Vermilion Energy 6K Announces 2015 Year-End Summary Reserves and Resource Information | VET 29 Feb 16

Exhibit 99.1

Vermilion Energy Inc. Announces 2015 Year-End Summary Reserves and Resource Information

CALGARY, Feb. 29, 2016 /CNW/ - 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⁾, whiletotal 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).

⁽¹⁾	As evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 8, 2016 with an effective date of December 31, 2015.
⁽²⁾	F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital costs for the period, including the change in undiscounted future development capital ("FDC"), by the change in the reserves, incorporating revisions and production, for the same period.
⁽³⁾	Vermilion retained GLJ to conduct an independent resource evaluation dated February 8, 2016 to assess contingent resources across all of the Company's key operating regions with an effective date of December 31, 2015 (the "GLJ 2015 Resource Assessment"). The associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 83%, 82% and 81%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources.

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⁾


		Light Crude Oil and			Natural Gas	Natural Gas	Natural Gas	Inflation	Exchange	Exchange
		& Medium Crude Oil		Crude Oil	Canada	Europe	Liquids	Rate	Rate	Rate
	WTI	Edmonton	Cromer	Brent Blend		National Balancing
	Cushing	Par Price	Medium	FOB	AECO	Point	FOB
	Oklahoma	40˚ API	29.3˚ API	North Sea	Gas Price	(UK)	Field Gate	Percent
Year	($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($US/bbl)	($Cdn/MMBtu)	($US/MMBtu)	($Cdn/bbl)	Per Year	($US/$Cdn)	($CdnEUR)
2015	48.82	57.23	51.91	53.75	2.70	6.55	34.59	1.1	0.783	1.419
Forecast
2016	44.00	55.86	50.80	45.00	2.76	5.55	30.27	2.0	0.725	1.517
2017	52.00	64.00	59.52	54.00	3.27	5.68	35.76	2.0	0.750	1.467
2018	58.00	68.39	63.60	61.00	3.45	6.10	39.04	2.0	0.775	1.419
2019	64.00	73.75	68.59	67.00	3.63	6.70	42.96	2.0	0.800	1.375
2020	70.00	78.79	73.27	73.00	3.81	7.30	45.85	2.0	0.825	1.333
2021	75.00	82.35	76.59	78.00	3.90	7.80	47.86	2.0	0.850	1.294
2022	80.00	88.24	82.06	83.00	4.10	8.30	51.23	2.0	0.850	1.294
2023	85.00	94.12	87.53	88.00	4.30	8.80	54.59	2.0	0.850	1.294
2024	87.88	96.48	89.73	91.39	4.50	9.14	57.18	2.0	0.850	1.294
Thereafter	2.0%	2.0%	2.0%	2.0%	2.0%	2.0%	2.0%	2.0%	0.850	1.294


Note:
⁽¹⁾	The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.

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

	Acquisition Costs
	Proved	Unproved	Exploration	Development	Total
(M$)	Properties	Properties	Costs	Costs	Costs
Australia	-	-	-	61,741	61,741
Canada	14,650	-	-	201,508	216,158
France	317	-	-	92,265	92,582
Germany	-	-	-	5,363	5,363
Hungary	-	-	1,166	-	1,166
Ireland	-	-	-	66,409	66,409
Netherlands	-	-	-	47,325	47,325
United States	12,764	-	-	12,250	25,014
Total	27,731	-	1,166	486,861	515,758

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

Commodity	Production	Reserve Life Index (years)
	Fourth Quarter 2015	Total Proved	Proved Plus Probable
Oil and natural gas liquids (bbl/d)	34,043	7.6	12.2
Natural gas (mmcf/d)	162.09	6.7	11.1
Oil Equivalent (boe/d)	61,058	7.2	11.7

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⁾

	Light Crude Oil & Medium Crude Oil		Heavy Oil		Tight Oil		Conventional Natural Gas
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)
Proved Developed Producing^{(3) (5) (6)}
Australia	11,465	11,465	-	-	-	-	-	-
Canada	13,528	11,785	9	9	10	8	98,840	89,253
France	34,866	32,097	-	-	-	-	7,835	7,309
Germany	-	-	-	-	-	-	20,876	18,148
Ireland	-	-	-	-	-	-	94,976	94,976
Netherlands	-	-	-	-	-	-	29,961	27,236
United States	384	314	-	-	-	-	372	304
Total Proved Developed Producing	60,243	55,661	9	9	10	8	252,860	237,226

	Shale Gas		Coal Bed Methane		Natural Gas Liquids		BOE
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross	Net
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
Proved Developed Producing^{(3) (5) (6)}
Australia	-	-	-	-	-	-	11,465	11,465
Canada	1,942	1,832	3,100	2,883	7,052	5,383	37,913	32,846
France	-	-	-	-	-	-	36,172	33,315
Germany	-	-	-	-	-	-	3,479	3,025
Ireland	-	-	-	-	-	-	15,829	15,829
Netherlands	-	-	-	-	66	60	5,060	4,599
United States	-	-	-	-	59	49	505	414
	1,942	1,832	3,100	2,883	7,177	5,492	110,423	101,493

	Light Crude Oil & Medium Crude Oil		Heavy Oil		Tight Oil		Conventional Natural Gas
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)
Proved Developed Non-Producing
Australia	-	-	-	-	-	-	-	-
Canada	1,032	940	-	-	-	-	17,090	14,633
France	1,914	1,754	-	-	-	-	-	-
Germany	-	-	-	-	-	-	8,263	7,157
Ireland	-	-	-	-	-	-	10,845	10,845
Netherlands	-	-	-	-	-	-	18,238	18,238
United States	313	254	-	-	-	-	318	258
Total Proved Developed Non-Producing	3,259	2,948	-	-	-	-	54,754	51,131

	Shale Gas		Coal Bed Methane		Natural Gas Liquids		BOE
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross	Net
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
Proved Developed Non-Producing
Australia	-	-	-	-	-	-	-	-
Canada	-	-	1,743	1,643	692	490	4,863	4,143
France	-	-	-	-	-	-	1,914	1,754
Germany	-	-	-	-	-	-	1,377	1,193
Ireland	-	-	-	-	-	-	1,808	1,808
Netherlands	-	-	-	-	22	22	3,062	3,062
United States	-	-	-	-	51	41	417	338
Total Proved Developed Non-Producing	-	-	1,743	1,643	765	553	13,441	12,298

	Light Crude Oil & Medium Crude Oil		Heavy Oil		Tight Oil		Conventional Natural Gas
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)
Proved Undeveloped^{(3) (8)}
Australia	2,300	2,300	-	-	-	-	-	-
Canada	8,411	7,357	-	-	-	-	74,181	68,479
France	3,941	3,693	-	-	-	-	-	-
Germany	-	-	-	-	-	-	2,361	1,684
Ireland	-	-	-	-	-	-	-	-
Netherlands	-	-	-	-	-	-	-	-
United States	1,337	1,087	-	-	-	-	1,480	1,204
Total Proved Undeveloped	15,989	14,437	-	-	-	-	78,022	71,367

	Shale Gas		Coal Bed Methane		Natural Gas Liquids		BOE
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross	Net
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
Proved Undeveloped
Australia	-	-	-	-	-	-	2,300	2,300
Canada	-	-	3,367	3,114	7,051	5,955	28,387	25,244
France	-	-	-	-	-	-	3,941	3,693
Germany	-	-	-	-	-	-	394	281
Ireland	-	-	-	-	-	-	-	-
Netherlands	-	-	-	-	-	-	-	-
United States	-	-	-	-	236	192	1,820	1,480
Total Proved Undeveloped	-	-	3,367	3,114	7,287	6,147	36,842	32,998

