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Questerre reports year-end reserves and resources


Source: Questerre Energy Corporation

THIS NEWS RELEASE IS NOT FOR DISSEMINATION OR DISTRIBUTION IN THE UNITED STATES OF AMERICA
TO UNITED STATES NEWSWIRE SERVICES OR UNITED STATES PERSONS

CALGARY, Alberta, March 12, 2018 (GLOBE NEWSWIRE) — Questerre Energy Corporation (“Questerre” or the “Company”) (TSX:QEC) (OSE:QEC) reported today on the results of its December 31, 2017 Reserves Assessment and Evaluation of its oil and natural gas properties (the “Report”), as evaluated by McDaniel & Associates Consultants Ltd.(“McDaniel”) with an effective date of December 31, 2017, prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ( “NI 51-101”).

Michael Binnion, President and Chief Executive Officer, commented, “Our reserve growth reflects the active drilling program at Kakwa this year and the light oil acquisition at Antler. Corporate proved and probable reserves gross reserves grew by 20% or 3.22 MMBoe from 15.7 MMBoe to 18.41 MMBoe, net of production during the year. The before tax NPV-10% estimated for the corporate proved and probable reserves using McDaniel’s year-end price forecast is $174.70 million.”

Commenting on Questerre’s Utica resources in Quebec, he added, “The reserve engineers updated our resource report from last year for their current price forecast. The best estimate of risked contingent resources net to Questerre for the Becancour and Lotbiniere project areas is unchanged at 214 Bcf. These project areas as assessed only cover 5% of our total acreage. The risked net present value discounted at 10% before tax for this limited development area is $301 million compared to $311 million last year.”

Credit Facility

The Company also reported on the status of its credit facility review that was conducted in the fourth quarter of 2017. The lender has advised that the primary credit facility will be renewed at $18 million. The facility will include a $17.9 million revolving operating demand facility (“Credit Facility A”). Credit Facility A can be used for general corporate purposes, ongoing operations and capital expenditures within Canada.

December 31, 2017 Reserve Information

In accordance with the requirements of NI 51-101, the Company anticipates filing its Annual Information Form that includes more detailed disclosure relating to petroleum and natural gas activities for the 2017 fiscal year, in the form of Form 51-101F1, at the end of March 2018 as set out in the Report.

The following tables set forth contain certain information relating to the oil and natural gas reserves of the Company’s properties and the present value of the estimated future net cash flow associated with such reserves as at December 31, 2017, which numbers may vary slightly from those presented in the Report due to rounding. Also, due to rounding, certain columns may not add exactly.

SUMMARY OF OIL AND GAS RESERVES
as of December 31, 2017

FORECAST PRICES AND COSTS

  LIGHT AND 
MEDIUM CRUDE OIL
CONVENTIONAL
NATURAL GAS
SHALE
GAS
NATURAL GAS
LIQUIDS
RESERVES CATEGORY Gross(1)
(Mbbl)
Net(2)
(Mbbl)
Gross(1)
(MMcf)
Net(2
(MMcf)
Gross(1)
(MMcf)
Net(2)
(MMcf)
Gross(1)
(Mbbl)
Net(2)
(Mbbl)
Proved
Developed Producing 1,203.6 1,154.8 298.7 277.7 5,486.4 5,080.7 1,001.4 794.3
Developed Non-Producing 11.8 8.8 46.2 42.4 429.9 397.5 88.1 74.6
  Undeveloped 433.9 413.1 15,324.6 14,123.1 2,835.1 2,446.8
Total Proved 1,649.3 1,576.8 344.9 320.0 21,241.0 19,601.3 3,924.6 3,315.7
Probable 623.4 594.6 170.0 156.3 27,337.5 24,954.3 4,028.3 3,202.2
Total Proved Plus Probable 2,272.8 2,171.4 514.8 476.3 48,578.5 44,555.6 7,952.9 6,517.9

(1) Gross reserves are working interest reserves before royalty deductions.
(2) Net reserves are working interest reserves after royalty deductions plus royalty interest reserves.
(3) Natural Gas Liquids include condensate volumes.

SUMMARY NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2017

FORECAST PRICES AND COSTS

  BEFORE INCOME TAXES DISCOUNTED AT
(%/YEAR)
AFTER INCOME TAXES DISCOUNTED AT
(%/YEAR)
UNIT VALUE
BEFORE TAX
RESERVES CATEGORY 0%
(M$)
5%
(M$)
10%
(M$)
15%
(M$)
20%
(M$)
0%
(M$)
5%
(M$)
10%
(M$)
15%
(M$)
20%
(M$)
@ 10%(1)
($/BOE)
Proved
Developed Producing 86,474.7 69,935.9 58,532.0 50,395.0 44,376.2 86,474.7 69,935.9 58,532.0 50,395.0 44,376.2 20.59
Developed Non‑Producing 4,624.5 4,008.3 3,562.1 3,226.3 2,964.3 4,624.5 4,008.3 3,562.1 3,226.3 2,964.3 22.72
Undeveloped 70,842.5 43,754.6 26,140.0 14,306.9 6,121.0 70,842.5 43,754.6 26,140.0 14,306.9 6,121.0 5.01
Total Proved 161,941.7 117,698.8 88,234.1 67,928.1 53,461.5 161,941.7 117,698.8 88,234.1 67,928.1 53,461.5 10.74
Probable 192,418.8 124,397.3 86,463.2 63,576.0 48,802.0 173,710.8 115,573.5 82,076.1 61,292.7 47,565.2 10.83
Total Proved Plus Probable 354,360.5 242,096.1 174,697.3 131,504.2 102,263.6 335,652.5 233,272.3 170,310.2 129,220.8 101,026.8 10.79

