Mar 1, 2018 SOURCE: PR NewsWire
Vermilion Energy Inc. Announces 2017 Year-End Summary Reserves and Resource Information
CALGARY, March 1, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce summary 2017 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, 2017 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, 2017, to be filed on March 1, 2018 and available on SEDAR at www.sedar.com and on the SEC's EDGAR system at www.sec.gov/edgar.shtml.
HIGHLIGHTS
-- Total proved ("1P") reserves increased by 0.5% to 176.6 mmboe, while
total proved plus probable ("2P") reserves increased 3% to 298.5 mmboe.
We replaced 103% and 134% of production at the 1P and 2P levels
respectively in 2017.
-- Finding and Development ("F&D")((2)) and Finding, Development and
Acquisition ("FD&A")((2)) costs, including Future Development Capital
("FDC") for 2017 on a 2P basis increased to $10.57/boe and $11.24/boe,
compared to $5.57/boe and $6.62/boe in 2016, respectively. Our
three-year F&D and FD&A costs, including FDC, on a 2P basis were
$8.23/boe and $8.87/boe, respectively. The largest driver of the
increase in F&D cost was the strengthening of the Euro relative to the
Canadian dollar in GLJ's foreign exchange rate forecast as compared to
the previous year, which increased FDC for our European properties.
Operating Recycle Ratio((3)) (including FDC) was 2.8x in 2017.
-- Proved Developed Producing ("PDP") reserves increased by 1.3% to 123.8
mmboe at an average F&D cost (including FDC) of $12.41/boe resulting in
a PDP Operating Recycle Ratio((3)) (including FDC) of 2.4x. PDP reserves
represent 70% of 1P reserves.
-- At year-end 2017, 2P reserves were comprised of 29% Brent-based light
crude, 15% North American-based light crude, 12% natural gas liquids,
19% European natural gas and 25% North American natural gas.
-- We continued to build our strong resource base in our West Pembina area
in Alberta. We added 29 (23.9 net) 2P locations in the condensate-rich
portion of the Mannville gas play in West Pembina at an average reserves
addition per well of approximately 520 mboe. The West Pembina-Mannville
reserves are Vermilion's largest resource base, representing over 40% of
total Canadian 2P reserves at December 31, 2017.
-- In the Ferrier area of Alberta we added nine (7.1 net) 2P locations in
the liquids-rich Mannville gas play at an average reserve addition per
well of approximately 1,100 mboe.
-- Our independent GLJ 2017 Resource Assessment((4)) indicates risked low,
best, and high estimates for contingent resources in the Development
Pending category of 107.3((4)) mmboe, 176.7((4)) mmboe, and 253.6((4))
mmboe, respectively. The GLJ 2017 Resource Assessment also indicates
risked low, best, and high estimates for contingent resources in the
Development Unclarified category of 7.5((4)) mmboe, 32.8((4)) mmboe, and
46.1((4)) mmboe, respectively. Over 80% of our risked contingent
resources reside in the Development Pending category. Prospective
resources were assessed at risked low, best and high estimates of
51.5((4)) mmboe, 153.4((4)) mmboe, and 260.4((4)) mmboe. Our contingent
and prospective resource bases remain a source of reserve additions,
with 20.5 mmboe of contingent resources and 1.7 mmboe of prospective
resources converted to 2P reserves during 2017.
(1) As evaluated by GLJ Petroleum
Consultants Ltd. ("GLJ") in a report
dated February 1, 2018 with an
effective date of December 31, 2017.
(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, 2018 to assess
contingent and prospective resources
across all of the Company's key
operating regions with an effective
date of December 31, 2017 (the "GLJ
2017 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
56%, 46% and 47%, respectively. The
aggregate associated chance of
commerciality for each of the low,
best and high estimate for
prospective resources in the
Prospect category are 23%, 22% and
22%, 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, 2017 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, 2018 with an effective date of December 31, 2017 (the "GLJ 2017 Reserves Evaluation"). The GLJ 2017 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, 2017 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 2017 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 2017 Reserve Evaluation. There is no assurance that the future price and cost assumptions used in the GLJ 2017 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 Crude Oil Conventional Conventional Natural Gas Inflation Exchange Exchange
& Medium Crude Oil Natural Gas Natural Gas Liquids Rate Rate Rate
Canada Europe
------ ------
Year WTI Edmonton Cromer Brent Blend AECO National Balancing FOB Percent ($US/$Cdn) ($Cdn/EUR)
Cushing Par Price Medium FOB Gas Price Point Field Gate Per Year
Oklahoma 40 API 29.3 API North Sea ($Cdn/MMBtu) (UK) ($Cdn/bbl)
($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/bbl) ($US/MMBtu)
--- --------- ---------- ---------- --------- -----------
2017 50.88 62.78 59.90 54.16 2.16 5.63 46.67 1.60 0.77 1.46
Forecast
2018 59.00 70.25 65.34 65.50 2.20 6.25 56.85 2.00 0.79 1.49
2019 59.00 70.25 65.34 63.50 2.54 6.50 53.46 2.00 0.79 1.46
2020 60.00 70.31 65.39 63.00 2.88 6.75 53.18 2.00 0.80 1.44
2021 66.00 72.84 67.74 66.00 3.24 7.00 54.74 2.00 0.81 1.42
2022 69.00 75.61 70.32 69.00 3.47 7.15 56.37 2.00 0.82 1.40
2023 72.00 78.31 72.83 72.00 3.58 7.30 58.31 2.00 0.83 1.39
2024 75.00 81.93 76.19 75.00 3.66 7.45 60.94 2.00 0.83 1.39
2025 78.00 85.54 79.55 78.00 3.73 7.60 63.57 2.00 0.83 1.39
2026 80.33 88.35 82.16 80.33 3.80 7.75 65.61 2.00 0.83 1.39
2027 81.88 90.22 83.90 81.88 3.88 7.90 66.96 2.00 0.83 1.39
---- ----- ----- ----- ----- ---- ---- ----- ---- ---- ----
Thereafter +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr 0.83 1.39
---------- -------- -------- -------- -------- -------- -------- -------- -------- ---- ----
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 2017, 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, France and Germany 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 and Germany is based on the TTF day/month-ahead index, as determined on the Title Transfer Facility Virtual Trading Point. For the year ended December 31, 2017, the average realized sales prices before hedging were $57.64 per bbl (United States) for WTI, $51.36 per bbl for Canadian-based crude oil, condensate and NGLs and $2.34 per Mcf for Canadian natural gas, $73.99 per bbl (Australia), $67.08 per bbl (France) for Brent-based crude oil, $7.19 per Mcf (Ireland), $7.18 per Mcf (Netherlands), and $6.38 per Mcf (Germany).
The following table summarizes the capital expenditures made by Vermilion on oil and gas properties for the year ended December 31, 2017:
Table 2: Capital Costs Incurred
Acquisition Costs
(M$) Proved Unproved Exploration Development Total
Properties Properties Costs Costs Costs
--- ---------- ---------- ----- ----- -----
Australia - - - 29,896 29,896
Canada 22,011 - - 148,211 170,222
Croatia - - 2,764 - 2,764
France - - 2,294 69,026 71,320
Germany - - 3,366 5,710 9,076
Hungary - - 2,596 - 2,596
Ireland - - - 544 544
Netherlands - - 16,468 14,956 31,424
United States 3,403 - - 19,058 22,461
------------- ----- --- --- ------ ------
Total 25,414 - 32,103 287,401 344,918
----- ------ --- ------ ------- -------
The following table sets forth the reserve life index based on total proved and proved plus probable reserve and fourth quarter 2017 production of 72,821 boe/d.