	Light Crude Oil & Medium Crude Oil		Heavy Oil		Tight Oil		Conventional Natural Gas
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)
Proved⁽³⁾
Australia	13,765	13,765	-	-	-	-	-	-
Canada	22,971	20,082	9	9	10	8	190,111	172,365
France	40,721	37,544	-	-	-	-	7,835	7,309
Germany	-	-	-	-	-	-	31,500	26,989
Ireland	-	-	-	-	-	-	105,821	105,821
Netherlands	-	-	-	-	-	-	48,199	45,474
United States	2,034	1,655	-	-	-	-	2,170	1,766
Total Proved	79,491	73,046	9	9	10	8	385,637	359,724

	Shale Gas		Coal Bed Methane		Natural Gas Liquids		BOE
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross	Net
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
Proved
Australia	-	-	-	-	-	-	13,765	13,765
Canada	1,942	1,832	8,210	7,640	14,795	11,828	71,163	62,233
France	-	-	-	-	-	-	42,027	38,762
Germany	-	-	-	-	-	-	5,250	4,499
Ireland	-	-	-	-	-	-	17,637	17,637
Netherlands	-	-	-	-	88	82	8,122	7,661
United States	-	-	-	-	346	282	2,742	2,232
Total Proved	1,942	1,832	8,210	7,640	15,229	12,192	160,706	146,789

	Light Crude Oil & Medium Crude Oil		Heavy Oil		Tight Oil		Conventional Natural Gas
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)
Probable⁽⁴⁾
Australia	3,700	3,700	-	-	-	-	-	-
Canada	14,786	12,565	3	3	3	2	132,676	120,460
France	21,325	19,814	-	-	-	-	1,559	1,505
Germany	-	-	-	-	-	-	17,999	14,999
Ireland	-	-	-	-	-	-	47,405	47,405
Netherlands	-	-	-	-	-	-	48,688	43,700
United States	3,818	3,131	-	-	-	-	4,378	3,590
Total Probable	43,629	39,210	3	3	3	2	252,705	231,659

	Shale Gas		Coal Bed Methane		Natural Gas Liquids		BOE
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross	Net
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
Probable
Australia	-	-	-	-	-	-	3,700	3,700
Canada	475	447	4,917	4,628	12,751	10,144	50,554	43,637
France	-	-	-	-	-	-	21,585	20,065
Germany	-	-	-	-	-	-	3,000	2,500
Ireland	-	-	-	-	-	-	7,901	7,901
Netherlands	-	-	-	-	83	66	8,198	7,349
United States	-	-	-	-	698	572	5,246	4,301
Total Probable	475	447	4,917	4,628	13,532	10,782	100,184	89,453

	Light Crude Oil & Medium Crude Oil		Heavy Oil		Tight Oil		Conventional Natural Gas
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)
Proved Plus Probable^{(3) (4)}
Australia	17,465	17,465	-	-	-	-	-	-
Canada	37,757	32,647	12	12	13	10	322,787	292,825
France	62,046	57,358	-	-	-	-	9,394	8,814
Germany	-	-	-	-	-	-	49,499	41,988
Ireland	-	-	-	-	-	-	153,226	153,226
Netherlands	-	-	-	-	-	-	96,887	89,174
United States	5,852	4,786	-	-	-	-	6,548	5,356
Total Proved Plus Probable	123,120	112,256	12	12	13	10	638,342	591,383

	Shale Gas		Coal Bed Methane		Natural Gas Liquids		BOE
	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross⁽²⁾	Net⁽²⁾	Gross	Net
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
Proved Plus Probable^{(3) (4)}
Australia	-	-	-	-	-	-	17,465	17,465
Canada	2,417	2,279	13,127	12,268	27,546	21,972	121,717	105,870
France	-	-	-	-	-	-	63,612	58,827
Germany	-	-	-	-	-	-	8,250	6,999
Ireland	-	-	-	-	-	-	25,538	25,538
Netherlands	-	-	-	-	171	148	16,320	15,010
United States	-	-	-	-	1,044	854	7,988	6,533
Total Proved Plus Probable	2,417	2,279	13,127	12,268	28,761	22,974	260,890	236,242


Notes:
⁽¹⁾	The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
⁽²⁾	"Gross Reserves" are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net Reserves" are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in reserves.
⁽³⁾	"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
⁽⁴⁾	"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
⁽⁵⁾	"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
⁽⁶⁾	"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
⁽⁷⁾	"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
⁽⁸⁾	"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

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

	Before Deducting Future Income Taxes Discounted At						After Deducting Future Income Taxes Discounted At
(M$)		0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
Proved Developed Producing^{(2) (4) (5)}
Australia		2,347	129,206	168,558	175,898	171,717	124,988	173,769	178,900	170,295	158,300
Canada		949,037	750,567	619,559	528,638	462,575	949,037	750,567	619,559	528,638	462,575
France		1,798,973	1,255,682	953,329	767,459	643,532	1,517,541	1,074,705	821,780	664,015	557,940
Germany		43,971	38,938	34,820	31,467	28,720	43,971	38,938	34,820	31,467	28,720
Ireland		552,363	501,468	439,666	387,319	345,603	552,363	501,468	439,666	387,319	345,603
Netherlands		83,154	94,117	99,646	102,200	103,013	64,192	75,617	81,576	84,532	85,720
United States		16,290	12,359	9,959	8,387	7,290	16,290	12,359	9,959	8,387	7,290
Total Proved Developed Producing		3,446,135	2,782,337	2,325,537	2,001,368	1,762,450	3,268,382	2,627,423	2,186,260	1,874,653	1,646,148
Proved Developed Non-Producing^{(2) (4) (6)}
Australia		-	-	-	-	-	-	-	-	-	-
Canada		104,042	71,099	54,809	45,013	38,420	104,042	71,099	54,809	45,013	38,420
France		90,457	62,628	45,934	35,314	28,159	58,901	40,465	29,248	22,088	17,265
Germany		25,871	19,029	14,433	11,275	9,044	25,871	19,029	14,433	11,275	9,044
Ireland		92,735	62,194	44,189	32,997	25,688	92,735	62,194	44,189	32,997	25,688
Netherlands		49,823	39,122	30,708	24,196	19,156	41,346	30,978	22,865	16,628	11,839
United States		9,355	5,641	3,488	2,150	1,264	9,355	5,641	3,488	2,150	1,264
Total Proved Developed Non-Producing		372,283	259,713	193,561	150,945	121,731	332,250	229,406	169,032	130,151	103,520
Proved Undeveloped^{(2) (7)}
Australia		90,351	65,761	47,675	34,243	24,141	54,095	38,796	27,698	19,530	13,425
Canada		489,912	322,128	216,629	147,559	100,575	394,990	268,530	185,169	128,464	88,643
France		195,493	141,793	105,874	81,079	63,249	126,807	88,335	62,501	44,867	32,357
Germany		6,456	3,478	1,746	724	117	6,456	3,478	1,746	724	117
Ireland		-	-	-	-	-	-	-	-	-	-
Netherlands		-	-	-	-	-	-	-	-	-	-
United States		33,881	15,244	5,265	(415)	(3,816)	33,881	15,244	5,265	(415)	(3,816)
Total Proved Undeveloped		816,093	548,404	377,189	263,190	184,266	616,229	414,383	282,379	193,170	130,726
Proved⁽²⁾
Australia		92,698	194,967	216,233	210,141	195,858	179,083	212,565	206,598	189,825	171,725
Canada		1,542,991	1,143,794	890,997	721,210	601,570	1,448,069	1,090,196	859,537	702,115	589,638
France		2,084,923	1,460,103	1,105,137	883,852	734,940	1,703,249	1,203,505	913,529	730,970	607,562
Germany		76,298	61,445	50,999	43,466	37,881	76,298	61,445	50,999	43,466	37,881
Ireland		645,098	563,662	483,855	420,316	371,291	645,098	563,662	483,855	420,316	371,291
Netherlands		132,977	133,239	130,354	126,396	122,169	105,538	106,595	104,441	101,160	97,559
United States		59,526	33,244	18,712	10,122	4,738	59,526	33,244	18,712	10,122	4,738
Total Proved		4,634,511	3,590,454	2,896,287	2,415,503	2,068,447	4,216,861	3,271,212	2,637,671	2,197,974	1,880,394
Probable⁽³⁾
Australia		233,918	195,941	160,242	132,868	112,579	131,359	109,293	88,489	72,597	60,886
Canada		1,259,521	782,374	525,575	374,090	277,970	925,820	572,010	383,568	273,386	203,911
France		1,368,130	737,715	464,855	321,653	235,825	898,657	464,533	277,847	181,362	124,539
Germany		58,777	38,397	26,546	19,305	14,655	58,777	38,397	26,546	19,305	14,655
Ireland		444,344	271,776	182,158	131,596	100,818	444,344	271,776	182,158	131,596	100,818
Netherlands		259,073	192,535	149,984	121,255	100,904	213,280	150,798	111,666	85,850	68,004
United States		169,572	89,698	51,373	30,603	18,222	111,879	59,733	33,482	18,708	9,648
Total Probable		3,793,335	2,308,436	1,560,733	1,131,370	860,973	2,784,116	1,666,540	1,103,756	782,804	582,461
Proved Plus Probable^{(2) (3)}
Australia		326,616	390,908	376,475	343,009	308,437	310,442	321,858	295,087	262,422	232,611
Canada		2,802,512	1,926,168	1,416,572	1,095,300	879,540	2,373,889	1,662,206	1,243,105	975,501	793,549
France		3,453,053	2,197,818	1,569,992	1,205,505	970,765	2,601,906	1,668,038	1,191,376	912,332	732,101
Germany		135,075	99,842	77,545	62,771	52,536	135,075	99,842	77,545	62,771	52,536
Ireland		1,089,442	835,438	666,013	551,912	472,109	1,089,442	835,438	666,013	551,912	472,109
Netherlands		392,050	325,774	280,338	247,651	223,073	318,818	257,393	216,107	187,010	165,563
United States		229,098	122,942	70,085	40,725	22,960	171,405	92,977	52,194	28,830	14,386
Total Proved Plus Probable		8,427,846	5,898,890	4,457,020	3,546,873	2,929,420	7,000,977	4,937,752	3,741,427	2,980,778	2,462,855


