CLEARVIEW RESOURCES LTD. Form F1 - STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION MARCH 31, 2017

Transcription

1 Form F1 - STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION Page 1 of 17

2 INTRODUCTION This report presents the reserves of Clearview Resources Ltd. (the Company ) with an effective date of March 31, The reserves data is based upon an evaluation prepared by the independent engineering and reserves evaluation firm of GLJ Petroleum Consultants Ltd. (hereafter GLJ ) based on GLJ s April 1, 2017 price forecasts. All of the Company s reserves are in Alberta, Canada. The Canadian Securities Administrators (CSA) has set out disclosure standards for Canadian publicly traded oil and gas companies in National Instrument (NI ). The crude oil and natural gas reserve estimates presented in the GLJ Report are based on the guidelines contained in the COGE Handbook and the reserve definitions contained in both NI and the Canadian Oil and Gas Evaluation (COGE) Handbook. GLJ was engaged to evaluate proved and probable reserves and no attempt was made to evaluation possible reserves. Refer to Appendix A for definitions of reserve terms, a glossary of abbreviations and formulas used in the conversion of units. Form F2, Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor and Form F3, Report of Management and Directors on Reserves Data and Other Information are provided separately. Caution Regarding the Use of Reserve Values The net present value (NPV) of future net revenue attributable to the Company s reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment and reclamation costs for only those wells assigned reserves by GLJ. It should not be assumed that the undiscounted or discounted estimates of net present value of future net revenue attributable to the Company s reserves estimated by GLJ represent the fair market value of those reserves. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves and the future cash flows attributable to such reserves. The reserve and associated cash flows set forth in the report are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of crude oil and natural gas, royalty rates, the assumed effects of regulation by government agencies and future operating costs, all of which may vary materially from actual results. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserve and future net revenue for all properties, due to effects of aggregations. Other assumptions and qualifications relating to costs, prices and future production and other matters are summarized herein. Boe's may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf equals 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In certain of the table set forth below, the columns may not add due to rounding. Page 2 of 17

3 Forward-Looking Statements The matters discussed in this report include certain forward-looking statements. Forward-looking statements include, without limitation, any statement that may predict, forecast, indicate, or imply future results, performance, or achievements. Forward-looking statements may be identified, without limitation, by the use of such words as anticipates, estimates, expects, intends, plans, predicts, projects, believes, or words or phrases of similar meaning. In addition, any statement that may be made concerning future performance, strategies or prospects and possible future corporate action, is also a forward-looking statement. Forward-looking statements are based on current expectations and projections about future general economic, political and relevant market factors, such as interest rates, foreign exchange rates, equity and capital markets, and the general business environment, in each case assuming no changes to applicable tax or other laws or government regulation. Expectations and projections about future events are inherently subject to, among other things, risks and uncertainties, some of which may be unforeseeable. Accordingly, assumptions concerning future economic and other factors may prove to be incorrect at a future date. Forward-looking statements are not guarantees of future performance, and actual events could differ materially from those expressed or implied in any forward-looking statements made by the Company. Any number of important factors could contribute to these digressions, including, but not limited to, general economic, political and market factors in North America and internationally, interest and foreign exchange rates, global equity and capital markets, business competition, technological change, changes in government relations, unexpected judicial or regulatory proceedings and catastrophic events. The Company stresses that the abovementioned list of important factors is not exhaustive. The Company urges all readers to consider these and other factors carefully before making any investment decisions. The Company urges all readers to avoid placing undue reliance on forward-looking statements. The Company disclaims any intention or obligation to update or revise these forward-looking statements as a result of new information, future events or otherwise, except as required under applicable securities laws. DATE OF STATEMENT 1. Effective Date The effective date of the reserves estimates and revenue projections in this report is March 31, Preparation Date The preparation date (latest date of receipt of information relevant to this evaluation by GLJ) of the report for the GLJ evaluation is May 31, Data Date Estimates of reserves and projections of production were generally prepared using information and production data available in the public domain to approximately March 31, In certain instances, the Company provided production and well information up to March 31, The Company provided GLJ with a representation letter confirming that complete and correct information had been provided to GLJ. Page 3 of 17

