Surge Energy Inc
Annual Report 2014

Plain-text annual report

Annual Information Form For the Year Ended December 31, 2014 Dated March 19, 2015 TABLE OF CONTENTS SELECT DEFINITIONS .............................................................................................................................................................. 3 ABBREVIATIONS AND CONVERSION ....................................................................................................................................... 4 NON-IFRS MEASURES ............................................................................................................................................................. 5 NOTES ON RESERVES DATA AND OTHER OIL AND NATURAL GAS INFORMATION .................................................................. 5 SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS ............................................................................................. 7 SURGE ENERGY INC. ............................................................................................................................................................... 9 DEVELOPMENT OF THE BUSINESS .......................................................................................................................................... 9 DESCRIPTION OF THE BUSINESS ........................................................................................................................................... 12 PRINCIPAL PRODUCING PROPERTIES ................................................................................................................................... 15 STATEMENT OF RESERVES DATA .......................................................................................................................................... 19 DESCRIPTION OF SHARE CAPITAL ......................................................................................................................................... 27 DIVIDEND POLICY ................................................................................................................................................................. 28 MARKET FOR SECURITIES ..................................................................................................................................................... 29 DIRECTORS AND OFFICERS ................................................................................................................................................... 29 AUDIT COMMITTEE .............................................................................................................................................................. 33 INDUSTRY CONDITIONS ....................................................................................................................................................... 34 LEGAL PROCEEDINGS AND REGULATORY ACTIONS .............................................................................................................. 52 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS ........................................................................... 52 AUDITOR, TRANSFER AGENT AND REGISTRAR ..................................................................................................................... 53 INTEREST OF EXPERTS .......................................................................................................................................................... 53 ADDITIONAL INFORMATION ................................................................................................................................................ 53 Schedule “A” – Form 51-101F2 Reports On Reserves Data By Independent Qualified Reserves Evaluators Schedule “B” – Form 51-101F3 Report Of Management And Directors On Reserves Data And Other Information Schedule “C” – Audit Committee Charter SELECT DEFINITIONS Unless the context indicates otherwise, the following terms shall have the meanings set out below when used in this Annual Information Form. Certain other terms and abbreviations used herein, but not defined herein, are defined in NI 51-101 or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or the COGE Handbook. “ABCA” means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended; “AIF” or “Annual Information Form” means this annual information form; “Audit Committee” means the audit committee of the Board; “Board of Directors” or “Board” means the board of directors of the Corporation; “COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum; “Common Shares” means the common shares of the Corporation; “Corporation” or “Surge” means Surge Energy Inc., a corporation amalgamated under the ABCA; “Credit Facility” means the $725 million extendible revolving term credit facility of the Corporation, as amended from time to time, with a banking syndicate led by National Bank of Canada and including Alberta Treasury Branches, Canadian Imperial Bank of Commerce, the Bank of Nova Scotia, JP Morgan Chase Bank, N.A., Toronto Branch, the Toronto Dominion Bank, Bank of Montreal, and HSBC Bank Canada, and bearing interest at bank rates; “Longview” means Longview Oil Corp.; “Longview Acquisition” means the acquisition by Surge of all of the issued and outstanding shares in the capital of Longview not already owned by Surge by plan of arrangement; “McDaniel” means McDaniel & Associates Consultants Ltd., independent oil and gas reservoir engineers; “NI 51-101” means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities; “Renegade Asset Acquisition” means the acquisition by the Corporation of the SE Saskatchewan Assets from Renegade Petroleum Ltd. pursuant to the terms of the asset sale agreement dated as of January 13, 2014, between Renegade and the Corporation; “Sproule” means Sproule Associates Limited, independent oil and gas reservoir engineers; “Surge Reserves Report” means the consolidated independent engineering report dated February 13, 2015 and effective December 31, 2014 prepared by Sproule and containing the evaluations of Sproule and McDaniel of the oil, NGL and natural gas reserves attributable to the properties of the Corporation; and “TSX” means the Toronto Stock Exchange. Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All dollar amounts set forth in this Annual Information Form, including “dollar”, “$” and “CAD$” are in Canadian dollars, except where otherwise indicated. “US$” means United States dollars. - 3 - ABBREVIATIONS AND CONVERSION In this Annual Information Form, the abbreviations set forth below have the following meanings: Oil and Natural Gas Liquids Natural Gas bbl bbls Mbbls MMbbls Mstb bbl/d NGLs stb Barrel Barrels thousand barrels million barrels 1,000 stock tank barrels barrels per day natural gas liquids stock tank barrel Mcf MMcf Mcf/d MMcf/d MMBtu Bcf GJ thousand cubic feet million cubic feet thousand cubic feet per day million cubic feet per day million British Thermal Units billion cubic feet gigajoule The following table sets forth certain standard conversions from Standard Imperial Units to the International System of Units (or metric units). To Convert From To Multiply By Mcf Cubic metres Bbls Cubic metres Feet Metres Miles Kilometres Acres Hectares Gigajoules MMbtu Cubic metres Cubic feet Cubic metres Bbls Metres Feet Kilometres Miles Hectares Acres MMbtu Gigajoules 28.174 35.494 0.159 6.293 0.305 3.281 1.609 0.621 0.405 2.50 0.950 1.0526 Other AECO API °API BOE BOE/d m3 MBOE MMBOE $000s M$ or $M MM$ WTI a natural gas storage facility located at Suffield, Alberta American Petroleum Institute an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 35.1° API or greater is generally referred to as light crude oil. Liquid petroleum with a specified gravity of 25.8° to 35° API or greater is generally referred to as medium crude oil. Liquid petroleum with a specified gravity of 25.7° API or lower is generally referred to as heavy crude oil. barrel of oil equivalent on the basis of 1 BOE to 6 Mcf of natural gas. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 1 BOE for 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead barrel of oil equivalent per day cubic metres 1,000 barrels of oil equivalent 1,000,000 barrels of oil equivalent thousands of dollars thousands of dollars millions of dollars West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade - 4 - NON-IFRS MEASURES This AIF contains the term “netback” which is not defined by IFRS and therefore may not be comparable to performance measures presented by others. In this AIF, "netback" is calculated by deducting royalties paid and production costs, including transportation costs, from prices received, excluding the effects of hedging. Management believes that in addition to net income, netbacks are a useful supplemental measure as it assists in the determination of the Corporation's operating performance. Readers should be cautioned, however, that this measure should not be construed as an alternative to both net income and net cash from (used in) operating activities, which are determined in accordance with IFRS, as indicators of the Corporation's performance. NOTES ON RESERVES DATA AND OTHER OIL AND NATURAL GAS INFORMATION Caution Respecting Reserves Information The determination of oil and natural gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions. 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. The recovery and reserve estimates of oil, NGL and natural gas reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. The estimated future net revenue from the production of the Corporation’s natural gas and petroleum reserves does not represent the fair market value of the Corporation's reserves. Caution Respecting BOE In this AIF, the abbreviation BOE means barrel of oil equivalent on the basis of 1 BOE to 6 Mcf of natural gas when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf to 1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Definitions Certain terms used in this AIF in describing reserves and other oil and natural gas information are defined below. Certain other terms and abbreviations used in this AIF, but not defined or described, are defined in NI 51-101 or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or the COGE Handbook. Reserves Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (a) analysis of drilling, geological, geophysical and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates as follows: “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. - 5 - “probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. The qualitative certainty levels referred to in the definitions above are applicable to "individual reserves entities" (which refers to the lowest level at which reserves calculations are performed) and to "reported reserves" (which refers to the highest-level sum of individual entity estimates for which reserves estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions: • • at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories as follows: “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 as follows: “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. “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. “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 sub-divide the developed reserves for the pool between developed producing and developed non- producing. This 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. Interests in Reserves, Production, Wells and Properties “gross” means: (a) in relation to an issuer's interest in production or reserves, its "company gross reserves", which are its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the issuer; (b) in relation to wells, the total number of wells in which an issuer has an interest; and (c) in relation to properties, the total area of properties in which an issuer has an interest. “net” means: (a) in relation to an issuer's interest in production or reserves its working interest (operating or non- operating) share after deduction of royalty obligations, plus its royalty interests in production or reserves; (b) in relation to an issuer's interest in wells, the number of wells obtained by aggregating the issuer's working interest in each of its gross wells; and (c) in relation to an issuer's interest in a property, the total area in which the issuer has an interest multiplied by the working interest owned by the issuer. “working interest” means the percentage of undivided interest held by an issuer in the oil and/or natural gas or mineral lease granted by the mineral owner, Crown or freehold, which interest gives the issuer the right to "work" the property (lease) to explore for, develop, produce and market the leased substances. - 6 - Description of Exploration and Development Wells and Costs “development costs” means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the crude oil and natural gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves; (b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly; (c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (d) provide improved recovery systems. “development well” means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive. “exploration costs” means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and natural gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as "geological and geophysical costs"); (b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records; (c) dry hole contributions and bottom hole contributions; (d) costs of drilling and equipping exploratory wells; and (e) costs of drilling exploratory type stratigraphic test wells. “exploration well” means a well that is not a development well, a service well or a stratigraphic test well. “service well” means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation or injection for combustion. SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS Certain statements or disclosures contained in this Annual Information Form constitute forward-looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Corporation believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Such forward-looking statements included in this Annual Information Form should not be unduly relied upon. These statements speak only as of the date of this Annual Information Form. In particular, this Annual Information Form may contain forward-looking statements and information pertaining to the following: the performance characteristics of the Corporation’s oil and natural gas properties; • • oil and natural gas production levels; • • projections of market prices and costs; • supply and demand for oil and natural gas; the size of the oil and natural gas reserves of the Corporation and anticipated future cash flows from such reserves; - 7 - • expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; the Corporation’s dividend policy and the amount of timing of dividends; treatment under governmental regulatory regimes and tax and royalty laws; • • • criteria and considerations in participations and acquisitions; • • • estimated abandonment and reclamation costs and the timing thereof; • expected land expiries and plans with respect thereto; • plans to implement enhanced recovery; and • capital expenditure programs, the allocation of such capital and the timing thereof. tax horizon; timing of development of undeveloped reserves; With respect to forward looking statements contained in this Annual Information Form, the Corporation has made assumptions regarding: the success of the Corporation’s operations and exploration and development activities; the availability of labour, services and drilling equipment; the availability of capital to fund planned expenditures; timing and amount of capital expenditures; • oil and natural gas production levels; • • prevailing weather conditions, commodity prices and exchange rates; • • • • general economic and financial market conditions; • • • government regulation in the areas of taxation, royalty rates and environmental protection; and • the success, nature and timing of water flood activities; the ability of the Corporation to secure necessary personnel, equipment and services; the success of exploration and development activities. The actual results, performance or achievements of the Corporation may differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this Annual Information Form: liabilities inherent in oil and natural gas operations; inability to secure labour, services or equipment on a timely basis or on favourable terms; • volatility in market prices for oil and natural gas; • volatility in exchange rates; • • uncertainties associated with estimating oil and natural gas reserves; • • competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; • unfavourable weather conditions; • • geological, technical, drilling, completion and processing problems; • results of water flood responses; • • changes in legislation, including changes in tax laws and incentive programs relating to the oil and gas industry; • • failure to realize the anticipated benefits of acquisitions; and the other factors discussed under “Risk Factors”. the outcome of litigation brought against the Corporation or other disputes involving the Corporation; incorrect assessments of the value of acquisitions and exploration and development programs; Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this Annual Information Form are expressly qualified by this cautionary statement. The Corporation does not undertake any obligation to publicly update or revise any forward-looking statements other than as required under applicable securities laws. - 8 - SURGE ENERGY INC. Corporate Structure Surge was incorporated on January 26, 1998 under the ABCA as “Zapata Capital Inc.” On June 18, 1999, the Corporation acquired all of the issued and outstanding shares of 744997 Alberta Ltd. and amalgamated with 744997 Alberta Ltd. under the name “Zapata Energy Corporation”. On June 25, 2010, the Corporation changed its name to “Surge Energy Inc.” On December 31, 2010, the Corporation amalgamated with its wholly owned subsidiary, Breaker Resources Ltd. On December 31, 2012, the Corporation amalgamated with is wholly owned subsidiary, Surge Oil Inc. On December 31, 2013, the Corporation amalgamated with its wholly owned subsidiaries, Flagstone Energy Inc. and 1779275 Alberta Ltd. On December 31, 2014, the Corporation amalgamated with its wholly owned subsidiary, Longview Oil Corp. The head office of the Corporation is located at 2100, 635 – 8th Avenue S.W., Calgary, Alberta T2P 3M3. The registered office of the Corporation is located at Suite 4000, 421 – 7th Avenue S.W., Calgary, Alberta, T2P 4K9. Intercorporate Relationships The Corporation has one wholly-owned subsidiary, 1413942 Alberta Ltd. The Corporation and 1413942 Alberta Ltd. are the general partners of Surge General Partnership. The corporate structure of the Corporation and its subsidiaries is as set forth in the diagram below: General DEVELOPMENT OF THE BUSINESS The Corporation is an independent Calgary, Alberta-based oil and gas company operating primarily in Alberta, Saskatchewan and Manitoba. The Common Shares are listed on the TSX under the symbol “SGY”. Three Year History Significant developments of the Corporation over the last three completed financial years are as set forth below: - 9 - 2012 Pradera Acquisition On January 6, 2012, the Corporation completed the acquisition of all of the issued and outstanding shares of Pradera Resources Inc. (the “Pradera Acquisition”) for aggregate consideration of approximately $106 million, consisting of 7.9 million Common Shares, $18.5 million in cash and the assumption of net debt totaling $14.5 million. Through the Pradera Acquisition, the Corporation acquired light oil production in its early stage of primary development focused in the Slave Point/Gilwood in the Gift/Nipisi area of Western Alberta, approximately 60 kilometres north-west of Slave Lake, Alberta. The assets consisted of approximately 1,200 bbl/d of production (100 percent light oil). Credit Facility The Credit Facility was increased from $150 million to $175 million in connection with the Pradera Acquisition. On April 12, 2012, the Corporation confirmed a further increase in the Credit Facility from $175 million to $250 million. In December 2012, the Corporation confirmed a further increase in the Credit Facility from $250 million to $290 million. 