Notes:
⁽¹⁾	The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
⁽²⁾	"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
⁽³⁾	"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
⁽⁴⁾	"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
⁽⁵⁾	"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
⁽⁶⁾	"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
⁽⁷⁾	"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

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

					Abandonment	Future Net		Future Net
				Capital	and	Revenue		Revenue
			Operating	Development	Reclamation	Before	Future	After
(M$)	Revenue	Royalties	Costs	Costs	Costs	Income Taxes	Income Taxes	Income Taxes
Proved⁽²⁾
Australia	1,279,689	-	765,611	164,897	256,483	92,698	(86,385)	179,083
Canada	3,444,744	430,994	956,472	429,587	84,700	1,542,991	94,922	1,448,069
France	3,739,055	286,952	1,054,237	142,825	170,118	2,084,923	381,674	1,703,249
Germany	243,200	34,472	121,828	7,557	3,045	76,298	-	76,298
Ireland	945,039	-	196,807	29,121	74,013	645,098	-	645,098
Netherlands	419,120	20,930	153,011	38,411	73,791	132,977	27,439	105,538
United States	193,175	53,303	33,559	44,764	2,023	59,526	-	59,526
Total Proved	10,264,022	826,651	3,281,525	857,162	664,173	4,634,511	417,650	4,216,861
Proved Plus Probable^{(2) (3)}
Australia	1,660,324	-	901,981	164,950	266,777	326,616	16,174	310,442
Canada	6,173,958	832,588	1,597,976	830,126	110,756	2,802,512	428,623	2,373,889
France	6,025,272	448,246	1,560,955	340,273	222,745	3,453,053	851,147	2,601,906
Germany	408,139	61,573	199,859	7,594	4,038	135,075	-	135,075
Ireland	1,487,330	-	294,754	29,121	74,013	1,089,442	-	1,089,442
Netherlands	908,049	67,612	274,464	87,472	86,451	392,050	73,232	318,818
United States	596,459	162,300	91,475	109,001	4,585	229,098	57,693	171,405
Total Proved Plus Probable	17,259,531	1,572,319	4,921,464	1,568,537	769,365	8,427,846	1,426,869	7,000,977


Notes:
⁽¹⁾	The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
⁽²⁾	"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
⁽³⁾	"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

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

	Future Net Revenue
	Before Income Taxes⁽²⁾
	(Discounted at 10% Per Year)	Unit Value
Proved Developed Producing	(M$)	($/boe)
Light crude oil & medium crude oil⁽³⁾	1,587,327	25.88
Heavy Oil⁽³⁾	216	12.36
Natural gas⁽⁴⁾	733,875	18.69
Shale Gas	2,860	7.26
Coal Bed Methane	1,259	2.62
Total Proved Developed Producing	2,325,537	22.91
Proved Developed Non-Producing
Light crude oil & medium crude oil⁽³⁾	66,158	20.41
Heavy Oil⁽³⁾	-	-
Natural gas⁽⁴⁾	126,536	14.41
Shale Gas	-	-
Coal Bed Methane	867	3.17
Total Proved Developed Non-Producing	193,561	15.74
Proved Undeveloped
Light crude oil & medium crude oil⁽³⁾	259,816	13.92
Heavy Oil⁽³⁾	-	-
Natural gas⁽⁴⁾	116,627	8.44
Shale Gas	-	-
Coal Bed Methane	746	1.44
Total Proved Undeveloped	377,189	11.43
Proved
Light crude oil & medium crude oil⁽³⁾	1,913,301	22.97
Heavy Oil⁽³⁾	216	12.42
Natural gas⁽⁴⁾	977,038	15.81
Shale Gas	2,860	7.28
Coal Bed Methane	2,872	2.26
Total Proved	2,896,287	19.73
Probable
Light crude oil & medium crude oil⁽³⁾	992,703	20.85
Heavy Oil⁽³⁾	87	15.91
Natural gas⁽⁴⁾	565,389	13.80
Shale Gas	691	7.26
Coal Bed Methane	1,863	2.26
Total Probable	1,560,733	19.73
Proved Plus Probable
Light crude oil & medium crude oil⁽³⁾	2,906,004	22.21
Heavy Oil⁽³⁾	303	13.30
Natural gas⁽⁴⁾	1,542,427	15.00
Shale Gas	3,551	7.33
Coal Bed Methane	4,735	2.31
Total Proved Plus Probable	4,457,020	18.87


Notes:
⁽¹⁾	The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
⁽²⁾	Other Company revenue and costs not related to a specific production group have been allocated proportionately to production groups. Unit values are based on Company Net Reserves. Net present value of reserves categories are an approximation based on major products.
⁽³⁾	Including solution gas and other by-products.
⁽⁴⁾	Including by-products but excluding solution gas.