4 DISCLOSURES OF RESERVES DATA (FORECAST PRICES AND COSTS) All reserves are in Western Canada, primarily in Alberta RESERVE DATA - BREAKDOWN OF RESERVES Light And Medium Oil Conventional Natural Gas Natural Gas Liquids Total Oil Equivalent Company Gross Company Net Company Gross Company Net Company Gross Company Net Company Gross Company Net Reserves Category Mbbl Mbbl MMcf MMcf Mbbl Mbbl Mboe Mboe Proved Producing 1,270 1,098 16,661 15,235 1, ,051 4,407 Developed nonproducing Undeveloped ,368 11, ,814 3,457 Total proved 2,248 1,975 30,011 27,420 1,885 1,550 9,135 8,095 Total probable 1, ,618 17,076 1,214 1,050 5,430 4,860 Total proved + probable 3,361 2,939 48,629 44, ,600 14,565 12,955 NET PRESENT VALUES OF FUTURE NET REVENUE (FORECAST PRICES AND COSTS) BEFORE INCOME TAXES DISCOUNTED AT % PER YEAR 0% 5% 10% 15% 20% Reserves Category M$ M$ M$ M$ M$ Proved producing 71,535 56,172 45,739 38,574 33,450 Proved non-producing 3,472 2,634 2,112 1,758 1,502 Proved undeveloped 42,089 26,584 16,973 10,919 6,997 Total proved 117,095 85,391 64,823 51,251 41,949 Total probable 95,141 56,143 36,497 25,576 18,941 Total proved + probable 212, , ,320 76,827 60,891 NET PRESENT VALUES OF FUTURE NET REVENUE AFTER INCOME TAXES DISCOUNTED AT % PER YEAR 0% 5% 10% 15% 20% Reserves Category M$ M$ M$ M$ M$ Proved producing 71,535 56,172 45,739 38,574 33,450 Proved non-producing 3,472 2,634 2,112 1,758 1,502 Proved undeveloped 31,528 19,955 12,607 7,929 4,881 Total proved 106,534 78,761 60,457 48,260 39,833 Total probable 70,312 40,897 26,199 18,141 13,315 Total proved + probable 176, ,658 86,657 66,401 53,148 Page 4 of 17

5 FUTURE NET REVENUE AND UNIT VALUE BASIS (BEFORE INCOME TAXES) Present Value 10% Discount Reserve Category M$ Proved producing Total proved Total proved + probable $/boe (3) $/Mcfe (3) Light & medium oil (1) 22, Conventional natural gas (2) 23, Total 45, Light & medium oil (1) 32, Conventional natural gas (2) 32, Total 64, Light & medium oil (1) 52, Conventional natural gas (2) 48, Total 101, Notes: 1. Including solution gas and other by-products. 2. Including by-products but excluding solution gas. 3. Other Company revenue and costs not related to a specific production group have been allocated proportionately to production groups. Unit values are based on the Company s working interest in the reserves. Page 5 of 17

6 * BT Before Tax AT After Tax Revenue TOTAL FUTURE NET REVENUE (UNDISCOUNTED) Royalties Operating costs Development costs Abandonment & reclamation costs Future net income BT* Income tax Future net income AT* Reserves Category M$ M$ M$ M$ M$ M$ M$ M$ Proved Producing 210,247 25, , ,006 71,535-71,535 Developed nonproducing 9,533 1,054 4, ,472-3,472 Undeveloped 157,420 13,185 46,411 52,125 3,610 42,089 10,561 31,528 Total proved 377,200 39, ,625 52,613 15, ,095 10, ,534 Total probable 243,961 25,586 94,275 25,344 3,615 95,141 24,829 70,312 Total proved + probable 621,161 65, ,900 77,957 18, ,236 35, ,846 FORECAST PRICES USED IN ESTIMATES This price forecast is the standard price forecast effective April 1, 2017 of the independent reserve evaluator, GLJ Petroleum Consultants Ltd. Edmonton Light Bow River Medium Ethane Butane Pentane AECO Spot CAD/ MMBtu WTI Inflation Year % USD/CAD USD/bbl CAD/bbl CAD/bbl CAD/bbl CAD/bbl CAD/bbl 2017 Q2-Q %/yr. +2.0%/yr. +2.0%/yr. +2.0%/yr. +2.0%/yr. +2.0%/yr. +2.0%/yr. Page 6 of 17