2013 Management Reorganization On May 8, 2013, the Corporation announced the appointment of Mr. Paul Colborne as President and Chief Executive Officer, the resignation of Mr. P Daniel O’Neil as President and Chief Executive Officer, and the appointment of Mr. Murray Bye as the Vice President, Production. In connection with his appointment as President and Chief Executive Officer, Mr. Colborne subscribed for an aggregate of $2.5 million in units of the Corporation at a price of $3.57 per unit. Each unit was comprised of one Common Share and two Common Share purchase warrants with each such warrant entitling the holder thereof to purchase one Common Share at $4.46 for a period of five years, subject to vesting based on both time and the performance of the Common Shares. With respect to time vesting, the warrants vest as to 1/3 on each of the first three anniversaries of the issuance date. With respect to performance vesting, the warrants vest as to 1/2 when the market price of the Common Shares (calculated using the volume weighted average trading price of the Common Shares for the preceding 20 trading days) reaches $6.30, and 1/2 when the market price reaches $8.40. Both the time and performance vesting criteria must occur before any warrants vest. The warrants are non-transferable, except to certain permitted transferees, all as approved by the Board. North Dakota Disposition On May 31, 2013, the Corporation completed the sale of certain non-core, primarily non-operated assets in North Dakota through the sale of all of the issued and outstanding shares of its previously wholly-owned subsidiary, Surge Energy USA Inc., for gross proceeds of US$42.7 million (the “North Dakota Disposition”). The assets of Surge Energy USA Inc. consisted of production of approximately 650 BOE/d, with independently engineered proved plus probable reserves of 2.2 million BOE, and a net present value of US$36.8 million (discounted at ten percent before tax as of December 31, 2012). Cenovus Asset Acquisition and Financing On July 3, 2013, the Corporation completed the acquisition of certain petroleum and natural gas properties and related assets in southwest Saskatchewan from Cenovus Energy Inc. for total consideration of $242.4 million (the “Cenovus Asset Acquisition”). The acquired assets are located in southwest Saskatchewan, approximately 100 kilometres southwest of Swift Current, Saskatchewan, 140 kilometres east of the Alberta border. The assets include an average working interest of approximately 98% in 14,485 gross (14,196 net) acres of undeveloped land as at April 1, 2013. Production from the assets was weighted 100% to medium crude oil and natural gas liquids. The property also included 134 gross (133 net) producing oil wells and 49 gross (49 net) non-producing oil wells as at April 1, 2013. Major facilities included a battery at 1-15-6-19- W3 that has capacity of 15,000 barrels of emulsion per day and 10 MMcf of gas per day, five tanks that have capacity for 5,000 barrels each, a free water knockout, a water treater and disposal water pumps. The assets consisted of production of approximately 3,468 BOE/d (average production volume for the three months ended September 30, 2013), with - 10 - independently engineered net proved plus probable reserves of 10.2 million BOE, and a net present value of $223 million (discounted at ten percent before tax as of April 1, 2013). Concurrently with the Cenovus Asset Acquisition, on July 3, 2013, the Corporation also completed a $247,500,000 “bought deal” unit financing by short form prospectus pursuant to which the Corporation issued an aggregate of 15,000,000 units at a price of $15.00 per unit and an additional 4,500,000 subscription receipts at a price of $5.00 per subscription receipt pursuant to the exercise of the underwriters’ option. Each unit was comprised of one Common Share and two subscription receipts. Each subscription receipt converted into one Common Share upon completion of the Cenovus Asset Acquisition. Flagstone Acquisition and Fort Calgary Asset Acquisition On November 13, 2013, the Corporation completed: (i) the acquisition of all of the issued and outstanding shares of Flagstone Energy Inc. (the “Flagstone Acquisition”); and (ii) the acquisition of certain petroleum and natural gas properties and related assets in southwest Manitoba from 1779275 Alberta Ltd. and Fort Calgary Resources Ltd. (the “Fort Calgary Asset Acquisition”); The Flagstone Acquisition involved a $147 million (based on a Surge share price of $6.00 per Common Share) purchase of all of the issued and outstanding shares of Flagstone Energy Inc., a Calgary based private oil and gas company with high netback, operated, producing light oil assets focused in the Steelman area of southeast Saskatchewan and the Dodsland area of southwest Saskatchewan. The consideration for the Flagstone Acquisition was comprised of 20.2 million Common Shares and cash consideration of $3.0 million, plus the assumption of $23 million of debt. The Fort Calgary Asset Acquisition involved the acquisition by the Corporation of high quality, high netback, operated, producing light oil assets primarily located in the southwest area of Manitoba for total consideration of $135 million (based on a Surge share price of $6.00 per Common Share), comprised of 14.2 million Common Shares and $50 million of cash. Wainwright Asset Acquisition and Financing On December 3, 2013, the Corporation completed the acquisition of certain oil and gas assets located in the Wainwright area of central Alberta from a Calgary based company for consideration of $76.8 million in cash (the “Wainwright Acquisition”). The assets included an average working interest of 80% in approximately 24,054 gross (19,252 net) acres of developed land and 64% in approximately 5,107 gross (3,291 net) acres of undeveloped land as at November 5, 2013. Production from the assets was weighted 98% to medium crude oil (23° API) and included key producing infrastructure, including batteries, pipelines, and water flood facilities. On November 28, 2013, just prior to the Wainwright Asset Acquisition, the Corporation completed a $63,273,000 “bought deal” subscription receipt financing by short form prospectus pursuant to which the Corporation issued an aggregate of 9,660,000 subscription receipts at a price of $6.55 per subscription receipt (including the exercise of the underwriters’ option). Each subscription receipt converted into one Common Share upon the completion of the Wainwright Asset Acquisition. Credit Facility On May 31, 2013, in connection with the North Dakota Disposition, the Credit Facility was reduced from $290 million to $277 million. On July 3, 2013, in connection with the Cenovus Asset Acquisition, the Credit Facility was increased from $277 million to $350 million. On December 3, 2013, in connection with Flagstone Acquisition, the Fort Calgary Asset Acquisition and the Wainwright Asset Acquisition, the Credit Facility was increased from $350 million to $470 million. 2014 Renegade Asset Acquisition and Financing On February 14, 2014, the Corporation completed the Renegade Acquisition and acquired certain petroleum and natural gas properties and related assets in southeast Saskatchewan for consideration of $109 million in cash. The assets included an average working interest of approximately 83% in 14,735 gross (12,226 net) acres of undeveloped land as at January 13, - 11 - 2014, with an internally estimated value of $3 million. Production from the assets was weighted 97% to light crude oil (36° API). The assets also included key producing infrastructure, including batteries, pipelines, and water flood facilities. On February 4, 2014, just prior to the Renegade Asset Acquisition, the Corporation completed a $80,506,440 “bought deal” subscription receipt financing by short form prospectus pursuant to which the Corporation issued an aggregate of 12,778,800 subscription receipts at a price of $6.30 per subscription receipt (including the exercise of the underwriters’ option). Each subscription receipt converted into one Common Share upon the completion of the Renegade Asset Acquisition. Longview Acquisition On February 28, 2014, Surge acquired 9.3 million shares in the capital of Longview (“Longview Shares”), representing 19.8 percent of the issued and outstanding Longview Shares, at a purchase price of $4.45 per Longview Share pursuant to a bought deal secondary offering of the Longview Shares. On June 5, 2014, Surge completed the Longview Acquisition, being the acquisition by Surge of all of the remaining issued and outstanding Longview Shares by plan of arrangement. Under the Longview Acquisition, shareholders of Longview, other than Surge, received 0.975 Common Shares in exchange for each Longview Share held. Surge issued an aggregate of 37,975,332 Common Shares (at a deemed price of $6.14 per Common Share) pursuant to the Longview Acquisition and assumed approximately $155 million of Longview net debt, implying a transaction value, including the Longview Shares purchased on February 28, 2014, of approximately $430 million. The Longview Acquisition included production, as at June 5, 2014, of approximately 5,700 BOE/d (80 percent oil and NGLs), proven and probable reserves, as at December 31, 2013, of approximately 37.6 million BOE (80 percent oil and NGLs) and approximately 143,600 net acres of undeveloped lands. Credit Facility Effective May 29, 2014, the Credit Facility was increased from $470 million to $525 million. On June 5, 2014, in connection with the Longview Acquisition, the Credit Facility was increased from $525 million to $725 million. Subsequent to the year ended December 31, 2014, on March 18, 2015, the Corporation confirmed the Credit Facility at $675 million, after giving effect to immaterial property dispositions and the reconfiguration of the Corporation’s WTI oil hedges. Significant Acquisitions Other than the Longview Acquisition, Surge did not complete any significant acquisitions during its most recently completed financial year for which disclosure is required under Part 8 of National Instrument 51-102 Continuous Disclosure Obligations. For further particulars regarding the Longview Acquisition, see the material change report of the Corporation dated June 12, 2014 and the business acquisition report dated July 27, 2014. See “General Development of the Business – Three Year History – 2014 – Longview Acquisition”, above. Overview DESCRIPTION OF THE BUSINESS The Corporation is a moderate growth, dividend paying oil and gas exploration, development and production company. Surge holds focused and operated high quality light and medium gravity crude oil properties, primarily in Alberta, Saskatchewan and Manitoba, characterized by large oil in place crude oil reservoirs with low recovery factors. The Corporation has a significant inventory of low risk development drilling locations, including several successful water flood projects. Surge currently pays monthly cash dividends to shareholders from its net cash flow in accordance with its dividend policy. See “Dividend Policy.” - 12 - Corporate Strategy The Corporation is building a moderate growth, dividend paying oil and gas company with focused, operated light and medium gravity crude oil assets. The Corporation focuses on assets with the following criteria: large oil in place with low recovery factors, available infrastructure, high working interest, operatorship, all-season access and drilling inventory, water flood opportunities and other upside that provides a definable high rate of return. Surge's business model is to grow, cost effectively, at a rate of three to five percent per year on a reserves, production and cash flow per share basis, to provide a sustainable annual dividend to shareholders, payable monthly, and to provide additional growth through accretive acquisitions of large oil in place assets with low recovery factors. Surge has a risk management/hedging program designed to protect cash flows, fund capital expenditures, and to pay dividends. To achieve sustainable and profitable growth, the Corporation intends to utilize its skills in identifying and capturing oil resource plays and then cost effectively exploiting those reserves. To achieve this, the Corporation may make asset and corporate acquisitions or enter into agreements that meet the Corporation’s business parameters. Management of the Corporation believes in controlling the timing and costs of its projects wherever possible. Accordingly, the Corporation seeks to become the operator of its properties. Further, to minimize competition within its geographic areas of interest, the Corporation strives to maximize its working interest ownership in its properties where reasonably possible. In reviewing potential drilling or acquisition opportunities, the Corporation gives consideration to the following criteria: (a) (b) (c) (d) risk capital to secure or evaluate the opportunity; the potential return on the project, if successful; the likelihood of success; and risked return versus cost of capital. In general, the Corporation pursues a portfolio approach in developing a large number of opportunities with a balance of risk profiles in an attempt to generate sustainable levels of growth. It should be noted that the Board of Directors of the Corporation may, in its discretion, approve asset or corporate acquisitions or investments that do not conform to the guidelines discussed above based upon the Board’s consideration of the qualitative aspects of the subject properties, including risk profile, technical upside, reserve life and asset quality. In addition, the management team of the Corporation, as described below under “Directors and Officers”, is continually assessing the assets and operations of the Corporation, including its existing land base, facilities, reserves, prospects and personnel. While the Corporation has prepared a budget for the first half of 2015 based on guidance for such year, the Corporation may further evaluate its existing reserves, drilling prospects, prevailing commodity prices and capital expenditure program, among other items, and may change its budget as the year progresses. The Corporation currently plans to pursue the development of its proven and probable undeveloped reserves within the next three years through ordinary course capital expenditures. However, the Corporation may choose to accelerate or delay development depending on a number of circumstances, including the existence of higher priority expenditures and prevailing commodity prices and cash flow. Competition The oil and natural gas industry is competitive in all its phases. The Corporation competes with numerous other participants in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. The Corporation’s competitors include resource companies which have greater financial resources, staff and facilities than those of the Corporation. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. The Corporation believes that its competitive position is equivalent to that of other oil and gas issuers of similar size and at a similar stage of development. - 13 - Cyclical and Seasonal Nature of Industry Surge’s operational results and financial condition are dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated during recent years and are determined by a number of factors, including global and local supply and demand factors, and including weather and general economic conditions, as well as conditions in other oil and natural gas producing and consuming regions. Surge attempts to mitigate such price risk through closely monitoring commodity markets and establishing disciplined hedging programs. The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for the goods and services of the Corporation. Demand for natural gas typically rises during cold winter months and hot summer months. Environmental Regulation The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Compliance with such legislation can require significant expenditures or result in operational restrictions. Breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties, all of which might have a significant negative impact on earnings and overall competitiveness. See below under the headings “Industry Conditions - Environmental Regulation” and “Risk Factors – Environmental Concerns”. The Corporation is obligated to abandon, retire and reclaim wells and wellsites in compliance with applicable environmental laws and regulations. As of December 31, 2014, the Corporation has recorded an asset retirement obligation of $219 million. The Corporation anticipates that the expenditures necessary to satisfy the asset retirement obligation will be incurred over a period of fifty years, with the majority of the expenditures being incurred from years 2025 to 2064. Other than asset retirement obligations and ordinary course operational expenditures necessary to ensure environmental compliance, the Corporation is not aware of any environmental protection requirement that will impact its capital expenditures, earnings or competitive position in a manner disproportionate to that of its peers in its area of operations. Marketing Surge’s crude oil and natural gas production are sold primarily through marketing companies at current market prices. See also “Interest of Management and Others in Material Transactions”. The Corporation also has a hedging policy as described under "Statement of Reserves Data and Other Oil and Gas Information – Other Oil and Gas Information – Forward Contracts". For details of the Corporation's forward contracts in place as at December 31, 2014, see the Corporation's audited annual financial statements for the year ended December 31, 2014, which have been filed on SEDAR and may be viewed under the Corporation's profile at www.sedar.com . See "Risk Factors". Personnel As at December 31, 2014, the Corporation had 79 head office employees and 3 field employees. - 14 - Health, Safety and Environmental Management, employees and contractors are responsible and accountable for the overall health, safety and environmental program. Surge operates in compliance with all applicable regulations and ensures that all staff and contractors employ sound practices to protect the environment and to ensure employee and public health and safety. Surge maintains a safe and environmentally responsible work place and provides training, equipment and procedures to all individuals in adhering to its policies. It also solicits and takes into consideration input from neighbors, communities and other stakeholders in regard to protecting people and the environment. PRINCIPAL PRODUCING PROPERTIES The Corporation’s principal oil and natural gas producing properties are located in Alberta, Saskatchewan and Manitoba. A description of those properties, as at December 31, 2014, is provided below. Northern Alberta As at December 31, 2014, the Corporation’s principal properties in northern Alberta included Valhalla/Wembley and Nipisi. Surge held an average working interest of approximately 71% in approximately 116,802 gross (83,005 net) developed acres and an average working interest of approximately 89% in approximately 117,762 gross (105,047 net) undeveloped acres. As at December 31, 2014, the Corporation held interests in 203 gross (152 net) oil wells and 58 gross (33 net) gas wells producing from, but not limited to, the Doe Creek, Doig, Montney, Slave Point, and Gilwood formations. In addition, the Corporation operates multiple oil batteries and an oil blending facility, providing a strong infrastructure base for future development in the area. As at December 31, 2014, Surge’s production in northern Alberta was approximately 5,365 BOE/d (66 percent oil and NGLs). Valhalla/Wembley The Valhalla/Wembley property is located in northwestern Alberta, approximately 40 kilometres northwest of Grand Prairie (TWP 74, Range 8, W6M). As at December 31, 2014, this operated property included an average working interest of approximately 76% in approximately 26,402 gross (20,057 net) developed acres and an average working interest of approximately 88% in approximately 21,761 gross (19,105 net) undeveloped acres. The majority of production from this property was from the new horizontal oil wells producing from an extensive tight sand, with up to 50 metres of gross light oil pay in the Triassic Doig formation. Additionally, in 2014, the Corporation acquired a 100% working interest in a vertically and horizontally developed Doe Creek oil pool which is currently under waterflood. Total proved plus probable (“2P”) reserves on these assets are estimated at 27,382 MBOE (54 percent oil and NGL’s), as at December 31st, 2014. In 2014, the Corporation drilled at total of 5 gross wells (3.78 net) horizontal multi-frac wells at Valhalla/Wembley. Nipisi The Nipisi property lies approximately 50 kilometres north of the town of Slave Lake, in northwestern Alberta. Light oil production is from the Slave Point and Gilwood formations. The Slave Point production is from horizontal, multi-frac wells and the Gilwood production is from vertical wells. There were approximately 17 Slave Point wells producing (98.5% working-interest) and a total of 13 Gilwood wells producing (100% working-interest). As at December 31, 2014, this operated property included an average working interest of approximately 78% in approximately 8,800 gross (6,891 net) developed acres and an average working interest of approximately 95% in approximately 15,840 gross (14,972 net) undeveloped acres. In 2014, the Corporation drilled a total of 2 gross (2 net) horizontal multi-frac oil wells at Nipisi. Both wells were on production by December 31st, 2014 and are averaging at internal type curve expectations. As of December 31st, 2014 the total estimated 2P reserves at Nipisi were 8,318 MBOE (100 percent oil). The waterflood project at Nipisi continued to advance in 2014. Two additional injectors were converted and a second water injection plant was constructed. - 15 - Central Alberta As at December 31, 2014, Surge’s principal properties in central Alberta included Windfall and Nevis. The Corporation held an average working interest of approximately 63% in approximately 62,280 gross (39,260 net) developed acres and an average working interest of approximately 92% in approximately 61,010 gross (56,418 net) undeveloped acres. As at December 31, 2014, the Corporation held interests in 236 gross (107 net) oil wells and 105 gross (27 net) gas wells producing from, but not limited to, the Banff, Wabamun, Rock Creek, Glauc, and Bluesky formations. In addition, the Corporation operates multiple oil batteries and gas handling facilities, providing a strong infrastructure base for future development in the area. As at December 31, 2014, Surge’s production in central Alberta was approximately 2,324 BOE/d (61 percent oil and