Vermilion Energy Inc. Announces 2013 Year-End Summary Reserves and Resource Information

CALGARY, March 3, 2014 /CNW/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce summary 2013 year-end reserves and resource information.  The estimates of reserves and resources and other oil and gas information contained in this news release has been estimated by GLJ Petroleum Consultants Ltd. ("GLJ") and prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGEH"). For additional information about Vermilion, including Vermilion's statement of reserves data and other information in Form 51-101F1, report on reserves data by independent qualified reserves evaluator or auditor in Form 51-101F2 and report of management and directors on oil and gas disclosure in Form 51-101F3, please review the Company's Annual Information Form for the year ended December 31, 2013, to be filed and available on SEDAR at www.sedar.com and on the SEC's EDGAR system at www.sec.gov.

HIGHLIGHTS

• Total proved ("1P") reserves increased 23% to 129.0 mmboe, while total proved plus probable ("2P") reserves increased 20% to 198.6 mmboe.
  
  
• In 2013, we added 48.7 mmboe of 2P reserves with 46.3 mmboe (95%) of 2P reserves additions coming from exploration and development ("E&D") activities and 2.4 mmboe (5%) of 2P reserves additions through acquisitions.
  
  
• At the 2P level, we replaced 309% of 2013 production through E&D activities (excluding acquisitions). Excluding Corrib-related expenditures and reserves additions, Vermilion reinvested 68% of fund flows from operations⁽¹⁾ to achieve a finding and development ("F&D") cost of $16.48/boe for E&D related 2P reserves additions (including future development costs "FDC") and a recycle ratio of 3.7 times.  Including Corrib-related development expenditures and reserves additions, Vermilion reinvested 81% of fund flows from operations to achieve an F&D cost of $16.59/boe for E&D related 2P reserves additions (including FDC costs) and a recycle ratio of 3.6 times.
  
  
• At the 2P level, we replaced 325% of 2013 production through all activities (including both E&D activities and acquisitions), at a finding, development and acquisition ("FD&A") cost of $17.02/boe (including future development costs) and a recycle ratio of 3.6 times. Our 2P FD&A cost for 2013 represents a 27% reduction from our FD&A cost in 2012.


• The GLJ 2013 Resources Assessment (as defined below) estimated contingent resources of 74.4 mmboe (low estimate) to 351.7 mmboe (high estimate), with a best estimate of 233.5 mmboe, and prospective resources of 59.4 mmboe (low estimate) to 818.8 mmboe (high estimate), with a best estimate of 498.7 mmboe. 
  
  
• At year-end 2013, 2P reserves were comprised  of 36% Brent-based light crude, 16% Canadian-based light crude, 7% natural gas liquids, 20% European natural gas and 21% Canadian natural gas.
  
  
• Reserve life index increased to 13.3 years for 2P reserves and 8.6 years for 1P reserves based on year-end 2013 reserves and annualized fourth quarter 2013 production of 40,960 boe/d, as compared to 12.5 years for 2P reserves and 8.0 years for 1P reserves at year-end 2012.
  
  
• Based on a successful six-well program in 2013, an additional 40 (28.4 net) undeveloped wells were added at the 2P level in the Mannville liquids-rich gas play in Alberta, with average reserves of 650 mboe/well.
  
  
• A successful five-well infill and extension drilling program in the Champotran field in the Paris Basin in France added 5.5 mmbbl of 2P reserves.
  
  
• The continued strong performance of our existing wells in combination with the results of our successful 2013 two-well drilling program resulted in the addition of 4.7 mmbbl of 2P reserves in Australia in 2013.

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

RESERVES, FUTURE NET REVENUE AND OTHER OIL AND GAS INFORMATION

The following is a summary of the oil and natural gas reserves and the value of future net revenue of Vermilion as evaluated by GLJ, independent petroleum engineering consultants in Calgary in a report dated February 4, 2014 with an effective date of December 31, 2013 (the "GLJ 2013 Reserves Evaluation").  The GLJ 2013 Reserves Evaluation was prepared in accordance with National Instrument 51-101 and COGEH.