7 RECONCILIATION OF CHANGES IN RESERVES Light and Medium Oil Natural Gas Liquids Conventional Natural Gas Total BOE Proved Proved Proved Proved + FACTORS Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe) March 31, , , ,775 2,339 9,114 2, ,549 Discoveries Extensions Improved Recovery Technical Revisions (31) (99) (130) (35) (11) (47) (536) (283) (819) (156) (157) (313) Acquisitions 1, ,273 1,601 1,110 2,710 25,030 16,818 41,848 7,210 4,748 11,958 Dispositions (163) (48) (210) (18) (6) (24) (490) (176) (666) (262) (83) (345) Economic Factors (6) (4) (10) (3) (3) (6) (46) (79) (125) (17) (20) (37) Production (91) 0 (91) (34) 0 (34) (723) 0 (723) (246) 0 (246) March 31, ,248 1,113 3,361 1,885 1,214 3,099 30,011 18,618 48,629 9,135 5,430 14,565 The Company has no heavy oil, synthetic oil, bitumen, coal bed methane, hydrates, shale oil or shale gas. Light & Medium Oil Natural Gas Liquids Conventual Natural Gas Total BOE Proved Proved Proved Proved Proved Probable + Probable Proved Probable + Probable Proved Probable + Probable Proved Probable + Probable FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe) March 31, , , ,361 1,819 8,180 2, ,346 Discoveries Infill Drilling Extensions Improved Recovery Technical Revisions , , Acquisitions Dispositions Economic Factors (88) 41 (47) (9) (0) (9) (219) 36 (183) (133) 47 (86) Production (120) 0 (120) (37) 0 (37) (691) 0 (691) (273) 0 (273) March 31, , , ,775 2,339 9,114 2, ,549 The Company has no heavy oil, synthetic oil, bitumen, coal bed methane, hydrates, shale oil or shale gas. Page 7 of 17

8 ADDITIONAL INFORMATION RELATING TO RESERVES DATA UNDEVELOPED RESERVES Undeveloped reserves are attributed by GLJ in accordance with the standards and procedures contained in the COGE Handbook. UNDEVELOPED RESERVES ATTRIBUTED BY YEAR Proved Undeveloped Reserves `Light & medium oil Conventional natural gas Natural gas liquids Oil equivalent Mbbl Mbbl MMcf MMcf Mbbl Mbbl Boe Boe Attributed Current Attributed Current Attributed Current Attributed Current Year This Year* Total This Year Total This Year Total This Year Total ,218 12, ,680 3, Probable Undeveloped Reserves ,883 11, ,337 3, * Refers to reserves first attributed at year-end of the fiscal year ending March 31. Proved Undeveloped Reserves Proved undeveloped reserves for the Company at March 31, 2017 relate to infill and development drilling. Probable Undeveloped Reserves Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to production. Development The Company has sufficient cash flow, unused bank credit facilities and a proven ability to raise equity capital in order to finance future development costs. However, the Company may choose to delay development in the following circumstances: higher priority expenditures, partner priorities do not include the proposed locations in which the Company holds interests, continued low commodity prices, and most importantly, consideration of the economic environment and maintenance of Clearview s financial integrity. Page 8 of 17