NGLs). Windfall The Windfall assets are located in western Alberta near Whitecourt (TWP 59, Range 15, W5M). As at December 31, 2014, this operated property included an average working interest of approximately 99% in approximately 7,520 gross (7,480 net) developed acres and an average working interest of approximately 97% in approximately 22,720 gross (22,104 net) undeveloped acres. Production from this property is derived from 10 horizontal multi-frac wells and nine vertical wells. A waterflood pilot, originally implemented in 2012, has demonstrated positive results in terms of stabilizing reservoir pressure and flattening the decline of the offset producing horizontal wells. A total of approximately 98,000 m3 (615,000 bbl) of water has been injected as of December 31st, 2014. The total estimated 2P reserves at Windfall, as of December 31, 2014 were 2,467 MBOE (41 percent oil and NGL’s). Nevis Nevis is an operated property which is situated 60 kilometres east of Red Deer, Alberta. The Nevis property was acquired pursuant to the Longview Acquisition. The property is divided into two main Wabamun oil pools. Crude oil quality for this property averages 39° API and there is associated natural gas and NGL production. Two operated facilities are utilized to process the oil and natural gas production from Nevis. The main producing zone is the Devonian age Wabamun Formation, which occurs at about 1,600 metres true vertical depth. This reservoir is a high porosity, low permeability carbonate which results in relatively low production inflow from vertical wells. As at December 31, 2014, this operated property included an average working interest of approximately 70% in approximately 19,367 gross (13,498 net) developed acres and an average working interest of approximately 100% in approximately 4,091 gross (4,091 net) undeveloped acres. Production from this property is derived from 73 horizontal multi-frac wells and 34 vertical wells. Two waterflood pilots are underway with both yielding encouraging results. As of December 31, 2014 the total estimated 2P reserves at Nevis were 6,590 MBOE (59 percent oil and NGL’s) Southeast Alberta As at December 31, 2014, Surge’s principal properties in southeastern Alberta included the Sparky assets and the mature waterflood at Silver. The Corporation held an average working interest of approximately 77% in approximately 139,881 gross (107,921 net) developed acres and an average working interest of approximately 89% in approximately 72,370 gross (64,104 net) undeveloped acres. As at December 31, 2014, the Corporation held interests in 451 gross (308 net) oil wells and 221 gross (77 net) gas wells producing from, but not limited to, the Lloydminster, Sparky, Cummings, Glauconite, Rex, Dina and Viking formations. In addition, the Corporation operates multiple oil batteries and an oil blending facility, providing a strong infrastructure base for future development in the area. As at December 31, 2014, Surge’s production in southeast Alberta was approximately 4,246 BOE/d (86 percent oil and NGLs). Sparky The Corporation’s Sparky Assets are comprised of four main fields spread between Provost and Wainwright in eastern Alberta and western Saskatchewan. Eye Hill and Provost are early stage primary development properties, while Wainwright and Macklin are far more mature, mostly developed waterflood assets. As at December 31, 2014, the Corporation held an average working interest of 84% in approximately 32,522 gross (27,316 net) developed acres and 88% in approximately 15,381 gross (13,569 net) undeveloped acres between Eye Hill, Provost, Macklin, and Wainwright. Production from the Sparky is primarily crude oil (89 percent oil and NGL’s) ranging from 23° to 28° degrees API. In 2014, the Corporation drilled - 16 - 9 gross (9 net) horizontal multistage frac oil wells on these properties. Additionally, a waterflood pilot at Eye Hill was initiated in Q4 2014. As of December 31, 2014 total estimated 2P reserves associated with the Sparky assets were 6,046 MBOE (95 percent oil and NGL’s). Silver Silver Lake is an operated property, located west of Provost in eastern Alberta (TWP 40 RGE 3W4M). As of December 31, 2014 the Corporation held an average working interest of approximately 79% in approximately 13,051 gross (10,270 net) developed acres and an average working interest of approximately 94% in approximately 9,202 gross (8,604 net) undeveloped acres. Production from this property is primarily 24° API Crude oil from the Lloydminster and Cummings formations. The field has been developed by a mixture of horizontal and vertical wells and is extensively under waterflood. As at December 31, 2014 the total estimated 2P reserves at Silver were 3,027 MBOE (93 percent oil and NGL’s). Southwest Saskatchewan Shaunavon The Shaunavon property, acquired in July 2013, is located in southwestern Saskatchewan, approximately 100 kilometres southwest of Swift Current, Saskatchewan and 140 kilometres east of the Alberta border (TWP 4-7, Range 18-20, W3M). As at December 31, 2014, this operated property included an average working interest of approximately 99% in approximately 21,756 gross (21,556 net) developed acres and an average working interest of approximately 97% in 13,103 gross (12,748 net) undeveloped acres. The Corporation’s production from this property is weighted 100% to medium crude oil (21-26° API). As at December 31, 2014, this property produced approximately 3,100 BOE/d, approximately 1,750 BOE/d from the Lower Shaunavon and 1,350 BOE/d from the Upper Shaunavon wells and the total estimated 2P reserves were 12,500 MBOE (100% oil). The Corporation operates major facilities at this property providing a strong infrastructure base for future development in the area. Facilities include a battery at 1-15-6-19-W3 that has capacity of 15,000 bbls of emulsion per day and 10 MMcf of gas per day, five tanks that have capacity for 5,000 bbls each, a free water knockout, a water treater, disposal/injection water pumps and ten satellites. The Corporation drilled 4 gross (3 net) wells in Lower Shaunavon in the first quarter of 2014. In late 2013, 5 Lower Shaunavon producers were converted to injectors. Of these, 3 injectors were on a pattern with producers offsetting at 200 metre interwell distance, and 2 injectors were on a pattern with producers offsetting at 400 metre interwell distance. Surge is reviewing plans for conformance control to improve recovery and to further expand the waterflood to better parts of the reservoir. At the emerging Upper Shaunavon play, the Company drilled 9 horizontal, multi-frac wells. The Corporation is investigating several different types of Enhanced Oil Recovery pilots to further increase recovery from this play. Southeast Saskatchewan/Manitoba Southeast Saskatchewan – Midale Area The Corporation’s entered into southeastern Saskatchewan through the Flagstone Acquisition in November 13, 2013. The Corporation enlarged its position with the addition of certain assets acquired pursuant to the Renegade acquisition on February 14, 2014 and again with the Longview Acquisition on June 5, 2014. The southeastern Saskatchewan area is broken into three Producing Areas situated near Estevan, Saskatchewan. The Macoun and Pinto areas contain mostly Midale production, while the Alida area is mainly Frobisher/Alida Production. As at December 31, 2014, the Corporation holds an average working interest of 77% in 37,941 gross (23,231 net) acres of developed land and 70% in 74,896 gross (52,627 net) acres of undeveloped land and 373 gross (168 net) producing oil wells for approximately 3,740 BOE/d and total estimated 2P reserves of 16,744 MBOE (95% oil). Macoun The Macoun area consists of production and land in Weyburn, Midale and Macoun properties (TWP 2-10, Range 7-15, W2M). Production from these properties is primarily from the Midale formation and consists of 98% oil (27-40° API). The - 17 - Corporation holds an average working interest of 75% in 12,470 gross (9,330 net) acres of developed land and 48% in 37,095 gross (17,751 net) acres of undeveloped land, the total estimated 2P reserves were 6,800 MBOE (99% oil) as of December 31, 2014. December 2014 average production was approximately 1,850 BOE/d from 276 gross (116 net) oil wells producing from, but not limited to, the Midale, Red River, Winnipegosis, Bakken and Frobisher/Alida formation. Most of the 2014 activity was focused in the Macoun Pool where Surge drilled 5 horizontal, multi stage fraced gross (3.6 net) wells. In 2014, Surge completed several open hole fracs on existing producers. Shortly thereafter, Surge has evolved towards utilizing cemented liners with burst ports as the primary completion design. The Corporation also implemented a waterflood in the Macoun pool by upgrading infrastructure and converting 1 horizontal well to injection. Results have been positive and there are plans to convert more wells to injection in 2015. In addition, the Corporation operates multiple batteries with pipeline connections providing a strong infrastructure base for future development in the area. Pinto The Pinto area includes production and land from the Steelman, Alameda, Pinto and Northgate properties (TWP 1-6, Range 1-6, W2M). Production from these properties is primarily from Midale formation and consists of 99% oil (36-40° API). Corporate average working interest is 82% in 8,194 gross (6,723 net) acres of developed land and 98% in 25,157 gross (24,747 net) acres of undeveloped land, the total estimated 2P reserves were 4,200 MBOE (84% oil) as of December 31, 2014. December 2014 average production was approximately 930 BOE/d from 97 gross (52 net) oil wells producing from, but not limited to, the Midale, Red River, Winnipegosis, and Frobisher/Alida formation. Most of the activity in 2014 was centered in the Pinto and Northgate Pools. Surge drilled 2 gross (2 net) horizontal multi- stage frac wells. Surge also completed 1 Longview well which was not frac’d prior to the Longview acquisition. In Northgate, Surge participated in 3 gross (0.9 net) horizontal multi stage frac wells. Currently, Surge is in the early stages of implementing a waterflood in the Pinto property and plans to commence injection into a horizontal well in Q3/Q4 2015. In addition, the Corporation operates multiple batteries with pipeline connections providing a strong infrastructure base for future development in the area. Alida The Alida area includes production and land from the Silverton, Ingoldsby, Gainsbourough and Workman properties (TWP 1-6, Range 30W1-1W2M). Production from these properties is primarily from the Frobisher/Alida formation and consists of 99% oil (30-37° API). Corporate average working interest is 76% in 17,277 gross (13,178 net) acres of developed land and 80% in 12,644 gross (10,129 net) acres of undeveloped land, the total estimated 2P reserves were 5,700 MBOE (98% oil) as at December 31, 2014. December 2014 average production was approximately 960 BOE/d from 191 gross (122 net) oil wells producing from the Frobisher/Alida formation. Properties under the Alida area are characterized by large original oil in place pools with strong water drives resulting in modest declines and predictable cash flows. In addition, the Corporation operates multiple oil batteries with pipeline connections providing a strong infrastructure base for future development in the area. Manson The Manson area includes production from Wapella, Saskatchewan and Manson, Manitoba about 200 kilometres east of Regina (TWP 13-15, Range 26W1-1W2M). Oil production is primarily 90% from the Bakken formation (Manson) which is 25° API. The Corporation holds an average working interest of 87% in approximately 10,585 gross (9,177 net) acres of developed land and 98% in approximately 63,091 gross (61,543 net) acres of undeveloped land as at December 31, 2014. Production from the assets is weighted 100% to crude oil and as at December 31, 2014, the Manson area was approximately 1,425 BOE/d from 88 gross (41 net) oil wells producing from, but not limited to, the Bakken, Lodgepole and Mannville formation and the total estimated 2P reserves were 6,200 MBOE (100% oil). The Wapella property was purchased on November 13, 2013 and enlarged with the addition of certain assets acquired pursuant to the Longview Acquisition. The Manson Property was acquired in November 13, 2013. Most of the 2014 activity occurred in Manson with Surge participating in 4 gross wells (1.1 net) with certain partners. - 18 - Waterflood was a big focus in East Manson Unit #1, 3 and 4 with the conversion of 5 wells (1 Vertical and 4 Horizontal wells) to water injection. In the waterflood, all 7 injectors have resulted in incremental production from offsetting producers, there has been no water breakthrough observed as of the date of this AIF. The Corporation estimates that 300-400 bbl/d of the current field production is attributable to waterflood response. STATEMENT OF RESERVES DATA In accordance with NI 51-101 – Standards for Disclosure for Oil and Gas Activities, Sproule prepared the Surge Reserves Report based on the evaluations of Sproule and McDaniel of the oil, NGL and natural gas reserves attributable to the properties of the Corporation as at December 31, 2014. The Surge Reserves Report is dated February 13, 2015. Sproule evaluated the Corporation’s Alberta properties including Sunset, Nipisi, Valhalla, Westerose, Chip Lake, Windfall, and Nevis in western Alberta and the Provost, Wainwright, Silver Lake, and Eye Hill fields in southeast Alberta. Sproule also evaluated a most of the Corporation’s Williston Basin properties, including Manson, Wapella, Steelman, Pinto, and Waskada. McDaniel evaluated most of the Corporation’s Saskatchewan properties including the Shaunavon and Viking properties in southwest Saskatchewan as well as a portion of the Williston Basin properties, specifically Macoun. Sproule evaluated approximately 83% of the Corporation’s assigned total proved plus probable reserves and approximately 76% of the Corporation’s total proved plus probable future net revenue, discounted at 10%. McDaniel evaluated approximately 17% of the Corporation’s total proved plus probable reserves and approximately 24% of the Corporation’s total proved plus probable future net revenue discounted at 10%. The tables below are a combined summary of the oil, NGL and natural gas reserves attributable to the properties of the Corporation and the net present value of future net revenue attributable to such reserves as evaluated in the Surge Reserves Report based on forecast price and cost assumptions. The tables summarize the data contained in the Surge Reserves Report and, as a result, may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly. The net present value of future net revenue attributable to 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 costs for only those wells assigned reserves by Sproule and McDaniel, as applicable. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by Sproule or McDaniel represent the fair market value of those reserves evaluated. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of oil, NGL and natural gas reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. The Surge Reserves Report is based on certain factual data supplied by the Corporation and Sproule’s and McDaniel’s respective opinions of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Corporation to Sproule and McDaniel. Both Sproule and McDaniel accepted this data as presented and neither title searches nor field inspections were conducted. Summary of Oil and Gas Reserves – Forecast Prices and Costs Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Gross Reserves Light and Medium Crude Oil (Mbbls) 27,167.5 643.7 14,185.6 41,996.8 29,365.6 71,362.4 Heavy Crude Oil (Mbbls) 7,662.5 38.4 1,196.2 8,897.1 4,890.3 13,787.4 Natural Gas Liquids (Mbbls) Natural Gas (MMcf) 51,587.0 2,003.6 2,424.3 56.5 30,627.7 1,265.2 84,639.0 3,325.3 1,762.1 46,156.2 5,087.4 130,795.2 - 19 - Light and Medium Crude Oil (Mbbls) 23,587.6 561.1 12,193.4 36,342.1 24,339.9 60,682.0 Net Reserves Heavy Crude Oil (Mbbls) Natural Gas Liquids (Mbbls) Natural Gas (MMcf) 6,702.2 33.1 992.4 7,727.7 4,323.8 12,051.5 45,597.2 1,448.4 2,125.3 37.6 26,740.1 945.5 74,462.6 2,431.5 1,250.7 40,196.7 3,682.2 114,659.3 Net Present Value of Future Net Revenue – Forecast Prices and Costs ($M) Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable ($M) Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Before Future Income Tax Expenses and Discounted at 0% 5% 10% 15% 20% 1,723,347 43,792 570,150 2,337,289 1,953,652 4,290,942 1,286,740 31,760 378,462 1,696,961 1,036,293 2,733,254 1,037,971 24,732 261,196 1,323,899 660,610 1,984,509 875,850 20,130 183,797 1,079,777 464,039 1,543,816 761,396 16,874 129,924 908,194 345,328 1,253,521 After Future Income Tax Expenses and Discounted at 0% 5% 10% 15% 20% 1,575,741 32,248 421,431 2,029,419 1,432,042 3,461,461 1,186,387 23,384 269,515 1,479,285 753,518 2,232,803 964,836 18,232 176,511 1,159,579 473,971 1,633,550 820,091 14,870 115,323 950,285 327,290 1,277,574 717,466 12,500 72,999 802,965 238,717 1,041,682 Unit Value before Income Tax Discounted at 10%/year ($/BOE) 26.39 25.08 14.05 22.47 18.04 20.77 Additional Information Concerning Future Net Revenue – Forecast Prices and Costs (Undiscounted) (Undiscounted) ($M) Total Proved Total Proved plus Probable Revenue 5,468,785 9,746,262 Royalties 770,602 1,472,224 Operating Costs 1,868,232 3,236,569 Develop- ment Costs 416,837 654,584 Abandon- ment and Other Costs 75,826 91,943 Future net revenue before income taxes 2,337,289 4,290,942 Future net revenue after income taxes 2,029,419 3,461,461 Future income taxes 282,389 782,958 - 20 - Future Net Revenue by Production Group – Forecast Prices and Costs Proved Light and Medium Crude Oil(1) Heavy Oil Natural Gas(2) Proved plus Probable Light and Medium Crude Oil(1) Heavy Oil Natural Gas(2) Future Net Revenue Before Income Taxes and Discounted at 10% ($M) Per Unit Future Net Revenue Before Income Taxes and Discounted at 10%(3) ($BOE) 1,074,632 231,790 17,475 1,653,983 307,510 23,016 29.57 29.99 8.07 27.26 25.52 7.69 Notes: 1. 2. 3. Including solution gas and other by-products. Including by-products, but excluding solution gas from oil wells. Based on net reserves volumes. Pricing Assumptions – Forecast Prices and Costs Both Sproule and McDaniel employed the following pricing and inflation rate assumptions as of December 31, 2014 in their evaluations contained in the Surge Reserves Report in estimating reserves data using forecast prices and costs. The weighted average historical prices received by the Corporation for 2014 are also reflected in the table below. Medium and Light Crude Oil Canadian Light Sweet Crude 40 API ($/bbl) 94.18 70.35 87.36 98.28 99.75 101.25 103.85 105.40 106.99 108.59 110.22 111.87 Western Canada Select 20.5 API ($/bbl) 82.04 60.50 75.13 84.52 85.79 87.07 89.31 90.65 92.01 93.39 94.79 96.21 Natural Gas Alberta AECO Gas Price ($/MMBtu) 4.50 3.32 3.71 3.90 4.47 5.05 5.13 5.22 5.31 5.40 5.49 5.58 Edmonton Pentanes plus ($/bbl) 102.33 78.60 97.60 109.80 111.44 113.12 116.02 117.76 119.53 121.32 123.14 124.99 NGL Edmonton Butane ($/bbl) 68.02 50.34 62.51 70.32 71.37 72.44 74.31 75.42 76.55 77.70 78.87 80.05 Edmonton Propane ($/bbl) 44.42 34.77 43.17 48.57 49.30 50.04 51.32 52.09 52.87 53.67 54.47 55.29 Inflation rates (%/Yr) 1.4 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 Exchange rate ($US/$Cdn) 0.905 0.850 0.870 0.870 0.870 0.870 0.870 0.870 0.870 0.870 0.870 0.870 Year 2014 (Surge Actual) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Escalated thereafter at a rate of +1.5% per annum. - 21 - Reconciliation of Changes in Reserves The following table sets forth a combined reconciliation of the Corporation’s gross reserves as at December 31, 2014, derived from the Surge Reserves Report using forecast prices and cost estimates, reconciled to the gross reserves of the Corporation as at December 31, 2013. Proved Balance at December 31, 2013 Extensions and Improved Recovery Technical Revisions Acquisitions Dispositions Economic Factors Production Balance at December 31, 2014 Probable Balance at December 31, 2013 Extensions and Improved Recovery Technical Revisions Acquisitions Dispositions Economic Factors Production Balance at December 31, 2014 Proved plus Probable Balance at December 31, 2013 Extensions and Improved Recovery Technical Revisions Acquisitions Dispositions Economic Factors Production Balance at December 31, 2014 Light and Medium Crude Oil (Mbbls) Heavy Oil (Mbbls) Natural Gas Liquids (Mbbls) Natural Gas (MMcf) 23,586 2,123 1,997 19,155 (223) (193) (4,419) 42,026 7,227 237 784 1,675 - 5 (1,030) 8,897 2,144 150 (223) 1,497 - (6) (236) 3,325 63,230 4,695 1,205 23,929 - (1,188) (7,230) 84,641 Light and Medium Crude Oil (Mbbls) Heavy Oil (Mbbls) Natural Gas Liquids (Mbbls) Natural Gas (MMcf) 19,575 3,261 (4,202) 10,819 (186) 77 - 29,343 3,298 59 (417) 1,937 - 13 - 4,890 1,218 124 (244) 659 - 4 - 1,762 35,214 3,588 (3,036) 9,487 - 900 - 46,152 Light and Medium Crude Oil (Mbbls) Heavy Oil (Mbbls) Natural Gas Liquids (Mbbls) Natural Gas (MMcf) 43,161 5,384 (2,205) 29,974 (409) (117) (4,426) 71,363 10,525 297 367 3,611 - 18 (1,030) 13,787 3,362 274 (467) 2,156 - (2) (236) 5,088 98,444 8,283 (1,831) 33,416 - (288) (7,230) 130,793 BOE (MBOE) 43,495 3,293 2,758 26,315 (223) (392) (6,891) 68,356 BOE (MBOE) 29,960 4,042 (5,368) 14,996 (186) 244 - 43,687 BOE (MBOE) 73,455 7,335 (2,610) 41,311 (409) (148) (6,897) 112,037 - 22 - Additional Information Relating to Reserves Data Undeveloped Reserves The following table sets forth the volumes of proved undeveloped reserves that were first attributed in each of the four most recent financial years and, in the aggregate, before that time: Proved Prior to 2011 2011 2012 2013 2014 Light and Medium Crude Oil (Mbbls) 1,898.5 3,343.7 2,955.3 6,215.5 4,713.0 Heavy Oil (Mbbls) Natural Gas Liquids (Mbbls) Natural Gas (MMcf) 424.2 302.3 1,191.3 366.1 166.1 302.3 721.5 306.6 574.8 268.3 10,984.9 19,281.0 8,393.0 15,195.3 5,100.0 The following table sets forth the volumes of probable undeveloped reserves that were first attributed in each of the four most recent financial years and, in the aggregate, before that time: Probable Prior to 2011 2011 2012 2013 2014 Light and Medium Crude Oil (Mbbls) 2,244.4 2,269.7 6,703.2 9,567.4 8,526.4 Heavy Oil (Mbbls) 521.8 161.2 457.2 196.5 71.1 Natural Gas Liquids (Mbbls) 311.5 398.0 197.8 350.5 274.0 Natural Gas (MMcf) 13,600.3 11,128.0 5,731.0 9,370.2 5,586.0 Proved undeveloped reserves are generally those reserves related to infill wells that have not yet been drilled or wells further away from gathering systems requiring relatively high capital to bring on production. Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to production. This also includes the probable undeveloped wedge from the proved undeveloped locations. The Corporation currently plans to pursue the development of its proven and probable undeveloped reserves within the next two years through ordinary course capital expenditures. However, the Corporation may choose to delay development depending on a number of circumstances, including the existence of higher priority expenditures and prevailing commodity prices and cash flow. Significant Factors or Uncertainties Affecting Reserves Data The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. As circumstances change and additional data becomes available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions. Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices and reservoir performance. Such revisions can be either positive or negative. - 23 - Future Development Costs The table below sets out the combined total development costs deducted in the estimation in the Surge Reserves Report of future net revenue attributable to proved reserves and proved plus probable reserves (using forecast prices and costs). 2015 2016 2017 2018 Remaining Years Total Undiscounted Forecast Prices and Costs Proved Reserves ($M) Proved plus Probable Reserves ($M) 104,106 154,559 130,038 27,978 156 416,837 131,854 243,307 179,847 98,339 1,236 654,583 The Corporation has four sources of funding available to finance its capital expenditure programs: internally generated cash flow from operations, funds raised from the sale of non-core assets, debt financing when appropriate and new issues of Common Shares, if available on favourable terms. The Corporation expects to fund the above future development costs primarily through internally generated cash flow, funds raised from the sale of non-core assets and debt. There can be no guarantee that the Board of Directors will allocate funding to develop all of the reserves attributed in the Reserve Reports or either of them. Failure to develop those reserves could have a negative impact on the Corporation’s future cash flow. Other Oil and Gas Information Oil and Gas Wells The following table sets forth the number and status of the Corporation's wells effective December 31, 2014. Oil Gross Net 877 0 929 1,806 553 0 558 1,111 Alberta Manitoba Saskatchewan Total Producing Natural Gas Gross Net Water Inj/Disp Net Gross Oil Gross Net Non-Producing Natural Gas Gross Net Water Inj/Disp Net Gross 324 0 70 394 144 0 5 149 230 12 80 322 143 12 47 202 1,267 146 817 2,230 795 122 540 1,457 431 0 27 458 197 0 12 209 129 3 76 208 85 2 51 138 Properties with no Attributed Reserves The following table summarizes, effective December 31, 2014, the gross and net acres of unproved properties in which the Corporation has an interest and also the number of net acres for which the Corporation's rights to explore, develop or exploit will, absent further action, expire within one year. Alberta Manitoba Saskatchewan Total Gross Undeveloped Acres Net Undeveloped Acres Net Undeveloped Acres Expiring within One Year 350,640 63,091 150,896 564,627 325,191 46,531 101,341 473,063 171,468 15,520 27,964 214,952 - 24 - Additional Information Concerning Abandonment and Reclamation Costs The Corporation typically estimates well abandonment costs area by area. Such costs are included in the Surge Reserves Report as deductions in arriving at future net revenue. The expected total abandonment costs included in the Surge Reserves Report for 1,214.8 net wells under the proved reserves category is $75.8 million undiscounted ($20.9 million discounted at 10%), of which a total of $2.9 million is estimated to be incurred in 2015, 2016 and 2017. This estimate does not include expected reclamation costs for surface leases. The Corporation will be liable for its share of ongoing environmental obligations and for the ultimate reclamation of the properties held by it upon abandonment. Ongoing environmental obligations are expected to be funded out of cash flow. Tax Horizon Based on planned capital expenditures and the forecast commodity pricing employed in the Surge Reserves Report, the Corporation estimates that it will not be required to pay current income taxes before 2019. Costs Incurred The following table summarizes capital expenditures incurred by the Corporation during the year ended December 31, 2014. Property Acquisition Costs Proved Properties 630,857 Unproved Properties – Property Dispositions (55,144) Exploration Costs – Development Costs 149,551 Total ($M) Drilling Activity The following table sets forth the gross and net exploration and development wells drilled by the Corporation based on rig release date during the year ended December 31, 2014. Light and Medium Oil Natural Gas Service Dry Total Planned Capital Expenditures Exploration Wells Gross Net – – – – – – – – – – Development Wells Gross 71.00 – – 2.00 73.00 Net 42.50 – – 0.50 43.00 The Corporation has announced a planned capital expenditure budget of approximately $22.3 million for the first half of 2015. Surge has allocated approximately $16.7 million to its 2015 H1 drilling program, $5.6 million to a combination of facilities, plants, land, acquisitions, corporate and capitalized general and administrative expenditures. The Corporation is planning to drill 6 gross (4.4 net) wells in the first half of 2015, targeting high quality light and medium gravity oil, with the majority of the operated activity at Shaunavon. - 25 - Production Estimates The following table discloses for each product type the total volume of production estimated by Sproule and McDaniel in the Surge Reserves Report for 2015 in the estimates of future net revenue from gross proved and gross proved plus probable reserves disclosed above. Light and Medium Oil (bbls/d) Natural Gas (Mcf/d) Natural Gas Liquids (bbls/d) 4,353 3,124 4,044 1,173 4,162 16,855 4,551 3,552 4,289 1,286 4,457 18,135 680 0 2,855 5,973 15,875 25,383 712 0 3,250 6,642 16,309 26,913 58 0 58 342 556 1,013 62 0 61 359 572 1,054 BOE (BOE/d) 4,524 3,124 4,577 2,510 7,363 22,099 4,732 3,552 4,891 2,753 7,748 23,675 % 20% 14% 21% 11% 33% 100% 20% 15% 21% 12% 33% 100% Proved SE Saskatchewan and Manitoba SW Saskatchewan SE Alberta Central Alberta Northern Alberta Total Proved Proved Plus Probable SE Saskatchewan and Manitoba SW Saskatchewan SE Alberta Central Alberta Northern Alberta Total Proved Plus Probable Production History The following table discloses, on a quarterly basis for the year ended December 31, 2014, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the Corporation. Average Daily Production Volume Mar 31, 2014 Jun 30, 2014 Sep 30, 2014 Dec 31, 2014 Three Months Ended Natural Gas (Mcf/d) Light and Medium Crude Oil (bbls/d) NGL (bbls/d) Total (BOE/d) 13,980 12,363 331 15,024 12,893 13,840 406 16,395 18,879 16,401 779 20,327 19,349 16,537 686 20,448 Prices Received, Royalties Paid, Production Costs and Netback – Crude Oil ($ per Bbl) Prices Received Royalties Paid Production Costs Transportation Costs Netback(1) Mar 31, 2014 Jun 30, 2014 Sep 30, 2014 Dec 31, 2014 Three Months Ended 80.75 (14.42) (14.30) (1.89) 50.14 87.27 (14.71) (15.63) (1.49) 55.43 77.81 (13.86) (16.11) (1.80) 46.04 57.90 (11.34) (16.35) (1.58) 28.63 Note: 1. Including solution gas and associated natural gas liquids revenue. - 26 - Prices Received, Royalties Paid, Production Costs and Netback – Natural Gas ($ per Mcf) Prices Received Royalties Paid Production Costs Transportation Costs Netback Mar 31, 2014 Jun 30, 2014 Sep 30, 2014 Dec 31, 2014 Three Months Ended 5.28 (0.05) (2.54) (0.50) 2.18 4.45 (0.17) (2.31) (0.44) 1.52 3.97 (0.02) (1.49) (0.52) 1.94 3.52 (0.02) (3.45) (0.53) (0.48) Prices Received, Royalties Paid, Production Costs and Netback – Combined ($ per BOE) Prices Received Royalties Paid Production Costs Transportation Costs Netback(1) Mar 31, 2014 Jun 30, 2014 Sep 30, 2014 Dec 31, 2014 Three Months Ended 79.55 (14.08) (14.35) (1.92) 49.20 85.89 (14.40) (15.71) (1.71) 54.07 76.85 (13.61) (16.02) (1.82) 45.40 56.49 (11.14) (15.72) (1.49) 28.14 Note: 1. Netback is calculated by deducting royalties paid and production costs, including transportation costs, from prices received, excluding the effects of hedging. Production Volume by Field The following table indicates the average daily net production from the Corporation’s important fields for the year ended December 31, 2014. Field Northern Alberta Central Alberta South East Alberta South West Saskatchewan South East Saskatchewan Total Light and Medium Oil (bbls/d) Natural Gas (Mcf/d) Natural Gas Liquids (bbls/d) 2,917 3,494 916 3,480 3,995 14,802 7,395 2,032 6,689 0 181 16,297 273 37 241 0 1 551 BOE (BOE/d) 4,423 3,870 2,272 3,480 4,025 18,069 % 24% 21% 13% 19% 22% 100% DESCRIPTION OF SHARE CAPITAL The Corporation is authorized to issue an unlimited number of Common Shares and an unlimited number of preferred shares, issuable in series. Common Shares The holders of Common Shares are entitled to: (i) one vote for each Common Share held at all meetings of shareholders of the Corporation other than meetings of the holders of any class or series of shares meeting as a class or series; (ii) receive any dividends declared by the Corporation on the Common Shares; and (iii) subject to the rights of shares ranking prior to the Common Shares, to receive the remaining property of the Corporation on dissolution, after the payment of all liabilities. - 27 - Preferred Shares Preferred shares may be issued in one or more series. The Board of Directors is authorized to fix the number of shares in each series and to determine the designation, rights, privileges, restrictions and conditions attached to the shares of each series. Preferred shares of the Corporation are entitled to a priority over the Common Shares with respect to the payment of dividends and the distribution of assets upon the liquidation, dissolution or winding-up of The Corporation. DIVIDEND POLICY On July 3, 2013, in connection with the Corporation’s transition to a sustainable, moderate growth, dividend paying oil and gas company, the Board adopted a policy of paying monthly dividends, initially at a rate of $0.40 per annum ($0.0333 monthly). On August 7, 2013, the Board approved an increase of the dividend to $0.42 per annum ($0.035 monthly). On October 22, 2013, pursuant to the Saskatchewan and Manitoba acquisitions, the Board approved a further increase of the dividend to $0.50 per annum ($0.04166 monthly). On November 6, 2013, pursuant to the Wainwright Acquisition, the Board approved a further increase of the dividend to $0.52 per annum ($0.04333 monthly). On January 13, 2014, pursuant to the SE Saskatchewan Asset Acquisition, the Board approved a further increase of the dividend to $0.54 per annum ($0.045 monthly). On June 5, 2014, pursuant to the Longview Acquisition, the Board approved a further increase of the dividend to $0.60 per annum ($0.05 monthly). On January 7, 2015, the Board approved a reduction of the dividend to $0.30 per annum ($0.025 monthly) as a result of the precipitous drop in crude oil prices from US$108 WTI per barrel in June 2014 to a low of US$43 WTI in February 2015. The primary objective of the Corporation’s dividend policy is to provide shareholders with relatively stable, predictable and sustainable monthly dividends. The agreement with respect to the Credit Facility contains certain restrictions on Surge’s ability to pay dividends in certain circumstances. In addition, the payment of dividends by a corporation is governed by the liquidity and insolvency tests described in the ABCA. Pursuant to the ABCA, after the payment of a dividend, a corporation must be able to pay its liabilities as they become due and the realizable value of the assets of the corporation must be greater than the liabilities and the legal stated capital of its outstanding securities. The following monthly cash dividends on Common Shares were declared for the periods indicated: Month January February March April May June July August September October November December Total 2013 2015 0.025 0.025 0.025 Dividends per Common Share 2014 $0.04333 $0.04333 $0.045 $0.045 $0.045 $0.05 $0.05 $0.05 $0.05 $0.05 $0.05 $0.05 $0.57166 $0.075 $0.035 $0.035 $0.035 $0.04166 $0.04333 $0.18999 Unless otherwise specified, all dividends paid or to be paid are designated as "eligible dividends" under the Income Tax Act (Canada). There can be no guarantee that the Corporation will maintain its dividend policy. The amount of cash dividends to be paid on the Common Shares, if any, will be subject to the discretion of the Board of Directors and may vary depending on a variety of factors, including the prevailing economic and competitive environment, results of operations, fluctuations in working capital, the price of oil and gas, the taxability of the Corporation, the Corporation’s ability to raise - 28 - capital, the amount of capital expenditures, the satisfaction of solvency tests imposed by the ABCA for the declaration and payment of dividends, applicable law and other factors. See "Risk Factors – Dividends". MARKET FOR SECURITIES The Common Shares are listed and posted for trading on the TSX under the trading symbol “SGY”. The following table sets forth the market price ranges and the trading volumes for the Common Shares for the periods indicated, as reported by the TSX, for the year ended December 31, 2014. Price Range ($) Period 2014 January February March April May June July August September October November December High 6.84 6.34 6.25 7.28 7.29 8.065 8.64 8.82 8.64 7.325 6.56 4.89 Low 6.05 5.51 5.64 5.98 6.60 6.75 7.23 7.91 7.11 5.68 4.90 3.23 Trading Volume 31,973,639 51,502,911 36,882,976 69,139,838 33,007,366 52,681,641 51,655,369 36,809,164 41,031,961 65,500,033 48,477,443 84,138,855 DIRECTORS AND OFFICERS The name, municipality of residence, principal occupation for the prior five years and position with the Corporation of each of the directors and officers of the Corporation are as follows: Name and Residence Position Principal Occupation During Previous Five Years Paul Colborne Calgary, Alberta President and Chief Executive Officer Director since April 13, 2010 President and CEO of the Corporation. He is also the President of StarValley Oil and Gas Ltd., a private, Calgary-based oil and gas company founded in November 2005. Mr. Colborne currently serves on the Board of Directors of Red River Oil Inc., a private oil and gas company. In 1993, after nine years practicing securities, banking and oil and gas law, Mr. Colborne directed his focus to the oil and gas industry and founded an oil and gas company called, Startech Energy Ltd., which grew to a 15,000 BOE/d, publicly traded company. Eight years later in 2001, Startech was acquired by ARC Energy Trust for more than C$500 million. From September 2003 to January 2005, Mr. Colborne was the President and CEO of StarPoint Energy Trust, a 36,000 BOE/d publicly traded energy trust. From 1996 to May of 2013, Mr. Colborne was on the Board of Crescent Point Energy, a 140,000 BOE/d, publicly traded, dividend paying oil and gas company. Until its sale in July of 2009, Mr. Colborne served as Chairman of TriStar Oil & Gas Ltd. He was also a Director for Westfire Energy Ltd., Twin Butte Energy Ltd., Cequence Energy, and Chairman of Seaview Energy Ltd. until its sale in December of 2009, he also served as a Director of Breaker Energy. Mr. Colborne was also Chairman and a Director of Mission Oil and Gas Inc. until its sale in February 2007. In May of 2014, Paul stepped down from the Board of Legacy Oil + Gas. In June of 2014, Paul completed his term as Chairman of New Star Energy, and stepped down as a Director. - 29 - Name and Residence Position Principal Occupation During Previous Five Years P. Daniel O'Neil(3)(4) Calgary, Alberta Director since April 13, 2010 Robert Leach(1)(2) Calgary, Alberta Director since April 13, 2010 Keith Macdonald(1)(3)(4) Calgary, Alberta Director since April 13, 2010 Independent businessperson since his retirement on May 8, 2013. Prior thereto, President and Chief Executive Officer of the Corporation since April 13, 2010. Prior thereto, President and Chief Executive Officer of Breaker Energy Ltd., a publicly traded oil and natural gas company, from its formation in September 2004 until its acquisition by NAL Oil & Gas Trust in December 2009. Mr. O’Neil is also a director of Cathedral Energy Services Ltd. Prior to its sale, Mr. O’Neil was also a director of Hyperion Exploration Corp. Chief Executive Officer of Custom Truck Sales Ltd., a private company operating Kenworth truck dealerships in Saskatchewan and Manitoba, and CEO of International Fitness Holdings, an operating arm of a private equity firm operating health clubs in Alberta. Mr. Leach was formerly the Chairman of the Board of Breaker Energy Inc. President of Bamako Investment Management Ltd., a private holding and financial consulting company. Mr. Macdonald is also a director of Bellatrix Exploration Ltd., a company listed on the TSX. As well, he is a director of Madalena Energy Inc. and Mountainview Energy Ltd., which are listed on the TSX Venture Exchange, and other public and private oil and gas companies. Mr. Macdonald has served as an officer and director of a number of public and private energy companies. James Pasieka Calgary, Alberta Director since April 13, 2010 Chairman of the Board since January 7, 2015 Partner of the national law firm McCarthy Tétrault LLP since September 2013. Prior thereto, partner of the national law firm Heenan Blaikie LLP since 2001. Mr. Pasieka has served as an officer and director of a number of public energy companies, chairman of the board of several oil and gas companies and was formerly Corporate Secretary of Breaker Energy Ltd. Murray Smith(1)(2) Calgary, Alberta Director since June 25, 2010 Colin Davies(3)(4) Calgary, Alberta Director since July 9, 2010 President of Murray Smith and Associates and a director of Critical Control Business Solutions Corp. and Williams Companies Inc. Mr. Smith also serves on the board of two private companies. Prior thereto, Mr. Smith was an Official Representative of the Province of Alberta to the United States of America until 2007. Prior thereto, he was a member of the Legislative Assembly in the Province of Alberta serving in four different Cabinet portfolios – Energy, Gaming, Labour, and Economic Development from 1993 to 2005. President & CEO of Corinthian Oil Corp. since November 2014, and prior thereto, President & CEO of Corinthian Exploration Corp., a private oil and gas company with assets located in the USA and Canada. Prior thereto, Mr. Davies was President & CEO of Corinthian Energy Corp., a private oil and gas company that was founded in 2004 and amalgamated with Surge Energy Inc. in July 2010. Mr. Davies is a professional engineer with over twenty five years of diverse experience in the oil and gas industry. - 30 - Name and Residence Position Principal Occupation During Previous Five Years Daryl Gilbert(2)(3) Calgary, Alberta Director since June 5, 2014 Managing Director and Investment Committee member of JOG Capital Inc. since May 2008. Mr. Gilbert has also been an independent businessman and investor, and serves as a director for a number of public and private entities, since 2005. Mr. Gilbert has been active in the western Canadian oil and natural gas sector for over 40 years, working in reserves evaluation with Gilbert Laustsen Jung Associates Ltd. (now GLJ Petroleum Consultants Ltd.) ("GLJ"), an engineering consulting firm, from 1979 to 2005. Mr. Gilbert served as President and Chief Executive Officer of GLJ from 1994 to 2005. Maxwell Lof Calgary, Alberta Chief Financial Officer Chief Financial Officer of the Corporation. Prior thereto, Chief Financial Officer and Vice-President, Finance of Breaker Energy Ltd. from its formation in September 2004 until its acquisition by NAL Oil & Gas Trust in December 2009. Dan Brown Calgary, Alberta Chief Operating Officer Margaret Elekes Calgary, Alberta Vice-President, Land Murray Bye Calgary, Alberta Vice-President, Production Gerry de Leeuw Calgary, Alberta Vice-President, Geosciences Chief Operating Officer of the Corporation. Prior thereto, Chief Operating Officer of Breaker Energy Ltd. from August 2009 until its acquisition by NAL Oil & Gas Trust in December 2009. Prior thereto, Mr. Brown was the Business Unit Team Lead at a major North American production company. Vice-President, Land of the Corporation. Prior thereto, Consulting Landman for Breaker Energy from its formation in September 2004 until its acquisition by NAL Oil & Gas Trust in December 2009. Prior thereto, US Land Manager for Upton Resources from December 1995 until its acquisition by StarPoint Energy in February 2004. Vice-President, Production of the Corporation since May 8, 2013. Prior thereto, Asset Team Lead - West at Surge since 2010. Prior to his role at Surge, Mr. Bye held a number of positions at EnCana Corporation between the years 2000 to 2010 including: Group Lead of Development, Exploitation Engineer, and Production Engineer. Vice-President, Geosciences of the Corporation. Gerry de Leeuw is a Professional Geologist with over 25 years of experience in the oil and gas industry focused in the Western Canadian Sedimentary basin. Over the past ten years, Gerry has served in a variety of senior executive roles with Devon Canada with his longest and most recent role as V.P. of Exploration and Development. Previous to Devon, he worked at a number of companies including; Northstar, TCPI, Amoco and Texaco where he gained experience through increasingly senior technical and management positions. Notes: 1. 