Table 3: Reserve Life Index
Commodity Production Reserve Life Index
(years)
--------- ---------- -------------------
Fourth Quarter 2017 Total Proved Proved Plus Probable
------------------- ------------ --------------------
Crude oil,
condensate and
natural gas
liquids (bbl/d) 33,109 8.5 13.8
Natural gas
(mmcf/d) 238.27 5.1 9.1
----------- ------ --- ---
Oil Equivalent
(boe/d) 72,821 6.6 11.2
-------------- ------ --- ----
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 Heavy Oil Tight Oil Conventional Natural Gas
Crude Oil
---------
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 9,065 9,065 - - - - - -
Canada 11,148 10,219 - - - - 139,772 128,023
France 35,944 33,265 - - - - 8,619 7,939
Germany 5,008 4,880 - - - - 29,791 26,881
Ireland - - - - - - 81,803 81,803
Netherlands - - - - - - 37,296 24,721
United States 982 782 - - - - 1,071 854
------------- --- --- --- --- --- --- ----- ---
Total Proved Developed Producing 62,147 58,211 - - - - 298,352 270,221
-------------------------------- ------ ------ --- --- --- --- ------- -------
Shale Gas Coal Bed Methane Natural Gas Liquids BOE
--------- ---------------- ------------------- ---
Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2)
(MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe)
Proved Developed Producing (3) (5) (6)
Australia - - - - - - 9,065 9,065
Canada 60 56 2,330 2,153 11,215 9,102 46,057 41,026
France - - - - - - 37,381 34,588
Germany - - - - - - 9,973 9,360
Ireland - - - - - - 13,634 13,634
Netherlands - - - - 137 90 6,353 4,210
United States - - - - 147 117 1,308 1,041
------------- --- --- --- --- --- --- ----- -----
Total Proved Developed Producing 60 56 2,330 2,153 11,499 9,309 123,771 112,924
-------------------------------- --- --- ----- ----- ------ ----- ------- -------
Light Crude Oil & Medium Heavy Oil Tight Oil Conventional Natural Gas
Crude Oil
---------
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 (3) (5) (7)
Australia 350 350 - - - -
Canada 878 768 - - - - 9,420 8,489
France 562 492 - - - - - -
Germany 539 521 - - - - 8,959 8,156
Ireland - - - - - - - -
Netherlands - - - - - - 21,010 20,482
United States - - - - - - - -
------------- --- --- --- --- --- --- --- ---
Total Proved Developed Non-Producing 2,329 2,131 - - - - 39,389 37,127
------------------------------------ ----- ----- --- --- --- --- ------ ------
Shale Gas Coal Bed Methane Natural Gas Liquids BOE
--------- ---------------- ------------------- ---
Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2)
(MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe)
Proved Developed Non-Producing (3) (5) (7)
Australia - - - - - - 350 350
Canada 1,079 1,025 2,360 2,200 410 309 3,431 3,029
France - - - - - - 562 492
Germany - - - - - - 2,032 1,880
Ireland - - - - - - - -
Netherlands - - - - 56 54 3,558 3,468
United States - - - - - - - -
------------- --- --- --- --- --- --- --- ---
Total Proved Developed Non-Producing 1,079 1,025 2,360 2,200 466 363 9,933 9,219
------------------------------------ ----- ----- ----- ----- --- --- ----- -----
Light Crude Oil & Medium Heavy Oil Tight Oil Conventional Natural Gas
Crude Oil
---------
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 1,500 1,500 - - - - - -
Canada 7,634 6,929 - - - - 91,104 83,603
France 4,140 3,767 - - - - 64 64
Germany 241 235 - - - - 2,361 1,939
Ireland - - - - - - - -
Netherlands - - - - - - 2,620 2,620
United States 3,300 2,693 - - - - 3,309 2,700
------------- ----- ----- --- --- --- --- ----- -----
Total Proved Undeveloped 16,815 15,124 - - - - 99,458 90,926
------------------------ ------ ------ --- --- --- --- ------ ------
Shale Gas Coal Bed Methane Natural Gas Liquids BOE
--------- ---------------- ------------------- ---
Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2)
(MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe)
Proved Undeveloped (3) (8)
Australia - - - - - - 1,500 1,500
Canada - - 2,023 1,849 8,679 7,689 31,834 28,860
France - - - - - - 4,151 3,778
Germany - - - - - - 635 558
Ireland - - - - - - - -
Netherlands - - - - - - 437 437
United States - - - - 454 370 4,306 3,513
------------- --- --- --- --- --- --- ----- -----
Total Proved Undeveloped - - 2,023 1,849 9,133 8,059 42,863 38,646
------------------------ --- --- ----- ----- ----- ----- ------ ------
Light Crude Oil & Medium Heavy Oil Tight Oil Conventional Natural Gas
Crude Oil
---------
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 10,915 10,915 - - - - - -
Canada 19,660 17,916 - - - - 240,296 220,115
France 40,646 37,524 - - - - 8,683 8,003
Germany 5,788 5,636 - - - - 41,111 36,976
Ireland - - - - - - 81,803 81,803
Netherlands - - - - - - 60,926 47,823
United States 4,282 3,475 - - - - 4,380 3,554
------------- ----- ----- --- --- --- --- ----- -----
Total Proved 81,291 75,466 - - - - 437,199 398,274
------------ ------ ------ --- --- --- --- ------- -------
Shale Gas Coal Bed Methane Natural Gas Liquids BOE
--------- ---------------- ------------------- ---
Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2)
(MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe)
Proved (3)
Australia - - - - - - 10,915 10,915
Canada 1,139 1,081 6,713 6,202 20,304 17,100 81,322 72,916
France - - - - - - 42,093 38,858
Germany - - - - - - 12,640 11,799
Ireland - - - - - - 13,634 13,634
Netherlands - - - - 193 144 10,347 8,115
United States - - - - 601 487 5,613 4,554
------------- --- --- --- --- --- --- ----- -----
Total Proved 1,139 1,081 6,713 6,202 21,098 17,731 176,564 160,791
------------ ----- ----- ----- ----- ------ ------ ------- -------
Light Crude Oil & Medium Heavy Oil Tight Oil Conventional Natural Gas
Crude Oil
---------
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 12,885 11,417 - - - - 181,055 164,336
France 21,786 20,115 - - - - 1,854 1,769
Germany 3,000 2,931 - - - - 53,134 47,092
Ireland - - - - - - 51,389 51,389
Netherlands - - - - - - 44,380 35,383
United States 7,073 5,827 - - - - 7,520 6,194
------------- ----- ----- --- --- --- --- ----- -----
Total Probable 49,394 44,940 - - - - 339,332 306,163
-------------- ------ ------ --- --- --- --- ------- -------
Shale Gas Coal Bed Methane Natural Gas Liquids BOE
--------- ---------------- ------------------- ---
Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2)
(MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe)
Probable (4)
Australia - - - - - - 4,650 4,650
Canada 214 203 3,053 2,846 14,282 12,186 57,887 51,501
France - - - - - - 22,095 20,410
Germany - - - - - - 11,856 10,780
Ireland - - - - - - 8,565 8,565
Netherlands - - - - 119 90 7,516 5,987
United States - - - - 1,031 849 9,357 7,708
------------- --- --- --- --- ----- --- ----- -----
Total Probable 214 203 3,053 2,846 15,432 13,125 121,926 109,601
-------------- --- --- ----- ----- ------ ------ ------- -------
Light Crude Oil & Medium Heavy Oil Tight Oil Conventional Natural Gas
Crude Oil
---------
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 15,565 15,565 - - - - - -
Canada 32,545 29,333 - - - - 421,351 384,451
France 62,432 57,639 - - - - 10,537 9,772
Germany 8,788 8,567 - - - - 94,245 84,068
Ireland - - - - - - 133,192 133,192
Netherlands - - - - - - 105,306 83,206
United States 11,355 9,302 - - - - 11,900 9,748
------------- ------ ----- --- --- --- --- ------ -----
Total Proved Plus Probable 130,685 120,406 - - - - 776,531 704,437
-------------------------- ------- ------- --- --- --- --- ------- -------
Shale Gas Coal Bed Methane Natural Gas Liquids BOE
--------- ---------------- ------------------- ---
Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2)
(MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe)
Proved Plus Probable (3) (4)
Australia - - - - - - 15,565 15,565
Canada 1,353 1,284 9,766 9,048 34,586 29,286 139,209 124,416
France - - - - - - 64,188 59,268
Germany - - - - - - 24,496 22,578
Ireland - - - - - - 22,199 22,199
Netherlands - - - - 312 234 17,863 14,102
United States - - - - 1,632 1,336 14,970 12,263
------------- --- --- --- --- ----- ----- ------ ------
Total Proved Plus Probable 1,353 1,284 9,766 9,048 36,530 30,856 298,490 270,391
-------------------------- ----- ----- ----- ----- ------ ------ ------- -------
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 (17,017) 90,880 132,474 146,048 147,713 77,180 124,390 136,979 136,121 130,383
Canada 929,867 770,860 647,843 559,708 494,964 929,867 770,860 647,843 559,708 494,964
France 1,791,774 1,315,070 1,030,403 849,032 725,407 1,473,144 1,091,894 858,839 708,168 604,390
Germany 276,577 249,619 206,965 174,876 151,703 276,578 249,619 206,965 174,876 151,703
Ireland 389,204 376,115 346,327 316,408 290,143 389,204 376,115 346,327 316,408 290,143