9 SIGNIFICANT ECONMIC FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA The evaluated oil and gas properties of the Company have no significant risks or uncertainties beyond those which are inherent in the oil and gas industry. These risks and uncertainties include, but are not limited to: commodity prices and exchange rates, operational risks in exploration, development and production, delays or changes in plans, risks associated with the uncertainty of reserve estimates, health and safety risks and the uncertainty of estimates and projections of production, costs and expenses. Competition from other producers, the lack of available qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources are additional risks the Company faces in this market. The Company's actual results, performance or achievements could differ materially from those expressed in, or implied by, these reserve estimates and accordingly, no assurance can be given that any of the forward-looking statements or estimates will transpire or occur or what benefits the Company can derive from them. The reader is cautioned not to place undue reliance on this forward-looking information. The Company applies significant judgement in estimating the nature, amount and timing of abandonment and reclamation costs and the actual costs could change substantially in amount and timing from those estimated in this report and those reported in the financial statements for the year ended March 31, The estimation of reserves requires significant judgment and decisions based on available geological, geophysical, engineering and economic data. These estimates can change substantially as additional information from ongoing development activities and production performance becomes available and as economic and political conditions impact oil and gas prices and costs change. The estimates are based on production forecasts, forecast prices and costs and future economic conditions. Asset Retirement Obligations Amounts recorded for asset retirement obligations and the related accretion expense requires the use of estimates with respect to the amount and timing of asset retirement, including well abandonment and well site reclamation. The future estimated cash outflows required to settle the obligations have been discounted using a risk-free rate of 2.17% at March 31, 2017 (March 31, %). The total undiscounted amount of future cash flows required to settle the obligation as estimated at March 31, 2017 was $22.7 million (March 31, $14.3 million). Additional Information Concerning Abandonment and Reclamation Costs Abandonment and reclamation costs for all wells (both existing and undrilled wells) that have been attributed reserves and certain dedicated facilities have been included in this Statement. This Statement of Reserves Data does not include abandonment and reclamation of any pipelines, non-dedicated facilities or for wells with no attributed reserves. The Company estimates the amount and timing of future abandonment and reclamation expenditures for each well. Wells within each operating area are assigned an average cost per well to abandon and reclaim the well site. The estimated expenditures are based on current regulatory standards, other public and the Company s own experience including actual abandonment and reclamation cost history. Additional information on the Company s asset retirement obligations, including abandonment and reclamation costs for all wells (those to which reserves have been attributed and those for which no reserves have been attributed) and facilities in which the Company holds an interest, can be found in the Company s Audited Financial Statements for the year ended March 31, 2017 and the accompanying Management Discussion and Analysis, which are available on SEDAR at Refer to Note 11 Risk Management and Financial Instruments of the Audited Financial Statements at March 31, 2017 and the Industry Conditions and Risks in the Management Discussion and Analysis at March 31, 2017 of the Company for additional analysis. Page 9 of 17

10 FUTURE DEVELOPMENT COSTS The development costs are in respect to the Company s properties in Western Canada (primarily the Lindale property) and are capital expenditures required in the future to convert proved and probable non-producing or undeveloped reserves to proved developed producing reserves. In the past, the Company has primarily relied on a combination of cash flow from operating activities and unused bank credit facilities to finance development. Given current oil and natural gas prices new equity issues, if available on favourable terms, are an additional source from which to finance the future development costs for the next few years. There can be no guarantee that funds will be available or that the Board will allocate funding to develop all of the reserves attributable in the GLJ Report. Failure to develop these reserves may have a negative impact on the Company s future cash flows. The interest and other costs of external funding are not included in the reserves and future net revenue estimates and may reduce the reserves and future net revenue to some degree depending upon the funding sources utilized. The Company does not anticipate that interest or other funding costs would make further development of any of the oil and gas assets uneconomic. Future Development Costs Year Proved Producing Total Proved Total Proved + Probable ,676 15, ,600 16, ,113 14, ,660 14, ,440 5, ,487 6, ,196 3,196 Subtotal ,558 77,325 Remainder Total ,613 77,957 10% Discounted ,133 56,994 PROPERTIES WITH NO ATTRIBUTED RESERVES At March 31, 2017, the Company s properties with no attributed reserves are small, being approximately 23,209 gross undeveloped acres and 14,834 net undeveloped acres. All of the undeveloped land is in Alberta, Canada. The Company expects approximately 320 net undeveloped acres of the mineral rights to expire by March 31, The Company has executed on its strategy to acquire producing oil and natural gas properties on which there are significant in-fill and secondary recovery options for future development opportunities. There are no significant economic factors or uncertainties that affect the anticipated development or production activities on properties with no attributed reserves. Page 10 of 17