2. 3. 4. Member of the Audit Committee. Member of the compensation, nominating and corporate governance committee of the Board. Member of the reserves committee of the Board. Member of the health, safety and environment committee of the Board. As a group, the directors and executive officers of the Corporation beneficially own, control or direct, directly or indirectly, 6,173,213 Common Shares, representing approximately 2.81 percent of the outstanding Common Shares as at March 19, 2015. - 31 - The terms of office of each of the directors of the Corporation will expire at the next annual general meeting of the shareholders of the Corporation. Cease Trade Orders, Bankruptcies, Penalties or Sanctions Other than as set forth below, to the knowledge of management of the Corporation: a) b) c) no director or executive officer of the Corporation is, or within the 10 years before the date of this AIF, has been, a director, chief executive officer or chief financial officer of any other issuer that: (i) was the subject of a cease trade or similar order or an order that denied the other issuer access to any exemptions under Canadian securities legislation that lasted for a period of more than 30 consecutive days that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or (ii) was subject to a cease trade or similar order or an order that denied the relevant issuer access to any exemption under securities legislation that lasted for a period of more than 30 consecutive days that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while the person was acting in the capacity as director, chief executive officer or chief financial officer; no director or executive officer, or any shareholder holding a sufficient number of securities of the Corporation to affect materially the control of the Corporation, or a personal holding company of any such person: (i) is, at the date of this AIF or has been within the 10 years before the date of this AIF, a director or executive officer of any company that, while that person was acting in that capacity or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or (ii) has, within the 10 years before the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or was subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, officer or shareholder; and no director or executive officer, or any shareholder holding a sufficient number of securities of the Corporation to affect materially the control of the Corporation, has: (i) been subject to any penalties or sanctions imposed by a court relating to Canadian securities legislation or by a Canadian securities regulatory authority or has entered into a settlement agreement with the Canadian securities regulatory authority; or (ii) been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision. Mr. Gilbert was a director of Globel Direct Inc ("Globel Direct") which sought and received protection under the Companies' Creditors Arrangement Act (Canada) in June 2007, and after a failed restructuring effort, a receiver was appointed by one of Globel Direct's lenders in December 2007. Cease trade orders dated September 24, 2008 and September 30, 2008 were issued by the Alberta Securities Commission and the British Columbia Securities Commission, respectively, for failure to file financial statements. The cease trade orders were issued following the appointment of the receiver and, as at the date hereof, have not been revoked. Conflicts of Interest The directors and officers of the Corporation may participate in activities and investments in the oil and gas industry outside the scope of their engagement or employment as directors or officers of the Corporation. As a result, the directors and officers may become subject to conflicts of interest. The ABCA provides that, in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA, the written mandate of the Board of Directors and the Corporation’s corporate governance policies. As at the date hereof, the Corporation is not aware of any existing or potential material conflicts of interest between the Corporation and a director or officer of the Corporation. - 32 - Composition of the Audit Committee, Charter and Review of Services AUDIT COMMITTEE The Audit Committee of the Board of Directors operates under a written charter that sets out its responsibilities and composition requirements. A copy of the charter is attached to this AIF as Schedule “C”. The members of the Audit Committee of the Board of Directors are Keith Macdonald (Chair), Murray Smith and Robert Leach. The Audit Committee charter requires all members of the Audit Committee to be “financially literate” and “independent” within the meaning of applicable securities laws. All members of the Audit Committee meet these requirements. The relevant education and experience of each Audit Committee member is outlined below: Name Independent Financially Literate Relevant Education and Experience Keith Macdonald   Murray Smith   Mr. Macdonald is currently the President of Bamako Investment Management Ltd., a private holding and financial consulting company. Mr. Macdonald is a director of Bellatrix Exploration Ltd., Madalena Energy Inc., and Mountainview Energy Ltd. He has served as chair and/or a member of the audit committee of each of those companies, as well as several other public oil and gas companies for which he has been a director. Mr. Macdonald was also formerly a director of Breaker Energy Ltd. prior to its sale in 2009. From 1994 to January 1999, Mr. Macdonald was vice president of finance and a director of New Cache Petroleum Ltd. Mr. Macdonald founded New Cache Petroleum Ltd. in 1988 and was its president until a merger in 1994. Mr. Macdonald holds the Chartered Accountants designation, achieved in 1980, and a Bachelor of Commerce degree (Accounting and Finance Major) from University of Calgary in 1978. President of Murray Smith and Associates and a director of Critical Control Business Solutions Corp. and Williams Companies Inc. Mr. Smith also serves on the board of two private companies. Prior thereto, Mr. Smith was an Official Representative of the Province of Alberta to the United States of America until 2007. Prior thereto, he was a member of the Legislative Assembly in the Province of Alberta serving in four different Cabinet portfolios – Energy, Gaming, Labour, and Economic Development from 1993 to 2005. From 1998-2004 Mr. Smith was a member of the Government of Alberta Treasury Board (responsible for the annual budget for Alberta) and a contributing member to Alberta’s debt elimination in 2004. Mr. Smith has a degree in Economics from the University of Calgary (1971) and is a graduate of the London Business School Senior Executive Program (2000). - 33 - Name Independent Financially Literate Relevant Education and Experience Robert Leach   Mr. Leach is currently the Chief Executive Officer of Custom Truck Sales Ltd., a private company operating Kenworth truck dealerships in Saskatchewan and Manitoba, and CEO of International Fitness Holdings, an operating arm of a private equity firm operating health clubs in Alberta. Mr. Leach was formerly the Chairman of the Board of Breaker Energy Inc. Mr. Leach has experience reviewing and assessing financial statements from his tenure on the audit committee of Breaker, as a member of the Board of Surge, and through his years of experience at Custom Truck Sales Ltd. and International Fitness Holdings. Mr. Leach holds a Bachelor of Commerce from the College of Commerce at the University of Saskatchewan where he majored in Accounting (1982). Mr. Leach articled with KPMG LLP and left to start a private business in 1983. Pre-Approval of Policies and Procedures The Audit Committee charter requires that any non-audit services by the Corporation’s auditors must be pre-approved by the Audit Committee. The Audit Committee has passed a resolution providing the Chairman of the Audit Committee with delegated authority to approve the provision of non-audit services by the Corporation’s auditors from time to time, provided that: (i) such services are provided pursuant to a written engagement letter setting out the services to be provided and the applicable fees; (ii) the provision of such services is otherwise in compliance with the Audit Committee’s charter; (iii) such services could not be reasonably seen to result in the auditors performing any management function, auditing their own work or serving in an advocacy role on behalf of the Corporation; (iv) the fees for such services do not exceed $50,000 per engagement; and (v) the Chairman reports to the Committee at the next regularly scheduled meeting any approval of non-audit services made pursuant to the authority delegated under the resolution. The Audit Committee also pre-approves all audit services and the fees to be paid. External Auditor Service Fees KPMG LLP are the auditors of the Corporation. KPMG LLP have been the auditors of the Corporation since May 5, 2010. The following table sets out the aggregate fees billed by KPMG LLP to the Corporation in each of the last two fiscal years. Year 2014 2013 Notes: 1. 2. Audit Fees(1) Audit-Related Fees Tax Fees(2) All Other Fees $391,000 $371,500 $61,000 $42,000 $178,450 $260,384 $0 $0 Audit fees consist of fees for the audit of annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements. During fiscal ended December 31, 2013 and 2014, the services provided in this category included quarterly review fees. Fees for tax compliance, tax advice and tax planning. Restrained Pipeline Capacity and Differential Volatility INDUSTRY CONDITIONS Western Canada has seen significant growth in crude production volumes over recent years. This has resulted in pressure on the pipeline take-away capacity, leading to apportionment on the main lines and, in turn, backed-up local feeder - 34 - pipelines. This has contributed to a widening of, and increased volatility in, the light oil pricing differential between WTI and Edmonton Par and the medium/heavy oil pricing differential between WTI and Cromer/WCS/Hardisty. Although pipeline expansions are ongoing and producers are increasingly turning to rail as an alternative means of transportation, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to market production. In addition, the pro-rationing of capacity on the interprovincial pipeline systems also continues to affect the ability to export oil and natural gas. Legislation and Regulation The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, Saskatchewan and Manitoba, all of which should be carefully considered by investors in the oil and natural gas industry. It is not expected that any of these controls or regulations will affect the operations of Surge in a manner materially different than they would affect other oil and natural gas producers of similar size. All current legislation is a matter of public record and Surge is unable to predict what additional legislation or amendments may be enacted. Some of the principal aspects of legislation, regulations and agreements governing the oil and natural gas industry are described further below. Pricing and Marketing – Oil The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance, and contractual terms of sale. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such a licence requires a public hearing and the approval of the Governor in Council. The NEB is currently undergoing a consultation process to update the regulations governing the issuance of export licences. The updating process is necessary to meet the criteria set out in the federal Jobs, Growth and Long-term Prosperity Act which received Royal Assent on June 29, 2012 (the "Prosperity Act"). In this transitory period, the NEB has issued, and is currently following an "Interim Memorandum of Guidance concerning Oil and Gas Export Applications and Gas Import Applications under Part VI of the National Energy Board Act". Pricing and Marketing – Natural Gas Alberta's natural gas market has been deregulated since 1985. Supply and demand determine the price of natural gas and price is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system such as the Alberta "NIT" (Nova Inventory Transfer), at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer's own arrangements (whether long or short term contracts and the specific point of sale). As natural gas is also traded on trading platforms such as the Natural Gas Exchange (NGX), Intercontinental Exchange or the New York Mercantile Exchange (NYMEX) in the United States, spot and future prices can also be influenced by supply and demand fundamentals on these platforms. The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such a licence requires a public hearing and the approval of the Governor in Council. - 35 - The governments of Saskatchewan and Alberta also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations. The North American Free Trade Agreement The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico came into force on January 1, 1994. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36 month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply. All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited. The signatory countries are also prohibited from imposing a minimum or maximum import price requirement except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports. NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. Provincial Royalties and Incentives General In addition to federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas, natural gas liquids and sulphur production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Operations not on Crown lands and subject to the provisions of specific agreements are also usually subject to royalties negotiated between the mineral owner and the lessee. These royalties are not eligible for incentive programs sponsored by various governments as discussed below. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are from time to time carved out of the working interest owner's interest through non- public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests. From time to time the governments of the western Canadian provinces have established incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Alberta Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced. Royalties are currently paid pursuant to "The New Royalty Framework" (implemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008) and the "Alberta Royalty Framework", which was implemented in 2010. Royalty rates for conventional oil are set by a single sliding rate formula that is applied monthly and incorporates separate variables to account for production rates and market prices. The maximum royalty payable under the royalty regime is 40 - 36 - percent. Royalty rates for natural gas under the royalty regime are similarly determined using a single sliding rate formula, with the maximum royalty payable under the royalty regime set at 36 percent. Producers of oil and natural gas from freehold lands in Alberta are required to pay annual freehold mineral tax. The freehold mineral tax is a tax levied by the Government of Alberta on the value of oil and natural gas production from non- Crown lands and is derived from the Freehold Mineral Rights Tax Act (Alberta). The freehold mineral tax is levied on an annual basis on calendar year production using a tax formula that takes into consideration, among other things, the amount of production, the hours of production, the value of each unit of production, the tax rate and the percentages that the owners hold in the title. The basic formula for the assessment of freehold mineral tax is: revenue less allocable costs equals net revenue divided by wellhead production equals the value based upon unit of production. If payors do not wish to file individual unit values, a default price is supplied by the Crown. On average, the tax levied is four percent of revenues reported from fee simple mineral title properties. The Government of Alberta has from time to time implemented drilling credits, incentives or transitional royalty programs to encourage oil and gas development and new drilling. For example, the Innovative Energy Technologies Program (the "IETP") has the stated objectives of increasing recovery from oil and gas deposits, finding technical solutions to the gas over bitumen issue, improving the recovery of bitumen by in-situ and mining techniques, and improving the recovery of natural gas from coal seams. The IETP provides royalty adjustments to specific pilot and demonstration projects that utilize new or innovative technologies to increase recovery from existing reserves. In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources (the "Emerging Resource and Technologies Initiative"). One such initiative was the New Well Royalty Rate, pursuant to which: • • • • coalbed methane wells will receive a maximum royalty rate of 5 percent for 36 producing months on up to 750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010; shale gas wells will receive a maximum royalty rate of 5 percent for 36 producing months with no limitation on production volume, retroactive to wells that began producing on or after May 1, 2010; horizontal gas wells will receive a maximum royalty rate of 5 percent for 18 producing months on up to 500 MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010; and horizontal oil wells and horizontal non-project oil sands wells will receive a maximum royalty rate of 5 percent with volume and production month limits set according to the depth (including the horizontal distance) of the well, retroactive to wells that commenced drilling on or after May 1, 2010. On July 24, 2014 the Government of Alberta introduced the Enhanced Oil Recovery Program, to be effective as of January 1, 2014. This program encourages the injection of fluids such as hydrocarbons, carbon dioxide, nitrogen, chemicals and other approved substances for the recovery of additional oil. The Government of Alberta shares in the cost to develop the resource by reducing the amount of the royalty due on crude oil (subject to certain approvals and restrictions). Saskatchewan In Saskatchewan, the amount payable as a Crown royalty or a freehold production tax in respect of oil depends on the type and vintage of oil, the quantity of oil produced in a month, the value of the oil produced and specified adjustment factors determined monthly by the provincial government. For Crown royalty and freehold production tax purposes, conventional oil is divided into "types", being "heavy oil", "southwest designated oil" or "non-heavy oil other than southwest designated oil". The conventional royalty and production tax classifications ("fourth tier oil", "third tier oil", "new oil" and "old oil") depend on the finished drilling date of a well and are applied to each of the three crude oil types slightly differently. Heavy oil is classified as third tier oil (produced from a vertical well having a finished drilling date on or after January 1, 1994 and before October 1, 2002 or incremental oil from new or expanded water flood projects with a commencement date on or after January 1, 1994 and before October 1, 2002), fourth tier oil (having a finished drilling date on or after October 1, 2002 or incremental oil from new or expanded water flood projects with a commencement date on or after October 1, 2002) or new oil (conventional oil that is not classified as "third tier oil" or "fourth tier oil"). Southwest designated oil uses the same definition of fourth tier oil but third tier oil is defined as conventional oil produced from a vertical well having a finished - 37 - drilling date on or after February 9, 1998 and before October 1, 2002 or incremental oil from new or expanded water flood projects with a commencement date on or after February 9, 1998 and before October 1, 2002, and new oil is defined as conventional oil produced from a horizontal well having a finished drilling date on or after February 9, 1998 and before October 1, 2002. For non-heavy oil other than southwest designated oil, the same classification as heavy oil is used but new oil is defined as conventional oil produced from a vertical well completed after 1973 and having a finished drilling date prior to 1994, conventional oil produced from a horizontal well having a finished drilling date on or after April 1, 1991 and before October 1, 2002, or incremental oil from new or expanded water flood projects with a commencement date on or after