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⁾

				Light Crude Oil &
AUSTRALIA	Total Oil⁽⁴⁾				Medium Crude Oil			Heavy Oil			Tight Oil
			Proved +				Proved +			Proved +			Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
At December 31, 2014	12,534	5,449	17,983		12,534	5,449	17,983	-	-	-	-	-	-
Discoveries	-	-	-		-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	500	50	550		500	50	550	-	-	-	-	-	-
Technical Revisions	3,087	(1,799)	1,288		3,087	(1,799)	1,288	-	-	-	-	-	-
Acquisitions	-	-	-		-	-	-	-	-	-	-	-	-
Dispositions	-	-	-		-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-		-	-	-	-	-	-	-	-	-
Production	(2,356)	-	(2,356)		(2,356)	-	(2,356)	-	-	-	-	-	-
At December 31, 2015	13,765	3,700	17,465		13,765	3,700	17,465	-	-	-	-	-	-

Total Gas⁽⁴⁾

Conventional Natural Gas

Coal Bed Methane⁽⁵⁾

Shale Natural Gas⁽⁵⁾

Proved +

Proved Probable P+P^{(1) (2)}

Proved

Probable

Proved

Probable

Proved

Probable

Proved

Probable

Factors

(MMcf)

At December 31, 2014

Discoveries

Extensions & Improved Recovery

Technical Revisions

Acquisitions

Dispositions

Economic Factors

Production

At December 31, 2015

	Natural Gas Liquids			BOE
			Proved +			Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable	Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)	(Mboe)
At December 31, 2014	-	-	-	12,534	5,449	17,983
Discoveries	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	500	50	550
Technical Revisions	-	-	-	3,087	(1,799)	1,288
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-
Production	-	-	-	(2,356)	-	(2,356)
At December 31, 2015	-	-	-	13,765	3,700	17,465

				Light Crude Oil &
CANADA	Total Oil⁽⁴⁾			Medium Crude Oil			Heavy Oil			Tight Oil
			Proved +			Proved +			Proved +			Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
At December 31, 2014	27,488	14,799	42,287	27,478	14,797	42,275	10	2	12	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	1,245	2,541	3,786	1,245	2,541	3,786	-	-	-	-	-	-
Technical Revisions	(283)	(825)	(1,108)	(295)	(828)	(1,123)	(1)	1	-	13	3	16
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	(9)	(4)	(13)	(9)	(4)	(13)	-	-	-	-	-	-
Economic Factors	(1,970)	(1,720)	(3,690)	(1,970)	(1,720)	(3,690)	-	-	-	-	-	-
Production	(3,481)	-	(3,481)	(3,478)	-	(3,478)	-	-	-	(3)	-	(3)
At December 31, 2015	22,990	14,792	37,782	22,971	14,786	37,757	9	3	12	10	3	13

	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale Natural Gas⁽⁵⁾
			Proved +			Proved +			Proved +			Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
Factors	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)
At December 31, 2014	177,414	141,032	318,446	153,592	130,581	284,173	22,260	10,031	32,291	1,562	420	1,982
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	56,482	22,244	78,726	56,482	22,244	78,726	-	-	-	-	-	-
Technical Revisions	4,325	(7,773)	(3,448)	3,505	(7,828)	(4,323)	-	-	-	820	55	875
Acquisitions	1,933	10,824	12,757	1,933	10,824	12,757	-	-	-	-	-	-
Dispositions	(39)	(8,944)	(8,983)	(39)	(8,944)	(8,983)	-	-	-	-	-	-
Economic Factors	(13,736)	(19,315)	(33,051)	(2,350)	(14,201)	(16,551)	(11,386)	(5,114)	(16,500)	-	-	-
Production	(26,116)	-	(26,116)	(23,012)	-	(23,012)	(2,664)	-	(2,664)	(440)	-	(440)
At December 31, 2015	200,263	138,068	338,331	190,111	132,676	322,787	8,210	4,917	13,127	1,942	475	2,417

	Natural Gas Liquids			BOE
			Proved +			Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable	Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)	(Mboe)
At December 31, 2014	13,550	11,331	24,881	70,608	49,635	120,243
Discoveries	-	-	-	-	-	-
Extensions & Improved Recovery	3,059	2,749	5,808	13,718	8,997	22,715
Technical Revisions	(410)	(2,077)	(2,487)	28	(4,197)	(4,169)
Acquisitions	187	1,538	1,725	509	3,342	3,851
Dispositions	(2)	(193)	(195)	(18)	(1,688)	(1,705)
Economic Factors	(95)	(597)	(692)	(4,354)	(5,536)	(9,891)
Production	(1,494)	-	(1,494)	(9,328)	-	(9,328)
At December 31, 2015	14,795	12,751	27,546	71,162	50,554	121,717

				Light Crude Oil &
FRANCE	Total Oil⁽⁴⁾			Medium Crude Oil			Heavy Oil			Tight Oil
			Proved +			Proved +			Proved +			Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
At December 31, 2014	35,602	20,288	55,890	35,602	20,288	55,890	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	4,328	2,466	6,794	4,328	2,466	6,794	-	-	-	-	-	-
Technical Revisions	5,268	(1,429)	3,839	5,268	(1,429)	3,839	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-	-	-	-
Production	(4,477)	-	(4,477)	(4,477)	-	(4,477)	-	-	-	-	-	-
At December 31, 2015	40,721	21,325	62,046	40,721	21,325	62,046	-	-	-	-	-	-

	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale Natural Gas⁽⁵⁾
			Proved +			Proved +			Proved +			Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
Factors	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)
At December 31, 2014	9,875	2,582	12,457	9,875	2,582	12,457	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	-	-	-	-	-	-	-	-	-
Technical Revisions	-	-	-	-	-	-	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	(1,686)	(1,023)	(2,709)	(1,686)	(1,023)	(2,709)	-	-	-	-	-	-
Production	(354)	-	(354)	(354)	-	(354)	-	-	-	-	-	-
At December 31, 2015	7,835	1,559	9,394	7,835	1,559	9,394	-	-	-	-	-	-

				Natural Gas Liquids						BOE
								Proved +						Proved +
Proved Probable P+P^{(1) (2)}				Proved		Probable		Probable		Proved		Probable		Probable
Factors				(Mbbl)		(Mbbl)		(Mbbl)		(Mboe)		(Mboe)		(Mboe)
At December 31, 2014				-		-		-		37,249		20,719		57,967
Discoveries				-		-		-		-		-		-
Extensions & Improved Recovery				-		-		-		4,328		2,465		6,794
Technical Revisions				-		-		-		5,268		(1,429)		3,839
Acquisitions				-		-		-		-		-		-
Dispositions				-		-		-		-		-		-
Economic Factors				-		-		-		(281)		(171)		(452)
Production				-		-		-		(4,537)		-		(4,537)
At December 31, 2015				-		-		-		42,027		21,585		63,612


					Light Crude Oil &
GERMANY	Total Oil⁽⁴⁾				Medium Crude Oil					Heavy Oil					Tight Oil
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)
At December 31, 2014	-	-	-		-		-		-	-	-		-		-	-	-
Discoveries	-	-	-		-		-		-	-	-		-		-	-	-
Extensions & Improved Recovery	-	-	-		-		-		-	-	-		-		-	-	-
Technical Revisions	-	-	-		-		-		-	-	-		-		-	-	-
Acquisitions	-	-	-		-		-		-	-	-		-		-	-	-
Dispositions	-	-	-		-		-		-	-	-		-		-	-	-
Economic Factors	-	-	-		-		-		-	-	-		-		-	-	-
Production	-	-	-		-		-		-	-	-		-		-	-	-
At December 31, 2015	-	-	-		-		-		-	-	-		-		-	-	-