11 FORWARD CONTRACTS The nature of the Company s operations results in exposure to fluctuations in commodity prices. The refiners posted prices are influenced by the US$ WTI reference price, transportation costs, US$/C$ exchange rates and the supply/demand situation of particular crude oil quality streams. Commodity prices for petroleum and natural gas are impacted by global economic and political events that dictate the levels of supply and demand. Management continuously monitors commodity prices and contracts to manage exposure to these risks when it deems appropriate. The Company does not utilize derivative financial instruments for speculative purposes. The Company hedges a portion of oil and natural gas sales through the use of derivative financial instruments or may use forward sales contracts or physical sales contracts when deemed appropriate. The Company s production is usually sold using spot or near-term contracts, with prices fixed at the time of transfer of custody or on the basis of a monthly average market price. The Company, however, may give consideration in certain circumstances to the appropriateness of entering into long term, fixed price marketing contracts. For details of the Company s financial commodity price contracts outstanding at March 31, 2017 refer to the Company s Audited Financial Statements as at and for the year ended March 31, 2017 and as filed on The Company is party to a long-term contract that requires that the majority of the natural gas production from the Bantry property to be marketed at a fixed rate of $0.05 per mcf, which was set at the inception of the contract. Approximately 33,800 mcf ( ,000 mcf) of natural gas was produced from the Bantry property in the year ended March 31, TAX HORIZON Based on after tax economic forecasts prepared by GLJ, income taxes are payable by the Company in 2022 and beyond for the total proved category and in 2020 and beyond in the proved + probable category. The Company s estimates income taxes are likely to be payable somewhat earlier as the Company takes into account expenses such as general, administrative and financing costs which are not considered in this Statement. COST INCURRED FOR THE FINANCIAL YEAR ENDED The Company operates entirely within Western Canada with all development in the financial year ended March 31, 2017 in Alberta. Property acquisition costs On February 7, 2017 and March 27, 2017, the Company acquired working interests in two producing oil and natural gas assets located in Central Alberta. The respective purchase prices paid by the Company were $11.4 million and $20.1 million prior to closing adjustments. The acquisitions both had an effective date of December 1, With closing adjustments, the total cash cost of the acquisitions was $29,782. Exploration costs No exploration costs were incurred in the year ended March 31, Development costs The capital costs incurred in the year ended March 31, 2017 totalled approximately $0.934 million. Three gross (0.32 net) oil wells were drilled at Lindale, AB in March Two gross (0.22 net) wells were also completed and equipped in March and on production in April The 3 rd well was drilled and will be completed and equipped later in Costs incurred in fiscal 2017 for this Lindale development work totalled approximately $0.7 million. Page 11 of 17

12 The Company holds interest in unitized and non-unitized properties, all of which are in Alberta, Canada. The following table sets forth the number of wells in which the Company held working interest as at March 31, Property Oil Natural Gas Service Total Gross Net Gross Net Gross Net Gross Net Bantry - Producing Bantry - Non-producing Caribou - Producing Caribou - Non-producing Carmangay/Travers - Producing Carmangay/Travers - Non-producing Caroline Swan Hills Gas Unit No. 1 - Producing Caroline Swan Hills Gas Unit No. 1 - Non-producing Carstairs Elkton Unit No. 1 - Producing Carstairs Elkton Unit No. 1 - Non-producing Crossfield Cardium Unit No. 2 - Producing Crossfield Cardium Unit No. 2 - Non-producing Crossfield Turner Valley Unit No. 1 - Producing Crossfield Turner Valley Unit No. 1 - Non-producing East Crossfield D-1 Unit - Producing East Crossfield D-1 Unit - Non-producing Lindale Cardium Unit - Producing Lindale Cardium Unit - Non-producing Northville - Producing Northville - Non-producing Pembina - Producing Pembina - Non-producing Warburg Belly River M Unit - Producing Warburg Belly River M Unit - Non-producing Wilson Creek - Producing Wilson Creek - Non-producing Other - Producing Other - Non-producing Total Page 12 of 17

