Vermilion Energy Inc. Announces 2016 Year-end Summary Reserves and Resource Information

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Feb 27, 2017, 06:00 ET

CALGARY, Feb. 27, 2017 /CNW/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce summary 2016 year-end reserves and resource information. The estimates of reserves and resources and other oil and gas information contained in this news release have been estimated by GLJ Petroleum Consultants Ltd. ("GLJ") effective as at December 31, 2016 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, 2016, to be filed on February 27, 2017 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 9% to 175.8 mmboe⁽¹⁾, while total proved plus probable ("2P") reserves increased 11% to 290.1 mmboe⁽¹⁾. This represents year-over-year 1P and 2P per share reserves growth of 4% and 5%, respectively.
Finding and Development ("F&D")⁽²⁾ and Finding, Development and Acquisition ("FD&A")⁽²⁾ costs, including Future Development Capital ("FDC") for 2016 on a 2P basis decreased 38% to $5.57/boe and 34% to $6.62/boe, respectively. Our three-year F&D and FD&A costs, including FDC, on a 2P basis were $10.76/boe and $14.22/boe, respectively.
Achieved a further $33.7 million (2%) reduction in FDC costs (excluding FDC related to properties acquired during the year) due to additional reductions in drilling, completions and facility capital costs. FDC costs related to properties acquired during the year totalled $40.3 million.
Operating Recycle Ratio⁽³⁾ (including FDC) was 4.9x during 2016, an increase over the 3.6x achieved during 2015. The impact of lower commodity prices year-over-year was more than offset by lower F&D costs and per unit expenses. These improvements are a result of Vermilion's continued focus on cost reduction and investment efficiency.
In 2016, we added 52.5 mmboe of 2P reserves with 37.5 mmboe (70%) of additions coming from organic exploration and development ("E&D") activities and 15.0 mmboe (30%) of additions through acquisitions.
Replaced 161% of production at the 2P level through E&D related activities and 226% including acquisitions. At the 1P level, we replaced 119% and 165% of 2016 production, respectively.
Increased Proved Developed Producing ("PDP") reserves by 11% to 122.2 mmboe at an average F&D cost (including FDC) of $6.68/boe resulting in an Operating Recycle Ratio⁽³⁾ (including FDC) of 4.1x. PDP reserves represent 70% of 1P reserves.
Our independent GLJ 2016 Resource Assessment⁽⁴⁾ indicates risked low, best, and high estimates for contingent resources in the Development Pending category of 120.4⁽⁴⁾ mmboe, 198.5⁽⁴⁾ mmboe, and 309.4⁽⁴⁾ mmboe, representing increases of 27%, 24% and 21%, respectively, compared to our GLJ 2015 Resource Assessment⁽⁵⁾. The GLJ 2016 Resource Assessment also indicates risked low, best, and high estimates for contingent resources in the Development Unclarified category of 9.9⁽⁴⁾ mmboe, 19.5⁽⁴⁾ mmboe, and 28.7⁽⁴⁾ mmboe. Over 90% of our risked contingent resources reside in the Development Pending category, reflecting the high quality nature of our contingent resource base. Prospective resources were assessed at risked low, best and high estimates of 45.2⁽⁴⁾ mmboe, 89.5⁽⁴⁾ mmboe, and 147.9⁽⁴⁾ mmboe.
At year-end 2016, 2P reserves were comprised of 31% Brent-based light crude, 15% North American-based light crude, 11% natural gas liquids, 21% European natural gas and 22% North American natural gas.
Increased reserve life index for 2P reserves to 13.1 years for year-end 2016 reserves based on annualized Q4 2016 production, compared to 11.7 years at year-end 2015. Year-end 2016 reserve life index for 1P reserves increased to 7.9 years, as compared to 7.2 years at year-end 2015.
Ongoing technical work associated with the German asset acquisition announced in Q2 2016 resulted in the identification of an additional ten (6.3 net) locations and related 2P reserves of approximately 6.3 mmboe.
In our Mannville condensate and liquids-rich gas plays in Alberta we added, at the 2P level, an additional eight (7.0 net) undeveloped wells in the West Pembina area and nine (7.0 net) wells in the Ferrier area. The average net reserves additions per well were approximately 620 mboe/well in West Pembina and 850 mboe/well in Ferrier.
We added ten (9.0 net) 2P locations at an average of 350 mboe per well in our emerging Turner Sand light crude oil development project in the Powder River Basin in Wyoming.

⁽¹⁾	As evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 1, 2017 with an effective date of December 31, 2016.
⁽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 expenditures 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⁾	"Operating Recycle Ratio" is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). "Operating Netback" is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis.
⁽⁴⁾	Vermilion retained GLJ to conduct an independent resource evaluation dated February 1, 2017 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2016 (the "GLJ 2016 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 84%, 83% and 82%, respectively. The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Unclarified category are 55%, 54% and 55%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 25%, 26% and 26%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources.
⁽⁵⁾	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 aggregate 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. For further information, see the "Contingent Resources" section of this news release.

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, 2016 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 1, 2017 with an effective date of December 31, 2016 (the "GLJ 2016 Reserves Evaluation"). The GLJ 2016 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, 2016 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 2016 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 2016 Reserve Evaluation. There is no assurance that the future price and cost assumptions used in the GLJ 2016 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 & Medium Crude Oil			Crude Oil	Conventional Natural Gas Canada	Conventional Natural Gas Europe	Natural Gas Liquids	Inflation Rate	Exchange Rate	Exchange 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)
2016	43.30	52.95	48.71	45.01	2.19	4.65	34.50	1.50	0.76	1.47
Forecast
2017	55.00	69.33	64.48	57.00	3.46	5.75	40.40	2.00	0.75	1.40
2018	59.00	72.26	67.20	61.00	3.10	6.00	41.41	2.00	0.78	1.35
2019	64.00	75.00	69.75	66.00	3.27	6.25	42.94	2.00	0.80	1.31
2020	67.00	76.36	71.02	70.00	3.49	6.50	43.77	2.00	0.83	1.27
2021	71.00	78.82	73.31	74.00	3.67	6.75	45.24	2.00	0.85	1.24
2022	74.00	82.35	76.59	77.00	3.86	6.89	47.30	2.00	0.85	1.24
2023	77.00	85.88	79.87	80.00	4.05	7.02	49.25	2.00	0.85	1.24
2024	80.00	89.41	83.15	83.00	4.16	7.16	51.23	2.00	0.85	1.24
2025	83.00	92.94	86.44	86.00	4.24	7.31	53.42	2.00	0.85	1.24
2026	86.05	95.61	88.92	89.64	4.32	7.45	54.80	2.00	0.85	1.24
Thereafter	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	2.0%	0.850	1.235


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 2016, the price of crude oil in the United States is based on WTI. The benchmark price for Canadian crude oil is Edmonton Par and Canadian natural gas is priced against AECO. The benchmark price for Australia and France crude oil is Dated Brent. The price of our natural gas in Ireland is based on the NBP index. 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. The price of Vermilion's natural gas in Germany is based on the TTF, as determined on the Title Transfer Facility Virtual Trading Point. For the year ended December 31, 2016, the average realized sales prices before hedging were $46.89 per bbl (United States) for WTI, $43.58 per bbl for Canadian-based crude oil, condensate and NGLs and $2.14 per Mcf for Canadian natural gas, $60.33 per bbl (Australia), $55.42 per bbl (France) for Brent-based crude oil, $5.86 per Mcf (Ireland), $5.67 per Mcf (Netherlands), and $5.33 per Mcf (Germany).

The following table summarizes the capital expenditures made by Vermilion on oil and natural gas properties for the year ended December 31, 2016:

Table 2: Capital Costs Incurred

	Acquisition Costs
	Proved	Unproved	Exploration	Development	Total
(M$)	Properties	Properties	Costs	Costs	Costs
Australia	-	-	-	59,910	59,910
Canada	13,309	-	-	62,706	76,015
Croatia	-	-	2,968	-	2,968
France	-	-	-	68,472	68,472
Germany	48,377	-	-	3,803	52,180
Hungary	-	-	338	-	338
Ireland	-	-	-	9,375	9,375
Netherlands	28,259	-	-	23,740	51,999
United States	5,935	-	-	13,539	19,474
Total	95,880	-	3,306	241,545	340,731

The following table sets forth the reserve life index based on total proved and proved plus probable reserve and fourth quarter 2016 production of 60,863 boe/d.

Table 3: Reserve Life Index

Commodity	Production	Reserve Life Index (years)
	Fourth Quarter 2016	Total Proved	Proved Plus Probable
Crude oil, condensate and natural gas liquids (bbl/d)	28,439	9.9	15.9
Natural gas (mmcf/d)	194.54	6.2	10.6
Oil Equivalent (boe/d)	60,863	7.9	13.1