(1) The unit values are based on net reserve volumes.
(2) The estimated future net revenue from the production of disclosed oil and gas reserves does not represent fair market value of the Company’s reserves. There is no assurance that such price and cost assumptions will be attained and variances can be material.

SUMMARY OF PRICE FORECASTS  
Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 Thereafter
AECO Spot Price ($C/MMBtu) 2.25 2.65 3.05 3.40 3.60 3.65 3.75 3.80 3.90 2%
Edmonton Light Crude Oil ($C/bbl) 70.10 71.30 74.90 80.50 82.80 84.40 86.10 87.80 89.60 2%
Edmonton Condensate & Natural Gasoline (C$/bbl) 73.10 74.40 78.00 83.70 86.00 87.70 89.50 91.20 93.10 2%

December 31, 2017 Quebec Resource Information

Questerre also reported on the year-end update prepared by GLJ Petroleum Consultants Ltd. (“GLJ”) to the independent resource assessment of its 735,910 gross (190,800 net) acres in the St. Lawrence Lowlands Quebec that have potential for the Upper Utica Shale effective December 31, 2017 in a report dated March 5, 2018 (the “GLJ Resource Assessment”). The GLJ Resource Assessment was prepared in accordance with NI 51-101 and the standards contained in the COGE Handbook. The GLJ Resource Assessment did not include any of the Corporation’s other properties. All anticipated results disclosed herein were prepared by GLJ, which is an independent qualified reserves evaluator.

GLJ used probabilistic methods to generate low, best and high estimates of total petroleum initially in-place (“TPIIP”), both discovered and undiscovered. Recoverable Contingent and Prospective Resources over Questerre’s acreage were estimated by analogy and based on available well data over the Quebec Utica and public data from US Utica and Marcellus shale plays. The evaluation consisted of the Upper Utica which includes the Indian Castle and Dolgeville members as well as the Flat Creek. The Flat Creek, the lower most member, was only evaluated to estimate undiscovered petroleum initially-in-place (“UPIIP”). No recoverable resources were assigned to the Flat Creek given the lack of test data showing established technology can support commercial development at this time.

The GLJ Resource Assessment is based on the results from several vertical and horizontal wells on the Questerre’s acreage that have all encountered pay in the Utica. Test data from these wells in conjunction with offset development and studies of the analogous US Utica supports the prospective commercial development of these resources.

Significant positive factors relevant to the estimate of Questerre’s resources include the importation of all natural gas consumed in Quebec creating demand for local production, premium realized pricing due to the transportation costs associated with importing natural gas for consumption, production test data from Questerre’s existing wells and the development of the analogous Utica shale in the United States. Significant negative factors include the limited number of wells on Questerre’s acreage, lack of a developed service sector providing uncertainty regarding estimates of capital and operating costs, developing hydrocarbon regulations and environmental legislation and the requirement to obtain social acceptability for oil and gas operations.

While Questerre believes it will have sufficient financial capability to fund its share of costs associated with the development program in the GLJ Resource Assessment, it may not have access to the necessary capital when required. Conducting the development program is also dependent on the participation by Questerre’s joint venture partners. There is no guarantee that they will elect to participate in the program to the extent required. Questerre retains the right to conduct activities without the operators’ participation on an independent operations basis whereby it can fund 100% of the capital costs for certain well operations and facilities in return for net revenue equal to 400% of its capital investment before the operators can elect to either remain in a penalty position or hold a working interest.

Contingent Resources

The TPIIP was determined probabilistically on a permit basis with estimates of 45 to 145 Bcf per square mile for the Upper Utica. This compares favorably to analogous US shale plays with estimates of the Utica in Ohio at between 35 to 85 Bcf per square mile and 25 to 150 Bcf per square mile for the Marcellus shale in Pennsylvania. Of the TPIIP estimated over Questerre’s acreage, only land within a 3 mile radius of a successfully tested well was quantified as discovered gas-in-place. Based on this qualification only 16% of the total mapped TPIIP in the Upper Utica was considered discovered Contingent Resource.

The Upper Utica was considered undiscovered for approximately 84% of the total mapped TPIIP. Recovery factors of 18%, 26% and 37% were applied to the low, best and high estimates resource cases respectively.

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 Resource Assessment. All contingent resources evaluated in the GLJ Resource Assessment were deemed economic at the effective date of December 31, 2017.

Questerre’s average working interest in its gross best estimate Contingent Resources is 25.9%. In addition to Questerre’s working interest, the Company also holds a royalty interest in the acreage and associated resources. As a result, in some cases Questerre’s net volumes (after royalties) exceed its working interest volumes. For clarity, included in the following tables are Questerre’s volume before royalties, gross working interest volumes and net volumes after royalties.