13 PRODUCTION ESTIMATES SUMMARY OF FIRST YEAR PRODUCTION FOR RESERVES AVERAGE DAILY PRODUCTION BY PROPERTIES OVER 20% - NORTHVILLE AND WILSON CREEK ALL OTHER PROPERTIES COMBINED AS OTHER PROPERTIES Oil Natural Gas Natural Gas Liquids Oil Equivalent Gross Net Gross Net Gross Net Gross Net Property Bbls/day Mcf/day Bbls/day Boe/day Proved Producing Northville 0 1 3,317 3, Wilson Creek ,761 1, Other Properties ,920 1, Total: Proved Producing ,998 6, ,965 1,723 Proved Developed Non-Producing Northville Wilson Creek Non-producing Total: Proved Developed Non-Producing Proved Undeveloped Northville Wilson Creek Other Properties Total: Proved Undeveloped Total Proved Northville 6 7 3,420 3, Wilson Creek ,761 1, Other Properties ,031 1, Total: Proved ,212 6, ,046 1,791 Total Probable Northville Wilson Creek Other Properties Total: Probable Total Proved + Probable Northville 6 7 3,517 3, Wilson Creek ,790 1, Other Properties ,096 1, Total: Proved + Probable ,403 6, ,123 1,855 Page 13 of 17

14 PRODUCTION AND OPERATING RESULTS FOR THE YEAR ENDED Q Q Q Q Production Oils and liquids bbls/day Natural gas * mcf/day 1,988 1,897 1,588 2,233 Total boe/day Prices Oils and liquids per bbl Natural gas * per mcf Total per boe Royalties Oils and liquids per bbl Natural gas * per mcf Total per boe Production costs Total per boe Netback Total per boe *NATURAL GAS IS CONVENTIAL NATURAL GAS DAILY PRODUCTION BY PROPERTY FOR THE YEAR ENDED Oil and Liquids Conventional natural gas Total Property Bbls/day Mcf/day Boe/day Carmangay Bantry Carstairs Elkton Unit Lindale Cardium Unit Wilson Creek Other Total 343 1, Page 14 of 17

15 MARCH 31, 2016 APPENDIX A DEFINITIONS USED FOR RESERVE CATEGORIES The following definitions form the basis of the classification of reserves and values presented in the GLJ Report. They have been prepared by the Standing Committee on Reserves Definitions of the Petroleum Society of the CIM ( CIM ), incorporated in the Society of Petroleum Evaluation Engineers ( SPEE ) Canadian Oil and Gas Evaluation Handbook ( COGE Handbook ) and specified by National Instrument ( NI ). Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recovered from known accumulations, from a given date forward, based on: Analysis of drilling, geological, geophysical and engineering data: The use of established technology; Specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed; and A remaining reserve life of no longer than 50 years. Reserves are classified according to the degree of certainty associated with the estimates. 1. Proved Reserves Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. 2. Probable Reserves Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved + probable reserves. 3. Possible Reserves Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved + probable plus possible reserves. Possible reserves have not been considered in this report. Other criteria that must also be met for categorization of reserves are provided in Section 5.5 of the COGE Handbook. Each of the reserves categories (proved, probable, and possible) may be divided into developed or undeveloped categories. 4. Developed Reserves Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. 5. Developed Producing Reserves Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. 6. Developed Non-Producing Reserves Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. 7. Undeveloped Reserves Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This Page 15 of 17