January 1, 1974 and before 1994 whereas old oil is defined as conventional oil not classified as third or fourth tier oil or new oil. Production tax rates for freehold production are determined by first determining the Crown royalty rate and then subtracting the "Production Tax Factor" ("PTF") applicable to that classification of oil. Currently the PTF is 6.9 for "old oil", 10.0 for "new oil" and "third tier oil" and 12.5 for "fourth tier oil". The minimum rate for freehold production tax is zero. Base prices are used to establish lower limits in the price-sensitive royalty structure for conventional oil and apply at a reference well production rate of 100 m3 for old oil, new oil and third tier oil, and 250 m3 per month for fourth tier oil. Where average wellhead prices are below the established base prices of $100 per m3 for third and fourth tier oil and $50 per m3 for new oil and old oil, base royalty rates are applied. Base royalty rates are 5 percent for all fourth tier oil, 10 percent for heavy oil that is third tier oil or new oil, 12.5 percent for southwest designated oil that is third tier oil or new oil, 15 percent for non-heavy oil other than southwest designated oil that is third tier or new oil, and 20 percent for old oil. Where average wellhead prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base oil price. Marginal royalty rates are 30 percent for all fourth tier oil, 25 percent for heavy oil that is third tier oil or new oil, 35 percent for southwest designated oil that is third tier oil or new oil, 35 percent for non-heavy oil other than southwest designated oil that is third tier or new oil, and 45 percent for old oil. The amount payable as a Crown royalty or a freehold production tax in respect of natural gas production is determined by a sliding scale based on the monthly provincial average gas price published by the Saskatchewan government (effective February 1, 2012), the quantity produced in a given month, the type of natural gas, and the classification of the natural gas. Like conventional oil, natural gas may be classified as "non-associated gas" (gas produced from gas wells) or "associated gas" (gas produced from oil wells) and royalty rates are determined according to the finished drilling date of the respective well. Non-associated gas is classified as new gas (having a finished drilling date before February 9, 1998 with a first production date on or after October 1, 1976), third tier gas (having a finished drilling date on or after February 9, 1998 and before October 1, 2002), fourth tier gas (having a finished drilling date on or after October 1, 2002) and old gas (not classified as either third tier, fourth tier or new gas). A similar classification is used for associated gas except that the classification of old gas is not used, the definition of fourth tier gas also includes production from oil wells with a finished drilling date prior to October 1, 2002, where the individual oil well has a gas-oil production ratio in any month of at least 3,500 m3 of gas for every m3 of oil, and new gas is defined as oil produced from a well with a finished drilling date before February 9, 1998 that received special approval, prior to October 1, 2002, to produce oil and gas concurrently without gas- oil ratio penalties. On December 9, 2010, the Government of Saskatchewan enacted the Freehold Oil and Gas Production Tax Act, 2010 with the intention to facilitate the efficient payment of freehold production taxes by industry. Two new regulations with respect to this legislation are: (i) The Freehold Oil and Gas Production Tax Regulations, 2012 which sets out the terms and conditions under which the taxes are calculated and paid; and (ii) The Recovered Crude Oil Tax Regulations, 2012 which sets out the terms and conditions under which taxes on recovered crude oil that was delivered from a crude oil recovery facility on or after March 1, 2012 are to be calculated and paid. As with conventional oil production, base prices based on a well reference rate of 250 103 m3 per month are used to establish lower limits in the price-sensitive royalty structure for natural gas. Where average field-gate prices are below the established base prices of $1.35 per gigajoule for third and fourth tier gas and $0.95 per gigajoule for new gas and old gas, base royalty rates are applied. Base royalty rates are 5 percent for all fourth tier gas, 15 percent for third tier or new gas, and 20 percent for old gas. Where average well-head prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base gas price. Marginal royalty rates are 30 percent for all fourth tier gas, 35 percent for third tier and new gas, and 45 percent for old gas. The current regulatory scheme provides for certain differences with respect to the administration of fourth tier gas which is associated gas. - 38 - The Government of Saskatchewan currently provides a number of targeted incentive programs. These include both royalty reduction and incentive volume programs, including the following: • Royalty/Tax Incentive Volumes for Vertical Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty (a Crown royalty rate of the lesser of "fourth tier oil" Crown royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of 0 percent) on incentive volumes of 8,000 m3 for deep development vertical oil wells, 4,000 m3 for non-deep exploratory vertical oil wells and 16,000 m3 for deep exploratory vertical oil wells (more than 1,700 metres or within certain formations) and after the incentive volume is produced, the oil produced will be subject to the "fourth tier" royalty tax rate; • Royalty/Tax Incentive Volumes for Exploratory Gas Wells Drilled on or after October 1, 2002 providing reduced Crown royalty (a Crown royalty rate of the lesser of "fourth tier oil" Crown royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of 0 percent) on incentive volumes of 25,000,000 m3 for qualifying exploratory gas wells; • Royalty/Tax Incentive Volumes for Horizontal Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty (a Crown royalty rate of the lesser of "fourth tier oil" Crown royalty rate and 2.5 percent) and freehold tax rates on incentive volumes of 6,000 m3 for non-deep horizontal oil wells and 16,000 m3 for deep horizontal oil wells (more than 1,700 metres total vertical depth or within certain formations) and after the incentive volume is produced, the oil produced will be subject to the "fourth tier" royalty tax rate; • Royalty/Tax Incentive Volumes for Horizontal Gas Wells drilled on or after June 1, 2010 and before April 1, 2013 providing for a classification of the well as a qualifying exploratory gas well and resulting in a reduced Crown royalty (a Crown royalty rate of the lesser of "fourth tier oil" Crown royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of 0 percent) on incentive volumes of 25,000,000 m3 for horizontal gas wells and after the incentive volume is produced, the gas produced will be subject to the "fourth tier" royalty tax rate; • Royalty/Tax Regime for Incremental Oil Produced from New or Expanded Waterflood Projects Implemented on or after October 1, 2002 whereby incremental production from approved water flood projects is treated as fourth tier oil for the purposes of Crown royalty and freehold tax calculations; • Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing prior to April 1, 2005 providing lower Crown royalty and freehold tax determinations based in part on the profitability of EOR projects during and subsequent to the payout of the EOR operations; • Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing on or after April 1, 2005 providing a Crown royalty of 1 percent of gross revenues on EOR projects pre-payout and 20 percent of EOR operating income post-payout and a freehold production tax of 0 percent pre-payout and 8 percent post- payout on operating income from EOR projects; and • Royalty/Tax Regime for High Water-Cut Oil Wells designed to extend the product lives and improve the recovery rates of high water-cut oil wells and granting "third tier oil" royalty/tax rates with a Saskatchewan Resource Credit of 2.5 percent for oil produced prior to April 2013 and 2.25 percent for oil produced on or after April 1, 2013 to incremental high water-cut oil production resulting from qualifying investments made to rejuvenate eligible oil wells and/or associated facilities. On June 22, 2011, the Government of Saskatchewan released the Upstream Petroleum Industry Associated Gas Conservation Standards, which are designed to reduce emissions resulting from the flaring and venting of associated gas (the "Associated Natural Gas Standards"). The Associated Natural Gas Standards were jointly developed with industry and the implementation of such standards commenced on July 1, 2012 for new wells and facilities licensed on or after such date. The new standards will apply to existing licensed wells and facilities on July 1, 2015. Effective April 1, 2014, the Saskatchewan Ministry of the Economy streamlined fees related to licenses and applications in the oil and gas sector by eliminating 10 different licensing fees, which resulted in an aggregate of 20,000 fee transactions per year, and replacing them with a single annual levy based on a company's production and number of wells. While the - 39 - fees have been streamlined, approvals to conduct the relevant activities are still required. These changes to the fee structure are part of ongoing work by the Government of Saskatchewan to streamline the licensing, regulation and monitoring processes in the oil and gas sector. The majority of Surge's production in Saskatchewan is "non-heavy oil other than southwest designated oil" with a vintage classification of "fourth tier oil". Saskatchewan royalty payable on this production is 2.5% until 6,000 m3 (37,740 barrels) of oil have been produced. Production in excess of this threshold is subject to a royalty rate based on well productivity and oil prices, with a base royalty rate of 5%, which represents the minimum royalty rate, and a maximum marginal royalty rate of 30%. Manitoba In Manitoba, the royalty amount payable on oil produced from Crown lands depends on the classification of the oil produced as "old oil" (produced from a well drilled prior to April 1, 1974 that does not qualify as new oil or third tier oil), "new oil" (oil that is not third tier oil and is produced from a well drilled on or after April 1, 1974 and prior to April 1, 1999, from an abandoned well re-entered during that period, from an old oil well as a result of an enhanced recovery project implemented during that period, or from a horizontal well), "third tier oil" (oil produced from a vertical well drilled after April 1, 1999, an abandoned well re-entered after that date, an inactive vertical well activated after that date, a marginal well that has undergone a major workover, or from an old oil well or a new oil well as a result of an enhanced recovery project implemented after that date), or "holiday oil" (oil that is exempt from any royalty or tax payable). Royalty rates are calculated on a sliding scale and based on the monthly oil production from a spacing unit, or oil production allocated to a unit tract under a unit agreement or unit order from the Minister. For horizontal wells, the royalty on oil produced from Crown lands is calculated based on the amount of oil production allocated to a spacing unit in accordance with the applicable regulations. Royalties payable on natural gas production from Crown lands are equal to 12.5 percent of the volume of natural gas sold. Producers of oil and natural gas from freehold lands in Manitoba are required to pay monthly freehold production taxes. The freehold production tax payable on oil is calculated on a sliding scale based on the monthly production volume and the classification of oil as old oil, new oil, third tier oil and holiday oil. Producers of natural gas from freehold lands in Manitoba are required to pay a monthly freehold production tax equal to 1.2 percent of the volume sold. There is no freehold production tax payable on gas consumed as lease fuel. The Government of Manitoba maintains a Drilling Incentive Program (the "Program") with the intent of promoting investment in the sustainable development of petroleum resources. The Program provides the licensee of newly drilled wells, or qualifying wells where a major workover has been completed, with a "holiday oil volume" pursuant to which no Crown royalties or freehold production taxes are payable until the holiday oil volume has been produced. Under the Program, wells drilled for purposes of injection (or wells converted to injection prior to producing predetermined volumes of oil) in an approved enhanced oil recovery project earn a one-year holiday for portions of the project area. The Program consists of the following components: • Vertical Well Incentive provides licensees of a vertical development or exploratory well drilled after December 31, 2013 and prior to January 1, 2019 with a holiday oil volume (a "HOV") of 500 m3. To qualify, the well must be less than 1.6 kilometres from the nearest well cased for production from the same or deeper zone; • Exploration and Deep Well Incentive provides a HOV for exploratory or deep oil development wells drilled after December 31, 2013 and prior to January 1, 2019 as follows: o Non-deep exploratory wells drilled more than 1.6 kilometres from the nearest well cased for production from the same or deeper zone earn a HOV of 4,000 m3; o Deep exploratory wells drilled below the Birdbear formation earn a HOV of 8,000 m3; and o Deep development wells completed for production in the Birdbear formation or deeper earn a HOV of 8,000 m3; - 40 - • Horizontal Well Incentive provides a HOV of 8,000 m3 for any horizontal well drilled after December 31, 2013 and prior to January 1, 2019 achieving an angle of at least 80 degrees for a minimum distance of 100 metres; • Marginal Well Major Workover Incentive provides a HOV of 500 m3 for any marginal well where a major workover is completed prior to January 1, 2019. A marginal oil well is a well or abandoned well that was not operated over the previous 12 months or that produced at an average rate of less than 3 m3 per operating day; • • Pressure Maintenance Project Incentive provides a one-year exemption from the payment of Crown royalties or freehold production taxes for a unit tract in which an injection well is drilled or a well is converted to water injection. For a well that is converted to injection after December 31, 2013 and before January 21, 2019 and that has a remaining HOV, the exemption will be extended to 18 months; and Solution Gas Conservation Incentive provides a royalty and tax exemption on gas until December 31, 2018 for projects that capture solution gas implemented after December 31, 2013. The Holiday Oil Volume Account, which allowed the movement of HOV to and from wells under specific conditions, will be eliminated as of January 1, 2015. Until December 31, 2014, the holder of an existing account may make a one-time transfer of 2,000 m3 to a well drilled between January 1 and December 31, 2014. Climate Change Regulation Federal The Government of Canada is a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") and a participant to the Copenhagen Accord (a non-binding agreement created by the UNFCCC which represents a broad political consensus and reinforces commitments to reducing greenhouse gas ("GHG") emissions). On January 29, 2010, Canada inscribed in the Copenhagen Accord its 2020 economy-wide target of a 17 percent reduction of GHG emissions from 2005 levels. This target is aligned with the United States target. In a report dated October 2013, the Government stated that this target represents a significant challenge in light of strong economic growth (Canada's economy is projected to be approximately 31 percent larger in 2020 compared to 2005 levels). On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both GHGs and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). The Updated Action Plan outlines emissions intensity-based targets for application to regulated sectors on a facility-specific basis, sector-wide basis or company-by-company basis. Although the intention was for draft regulations aimed at implementing the Updated Action Plan to become binding on January 1, 2010, the only regulations being implemented are in the transportation and electricity sectors. The federal government indicates that it is taking a sector-by-sector regulatory approach to reducing GHG emissions and is working on regulations for other sectors. Representatives of the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to GHG emissions regulation. In June 2012, the second US-Canada Clean Energy Dialogue Action Plan was released. The plan renewed efforts to enhance bilateral collaboration on the development of clean energy technologies to reduce GHG emissions. It is expected that any regulations eventually implemented by the Government of Canada will have an impact of the oil and gas industry as a whole, which could result in increased costs for Surge to comply with such legislation. In the meantime, Surge will continue to monitor the policies of the Government of Canada and any resulting legislation with respect to GHG emissions. The US Environmental Protection Agency (“EPA”) is proceeding to regulate greenhouse gases under the Clean Air Act. This EPA action is subject to legal and political challenges, the outcome of which cannot be predicted. The ultimate form of Canadian regulation is anticipated to be strongly influenced by the regulatory decisions made within the United States. Various states have enacted or are evaluating low carbon fuel standards, which may affect access to market for crude oils with higher emissions intensity. Alberta - 41 - As part of its efforts to reduce GHG emissions, Alberta introduced legislation to address GHG emissions: the Climate Change and Emissions Management Act (the "CCEMA") enacted on December 4, 2003 and amended through the Climate Change and Emissions Management Amendment Act, which received royal assent on November 4, 2008. The CCEMA is based on an emissions intensity approach and aims for a 50 percent reduction from 1990 emissions relative to GDP by 2020. The accompanying regulations include the Specified Gas Emitters Regulation ("SGER"), which imposes GHG limits, and the Specified Gas Reporting Regulation, which imposes GHG emissions reporting requirements. Alberta facilities emitting more than 100,000 tonnes of GHGs a year are subject to compliance with the CCEMA. Alberta is the first jurisdiction in North America to impose regulations requiring large facilities in various sectors to reduce their GHG emissions. At this point Surge does not own or anticipate owning or operating any facilities which emit more than 100,000 tonnes of GHGs per year. On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010. It deemed the pore space underlying all land in Alberta to be, and to have always been, the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions. Saskatchewan On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act (the "MRGGA") to regulate GHG emissions in the province. The MRGGA has received royal assent but has not yet been proclaimed and so is not yet in force. It remains unclear to what degree a scheme implemented under the MRGGA will affect Surge. Manitoba The Government of Manitoba has commenced public consultations with respect to the development of a cap and trade system to reduce greenhouse gas emissions. The enactment of The Climate Change and Emissions Reductions Act (Manitoba) sets emission reduction targets as of December 31, 2012 at 6% below 1990 emissions and details the commitment of the Government of Manitoba to various initiatives in an effort to reduce greenhouse gas emissions, but no legislation has been effected which imposes mandatory emission reduction targets on emitters. Land Tenure Crude oil and natural gas located in the western Canadian provinces is owned both by the respective provincial governments and by private individuals. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits for varying periods and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. Where oil and natural gas is privately owned, rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated. The respective provincial governments predominantly own the rights to crude oil and natural gas located in the western provinces, with the exception of Manitoba where private ownership accounts for approximately 80 percent of the crude oil and natural gas rights in the southwestern portion of the province. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated. Each of the provinces of Alberta, Saskatchewan and Manitoba has implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or license. Alberta also has a policy of "shallow rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licenses. For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term of the lease or license. Holders of leases or licences that have been continued indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implemented three years from the date of the notice. In 2013, Alberta Energy placed an indefinite hold on serving shallow rights reversion notices for leases and licences that were granted prior - 42 - to January 1, 2009. Alberta Energy stated that it will provide the industry with notice if, in the future, a decision is made to serve shallow rights reversion notices. Environmental Regulation The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation, all of which is subject to governmental review and revision from time to time. Such legislation provides for restrictions and prohibitions on the release or emitting of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such legislation sets out the requirements for the satisfactory abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties. Federal Pursuant to the Prosperity Act, the Government of Canada amended or repealed several pieces of federal environmental legislation and in addition, created a new federal environment assessment regime that came in to force on July 6, 2012. The changes to the environmental legislation under the Act are intended to provide for more efficient and timely environmental assessments of projects that previously had been subject to overlapping legislative jurisdiction. Alberta The regulatory landscape in Alberta has undergone a transformation from multiple regulatory bodies to a single regulator for upstream oil and gas, oil sands and coal development activity. On June 17, 2013, the Alberta Energy Regulator (the "AER") assumed the functions and responsibilities of the former Energy Resources Conservation Board, including those found under the Oil and Gas Conservation Act the ("ABOGCA"). On November 30, 2013, the AER assumed the energy related functions and responsibilities of Alberta Environment and Sustainable Resource Development ("AESRD") in respect of the disposition and management of public lands under the Public Lands Act. On March 29, 2014, the AER assumed the energy related functions and responsibilities of AESRD in the areas of environment and water under the Environmental Protection and Enhancement Act and the Water Act, respectively. The AER's responsibilities exclude the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as Alberta Energy's responsibility for mineral tenure. The objective behind the transformation to a single regulator is the creation of an enhanced regulatory regime that is efficient, attractive to business and investors, and effective in supporting public safety, environmental management and resource conservation while respecting the rights of landowners. In December 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the "ALUF"). The ALUF sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans. The Alberta Land Stewardship Act (the "ALSA") provides the legislative authority for the Government of Alberta to implement the policies contained in the ALUF. Regional plans established under the ALSA are deemed to be legislative instruments equivalent to regulations and will be binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry. In the event of a conflict or inconsistency between a regional plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, licenses, registrations, approvals and authorizations for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan. Among the measures to support the goals of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection, conservation and enhancement of land, and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment. - 43 - On August 22, 2012, the Government of Alberta approved the Lower Athabasca Regional Plan ("LARP") which came into force on September 1, 2012. The LARP is the first of seven regional plans developed under the ALUF. LARP covers a region in the northeastern corner of Alberta that is approximately 93,212 square kilometres in size. The region includes a substantial portion of the Athabasca oilsands area, which contains approximately 82 percent of the province's oilsands resources and much of the Cold Lake oilsands area. LARP establishes six new conservation areas and nine new provincial recreation areas. In conservation and provincial recreation areas, conventional oil and gas companies with pre-existing tenure may continue to operate. Any new petroleum and gas tenure issued in conservation and provincial recreation areas will include a restriction that prohibits surface access. The South Saskatchewan Regional Plan (“SSRP”) was approved by the Government of Alberta on July 23, 2014 and became effective on September 1, 2014. The SSRP is the second regional plan developed under the ALUF and covers approximately 83,764 square kilometres and includes 44 percent of the province’s population. The SSRP creates four new and four expanded conservation areas, and two new and six expanded provincial parks and recreational areas. Similar to LARP, the SSRP will honour existing petroleum and natural gas tenure in conservation and provincial recreational areas. However, oil and gas companies must nonetheless minimize impacts of activities on the natural landscape, historic resources, wildlife, fish and vegetation when exploring, developing and extracting the resources. Any new petroleum and natural gas tenures sold in conservation areas, provincial parks, and recreational areas will prohibit surface access. Freehold mineral rights will not be subject to this restriction. With the implementation of the new Alberta regulatory structure under the AER, AESRD will remain responsible for development and implementation of regional plans. However, the AER will take on some responsibility for implementing regional plans in respect of energy related activities. Saskatchewan In May 2011, Saskatchewan passed changes to The Oil and Gas Conservation Act ("SKOGCA"), the act governing the regulation of resource development operations in the province. Although the associated Bill received Royal Assent on May 18, 2011, it was not proclaimed into force until April 1, 2012, in conjunction with the release of The Oil and Gas Conservation Regulations, 2012 ("OGCR") and The Petroleum Registry and Electronic Documents Regulations ("Registry Regulations"). The aim of the amendments to the SKOGCA, and the associated regulations, is to provide resource companies investing in Saskatchewan's energy and resource industries with the best support services and business and regulatory systems available. With the enactment of the Registry Regulations and the OGCR, Saskatchewan has implemented a number of operational aspects, including the increased demand for record-keeping, increased testing requirements for injection wells and increased investigation and enforcement powers, and procedural aspects, including those related to Saskatchewan's participation as partner in the Petroleum Registry of Alberta. Manitoba In Manitoba, the Petroleum Branch of Innovation, Energy and Mines develops, recommends, implements and administers policies and legislation aimed at the sustainable, orderly, safe and efficient development of crude oil and natural gas resources. Oil and gas exploration, development, production and transportation are subject to regulation under The Oil and Gas Act (the "MBOGA") and The Oil and Gas Production Tax Act, and related regulations and guidelines. Liability Management Rating Programs Alberta In Alberta, the AER administers the Licensee Liability Rating Program (the "AB LLR Program"). The AB LLR Program is a liability management program governing most conventional upstream oil and gas wells, facilities and pipelines. The ABOGCA establishes an orphan fund (the "Orphan Fund") to pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program if a licensee or working interest participant ("WIP") becomes defunct. The Orphan Fund is funded by licensees in the AB LLR Program through a levy administered by the AER. The AB LLR Program is designed to minimize the risk to the Orphan Fund posed by unfunded liability of licensees and prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines. The AB LLR Program requires a licensee whose deemed liabilities exceed its deemed assets to provide the AER with a security deposit. The ratio of deemed liabilities to deemed assets is assessed once each month and failure to post the required security deposit may result in the initiation of enforcement action by the AER. - 44 - On May 1, 2013, the AER began to implement a three year program of changes to the LLR Program. Some of the important changes which will be implemented through this three year process include: • • • • a 25 percent increase to the prescribed average reclamation cost for each individual well or facility (which will increase a licensee's deemed liabilities); a $7,000 increase to facility abandonment cost parameters for each well equivalent (which will increase a licensee's deemed liabilities); a decrease in the industry average netback from a five-year to a three-year average (which will affect the calculation of a licensee's deemed assets, as the reduction from five to three years results in the average being more sensitive to price changes); and a change to the present value and salvage factor, which increase to 1.0 for all active facilities from the current 0.75 for active wells and 0.50 for active facilities (which will increase a licensee's deemed liabilities). The changes will be implemented over a three-year period, ending May 2015. The first phase was implemented in May 2013, the second phase was implemented in May 2014 and the final phase will be implemented in May 2015. The changes to the AB LLR Program stem from concern that the previous regime significantly underestimated the environmental liabilities of licensees. On July 4, 2014, the AER introduced the inactive well compliance program (the “IWCP”) to address the growing inventory of inactive wells in Alberta and to increase the AER’s surveillance and compliance efforts under Directive 013: Suspension Requirements for Wells (“Directive 013”). The IWCP applies to all inactive wells that are noncompliant with Directive 013 as of April 1, 2015. The objective is to bring all inactive noncompliant wells under the IWCP into compliance with the requirements of Directive 013 within five years. As of April 1, 2015, each licensee will be required to bring 20% of its inactive wells into compliance every year, either by reactivating or suspending the wells in accordance with Directive 013 or by abandoning them in accordance with Directive 020: Well Abandonment. Saskatchewan In Saskatchewan, the Ministry of Economy implements the Licensee Liability Rating Program (the "SK LLR Program"). The SK LLR Program is designed to assess and manage the financial risk that a licensee's well and facility abandonment and reclamation liabilities pose to an orphan fund (the "Oil and Gas Orphan Fund"). The Oil and Gas Orphan Fund is responsible for carrying out the abandonment and reclamation of wells and facilities contained within the SK LLR Program when a licensee or WIP is defunct or missing. The SK LLR Program requires a licensee whose deemed liabilities exceed its deemed assets to post a security deposit. The ratio of deemed liabilities to deemed assets is assessed each month for all licensees of oil, gas and service wells and upstream oil and gas facilities. Manitoba To date, Manitoba has not implemented a liability management rating program similar to those found in the other western provinces. However, operators of wells licensed in the province are required to post a performance deposit to ensure that the operation and abandonment of wells and the rehabilitation of sites occurs in accordance with the MBOGA and the Drilling and Production Regulations. In certain circumstances, a performance deposit may be refunded. The MBOGA also establishes the Abandonment Fund Reserve Account (the "Abandonment Fund"). The Abandonment Fund is a source of funds that may be used to operate or abandon a well when the licensee or permittee fails to comply with the MBOGA. The Abandonment Fund may also be used to rehabilitate the site of an abandoned well or facility or to address any adverse effect on property caused by a well or facility. Deposits into the Abandonment Fund are comprised of non-refundable levies charged when certain licences and permits are issued or transferred as well as annual levies for inactive wells and batteries. - 45 - RISK FACTORS An investment in Common Shares would be subject to certain risks. Investors should carefully consider the following risk factors: Operational Risks Oil and natural gas exploration operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering and oil spills, each of which could result in substantial damage to oil and natural gas wells, producing facilities, other property and the environment or in personal injury. In accordance with industry practice, Surge is not fully insured against all of these risks, nor are all such risks insurable. Although Surge maintains liability insurance in an amount which it considers adequate, the nature of these risks is such that liabilities could exceed policy limits, in which event Surge could incur significant costs that could have a materially adverse effect upon its financial condition. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations. Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to Surge and may delay exploration and development activities. Oil and natural gas exploration and development activities are dependent on access to areas where operations are to be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances. Unexpected adverse weather conditions, such as flooding or prolonged break-up, can have a significant negative impact on capital expenditures, operations and costs. To the extent Surge is not the operator of its oil and natural gas properties, it is dependent on such operators for the timing of activities related to such properties and is largely unable to direct or control the activities of the operators. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although Surge intends to operate the majority of its properties, there is no guarantee that it will remain operator of such properties or that Surge will operate other properties it may acquire in the future. In addition, the success of Surge will be largely dependent upon the performance of its management and key employees. Surge does not have any key man insurance policies and, therefore, there is a risk that the death or departure of any member of management or any key employee could have a material adverse effect on Surge. Surge's ability to market oil and natural gas from its wells also depends upon numerous other factors beyond its control, including, among other things, the availability of natural gas processing and storage capacity, the availability of pipeline capacity, the price of oilfield services and the effects of inclement weather. Because of these factors, Surge may be unable to market some or all of the oil and natural gas it produces or to obtain favourable prices for the oil and natural gas it produces. Volatility of Oil and Natural Gas Prices and Markets Surge's financial performance and condition are substantially dependent on the prevailing prices of oil and natural gas which are unstable and subject to fluctuation. Fluctuations in oil or natural gas prices could have an adverse effect on Surge's operations and financial condition and the value and amount of its reserves. Prices for crude oil fluctuate in response to global and North American supply of and demand for oil, market performance and uncertainty and a variety of other factors which are outside the control of Surge including, but not limited, to the world economy and OPEC's ability to adjust supply to world demand, government regulation, political stability and the availability of alternative fuel sources. In addition, the prices received by Surge for its oil are subject to differentials against such benchmarks as WTI and Edmonton Par which can fluctuate substantially and result in Surge realizing prices substantially below such benchmarks. Natural gas prices are influenced primarily by factors within North America, including North American supply and demand, economic performance, weather conditions and availability and pricing of alternative fuel sources. - 46 - Decreases in oil and natural gas prices realized by Surge will result in reduced net production revenue and may change the economics of producing from some wells, which could result in a reduction in the volume of Surge's reserves. Any further substantial declines in the prices of crude oil or natural gas could also result in delay or cancellation of existing or future drilling, development or construction programs or the curtailment of production. All of these factors could result in a material decrease in Surge's net production revenue, cash flows and profitability causing a reduction in its oil and gas acquisition and development activities. In addition, bank borrowings available to Surge will in part be determined by Surge's borrowing base. A sustained material decline in prices from historical average prices could further reduce such borrowing base, therefore reducing the bank credit available and could require that a portion of its bank debt be repaid. Surge may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, Surge will not benefit from such increases. Possible Failure to Realize Anticipated Benefits of Acquisitions The Corporation has recently completed a number of acquisitions and may complete future acquisitions to strengthen its position in the oil and natural gas industry and to create the opportunity to realize certain benefits including, among other things, potential cost savings. Achieving the benefits of recent and any future acquisitions the Corporation may complete will depend in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as the Corporation's ability to realize the anticipated growth opportunities and synergies from combining the acquired assets and operations with those of the Corporation. The integration of acquired assets requires the dedication of substantial management effort, time and resources which may divert management’s focus and resources from other strategic opportunities and from operational matters during this process. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the Corporation’s ability to achieve the anticipated benefits of recent and any future acquisitions. Sour Natural Gas Some of the Corporation’s current or future properties include wells that produce sour natural gas and facilities that process sour natural gas. An accidental discharge or leak of sour natural gas can be fatal or cause serious injury. The dangers associated with drilling for, producing, processing and transporting sour natural gas necessitate increased environmental, health and safety compliance costs to Surge and any accidental discharge or leak of sour natural gas could lead to significant liabilities to Surge. Surge has implemented policies and protocols to address this risk, but it is not possible for any issuer to eliminate all of the risks associated with producing, processing and transporting sour natural gas. Environmental Concerns Many aspects of the oil and natural gas business present environmental risks and hazards, including the risk that Surge may be in noncompliance with an environmental law, regulation, permit, licence, or other regulatory approval, possibly unintentionally or without knowledge. Such risks may expose Surge to fines or penalties, third party liabilities or to the requirement to remediate, which could be material. The operational hazards associated with possible blowouts, accidents, oil spills, natural gas leaks, fires, or other damage to a well or a pipeline may require Surge to incur costs and delays to undertake corrective actions, could result in environmental damage or contamination or could result in serious injury or death to employees, consultants, contractors or members of the public, creating the potential for significant liability to Surge. Also, the occurrence of any such incident could damage Surge's reputation in the surrounding communities and make it more difficult for Surge to pursue its operations in those areas. Compliance with environmental laws and regulations could materially increase Surge's costs. Surge may incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, Surge may be required to incur significant costs to comply with future federal or provincial greenhouse gas emissions reduction requirements or other regulations, if enacted. Although Surge maintains insurance consistent with prudent industry practice, it is not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, - 47 - insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms. Accordingly, Surge's properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons. It is also possible that changing regulatory requirements or emerging jurisprudence could render such insurance of less benefit to Surge. Dividends Notwithstanding anything contained in this Annual Information Form, the payment and the amount of dividends declared, if any, will be subject to the discretion of the Board and will depend on the Board's assessment of the Corporation's outlook for growth, capital expenditure requirements, funds from operations, potential opportunities, debt position and other conditions that the Board may consider relevant at such future time, including applicable restrictions that may be imposed under the Credit Facility and on the ability of the Corporation to pay dividends. The amount of future cash dividends, if any, may also vary depending on a variety of factors, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens and foreign exchange rates. In addition, the market value of the Common Shares may decline if the Corporation's cash dividends decline in the future, and that market value decline may be material. See “Dividend Policy.” Hydraulic Fracturing The proliferation of the use of hydraulic fracturing as a recovery technique employed in oil and natural gas drilling has given rise to