	Total Gas⁽⁴⁾				Conventional Natural Gas					Coal Bed Methane⁽⁵⁾					Shale Natural Gas⁽⁵⁾
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)
At December 31, 2014	40,258	21,301	61,559		40,258		21,301		61,559	-	-		-		-	-	-
Discoveries	-	-	-		-		-		-	-	-		-		-	-	-
Extensions & Improved Recovery	2,546	(2,546)	-		2,546		(2,546)		-	-	-		-		-	-	-
Technical Revisions	(5,543)	(756)	(6,299)		(5,543)		(756)		(6,299)	-	-		-		-	-	-
Acquisitions	-	-	-		-		-		-	-	-		-		-	-	-
Dispositions	-	-	-		-		-		-	-	-		-		-	-	-
Economic Factors	-	-	-		-		-		-	-	-		-		-	-	-
Production	(5,761)	-	(5,761)		(5,761)		-		(5,761)	-	-		-		-	-	-
At December 31, 2015	31,500	17,999	49,499		31,500		17,999		49,499	-	-		-		-	-	-


	Natural Gas Liquids				BOE
			Proved +						Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mboe)		(Mboe)		(Mboe)
At December 31, 2014	-	-	-		6,710		3,550		10,260
Discoveries	-	-	-		-		-		-
Extensions & Improved Recovery	-	-	-		424		(424)		-
Technical Revisions	-	-	-		(924)		(126)		(1,050)
Acquisitions	-	-	-		-		-		-
Dispositions	-	-	-		-		-		-
Economic Factors	-	-	-		-		-		-
Production	-	-	-		(960)		-		(960)
At December 31, 2015	-	-	-		5,250		3,000		8,250


					Light Crude Oil &
IRELAND	Total Oil⁽⁴⁾				Medium Crude Oil					Heavy Oil					Tight Oil
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)
At December 31, 2014	-	-	-		-		-		-	-	-		-		-	-	-
Discoveries	-	-	-		-		-		-	-	-		-		-	-	-
Extensions & Improved Recovery	-	-	-		-		-		-	-	-		-		-	-	-
Technical Revisions	-	-	-		-		-		-	-	-		-		-	-	-
Acquisitions	-	-	-		-		-		-	-	-		-		-	-	-
Dispositions	-	-	-		-		-		-	-	-		-		-	-	-
Economic Factors	-	-	-		-		-		-	-	-		-		-	-	-
Production	-	-	-		-		-		-	-	-		-		-	-	-
At December 31, 2015	-	-	-		-		-		-	-	-		-		-	-	-


	Total Gas⁽⁴⁾				Conventional Natural Gas					Coal Bed Methane⁽⁵⁾					Shale Natural Gas⁽⁵⁾
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)
At December 31, 2014	105,931	38,707	144,638		105,931		38,707		144,638	-	-		-		-	-	-
Discoveries	-	-	-		-		-		-	-	-		-		-	-	-
Extensions & Improved Recovery	-	-	-		-		-		-	-	-		-		-	-	-
Technical Revisions	(99)	8,698	8,599		(99)		8,698		8,599	-	-		-		-	-	-
Acquisitions	-	-	-		-		-		-	-	-		-		-	-	-
Dispositions	-	-	-		-		-		-	-	-		-		-	-	-
Economic Factors	-	-	-		-		-		-	-	-		-		-	-	-
Production	(11)	-	(11)		(11)		-		(11)	-	-		-		-	-	-
At December 31, 2015	105,821	47,405	153,226		105,821		47,405		153,226	-	-		-		-	-	-


	Natural Gas Liquids				BOE
			Proved +						Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mboe)		(Mboe)		(Mboe)
At December 31, 2014	-	-	-		17,655		6,451		24,106
Discoveries	-	-	-		-		-		-
Extensions & Improved Recovery	-	-	-		-		-		-
Technical Revisions	-	-	-		(17)		1,450		1,434
Acquisitions	-	-	-		-		-		-
Dispositions	-	-	-		-		-		-
Economic Factors	-	-	-		-		-		-
Production	-	-	-		(2)		-		(2)
At December 31, 2015	-	-	-		17,637		7,901		25,538


					Light Crude Oil &
NETHERLANDS	Total Oil⁽⁴⁾				Medium Crude Oil					Heavy Oil					Tight Oil
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)
At December 31, 2014	-	-	-		-		-		-	-	-		-		-	-	-
Discoveries	-	-	-		-		-		-	-	-		-		-	-	-
Extensions & Improved Recovery	-	-	-		-		-		-	-	-		-		-	-	-
Technical Revisions	-	-	-		-		-		-	-	-		-		-	-	-
Acquisitions	-	-	-		-		-		-	-	-		-		-	-	-
Dispositions	-	-	-		-		-		-	-	-		-		-	-	-
Economic Factors	-	-	-		-		-		-	-	-		-		-	-	-
Production	-	-	-		-		-		-	-	-		-		-	-	-
At December 31, 2015	-	-	-		-		-		-	-	-		-		-	-	-


	Total Gas⁽⁴⁾				Conventional Natural Gas					Coal Bed Methane⁽⁵⁾					Shale Natural Gas⁽⁵⁾
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)
At December 31, 2014	37,155	47,076	84,231		37,155		47,076		84,231	-	-		-		-	-	-
Discoveries	17,405	2,880	20,285		17,405		2,880		20,285	-	-		-		-	-	-
Extensions & Improved Recovery	5,736	4,366	10,102		5,736		4,366		10,102	-	-		-		-	-	-
Technical Revisions	4,242	(5,634)	(1,392)		4,242		(5,634)		(1,392)	-	-		-		-	-	-
Acquisitions	-	-	-		-		-		-	-	-		-		-	-	-
Dispositions	-	-	-		-		-		-	-	-		-		-	-	-
Economic Factors	-	-	-		-		-		-	-	-		-		-	-	-
Production	(16,339)	-	(16,339)		(16,339)		-		(16,339)	-	-		-		-	-	-
At December 31, 2015	48,199	48,688	96,887		48,199		48,688		96,887	-	-		-		-	-	-


	Natural Gas Liquids				BOE
			Proved +						Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mboe)		(Mboe)		(Mboe)
At December 31, 2014	54	103	157		6,247		7,949		14,196
Discoveries	39	7	46		2,940		487		3,427
Extensions & Improved Recovery	7	6	13		963		734		1,697
Technical Revisions	24	(33)	(9)		731		(972)		(241)
Acquisitions	-	-	-		-		-		-
Dispositions	-	-	-		-		-		-
Economic Factors	-	-	-		-		-		-
Production	(36)	-	(36)		(2,759)		-		(2,758)
At December 31, 2015	88	83	171		8,122		8,198		16,320


					Light Crude Oil &
UNITED STATES	Total Oil⁽⁴⁾				Medium Crude Oil					Heavy Oil					Tight Oil
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)
At December 31, 2014	449	1,338	1,787		449		1,338		1,787	-	-		-		-	-	-
Discoveries	-	-	-		-		-		-	-	-		-		-	-	-
Extensions & Improved Recovery	1,367	1,324	2,691		1,367		1,324		2,691	-	-		-		-	-	-
Technical Revisions	106	370	476		106		370		476	-	-		-		-	-	-
Acquisitions	196	786	982		196		786		982	-	-		-		-	-	-
Dispositions	-	-	-		-		-		-	-	-		-		-	-	-
Economic Factors	-	-	-		-		-		-	-	-		-		-	-	-
Production	(84)	-	(84)		(84)		-		(84)	-	-		-		-	-	-
At December 31, 2015	2,034	3,818	5,852		2,034		3,818		5,852	-	-		-		-	-	-


