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

February 27, 2017

 

CALGARY, Feb. 27, 2017 /CNW/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce summary 2016 year-end reserves and resource information.  The estimates of reserves and resources and other oil and gas information contained in this news release have been estimated by GLJ Petroleum Consultants Ltd. ("GLJ") effective as at December 31, 2016 and prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGEH"). For additional information about Vermilion, including Vermilion's statement of reserves data and other information in Form 51-101F1, report on reserves data by independent qualified reserves evaluator or auditor in Form 51-101F2 and report of management and directors on oil and gas disclosure in Form 51-101F3, please review the Company's Annual Information Form for the year ended December 31, 2016, to be filed on February 27, 2017 and available on SEDAR at www.sedar.com and on the SEC's EDGAR system at www.sec.gov.

HIGHLIGHTS

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

 

(1)

As evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 1, 2017 with an effective date of December 31, 2016.

(2)

F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital ("FDC"), by the change in the reserves, incorporating revisions and production, for the same period.

(3)

"Operating Recycle Ratio" is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost).  "Operating Netback" is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis.

(4)

Vermilion retained GLJ to conduct an independent resource evaluation dated February 1, 2017 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2016 (the "GLJ 2016 Resource Assessment").  The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 84%, 83% and 82%, respectively.  The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Unclarified category are 55%, 54% and 55%, respectively.  The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 25%, 26% and 26%, respectively.  There is uncertainty that it will be commercially viable to produce any portion of the resources.

(5)

Vermilion retained GLJ to conduct an independent resource evaluation dated February 8, 2016 to assess contingent resources across all of the Company's key operating regions with an effective date of December 31, 2015 (the "GLJ 2015 Resource Assessment").  The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 83%, 82% and 81%, respectively.  There is uncertainty that it will be commercially viable to produce any portion of the resources.  For further information, see the "Contingent Resources" section of this news release.

 

DISCLAIMER

Certain statements included or incorporated by reference in this news release may constitute forward looking statements or financial outlooks under applicable securities legislation.  Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook.  Forward looking statements or information in this news release may include, but are not limited to: 

  • capital expenditures;
  • business strategies and objectives;
  • estimated reserve quantities and the discounted present value of future net cash flows from such reserves;
  • petroleum and natural gas sales;
  • future production levels (including the timing thereof) and rates of average annual production growth, estimated contingent resources and prospective resources;
  • exploration and development plans;
  • acquisition and disposition plans and the timing thereof;
  • operating and other expenses, including the payment of future dividends;
  • royalty and income tax rates;
  • the timing of regulatory proceedings and approvals; and
  • the estimate of Vermilion's share of the expected natural gas production from the Corrib field.


Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect.  In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things:

  • the ability of the Company to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally;
  • the ability of the Company to market crude oil, natural gas liquids and natural gas successfully to current and new customers;
  • the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation;
  • the timely receipt of required regulatory approvals;
  • the ability of the Company to obtain financing on acceptable terms;
  • foreign currency exchange rates and interest rates;
  • future crude oil, natural gas liquids and natural gas prices; and
  • Management's expectations relating to the timing and results of development activities.

 

 

Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct.  Financial outlooks are provided for the purpose of understanding the Company's financial strength and business objectives and the information may not be appropriate for other purposes.  Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward looking statements or information.  These risks and uncertainties include but are not limited to:

  • the ability of management to execute its business plan;
  • the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids and natural gas;
  • risks and uncertainties involving geology of crude oil, natural gas liquids and natural gas deposits;
  • risks inherent in the Company's marketing operations, including credit risk;
  • the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures;
  • the uncertainty of estimates and projections relating to production, costs and expenses;
  • potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
  • the Company's ability to enter into or renew leases on acceptable terms;
  • fluctuations in crude oil, natural gas liquids and natural gas prices, foreign currency exchange rates and interest rates;
  • health, safety and environmental risks;
  • uncertainties as to the availability and cost of financing;
  • the ability of the Company to add production and reserves through exploration and development activities;
  • general economic and business conditions;
  • the possibility that government policies or laws may change or governmental approvals may be delayed or withheld;
  • uncertainty in amounts and timing of royalty payments;
  • risks associated with existing and potential future law suits and regulatory actions against the Company; and
  • other risks and uncertainties described elsewhere in the annual information form of the Company for the year ended December 31, 2016 or in the Company's other filings with Canadian securities authorities.

 

The forward-looking statements or information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.

RESERVES, FUTURE NET REVENUE AND OTHER OIL AND GAS INFORMATION

The following is a summary of the oil and natural gas reserves and the value of future net revenue of Vermilion as evaluated by GLJ, independent petroleum engineering consultants in Calgary in a report dated February 1, 2017 with an effective date of December 31, 2016 (the "GLJ 2016 Reserves Evaluation").  The GLJ 2016 Reserves Evaluation was prepared in accordance with National Instrument 51-101 and COGEH. 

