flows from operations to net earnings

	Year Ended
($M)	Dec 31, 2013	Dec 31, 2012
Fund flows from operations	667,526	557,728
Equity based compensation	(60,845)	(47,104)
Unrealized gain on derivative instruments	5,111	5,751
Unrealized foreign exchange gain (loss)	52,028	(4,350)
Unrealized other expense	(1,451)	(1,220)
Accretion	(24,565)	(23,040)
Depletion and depreciation	(322,386)	(295,943)
Deferred taxes	(35,177)	19,291
Impairment (recovery)	47,400	(65,800)
Gain on acquisition	-	45,309
Net earnings	327,641	190,622

Vermilion has two major customers with revenues in excess of 10% within the France and Netherlands segments. Sales to the major customer in the France segment for year ended December 31, 2013 were $453.3 million (2012 - $380.6 million). All sales in the Netherlands segment were to one customer.

16. COMMITMENTS

Vermilion had the following future commitments associated with its operating leases as at December 31, 2013:

($M)	Less than 1 year	1 - 3 years	4 - 5 years	After 5 years	Total
Payments by period	19,038	29,489	23,919	62,211	134,657

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

17. CASH AND CASH EQUIVALENTS

Cash and cash equivalents was comprised of the following:

($M)	Dec 31, 2013		Dec 31, 2012
Money on deposit with financial institutions		379,936		78,396
Short-term investments		9,623		23,729
Cash and cash equivalents		389,559		102,125

18. CAPITAL DISCLOSURES

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

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

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

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

	Year Ended
($M except as indicated)	Dec 31, 2013	Dec 31, 2012
Long-term debt	990,024	642,022
Current liabilities	347,444	355,711
Current assets	(587,783)	(320,502)
Net debt [1]	749,685	677,231
Cash flows from operating activities	705,025	496,580
Changes in non-cash operating working capital	(49,421)	47,409
Asset retirement obligations settled	11,922	13,739
Fund flows from operations [2]	667,526	557,728
Ratio of net debt to fund flows from operations ([1] ÷ [2])	1.1	1.2

The ratio of net debt to fund flows from operations for the year ended December 31, 2013 was relatively consistent with same period in 2012 as fund flows from operations increased proportionately with net debt. The increase in net debt was the result of the Northern acquisition in the fourth quarter of 2013 and current year capital expenditures pertaining to the Ireland assets, which are currently under development.

19. FINANCIAL INSTRUMENTS

Classification of Financial Instruments

The following table summarizes information relating to Vermilion's financial instruments as at December 31, 2013 and December 31, 2012:

As at Dec 31, 2013

As at Dec 31, 2012

Class of financial instrument

Consolidated balance sheet caption

Accounting designation

Related caption on Statement of Net
Earnings

Carrying value ($M)

Fair value ($M)

Carrying value ($M)

Fair value ($M)

Fair value measurement hierarchy

Cash

Cash and cash equivalents

HFT

Gains and losses on foreign exchange are included in foreign exchange (gain) loss

389,559

102,125

Level 1

Receivables

Accounts receivable

LAR

Gains and losses on foreign exchange are included in foreign exchange (gain) loss and impairments are recognized as general and administration expense

167,618

180,064

Not applicable

Derivative assets

Derivative instruments

HFT

Loss on derivative instruments

2,285

2,086

Level 2

Derivative liabilities

Derivative instruments

HFT

Loss on derivative instruments

(3,572)

(8,484)

Level 2

Payables

Accounts payable and accrued liabilities

OTH

Gains and losses on foreign exchange are included in foreign exchange (gain) loss

(288,257)

(319,518)

Not applicable

Dividends payable

Long-term debt

OTH

Interest expense

(990,024)

(998,648)

(642,022)

(656,315)

Not applicable

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

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

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

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

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

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

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

Determination of Fair Values

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

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

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

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

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

Nature and Extent of Risks Arising from Financial Instruments

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

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

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

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

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

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

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

Summarized Quantitative Data Associated with the Risks Arising from Financial Instruments

Credit risk:
As at December 31, 2013, Vermilion's maximum exposure to receivable credit risk was $169.9 million (December 31, 2012 - $182.2 million) which is the aggregate value of receivables and derivative assets at the balance sheet date. Vermilion's receivables are primarily due from counterparties that have investment grade third party credit ratings or, in the absence of the availability of such ratings, have been satisfactorily reviewed by Vermilion for creditworthiness. Additionally, cash and cash equivalents consist of moneys on deposit and short-term investments which may be subject to counterparty credit risk. Vermilion mitigates this risk by transacting with North American institutions with high third party credit ratings.