	Total Gas⁽⁴⁾				Conventional Natural Gas					Coal Bed Methane⁽⁵⁾					Shale Natural Gas⁽⁵⁾
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)
At December 31, 2014	243	1,402	1,645		243		1,402		1,645	-	-		-		-	-	-
Discoveries	-	-	-		-		-		-	-	-		-		-	-	-
Extensions & Improved Recovery	1,453	1,569	3,022		1,453		1,569		3,022	-	-		-		-	-	-
Technical Revisions	274	507	781		274		507		781	-	-		-		-	-	-
Acquisitions	220	900	1,120		220		900		1,120	-	-		-		-	-	-
Dispositions	-	-	-		-		-		-	-	-		-		-	-	-
Economic Factors	-	-	-		-		-		-	-	-		-		-	-	-
Production	(18)	-	(18)		(18)		-		(18)	-	-		-		-	-	-
At December 31, 2015	2,170	4,378	6,548		2,170		4,378		6,548	-	-		-		-	-	-


	Natural Gas Liquids				BOE
			Proved +						Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mboe)		(Mboe)		(Mboe)
At December 31, 2014	10	58	68		500		1,630		2,129
Discoveries	-	-	-		-		-		-
Extensions & Improved Recovery	233	250	483		1,842		1,836		3,678
Technical Revisions	72	247	319		223		702		925
Acquisitions	35	143	178		267		1,079		1,346
Dispositions	-	-	-		-		-		-
Economic Factors	-	-	-		-		-		-
Production	(3)	-	(3)		(90)		-		(90)
At December 31, 2015	346	698	1,044		2,742		5,246		7,988


					Light Crude Oil &
TOTAL COMPANY	Total Oil⁽⁴⁾				Medium Crude Oil					Heavy Oil					Tight Oil
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)		(Mbbl)		(Mbbl)	(Mbbl)	(Mbbl)
At December 31, 2014	76,073	41,874	117,947		76,063		41,872		117,935	10	2		12		-	-	-
Discoveries	-	-	-		-		-		-	-	-		-		-	-	-
Extensions & Improved Recovery	7,440	6,381	13,821		7,440		6,381		13,821	-	-		-		-	-	-
Technical Revisions	8,178	(3,683)	4,496		8,166		(3,686)		4,480	(1)	1		-		13	3	16
Acquisitions	196	786	982		196		786		982	-	-		-		-	-	-
Dispositions	(9)	(4)	(13)		(9)		(4)		(13)	-	-		-		-	-	-
Economic Factors	(1,970)	(1,720)	(3,690)		(1,970)		(1,720)		(3,690)	-	-		-		-	-	-
Production	(10,398)	-	(10,398)		(10,395)		-		(10,395)	-	-		-		(3)	-	(3)
At December 31, 2015	79,510	43,635	123,145		79,491		43,629		123,120	9	3		12		10	3	13


	Total Gas⁽⁴⁾				Conventional Natural Gas					Coal Bed Methane⁽⁵⁾					Shale Natural Gas⁽⁵⁾
			Proved +						Proved +				Proved +				Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable	Proved	Probable		Probable		Proved	Probable	Probable
Factors	(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)
At December 31, 2014	370,876	252,100	622,976		347,054		241,649		588,703	22,260	10,031		32,291		1,562	420	1,982
Discoveries	17,405	2,880	20,285		17,405		2,880		20,285	-	-		-		-	-	-
Extensions & Improved Recovery	66,217	25,633	91,850		66,218		25,633		91,851	-	-		-		-	-	-
Technical Revisions	3,199	(4,958)	(1,760)		2,379		(5,013)		(2,635)	-	-		-		820	55	875
Acquisitions	2,153	11,724	13,877		2,153		11,724		13,877	-	-		-		-	-	-
Dispositions	(39)	(8,944)	(8,983)		(39)		(8,944)		(8,983)	-	-		-		-	-	-
Economic Factors	(15,422)	(20,338)	(35,760)		(4,036)		(15,224)		(19,260)	(11,386)	(5,114)		(16,500)		-	-	-
Production	(48,599)	-	(48,599)		(45,495)		-		(45,495)	(2,664)	-		(2,664)		(440)	-	(440)
At December 31, 2015	395,788	258,097	653,885		385,637		252,705		638,342	8,210	4,917		13,127		1,942	475	2,417


	Natural Gas Liquids				BOE
			Proved +						Proved +
Proved Probable P+P^{(1) (2)}	Proved	Probable	Probable		Proved		Probable		Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)		(Mboe)		(Mboe)		(Mboe)
At December 31, 2014	13,614	11,492	25,106		151,503		95,383		246,884
Discoveries	39	7	46		2,940		487		3,427
Extensions & Improved Recovery	3,299	3,005	6,304		21,775		13,659		35,433
Technical Revisions	(315)	(1,863)	(2,178)		8,397		(6,372)		2,026
Acquisitions	222	1,681	1,903		776		4,421		5,197
Dispositions	(2)	(193)	(195)		(18)		(1,688)		(1,705)
Economic Factors	(95)	(597)	(692)		(4,635)		(5,707)		(10,342)
Production	(1,533)	-	(1,533)		(20,032)		-		(20,031)
At December 31, 2015	15,229	13,532	28,761		160,706		100,184		260,889								.


Notes:
⁽¹⁾	"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
⁽²⁾	"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
⁽³⁾	The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
⁽⁴⁾	For reporting purposes, "Total Oil" is the sum of Light Crude oil and Medium Crude Oil, Heavy Oil and Tight Oil. For reporting purposes, "Total Gas" is the sum of Conventional Natural Gas, Coal Bed Methane and Shale Natural Gas.
⁽⁵⁾	"Coal Bed Methane" and "Shale Natural Gas" were considered "Unconventional Natural Gas" in previous years. NI 51-5101 no longer differentiates between conventional and unconventional activities.

The table below sets out the future development costs deducted in the estimation of future net revenue attributable to total proved reserves and total proved plus probable reserves (using forecast prices and costs).

Table 9: Future Development Costs⁽¹⁾

	Total Proved	Total Proved Plus Probable
(M$)	Estimated Using Forecast Prices and Costs	Estimated Using Forecast Prices and Costs
Australia
2016	52,820	52,820
2017	6,701	6,701
2018	51,052	51,052
2019	2,993	2,993
2020	3,052	3,052
Remainder	48,279	48,332
Total for all years undiscounted	164,897	164,950
Canada
2016	120,559	152,322
2017	98,902	170,944
2018	89,432	189,394
2019	45,342	136,985
2020	51,326	127,236
Remainder	24,026	53,245
Total for all years undiscounted	429,587	830,126
France
2016	47,099	79,711
2017	41,380	77,270
2018	12,751	76,088
2019	7,300	49,803
2020	15,570	24,985
Remainder	18,725	32,416
Total for all years undiscounted	142,825	340,273
Germany
2016	210	210
2017	159	159
2018	141	141
2019	6,936	6,936
2020	110	147
Remainder	1	1
Total for all years undiscounted	7,557	7,594
Ireland
2016	8,862	8,862
2017	1,321	1,321
2018	-	-
2019	1,826	1,826
2020	-	-
Remainder	17,112	17,112
Total for all years undiscounted	29,121	29,121
Netherlands
2016	1,487	5,150
2017	28,416	48,788
2018	1,076	15,274
2019	424	11,254
2020	433	433
Remainder	6,575	6,573
Total for all years undiscounted	38,411	87,472
United States
2016	11,034	30,362
2017	24,333	37,820
2018	9,397	40,819
2019	-	-
2020	-	-
Remainder	-	-
Total for all years undiscounted	44,764	109,001


Total Company
2016	242,071	329,437
2017	201,212	343,003
2018	163,849	372,768
2019	64,821	209,797
2020	70,491	155,853
Remainder	114,718	157,679
Total for all years undiscounted	857,162	1,568,537


Note:
⁽¹⁾	The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.