Reserves and other oil and gas information in this news release is effective December 31, 2016 unless otherwise stated.

All evaluations of future net production revenue set forth in the tables below are stated after overriding and lessor royalties, Crown royalties, freehold royalties, mineral taxes, direct lifting costs, normal allocated overhead and future capital investments, including abandonment and reclamation obligations.  Future net production revenues estimated by the GLJ 2016 Reserves Evaluation do not represent the fair market value of the reserves.  Other assumptions relating to the costs, prices for future production and other matters are included in the GLJ 2016 Reserve Evaluation.  There is no assurance that the future price and cost assumptions used in the GLJ 2016 Reserves Evaluation will prove accurate and variances could be material.

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

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

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

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

Table 1: Forecast Prices used in Estimates (1)

 

Light Crude Oil and

& Medium Crude Oil

Crude Oil

Conventional

Natural Gas

Canada

Conventional

Natural Gas

Europe

Natural Gas

Liquids

Inflation

Rate

Exchange
Rate

Exchange
Rate

 

WTI

Edmonton

Cromer

Brent Blend

 

National Balancing

       
 

Cushing

Par Price

Medium

FOB

AECO

Point

FOB

     
 

Oklahoma

40˚ API

29.3˚ API

North Sea

Gas Price

(UK)

Field Gate

Percent

   

Year

($US/bbl)

($Cdn/bbl)

($Cdn/bbl)

 ($US/bbl)

($Cdn/MMBtu)

($US/MMBtu)

($Cdn/bbl)

Per Year

($US/$Cdn)

($CdnEUR)

2016

43.30

52.95

48.71

45.01

2.19

4.65

34.50

1.50

0.76

1.47

Forecast

                   

2017

55.00

69.33

64.48

57.00

3.46

5.75

40.40

2.00

0.75

1.40

2018

59.00

72.26

67.20

61.00

3.10

6.00

41.41

2.00

0.78

1.35

2019

64.00

75.00

69.75

66.00

3.27

6.25

42.94

2.00

0.80

1.31

2020

67.00

76.36

71.02

70.00

3.49

6.50

43.77

2.00

0.83

1.27

2021

71.00

78.82

73.31

74.00

3.67

6.75

45.24

2.00

0.85

1.24

2022

74.00

82.35

76.59

77.00

3.86

6.89

47.30

2.00

0.85

1.24

2023

77.00

85.88

79.87

80.00

4.05

7.02

49.25

2.00

0.85

1.24

2024

80.00

89.41

83.15

83.00

4.16

7.16

51.23

2.00

0.85

1.24

2025

83.00

92.94

86.44

86.00

4.24

7.31

53.42

2.00

0.85

1.24

2026

86.05

95.61

88.92

89.64

4.32

7.45

54.80

2.00

0.85

1.24

Thereafter

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

2.0%

0.850

1.235

   

Note:

 (1) 

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

 

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

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

Table 2: Capital Costs Incurred

 

Acquisition Costs

 
 

Proved

Unproved

Exploration

Development

Total

(M$)

Properties

Properties

Costs

Costs

Costs

Australia

-

-

-

59,910

59,910

Canada

13,309

-

-

62,706

76,015

Croatia

-

-

2,968

-

2,968

France

-

-

-

68,472

68,472

Germany

48,377

-

-

3,803

52,180

Hungary

-

-

338

-

338

Ireland

-

-

-

9,375

9,375

Netherlands

28,259

-

-

23,740

51,999

United States                       

5,935

-

-

13,539

19,474

Total

95,880

-

3,306

241,545

340,731

 

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

Table 3: Reserve Life Index

Commodity

Production

 

Reserve Life Index (years)

 

Fourth Quarter 2016

 

Total Proved

 

Proved Plus Probable

Crude oil, condensate and natural gas liquids (bbl/d)        

28,439

 

9.9

 

15.9

Natural gas (mmcf/d)

194.54

 

6.2

 

10.6

Oil Equivalent (boe/d)

60,863

 

7.9

 

13.1

 

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

The following tables may not total due to rounding.

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

 

Light Crude Oil & Medium
Crude Oil

Heavy Oil

Tight Oil

Conventional Natural Gas

 

Gross (2)

Net (2)

Gross (2)

Net (2)

Gross (2)

Net (2)

Gross (2)

Net (2)

 

(Mbbl)

(Mbbl)

(Mbbl)

(Mbbl)

(Mbbl)

(Mbbl)

(MMcf)

(MMcf)

Proved Developed Producing (3) (5) (6)

               

Australia

10,718

10,718

-

-

-

-

-

-

Canada

12,277

10,990

-

-

12

8

112,918

101,728

France

36,481

33,478

-

-

-

-

5,412

5,024

Germany

4,805

Vermilion Energy Inc.
3500, 520 3rd Avenue SW
Calgary, Alberta T2P 0R3
Phone: 1-403-269-4884
Fax: 1-403-476-8100
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