A range of contingent resources estimates (low, best and high) were prepared by GLJ. See notes 5 to 7 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 on hold of 18.6 million boe (low estimate) to 50.0 million boe (high estimate), with a best estimate of 30.4 million boe.

The GLJ Resources Assessment estimated gross risked contingent resources with a project maturity subclass of development unclarified of 8.9 million boe (low estimate) to 23.8 million boe (high estimate), with a best estimate of 14.6 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.

Contingent resources can be sub-classified based on their project maturity sub-class which help identify a project’s change of commerciality. The project maturity subclasses for contingent resources are “development pending”, “development on hold”, “development unclarified” or “development not viable”, all as defined in the COGE Handbook. “Development pending” is when resolution of the final conditions for development is being actively pursued (high chance of development). “Development on hold” is when there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator. “Development unclarified” is when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. “Development not viable” is when no further data acquisition or evaluation is currently planned and hence there is a low chance of development.

Those areas classified as development on hold are primarily contingent on the passage of applicable hydrocarbon and environmental legislation and regulations as well as local acceptability. Remaining areas classified as development unclarified have additional contingency or risk associated with securing social license to operate and are thereby a lower priority for development. Additional contingencies include firm development plans, detailed cost estimates and corporate approvals and sanctioning. There is no certainty that any portion of the Contingent Resources will be economic to develop. Though pilot horizontal development plans have been proposed, the project evaluation scenario for the Contingent Resources is not sufficiently defined to make an investment decision to proceed to development.

Contingent Resources are evaluated based on the same fiscal conditions used in the assessment of reserves, and as such, are forecasted to be economic. Contingent Resource values are estimated on the basis of established technology, namely multistage hydraulic fracturing recovery technologies that are widely used in the development of shale gas plays including in the Montney in Canada and the Utica formation in Ohio.

The chance of commerciality for Contingent Resources is equal to the product of the chance of discovery and the chance of development. “Chance of discovery” is the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. “Chance of development” is the estimated probability that, once discovered, a known accumulation will be commercially developed. Based on contingencies related to the passage of applicable hydrocarbon and environmental legislation, regulations, local acceptability, and additional risk associated with securing social license to operate, firm development plans, detailed cost estimates and corporate approvals GLJ estimated the Chance of Development for the development unclarified subclass ranges between 10% and 25% as detailed in the table below. By definition the chance of discovery for Contingent Resource is 100%. The corresponding chance of commerciality for the development unclarified subclass is therefore estimated at between 10% and 25% as detailed in the table below.

