CALGARY, Alberta, March 16, 2020 (GLOBE NEWSWIRE) — Questerre Energy Corporation (“Questerre” or the “Company”) (TSX,OSE:QEC) reported today on the results of its December 31, 2019 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, 2019, 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, “Obviously we are all focused on the recent market impacts of OPEC and Russia indicating production increases in the short term. This is in the context of a likely reduction in demand due to the coronavirus. The reserve and resource reports are produced on the assumption these are short term market impacts and do not reflect the long term demand and supply for oil and gas globally.”With respect to the reserve report, he added, “We saw continued growth in our reserves with the successful drilling program at Kakwa North last year. Corporate proved and probable reserves grew by about 20% or 5.4 MMboe from 29.9 MMboe to 35.3 MMBoe, net of production during the year. The before tax NPV-10% estimated for the corporate proved and probable reserves using the average price forecast of three reserve engineering firms as of December 31, 2019 is $237.5 million.”Commenting on the Utica resources in Quebec, he added, “Following the acquisition which closed effective December 31, 2019, the reserve engineers updated our resource report. The revised resource assessment incorporates the planned engineering for our Clean Tech Energy project and our plans to share net revenue from the project with the local towns and communities. The best estimate of risked contingent resources net to Questerre for the areas sub-classified as development on hold is 1.3 Tcf. The risked net present value discounted at 10% before tax for this limited development area is $1.0 billion.”December 31, 2019 Reserve InformationIn accordance with the requirements of NI 51-101, the Company anticipates filing its Annual Information Form that will include more detailed disclosure relating to the Company’s petroleum and natural gas activities for the 2019 fiscal year, in the form of Form 51-101F1, at the end of March 2020.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, 2019, which numbers may vary slightly from those presented in the Report due to rounding. Also, due to rounding, certain columns may not add exactly.The price forecast employed by McDaniel in estimating Questerre’s reserves is based on the average of commodity price forecasts effective January 1, 2020, from three qualified reserves evaluators who are independent of the Company, being GLJ Petroleum Consultants, Sproule Associates Ltd., and McDaniel’s (each of which is available on their respective websites at www.gljpc.com, www.sproule.com and www.mcdan.com).
SUMMARY OF OIL AND GAS RESERVES
as of December 31, 2019FORECAST PRICES AND COSTS(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, 2019FORECAST PRICES AND COSTS(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.
December 31, 2019 Quebec Resource InformationQuesterre also reported on the year-end update prepared by GLJ Petroleum Consultants Ltd. (“GLJ”) on the independent resource assessment of its 1.2 million gross (1.0 million net) acres in the St. Lawrence Lowlands, Quebec that have potential for the Upper Utica Shale effective December 31, 2019 in a report dated March 10, 2020 (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 both the Indian Castle and Dolgeville members of the Utica formation. The Flat Creek, the lower most member of the Utica, was only evaluated to estimate undiscovered petroleum initially-in-place (“UPIIP”). No recoverable resources were assigned to the Flat Creek based on the lack of any test data as of the effective date of the Report. A portion of these quantities may become recoverable in the future as commercial circumstances change or as technical development occurs.The GLJ Resource Assessment is based on the results from several pilot vertical and horizontal wells on Questerre’s acreage that have all encountered pay in the Utica. Furthermore, available test data from these wells in conjunction with offset development and analogy examination of the Utica development in the United States provides sufficient evidence that the evaluated resource is capable of commercial production.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, 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 the costs associated with the development program in the GLJ Resource Assessment, it may not have access to the necessary capital when required.Contingent ResourcesThe 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 Contingent Resources. Recovery factors of 22%, 32% and 46% 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, 2019.  Questerre’s average working interest in its gross best estimate Contingent Resources is 75%.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 128.9 million boe (low estimate) to 349.3 million boe (high estimate), with a best estimate of 214.7 million boe.The GLJ Resources Assessment estimated gross risked contingent resources with a project maturity subclass of development unclarified of 34.9 million boe (low estimate) to 95.9 million boe (high estimate), with a best estimate of 59.1 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.The Company’s Contingent Resources require additional data gathering, the preparation of firm development plans, and regulatory application and approval for development. Therefore, the Contingent Resources have been sub-classified as development on hold and development unclarified. Those areas classified as development on hold are primarily contingent on government and public approval for development. Remaining areas classified as development unclarified have additional contingency or risk associated with public approval of respective county populations, thereby lowering priority for development by the Company. 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 by the Company 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 the Utica formation in Ohio and in similar plays such as the Marcellus and Western Canadian shale gas plays.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 the contingencies related to the amendment or exemption from applicable hydrocarbon and environmental regulations, local acceptability, firm development plans, detailed cost estimates and corporate approvals, GLJ estimated the Chance of Development for the development on hold subclass as 70% 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 on hold subclass is therefore estimated at 70% as detailed in the table below. Based on contingencies related to the amendment or exemption from applicable hydrocarbon and environmental 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, 2019
Notes: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.
 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.
 “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.
 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.
 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% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
 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% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
 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% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
 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.