Netherlands 48,794 60,781 66,245 68,260 68,404 48,793 60,781 66,245 68,260 68,404
United States 44,617 34,550 28,272 24,106 21,170 44,619 34,550 28,272 24,106 21,170
------------- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Proved Developed Producing 3,463,816 2,897,875 2,458,529 2,138,438 1,899,504 3,239,385 2,708,209 2,291,470 1,987,647 1,761,157
-------------------------------- --------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Proved Developed Non-Producing (2) (4) (6)
Australia 28,079 24,122 20,869 18,180 15,942 28,079 24,122 20,869 18,180 15,942
Canada 60,804 42,405 32,416 26,238 22,048 60,804 42,405 32,417 26,238 22,048
France 10,082 8,113 6,095 4,559 3,438 6,848 5,499 3,953 2,763 1,896
Germany 49,825 37,600 27,510 20,411 15,501 32,059 29,369 23,502 18,374 14,426
Ireland - - - - - - - - - -
Netherlands 70,140 70,244 67,599 63,916 59,989 53,099 54,167 52,375 49,452 46,205
United States - - - - - - - - - -
------------- --- --- --- --- --- --- --- --- --- ---
Total Proved Developed Non-Producing 218,930 182,484 154,489 133,304 116,918 180,889 155,562 133,116 115,007 100,517
------------------------------------ ------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Proved Undeveloped (2) (7)
Australia 54,981 43,263 34,175 27,105 21,564 25,101 18,532 13,890 10,524 8,032
Canada 524,830 354,396 246,584 175,252 126,009 397,236 281,016 202,741 148,193 108,836
France 177,851 128,923 96,156 73,638 57,592 127,650 88,876 63,091 45,660 33,460
Germany 17,161 11,696 8,012 5,495 3,737 12,154 8,910 6,412 4,551 3,166
Ireland - - - - - - - - - -
Netherlands 10,559 8,825 7,405 6,255 5,323 7,921 6,405 5,174 4,189 3,401
United States 110,911 64,500 39,231 24,394 15,111 105,425 62,306 38,295 23,973 14,912
------------- ------- ------ ------ ------ ------ ------- ------ ------ ------ ------
Total Proved Undeveloped 896,293 611,603 431,563 312,139 229,336 675,487 466,045 329,603 237,090 171,807
------------------------ ------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Proved (2)
Australia 66,043 158,265 187,518 191,333 185,219 130,360 167,044 171,738 164,825 154,357
Canada 1,515,501 1,167,661 926,843 761,198 643,021 1,387,907 1,094,281 883,001 734,139 625,848
France 1,979,707 1,452,106 1,132,654 927,229 786,437 1,607,642 1,186,269 925,883 756,591 639,746
Germany 343,563 298,915 242,487 200,782 170,941 320,791 287,898 236,879 197,801 169,295
Ireland 389,204 376,115 346,327 316,408 290,143 389,204 376,115 346,327 316,408 290,143
Netherlands 129,493 139,850 141,249 138,431 133,716 109,813 121,353 123,794 121,901 118,010
United States 155,528 99,050 67,503 48,500 36,281 150,044 96,856 66,567 48,079 36,082
------------- ------- ------ ------ ------ ------ ------- ------ ------ ------ ------
Total Proved 4,579,039 3,691,962 3,044,581 2,583,881 2,245,758 4,095,761 3,329,816 2,754,189 2,339,744 2,033,481
------------ --------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Probable (3)
Australia 154,459 149,732 125,619 102,719 84,652 93,591 88,478 72,912 58,670 47,633
Canada 1,363,584 814,347 539,091 384,014 288,722 1,003,602 592,655 390,429 278,355 210,521
France 1,200,008 673,205 431,159 299,927 219,972 879,913 477,377 292,831 193,985 134,663
Germany 414,585 244,149 151,416 100,767 70,641 293,314 172,157 104,603 68,306 47,063
Ireland 350,695 246,321 182,785 141,844 114,117 350,695 246,321 182,785 141,844 114,117
Netherlands 197,136 167,242 141,871 121,179 104,496 130,277 108,388 89,527 74,196 61,980
United States 353,649 198,078 124,603 84,897 61,103 278,493 157,846 100,547 69,404 50,591
------------- ------- ------- ------- ------ ------ ------- ------- ------- ------ ------
Total Probable 4,034,116 2,493,074 1,696,544 1,235,347 943,703 3,029,885 1,843,222 1,233,634 884,760 666,568
-------------- --------- --------- --------- --------- ------- --------- --------- --------- ------- -------
Proved Plus Probable (2) (3)
Australia 220,502 307,997 313,137 294,052 269,871 223,951 255,522 244,650 223,495 201,990
Canada 2,879,085 1,982,008 1,465,934 1,145,212 931,743 2,391,509 1,686,936 1,273,430 1,012,494 836,369
France 3,179,715 2,125,311 1,563,813 1,227,156 1,006,409 2,487,555 1,663,646 1,218,714 950,576 774,409
Germany 758,148 543,064 393,903 301,549 241,582 614,105 460,055 341,482 266,107 216,358
Ireland 739,899 622,436 529,112 458,252 404,260 739,899 622,436 529,112 458,252 404,260
Netherlands 326,629 307,092 283,120 259,610 238,212 240,090 229,741 213,321 196,097 179,990
United States 509,177 297,128 192,106 133,397 97,384 428,537 254,702 167,114 117,483 86,673
------------- ------- ------- ------- ------- ------ ------- ------- ------- ------- ------
Total Proved Plus Probable 8,613,155 6,185,036 4,741,125 3,819,228 3,189,461 7,125,646 5,173,038 3,987,823 3,224,504 2,700,049
-------------------------- --------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
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))
(M$) Revenue Royalties Operating Capital Abandonment Future Net Future Future Net
Costs Development and Revenue Income Taxes Revenue
Costs Reclamation Before After
Costs Income Taxes Income Taxes
--- ----- ------------ ------------
Proved (2)
Australia 978,200 - 564,074 100,883 247,200 66,043 (64,317) 130,360
Canada 3,488,501 344,924 1,118,811 412,323 96,942 1,515,501 127,594 1,387,907
France 3,591,175 272,788 997,961 125,874 214,845 1,979,707 372,065 1,607,642
Germany 853,470 44,503 298,194 20,409 146,801 343,563 22,772 320,791
Ireland 643,435 - 170,325 18,907 64,999 389,204 - 389,204
Netherlands 546,125 104,158 203,425 28,166 80,883 129,493 19,680 109,813
United States 404,551 112,559 65,468 66,993 4,003 155,528 5,484 150,044
------------- ------- ------- ------ ------ ----- ------- ----- -------
Total Proved 10,505,457 878,932 3,418,258 773,555 855,673 4,579,039 483,278 4,095,761
------------ ---------- ------- --------- ------- ------- --------- ------- ---------
Proved Plus
Probable (2) (3)
Australia 1,432,958 - 775,932 166,801 269,723 220,502 (3,449) 223,951
Canada 6,224,592 647,349 1,828,575 744,672 124,911 2,879,085 487,576 2,391,509
France 5,718,238 433,546 1,481,349 346,196 277,432 3,179,715 692,160 2,487,555
Germany 1,672,382 105,662 507,204 104,899 196,469 758,148 144,043 614,105
Ireland 1,113,630 - 270,554 38,178 64,999 739,899 - 739,899
Netherlands 950,074 180,041 296,854 53,369 93,181 326,629 86,539 240,090
United States 1,137,518 308,001 166,074 145,966 8,300 509,177 80,640 428,537
------------- --------- ------- ------- ------- ----- ------- ------ -------
Total Proved Plus
Probable 18,249,392 1,674,599 5,326,542 1,600,081 1,035,015 8,613,155 1,487,509 7,125,646
----------------- ---------- --------- --------- --------- --------- --------- --------- ---------
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 Unit Value
Before Income Taxes (2)
(Discounted at 10% Per Year)
---------------------------
Proved Developed Producing (M$) ($/boe)
Light Crude Oil & Medium
Crude Oil (3) 1,764,235 27.51
Heavy Oil (3) - -
Conventional Natural Gas (4) 693,722 14.33
Shale Gas 122 8.56
Coal Bed Methane 450 1.25
---------------- --- ----
Total Proved Developed
Producing 2,458,529 21.77
---------------------- --------- -----
Proved Developed Non-
Producing
Light Crude Oil & Medium
Crude Oil (3) 43,821 18.44
Heavy Oil (3) - -
Conventional Natural Gas (4) 108,904 17.4
Shale Gas 984 4.54
Coal Bed Methane 780 2.13
---------------- --- ----
Total Proved Developed Non-
Producing 154,489 16.76
--------------------------- ------- -----
Proved Undeveloped
Light Crude Oil & Medium
Crude Oil (3) 273,008 14.16
Heavy Oil (3) - -
Conventional Natural Gas (4) 158,318 8.31
Shale Gas - -
Coal Bed Methane 237 0.77
---------------- --- ----
Total Proved Undeveloped 431,563 12.04
------------------------ ------- -----
Proved
Light Crude Oil & Medium
Crude Oil (3) 2,081,064 24.35
Heavy Oil (3) - -
Conventional Natural Gas (4) 960,944 12.92
Shale Gas 1,106 4.58
Coal Bed Methane 1,467 1.36
---------------- ----- ----
Total Proved 3,044,581 18.94
------------ --------- -----
Probable
Light Crude Oil & Medium
Crude Oil (3) 1,031,625 19.21
Heavy Oil (3) - -
Conventional Natural Gas (4) 663,113 11.98
Shale Gas 238 5.49
Coal Bed Methane 1,568 3.31
---------------- ----- ----
Total Probable 1,696,544 15.48
-------------- --------- -----
Proved Plus Probable
Light Crude Oil & Medium
Crude Oil (3) 3,112,689 22.47
Heavy Oil (3) - -
Conventional Natural Gas (4) 1,624,057 12.42
Shale Gas 1,344 4.85
Coal Bed Methane 3,035 1.92
---------------- ----- ----
Total Proved Plus Probable 4,741,125 17.53
-------------------------- --------- -----
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, 2017 compared to such reserves as at December 31, 2016.