SUMMARY OF OIL AND GAS RISKED RESOURCES
as of December 31, 2017

Summary Of Oil And Gas Risked Resources
Shale Gas Oil Equivalent
Company Interest Company Company Company Interest Company Company Chance of Chance of Chance of
Before Royalties Gross Net Before Royalties Gross Net Development Discovery Commerciality
Resources Category MMcf MMcf MMcf Mboe Mboe Mboe % % %
Contingent Resources
Low Estimate – On Hold
Becancour / Ste. Sophie-de-Levrard   62,618   53,020   57,222   10,436   8,837   9,537 70 100 70
La Visitation-de-Yamaska   –   –   –   –   –   –
St. David   –   –   –   –   –   –
St. Edouard-de-Lotbiniere   68,468   58,520   62,423   11,411   9,753   10,404 70 100 70
St. Francois-du-Lac / Pierreville   –   –   –   –   –   –
St. Louis   –   –   –   –   –   –
Utica Prospective Resources   –   –   –   –   –   –
Total: Low Estimate – On Hold   131,087   111,540   119,645   21,848   18,590   19,941
Best Estimate – On Hold
Becancour / Ste. Sophie-de-Levrard   102,466   86,760   93,559   17,078   14,460   15,593 70 100 70
La Visitation-de-Yamaska   –   –   –   –   –   –
St. David   –   –   –   –   –   –
St. Edouard-de-Lotbiniere   112,039   95,760   102,119   18,673   15,960   17,020 70 100 70
St. Francois-du-Lac / Pierreville   –   –   –   –   –   –
St. Louis   –   –   –   –   –   –
Utica Prospective Resources   –   –   –   –   –   –
Total: Best Estimate – On Hold   214,506   182,520   195,678   35,751   30,420   32,613
High Estimate – On Hold
Becancour / Ste. Sophie-de-Levrard   168,369   142,560   153,588   28,061   23,760   25,598 70 100 70
La Visitation-de-Yamaska   –   –   –   –   –   –
St. David   –   –   –   –   –   –
St. Edouard-de-Lotbiniere   184,098   157,349   167,695   30,683   26,225   27,949 70 100 70
St. Francois-du-Lac / Pierreville   –   –   –   –   –   –
St. Louis   –   –   –   –   –   –
Utica Prospective Resources   –   –   –   –   –   –
Total: High Estimate – On Hold   352,467   299,909   321,283   58,745   49,985   53,547
Shale Gas Oil Equivalent
Company Interest Company Company Company Interest Company Company Chance of Chance of Chance of
Before Royalties Gross Net Before Royalties Gross Net Development Discovery Commerciality
Resources Category MMcf MMcf MMcf Mboe Mboe Mboe % % %
Contingent Resources
Low Estimate – Unclarified
Becancour / Ste. Sophie-de-Levrard   –   –   –   –   –   –
La Visitation-de-Yamaska   33,623   28,737   30,646   5,604   4,790   5,108 25 100 25
St. David   13,449   11,495   12,255   2,242   1,916   2,043 10 100 10
St. Edouard-de-Lotbiniere   –   –   –   –   –   –
St. Francois-du-Lac / Pierreville   6,688   6,688   5,996   1,115   1,115   999 10 100 10
St. Louis   6,688   6,688   5,996   1,115   1,115   999 10 100 10
Utica Prospective Resources   –   –   –   –   –   –
Total: Low Estimate – Unclarified   60,448   53,608   54,893   10,075   8,935   9,149
Best Estimate – Unclarified
Becancour / Ste. Sophie-de-Levrard   –   –   –   –   –   –
La Visitation-de-Yamaska   55,019   47,025   50,140   9,170   7,837   8,357 25 100 25
St. David   22,008   18,810   20,051   3,668   3,135   3,342 10 100 10
St. Edouard-de-Lotbiniere   –   –   –   –   –   –
St. Francois-du-Lac / Pierreville   10,944   10,944   9,809   1,824   1,824   1,635 10 100 10
St. Louis   10,944   10,944   9,809   1,824   1,824   1,635 10 100 10
Utica Prospective Resources   –   –   –   –   –   –
Total: Best Estimate – Unclarified   98,915   87,723   89,809   16,486   14,620   14,968
High Estimate – Unclarified
Becancour / Ste. Sophie-de-Levrard   –   –   –   –   –   –
La Visitation-de-Yamaska   89,736   76,698   81,731   14,956   12,783   13,622 25 100 25
St. David   35,648   30,469   32,457   5,941   5,078   5,409 10 100 10
St. Edouard-de-Lotbiniere   –   –   –   –   –   –
St. Francois-du-Lac / Pierreville   17,878   17,878   16,012   2,980   2,980   2,669 10 100 10
St. Louis   17,759   17,759   15,906   2,960   2,960   2,651 10 100 10
Utica Prospective Resources   –   –   –   –   –   –
Total: High Estimate – Unclarified   161,022   142,803   146,106   26,837   23,801   24,351