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	10,718	10,718	-	-	-	-	-	-
Canada	12,277	10,990	-	-	12	8	112,918	101,728
France	36,481	33,478	-	-	-	-	5,412	5,024
Germany	4,805	4,706	-	-	-	-	30,892	27,510
Ireland	-	-	-	-	-	-	95,861	95,861
Netherlands	-	-	-	-	-	-	41,494	29,860
United States	699	551	-	-	-	-	696	552
Total Proved Developed Producing	64,980	60,443	-	-	12	8	287,273	260,535
	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	-	-	-	-	-	-	10,718	10,718
Canada	1,371	1,291	2,482	2,275	8,484	6,395	40,235	34,942
France	-	-	-	-	-	-	37,383	34,315
Germany	-	-	-	-	-	-	9,954	9,291
Ireland	-	-	-	-	-	-	15,977	15,977
Netherlands	-	-	-	-	59	59	6,975	5,036
United States	-	-	-	-	97	76	912	719
	1,371	1,291	2,482	2,275	8,640	6,530	122,154	110,998
	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 Developed Non-Producing
Australia	700	700	-	-	-	-	-	-
Canada	1,008	874	-	-	-	-	24,705	22,319
France	1,814	1,666	-	-	-	-	-	-
Germany	240	230	-	-	-	-	8,227	7,389
Ireland	-	-	-	-	-	-	-	-
Netherlands	-	-	-	-	-	-	17,815	15,327
United States	-	-	-	-	-	-	-	-
Total Proved Developed Non-Producing	3,762	3,470	-	-	-	-	50,747	45,035
	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	-	-	-	-	-	-	700	700
Canada	-	-	2,536	2,389	1,649	1,283	7,197	6,275
France	-	-	-	-	-	-	1,814	1,666
Germany	-	-	-	-	-	-	1,611	1,462
Ireland	-	-	-	-	-	-	-	-
Netherlands	-	-	-	-	21	21	2,990	2,576
United States	-	-	-	-	-	-	-	-
Total Proved Developed Non-Producing	-	-	2,536	2,389	1,670	1,304	14,312	12,679
	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	1,000	1,000	-	-	-	-	-	-
Canada	8,677	7,595	-	-	-	-	79,475	71,420
France	3,749	3,506	-	-	-	-	70	70
Germany	243	237	-	-	-	-	2,361	1,918
Ireland	-	-	-	-	-	-	3,714	3,714
Netherlands	-	-	-	-	-	-	3,041	3,041
United States	2,470	2,019	-	-	-	-	2,273	1,858
Total Proved Undeveloped	16,139	14,357	-	-	-	-	90,934	82,021
	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	-	-	-	-	-	-	1,000	1,000
Canada	-	-	3,043	2,812	7,230	5,541	29,660	25,508
France	-	-	-	-	-	-	3,761	3,518
Germany	-	-	-	-	-	-	637	557
Ireland	-	-	-	-	-	-	619	619
Netherlands	-	-	-	-	1	1	508	508
United States	-	-	-	-	315	258	3,164	2,587
Total Proved Undeveloped	-	-	3,043	2,812	7,546	5,800	39,349	34,297
	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	12,418	12,418	-	-	-	-	-	-
Canada	21,962	19,460	-	-	12	8	217,098	195,467
France	42,044	38,650	-	-	-	-	5,482	5,094
Germany	5,288	5,173	-	-	-	-	41,480	36,817
Ireland	-	-	-	-	-	-	99,575	99,575
Netherlands	-	-	-	-	-	-	62,350	48,228
United States	3,169	2,570	-	-	-	-	2,969	2,410
Total Proved	84,881	78,271	-	-	12	8	428,954	387,591
	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	-	-	-	-	-	-	12,418	12,418
Canada	1,371	1,291	8,061	7,476	17,363	13,219	77,092	66,725
France	-	-	-	-	-	-	42,958	39,499
Germany	-	-	-	-	-	-	12,202	11,310
Ireland	-	-	-	-	-	-	16,596	16,596
Netherlands	-	-	-	-	81	81	10,473	8,120
United States	-	-	-	-	412	334	4,076	3,306
Total Proved	1,371	1,291	8,061	7,476	17,856	13,634	175,815	157,974
	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	4,650	4,650	-	-	-	-	-	-
Canada	14,103	12,146	-	-	2	1	151,707	135,215
France	21,933	20,261	-	-	-	-	892	884
Germany	2,279	2,238	-	-	-	-	54,284	47,482
Ireland	-	-	-	-	-	-	50,787	50,787
Netherlands	-	-	-	-	-	-	43,184	33,118
United States	5,727	4,716	-	-	-	-	5,481	4,512
Total Probable	48,692	44,011	-	-	2	1	306,335	271,998
	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	-	-	-	-	-	-	4,650	4,650
Canada	284	267	4,677	4,395	12,907	9,730	53,123	45,190
France	-	-	-	-	-	-	22,082	20,408
Germany	-	-	-	-	-	-	11,326	10,152
Ireland	-	-	-	-	-	-	8,465	8,465
Netherlands	-	-	-	-	63	56	7,260	5,576
United States	-	-	-	-	760	625	7,401	6,093
Total Probable	284	267	4,677	4,395	13,730	10,411	114,307	100,534
	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	17,068	17,068	-	-	-	-	-	-
Canada	36,065	31,606	-	-	14	9	368,805	330,682
France	63,977	58,911	-	-	-	-	6,374	5,978
Germany	7,567	7,411	-	-	-	-	95,764	84,299
Ireland	-	-	-	-	-	-	150,362	150,362
Netherlands	-	-	-	-	-	-	105,534	81,346
United States	8,896	7,286	-	-	-	-	8,450	6,922
Total Proved Plus Probable	133,573	122,282	-	-	14	9	735,289	659,589
	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	-	-	-	-	-	-	17,068	17,068
Canada	1,655	1,558	12,738	11,871	30,270	22,949	130,215	111,915
France	-	-	-	-	-	-	65,040	59,907
Germany	-	-	-	-	-	-	23,528	21,462
Ireland	-	-	-	-	-	-	25,061	25,061
Netherlands	-	-	-	-	144	137	17,733	13,696
United States	-	-	-	-	1,172	959	11,477	9,399
Total Proved Plus Probable	1,655	1,558	12,738	11,871	31,586	24,045	290,122	258,508


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	134,236	217,117	240,607	240,546	231,618	164,830	197,187	199,187	190,432	178,594
Canada	963,690	777,268	645,191	553,740	487,804	963,690	777,268	645,191	553,740	487,804
France	2,009,158	1,404,527	1,073,623	871,502	736,836	1,664,358	1,169,631	894,523	725,047	611,642
Germany	193,385	187,330	161,141	138,822	121,707	193,385	187,330	161,141	138,822	121,707
Ireland	471,720	441,671	396,917	356,653	323,302	471,720	441,671	396,917	356,653	323,302
Netherlands	76,272	86,832	91,069	92,068	91,365	65,732	76,545	81,019	82,239	81,743
United States	29,716	23,345	19,334	16,637	14,710	29,716	23,345	19,334	16,637	14,710
Total Proved Developed Producing	3,878,177	3,138,090	2,627,882	2,269,968	2,007,342	3,553,431	2,872,977	2,397,312	2,063,570	1,819,502
Proved Developed Non-Producing^{(2) (4) (6)}
Australia	31,411	35,177	32,247	28,181	24,473	31,411	35,177	32,247	28,181	24,473
Canada	147,607	108,964	87,413	73,769	64,329	147,607	108,964	87,413	73,769	64,329
France	87,674	71,387	60,449	52,665	46,857	60,567	49,131	41,376	35,850	31,732
Germany	41,121	29,470	21,864	16,769	13,244	41,121	29,470	21,864	16,769	13,244
Ireland	-	-	-	-	-	-	-	-	-	-
Netherlands	46,907	45,115	42,066	38,740	35,545	33,688	32,489	29,973	27,127	24,367
United States	-	-	-	-	-	-	-	-	-	-
Total Proved Developed Non-Producing	354,720	290,113	244,039	210,124	184,448	314,394	255,231	212,873	181,696	158,145
Proved Undeveloped^{(2) (7)}
Australia	34,323	24,134	16,832	11,574	7,761	12,618	2,648	(1,772)	(3,929)	(5,057)
Canada	569,308	368,599	249,906	175,120	125,532	416,577	282,567	199,226	144,148	106,013
France	187,253	137,261	104,175	81,348	64,957	129,800	91,741	66,604	49,467	37,335
Germany	18,403	11,756	7,584	4,902	3,130	18,403	11,756	7,584	4,902	3,130
Ireland	12,873	9,337	6,763	4,894	3,536	12,873	9,337	6,763	4,894	3,536
Netherlands	10,896	9,095	7,611	6,411	5,443	8,160	6,584	5,294	4,263	3,443
United States	72,284	38,191	20,027	9,645	3,348	72,284	38,191	20,027	9,645	3,348
Total Proved Undeveloped	905,340	598,373	412,898	293,894	213,707	670,715	442,824	303,726	213,390	151,748
Proved⁽²⁾
Australia	199,970	276,428	289,686	280,301	263,852	208,859	235,012	229,662	214,684	198,010
Canada	1,680,605	1,254,831	982,510	802,629	677,665	1,527,874	1,168,799	931,830	771,657	658,146
France	2,284,085	1,613,175	1,238,247	1,005,515	848,650	1,854,725	1,310,503	1,002,503	810,364	680,709
Germany	252,909	228,556	190,589	160,493	138,081	252,909	228,556	190,589	160,493	138,081
Ireland	484,593	451,008	403,680	361,547	326,838	484,593	451,008	403,680	361,547	326,838
Netherlands	134,075	141,042	140,746	137,219	132,353	107,580	115,618	116,286	113,629	109,553
United States	102,000	61,536	39,361	26,282	18,058	102,000	61,536	39,361	26,282	18,058
Total Proved	5,138,237	4,026,576	3,284,819	2,773,986	2,405,497	4,538,540	3,571,032	2,913,911	2,458,656	2,129,395
Probable⁽³⁾
Australia	198,227	163,180	128,734	101,649	81,484	107,201	87,874	68,562	53,406	42,201
Canada	1,372,807	814,946	539,761	384,694	288,798	1,009,708	591,846	389,432	277,104	208,604
France	1,378,689	734,502	464,026	323,290	239,221	974,931	502,379	305,000	203,471	143,693
Germany	336,322	208,119	130,651	86,473	59,902	248,590	162,713	105,566	71,859	51,003
Ireland	354,566	235,805	167,862	126,297	99,303	354,566	235,805	167,862	126,297	99,303
Netherlands	162,029	137,048	115,870	98,750	85,096	111,908	92,487	75,843	62,469	51,946
United States	270,229	147,720	90,240	59,467	41,247	175,706	98,838	61,958	41,765	29,522
Total Probable	4,072,869	2,441,320	1,637,144	1,180,620	895,051	2,982,610	1,771,942	1,174,223	836,371	626,272
Proved Plus Probable^{(2) (3)}
Australia	398,197	439,608	418,420	381,950	345,336	316,060	322,886	298,224	268,090	240,211
Canada	3,053,412	2,069,777	1,522,271	1,187,323	966,463	2,537,582	1,760,645	1,321,262	1,048,761	866,750
France	3,662,774	2,347,677	1,702,273	1,328,805	1,087,871	2,829,656	1,812,882	1,307,503	1,013,835	824,402
Germany	589,231	436,675	321,240	246,966	197,983	501,499	391,269	296,155	232,352	189,084
Ireland	839,159	686,813	571,542	487,844	426,141	839,159	686,813	571,542	487,844	426,141
Netherlands	296,104	278,090	256,616	235,969	217,449	219,488	208,105	192,129	176,098	161,499
United States	372,229	209,256	129,601	85,749	59,305	277,706	160,374	101,319	68,047	47,580
Total Proved Plus Probable	9,211,106	6,467,896	4,921,963	3,954,606	3,300,548	7,521,150	5,342,974	4,088,134	3,295,027	2,755,667


