CALGARY, Feb. 29, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce summary 2015 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, 2015, to be filed on March 4, 2016 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 6% to 160.7 mmboe(1), while total proved plus probable ("2P") reserves also increased 6% to 260.9 mmboe(1).  This represents year-over-year 1P and 2P per share reserves growth of 2% and 1%, respectively.
• Finding and Development ("F&D")(2) and Finding, Development and Acquisition ("FD&A")(2) costs, including Future Development Capital ("FDC") for 2015 on a 2P basis decreased 48% to $8.98/boe and 55% to $10.03/boe, respectively.  Similarly, our three-year F&D and FD&A, including FDC, on a 2P basis were $14.82/boe and $17.81/boe, respectively.
• Achieved a $212.6 million (12%) reduction in FDC costs attributable our existing assets through reductions in drilling, completions and facility capital costs.  This was partially offset by the addition of $38.4 million of FDC related to properties acquired during the year resulting in a net reduction in FDC of 11% to $1.6 billion in 2015.
• Recycle ratio (including FDC) was 3.6x during 2015, an increase over 3.2x achieved during 2014, indicating that Vermilion has been able to maintain our high level of investment efficiency despite the decline in commodity prices.
• In 2015, we added 34.0 mmboe of 2P reserves with 30.5 mmboe (90%) of additions coming from exploration and development ("E&D") activities and 3.5 mmboe (10%) of additions through acquisitions.
• Replaced 152% of production at the 2P level through E&D related activities and 170% including acquisitions.  At a 1P level, we replaced 142% and 146% of 2015 production, respectively.
• Increased Proved Developed Producing ("PDP") reserves by 25% to 110.4 mmboe at an average F&D cost (including FDC) of $10.67/boe resulting in a recycle ratio (including FDC) of 3.0x.  PDP reserves represent 69% of 1P reserves in 2015 as compared to 58% in 2014.
• Positive technical revisions of 2.0 mmboe on a 2P basis resulting from strong well performance were more than offset by 10.3 mmboe of revisions due to the decrease in commodity prices since year-end 2014.  Only 4% of the economic revisions occurred outside of Canada, reflecting the continued high quality of our reserves attributable to our international operations.
• Our independent GLJ 2015 Resource Assessment(3) indicates low, best, and high estimates for contingent resources in the Development Pending category are 95.1(3) mmboe, 160.7(3) mmboe, and 254.7(3) mmboe, respectively.  Approximately 80% of our best estimate contingent resources evaluated reside in the Development Pending category, reflecting the high quality nature of our contingent resource base.
• At year-end 2015, 2P reserves were comprised of 30% Brent-based light crude, 17% North American-based light crude, 11% natural gas liquids, 20% European natural gas and 22% North American natural gas.
• Achieved a reserve life index for 2P reserves of 11.7 years for year-end 2015 reserves based on annualized Q4 2015 production, compared to 13.6 years at year-end 2014. Year-end 2015 reserve life index for 1P reserves was 7.2 years, as compared to 8.4 years at year-end 2014.
• Based on the continued success of our Mannville liquids-rich gas play in Alberta, our 2015 activities resulted in an additional 35 (23.2 net) undeveloped wells booked at the 2P level, with average net reserves of approximately 620 mboe/well.  Additionally, we added a further 14 (9 net) undeveloped wells that were attributed to lands acquired in 2015.
• In the Paris Basin, we added 7.3 mmboe of 2P reserves, related to 18 development opportunities, including 15 new additions and strong upward revisions related to well performance and expanded waterflood response.  Well additions and successful workover and optimization campaigns in the Aquitaine Basin in France added a further 2.8 mmboe of 2P reserves.
• We added an additional 1.9 mmboe of 2P reserves to our Slootdorp-06 well (92.8 working interest) related to the discovery in the Rotliegend formation and an additional 1.5 mmboe of 2P reserves to our Slootdorp-07 well (92.8% working interest) related to the discovery in the Zechstein formation).

DISCLAIMER

Certain statements included or incorporated by reference in this news release 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 news release 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 of future dividends;
• royalty and income tax rates;
• the timing of regulatory proceedings and approvals; 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 the Company to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally;
• the ability of the Company 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 the Company 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 development activities.

Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct.  Financial outlooks are provided for the purpose of understanding the Company'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 the Company 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 the Company'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, costs and expenses;
• potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
• the Company'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 the Company to add production and reserves through exploration and development activities;
• general economic and business conditions;
• 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 the Company; and
• other risks and uncertainties described elsewhere in the annual information form of the Company for the year ended December 31, 2014 or in the Company's other filings with Canadian securities authorities.

The forward-looking statements or information contained in this news release are made as of the date hereof and the Company 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.

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 8, 2016 with an effective date of December 31, 2015 (the "GLJ 2015 Reserves Evaluation").  The GLJ 2015 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, 2015 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 2015 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 2015 Reserve Evaluation.  There is no assurance that the future price and cost assumptions used in the GLJ 2015 Reserves Evaluation will prove accurate and variances could be material.

Reserves for Australia, Canada, France, Germany, Ireland, the Netherlands and the United States 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 tables above are provided by GLJ.  For 2015, the price of Vermilion's 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 purchases all natural gas produced by Vermilion in the Netherlands.  The price of Vermilion's natural gas in Germany is based on the TTF month-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees.  The benchmark price for Australia and France crude oil is Dated Brent. The benchmark price for Canadian crude oil is Edmonton Par and Canadian natural gas is priced against AECO.  For the year ended December 31, 2015, the average realized sales prices before hedging were $70.22 per bbl (Australia), $7.79 per Mcf (Netherlands), $7.18 per Mcf (Germany), $63.31 per bbl (France) for Brent-based crude oil, $49.10 per bbl (United States) for WTI, $49.73 per bbl for Canadian-based crude oil and NGLs and $2.78 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, 2015:

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 2015 production of 61,058 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, 2015 compared to such reserves as at December 31, 2014.

Table 8: Reconciliation of Company Gross Reserves by Principal Product Type - Based on Forecast Prices and Costs (3)