Table 8: Reconciliation of Company Gross Reserves by Principal Product Type - Based on Forecast Prices and Costs ((3))
AUSTRALIA Total Oil (4) Light Crude Oil & Heavy Oil Tight Oil
Medium Crude Oil
--- ----------------
Proved Probable P+P (1) (2) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 12,418 4,650 17,068 12,418 4,650 17,068 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions 603 - 603 603 - 603 - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production (2,106) - (2,106) (2,106) - (2,106) - - - - - -
---------- ------ --- ------ ------ --- ------ --- --- --- --- --- ---
At December 31, 2017 10,915 4,650 15,565 10,915 4,650 15,565 - - - - - -
-------------------- ------ ----- ------ ------ ----- ------ --- --- --- --- --- ---
Total Gas (4) Conventional Natural Gas Coal Bed Methane (5) Shale Gas (5)
------------ ------------------------ ------------------- ------------
Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 - - - - - - - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions - - - - - - - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production - - - - - - - - - - - -
---------- --- --- --- --- --- --- --- --- --- --- --- ---
At December 31, 2017 - - - - - - - - - - - -
-------------------- --- --- --- --- --- --- --- --- --- --- --- ---
Natural Gas Liquids BOE
------------------- ---
Proved Probable Proved + Proved Probable Proved +
Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mboe) (Mboe) (Mboe)
------- ----- ----- ----- ----- ----- -----
At December 31, 2016 - - - 12,418 4,650 17,068
Discoveries - - - - - -
Extensions & Improved Recovery - - - - - -
Technical Revisions - - - 603 - 603
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors - - - - - -
Production - - - (2,106) - (2,106)
---------- --- --- --- ------ --- ------
At December 31, 2017 - - - 10,915 4,650 15,565
==================== === === === ====== ===== ======
( )
CANADA Total Oil (4) Light Crude Oil & Heavy Oil Tight Oil
Medium Crude Oil
--- ----------------
Proved Probable P+P (1) (2) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 21,974 14,105 36,079 21,962 14,103 36,065 - - - 12 2 14
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 594 302 896 594 302 896 - - - - - -
Technical Revisions (681) (1,542) (2,223) (670) (1,540) (2,210) - - - (11) (2) (13)
Acquisitions 16 4 20 16 4 20 - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors (48) 16 (32) (48) 16 (32) - - - - - -
Production (2,195) - (2,195) (2,194) - (2,194) - - - (1) - (1)
---------- ------ --- ------ ------ --- ------ --- --- --- --- --- ---
At December 31, 2017 19,660 12,885 32,545 19,660 12,885 32,545 - - - - - -
-------------------- ------ ------ ------ ------ ------ ------ --- --- --- --- --- ---
Total Gas (4) Conventional Natural Gas Coal Bed Methane (5) Shale Gas (5)
------------ ------------------------ ------------------- ------------
Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
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
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 58,040 29,520 87,560 57,075 28,977 86,052 965 543 1,508 - - -
Technical Revisions 1,696 372 2,068 1,057 378 1,435 799 64 863 (160) (70) (230)
Acquisitions 3,452 1,113 4,565 2,686 872 3,558 766 241 1,007 - - -
Dispositions (2,182) (2,150) (4,332) (576) (231) (807) (1,606) (1,919) (3,525) - - -
Economic Factors (3,658) (1,201) (4,859) (2,497) (648) (3,145) (1,161) (553) (1,714) - - -
Production (35,730) - (35,730) (34,547) - (34,547) (1,111) - (1,111) (72) - (72)
---------- ------- --- ------- ------- --- ------- ------ --- ------ --- --- ---
At December 31, 2017 248,148 184,322 432,470 240,296 181,055 421,351 6,713 3,053 9,766 1,139 214 1,353
-------------------- ------- ------- ------- ------- ------- ------- ----- ----- ----- ----- --- -----
Natural Gas Liquids BOE
------------------- ---
Proved Probable Proved + Proved Probable Proved +
Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mboe) (Mboe) (Mboe)
------- ----- ----- ----- ----- ----- -----
At December 31, 2016 17,363 12,907 30,270 77,092 53,123 130,215
Discoveries - - - - - -
Extensions & Improved Recovery 5,669 1,235 6,904 15,936 6,457 22,393
Technical Revisions (271) 95 (176) (668) (1,386) (2,054)
Acquisitions 351 113 464 942 303 1,245
Dispositions (3) (1) (4) (367) (359) (726)
Economic Factors (184) (67) (251) (842) (251) (1,093)
Production (2,621) - (2,621) (10,771) - (10,771)
---------- ------ --- ------ ------- --- -------
At December 31, 2017 20,304 14,282 34,586 81,322 57,887 139,209
==================== ====== ====== ====== ====== ====== =======
FRANCE Total Oil (4) Light Crude Oil & Heavy Oil Tight Oil
Medium Crude Oil
--- ----------------
Proved Probable P+P (1) (2) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 42,044 21,933 63,977 42,044 21,933 63,977 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 1,688 1,879 3,567 1,688 1,879 3,567 - - - - - -
Technical Revisions 1,086 (1,912) (826) 1,086 (1,912) (826) - - - - - -
Acquisitions - - - - - - - - - - -
-
Dispositions - - - - - - - - - - - -
Economic Factors (126) (114) (240) (126) (114) (240) - - - - - -
Production (4,046) - (4,046) (4,046) - (4,046) - - - - - -
---------- ------ --- ------ ------ --- ------ --- --- --- --- --- ---
At December 31, 2017 40,646 21,786 62,432 40,646 21,786 62,432 - - - - - -
-------------------- ------ ------ ------ ------ ------ ------ --- --- --- --- --- ---
Total Gas (4) Conventional Natural Gas Coal Bed Methane (5) Shale Gas (5)
------------ ------------------------ ------------------- ------------
Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 5,482 892 6,374 5,482 892 6,374 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions 3,239 968 4,207 3,239 968 4,207 - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors (37) (6) (43) (37) (6) (43) - - - - - -
Production (1) - (1) (1) - (1) - - - - - -
---------- --- --- --- --- --- --- --- --- --- --- --- ---
At December 31, 2017 8,683 1,854 10,537 8,683 1,854 10,537 - - - - - -
-------------------- ----- ----- ------ ----- ----- ------ --- --- --- --- --- ---
Natural Gas Liquids BOE
------------------- ---
Proved Probable Proved + Proved Probable Proved +
Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mboe) (Mboe) (Mboe)
------- ----- ----- ----- ----- ----- -----
At December 31, 2016 - - - 42,958 22,082 65,040
Discoveries - - - - - -
Extensions & Improved Recovery - - - 1,688 1,879 3,567
Technical Revisions - - - 1,625 (1,751) (126)
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors - - - (132) (115) (247)
Production - - - (4,046) - (4,046)
---------- --- --- --- ------ --- ------
At December 31, 2017 - - - 42,093 22,095 64,188
==================== === === === ====== ====== ======
GERMANY Total Oil (4) Light Crude Oil & Heavy Oil Tight Oil
Medium Crude Oil
--- ----------------
Proved Probable P+P (1) (2) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 5,288 2,279 7,567 5,288 2,279 7,567 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 300 275 575 300 275 575 - - - - - -
Technical Revisions 699 480 1,179 699 480 1,179 - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors (112) (34) (146) (112) (34) (146) - - - - - -
Production (387) - (387) (387) - (387) - - - - - -
---------- ---- --- ---- ---- --- ---- --- --- --- --- --- ---
At December 31, 2017 5,788 3,000 8,788 5,788 3,000 8,788 - - - - - -
-------------------- ----- ----- ----- ----- ----- ----- --- --- --- --- --- ---
Total Gas (4) Conventional Natural Gas Coal Bed Methane (5) Shale Gas (5)
------------ ------------------------ ------------------- ------------
Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 41,481 54,284 95,765 41,481 54,284 95,765 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 117 108 225 117 108 225 - - - - - -
Technical Revisions 6,590 (1,027) 5,563 6,590 (1,027) 5,563 - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - (231) (231) - (231) (231) - - - - - -
Production (7,077) - (7,077) (7,077) - (7,077) - - - - - -
---------- ------ --- ------ ------ --- ------ --- --- --- --- --- ---
At December 31, 2017 41,111 53,134 94,245 41,111 53,134 94,245 - - - - - -
-------------------- ------ ------ ------ ------ ------ ------ --- --- --- --- --- ---
Natural Gas Liquids BOE
------------------- ---
Proved Probable Proved + Proved Probable Proved +
Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mboe) (Mboe) (Mboe)
------- ----- ----- ----- ----- ----- -----
At December 31, 2016 - - - 12,202 11,326 23,528
Discoveries - - - - - -
Extensions & Improved Recovery - - - 320 293 613
Technical Revisions - - - 1,797 310 2,107
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors - - - (112) (73) (185)
Production - - - (1,567) - (1,567)
---------- --- --- --- ------ --- ------
At December 31, 2017 - - - 12,640 11,856 24,496
-------------------- --- --- --- ------ ------ ------
IRELAND Total Oil (4) Light Crude Oil & Heavy Oil Tight Oil
Medium Crude Oil
--- ----------------
Proved Probable P+P (1) (2) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 - - - - - - - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions - - - - - - - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production - - - - - - - - - - - -
---------- --- --- --- --- --- --- --- --- --- --- --- ---
At December 31, 2017 - - - - - - - - - - - -
-------------------- --- --- --- --- --- --- --- --- --- --- --- ---
Total Gas (4) Conventional Natural Gas Coal Bed Methane (5) Shale Gas (5)
------------ ------------------------ ------------------- ------------
Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 99,575 50,787 150,362 99,575 50,787 150,362 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions 3,553 602 4,155 3,553 602 4,155 - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production (21,325) - (21,325) (21,325) - (21,325) - - - - - -
---------- ------- --- ------- ------- --- ------- --- --- --- --- --- ---
At December 31, 2017 81,803 51,389 133,192 81,803 51,389 133,192 - - - - - -
-------------------- ------ ------ ------- ------ ------ ------- --- --- --- --- --- ---
Natural Gas Liquids BOE
------------------- ---
Proved Probable Proved + Proved Probable Proved +
Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mboe) (Mboe) (Mboe)