Risked Summary Net Present Values of Future Net Revenue

Before Income Taxes Discounted At (%/year) After Income Taxes Discounted At (%/year) Discounted at 10%/year
0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
Resources Category M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ $/boe $/Mcfe
Contingent Resources
Low Estimate – On Hold
Becancour / Ste. Sophie-de-Levrard   205,086   119,145   75,387   50,467   35,070   205,086   119,145   75,387   50,467   35,070   7.90   1.32
La Visitation-de-Yamaska   –   –   –   –   –   –   –   –   –   –   –   –
St. David   –   –   –   –   –   –   –   –   –   –   –   –
St. Edouard-de-Lotbiniere   221,336   128,051   80,592   53,613   36,983   221,336   128,051   80,592   53,613   36,983   7.75   1.29
St. Francois-du-Lac / Pierreville   –   –   –   –   –   –   –   –   –   –   –   –
St. Louis   –   –   –   –   –   –   –   –   –   –   –   –
Utica Prospective Resources   –   –   –   –   –   –   –   –   –   –   –   –
Total: Low Estimate – On Hold   426,422   247,196   155,979   104,080   72,053   426,422   247,196   155,979   104,080   72,053
Best Estimate – On Hold
Becancour / Ste. Sophie-de-Levrard   420,787   230,282   144,878   98,900   71,037   420,787   230,282   144,878   98,900   71,037   9.29   1.55
La Visitation-de-Yamaska   –   –   –   –   –   –   –   –   –   –   –   –
St. David   –   –   –   –   –   –   –   –   –   –   –   –
St. Edouard-de-Lotbiniere   456,482   249,298   156,421   106,465   76,231   456,482   249,298   156,421   106,465   76,231   9.19   1.53
St. Francois-du-Lac / Pierreville   –   –   –   –   –   –   –   –   –   –   –   –
St. Louis   –   –   –   –   –   –   –   –   –   –   –   –
Utica Prospective Resources   –   –   –   –   –   –   –   –   –   –   –   –
Total: Best Estimate – On Hold   877,269   479,581   301,299   205,364   147,268   877,269   479,581   301,299   205,364   147,268
High Estimate – On Hold
Becancour / Ste. Sophie-de-Levrard   807,758   412,948   256,511   176,254   128,376   807,758   412,948   256,511   176,254   128,376   10.02   1.67
La Visitation-de-Yamaska   –   –   –   –   –   –   –   –   –   –   –   –
St. David   –   –   –   –   –   –   –   –   –   –   –   –
St. Edouard-de-Lotbiniere   878,599   448,618   278,238   190,875   138,800   878,599   448,618   278,238   190,875   138,800   9.96   1.66
St. Francois-du-Lac / Pierreville   –   –   –   –   –   –   –   –   –   –   –   –
St. Louis   –   –   –   –   –   –   –   –   –   –   –   –
Utica Prospective Resources   –   –   –   –   –   –   –   –   –   –   –   –
Total: High Estimate – On Hold   1,686,357   861,566   534,749   367,128   267,176   1,686,357   861,566   534,749   367,128   267,176
Net Present Values of Future Net Revenue Net Present Values of Future Net Revenue Unit Value Before Income Tax
Before Income Taxes Discounted At (%/year) After Income Taxes Discounted At (%/year) Discounted at 10%/year
0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
Resources Category M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ $/boe $/Mcfe
Contingent Resources
Low Estimate – Unclarified
Becancour / Ste. Sophie-de-Levrard
La Visitation-de-Yamaska 114,467 58,842 33,157 19,884 12,443 114,467 58,842 33,157 19,884 12,443 6.49 1.08
St. David 48,158 22,472 11,577 6,386 3,696 48,158 22,472 11,577 6,386 3,696 5.67 0.94
St. Edouard-de-Lotbiniere
St. Francois-du-Lac / Pierreville 19,546 10,038 5,562 3,241 1,947 19,546 10,038 5,562 3,241 1,947 5.57 0.93
St. Louis  20,309 9,465 4,785 2,556 1,415 20,309 9,465 4,785 2,556 1,415 4.79 0.80
Utica Prospective Resources  –
Total: Low Estimate – Unclarified 202,480 100,817 55,080 32,067 19,501 202,480 100,817 55,080 32,067 19,501
Best Estimate – Unclarified
Becancour / Ste. Sophie-de-Levrard
La Visitation-de-Yamaska 235,533 114,065 63,943 39,134 25,340 235,533 114,065 63,943 39,134 25,340 7.65 1.28
St. David 98,597 43,246 22,111 12,406 7,398 98,597 43,246 22,111 12,406 7,398 6.62 1.10
St. Edouard-de-Lotbiniere
St. Francois-du-Lac / Pierreville 42,105 20,729 11,676 7,143 4,608 42,105 20,729 11,676 7,143 4,608 7.14 1.19
St. Louis 43,730 19,510 10,013 5,606 3,324 43,730 19,510 10,013 5,606 3,324 6.12 1.02
Utica Prospective Resources
Total: Best Estimate – Unclarified 419,965 197,551 107,744 64,289 40,670 419,965 197,551 107,744 64,289 40,670
High Estimate – Unclarified
Becancour / Ste. Sophie-de-Levrard  –
La Visitation-de-Yamaska 448,384 204,484 113,364 69,870 45,897 448,384 204,484 113,364 69,870 45,897 8.32 1.39
St. David 185,172 77,086 39,003 22,017 13,299 185,172 77,086 39,003 22,017 13,299 7.21 1.20
St. Edouard-de-Lotbiniere  –
St. Francois-du-Lac / Pierreville  82,533 38,322 21,500 13,372 8,848 82,533 38,322 21,500 13,372 8,848 8.06 1.34
St. Louis 84,980 35,985 18,410 10,476 6,366 84,980 35,985 18,410 10,476 6,366 6.94 1.16
Utica Prospective Resources
Total: High Estimate – Unclarified 801,069 355,878 192,277 115,735 74,410 801,069 355,878 192,277 115,735 74,410

Notes:

  1. Contingent resources are defined in the COGE Handbook 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 Questerre 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. “Gross” contingent resources are Questerre’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Questerre. “Net” contingent resources are Questerre’s working interest (operating or non-operating) share after deduction of royalty obligations, plus Questerre’s royalty interests in contingent resources.
  4. 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.
  5. Low Estimate Contingent Resources are 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.
  6. Best Estimate Contingent Resources are 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.
  7. High Estimate Contingent Resources are 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.
  8. The Chance of Development (CoDev) is the estimated probability that, once discovered, a known accumulation will be commercially developed. Five factors have been considered in determining the CoDev as follows:
    CoDev = Ps (Economic Factor) × Ps (Technology Factor) × Ps (Development Plan Factor) ×Ps (Development Timeframe Factor) × Ps (Other Contingency Factor) wherein Ps is the probability of success

Economic Factor – For reserves to be assessed, a project must be economic. With respect to contingent resources, this factor captures uncertainty in the assessment of economic status principally due to uncertainty in cost estimates and marketing options. Economic viability uncertainty due to technology is more aptly captured with the Technology Factor. The Economic Factor will be 1 for reserves and will often be 1 for development pending projects and for projects with a development study or pre-development study with a robust rate of return. A robust rate of return means that the project retains economic status with variation in costs and/or marketing plans over the expected range of outcomes for these variables.