16 MARCH 31, 2016 allocation should be based on the estimator s assessment as to the reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their respective development and production status. 8. Levels of Certainty for Reported Reserves The qualitative certainty levels contained in the definitions in Sections 1, 2 and 3 are applicable to individual reserves entities, which refers to the lowest level at which reserves estimates are made, and to reported reserves, which refers to the highest-level sum of individual entity estimates for which reserve estimates are made. Reported total reserves estimated by deterministic or probabilistic methods, whether comprised of a single reserves entity or an aggregate estimate for multiple entities should target the following levels of certainty under a specific set of economic conditions: (a) There is a 90% probability that at least the estimated proved reserves will be recovered. (b) There is a 50% probability that at least the sum of the estimated proved reserves plus probable reserves will be recovered. (c) There is a 10% probability that at least the sum of the estimated proved reserves plus probable reserves plus possible reserves will be recovered. A quantitative measure of the probability associated with a reserves estimate is generated only when a probabilistic estimate is conducted. The majority of reserves estimates will be performed using deterministic methods that do not provide a quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in Section of the COGE Handbook. Whether deterministic or probabilistic methods are used, evaluators are expressing their professional judgement as to what are reasonable estimates. 9. Remaining Recoverable Reserves are the total remaining recoverable reserves associated with the acreage in which the Company has an interest. 10. Company Gross Reserves are the Company s working interest share of the remaining reserves, before deduction of any royalties. 11. Company Net Reserves are the gross remaining reserves of the properties in which the Company has an interest, less all Crown, freehold, and overriding royalties and interests owned by others. 12. Net Production Revenue is income derived from the sale of net reserves of oil, pipeline gas, and gas by-products, less all capital and operating costs. 13. Fair Market Value is defined as the price at which a purchaser seeking an economic and commercial return on investment would be willing to buy, and a vendor would be willing to sell, where neither is under compulsion to buy or sell and both are competent and have reasonable knowledge of the facts. 14. Barrels of Oil Equivalent (BOE) Reserves - BOE are the sum of the oil reserves, plus the gas reserves divided by a factor of 6, plus the natural gas liquid reserves, all expressed in barrels or thousands of barrels. Equivalent reserves can also be expressed in thousands of cubic feet of gas equivalent (McfGE) using a conversion ratio of 1 bbl: 6 Mcf. 15. Oil (or Crude Oil) a mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulphur and other non-hydrocarbons, but does not include liquids obtained from the processing of natural gas. 16. Gas (or Natural Gas) a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs, but are gaseous at atmospheric conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds. 17. Non-Associated Gas an accumulation of natural gas in a reservoir where there is no crude oil. 18. Associated Gas - the gas cap overlying a crude oil accumulation in a reservoir. 19. Solution Gas - gas dissolved in crude oil. 20. Natural Gas Liquids - those hydrocarbon components that can be removed from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate, and small quantities of non-hydrocarbons. Page 16 of 17

17 MARCH 31, 2016 GLOSSARY OF ABBREVIATIONS AECO-C Alberta Energy Company C Meter Station of the Nova Pipeline System API American Petroleum Institute Bbl Barrels Bbl/d Barrels per day BOE Barrel of oil equivalent (A BOE conversion ratio of 6 Mcf equals 1 Bbl has been used in this report) BOE/d Barrels of oil equivalent per day GJ Gigajoules GJ/d Gigajoules per day Mbbl Thousand barrels MBOE Thousands of barrels of oil equivalent Mcf Thousand cubic feet Mcf/d Thousand cubic feet per day MMcf Million cubic feet MMcf/d Million cubic feet per day MMBtu Million British thermal units MMBtu/d Million British thermal units per day NGLs Natural gas liquids WTI West Texas Intermediate M$ Thousands of dollars MM$ Millions of dollars 1 acre 0.4 hectares 2.5 acres 1 hectare 1 Bbl cubic metres 6.29 Bbls 1 cubic metre 1 foot metres feet 1 metre 1 Mcf 28.2 cubic metres Mcf 1 cubic metre 1 mile 1.61 kilometres 0.62 miles 1 kilometre 1 MMBtu GJ MMBtu 1 GJ CONVERSION OF UNITS Page 17 of 17