------- ----- ----- ----- ----- ----- -----
At December 31, 2016 - - - 16,596 8,465 25,061
Discoveries - - - - - -
Extensions & Improved Recovery - - - - - -
Technical Revisions - - - 592 100 692
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors - - - - - -
Production - - - (3,554) - (3,554)
---------- --- --- --- ------ --- ------
At December 31, 2017 - - - 13,634 8,565 22,199
-------------------- --- --- --- ------ ----- ------
NETHERLANDS Total Oil (4) Light Crude Oil & Heavy Oil Tight Oil
Medium Crude Oil
--- ----------------
Proved Probable P+P (1) (2) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 - - - - - - - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions - - - - - - - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production - - - - - - - - - - - -
---------- --- --- --- --- --- --- --- --- --- --- --- ---
At December 31, 2017 - - - - - - - - - - - -
-------------------- --- --- --- --- --- --- --- --- --- --- --- ---
Total Gas (4) Conventional Natural Gas Coal Bed Methane (5) Shale Gas (5)
------------ ------------------------ ------------------- ------------
Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 62,350 43,184 105,534 62,350 43,184 105,534 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 8,163 7,807 15,970 8,163 7,807 15,970 - - - - - -
Technical Revisions 5,232 (6,579) (1,347) 5,232 (6,579) (1,347) - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors (22) (32) (54) (22) (32) (54) - - - - - -
Production (14,797) - (14,797) (14,797) - (14,797) - - - - - -
---------- ------- --- ------- ------- --- ------- --- --- --- --- --- ---
At December 31, 2017 60,926 44,380 105,306 60,926 44,380 105,306 - - - - - -
-------------------- ------ ------ ------- ------ ------ ------- --- --- --- --- --- ---
Natural Gas Liquids BOE
------------------- ---
Proved Probable Proved + Proved Probable Proved +
Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mboe) (Mboe) (Mboe)
------- ----- ----- ----- ----- ----- -----
At December 31, 2016 81 63 144 10,473 7,260 17,733
Discoveries - - - - - -
Extensions & Improved Recovery 30 21 51 1,391 1,322 2,713
Technical Revisions 115 35 150 986 (1,061) (75)
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors - - - (4) (5) (9)
Production (33) - (33) (2,499) - (2,499)
---------- --- --- --- ------ --- ------
At December 31, 2017 193 119 312 10,347 7,516 17,863
-------------------- --- --- --- ------ ----- ------
UNITED STATES Total Oil (4) Light Crude Oil & Heavy Oil Tight Oil
Medium Crude Oil
--- ----------------
Proved Probable P+P (1) (2) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 3,169 5,727 8,896 3,169 5,727 8,896 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 1,413 1,483 2,896 1,413 1,483 2,896 - - - - - -
Technical Revisions (49) (133) (182) (49) (133) (182) - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors (9) (4) (13) (9) (4) (13) - - - - - -
Production (242) - (242) (242) - (242) - - - - - -
---------- ---- --- ---- ---- --- ---- --- --- --- --- --- ---
At December 31, 2017 4,282 7,073 11,355 4,282 7,073 11,355 - - - - - -
-------------------- ----- ----- ------ ----- ----- ------ --- --- --- --- --- ---
Total Gas (4) Conventional Natural Gas Coal Bed Methane (5) Shale Gas (5)
------------ ------------------------ ------------------- ------------
Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 2,969 5,481 8,450 2,969 5,481 8,450 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 1,328 1,554 2,882 1,328 1,554 2,882 - - - - - -
Technical Revisions 231 489 720 231 489 720 - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors (5) (4) (9) (5) (4) (9) - - - - - -
Production (143) - (143) (143) - (143) - - - - - -
---------- ---- --- ---- ---- --- ---- --- --- --- --- --- ---
At December 31, 2017 4,380 7,520 11,900 4,380 7,520 11,900 - - - - - -
-------------------- ----- ----- ------ ----- ----- ------ --- --- --- --- --- ---
Natural Gas Liquids BOE
------------------- ---
Proved Probable Proved + Proved Probable Proved +
Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mboe) (Mboe) (Mboe)
------- ----- ----- ----- ----- ----- -----
At December 31, 2016 412 760 1,172 4,076 7,401 11,477
Discoveries - - - - - -
Extensions & Improved Recovery 182 213 395 1,816 1,955 3,771
Technical Revisions 28 59 87 18 7 25
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors (1) (1) (2) (11) (6) (17)
Production (20) - (20) (286) - (286)
---------- --- --- --- ---- --- ----
At December 31, 2017 601 1,031 1,632 5,613 9,357 14,970
-------------------- --- ----- ----- ----- ----- ------
TOTAL COMPANY Total Oil (4) Light Crude Oil & Heavy Oil Tight Oil
Medium Crude Oil
--- ----------------
Proved Probable P+P (1) (2) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 84,893 48,694 133,587 84,881 48,692 133,573 - - - 12 2 14
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 3,995 3,939 7,934 3,995 3,939 7,934 - - - - - -
Technical Revisions 1,658 (3,107) (1,449) 1,669 (3,105) (1,436) - - - (11) (2) (13)
Acquisitions 16 4 20 16 4 20 - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors (295) (136) (431) (295) (136) (431) - - - - - -
Production (8,976) - (8,976) (8,975) - (8,975) - - - (1) - (1)
---------- ------ --- ------ ------ --- ------ --- --- --- --- --- ---
At December 31, 2017 81,291 49,394 130,685 81,291 49,394 130,685 - - - - - -
-------------------- ------ ------ ------- ------ ------ ------- --- --- --- --- --- ---
Total Gas (4) Conventional Natural Gas Coal Bed Methane (5) Shale Gas (5)
------------ ------------------------ ------------------- ------------
Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved +
Probable Probable Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
At December 31, 2016 438,387 311,296 749,683 428,955 306,335 735,290 8,061 4,677 12,738 1,371 284 1,655
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 67,648 38,989 106,637 66,683 38,446 105,129 965 543 1,508 - - -
Technical Revisions 20,541 (5,175) 15,366 19,902 (5,169) 14,733 799 64 863 (160) (70) (230)
Acquisitions 3,452 1,113 4,565 2,686 872 3,558 766 241 1,007 - - -
Dispositions (2,182) (2,150) (4,332) (576) (231) (807) (1,606) (1,919) (3,525) - - -
Economic Factors (3,722) (1,474) (5,196) (2,561) (921) (3,482) (1,161) (553) (1,714) - - -
Production (79,073) - (79,073) (77,890) - (77,890) (1,111) - (1,111) (72) - (72)
---------- ------- --- ------- ------- --- ------- ------ --- ------ --- --- ---
At December 31, 2017 445,051 342,599 787,650 437,199 339,332 776,531 6,713 3,053 9,766 1,139 214 1,353
-------------------- ------- ------- ------- ------- ------- ------- ----- ----- ----- ----- --- -----
Natural Gas Liquids BOE
------------------- ---
Proved Probable Proved + Proved Probable Proved +
Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mboe) (Mboe) (Mboe)
------- ----- ----- ----- ----- ----- -----
At December 31, 2016 17,856 13,730 31,586 175,815 114,307 290,122
Discoveries - - - - - -
Extensions & Improved Recovery 5,881 1,469 7,350 21,151 11,906 33,057
Technical Revisions (128) 189 61.49 4,953 (3,781) 1,172
Acquisitions 351 113 464 942 303 1,245
Dispositions (3) (1) (4) (367) (359) (726)
Economic Factors (185) (68) (253) (1,101) (450) (1,551)
Production (2,674) - (2,674) (24,829) - (24,829)
---------- ------ --- ------ ------- --- -------
At December 31, 2017 21,098 15,432 36,530.49 176,564 121,926 298,490
-------------------- ------ ------ --------- ------- ------- -------
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))
(M$) Total Proved Total Proved Plus Probable
Estimated Using Forecast Estimated Using Forecast
Prices and Costs Prices and Costs
--- ------------------------- -------------------------
Australia
2018 11,565 11,565
2019 70,052 70,052
2020 3,026 3,026
2021 3,140 58,821
2022 3,164 3,164
Remainder 9,936 20,173
--------- ----- ------
Total for all
years
undiscounted 100,883 166,801
------------- ------- -------
Canada
2018 136,499 150,107
2019 142,540 155,186
2020 110,461 139,784
2021 20,828 119,929
2022 622 114,329
Remainder 1,373 65,337
--------- ----- ------
Total for all
years
undiscounted 412,323 744,672
------------- ------- -------
France
2018 30,969 52,162
2019 34,118 84,258
2020 19,848 100,335
2021 26,017 59,875
2022 4,289 24,707
Remainder 10,633 24,859
--------- ------ ------
Total for all
years
undiscounted 125,874 346,196
------------- ------- -------
Germany
2018 2,116 5,381
2019 11,172 17,742
2020 3,162 10,590
2021 3,185 29,808
2022 124 38,918
Remainder 650 2,460
--------- --- -----
Total for all
years
undiscounted 20,409 104,899
------------- ------ -------
Ireland
2018 - -
2019 1,855 1,855
2020 - 19,271
2021 - -
2022 - -
Remainder 17,052 17,052
--------- ------ ------
Total for all
years
undiscounted 18,907 38,178
------------- ------ ------
Netherlands
2018 3,205 9,569
2019 12,253 13,923
2020 6,181 14,170
2021 324 4,909
2022 326 4,921
Remainder 5,877 5,877
--------- ----- -----
Total for all
years
undiscounted 28,166 53,369
------------- ------ ------
United States
2018 3,797 11,392
2019 28,082 39,224
2020 35,114 46,818
2021 - 48,532
2022 - -
Remainder - -
--------- --- ---
Total for all
years
undiscounted 66,993 145,966
------------- ------ -------
Total Company
2018 188,151 240,176
2019 300,072 382,240
2020 177,792 333,994
2021 53,494 321,874
2022 8,525 186,039
Remainder 45,521 135,758
--------- ------ -------
Total for all
years
undiscounted 773,555 1,600,081
------------- ------- ---------
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.
APPENDIX A
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, 2017. 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 107.3 million boe (low estimate) to 253.6 million boe (high estimate), with a best estimate of 176.7 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 7.5 million boe (low estimate) to 46.1 million boe (high estimate), with a best estimate of 32.8 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, 2017 ((1) (2)) - Forecast Prices and Costs ((3) (4))
Resources Light Crude Oil & Conventional Coal Bed Natural Gas BOE Unrisked
Medium Crude Oil Natural Gas Methane Liquids BOE
---------------- ----------- ------- ------- ---
Project
Maturity Gross Net Gross Net Gross Net Gross Net Gross Net Chance Gross Net
of Dev.