Contingent resources for the Lowlands have been estimated based the results from several pilot vertical and horizontal wells on the Company’s acreage that have all encountered pay in the Utica. Furthermore, available test data from these wells, in conjunction with offset development and analogy examination of the Utica development in the United States, provides sufficient evidence that the evaluated resource is capable of commercial production. The estimated unrisked cost to bring these contingent resources on commercial production is $2.3 billion and the expected timeline is between one and six years. The specific contingencies for these resources are the passage of applicable revisions or exemptions from hydrocarbon and environmental regulations, local acceptability, firm development plans, detailed cost estimates and corporate approvals and sanctioning.
 In Canada, GLJ has estimated a Company gross aggregate of risked on hold best estimate development on hold contingent resources of 214 million boe for the projects outlined below. Utilizing established recovery technology, the unrisked estimated cost to bring these resources on commercial production is an aggregate of $2.3 billion with an expected timeline of one to six years.

Becancour / Ste. Sophie-de-Levrard – Based on contingencies related to the passage of applicable revisions or exemptions from hydrocarbon and environmental 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 77 million boe and the unrisked estimated cost to bring these resources on commercial production is $0.8 billion. The expected timeline is one to five years.

St. Edouard-de-Lotbiniere – Based on contingencies related to the passage of applicable revisions or exemptions from hydrocarbon and environmental 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 137 million boe and the unrisked estimated cost to bring these resources on commercial production is $1.4 billion. The expected timeline is one to six years.

In Canada, GLJ has estimated a Company gross aggregate of risked best estimate development unclarified contingent resources of 355 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 $2.8 billion with an expected timeline of one to four years.

La Visitation-de-Yamaska – Based on contingencies related to the passage of applicable revisions or exemptions from hydrocarbon and environmental 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 39 million boe and the unrisked estimated cost to bring these resources on commercial production is $1.1 billion. The expected timeline is one to six years.

St, David – Based on contingencies related to the passage of applicable revisions or exemptions from hydrocarbon and environmental 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 16 million boe and the unrisked estimated cost to bring these resources on commercial production is $1.1 billion. The expected timeline is one to four years.

St. Francois-du-Lac / Pierreville – Based on contingencies related to the passage of applicable revisions or exemptions from hydrocarbon and environmental 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 2.3 million boe and the unrisked estimated cost to bring these resources on commercial production is $0.2 billion. The expected timeline is one to three years.

St. Louis – Based on contingencies related to the passage of applicable revisions or exemptions from hydrocarbon and environmental 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 2.3 million boe and the risked estimated cost to bring these resources on commercial production is $0.2 billion. The expected timeline is one to three years.

Three Consultants’ Average
Summary of Natural Gas Price Forecasts
January 1, 2020Prospective ResourcesSummary 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, 2019.The Upper Utica was considered undiscovered for approximately 84% of the total mapped TPIIP. Recovery factors of 24%, 35% and 52% 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 604 million boe (low estimate) to 1,680 million boe (high estimate), with a best estimate of 1,006 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 amendment or exemption from applicable hydrocarbon and environmental legislation and regulations, local acceptability, and additional risk associated with securing social license to operate, firm development plans, detailed cost estimates and corporate approvals GLJ estimates the Chance of Development to range between 10% and 70% with an average of 32%. 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%. The corresponding chance of commerciality ranges between 8% and 57% with an average of 26%. Production and development forecasts were not completed by GLJ as part of the prospective resource evaluation.The following table sets forth Questerre’s best estimate risked prospective resources by product type at December 31, 2019:Notes: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.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.The forecast price and cost assumptions were also utilized by GLJ in preparing the GLJ Resource Assessment.             “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.             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.       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 604 million boe. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.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 1,006 million. If probabilistic methods are used, there should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.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 1,680 million boe. If probabilistic methods are used, there should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.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 is an energy technology and innovation company. It is leveraging its expertise gained through early exposure to low permeability reservoirs to acquire significant high-quality resources. We believe we can successfully transition our energy portfolio. With new clean technologies and innovation to responsibly produce and use energy, we can sustain both human progress and our natural environment. 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.Advisory Regarding Forward-Looking StatementsThis 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; the effect of the coronavirus on the markets and the demand for oil and gas; 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, 2018 and will be available in the Company’s Annual Information Form for the year ended December 31, 2019 which is anticipated to be filed by the end of March 2020, 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.For further information, please contact: Questerre Energy Corporation
Jason D’Silva, Chief Financial Officer
(403) 777-1185 | (403) 777-1578 (FAX) |Email:
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