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	1,130,774	-	585,013	98,280	247,512	199,969	(8,890)	208,859
Canada	3,767,788	508,170	1,060,685	421,548	96,780	1,680,605	152,731	1,527,874
France	3,892,917	309,696	1,017,941	123,472	157,722	2,284,086	429,361	1,854,725
Germany	812,577	43,400	383,854	12,267	120,147	252,909	-	252,909
Ireland	755,793	-	174,058	35,412	61,729	484,594	-	484,594
Netherlands	523,311	103,758	197,686	22,639	65,154	134,074	26,495	107,579
United States	297,606	83,116	48,860	60,639	2,991	102,000	-	102,000
Total Proved	11,180,766	1,048,140	3,468,097	774,257	752,035	5,138,237	599,697	4,538,540
Proved Plus Probable^{(2) (3)}
Australia	1,611,584	-	777,207	175,660	260,522	398,197	82,137	316,060
Canada	6,601,327	949,111	1,699,340	774,361	125,102	3,053,413	515,831	2,537,582
France	6,232,560	486,688	1,560,331	317,562	205,205	3,662,774	833,118	2,829,656
Germany	1,534,267	102,937	592,967	88,681	160,451	589,231	87,732	501,499
Ireland	1,208,966	-	272,665	35,412	61,729	839,159	-	839,159
Netherlands	887,526	181,892	286,933	45,647	76,950	296,104	76,616	219,488
United States	888,444	241,131	130,837	137,814	6,434	372,229	94,523	277,706
Total Proved Plus Probable	18,964,674	1,961,759	5,320,280	1,575,137	896,393	9,211,107	1,689,957	7,521,150


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⁾	1,869,323	28.43
Heavy Oil⁽³⁾	-	-
Conventional Natural gas⁽⁴⁾	755,799	16.95
Shale Gas	1,928	6.93
Coal Bed Methane	832	2.19
Total Proved Developed Producing	2,627,882	23.68
Proved Developed Non-Producing
Light crude oil & medium crude oil⁽³⁾	119,652	32.00
Heavy Oil⁽³⁾	-	-
Conventional Natural gas⁽⁴⁾	123,922	14.51
Shale Gas	-	-
Coal Bed Methane	465	1.17
Total Proved Developed Non-Producing	244,039	19.25
Proved Undeveloped
Light crude oil & medium crude oil⁽³⁾	279,927	14.84
Heavy Oil⁽³⁾	-	-
Conventional Natural gas⁽⁴⁾	132,343	8.84
Shale Gas	-	-
Coal Bed Methane	628	1.34
Total Proved Undeveloped	412,898	12.04
Proved
Light crude oil & medium crude oil⁽³⁾	2,268,902	25.72
Heavy Oil⁽³⁾	-	-
Conventional Natural gas⁽⁴⁾	1,012,064	14.82
Shale Gas	1,928	6.97
Coal Bed Methane	1,925	1.53
Total Proved	3,284,819	20.79
Probable
Light crude oil & medium crude oil⁽³⁾	1,044,229	20.31
Heavy Oil⁽³⁾	-	-
Conventional Natural gas⁽⁴⁾	590,638	12.22
Shale Gas	357	6.26
Coal Bed Methane	1,920	2.62
Total Probable	1,637,144	16.28
Proved Plus Probable
Light crude oil & medium crude oil⁽³⁾	3,313,131	23.76
Heavy Oil⁽³⁾	-	-
Conventional Natural gas⁽⁴⁾	1,602,702	13.70
Shale Gas	2,285	6.93
Coal Bed Methane	3,845	1.91
Total Proved Plus Probable	4,921,963	19.04


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 product type have been allocated proportionately to the specified product types. 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, 2016 compared to such reserves as at December 31, 2015.

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, 2015	13,765	3,700	17,465	13,765	3,700	17,465	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	700	1,300	2,000	700	1,300	2,000	-	-	-	-	-	-
Technical Revisions	260	(350)	(90)	260	(350)	(90)	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-	-	-	-
Production	(2,307)	-	(2,307)	(2,307)	-	(2,307)	-	-	-	-	-	-
At December 31, 2016	12,418	4,650	17,068	12,418	4,650	17,068	-	-	-	-	-	-
	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale 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, 2015	-	-	-	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	-	-	-	-	-	-	-	-	-
Technical Revisions	-	-	-	-	-	-	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-	-	-	-
Production	-	-	-	-	-	-	-	-	-	-	-	-
At December 31, 2016	-	-	-	-	-	-	-	-	-	-	-	-
	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, 2015	-	-	-	13,765	3,700	17,465
Discoveries	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	700	1,300	2,000
Technical Revisions	-	-	-	260	(350)	(90)
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-
Production	-	-	-	(2,307)	-	(2,307)
At December 31, 2016	-	-	-	12,418	4,650	17,068

				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, 2015	22,990	14,792	37,782	22,971	14,786	37,757	9	3	12	10	3	13
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	620	281	901	620	281	901	-	-	-	-	-	-
Technical Revisions	611	(1,284)	(673)	616	(1,280)	(664)	(9)	(3)	(12)	4	(1)	3
Acquisitions	206	317	523	206	317	523	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	(15)	(1)	(16)	(15)	(1)	(16)	-	-	-	-	-	-
Production	(2,438)	-	(2,438)	(2,436)	-	(2,436)	-	-	-	(2)	-	(2)
At December 31, 2016	21,974	14,105	36,079	21,962	14,103	36,065	-	-	-	12	2	14
	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale 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, 2015	200,263	138,068	338,331	190,111	132,676	322,787	8,210	4,917	13,127	1,942	475	2,417
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	18,401	20,608	39,009	18,401	20,608	39,009	-	-	-	-	-	-
Technical Revisions	27,342	(8,022)	19,320	26,058	(7,696)	18,362	1,394	(135)	1,259	(110)	(191)	(301)
Acquisitions	13,078	6,758	19,836	13,006	6,671	19,677	72	87	159	-	-	-
Dispositions	(353)	(132)	(485)	(353)	(132)	(485)	-	-	-	-	-	-
Economic Factors	(1,351)	(612)	(1,963)	(649)	(420)	(1,069)	(702)	(192)	(894)	-	-	-
Production	(30,850)	-	(30,850)	(29,476)	-	(29,476)	(913)	-	(913)	(461)	-	(461)
At December 31, 2016	226,530	156,668	383,198	217,098	151,707	368,805	8,061	4,677	12,738	1,371	284	1,655
	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, 2015	14,795	12,751	27,546	71,162	50,554	121,717
Discoveries	-	-	-	-	-	-
Extensions & Improved Recovery	1,412	825	2,237	5,099	4,541	9,640
Technical Revisions	2,004	(1,088)	916	7,172	(3,709)	3,463
Acquisitions	1,045	471	1,516	3,431	1,914	5,345
Dispositions	(8)	(3)	(11)	(67)	(25)	(92)
Economic Factors	(31)	(49)	(80)	(271)	(152)	(423)
Production	(1,854)	-	(1,854)	(9,434)	-	(9,434)
At December 31, 2016	17,363	12,907	30,270	77,092	53,123	130,215

				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, 2015	40,721	21,325	62,046	40,721	21,325	62,046	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	2,279	314	2,593	2,279	314	2,593	-	-	-	-	-	-
Technical Revisions	3,445	319	3,764	3,445	319	3,764	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	(47)	(25)	(72)	(47)	(25)	(72)	-	-	-	-	-	-
Production	(4,354)	-	(4,354)	(4,354)	-	(4,354)	-	-	-	-	-	-
At December 31, 2016	42,044	21,933	63,977	42,044	21,933	63,977	-	-	-	-	-	-
	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale 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, 2015	7,835	1,559	9,394	7,835	1,559	9,394	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	-	-	-	-	-	-	-	-	-
Technical Revisions	(2,170)	(654)	(2,824)	(2,170)	(654)	(2,824)	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	(20)	(13)	(33)	(20)	(13)	(33)	-	-	-	-	-	-
Production	(163)	-	(163)	(163)	-	(163)	-	-	-	-	-	-
At December 31, 2016	5,482	892	6,374	5,482	892	6,374	-	-	-	-	-	-
	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, 2015	-	-	-	42,027	21,585	63,612
Discoveries	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	2,279	314	2,593
Technical Revisions	-	-	-	3,083	210	3,293
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	-	-	-	(50)	(27)	(77)
Production	-	-	-	(4,381)	-	(4,381)
At December 31, 2016	-	-	-	42,958	22,082	65,040

				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, 2015	-	-	-	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	244	755	999	244	755	999	-	-	-	-	-	-
Technical Revisions	-	-	-	-	-	-	-	-	-	-	-	-
Acquisitions	5,044	1,524	6,568	5,044	1,524	6,568	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-	-	-	-
Production	-	-	-	-	-	-	-	-	-	-	-	-
At December 31, 2016	5,288	2,279	7,567	5,288	2,279	7,567	-	-	-	-	-	-
	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale 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, 2015	31,500	17,999	49,499	31,500	17,999	49,499	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	-	33,249	33,249	-	33,249	33,249	-	-	-	-	-	-
Technical Revisions	4,250	(898)	3,352	4,250	(898)	3,352	-	-	-	-	-	-
Acquisitions	11,182	3,934	15,116	11,182	3,934	15,116	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-	-	-	-
Production	(5,452)	-	(5,452)	(5,452)	-	(5,452)	-	-	-	-	-	-
At December 31, 2016	41,480	54,284	95,764	41,480	54,284	95,764	-	-	-	-	-	-
	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, 2015	-	-	-	5,250	3,000	8,250
Discoveries	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	244	6,297	6,541
Technical Revisions	-	-	-	708	(150)	559
Acquisitions	-	-	-	6,909	2,179	9,087
Dispositions	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-
Production	-	-	-	(909)	-	(909)
At December 31, 2016	-	-	-	12,202	11,326	23,528

				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, 2015	-	-	-	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	-	-	-	-	-	-	-	-	-
Technical Revisions	-	-	-	-	-	-	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-	-	-	-
Production	-	-	-	-	-	-	-	-	-	-	-	-
At December 31, 2016	-	-	-	-	-	-	-	-	-	-	-	-
	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale 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, 2015	105,821	47,405	153,226	105,821	47,405	153,226	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	3,714	2,718	6,432	3,714	2,718	6,432	-	-	-	-	-	-
Technical Revisions	8,610	721	9,331	8,610	721	9,331	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	57	(57)	-	57	(57)	-	-	-	-	-	-	-
Production	(18,627)	-	(18,627)	(18,627)	-	(18,627)	-	-	-	-	-	-
At December 31, 2016	99,575	50,787	150,362	99,575	50,787	150,362	-	-	-	-	-	-
	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, 2015	-	-	-	17,637	7,901	25,538
Discoveries	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	619	453	1,072
Technical Revisions	-	-	-	1,435	121	1,556
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	-	-	-	10	(10)	-
Production	-	-	-	(3,105)	-	(3,105)
At December 31, 2016	-	-	-	16,596	8,465	25,061