Sub-Class (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe) % (9) (Mboe) (Mboe)
--------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ---- ----- -----
Contingent (1C) - Low Estimate
Development Pending (10)
Australia - - - - - - - - - - - - -
Canada 11,918 10,818 217,576 200,317 2,081 1,977 17,879 15,803 66,407 60,337 82% 80,740 73,403
France 13,677 12,798 940 940 - - - - 13,834 12,955 87% 15,923 14,908
Germany - - 19,342 16,795 - - - - 3,224 2,799 77% 4,187 3,635
Ireland - - - - - - - - - - - - -
Netherlands 61 61 4,647 4,647 - - 1 1 837 837 81% 1,038 1,038
USA 17,651 14,699 17,643 14,693 - - 2,416 2,104 23,008 19,252 90% 25,567 21,391
--- ------ ------ ------ ------ --- --- ----- ----- ------ ------ --- ------ ------
Total 43,307 38,376 260,148 237,392 2,081 1,977 20,296 17,908 107,310 96,180 84% 127,453 114,375
----- ------ ------ ------- ------- ----- ----- ------ ------ ------- ------ --- ------- -------
Contingent (2C) - Best Estimate
Development Pending (10)
Australia (11) 2,440 2,440 - - - - - - 2,440 2,440 80% 3,050 3,050
Canada (12) 19,312 17,209 352,291 322,162 2,520 2,394 27,354 23,739 105,801 95,041 81% 131,380 118,063
France (13) 27,054 25,229 1,245 1,245 - - - - 27,262 25,437 85% 32,027 29,891
Germany (14) - - 33,721 29,267 - - - - 5,620 4,878 77% 7,299 6,335
Ireland - - - - - - - - - - - - -
Netherlands (15) 121 121 13,995 13,995 - - 8 8 2,462 2,462 78% 3,170 3,169
USA (16) 25,289 21,060 25,924 21,589 - - 3,554 2,960 33,164 27,618 90% 36,849 30,687
------- ------ ------ ------ ------ --- --- ----- ----- ------ ------ --- ------ ------
Total 74,216 66,059 427,176 388,258 2,520 2,394 30,916 26,707 176,749 157,876 83% 213,775 191,195
----- ------ ------ ------- ------- ----- ----- ------ ------ ------- ------- --- ------- -------
Contingent (3C) - High Estimate
Development Pending (10)
Australia 3,280 3,280 3,280 3,280 80% 4,100 4,100
Canada 24,079 21,133 488,328 443,399 2,943 2,796 37,617 31,953 143,575 127,452 80% 179,355 159,116
France 43,275 40,278 1,618 1,618 - - - - 43,545 40,548 84% 51,613 48,043
Germany - - 62,480 54,212 - - - - 10,413 9,035 77% 13,523 11,734
Ireland - - - - - - - - - - - - -
Netherlands 242 242 27,237 27,237 - - 16 16 4,798 4,798 79% 6,100 6,097
USA 36,411 30,320 38,218 31,826 - - 5,240 4,363 48,021 39,987 90% 53,356 44,430
--- ------ ------ ------ ------ --- --- ----- ----- ------ ------ --- ------ ------
Total 107,287 95,253 617,881 558,292 2,943 2,796 42,873 36,332 253,632 225,100 82% 308,047 273,520
----- ------- ------ ------- ------- ----- ----- ------ ------ ------- ------- --- ------- -------
Resources Light Crude Oil & Conventional Coal Bed Natural Gas BOE Unrisked
Medium Crude Oil Natural Gas Methane Liquids BOE
---------------- ----------- ------- ------- ---
Project
Maturity Gross Net Gross Net Gross Net Gross Net Gross Net Chance Gross Net
of Dev.
Sub-Class (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe) % (9) (Mboe) (Mboe)
--------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ---- ----- -----
Contingent (1C) - Low Estimate
Development Unclarified (17)
Australia - - - - - - - - - - - - -
Canada - - 30,844 27,821 - - 531 439 5,672 5,076 60% 9,463 8,474
France 1,302 1,235 - - - - - - 1,302 1,235 41% 3,212 3,049
Germany - - - - - - - - - - - - -
Ireland - - - - - - - - - - - - -
Netherlands - - 3,120 3,120 - - - - 520 520 70% 743 743
USA - - - - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- --- --- --- ---
Total 1,302 1,235 33,964 30,941 - - 531 439 7,494 6,831 56% 13,418 12,266
----- ----- ----- ------ ------ --- --- --- --- ----- ----- --- ------ ------
Contingent (2C) - Best Estimate
Development Unclarified (17)
Australia - - - - - - - - - - - - -
Canada (18) - - 60,273 53,873 60,886 57,652 6,641 5,995 26,834 24,583 46% 58,404 53,558
France (19) 2,539 2,410 - - - - - - 2,539 2,410 45% 5,690 5,404
Germany - - 1,496 1,190 - - - - 249 198 35% 711 566
Ireland - - - - - - - - - - - - -
Netherlands (20) - - 18,678 18,104 - - 32 16 3,145 3,033 51% 6,134 5,912
USA - - - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- --- --- ---
Total 2,539 2,410 80,447 73,167 60,886 57,652 6,673 6,011 32,767 30,224 46% 70,939 65,440
----- ----- ----- ------ ------ ------ ------ ----- ----- ------ ------ --- ------ ------
Contingent (3C) - High Estimate
Development Unclarified (17)
Australia - - - - - - - - - - - - -
Canada - - 78,561 69,281 77,410 72,283 10,104 8,744 36,099 32,338 46% 78,918 70,761
France 3,825 3,632 - - - - - - 3,825 3,632 46% 8,250 7,828
Germany - - 2,327 1,850 - - - - 388 308 35% 1,109 880
Ireland - - - - - - - - - - - - -
Netherlands - - 34,682 33,807 - - 48 24 5,828 5,659 54% 10,743 10,441
USA - - - - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- --- --- --- ---
Total 3,825 3,632 115,570 104,938 77,410 72,283 10,152 8,768 46,140 41,937 47% 99,020 89,910
----- ----- ----- ------- ------- ------ ------ ------ ----- ------ ------ --- ------ ------
Table 11: Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2017 - 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 - - - - - - - - - -
Canada 1,324,088 692,454 384,479 223,327 133,827 968,246 491,682 261,417 143,098 78,999
France 646,356 356,990 207,518 125,059 77,334 475,460 249,755 136,639 76,160 42,380
Germany 25,368 15,606 8,171 2,911 (697) 15,012 7,957 2,377 (1,574) (4,234)
Ireland - - - - - - - - - -
Netherlands 30,463 22,364 16,718 12,743 9,886 18,249 13,309 9,784 7,297 5,522
USA 705,352 353,098 190,899 109,417 65,316 553,775 277,974 149,964 85,463 50,507
--- ------- ------- ------- ------- ------ ------- ------- ------- ------ ------
Total 2,731,627 1,440,512 807,785 473,457 285,666 2,030,742 1,040,677 560,181 310,444 173,174
----- --------- --------- ------- ------- ------- --------- --------- ------- ------- -------
Contingent (2C) - Best Estimate (7)
Development Pending (10)
Australia (11) 81,610 50,240 31,044 19,219 11,873 17,295 7,186 1,687 (1,167) (2,534)
Canada (12) 2,286,705 1,179,969 662,147 394,654 245,475 1,674,927 844,557 458,109 261,348 153,799
France (13) 1,414,420 759,973 439,654 268,026 170,036 1,048,109 540,491 298,625 172,711 103,017
Germany (14) 116,948 83,758 60,390 44,003 32,395 80,292 56,601 39,643 27,741 19,370
Ireland - - - - - - - - - -
Netherlands (15) 81,618 57,215 41,025 29,997 22,252 43,748 28,728 18,805 12,189 7,679
USA (16) 1,275,912 623,677 342,983 205,348 130,725 1,004,012 492,135 270,653 161,886 102,881
------- --------- ------- ------- ------- ------- --------- ------- ------- ------- -------
Total 5,257,213 2,754,832 1,577,243 961,247 612,756 3,868,383 1,969,698 1,087,522 634,708 384,212
----- --------- --------- --------- ------- ------- --------- --------- --------- ------- -------
Contingent (3C) - High Estimate (8)
Development Pending (10)
Australia 162,700 104,204 67,988 45,184 30,555 54,329 31,507 18,140 10,277 5,629
Canada 3,312,383 1,649,632 923,352 557,850 354,901 2,402,861 1,167,883 630,702 364,282 219,347
France 2,463,627 1,310,231 760,541 468,396 301,212 1,827,017 934,100 520,513 306,268 186,763
Germany 302,880 217,383 159,970 120,614 92,931 212,387 151,748 110,557 82,278 62,446
Ireland - - - - - - - - - -
Netherlands 205,065 142,394 103,727 78,262 60,611 110,555 74,368 52,017 37,485 27,588
USA 2,174,766 1,004,149 546,550 330,707 215,009 1,713,929 792,856 431,644 261,128 169,703
--- --------- --------- ------- ------- ------- --------- ------- ------- ------- -------
Total 8,621,421 4,427,993 2,562,128 1,601,013 1,055,219 6,321,078 3,152,462 1,763,573 1,061,718 671,476
----- --------- --------- --------- --------- --------- --------- --------- --------- --------- -------
Contingent (1C) - Low Estimate (6)
Development Unclarified (17)
Australia - - - - - - - - - -
Canada 53,655 21,601 9,005 3,855 1,673 41,934 16,497 6,597 2,643 1,029
France 97,733 53,885 31,470 19,270 12,266 73,554 40,473 23,562 14,377 9,118
Germany - - - - - - - - - -
Ireland - - - - - - - - - -
Netherlands 13,366 8,426 5,351 3,406 2,156 6,990 3,867 1,988 855 175
USA - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- ---
Total 164,754 83,912 45,826 26,531 16,095 122,478 60,837 32,147 17,875 10,322
----- ------- ------ ------ ------ ------ ------- ------ ------ ------ ------
Contingent (2C) - Best Estimate (7)
Development Unclarified (17)
Australia - - - - - - - - - -
Canada (18) 371,151 160,012 67,074 23,472 2,109 267,364 108,714 38,845 6,527 (8,792)
France (19) 180,756 91,957 50,625 29,643 18,218 134,726 67,893 36,941 21,367 12,973
Germany 472 736 724 616 487 (353) 41 132 107 45
Ireland - - - - - - - - - -
Netherlands (20) 101,333 60,727 37,612 23,937 15,510 58,291 33,549 19,395 11,127 6,149
USA - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- ---
Total 653,712 313,432 156,035 77,668 36,324 460,028 210,197 95,313 39,128 10,375
----- ------- ------- ------- ------ ------ ------- ------- ------ ------ ------
Contingent (3C) - High Estimate (8)
Development Unclarified (17)
Australia - - - - - - - - - -
Canada 685,972 314,515 159,130 85,452 47,007 547,002 261,869 138,799 78,569 46,086
France 292,883 138,555 73,474 42,171 25,626 217,128 101,766 53,321 30,222 18,141
Germany 4,579 4,019 3,344 2,727 2,210 2,638 2,450 2,054 1,651 1,300
Ireland - - - - - - - - - -
Netherlands 244,742 135,716 82,312 53,187 35,980 141,378 76,237 44,453 27,335 17,400
USA - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- ---
Total 1,228,176 592,805 318,260 183,537 110,823 908,146 442,322 238,627 137,777 82,927
----- --------- ------- ------- ------- ------- ------- ------- ------- ------- ------
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 2017
reserves report were also
utilized by GLJ in
preparing the GLJ Resource
Assessment. See "Forecast
Prices Used in Estimates"
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) 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) Risked development pending
best estimate 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 risked
estimated cost to bring
these contingent resources
on commercial production
is $143 MM and the
expected timeline is
between 6 and 8 years.