Technology Factor – For reserves to be assessed, a project must utilize established technology. With respect to contingent resources, this factor captures the uncertainty in the viability of the proposed technology for the subject reservoir, namely, the uncertainty associated with technology under development. By definition, technology under development is a recovery process or process improvement that has been determined to be technically viable via field test and is being field tested further to determine its economic viability in the subject reservoir. The Technology Factor will be 1 for reserves and for established technology. For technology under development, this factor will consider different risks associated with technologies being developed at the scale of the well versus the scale of a project and technologies which are being modified or extended for the subject reservoir versus new emerging technologies which have not previously been applied in any commercial application. The risk assessment will also consider the quality and sufficiency of the test data available, the ability to reliably scale such data and the ability to extrapolate results in time.

Development Plan Factor – For reserves to be assessed, a project must have a detailed development plan. With respect to contingent resources, this factor captures the uncertainty in the project evaluation scenario. The Development Plan Factor will be 1 for reserves and high, approaching 1, for development pending projects. This factor will consider development plan detail variations including the degree of delineation, reservoir specific development and operating strategy detail (technology decision, well layouts (spacing and pad locations), completion strategy, start-up strategy, water source and disposal, other infrastructure, facility design, marketing plans etc) and the quality of the cost estimates as provided by the developer.

Development Timeframe Factor – In the case of major projects, for reserves to be assessed, first major capital spending must be initiated within 5 years of the effective date. The Development Timeframe Factor will be 1 for reserves and will often be 1 for development pending projects provided the project is planned on-stream based on the same criteria used in the assessment of reserves. With respect to contingent resources, the factor will approach 1 for projects planned on-stream with a timeframe slightly longer than the limiting reserves criteria.

Other Contingency Factor – For reserves to be assessed, all contingencies must be eliminated. With respect to contingent resources, this factor captures major contingencies, usually beyond the control of the operator, other than those captured by economic status, technology status, project evaluation scenario status and the development timeframe. The Other Contingency Factor will be 1 for reserves and for development pending projects and less than 1 for on hold. Provided all contingencies have been identified and their resolution is reasonably certain, this factor would also be 1 for development unclarified projects.

These factors may be inter-related (dependent) and care has been taken to ensure that risks are appropriately accounted.

  1. Contingent resources for the Lowlands have been estimated based the results from several vertical and horizontal wells on the Company’s acreage that have all encountered pay in the Utica. Test data from these wells in conjunction with offset development and studies of analogous US Utica supports the prospective commercial development on these resources. The estimated unrisked cost to bring these contingent resources on commercial production is $809.28 million and the expected timeline is between 2 and 11 years. The specific contingencies for these resources are the passage of applicable hydrocarbon and environmental legislation, regulations, local acceptability, firm development plans, detailed cost estimates and corporate approvals and sanctioning.
  2. In Canada, GLJ has estimated a Company gross aggregate of risked on hold best estimate contingent resources of 30.42 million boe for the projects outlined below. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $168 million with an expected timeline of 2 to 4 years.Becancour / Ste. Sophie-de-Levrard – Based on contingencies related to the passage of applicable hydrocarbon and environmental legislation, regulations, local acceptability, firm development plans, detailed cost estimates and corporate approvals and sanctioning GLJ has estimated a Company gross risked development on hold best estimate contingent resources at 14.5 million boe and the risked estimated cost to bring these resources on commercial production is $79.3 million. The expected timeline is 2 to 4 years.

    St. Edouard-de-Lotbiniere – Based on contingencies related to the passage of applicable hydrocarbon and environmental legislation, regulations, local acceptability and firm development plans, detailed cost estimates and corporate approvals and sanctioning GLJ has estimated a Company gross risked development on hold best estimate contingent resources at 15.96 million boe and the risked estimated cost to bring these resources on commercial production is $88.7 million. The expected timeline is 1 to 4 years.

  1. In Canada, GLJ has estimated a Company gross aggregate of risked unclarified best estimate contingent resources of 14.62 million boe for the projects outlined below. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $83.83 million with an expected timeline of 3 to 8 years.La Visitation-de-Yamaska – Based on contingencies related to the passage of applicable hydrocarbon and environmental legislation, regulations, local acceptability, and additional risk associated with securing social license to operate, firm development plans, detailed cost estimates and corporate approvals and sanctioning GLJ has estimated a Company gross risked development unclarified best estimate contingent resources at 7.84 million boe and the risked estimated cost to bring these resources on commercial production is $44.83 million. The expected timeline is 3 to 7 years.

    St, David – Based on contingencies related to the passage of applicable hydrocarbon and environmental legislation, regulations, local acceptability, and additional risk associated with securing social license to operate, firm development plans, detailed cost estimates and corporate approvals and sanctioning GLJ has estimated a Company gross risked development on hold best estimate contingent resources at 3.14 million boe and the risked estimated cost to bring these resources on commercial production is $18.15 million. The expected timeline is 5 to 9 years.

    St. Francois-du-Lac / Pierreville – Based on contingencies related to the passage of applicable hydrocarbon and environmental legislation, regulations, local acceptability, and additional risk associated with securing social license to operate, firm development plans, detailed cost estimates and corporate approvals and sanctioning GLJ has estimated a Company gross risked development on hold best estimate contingent resources at 1.82 million boe and the risked estimated cost to bring these resources on commercial production is $10.29 million. The expected timeline is 3 to 6 years.