				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, 2015	-	-	-	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	-	-	-	-	-	-	-	-	-	-	-	-
Technical Revisions	-	-	-	-	-	-	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-	-	-	-
Production	-	-	-	-	-	-	-	-	-	-	-	-
At December 31, 2016	-	-	-	-	-	-	-	-	-	-	-	-
	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale 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, 2015	48,199	48,688	96,887	48,199	48,688	96,887	-	-	-	-	-	-
Discoveries	233	145	378	233	145	378	-	-	-	-	-	-
Extensions & Improved Recovery	8,104	8,782	16,886	8,104	8,782	16,886	-	-	-	-	-	-
Technical Revisions	20,790	(15,818)	4,972	20,790	(15,818)	4,972	-	-	-	-	-	-
Acquisitions	2,654	1,446	4,100	2,654	1,446	4,100	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	(128)	(59)	(187)	(128)	(59)	(187)	-	-	-	-	-	-
Production	(17,502)	-	(17,502)	(17,502)	-	(17,502)	-	-	-	-	-	-
At December 31, 2016	62,350	43,184	105,534	62,350	43,184	105,534	-	-	-	-	-	-
	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, 2015	88	83	171	8,122	8,198	16,320
Discoveries	1	1	2	40	25	65
Extensions & Improved Recovery	3	7	10	1,353	1,470	2,823
Technical Revisions	17	(31)	(14)	3,482	(2,667)	815
Acquisitions	5	3	8	447	244	691
Dispositions	-	-	-	-	-	-
Economic Factors	(1)	(0)	(1)	(22)	(10)	(32)
Production	(32)	-	(32)	(2,949)	-	(2,949)
At December 31, 2016	81	63	144	10,473	7,260	17,733

				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, 2015	2,034	3,818	5,852	2,034	3,818	5,852	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	1,105	1,644	2,749	1,105	1,644	2,749	-	-	-	-	-	-
Technical Revisions	178	271	449	178	271	449	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	(4)	(6)	(10)	(4)	(6)	(10)	-	-	-	-	-	-
Production	(144)	-	(144)	(144)	-	(144)	-	-	-	-	-	-
At December 31, 2016	3,169	5,727	8,896	3,169	5,727	8,896	-	-	-	-	-	-
	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale 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, 2015	2,170	4,378	6,548	2,170	4,378	6,548	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	1,011	1,578	2,589	1,011	1,578	2,589	-	-	-	-	-	-
Technical Revisions	(129)	(460)	(589)	(129)	(460)	(589)	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	(6)	(15)	(21)	(6)	(15)	(21)	-	-	-	-	-	-
Production	(77)	-	(77)	(77)	-	(77)	-	-	-	-	-	-
At December 31, 2016	2,969	5,481	8,450	2,969	5,481	8,450	-	-	-	-	-	-
	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, 2015	346	698	1,044	2,742	5,246	7,988
Discoveries	-	-	-	-	-	-
Extensions & Improved Recovery	141	219	360	1,415	2,127	3,541
Technical Revisions	(62)	(155)	(217)	94	39	134
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	(2)	(2)	(4)	(7)	(11)	(18)
Production	(11)	-	(11)	(168)	-	(168)
At December 31, 2016	412	760	1,172	4,076	7,401	11,477

				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, 2015	79,510	43,635	123,145	79,491	43,629	123,120	9	3	12	10	3	13
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions & Improved Recovery	4,948	4,294	9,242	4,948	4,294	9,242	-	-	-	-	-	-
Technical Revisions	4,492	(1,044)	3,450	4,499	(1,040)	3,459	(9)	(3)	(12)	4	(1)	3
Acquisitions	5,250	1,841	7,091	5,250	1,841	7,091	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	(66)	(32)	(98)	(66)	(32)	(98)	-	-	-	-	-	-
Production	(9,243)	-	(9,243)	(9,241)	-	(9,241)	-	-	-	(2)	-	(2)
At December 31, 2016	84,891	48,694	133,587	84,881	48,692	133,573	-	-	-	12	2	14
	Total Gas⁽⁴⁾			Conventional Natural Gas			Coal Bed Methane⁽⁵⁾			Shale 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, 2015	395,788	258,097	653,885	385,637	252,705	638,342	8,210	4,917	13,127	1,942	475	2,417
Discoveries	233	145	378	233	145	378	-	-	-	-	-	-
Extensions & Improved Recovery	31,230	66,935	98,165	31,230	66,935	98,165	-	-	-	-	-	-
Technical Revisions	58,693	(25,131)	33,562	57,408	(24,805)	32,603	1,394	(135)	1,259	(110)	(191)	(301)
Acquisitions	26,914	12,138	39,052	26,842	12,051	38,893	72	87	159	-	-	-
Dispositions	(353)	(132)	(485)	(353)	(132)	(485)	-	-	-	-	-	-
Economic Factors	(1,448)	(756)	(2,204)	(746)	(564)	(1,310)	(702)	(192)	(894)	-	-	-
Production	(72,671)	-	(72,671)	(71,297)	-	(71,297)	(913)	-	(913)	(461)	-	(461)
At December 31, 2016	438,386	311,296	749,682	428,954	306,335	735,289	8,061	4,677	12,738	1,371	284	1,655
	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, 2015	15,229	13,532	28,761	160,706	100,184	260,889
Discoveries	1	1	2	40	25	65
Extensions & Improved Recovery	1,556	1,051	2,607	11,709	16,502	28,210
Technical Revisions	1,959	(1,274)	685	16,233	(6,506)	9,730
Acquisitions	1,050	474	1,524	10,787	4,337	15,123
Dispositions	(8)	(3)	(11)	(67)	(25)	(92)
Economic Factors	(34)	(51)	(85)	(340)	(210)	(550)
Production	(1,897)	-	(1,897)	(23,253)	-	(23,253)
At December 31, 2016	17,856	13,730	31,586	175,815	114,307	290,122


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 Gas.
⁽⁵⁾	"Coal Bed Methane" and "Shale Gas" were considered "Unconventional Natural Gas" in previous years. NI 51-101 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
2017	9,420	9,420
2018	6,701	6,701
2019	51,052	51,052
2020	2,993	2,993
2021	3,052	57,174
Remainder	25,062	48,320
Total for all years undiscounted	98,280	175,660
Canada
2017	77,141	101,695
2018	90,442	126,482
2019	81,623	128,701
2020	95,424	189,622
2021	59,376	175,978
Remainder	17,542	51,883
Total for all years undiscounted	421,548	774,361
France
2017	39,113	60,593
2018	29,528	49,613
2019	23,548	107,737
2020	6,753	40,020
2021	14,167	23,931
Remainder	10,363	35,668
Total for all years undiscounted	123,472	317,562
Germany
2017	2,183	3,562
2018	584	3,272
2019	8,499	30,655
2020	154	6,863
2021	153	41,162
Remainder	694	3,167
Total for all years undiscounted	12,267	88,681
Ireland
2017	1,311	1,311
2018	-	-
2019	1,706	1,706
2020	16,890	16,890
2021	-	-
Remainder	15,505	15,505
Total for all years undiscounted	35,412	35,412
Netherlands
2017	2,200	7,790
2018	13,525	15,009
2019	604	4,838
2020	385	4,278
2021	287	8,095
Remainder	5,638	5,637
Total for all years undiscounted	22,639	45,647
United States
2017	10,500	10,500
2018	18,426	36,468
2019	18,207	48,039
2020	13,506	42,806
2021	-	-
Remainder	-	1
Total for all years undiscounted	60,639	137,814
Total Company
2017	141,868	194,871
2018	159,206	237,545
2019	185,239	372,728
2020	136,105	303,472
2021	77,035	306,340
Remainder	74,804	160,181
Total for all years undiscounted	774,257	1,575,137


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

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. All contingent resources evaluated in the GLJ Resources Assessment were deemed economic at the effective date of December 31, 2016. Contingent resources are in addition to reserves estimated in the GLJ Report.

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 gross risked contingent resources with a project maturity subclass of "Development Pending" of 120.4 million boe (low estimate) to 309.4 million boe (high estimate), with a best estimate of 198.5 million boe. Contingent resources are in addition to reserves estimated in the GLJ Report.

The GLJ Resources Assessment estimated gross risked contingent resources with a project maturity subclass of "Development Unclarified" of 10.7 million boe (low estimate) to 28.7 million boe (high estimate), with a best estimate of 19.5 million boe.

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.

Table 10: Summary of Risked Oil and Gas Contingent Resources as at December 31, 2016 ^{(1) (2)} - Forecast Prices and Costs ^{(3) (4)}