The specific contingencies
for these resources are
corporate commitment and
development timing.
(12) Risked development pending
best estimate 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 risked
estimated cost to bring
these contingent resources
on commercial production
is $1,066 MM and the
expected timeline is
between 3 and 12 years.
The specific contingencies
for these resources are
corporate commitment and
development timing.
(13) Risked development pending
best estimate 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 risked
estimated cost to bring
these contingent resources
on commercial production
is $571 MM and the
expected timeline is
between 3 and 12 years.
The specific contingencies
for these resources are
corporate commitment and
development timing.
(14) Risked development pending
best estimate 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 risked
estimated cost to bring
these contingent resources
on commercial production
is $75 MM and the expected
timeline is between 2 and
4 years. The specific
contingencies for these
resources are corporate
commitment and development
timing.
(15) Risked development pending
best estimate 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 risked
estimated cost to bring
these contingent resources
on commercial production
is $45 MM and the expected
timeline is between 2 and
4 years. The specific
contingencies for these
resources are corporate
commitment and development
timing.
(16) Risked development pending
best estimate 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 risked
risked estimated cost to
bring these contingent
resources on commercial
production is $380 MM and
the expected timeline is
between 1 and 11 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 26.8 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 $323 MM
with an expected timeline
of 3 to 12 years.
Edson Duvernay Based on
contingencies
related to
corporate
commitment
and
development
timing,
economic
risks
associated
with lower
liquid
yields, and
capital and
operating
cost
uncertainty,
GLJ has
estimated
risked
unclarified
best estimate
contingent
resources at
15.5 mmboe
and the
risked
estimated
cost to bring
these
resources on
commercial
production is
$242.8 MM.
The expected
timeline is 3
to 7 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
4.7 mmboe and
the risked
estimated
cost to bring
these
resources on
commercial
production is
$31 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
3.2 mmboe and
the risked
estimated
cost to bring
these
resources on
commercial
production is
$23 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
3.3 mmboe and
the risked
estimated
cost to bring
these
resources on
commercial
production is
$26 MM. The
expected
timeline is 4
to 6 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 $37 MM
with an expected timeline
of 7 to 8 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 7
to 9 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
$8 MM. The
expected
timeline is 8
to 10 years.
(20) In the Netherlands, GLJ has
estimated an aggregate of
risked unclarified best
estimate contingent
resources of 3.1 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 $51 MM
with an expected timeline
of 8 to 10 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
1.5 mmboe and
the risked
estimated
cost to bring
these
resources on
commercial
production is
$25 MM. The
expected
timeline is 3
to 7 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
1.6 mmboe and
the risked
estimated
cost to bring
these
resources on
commercial
production is
$26 MM. The
expected
timeline is 3
to 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, 2017. 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 51.5 million boe (low estimate) to 260.4 million boe (high estimate), with a best estimate of 153.4 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.
Summary of Risked Oil and Gas Prospective Resources as at December 31, 2017((1)(2)) - Forecast Prices and Costs((3)(4))
Resources Light Crude Oil & Conventional Coal Bed Natural Gas BOE Unrisked
Medium Crude Oil Natural Gas Methane Liquids BOE
---------------- ----------- ------- ------- ---
Project
Maturity Gross Net Gross Net Gross Net Gross Net Gross Net Chance of Gross Net
Commerciality
Sub-Class (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe) % (9) (Mboe) (Mboe)
--------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ---- ----- -----
Prospective -Low
Estimate
Prospect (10)
Australia - - - - - - - - - - - -
Canada 185 168 66,480 61,570 - - 4,522 3,982 15,787 14,412 34.0% 46,435 42,388
France 5,528 4,977 - - - - - - 5,528 4,977 21.3% 25,904 23,366
Germany - - 136,066 116,769 - - - - 22,678 19,462 29.0% 78,200 67,110
Ireland - - - - - - - - - - - -
Netherlands - - 44,603 41,372 - - 50 46 7,484 6,941 10.1% 73,823 68,723
USA - - - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- --- --- ---
Total 5,713 5,145 247,149 219,711 - - 4,572 4,028 51,477 45,792 22.9% 224,362 201,587
----- ----- ----- ------- ------- --- --- ----- ----- ------ ------ ---- ------- -------
Prospective -Best
Estimate
Prospect (10)
Australia (11) 579 579 - - - - - - 579 579 48.0% 1,206 1,206
Canada (12) 2,090 1,871 162,093 147,542 112,623 106,205 24,876 22,098 72,752 66,260 23.5% 309,610 281,957
France (13) 16,335 14,636 - - - - - - 16,335 14,636 21.4% 76,358 68,393
Germany (14) - - 292,725 251,987 - - - - 48,788 41,998 29.0% 168,235 144,821
Ireland - - - - - - - - - - - -
Netherlands (15) - - 89,366 82,029 - - 96 89 14,990 13,761 10.2% 147,256 134,912
USA - - - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- --- --- ---
Total 19,004 17,086 544,184 481,558 112,623 106,205 24,972 22,187 153,444 137,234 21.8% 702,665 631,289
----- ------ ------ ------- ------- ------- ------- ------ ------ ------- ------- ---- ------- -------
Prospective -High
Estimate
Prospect (10)
Australia 1,462 1,462 - - - - - - 1,462 1,462 48.0% 3,046 3,046
Canada 2,684 2,383 231,682 209,203 147,282 136,241 38,134 32,553 103,979 92,510 23.8% 436,843 388,697
France 35,640 32,301 - - - - - - 35,640 32,301 22.8% 156,320 141,671
Germany - - 554,429 479,424 - - - - 92,405 79,904 29.0% 318,638 275,531
Ireland - - - - - - - - - - - -
Netherlands - - 160,271 148,815 - - 171 159 26,883 24,962 10.6% 252,881 235,491
USA - - - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- --- --- ---
Total 39,786 36,146 946,382 837,442 147,282 136,241 38,305 32,712 260,369 231,139 22.3% 1,167,728 1,044,436
----- ------ ------ ------- ------- ------- ------- ------ ------ ------- ------- ---- --------- ---------
Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2017 - 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)
Australia - - - - - - - - - -
Canada 207,770 95,938 44,659 19,798 7,252 169,908 75,170 32,207 11,777 1,780
France 238,004 131,320 76,140 46,216 29,224 187,762 102,964 59,117 35,418 22,032
Germany 368,323 169,166 74,634 29,008 6,565 252,131 112,397 44,221 11,701 (3,782)
Ireland - - - - - - - - - -
Netherlands 274,447 125,347 68,782 42,725 28,862 145,575 61,601 29,728 15,701 8,716
USA - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- ---
Total 1,088,544 521,771 264,215 137,747 71,903 755,376 352,132 165,273 74,597 28,746
----- --------- ------- ------- ------- ------ ------- ------- ------- ------ ------
Prospective (Pr2) -Best Estimate (7)
Prospect (10)
Australia (11) 41,338 23,669 14,015 8,555 5,365 16,344 8,905 4,999 2,884 1,705
Canada (12) 1,491,712 623,324 281,364 133,988 65,665 1,065,129 430,068 182,436 78,310 31,913
France (13) 722,008 401,287 237,931 149,181 98,046 533,938 289,739 167,209 101,849 64,935
Germany (14) 1,259,830 556,044 260,954 126,408 60,705 883,031 385,237 174,225 78,544 32,534
Ireland - - - - - - - - - -
Netherlands (15) 664,124 319,700 187,996 124,429 88,794 358,130 165,622 92,188 57,620 38,865
USA - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- ---
Total 4,179,012 1,924,024 982,260 542,561 318,575 2,856,572 1,279,571 621,057 319,207 169,952
----- --------- --------- ------- ------- ------- --------- --------- ------- ------- -------
Prospect (10)
Australia 136,670 74,308 43,028 26,126 16,460 57,049 30,416 17,274 10,298 6,378
Canada 2,681,315 1,109,012 521,064 267,963 146,940 1,909,850 772,257 349,756 171,101 87,888
France 1,937,405 1,011,329 573,475 347,956 223,097 1,458,826 749,093 417,797 249,512 157,614
Germany 2,751,890 1,219,651 585,356 295,653 153,056 1,969,884 858,139 400,902 194,089 93,693
Ireland - - - - - - - - - -
Netherlands 1,355,100 675,317 411,776 281,254 206,125 738,129 360,566 214,793 143,533 103,140
USA - - - - - - - - - -
--- --- --- --- --- --- --- --- --- --- ---
Total 8,862,380 4,089,617 2,134,699 1,218,952 745,678 6,133,738 2,770,471 1,400,522 768,533 448,713
----- --------- --------- --------- --------- ------- --------- --------- --------- ------- -------
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 2017 reserves report were also
utilized by GLJ in preparing the
GLJ Resource Assessment. See "GLJ
December 31, 2017 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 CoDis
and the CoDev. CoDis is defined in
COGEH as the estimated probability
that exploration activities will
confirm the existence of a
significant accumulation of
potentially recoverable petroleum.