Reserves and other oil and gas information in this news release is effective December 31, 2013 unless otherwise stated.

All evaluations of future net production revenue set forth in the tables below are stated after overriding and lessor royalties, Crown royalties, freehold royalties, mineral taxes, direct lifting costs, normal allocated overhead and future capital investments, including abandonment and reclamation obligations.  Future net production revenues estimated by the GLJ 2013 Reserves Evaluation do not represent the fair market value of the reserves.  Other assumptions relating to the costs, prices for future production and other matters are included in the GLJ 2013 Reserves Evaluation.  There is no assurance that the future price and cost assumptions used in the GLJ 2013 Reserves Evaluation will prove accurate and variances could be material.

Reserves for Australia, Canada, France, Ireland and the Netherlands are established using deterministic methodology.  Total proved reserves are established at the 90 percent probability (P90) level.  There is a 90 percent probability that the actual reserves recovered will be equal to or greater than the P90 reserves.  Total proved plus probable reserves are established at the 50 percent probability (P50) level.  There is a 50 percent probability that the actual reserves recovered will be equal to or greater than the P50 reserves.

Estimates of reserves have been made assuming that development of each property, in respect of which estimates have been made, will occur without regard to the availability of funding required for that development.

With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.

Pricing used in the forecast price estimates is set forth in the table below and referenced in the notes to subsequent tables.

Table 1: Forecast Prices used in Estimates ⁽¹⁾

All forecast prices in the table above are provided by GLJ.  For 2013, the price of Vermilion's natural gas in the Netherlands was 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 purchases all natural gas produced by Vermilion in the Netherlands.  Prior to 2013, the natural gas price received by Vermilion in the Netherlands was calculated using a formula based on the trailing average of Dated Brent and natural gas prices from European trading hubs.  France natural gas production was benchmarked to National Balancing Point (UK).  The benchmark price for Australia and France crude oil was Dated Brent. The benchmark price for Canadian crude oil was Edmonton Par and Canadian natural gas was priced against AECO.  For the year ended December 31, 2013, the average realized sales prices before hedging were $119.38 per bbl (Australia), $10.61 per Mcf (Netherlands), $108.55 per bbl (France) for Brent-based crude oil, $89.78 per bbl for Canadian-based crude oil and NGLs and $3.40 per Mcf for Canadian natural gas.

The following table summarizes the capital expenditures made by Vermilion on oil and natural gas properties for the year ended December 31, 2013:

Table 2: Capital Costs Incurred

The following table sets forth the reserve life index based on total proved and proved plus probable reserve and fourth quarter 2013 production of 40,960 boe/d.

Table 3: Reserve Life Index

The following tables provide reserves data and a breakdown of future net revenue by component and production group using forecast prices and costs.  For Canada, the tables following include Alberta gas cost allowance.

The following tables may not total due to rounding.

Table 4: Oil and Gas Reserves - Based on Forecast Prices and Costs ⁽¹⁾

Table 5: Net Present Values of Future Net Revenue - Based on Forecast Prices and Costs ⁽¹⁾

Table 6: Total Future Net Revenue (Undiscounted) Based on Forecast Prices and Costs ⁽¹⁾

Table 7: Future Net Revenue by Production Group Based on Forecast Prices and Costs ⁽¹⁾

Reconciliations of Changes in Reserves

The following tables set forth a reconciliation of the changes in Vermilion's gross light and medium crude oil, heavy oil and associated and non-associated gas (combined) reserves as at December 31, 2013 compared to such reserves as at December 31, 2012 based on the forecast price and cost assumptions set forth in note 3.

Table 8: Reconciliation of Company Gross Reserves by Principal Product Type - Based on Forecast Prices and Costs