	Light Crude Oil &		Conventional		Coal Bed		Natural Gas			BOE			Unrisked
Resources	Medium Crude Oil		Natural Gas		Methane		Liquids						BOE
Project													Chance
Maturity	Gross	Net	Gross	Net	Gross	Net	Gross	Net		Gross	Net		of Dev.	Gross	Net
Sub-Class	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)		(Mboe)		(Mboe)	(%)⁽⁹⁾	(Mboe)	(Mboe)
Contingent (1C) - Low Estimate
Development Pending⁽¹⁰⁾
Australia⁽¹¹⁾	-	-	-	-	-	-	-	-		-		-	-	-	-
Canada⁽¹²⁾	13,145	9,681	250,957	226,293	1,455	1,382	19,917	15,769		75,131		63,396	81.9%	91,750	77,305
France⁽¹³⁾	14,152	13,241	969	969	-	-	-	-		14,314		13,403	86.8%	16,486	15,438
Germany⁽¹⁴⁾	-	-	17,317	15,138	-	-	-	-		2,886		2,523	78.3%	3,686	3,222
Ireland	-	-	-	-	-	-	-	-		-		-	-	-	-
Netherlands⁽¹⁵⁾	-	-	10,336	10,336	-	-	2	2		1,725		1,725	81.4%	2,119	2,119
USA⁽¹⁶⁾	20,581	17,072	18,952	15,720	-	-	2,627	2,179		26,367		21,871	90.0%	29,296	24,300
Total	47,878	39,994	298,531	268,456	1,455	1,382	22,546	17,950		120,423		102,918	84.0%	143,337	122,384
Contingent (2C) - Best Estimate
Development Pending⁽¹⁰⁾
Australia⁽¹¹⁾	2,440	2,440	-	-	-	-	-	-		2,440		2,440	80.0%	3,050	3,050
Canada⁽¹²⁾	25,648	18,373	389,272	346,617	3,534	3,357	29,537	22,869		120,653		99,571	80.3%	150,178	123,661
France⁽¹³⁾	27,543	25,702	1,246	1,246	-	-	-	-		27,751		25,908	85.1%	32,628	30,453
Germany⁽¹⁴⁾	-	-	29,595	25,886	-	-	-	-		4,933		4,314	78.3%	6,300	5,510
Ireland	-	-	-	-	-	-	-	-		-		-	-	-	-
Netherlands⁽¹⁵⁾	-	-	28,521	28,521	-	-	6	6		4,760		4,760	81.3%	5,853	5,853
USA⁽¹⁶⁾	29,466	24,441	27,811	23,069	-	-	3,855	3,197		37,956		31,483	90.0%	42,173	34,981
Total	85,097	70,956	476,445	425,339	3,534	3,357	33,398	26,072		198,493		168,476	82.6%	240,182	203,508
Contingent (3C) - High Estimate
Development Pending⁽¹⁰⁾
Australia⁽¹¹⁾	3,280	3,280	-	-	-	-	-	-		3,280		3,280	80.0%	4,100	4,100
Canada⁽¹²⁾	52,590	37,459	567,390	500,749	5,174	4,788	41,650	31,616		189,667		153,331	79.2%	239,562	193,233
France⁽¹³⁾	43,866	40,873	1,609	1,609	-	-	-	-		44,134		41,141	84.3%	52,336	48,774
Germany⁽¹⁴⁾	-	-	54,150	47,382	-	-	-	-		9,025		7,897	78.3%	11,526	10,086
Ireland	-	-	-	-	-	-	-	-		-		-	-	-	-
Netherlands⁽¹⁵⁾	-	-	50,159	50,159	-	-	13	13		8,373		8,373	80.5%	10,403	10,403
USA⁽¹⁶⁾	42,381	35,152	40,945	33,961	-	-	5,675	4,707		54,880		45,519	90.0%	60,977	50,577
Total	142,117	116,764	714,253	633,860	5,174	4,788	47,338	36,336		309,359		259,541	81.6%	378,904	317,173

	Light Crude Oil &		Conventional		Coal Bed		Natural Gas			BOE			Unrisked
Resources	Medium Crude Oil		Natural Gas		Methane		Liquids						BOE
Project													Chance
Maturity	Gross	Net	Gross	Net	Gross	Net	Gross	Net		Gross		Net	of Dev.	Gross	Net
Sub-Class	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)		(Mboe)		(Mboe)	(%)⁽⁹⁾	(Mboe)	(Mboe)
Contingent (1C) - Low Estimate
Development Unclarified⁽¹⁷⁾
Australia	-	-	-	-	-	-	-	-		-		-	-	-	-
Canada⁽¹⁸⁾	-	-	44,744	39,976	-	-	897	745		8,354		7,408	58.2%	14,361	12,743
France⁽¹⁹⁾	1,511	1,434	-	-	-	-	-	-	1,511		1,434		42.4%	3,560	3,376
Germany	-	-	-	-	-	-	-	-	-		-		-	-	-
Ireland	-	-	-	-	-	-	-	-		-		-	-	-	-
Netherlands	-	-	-	-	-	-	-	-		-		-	-	-	-
USA	-	-	-	-	-	-	-	-		-		-	-	-	-
Total	1,511	1,434	44,744	39,976	-	-	897	745		9,865		8,842	55.0%	17,921	16,119
Contingent (2C) - Best Estimate
Development Unclarified⁽¹⁷⁾
Australia	-	-	-	-	-	-	-	-	-		-		-	-	-
Canada⁽¹⁸⁾	-	-	75,428	66,726	-	-	1,640	1,339	14,211		12,460		57.2%	24,859	21,796
France⁽¹⁹⁾	2,539	2,410	-	-	-	-	-	-	2,539		2,410		44.6%	5,690	5,398
Germany	-	-	-	-	-	-	-	-	-		-		-	-	-
Ireland	-	-	-	-	-	-	-	-	-		-		-	-	-
Netherlands⁽²⁰⁾	-	-	16,351	15,777	-	-	32	16	2,757		2,646		49.4%	5,580	5,301
USA	-	-	-	-	-	-	-	-	-		-		-	-	-
Total	2,539	2,410	91,779	82,503	-	-	1,672	1,355		19,507		17,516	54.0%	36,129	32,495
Contingent (3C) - High Estimate
Development Unclarified⁽¹⁷⁾
Australia	-	-	-	-	-	-	-	-		-		-	-	-	-
Canada⁽¹⁸⁾	-	-	103,491	89,867	-	-	2,178	1,727		19,427		16,705	57.6%	33,746	29,063
France⁽¹⁹⁾	3,825	3,632	-	-	-	-	-	-		3,825		3,632	46.4%	8,250	7,829
Germany	-	-	-	-	-	-	-	-		-		-	-	-	-
Ireland	-	-	-	-	-	-	-	-		-		-	-	-	-
Netherlands⁽²⁰⁾	-	-	32,346	31,475	-	-	48	24		5,439		5,270	53.4%	10,184	9,761
USA	-	-	-	-	-	-	-	-		-		-	-	-	-
Total	3,825	3,632	135,837	121,342	-	-	2,226	1,751		28,691		25,607	55.0%	52,180	46,653

Table 11: Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2016 - 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⁽¹⁰⁾
Australia⁽¹¹⁾	-	-	-	-	-	-	-	-	-	-
Canada⁽¹²⁾	1,469,731	806,673	468,784	284,859	179,205	567,431	315,876	182,036	107,244	107,244
France⁽¹³⁾	819,095	435,463	247,355	146,903	90,157	582,296	295,394	158,897	88,278	49,769
Germany⁽¹⁴⁾	29,787	19,161	11,552	6,390	2,959	20,027	11,662	5,658	1,665	(894)
Ireland	-	-	-	-	-	-	-	-	-	-
Netherlands⁽¹⁵⁾	51,663	37,509	28,134	21,720	17,177	27,656	19,744	14,440	10,833	8,313
USA⁽¹⁶⁾	875,320	424,777	223,556	125,266	73,505	562,210	269,146	138,253	74,966	42,140
Total	3,245,596	1,723,583	979,381	585,138	363,003	2,261,816	1,163,377	633,124	357,778	206,572
Contingent (2C) - Best Estimate⁽⁷⁾
Development Pending⁽¹⁰⁾
Australia⁽¹¹⁾	102,151	60,643	36,438	22,134	13,559	26,695	12,642	5,228	1,407	(483)
Canada⁽¹²⁾	2,749,285	1,453,434	840,871	519,322	337,021	2,003,094	1,033,233	579,568	345,415	215,410
France⁽¹³⁾	1,730,450	899,321	508,686	305,273	191,641	1,230,218	615,216	334,091	191,820	114,668
Germany⁽¹⁴⁾	103,451	71,870	50,479	35,968	25,990	74,526	50,615	34,375	23,449	16,048
Ireland	-	-	-	-	-	-	-	-	-	-
Netherlands⁽¹⁵⁾	160,324	110,209	79,494	59,475	45,757	86,998	58,171	40,486	29,074	21,367
USA⁽¹⁶⁾	1,561,749	736,050	390,965	226,282	139,356	1,007,434	471,250	247,014	140,765	85,218
Total	6,407,410	3,331,527	1,906,933	1,168,454	753,324	4,428,965	2,241,127	1,240,762	731,930	452,228
Contingent (3C) - High Estimate⁽⁸⁾
Development Pending⁽¹⁰⁾
Australia⁽¹¹⁾	190,589	116,134	72,383	46,105	29,966	63,277	36,147	20,606	11,695	6,558
Canada⁽¹²⁾	5,020,914	2,498,830	1,392,053	837,248	532,137	3,660,740	1,782,927	966,824	563,961	346,457
France⁽¹³⁾	2,954,319	1,525,736	866,518	524,651	332,885	2,100,039	1,051,087	577,537	337,293	205,471
Germany⁽¹⁴⁾	252,820	174,810	124,211	90,601	67,647	184,908	126,647	88,732	63,652	46,653
Ireland	-	-	-	-	-	-	-	-	-	-
Netherlands⁽¹⁵⁾	315,718	211,894	151,407	113,180	87,473	171,705	113,248	79,106	57,702	43,468
USA⁽¹⁶⁾	2,640,857	1,172,989	614,674	358,063	224,065	1,708,970	754,738	392,026	226,212	140,202
Total	11,375,217	5,700,393	3,221,246	1,969,848	1,274,173	7,889,639	3,864,794	2,124,831	1,260,515	788,809

Contingent (1C) - Low Estimate⁽⁶⁾
Development Unclarified⁽¹⁷⁾
Australia	-	-	-	-	-	-	-	-	-	-
Canada⁽¹⁸⁾	81,186	32,743	13,139	4,876	1,294	58,404	22,305	7,967	2,138	(237)
France⁽¹⁹⁾	109,246	56,246	30,550	17,349	10,224	77,091	38,798	20,522	11,315	6,453
Germany	-	-	-	-	-	-	-	-	-	-
Ireland	-	-	-	-	-	-	-	-	-	-
Netherlands⁽²⁰⁾	-	-	-	-	-	-	-	-	-	-
USA	-	-	-	-	-	-	-	-	-	-
Total	190,432	88,989	43,689	22,225	11,518	135,495	61,103	28,489	13,453	6,216
Contingent (2C) - Best Estimate⁽⁷⁾
Development Unclarified⁽¹⁷⁾
Australia	-	-	-	-	-	-	-	-	-	-
Canada⁽¹⁸⁾	149,050	60,346	25,047	10,046	3,342	107,851	41,837	15,842	5,073	466
France⁽¹⁹⁾	198,194	95,437	49,664	27,439	15,881	140,218	66,266	33,693	18,135	10,199
Germany	-	-	-	-	-	-	-	-	-	-
Ireland	-	-	-	-	-	-	-	-	-	-
Netherlands⁽²⁰⁾	63,974	35,129	18,879	9,435	3,747	34,153	16,587	6,654	985	(2,320)
USA	-	-	-	-	-	-	-	-	-	-
Total	411,218	190,912	93,590	46,920	22,970	282,222	124,690	56,189	24,193	8,345
Contingent (3C) - High Estimate⁽⁸⁾
Development Unclarified⁽¹⁷⁾
Australia	-	-	-	-	-	-	-	-	-	-
Canada⁽¹⁸⁾	250,258	97,428	41,153	18,033	7,732	181,844	68,851	27,516	10,840	3,628
France⁽¹⁹⁾	320,784	143,786	72,178	39,161	22,464	227,214	100,294	49,348	26,186	14,667
Germany	-	-	-	-	-	-	-	-	-	-
Ireland	-	-	-	-	-	-	-	-	-	-
Netherlands⁽²⁰⁾	176,750	94,921	54,922	33,238	20,539	96,181	48,927	25,901	13,615	6,587
USA	-	-	-	-	-	-	-	-	-	-
Total	747,792	336,135	168,253	90,432	50,735	505,239	218,072	102,765	50,641	24,882


Notes:
⁽¹⁾	Contingent resources are 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 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 2016 reserves report were also utilized by GLJ in preparing the GLJ Resource Assessment. See "GLJ December 31, 2016 Forecast Prices" in this AIF.
⁽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 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 projects 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 projects 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 projects 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 projects. These factors may be inter-related (dependent) and care has been taken to ensure that risks are appropriately accounted.