CoDev is defined as the estimated
probability that, once discovered,
a known accumulation will be
commercially developed.
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:
--
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.
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 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 27% and the
aggregate CoDis at 88%. The
corresponding chance of
commerciality is 23%. Risked best
estimate prospective resources have
been estimated at an aggregate of
72.8 mmboe. Utilizing established
recovery technology, the risked
estimated cost to bring these
resources on commercial production
is an aggregate of $1061 MM. The
expected development timeline is 2
to 20 years.
Edson Duvernay Based on reservoir risk,
development timing and economic
risk related to capital and
operating cost uncertainty, GLJ
has estimated the CoDev at 19% and
the CoDis at 90%. The
corresponding chance of
commerciality is 17%. Risked best
estimate prospective resources
have been estimated at 33.6 mmboe
and the risked estimated cost to
bring these resources on
commercial production is $638 MM
with an expected timeline of 7 to
14 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
9 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
6.2 mmboe and the risked estimated
cost to bring these resources on
commercial production is $53 MM
with an expected timeline of 6 to
12 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 $66 MM.
The expected development timeline
is 9 to 11 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
3.3 mmboe and the risked estimated
cost to bring these resources on
commercial production is $60 MM
with an expected timeline of 7 to
11 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
2.7 mmboe and the risked estimated
cost to bring these resources on
commercial production is $23 MM
with an expected timeline of 15 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 MM
with an expected timeline of 3 to
9 years.
(13) Prospective resources for
France have been estimated
based on the individual
prospects outlined below.
GLJ has estimated the
aggregate CoDev at 74% and
the aggregate CoDis at 28%.
The corresponding chance of
commerciality is 21%.
Risked best estimate
prospective resources have
been estimated at an
aggregate of 16.3.
Utilizing established
recovery technology, the
risked estimated cost to
bring these resources on
commercial production is an
aggregate of $380 MM. The
expected development
timeline is 1 to 13 years.
Seebach Prospect Based on risks associated with
seal, trap, reservoir and charge
along with development timing, GLJ
has estimated the CoDev at 75% and
the CoDis at 18%. The
corresponding chance of
commerciality is 14%.
Risked best estimate prospective
resources have been estimated at
7.8 mmboe and the risked estimated
cost to bring these resources on
commercial production is $40 MM
with an expected timeline of 5 to
7 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 $233 MM
with an expected timeline of 9 to
13 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 $35 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 $7 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 67%. The corresponding
chance of commerciality is 54%.
Risked best estimate prospective
resources have been estimated at
0.9 mmboe and the risked estimated
cost to bring these resources on
commercial production is $21 MM
with an expected timeline of 1 to
11 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 $14 MM
with an expected timeline of 7 to
9 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 $19 MM
with an expected timeline of 10 to
12 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 $7 MM
with an expected timeline of 4 to
5 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 $4 MM
with an expected timeline of 4 to
5 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 10%. 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 $1 MM
with an expected timeline of 8
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
0.07 mmboe and the risked
estimated cost to bring these
resources on commercial production
is $1 MM with an expected
timeline of 4 to 5 years.
(14) Prospective resources for
Germany have been estimated
based on the individual
prospects outlined below.
GLJ has estimated the
aggregate CoDev at 70% and
the aggregate CoDis at 42%.
The corresponding chance of
commerciality is 29%. Risked
best estimate prospective
resources have been
estimated at an aggregate of
48.8 mmboe. Utilizing
established recovery
technology, the risked
estimated cost to bring
these resources on
commercial production is an
aggregate of 313.4 MM. The
expected development
timeline is 1 to 13 years.
Wisselshorst A Prospect Based on seal and trap risk along
with development timing , GLJ has
estimated the CoDev at 90%, and
the CoDisc at 58%. The
corresponding chance of
commerciality is 52%. Risked Best
Estimate Prospective resources
have been estimated at 13.5 mmboe
and the risked estimated cost to
bring these resources on
commercial production is $85.5MM
with an expected timeline of 2 to
9 years.
Ihlow Prospect Based on reservoir, seal and trap
risk along with development
timing, GLJ has estimated the
CoDev at 71%, and the CoDisc 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 $46.6MM
with an expected timeline of 5 to
7 years.
Wisselshorst B Prospect Based on reservoir, seal and trap
risk along with development
timing, GLJ has estimated the
CoDev at 90%, and the CoDisc at
50%. The corresponding chance of
commerciality is 45%. Risked Best
Estimate Prospective resources
have been estimated at 5.5 mmboe
and the risked estimated cost to
bring these resources on
commercial production is $42.7MM
with an expected timeline of 5 to
12 years.
Weissenmoor South Based on reservoir and trap risk
along with development timing, GLJ
has estimated the CoDev at 90%,
and the CoDisc at 36%. The
corresponding chance of
commerciality is 32%. Risked Best
Estimate Prospective resources
have been estimated at 4.2 mmboe
and the risked estimated cost to
bring these resources on
commercial production is $15.9MM
with an expected timeline of 3 to
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 CoDisc 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 $16MM
with an expected timeline of 8 to
9 years.
Fallingbostel Based on reservoir, seal and trap
risk along with development
timing, GLJ has estimated the
CoDev at 90%, and the CoDisc at
29%. The corresponding chance of
commerciality is 26%. 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 $29.5MM
with an expected timeline of 3 to
9 years.
Hellwege Based on reservoir and trap risk
along with development timing, GLJ
has estimated the CoDev at 90%,
and the CoDisc at 40%. The
corresponding chance of
commerciality is 36%. Risked Best
Estimate Prospective resources
have been estimated at 2.9 mmboe
and the risked estimated cost to
bring these resources on
commercial production is $16.1MM
with an expected timeline of 3 to
8 years.
Jeddeloh Prospect Based on reservoir, seal and trap
risk along with development
timing, GLJ has estimated the
CoDev at 38%, and the CoDisc at
32%. The corresponding chance of
commerciality is 12%. Risked Best
Estimate Prospective resources
have been estimated at 2.9 mmboe
and the risked estimated cost to
bring these resources on
commercial production is $23.1MM
with an expected timeline of 3 to
12 years.
Ohlendorf Prospect Based on source and trap risk along
with development timing, GLJ has
estimated the CoDev at 58%, and
the CoDisc 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 $11.1MM
with an expected timeline of 9 to
13 years.
Uphuser Meer Prospect Based on reservoir, seal and trap
risk along with development
timing, GLJ has estimated the
CoDev at 47%, and the CoDisc at
51%. The corresponding chance of
commerciality is 24%. Risked Best
Estimate Prospective resources
have been estimated at 1.7 mmboe
and the risked estimated cost to
bring these resources on
commercial production is $8.3MM
with an expected timeline of 6 to
7 years.
Simonswolde North Prospect Based on reservoir, seal and trap
risk along with development timing
, GLJ has estimated the CoDev at
62%, and the CoDisc 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 $6.1MM
with an expected timeline of 6 to
7 years.
Burgmoor Z5 Prospect Based on reservoir, seal and trap
risk along with development
timing, GLJ has estimated the
CoDev at 63%, and the CoDisc at
52%. The corresponding chance of
commerciality is 33%. Risked Best
Estimate Prospective resources
have been estimated at 0.7mmboe
and the risked estimated cost to
bring these resources on
commercial production is $1.1MM
with an expected timeline of 1
year.
Widdernhausen East Prospect Based on reservoir, seal and trap
risk along with development
timing, GLJ has estimated the
CoDev at 32%, and the CoDisc at
44%. The corresponding chance of
commerciality is 14%. Risked Best
Estimate Prospective resources
have been estimated at 0.4 mmboe
and the risked estimated cost to
bring these resources on
commercial production is $2.7MM
with an expected timeline of 7 to
12 years.
Wellie Prospect Based on reservoir, seal and source
risk along with development
timing, GLJ has estimated the
CoDev at 32%, and the CoDisc 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 $3.3MM
with an expected timeline of 10
years.
Otterstedt Prospect Based on reservoir, seal and trap
risk along with development timing
, GLJ has estimated the CoDev at
46%, and the CoDisc 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 $3.5MM
with an expected timeline of 8 to
13 years.
Ostervesede Prospect Based on reservoir and seal risk
along with development timing, GLJ
has estimated the CoDev at 23%,
and the CoDisc 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 $0.7MM
with an expected timeline of 7 to
10 years.
(15) Prospective
resources for
Netherlands have
been estimated
based on the
factors outlined
below. GLJ has
estimated the
aggregate CoDev
at 28% and the
aggregate CoDis
at 39%. The
corresponding
chance of
commerciality is
11%. Risked best
estimate
prospective
resources have
been estimated at
an aggregate of
15.0 mmboe.
Utilizing
established
recovery
technology, the
risked estimated
cost to bring
these resources
on commercial
production is an
aggregate of 127
MM with an
expected timeline
of 2 to 15 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 41%. The
corresponding
chance of
commerciality is
10%. Risked best
estimate
prospective
resources have
been estimated at
an aggregate of
12.1 mmboe and
the risked
estimated cost to
bring these
resources on
commercial
production is an
aggregate of 83
MM with an
expected timeline
of 2 to 15 years.
-- Chance of discovery provided for 109
prospective reservoir targets across
91 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.
-- 65 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 41% and
the aggregate
CoDis at 28%. The
corresponding
chance of
commerciality is
12%. Risked best
estimate
prospective
resources have
been estimated at
an aggregate of
2.9 mmboe and the
risked estimated
cost to bring
these resources
on commercial
production is an
aggregate of$ 43
MM with an
expected timeline
of 2 to 12 years.
-- Chance of discovery provided for 25
prospective reservoir targets across
21 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.
-- 17 prospects summed probabilistically
across 5 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 emphasizes organic production growth augmented with value-adding acquisitions, 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 currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion currently pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.0%.
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 Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted 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.