    St. Louis – Based on contingencies related to the passage of applicable hydrocarbon and environmental legislation, regulations, local acceptability, and additional risk associated with securing social license to operate, firm development plans, detailed cost estimates and corporate approvals and sanctioning GLJ has estimated a Company gross risked development on hold best estimate contingent resources at 1.82 million boe and the risked estimated cost to bring these resources on commercial production is $10.56 million. The expected timeline is 5 to 8 years.

GLJ Petroleum Consultants
Summary of Natural Gas Price Forecasts
January 1, 2018

NYMEX Midwest Alliance Alberta Saskatchewan Plant Gate
Henry Hub Price at AECO/NIT Transfer Pool Plant Gate Plant Gate British Columbia Alberta
Near Month Contract Chicago Spot Spot Spot Sulphur Sulphur
Constant Then Then Then Then Constant Then Westcoast Spot FOB at Plant
2018 $ Current Current Current Current 2018 $ Current ARP SaskEnergy Spot Sumas Spot Station 2 Plant Gate Vancouver Gate
Year USD/MMBtu USD/MMBtu USD/MMBtu CAD/MMBtu CAD/MMBtu CAD/MMBtu CAD/MMBtu CAD/MMBtu CAD/MMBtu CAD/MMBtu USD/MMBtu CAD/MMBtu CAD/MMBtu USD/lt CAD/lt
2018 Q1 2.80 2.80 2.70 1.95 1.95 1.70 1.70 1.70 1.80 1.85 2.55 1.10 0.89 90.00 63.92
2018 Q2 2.80 2.80 2.70 2.13 2.13 1.87 1.87 1.87 1.97 2.03 2.20 1.28 1.07 90.00 63.92
2018 Q3 2.90 2.90 2.80 2.29 2.29 2.04 2.04 2.04 2.14 2.19 2.50 1.49 1.29 90.00 63.92
2018 Q4 2.90 2.90 2.80 2.41 2.41 2.15 2.15 2.15 2.25 2.31 2.65 1.71 1.50 90.00 63.92
2018 Full Year 2.85 2.85 2.75 2.20 2.20 1.94 1.94 1.94 2.04 2.10 2.48 1.40 1.19 90.00 63.92
2019 2.94 3.00 2.90 2.54 2.54 2.24 2.28 2.28 2.38 2.44 2.50 1.99 1.78 100.00 76.58
2020 3.12 3.25 3.15 2.88 2.88 2.52 2.62 2.62 2.72 2.78 2.75 2.48 2.27 102.00 77.50
2021 3.30 3.50 3.40 3.24 3.24 2.80 2.97 2.97 3.07 3.14 3.00 2.94 2.73 104.04 78.44
2022 3.42 3.70 3.60 3.47 3.47 2.96 3.20 3.20 3.30 3.37 3.20 3.17 2.96 106.12 79.41
2023 3.50 3.86 3.76 3.58 3.58 3.00 3.31 3.31 3.41 3.48 3.36 3.28 3.06 108.24 80.41
2024 3.50 3.94 3.84 3.66 3.66 3.00 3.38 3.38 3.48 3.56 3.44 3.36 3.14 110.40 83.01
2025 3.50 4.02 3.92 3.73 3.73 3.01 3.45 3.45 3.55 3.63 3.52 3.43 3.21 112.62 85.69
2026 3.50 4.10 4.00 3.80 3.80 3.01 3.53 3.53 3.63 3.70 3.60 3.50 3.29 114.87 88.40
2027 3.50 4.18 4.08 3.88 3.88 3.01 3.60 3.60 3.70 3.78 3.68 3.58 3.36 117.17 91.17
2028+ 3.50 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr 3.01 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr

Unless otherwise stated, the gas price reference point is the receipt point on the applicable provincial gas transmission system known as the plant gate.
The plant gate price represents the price before raw gathering and processing charges are deducted.

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 COGE Handbook 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.

The Upper Utica was considered undiscovered for approximately 84% of the total mapped TPIIP. Recovery factors of 19%, 27% and 40% were applied to the low, best and high estimates resource cases respectively.

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 87 million boe (low estimate) to 238 million boe (high estimate), with a best estimate of 143 million boe.

The chance of commerciality for Prospective Resources is equal to the product of the chance of discovery and the chance of development. “Chance of discovery” is the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. “Chance of development” is the estimated probability that, once discovered, a known accumulation will be commercially developed. Based on contingencies related to the passage of applicable hydrocarbon and environmental legislation, regulations, local acceptability, and additional risk associated with securing social license to operate, firm development plans, detailed cost estimates and corporate approvals GLJ estimated the Chance of Development at 19 percent. Proximity to extensional and compressional-related fault systems presents risk of structuring resulting in leak off and reduced pressures in some prospective regions, additionally, lack of delineation data provides reservoir risk associated with uncertainty regarding reservoir quality and rock mechanics amicable to hydraulic fracturing. Therefore, GLJ has estimated the Chance of Discovery at 81 percent. The corresponding chance of commerciality is 15 percent. This also takes into account Questerre’s working interest and operatorship of its assets as Questerre is subject to the priorities of working interest partners for such assets. Production and development forecasts were not completed by GLJ as part of the prospective resources evaluation.