⁽¹⁰⁾	Project maturity subclass development pending is defined as contingent resources where resolution of the final conditions for development is being actively pursued (high chance of development).
⁽¹¹⁾	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 $142 MM and the expected timeline is between 7 and 9 years. The specific contingencies for these resources are corporate commitment and development timing.
⁽¹²⁾	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 $1,170 MM and the expected timeline is between 1 and 12 years. The specific contingencies for these resources are corporate commitment and development timing.
⁽¹³⁾	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 $550 MM and the expected timeline is between 3and 10 years. The specific contingencies for these resources are corporate commitment and development timing.
⁽¹⁴⁾	Contingent resources for Germany 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 $55 MM and the expected timeline is between 3 and 5 years. The specific contingencies for these resources are corporate commitment and development timing.
⁽¹⁵⁾	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 $34 MM and the expected timeline is between two and 10 years. The specific contingencies for these resources are corporate commitment and development timing.
⁽¹⁶⁾	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 $431 MM and the expected timeline is between 4 and 12 years. The specific contingencies for these resources are corporate commitment and development timing.
⁽¹⁷⁾	Project maturity subclass development unclarified is defined as contingent resources when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties.
⁽¹⁸⁾	In Canada, GLJ has estimated an aggregate of risked unclarified best estimate contingent resources of 14.2 mmboe for the projects outlined below. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $108 MM with an expected timeline of 4 to 15 years.

	Ferrier Notikewin	Based on contingencies related to corporate commitment and development timing that is greater than 10 years, GLJ has estimated risked unclarified best estimate contingent resources at 5.1 mmboe and the risked estimated cost to bring these resources on commercial production is $36 MM. The expected timeline is 11 to 15 years.

	Ferrier Falher	Based on contingencies related to corporate commitment and development timing that is greater than 10 years, GLJ has estimated risked unclarified best estimate contingent resources at 3.8 mmboe and the risked estimated cost to bring these resources on commercial production is $28 MM. The expected timeline is 11 to 15 years.

	West Pembina Glauconite	Based on contingencies related to corporate commitment and development timing as well as economic risk related to capital and operating cost uncertainty due to limited horizontal development in proximity to interest lands, GLJ has estimated risked unclarified best estimate contingent resources at 5.3 mmboe and the risked estimated cost to bring these resources on commercial production is $44 MM. The expected timeline is 4 to 10 years.
⁽¹⁹⁾	In France, GLJ has estimated an aggregate of risked unclarified best estimate contingent resources of 2.5 mmboe for the projects outlined below. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $36 MM with an expected timeline of 8 to 10 years.

	Charmottes	Based on contingencies related to corporate commitment and development timing, along with the project still being in the pre-development study/sourcing stage related to waterflood development, GLJ has estimated risked unclarified best estimate contingent resources at 1.3 mmboe and the risked estimated cost to bring these resources on commercial production is $29 MM. The expected timeline is 8 to 10 years.

	Chaunoy	Based on contingencies related to corporate commitment and development timing, along with a CO2 pilot project still being in the conceptual study stage, GLJ has estimated risked unclarified best estimate contingent resources at 1.2 mmboe and the risked estimated cost to bring these resources on commercial production is $7 MM. The expected timeline is 9 to 10 years.
⁽²⁰⁾	In the Netherlands, GLJ has estimated an aggregate of risked unclarified best estimate contingent resources of 2.8 mmboe for the projects outlined below. Utilizing established recovery technology, the risked estimated to bring these resources on commercial production an aggregate of $45 MM with an expected timeline of 3 to 9 years.

	Netherlands East	Based on contingencies related to corporate commitment and development timing along with proof-of-concept utilizing directional drilling and unknown deliverability from Zechstein carbonates, GLJ has estimated risked unclarified best estimate contingent resources at 1.6 mmboe and the risked estimated cost to bring these resources on commercial production is $24 MM. The expected timeline is 3 to 9 years.

	Netherlands West	Based on contingencies related to corporate commitment and development timing along with further study required regarding the deliverability of the Bunter sands, GLJ has estimated risked unclarified best estimate contingent resources at 1.2 mmboe and the risked estimated cost to bring these resources on commercial production is $21 MM. The expected timeline is 5 years.

PROSPECTIVE RESOURCES

Summary information regarding prospective resources and net present value of future net revenues from prospective 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. All prospective resources evaluated in the GLJ Resources Assessment were deemed economic at the effective date of December 31, 2016. Prospective resources are in addition to reserves estimated in the GLJ Report.

A range of prospective 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 gross risked prospective resources of 45.2 million boe (low estimate) to 147.9 million boe (high estimate), with a best estimate of 89.5 million boe.

An estimate of risked net present value of future net revenue of prospective 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 prospective resources that are considered too uncertain with respect to the chance of development and chance of discovery to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.

Table 12: Summary of Risked Oil and Gas Prospective Resources as at December 31, 2016 ^{(1) (2)} - Forecast Prices and Costs ^{(3) (4)}

	Light Crude Oil &		Conventional		Coal Bed		Natural Gas		BOE		Unrisked
Resources	Medium Crude Oil		Natural Gas		Methane		Liquids				BOE
Project											Chance of
Maturity	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Commerciality	Gross	Net
Sub-Class	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)	(%)⁽⁹⁾	(Mboe)	(Mboe)
Prospective - Low Estimate
Prospect⁽¹⁰⁾
Australia⁽¹¹⁾	-	-	-	-	-	-	-	-	-	-	-	-	-
Canada⁽¹²⁾	185	166	95,116	87,039	-	-	5,458	4,703	21,496	19,376	32.9%	65,396	58,986
France⁽¹³⁾	3,379	3,044	-	-	-	-	-	-	3,379	3,044	49.0%	6,898	6,253
Germany⁽¹⁴⁾	-	-	88,561	76,691	-	-	-	-	14,760	12,782	24.6%	59,995	51,954
Ireland	-	-	-	-	-	-	-	-	-	-	-	-	-
Netherlands⁽¹⁵⁾	-	-	33,037	31,606	-	-	16	14	5,522	5,282	11.6%	47,452	45,232
USA	-	-	-	-	-	-	-	-	-	-	-	-	-
Total	3,564	3,210	216,714	195,336	-	-	5,474	4,717	45,157	40,484	25.1%	179,741	162,425
Prospective - Best Estimate
Prospect⁽¹⁰⁾
Australia⁽¹¹⁾	579	579	-	-	-	-	-	-	579	579	48.0%	1,207	1,027
Canada⁽¹²⁾	2,263	2,029	170,797	153,565	-	-	10,195	8,412	40,924	36,035	34.3%	119,269	105,029
France⁽¹³⁾	9,609	8,532	-	-	-	-	-	-	9,609	8,532	37.2%	25,835	22,939
Germany⁽¹⁴⁾	-	-	169,557	147,917	-	-	-	-	28,260	24,653	24.6%	114,865	100,205
Ireland	-	-	-	-	-	-	-	-	-	-	-	-	-
Netherlands⁽¹⁵⁾	-	-	60,647	57,618	-	-	30	27	10,138	9,630	11.8%	85,890	81,192
USA	-	-	-	-	-	-	-	-	-	-	-	-	-
Total	12,451	11,140	401,001	359,100	-	-	10,225	8,439	89,510	79,429	25.8%	347,066	310,392
Prospective - High Estimate
Prospect⁽¹⁰⁾
Australia⁽¹¹⁾	1,462	1,462	-	-	-	-	-	-	1,462	1,462	48.0%	3,046	3,046
Canada⁽¹²⁾	2,394	2,142	244,013	217,049	-	-	14,659	11,724	57,722	50,041	35.6%	162,333	140,646
France⁽¹³⁾	21,406	19,496	-	-	-	-	-	-	21,406	19,496	48.4%	44,243	40,766
Germany⁽¹⁴⁾	-	-	289,626	254,136	-	-	-	-	48,271	42,356	24.6%	196,205	172,162
Ireland	-	-	-	-	-	-	-	-	-	-	-	-	-
Netherlands⁽¹⁵⁾	-	-	114,102	106,974	-	-	59	52	19,076	17,881	11.9%	159,744	148,690
USA	-	-	-	-	-	-	-	-	-	-	-	-	-
Total	25,262	23,100	647,741	578,159	-	-	14,718	11,776	147,937	131,236	26.2%	565,571	505,310

Table 13: Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2016 - 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%
Prospective (Pr1) -Low Estimate⁽⁶⁾
Prospect⁽¹⁰⁾
Canada⁽¹²⁾	273,867	127,001	60,110	27,921	11,751	198,318	85,907	35,748	12,466	1,407
France⁽¹³⁾	151,213	75,323	38,554	20,217	10,789	102,347	48,093	22,638	10,518	4,652
Germany⁽¹⁴⁾	155,230	65,643	24,054	5,229	(3,139)	106,234	38,604	8,125	(4,675)	(9,585)
Netherlands⁽¹⁵⁾	146,420	81,758	50,537	34,384	25,278	75,803	39,394	21,746	13,088	8,573
Total	726,730	349,725	173,255	87,751	44,679	482,702	211,998	88,257	31,397	5,047
Prospective (Pr2) -Best Estimate⁽⁷⁾
Prospect⁽¹⁰⁾
Australia⁽¹¹⁾	46,694	25,575	14,527	8,526	5,152	18,252	9,659	5,268	2,957	1,705
Canada⁽¹²⁾	727,622	350,852	183,676	102,149	59,257	528,484	248,071	122,227	63,175	33,061
France⁽¹³⁾	517,189	263,016	143,095	82,612	50,242	362,550	176,276	91,520	50,373	29,196
Germany⁽¹⁴⁾	572,696	240,171	105,603	47,332	20,454	415,985	166,082	66,349	24,697	6,525
Netherlands⁽¹⁵⁾	364,314	193,047	120,340	83,689	62,715	195,684	99,659	59,140	39,348	28,449
Total	2,228,515	1,072,661	567,241	324,308	197,820	1,520,955	699,747	344,504	180,550	98,936
Prospective (Pr3) -High Estimate⁽⁸⁾
Prospect⁽¹⁰⁾
Australia⁽¹¹⁾	150,518	78,083	43,242	25,161	15,218	62,445	31,968	17,425	9,981	5,947
Canada⁽¹²⁾	1,110,298	500,889	256,708	143,539	85,330	808,440	354,301	174,070	92,184	51,196
France⁽¹³⁾	1,550,119	742,476	388,981	219,441	131,689	1,098,279	514,614	263,597	145,437	85,435
Germany⁽¹⁴⁾	1,215,756	520,750	240,583	116,696	57,872	897,478	370,617	162,227	72,477	31,319
Netherlands⁽¹⁵⁾	785,423	409,343	255,631	178,273	133,629	425,214	216,893	132,001	90,034	66,319
Total	4,812,114	2,251,541	1,185,145	683,110	423,738	3,291,856	1,488,393	749,320	410,113	240,216