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

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

The following table summarizes Vermilion's undiscounted non-derivative financial liabilities and their contractual maturities as at December 31, 2013 and December 31, 2012:

		Later than	Later than	Later than
		one month and	three months and	one year and
	Due in	not later than	not later than	not later than
($M)	one month	three months	one year	five years
December 31, 2013	154,176	118,764	15,317	991,898
December 31, 2012	109,312	209,783	423	644,784

Market risk:
Vermilion's financial instruments are exposed to currency risk related to changes in foreign currency denominated financial instruments and commodity price risk related to outstanding derivative positions. The following table summarizes what the impact on comprehensive income before tax would be for the year ended December 31, 2013 given changes in the relevant risk variables that Vermilion considers were reasonably possible at the balance sheet date. The impact on comprehensive income before tax associated with changes in these risk variables for assets and liabilities that are not considered financial instruments are excluded from this analysis. This analysis does not attempt to reflect any interdependencies between the relevant risk variables.

		Before tax effect on comprehensive
		income - increase (decrease)
Risk ($M)	Description of change in risk variable	Dec 31, 2013	Dec 31, 2012
Currency risk - Euro to Canadian	Increase in strength of the Canadian dollar against the	(14,276)	(6,476)
	Euro by 5% over the relevant closing rates
	Decrease in strength of the Canadian dollar against the	14,276	6,476
	Euro by 5% over the relevant closing rates
Currency risk - US $ to Canadian	Increase in strength of the Canadian dollar against the	(4,420)	(1,971)
	US$ by 5% over the relevant closing rates
	Decrease in strength of the Canadian dollar against the	4,420	1,971
	US$ by 5% over the relevant closing rates
Commodity price risk	Increase in relevant oil reference price within option pricing models used to determine	(12,291)	(12,908)
	the fair value of financial derivatives by US$5.00/bbl at the relevant valuation dates
	Decrease in relevant oil reference price within option pricing models used to determine	11,376	12,296
	the fair value of financial derivatives by US$5.00/bbl at the relevant valuation dates
Interest rate risk	Increase in average Canadian prime interest rate	(4,945)	(2,007)
	by 100 basis points during the relevant periods
	Decrease in average Canadian prime interest rate	4,945	2,007
	by 100 basis points during the relevant periods

Reasonably possible changes in natural gas prices would not have had a material impact on comprehensive income for the years ended December 31, 2013 and 2012.

20. RELATED PARTY DISCLOSURES

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

The following table summarizes the compensation of directors and other members of key management personnel during the years ended December 31, 2013 and December 31, 2012:

		Year Ended
($M)	Dec 31, 2013		Dec 31, 2012
Short-term benefits		6,308		6,545
Share-based payments		19,302		15,428
		25,610		21,973
Number of individuals included in the above amounts		17		19

21. WAGES AND BENEFITS

Included in operating expenses and general and administrative expenses for the year ended December 31, 2013 were $53.2 million and $45.9 million of wages and benefits, respectively (2012 - $45.3 million and $30.9 million, respectively).

22. SUBSEQUENT EVENTS

Purchase and Sale Agreement with GDF Suez E&P Deutschland GmbH

On November 6, 2013, Vermilion announced that it entered into a definitive purchase and sale agreement with GDF Suez E&P Deutschland GmbH ("GDF") whereby Vermilion, through its wholly-owned subsidiary, will acquire GDF's 25% interest in four producing natural gas fields and a surrounding exploration license located in northwest Germany. GDF is an affiliate of GDF Suez S.A., a publicly traded, French multinational utility. In addition, the acquisition also includes the purchase of 0.4% of the equity of Ergas Munster GmbH ("EGM"), a joint venture created in 1959 to jointly transport, process, and market gas in northwest Germany. The acquisition represents Vermilion's entry into the German E&P business, a producing region with a long history of oil and gas development activity, low political risk and strong marketing fundamentals. The acquisition is well aligned with Vermilion's European focus, and will increase its exposure to the strong fundamentals and pricing of the European natural gas markets. The acquisition closed in February of 2014 for cash proceeds of approximately $172.0 million plus customary working capital adjustments.

Given the recent timing of the acquisition, the Company has not yet completed the accounting for the acquisition and accordingly not all relevant disclosures are available for the business combination. The Company will report the purchase price allocation in the Company's consolidated financial statements for the three months ended March 31, 2014.

SOURCE: Vermilion Energy Inc.

Lorenzo Donadeo, Chief Executive Officer;
Anthony Marino, President & COO;

Curtis W. Hicks, Executive VP & CFO; and/or
Dean Morrison, Director Investor Relations
TEL (403) 269-4884
IR TOLL FREE 1-866-895-8101
[email protected]
www.vermilionenergy.com

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