The following table sets forth Questerre’s best estimate risked prospective resources by product type at December 31, 2017:

Oil Equivalent
Company Interest Company Company Company Interest Company Company Chance of Chance of Chance of
Before Royalties Gross Net Before Royalties Gross Net Development Discovery Commerciality
Resources Category Resources Category MMcf MMcf MMcf Mboe Mboe Mboe % % %
Prospective Resources
Total: Low Estimate – Prospect 573,239 521,075 520,350 95,540 86,846 86,725 19 81 15
Total: Best Estimate – Prospect 944,281 858,352 857,158 157,380 143,059 142,860 19 81 15
Total: High Estimate – Prospect 1,573,801 1,430,587 1,428,596 262,300 238,431 238,099 19 81 15

Notes:

  1. Prospective resources are defined in the COGE Handbook 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 Questerre 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.
  1. 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.
  1. The forecast price and cost assumptions utilized in the year-end 2017 reserves report were also utilized by GLJ in preparing the GLJ Resource Assessmen
  1. “Gross” prospective resources are Questerre’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company. “Net” prospective resources are Questerre’s working interest (operating or non-operating) share after deduction of royalty obligations, plus Questerre’s royalty interests in prospective resources.
  1. 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.
  1. The Low Estimate Prospective Resources is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual net remaining quantities recovered will exceed the low estimate of 87 million boe. 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.
  1. The Best Estimate Prospective Resources is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual net remaining quantities recovered will be greater or less than the best estimate of 143 million. 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.
  1. The High Estimate Prospective Resources is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual net remaining quantities recovered will exceed the high estimate of 238 million boe. 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.
  1. The chance of commerciality is defined as the product of the chance of discovery and the chance of development. Chance of discovery is defined in COGE Handbook as the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. Chance of development is defined as the estimated probability that, once discovered, a known accumulation will be commercially developed

Questerre Energy Corporation is leveraging its expertise gained through early exposure to shale and other non-conventional reservoirs. The Company has base production and reserves in the tight oil Bakken/Torquay of southeast Saskatchewan. It is bringing on production from its lands in the heart of the high-liquids Montney shale fairway. It is a leader on social license to operate issues for its Utica shale gas discovery in the St. Lawrence Lowlands, Quebec. It is pursuing oil shale projects with the aim of commercially developing these significant resources.

Questerre is a believer that the future success of the oil and gas industry depends on a balance of economics, environment and society. We are committed to being transparent and are respectful that the public must be part of making the important choices for our energy future.

For further information, please contact:

Questerre Energy Corporation
Jason D’Silva, Chief Financial Officer
(403) 777-1185 | (403) 777-1578 (FAX) | Email: info@questerre.com

Advisory Regarding Forward-Looking Statements

This news release contains certain statements which constitute forward-looking statements or information (“forward-looking statements”) including its estimated future net revenues, price forecasts and the filing of an Annual Information Form. In addition, statements relating to reserves and resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future.

Forward-looking statements are based on a number of material factors, expectations or assumptions of Questerre which have been used to develop such statements and information but which may prove to be incorrect. Although Questerre believes that the expectations reflected in these forward-looking statements are reasonable, undue reliance should not be placed on them because Questerre can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Further, events or circumstances may cause actual results to differ materially from those predicted as a result of numerous known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company, including, without limitation: whether the Company’s exploration and development activities respecting its prospects will be successful or that material volumes of petroleum and natural gas reserves will be encountered, or if encountered can be produced on a commercial basis; the ultimate size and scope of any hydrocarbon bearing formations on its lands; that drilling operations on its lands will be successful such that further development activities in these areas are warranted; that Questerre will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities will be consistent with past operations; the general stability of the economic and political environment in which Questerre operates; drilling results; field production rates and decline rates; the general continuance of current industry conditions; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Questerre to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Questerre operates; and the ability of Questerre to successfully market its oil and natural gas products; changes in commodity prices; changes in the demand for or supply of the Company’s products; unanticipated operating results or production declines; changes in tax or environmental laws, changes in development plans of Questerre or by third party operators of Questerre’s properties, increased debt levels or debt service requirements; inaccurate estimation of Questerre’s oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Questerre’s public disclosure documents. Additional information regarding some of these risks, expectations or assumptions and other factors may be found under in the Company’s Annual Information Form for the year ended December 31, 2016 and other documents available on the Company’s profile at www.sedar.com. The reader is cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements contained in this news release are made as of the date hereof and Questerre undertakes no obligations to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

All evaluations and reviews of future net revenue are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The estimated future net revenue from the production of disclosed oil and gas reserves does not represent the fair market value of the Company’s reserves. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual light and medium crude oil, shale gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. All of the Company’s light and medium crude oil, shale gas and natural gas liquids reserves are located in Canada.

Barrel of oil equivalent (“boe”) amounts may be misleading, particularly if used in isolation. A boe conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil and the conversion ratio of one barrel to six thousand cubic feet is based on an energy equivalent conversion method application at the burner tip and does not necessarily represent an economic value equivalent at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.



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