Notes:
⁽¹⁾	Prospective resources are defined in the COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from unknown accumulations by application of future development projects. Prospective resources have both an associated chance of discovery (CoDis) and a chance of development (CoDev). There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources or that Vermilion will produce any portion of the volumes currently classified as prospective resources. The estimates of prospective 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 prospective resources does not represent the fair market value of the prospective resources. Actual prospective 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 prospective 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 2016 reserves report were also utilized by GLJ in preparing the GLJ Resource Assessment. See "GLJ December 31, 2016 Forecast Prices" in this AIF.
⁽⁴⁾	"Gross" prospective resources are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net" prospective resources are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in prospective resources.
⁽⁵⁾	The risked net present value of future net revenue attributable to the prospective resources does not represent the fair market value of the prospective 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 commerciality is defined as the product of the chance of discovery and the chance of development. Chance of discovery is defined in COGEH as the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. Chance of development is defined as the estimated probability that, once discovered, a known accumulation will be commercially developed.

	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 prospective 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 prospective 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 prospective 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 prospective 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 prospective 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. The Chance of Discovery (CoDis) is defined in COGEH as the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. Five factors have been considered in determining the CoDis as follows: CoDis = Ps (Source) × Ps (Timing and Migration) × Ps (Trap) ×Ps (Seal) × Ps (Reservoir) wherein Ps is the probability of success Source – For a significant accumulation of potentially recoverable petroleum, a viable source rock capable of generating hydrocarbons must exist. The probability of a source rock investigates stratigraphic presence and location, volumetric adequacy and organic richness of the proposed source rock. In proven hydrocarbon systems, this factor will be a 1. This factor becomes critical when looking at frontier basins. Timing and Migration - For a significant accumulation of potentially recoverable petroleum, the source rock must reach thermal maturity to generate the hydrocarbons and have a conduit with which to fill the closures that existed at the time of migration. The probability of timing and migration investigates the movement of hydrocarbons from the source rock to the trap. This factor evaluates the pathways and/or carrier beds, including fault systems, which can transport buoyant hydrocarbons from the source kitchen to the prospect area at a time that the trap existed. This factor is often 1 in producing trends, but there is a possibility of migration shadows where the conduits do not fill a viable trap, which would decrease this factor. Trap - For a significant accumulation of potentially recoverable petroleum, a reservoir must be present in a structural or stratigraphic closure. The trap factor looks at the definition of the geometry of the accumulation, which is determined using seismic, gravity and/or magnetic techniques and surrounding well logs to determine the probability of a significant accumulation. The risking of this includes examining data quality (e.g. 2D vs 3D seismic coverage) and potential depth conversion possibilities which give confidence in the mapped trap. Stratigraphic trap definition is used for volumetric calculations, but it is given a 1 for this chance factor as the stratigraphic risk will be captured in seal. Seal - For a significant accumulation of potentially recoverable petroleum, a reservoir must be sealed both on the top and laterally by a lithology that contains the hydrocarbon accumulation within the reservoir. It is also necessary that these accumulated hydrocarbons have been preserved from flushing or leakage. Factors that affect top, seat and lateral seals are fluid viscosity, bed thickness, natural continuity of sealing facies, differential permeability, fault history and reservoir pressures needed to maintain a hydrocarbon column. The probability that the accumulation is not able to be contained by the surrounding rocks is captured in this chance factor. Reservoir - For a significant accumulation of potentially recoverable petroleum, a reservoir rock must be present and have sufficient porosity and permeability and be of a sufficient thickness to produce quantities of mobile hydrocarbon. Under this approach, encountering wet, commercial quality and quantity sandstones would not be a failure in the reservoir category, but rather in one of the other factors. It is the reservoir along with the trap which determine the volumetrics of the accumulation. Serial multiplication of these five decimal fractions representing the five geologic chance factors can be done as they are considered independent of each other.
⁽¹⁰⁾	GLJ has sub-classified the best estimate prospective resources by maturity status, consistent with the requirements of the COGE Handbook. These prospective resources have been sub-classified as "Prospect" which the COGE Handbook defines as a potential accumulation within a play that is sufficiently well defined to present a viable drilling target.
⁽¹¹⁾	Prospective resources for Australia have been estimated based on development timing and reservoir risk, GLJ has estimated the CoDev at 80% and the CoDis at 60%. The corresponding chance of commerciality is 48%. Risked best estimate prospective resources have been estimated at .06 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is $17.2 MM. The expected development timeline is 8 years.
⁽¹²⁾	Prospective resources for Canada have been estimated based on the individual prospects outlined below. GLJ has estimated the aggregate CoDev at 86% and the aggregate CoDis at 40%. The corresponding chance of commerciality is 34%. Risked best estimate prospective resources have been estimated at an aggregate of 40.9 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $621.9 MM. The expected development timeline is 2 to 20 years.


		Wilrich Prospect:	Based on reservoir risk, development timing and limited Wilrich development on the land base, GLJ has estimated the CoDev at 35% and the CoDis at 85%. The corresponding chance of commerciality is 30%. Risked best estimate prospective resources have been estimated at 22.2 mmboe and the risked estimated cost to bring these resources on commercial production is $218 MM with an expected timeline of 2 to 8 years.

		West Pembina Glauconite Prospect:	Based on chance of discovery risk due to uncertainty regarding threshold for reservoir quality to support commercial development of resources with horizontal drilling, along with economic risk related to capital and operating cost uncertainty due to limited horizontal development in proximity to interest lands and chance of development risk related to corporate commitment and development timing. GLJ has estimated the CoDev at 34% and the CoDis at 90%. The corresponding chance of commerciality is 31%. Risked best estimate prospective resources have been estimated at 8.4 mmboe and the risked estimated cost to bring these resources on commercial production is $242 MM with an expected timeline of 6 to 14 years.

		Drayton Valley Notikewin Prospect:	Based on reservoir risk and development timing, GLJ has estimated the CoDev at 70% and the CoDis at 85%. The corresponding chance of commerciality is 60%. Risked best estimate prospective resources have been estimated at 4.6 mmboe and the risked estimated cost to bring these resources on commercial production is $69.3 MM. The expected development timeline is 10 to 12 years.

		Saskatchewan Prospects	Based on reservoir risk and development timing, GLJ has estimated the CoDev at 90% and the CoDis at 80%. The corresponding chance of commerciality is 72%. Risked best estimate prospective resources have been estimated at 3.0 mmboe and the risked estimated cost to bring these resources on commercial production is $63.6 MM with an expected timeline of 7 to 12 years

		Ferrier Falher Prospect	Based on reservoir risk and development timing, GLJ has estimated the CoDev at 60% and the CoDis at 90%. The corresponding chance of commerciality is 54%. Risked best estimate prospective resources have been estimated at 2.6 mmboe and the risked estimated cost to bring these resources on commercial production is $24.9 MM with an expected timeline of 16 to 20 years.

		Utikuma Gilwood Prospect	Based on reservoir risk, development timing and limited Gilwood development in the area, GLJ has estimated the CoDev at 60% and the CoDis at 50%. The corresponding chance of commerciality is 30%. Risked best estimate prospective resources have been estimated at 0.2 mmboe and the risked estimated cost to bring these resources on commercial production is $3.2 MM with an expected timeline of 16 to 20 years.
⁽¹³⁾	Prospective resources for France have been estimated based on the individual prospects outlined below. GLJ has estimated the aggregate CoDev at 52% and the aggregate CoDis at 71%. The corresponding chance of commerciality is 37%. Risked best estimate prospective resources have been estimated at an aggregate of 9.6 Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $254.3 MM. The expected development timeline is 3 to 12 years.

		Rachee Prospect	Based on risk of closure and data quality along with development timing, GLJ has estimated the CoDev at 80% and the CoDis at 80%. The corresponding chance of commerciality is 64%. Risked best estimate prospective resources have been estimated at 3.4 mmboe and the risked estimated cost to bring these resources on commercial production is $125.0 MM with an expected timeline of 10 to 14 years.

		Malnoue Prospect	Based on reservoir, structure and trap risk along with development timing, GLJ has estimated the CoDev at 70% and the CoDis at 38%. The corresponding chance of commerciality is 27%. Risked best estimate prospective resources have been estimated at 1.4 mmboe and the risked estimated cost to bring these resources on commercial production is $31.6 MM with an expected timeline of 8 to 12 years.

		West Lavergne Prospect	Based on structure risk and development timing GLJ has estimated the CoDev at 80% and the CoDis at 70%. The corresponding chance of commerciality is 56%. Risked best estimate prospective resources have been estimated at 1.2 mmboe and the risked estimated cost to bring these resources on commercial production is $6.1 MM with an expected timeline of 4 years.

		Champotran Prospect	Based on reservoir risk and development timing, GLJ has estimated the CoDev at 80% and the CoDis at 80%. The corresponding chance of commerciality is 64%. Risked best estimate prospective resources have been estimated at 0.7 mmboe and the risked estimated cost to bring these resources on commercial production is $14.6 MM with an expected timeline of 7 to 8 years.

		Cazaux Prospect	Based on reservoir risk and development timing, GLJ has estimated the CoDev at 70% and the CoDis at 30%. The corresponding chance of commerciality is 21%. Risked best estimate prospective resources have been estimated at 0.6 mmboe and the risked estimated cost to bring these resources on commercial production is $10.3 MM with an expected timeline of 5 to 7 years.