Vermilion expects to source its capital expenditure requirements from internally generated cash flow and, as appropriate, from Vermilion's existing credit facility or equity or debt financing. It is anticipated that costs of funding the future development costs will not impact development of its properties or Vermilion's reserves or future net revenue.

CONTINGENT RESOURCES

Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent resources across all of the Company's key operating regions with an effective date of December 31, 2015 (the "GLJ Resources Assessment"). All contingent resources evaluated in the GLJ Resources Assessment were deemed economic at the effective date of December 31, 2015.

A range of contingent resources estimates (low, best and high) were prepared by GLJ. See notes 6 to 8 of the tables below for a description of low estimate, best estimate and high estimate.

The GLJ Resources Assessment estimated contingent resources of 95.1 million boe (low estimate) to 254.7 million boe (high estimate), with a best estimate of 160.7 million boe. Contingent resources are in addition to reserves estimated in the GLJ Report.

An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.

Summary information regarding contingent resources and net present value of future net revenues from contingent resources are set forth below and are derived, in each case, from the GLJ Resources Assessment. The GLJ Resources Assessment was prepared in accordance with COGEH and NI-51-101 by GLJ, an independent qualified reserve evaluator.

Table 10: Summary of Risked Oil and Gas Contingent Resources as at December 31, 2015^{(1) (2)}- Forecast Prices and Costs^{(3) (4)}

																Unrisked
	Light Crude Oil &			Conventional			Coal Bed			Natural Gas			Oil			Oil
Resources	Medium Crude Oil			Natural Gas			Methane			Liquids			Equivalent			Equivalent
Project																Chance
Maturity		Gross	Net		Gross	Net		Gross	Net		Gross	Net		Gross	Net	of Dev.	Gross	Net
Sub-Class		(Mbbl)	(Mbbl)		(MMcf)	(MMcf)		(Mbbl)	(Mbbl)		(Mbbl)	(Mbbl)		(Mbbl)	(Mbbl)	(%)⁽⁹⁾	(Mbbl)	(Mbbl)
Contingent (1C) - Low Estimate
Development Pending
Australia⁽¹⁰⁾		-	-		-	-		-	-		-	-		-	-	-	-	-
Canada⁽¹¹⁾		15,733	11,470		216,245	186,486		3,537	3,360		15,457	11,988		67,820	55,099	81.5%	83,218	67,516
France⁽¹²⁾		12,604	11,853		1,020	1,020		-	-		-	-		12,774	12,023	87.8%	14,542	13,687
Germany		-	-		-	-		-	-		-	-		-	-	-	-	-
Ireland⁽¹³⁾		-	-		4,475	4,475		-	-		-	-		746	746	70.0%	1,065	1,065
Netherlands⁽¹⁴⁾		-	-		215	215		-	-		-	-		36	36	60.0%	60	60
USA⁽¹⁵⁾		10,099	8,314		11,178	9,202		-	-		1,782	1,467		13,744	11,315	90.0%	15,272	12,571
Total		38,436	31,637		233,133	201,398		3,537	3,360		17,239	13,455		95,120	79,219	83.3%	114,157	94,899
Contingent (2C) - Best Estimate
Development Pending
Australia⁽¹⁰⁾		3,000	3,000		-	-		-	-		-	-		3,000	3,000	80.0%	3,750	3,750
Canada⁽¹¹⁾		24,685	17,637		361,733	312,655		6,445	6,009		24,018	18,485		110,066	89,233	79.8%	138,003	111,976
France⁽¹²⁾		25,611	24,007		1,300	1,300		-	-		-	-		25,828	24,224	85.7%	30,138	28,255
Germany		-	-		-	-		-	-		-	-		-	-	-	-	-
Ireland⁽¹³⁾		-	-		6,859	6,859		-	-		-	-		1,143	1,143	70.0%	1,633	1,633
Netherlands⁽¹⁴⁾		-	-		4,739	4,739		-	-		3	3		793	793	60.0%	1,321	1,321
USA⁽¹⁵⁾		14,470	11,912		16,449	13,540		-	-		2,622	2,159		19,834	16,328	90.0%	22,038	18,141
Total		67,766	56,556		391,080	339,093		6,445	6,009		26,643	20,647		160,664	134,721	81.6%	196,883	165,076
Contingent (3C) - High Estimate
Development Pending
Australia⁽¹⁰⁾		4,040	4,040		-	-		-	-		-	-		4,040	4,040	80.0%	5,050	5,050
Canada⁽¹¹⁾		51,590	36,716		537,685	461,047		8,843	8,270		34,482	25,750		177,160	140,686	78.6%	225,319	179,007
France⁽¹²⁾		41,455	38,784		1,670	1,670		-	-		-	-		41,733	39,062	85.0%	49,114	45,950
Germany		-	-		-	-		-	-		-	-		-	-	-	-	-
Ireland⁽¹³⁾		-	-		10,671	10,671		-	-		-	-		1,779	1,779	70.0%	2,541	2,541
Netherlands⁽¹⁴⁾		-	-		9,294	9,294		-	-		6	6		1,555	1,555	60.0%	2,592	2,592
USA⁽¹⁵⁾		20,592	16,951		23,987	19,746		-	-		3,824	3,148		28,414	23,390	90.0%	31,571	25,988
Total		117,677	96,491		583,307	502,428		8,843	8,270		38,312	28,904		254,681	210,512	80.5%	316,187	261,128

Table 11: Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2015 - Forecast Prices and Costs⁽³⁾

Resources Project
Maturity Sub-Class	Before Income Taxes, Discounted at⁽⁵⁾						After Income Taxes, Discounted at⁽⁵⁾
(M$)		0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
Contingent (1C) -Low Estimate⁽⁶⁾
Development Pending
Australia		-	-	-	-	-	-	-	-	-	-
Canada		1,263,475	696,994	404,377	244,496	152,795	917,336	485,559	266,767	150,423	85,918
France		764,172	412,773	234,791	138,408	83,554	500,593	255,152	135,124	72,474	38,285
Germany		-	-	-	-	-	-	-	-	-	-
Ireland		10,759	6,832	3,908	1,827	388	10,759	6,832	3,908	1,827	388
Netherlands		321	288	235	183	139	(111)	(31)	(4)	1	(1)
USA		402,480	183,006	86,860	41,587	19,010	257,913	112,016	47,760	18,068	3,877
Total		2,441,207	1,299,893	730,171	426,501	255,886	1,686,490	859,528	453,555	242,793	128,467
Contingent (2C) -Best Estimate⁽⁷⁾
Development Pending
Australia		112,493	76,004	51,782	35,416	24,186	8,804	(933)	(6,457)	(9,465)	(10,961)
Canada		2,320,917	1,231,251	711,661	438,235	283,381	1,690,519	869,129	482,208	282,696	172,627
France		1,596,937	861,198	493,517	295,075	181,775	1,046,955	534,621	286,991	157,949	87,111
Germany		-	-	-	-	-	-	-	-	-	-
Ireland		34,337	24,293	16,560	11,029	7,171	25,752	18,634	12,872	8,618	5,581
Netherlands		17,580	12,005	8,041	5,233	3,236	8,618	5,315	2,916	1,218	28
USA		761,511	347,466	175,611	95,123	53,819	490,733	219,043	105,532	52,935	26,574
Total		4,843,775	2,552,217	1,457,172	880,111	553,568	3,271,381	1,645,809	884,062	493,951	280,960
Contingent (3C) -High Estimate⁽⁸⁾
Development Pending
Australia		213,428	151,220	109,414	80,640	60,405	40,896	22,363	11,003	3,988	(347)
Canada		4,528,849	2,254,759	1,249,423	745,486	469,386	3,301,748	1,601,403	857,791	491,549	295,260
France		2,789,003	1,489,072	858,593	521,966	329,664	1,828,488	934,880	512,726	293,550	172,056
Germany		-	-	-	-	-	-	-	-	-	-
Ireland		73,725	48,565	32,219	21,620	14,641	55,100	36,396	24,132	16,127	10,830
Netherlands		54,851	37,676	26,539	19,104	13,995	29,079	19,328	12,926	8,658	5,754
USA		1,306,063	569,626	289,610	162,255	96,886	844,550	363,515	179,660	96,592	54,589
Total		8,965,919	4,550,918	2,565,798	1,551,071	984,977	6,099,861	2,977,885	1,598,238	910,464	538,142