		Vulaines Prospect	Based on reservoir and structure risk along with development timing, GLJ has estimated the CoDev at 80% and the CoDis at 40%. The corresponding chance of commerciality is 32%. Risked best estimate prospective resources have been estimated at 0.6 mmboe and the risked estimated cost to bring these resources on commercial production is $12.6 MM with an expected timeline of 5 to 6 years.

		Phobos Prospect	Based on reservoir, and closure risk, economic factors and development timing, GLJ has estimated the CoDev at 50% and the CoDis at 50%. The corresponding chance of commerciality is 25%. Risked best estimate prospective resources have been estimated at 0.5 mmboe and the risked estimated cost to bring these resources on commercial production is $20.6 MM with an expected timeline of 9 to 10 years.

		Charmottes Prospect	Based on reservoir risk and development timing, GLJ has estimated the CoDev at 60% and the CoDis at 50%. The corresponding chance of commerciality is 30%. Risked best estimate prospective resources have been estimated at 0.5 mmboe and the risked estimated cost to bring these resources on commercial production is $18.5 MM with an expected timeline of 8 to 10 years.

		Bernet Prospect	Based on risks associated with reservoir, seal and trap along with economic factors, and development timing, GLJ has estimated the CoDev at 50% and the CoDis at 65%. The corresponding chance of commerciality is 33%. Risked best estimate prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $6.7 MM with an expected timeline of 5 to 6 years.

		Vert Le Grand Prospect	Based on reservoir and structure risk along with development timing, GLJ has estimated the CoDev at 70% and the CoDis at 28%. The corresponding chance of commerciality is 20%. Risked best estimate prospective resources have been estimated at 0.2 mmboe and the risked estimated cost to bring these resources on commercial production is $3.6 MM with an expected timeline of 3 years.

		Pays De Born Prospect	Based on reservoir, seal and trap risk, along with economic factors and development timing, GLJ has estimated the CoDev at 50% and the CoDis at 50%. The corresponding chance of commerciality is 25%. Risked best estimate prospective resources have been estimated at 0.1 mmboe and the risked estimated cost to bring these resources on commercial production is $2.6 MM with an expected timeline of 8 to 9 years.

		Les Genets Prospect	Based on reservoir, seal and closure risk, along with economic factors and development timing, GLJ has estimated the CoDev at 60% and the CoDis at 16%. The corresponding chance of commerciality is 9.6%. Risked best estimate prospective resources have been estimated at 0.1 mmboe and the risked estimated cost to bring these resources on commercial production is $0.9 MM with an expected timeline of 9 years.

		North Acacias Prospect	Based on reservoir, seal and trap risk, along with economic factors and development timing, GLJ has estimated the CoDev at 70% and the CoDis at 39%. The corresponding chance of commerciality is 27%. Risked best estimate prospective resources have been estimated at 0.08 mmboe and the risked estimated cost to bring these resources on commercial production is $1.2 MM with an expected timeline of 6 to 7 years.
⁽¹⁴⁾	Prospective resources for Germany have been estimated based on the individual prospects outlined below. GLJ has estimated the aggregate CoDev at 60% and the aggregate CoDis at 41%. The corresponding chance of commerciality is 25%. Risked best estimate prospective resources have been estimated at an aggregate of 28.3 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of 173.6MM. The expected development timeline is 2 to 15 years.

		Ihlow Prospect	Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 71%, and the CoDis at 51%. The corresponding chance of commerciality is 36%. Risked best estimate prospective resources have been estimated at 6.6 mmboe and the risked estimated cost to bring these resources on commercial production is $44.7 MM with an expected timeline of 8 years.

		Wisselshorst A Prospect	Based on seal and trap risk along with development timing , GLJ has estimated the CoDev at 90%, and the CoDis at 45%. The corresponding chance of commerciality is 41%. Risked best estimate prospective resources have been estimated at 4.8 mmboe and the risked estimated cost to bring these resources on commercial production is $32.2 MM with an expected timeline of 8 years.

		Simonswolde South Prospect	Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 71%, and the CoDis at 48%. The corresponding chance of commerciality is 34%. Risked best estimate prospective resources have been estimated at 4.1 mmboe and the risked estimated cost to bring these resources on commercial production is $14.6 MM with an expected timeline of 10 years.

		Klosterseelte Prospect	Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 49%, and the CoDis at 49%. The corresponding chance of commerciality is 24%. Risked best estimate prospective resources have been estimated at 2.8 mmboe and the risked estimated cost to bring these resources on commercial production is $12.2 MM with an expected timeline of 5 years.

		Ohlendorf Prospect	Based on source and trap risk along with development timing, GLJ has estimated the CoDev at 58%, and the CoDis at 30%. The corresponding chance of commerciality is 17%. Risked best estimate prospective resources have been estimated at 2.4 mmboe and the risked estimated cost to bring these resources on commercial production is $10.1 MM with an expected timeline of 15 years.

		Wisselshorst B Prospect	Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 90%, and the CoDis at 38%. The corresponding chance of commerciality is 34%. Risked best estimate prospective resources have been estimated at 2.3 mmboe and the risked estimated cost to bring these resources on commercial production is $17.9 MM with an expected timeline of 11 years.

		Jeddeloh Prospect	Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 38%, and the CoDis at 31%. The corresponding chance of commerciality is 12%. Risked best estimate prospective resources have been estimated at 2.3 mmboe and the risked estimated cost to bring these resources on commercial production is $18.5 MM with an expected timeline of 8 years.

		Simonswolde North Prospect	Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 62%, and the CoDis at 45%. The corresponding chance of commerciality is 28%. Risked best estimate prospective resources have been estimated at 1.4 mmboe and the risked estimated cost to bring these resources on commercial production is $5.6 MM with an expected timeline of 8 years.

		Uphuser Meer Prospect	Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 47%, and the CoDis at 51%. The corresponding chance of commerciality is 24%. Risked best estimate prospective resources have been estimated at 1.0 mmboe and the risked estimated cost to bring these resources on commercial production is $4.5 MM with an expected timeline of 9 years.

		Burgmoor Z5 Prospect	Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 63%, and the CoDis at 52%. The corresponding chance of commerciality is 33%. Risked best estimate prospective resources have been estimated at 0.7 mmboe and the risked estimated cost to bring these resources on commercial production is $2.8 MM with an expected timeline of 2 years.

		Wellie Prospect	Based on reservoir, seal and source risk along with development timing, GLJ has estimated the CoDev at 32%, and the CoDis at 20%. The corresponding chance of commerciality is 6%. Risked best estimate prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $3 MM with an expected timeline of 11 years.

		Otterstedt Prospect	Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 46%, and the CoDis at 34%. The corresponding chance of commerciality is 16%. Risked best estimate prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $3.2 MM with an expected timeline of 14 years.

		Widdernhausen East Prospect	Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 32%, and the CoDis at 44%. The corresponding chance of commerciality is 14%. Risked best estimate prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $2.1 MM with an expected timeline of 12 years.

		Ostervesede Prospect	Based on reservoir and seal risk along with development timing, GLJ has estimated the CoDev at 23%, and the CoDis at 25%. The corresponding chance of commerciality is 6%. Risked best estimate prospective resources have been estimated at 0.1 mmboe and the risked estimated cost to bring these resources on commercial production is $0.7 MM with an expected timeline of 11 years.
⁽¹⁵⁾	Prospective resources for Netherlands have been estimated based on the factors outlined below. GLJ has estimated the aggregate CoDev at 40% and the aggregate CoDis at 30%. The corresponding chance of commerciality is 12%. Risked best estimate prospective resources have been estimated at an aggregate of 10.1 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of 88.2 MM with an expected timeline of 2 to 12 years.

	Prospective resources for Netherlands East have been estimated based on the individual areas outlined below. GLJ has estimated the aggregate CoDev at 25% and the aggregate CoDis at 44%. The corresponding chance of commerciality is 11%. Risked best estimate prospective resources have been estimated at an aggregate of 8.0 mmboe and the risked estimated cost to bring these resources on commercial production is an aggregate of 66.3 MM with an expected timeline of 2 to 12 years.

	Chance of discovery provided for 111 prospective reservoir targets across 92 prospective locations. Risk primarily associated with presence of reservoir and seal as region proven to have adequate source, migration and timing to charge target reservoirs. Chance of development risked to account for company commitment and development timing, anticipated timing for permitting in respective licenses and distance to export (i.e. pipeline/facility requirements to transport gas to sales point). Chance of development is also a function of prospect size. 92 prospects summed probabilistically across 13 development groups to appropriately allocate required infrastructure capital across multiple prospective targets within reasonable proximity. As probabilistic summation of the groups resulted in strong economic indicators, no further minimum economic field size calculations were applied as they were considered to have nominal impact.

	Prospective resources for Netherlands West have been estimated based on the factors outlined below. GLJ has estimated the aggregate CoDev at 65% and the aggregate CoDis at 28%. The corresponding chance of commerciality is 18%. Risked best estimate prospective resources have been estimated at an aggregate of 2.1 mmboe and the risked estimated cost to bring these resources on commercial production is an aggregate of$ 21.8 MM with an expected timeline of 2 to 9 years.

	Chance of discovery provided for 10 prospective reservoir targets across 11 prospective locations. Risk primarily associated with presence of reservoir and seal as region proven to have adequate source, migration and timing to charge target reservoirs. Chance of development risked to account for company commitment and development timing, anticipated timing for permitting in respective licenses and distance to export (i.e. pipeline/facility requirements to transport gas to sales point). Chance of development is also a function of prospect size. 11 prospects summed probabilistically across 3 development groups to appropriately allocate required infrastructure capital across multiple prospective targets within reasonable proximity. As probabilistic summation of the groups resulted in strong economic indicators no further minimum economic field size calculations were applied as they were considered to have nominal impact.

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 5%.

Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.

Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years 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.

Netbacks and Operating 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. "Operating Recycle Ratio" is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). "Netbacks" are per boe and per Mcf measures used in operational and capital allocation decisions. "Operating Netback" is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. Management assesses Operating Netback as a measure of the profitability and efficiency of our field operations. F&D (finding and development) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital, by the change in the reserves, incorporating revisions and production, for the same period.

SOURCE Vermilion Energy Inc.

Anthony Marino, President & CEO; Curtis W. Hicks, C.A., Executive VP & CFO and/or Kyle Preston, Director Investor RelationsTEL (403) 269-4884 | IR TOLL FREE 1-866-895-8101 | [email protected] | www.vermilionenergy.com

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