Notes:
⁽¹⁾	The contingent resource assessments were prepared by GLJ in accordance with the definitions, standards and procedures contained in the COGEH and NI 51-101. Contingent resource is defined in the COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated, as at a given date, and that the resources can be profitably produced in the future. The risked net present value of the future net revenue from the contingent resources does not necessarily represent the fair market value of the contingent resources. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein.
⁽²⁾	GLJ prepared the estimates of contingent resources shown for each property using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table.
⁽³⁾	The forecast price and cost assumptions utilized in the year-end 2015 reserves report were also utilized by GLJ in preparing the contingent resource assessments. See "GLJ December 31, 2015 Forecast Prices" in Vermilion's Annual Information Form for the year ended December 31, 2015.
⁽⁴⁾	"Gross" Contingent Resources are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net" Contingent Resources are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in Contingent Resources.
⁽⁵⁾	The risked net present value of future net revenue attributable to the contingent resources does not necessarily represent the fair market value of the contingent resources. Estimated abandonment and reclamation costs have been included in the evaluation.
⁽⁶⁾	This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
⁽⁷⁾	This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
⁽⁸⁾	This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
⁽⁹⁾	The Chance of Development (CoDev) is the estimated probability that, once discovered, a known accumulation will be commercially developed. Five factors have been considered in determining the CoDev as follows:
	· CoDev = Ps (Economic Factor) × Ps (Technology Factor) × Ps (Development Plan Factor) ×Ps (Development Timeframe Factor) × Ps (Other Contingency Factor) wherein · Ps is the probability of success · Economic Factor - For reserves to be assessed, a project must be economic. With respect to contingent resources, this factor captures uncertainty in the assessment of economic status principally due to uncertainty in cost estimates and marketing options. Economic viability uncertainty due to technology is more aptly captured with the Technology Factor. The Economic Factor will be 1 for reserves and will often be 1 for development pending and for projects with a development study or pre-development study with a robust rate of return. A robust rate of return means that the project retains economic status with variation in costs and/or marketing plans over the expected range of outcomes for these variables. · Technology Factor - For reserves to be assessed, a project must utilize established technology. With respect to contingent resources, this factor captures the uncertainty in the viability of the proposed technology for the subject reservoir, namely, the uncertainty associated with technology under development. By definition, technology under development is a recovery process or process improvement that has been determined to be technically viable via field test and is being field tested further to determine its economic viability in the subject reservoir. The Technology Factor will be 1 for reserves and for established technology. For technology under development, this factor will consider different risks associated with technologies being developed at the scale of the well versus the scale of a project and technologies which are being modified or extended for the subject reservoir versus new emerging technologies which have not previously been applied in any commercial application. The risk assessment will also consider the quality and sufficiency of the test data available, the ability to reliably scale such data and the ability to extrapolate results in time. · Development Plan Factor - For reserves to be assessed, a project must have a detailed development plan. With respect to contingent resources, this factor captures the uncertainty in the project evaluation scenario. The Development Plan Factor will be 1 for reserves and high, approaching 1, for development pending projects. This factor will consider development plan detail variations including the degree of delineation, reservoir specific development and operating strategy detail (technology decision, well layouts (spacing and pad locations), completion strategy, start-up strategy, water source and disposal, other infrastructure, facility design, marketing plans etc) and the quality of the cost estimates as provided by the developer. · Development Timeframe Factor - In the case of major projects, for reserves to be assessed, first major capital spending must be initiated within 5 years of the effective date. The Development Timeframe Factor will be 1 for reserves and will often be 1 for development pending provided the project is planned on-stream based on the same criteria used in the assessment of reserves. With respect to contingent resources, the factor will approach 1 for projects planned on-stream with a timeframe slightly longer than the limiting reserves criteria. · Other Contingency Factor - For reserves to be assessed, all contingencies must be eliminated. With respect to contingent resources, this factor captures major contingencies, usually beyond the control of the operator, other than those captured by economic status, technology status, project evaluation scenario status and the development timeframe. The Other Contingency Factor will be 1 for reserves and for development pending and less than 1 for on hold. Provided all contingencies have been identified and their resolution is reasonably certain, this factor would also be 1 for development unclarified. · These factors may be inter-related (dependent) and care has been taken to ensure that risks are appropriately accounted.
⁽¹⁰⁾	Contingent resources for Australia have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $171 MM and the expected timeline is between two and six years. The specific contingencies for these resources are Corporate Commitment and Development Timing.
⁽¹¹⁾	Contingent resources for Canada have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $1,234 MM and the expected timeline is between one and 10 years. The specific contingencies for these resources are Corporate Commitment and Development Timing.
⁽¹²⁾	Contingent resources for France have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $542 MM and the expected timeline is between two and 10 years. The specific contingencies for these resources are Corporate Commitment and Development Timing.
⁽¹³⁾	Contingent resources for Ireland have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $31 MM and the expected timeline is between three and four years. The specific contingencies for these resources are Corporate Commitment and Development Timing.
⁽¹⁴⁾	Contingent resources for Netherlands have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $14 MM and the expected timeline is between two and 10 years. The specific contingencies for these resources are Corporate Commitment and Development Timing.
⁽¹⁵⁾	Contingent resources for USA have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $278 MM and the expected timeline is between two and 10 years. The specific contingencies for these resources are Corporate Commitment and Development Timing.

ABOUT VERMILION

Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 7%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.

Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel equivalent of oil. Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas 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.

Fund flows from operations, netbacks and recycle ratio are measures that do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable with the calculations of similar measures for other entities. "Fund flows from operations" represents cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management considers fund flows from operations and fund flows from operations per share to be key measures as they demonstrate Vermilion's ability to generate the cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a useful measure of Vermilion's ability to generate cash that is not subject to short-term movements in non-cash operating working capital. "Recycle Ratio" means a measure of capital efficiency calculated by dividing the operating netback of production by the cost of adding reserves. "Netbacks" are per boe and per Mcf measures used in operational and capital allocation decisions. After-tax cash flow netbacks are calculated as cash flow from operating activities (determined in accordance with IFRS) expressed on a per boe basis.

SOURCE Vermilion Energy Inc.

PDF available at: http://stream1.newswire.ca/media/2016/02/29/20160229_C9877_DOC_EN_44637.pdf

%CIK: 0001293135

For further information:

Anthony Marino, President & COO;
Curtis W. Hicks, C.A., Executive VP & CFO; and/or
Dean Morrison, Director Investor Relations
TEL (403) 269-4884
IR TOLL FREE 1-866-895-8101
investor_relations@vermilionenergy.com
www.vermilionenergy.com

CO: Vermilion Energy Inc.

CNW 02:15e 29-FEB-16

Vermilion Energy (VET) 6-KVermilion Energy Inc. Announces 2015 Year-End Summary Reserves and Resource Information