increased public scrutiny of its environmental aspects, particularly with respect to its potential impact on local aquifers. Surge utilizes hydraulic fracturing in a significant portion of the light oil wells it drills and completes. Negative public perception of hydraulic fracturing may place pressure on governments in the jurisdictions where Surge operates to implement additional regulatory requirements or limitations on the utilization of hydraulic fracturing, which in turn could restrict Surge's operations and increase its costs. Availability of Services The availability of the services necessary to drill and complete the types of horizontal oil wells that form a substantial portion of Surge's planned exploration and development activities in 2014 remains constrained due to increased demand and competition for such services. Such constraint may increase the costs of such services or result in the delay of planned exploration and development activities. Reserve Estimates There are numerous uncertainties inherent in evaluating quantities of reserves and the net present value of future net revenue to be derived therefrom, including many factors beyond the control of Surge. The reserves information contained in the Surge Reserves Report and set forth herein, including information respecting the net present value of future net revenue from reserves, represents an estimate only. This estimate is based on a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of oil and natural gas, operating costs and royalties and other government levies that may be imposed over the producing life of the reserves. These assumptions were based on price forecasts in use at the date the Reserve Reports were prepared and many of these assumptions are subject to change and are beyond the control of Surge. Ultimately, the actual reserves attributable to Surge's properties will vary from the estimates contained in the Surge Reserves Report and those variations may be material and affect the market price of the Common Shares. Reserve Replacement Surge's future oil and natural gas reserves and production and the cash flows to be derived therefrom are highly dependent on successfully acquiring or discovering new reserves. Without the continual addition of new reserves, any existing reserves Surge may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in reserves will depend not only on Surge's ability to develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. There can be no - 48 - assurance that Surge's future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas. Industry Regulation and Competition There is strong competition relating to all aspects of the oil and natural gas industry. Surge will actively compete for capital, skilled personnel, undeveloped land, reserve acquisitions, access to drilling rigs, service rigs and other equipment, access to processing facilities and pipeline and refining capacity, and in all other aspects of its operations with a substantial number of other organizations, many of which may have greater technical and financial resources than Surge. Some of those organizations not only explore for, develop and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a world-wide basis and as such have greater and more diverse resources on which to draw. Surge's ability to increase reserves and production in the future will depend not only on its ability to develop its present properties, but also on its ability to select and acquire suitable producing properties or prospects for exploratory drilling. The marketability of oil and natural gas acquired or discovered will be affected by numerous factors beyond the control of Surge. These factors include reservoir characteristics, market fluctuations, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulation. Oil and natural gas operations (exploration, production, pricing, marketing, transportation and royalty rates) are subject to extensive controls and regulations imposed by various levels of government, including those described above under the heading "Industry Conditions", which may be amended from time to time. Surge's oil and natural gas operations may also be subject to compliance with federal, provincial and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Changes to the regulation of the oil and gas industry in jurisdictions in which Surge operates may adversely impact Surge's ability to economically develop existing reserves and add new reserves. Variations in Foreign Exchange Rates and Interest Rates Surge's expenses will be denominated in Canadian dollars, while the price of oil and natural gas will generally be denominated in U.S. dollars or impacted by the Canadian dollar to U.S. dollar exchange rate. As the exchange rate for the Canadian dollar versus the U.S. dollar increases, Surge will generally receive fewer Canadian dollars for its production. If the value of the Canadian dollar against the U.S. dollar increases, the financial results of Surge may be negatively affected. Surge's management may initiate certain hedges to mitigate these risks. Future fluctuations in the Canadian/United States foreign exchange rate may impact the future value of Surge's reserves as determined by independent evaluators. In addition, variations in interest rates could result in a significant change in the amount Surge will pay to service debt, potentially adversely affecting the value of the Common Shares. Price Volatility of Publicly Traded Securities In recent years, the securities markets in Canada and the United States have experienced a high level of price and volume volatility, and the market price of securities of many companies, particularly those considered to be development stage companies, has experienced wide fluctuations in price which have not necessarily been related to the operating performance, underlying asset values or prospects of such companies. There can be no assurance that continual fluctuations in price will not occur. It is likely that the market price for the Common Shares will be subject to market trends generally, notwithstanding the financial and operational performance of Surge. Credit Facility Risks The Corporation currently has the Credit Facility and the amount authorized thereunder is dependent on the borrowing base determined by its lenders. The Corporation is required to comply with covenants under the Credit Facility which may, in certain cases, include certain financial ratio tests, which from time to time either affect the availability, or price, of additional funding and in the event that the Corporation does not comply with these covenants, the Corporation's access to capital could be restricted or repayment could be required. Events beyond the Corporation's control may contribute to the failure of the Corporation to comply with such covenants. A failure to comply with covenants could result in default under the Credit Facility, which could result in the Corporation being required to repay amounts owing thereunder. Even if the Corporation is able to obtain new financing, it may not be on commercially reasonable terms or terms that are acceptable to the Corporation. If the Corporation is unable to repay amounts owing under the Credit Facility, the lenders under the - 49 - Credit Facility could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness. The acceleration of the Corporation's indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration provisions. In addition, the Credit Facility may impose operating and financial restrictions on the Corporation that could include restrictions on the payment of dividends, repurchase or making of other distributions with respect to the Corporation's securities, incurring of additional indebtedness, the provision of guarantees, the assumption of loans, making of capital expenditures, entering into of amalgamations, mergers, take-over bids or disposition of assets, among others. The Corporation's lenders use the Corporation's reserves, commodity prices, applicable discount rate and other factors, to periodically determine the Corporation's borrowing base. A material decline in commodity prices could reduce the Corporation's borrowing base, reducing the funds available to the Corporation under the Credit Facility. This could result in the requirement to repay a portion, or all, of the Corporation's bank indebtedness. Geopolitical Risks Political events throughout the world that cause disruptions in the supply of oil continuously affect the marketability and price of oil and natural gas acquired or discovered by the Corporation. Conflicts, or conversely peaceful developments, arising outside of Canada have a significant impact on the price of oil and natural gas. Any particular event could result in a material decline in prices and result in a reduction of the Corporation's net production revenue. In addition, the Corporation's oil and natural gas properties, wells and facilities could be the subject of a terrorist attack. If any of the Corporation's properties, wells or facilities are the subject of terrorist attack it may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. The Corporation does not have insurance to protect against the risk from terrorism. Substantial Capital Requirements; Liquidity Surge may have to make substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. If revenues or reserves decline, Surge may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the company. Moreover, future activities may require Surge to alter its capitalization significantly. The inability of the company to access sufficient capital for its operations could have a material adverse effect on its financial condition, results of operations or prospects. Issuance of Debt From time to time Surge may enter into transactions to acquire assets or shares of other corporations. These transactions may be financed partially or wholly through debt, which may increase debt levels above industry standards. Surge's articles and by-laws do not limit the amount of indebtedness it may incur. The level of Surge's indebtedness from time to time could impair its ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise. Abandonment and Reclamation Costs Surge will be responsible for compliance with terms and conditions of environmental and regulatory approvals and all laws and regulations regarding abandonment and reclamation in respect of its properties, which abandonment and reclamation costs may be substantial. A breach of such legislation or regulations may result in the imposition of fines and penalties, including an order for cessation of operations at the site until satisfactory remedies are made. Delay in Cash Receipts and Credit Worthiness of Counterparties In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of Surge's properties, and by the operator to Surge, payments between any of such parties may also be delayed by restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, recovery by the operator of expenses incurred in the operation of Surge's properties or the establishment by the - 50 - operator of reserves for such expenses. In addition, the insolvency or financial impairment of any counterparty owing money to Surge, including industry partners and marketing agents, could prevent Surge from collecting such debts. Hedging From time to time, the Corporation may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline. However, to the extent that the Corporation engages in price risk management activities to protect itself from commodity price declines, it may also be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, the Corporation's hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances in which: production falls short of the hedged volumes; there is a widening of price-basis differentials between delivery points for production and the delivery point assumed in the hedge arrangement; the counterparties to the hedging arrangements or other price risk management contracts fail to perform under those arrangements; or a sudden unexpected event materially impacts oil and natural gas prices. Similarly, from time to time the Corporation may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar. However, if the Canadian dollar declines in value compared to the United States dollar, the Corporation will not benefit from the fluctuating exchange rate. Dilution Common Shares, including rights, warrants, special warrants, subscription receipts and other securities to purchase, to convert into or to exchange into Common Shares, may be created, issued, sold and delivered on such terms and conditions and at such times as the Board may determine. In addition, Surge may issue additional Common Shares from time to time pursuant to Surge's stock option plan and stock incentive plan. The issuance of these Common Shares would result in dilution to holders of Common Shares. Net Asset Value Surge's net asset value will vary depending upon a number of factors beyond the control of Surge's management, including oil and natural gas prices. The trading price of the Common Shares is also determined by a number of factors which are beyond the control of management and such trading price may be greater than or less than the net asset value of Surge. Reliance on Management Shareholders will be dependent on the management of Surge in respect of the administration and management of all matters relating to Surge and its properties and operations. Investors who are not willing to rely on the management of Surge should not invest in Common Shares. Permits and Licenses The operations of Surge may require licenses and permits from various governmental authorities. There can be no assurance that Surge will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at its projects. Title to Properties Although title reviews will be done according to industry standards prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells as determined appropriate by management, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat a claim of Surge which could result in a reduction of Surge's interest in a property or well and the revenue received by Surge therefrom. - 51 - Aboriginal Claims Aboriginal peoples have claimed aboriginal title and rights to resources and various properties in western Canada. Such claims, in relation to any of Surge's lands, if successful, could have an adverse effect on its operations. Corporate Matters To date, Surge has not paid any dividends on its outstanding Common Shares. Certain of the directors and officers of Surge are also directors and officers of other oil and gas companies involved in natural resource exploration and development, and conflicts of interest may arise between their duties as officers and directors of Surge, as the case may be, and as officers and directors of such other companies. Failure to Maintain Listing of the Common Shares The Common Shares are currently listed for trading on the facilities of the TSX. The failure of Surge to meet the applicable listing or other requirements of the TSX in the future may result in the Common Shares ceasing to be listed for trading on the TSX, which would have a material adverse effect on the value of the Common Shares. There can be no assurance that the Common Shares will continue to be listed for trading on the TSX. Structure of Surge From time to time, Surge may take steps to organize its affairs in a manner that minimizes taxes and other expenses payable with respect to the operation of Surge and its subsidiaries. If the manner in which Surge structures its affairs is successfully challenged by a taxation or other authority, Surge and the holders of Common Shares may be adversely affected. Changes in Legislation It is possible that the Canadian federal and provincial government or regulatory authorities could choose to change the Canadian federal income tax laws, royalty regimes, environmental laws or other laws applicable to oil and gas companies and that any such changes could materially adversely affect Surge, its shareholders and the market value of the Common Shares. Additional information on the risks, assumptions and uncertainties are found in this Annual Information Form under the heading “Special Note Regarding Forward Looking Statements”. LEGAL PROCEEDINGS AND REGULATORY ACTIONS There are no outstanding legal proceedings material to the Corporation to which the Corporation is a party or in respect of which any of its properties are subject, nor are there any such proceedings known to the Corporation to be contemplated. During the year ended December 31, 2014, there were (i) no penalties or sanctions imposed against the Corporation by a court relating to securities legislation or by a securities regulatory authority; (ii) no other penalties or sanctions imposed by a court or regulatory body against the Corporation that it believes would likely be considered important to a reasonable investor in making an investment decision; and (iii) no settlement agreements entered into by the Corporation with a court relating to securities legislation or with a securities regulatory authority. INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS The Corporation contracts with a third-party consultant corporation (the “Marketing Corporation”) to maintain, negotiate and implement a portion of its crude oil, natural gas liquids and natural gas marketing contracts. The Corporation sold 32% of the Corporation’s gross revenues to the Marketing Corporation during the year ended December 31, 2014. Paul Colborne, an executive officer and director of the Corporation, previously held a 20% ownership interest in a company (the “Non-Voting Shareholder”) that owns 100% of the non-voting shares of the Marketing Corporation. The Non-Voting Shareholder had preferential rights over other shareholders in terms of payment of dividends by the Marketing - 52 - Corporation, and was entitled to receive 35% of the net income of the Marketing Corporation annually as a dividend. In June 2014, Mr. Colborne disposed of his indirect interest in the Marketing Corporation. There are no material terms of any marketing contracts currently being negotiated involving the Corporation or the Marketing Corporation. Each of James Pasieka, a director of the Corporation, and Michael Bennett, the Corporate Secretary of the Corporation, is a partner of the national law firm McCarthy Tétrault LLP, which law firm rendered legal services to the Corporation. Except as disclosed above or as may be disclosed elsewhere in this AIF, none of the directors, executive officers or principal shareholders of the Corporation, and no associate or affiliate of any of them, has or has had any material interest in any transaction or any proposed transaction which has materially affected or is reasonably expected to materially affect the Corporation or any of its affiliates. AUDITOR, TRANSFER AGENT AND REGISTRAR The auditor of the Corporation is KPMG LLP who has been the auditor since May 5, 2010. The transfer agent and registrar for the Common Shares is Olympia Trust Company at its principal offices in Calgary, Alberta and Toronto, Ontario. INTEREST OF EXPERTS The Surge Reserves Report and certain reserves estimates contained in filings made by the Corporation under National Instrument 51-102 – Continuous Disclosure Requirements during the year ended December 31, 2014 were prepared by Sproule and McDaniel. As at the date of this Annual Information Form, the directors, officers, employees and consultants of Sproule who participated in the preparation of the Sproule Report or such reserves estimates or who were in a position to directly influence the preparation or outcome of the preparation of the Sproule Report or such reserves estimates, as a group, owned, directly or indirectly, less than 1% of the outstanding Common Shares. As at the date of this Annual Information Form, the directors, officers, employees and consultants of McDaniel who participated in the preparation of the McDaniel Report or such reserves estimates or who were in a position to directly influence the preparation or outcome of the preparation of the Sproule Report or such reserves estimates, as a group, owned, directly or indirectly, less than 1% of the outstanding Common Shares. KPMG LLP are independent of the Corporation pursuant to the rules of professional conduct of the Institute of Chartered Accountants of Alberta. ADDITIONAL INFORMATION Additional information concerning the Corporation may be found under the Corporation’s profile on SEDAR at www.sedar.com. Additional information, including information concerning directors’ and officers’ remuneration and indebtedness, principal holders of the Corporation’s securities and securities authorized for issuance under equity compensation plans, will be contained in the information circular of the Corporation for the annual general meeting of the holders of Common Shares scheduled to be held in 2015. Additional financial information is provided in the Corporation’s comparative financial statements and management’s discussion and analysis for the year ended December 31, 2014. - 53 - REPORTS ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS SCHEDULE “A” A - 2 A - 3 A - 4 A - 5 A - 6 SCHEDULE “B” FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION Terms to which a meaning is ascribed in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities have the same meaning herein. Management of Surge Energy Inc. (the “Corporation”) is responsible for the preparation and disclosure of information with respect to the Corporation’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2014, estimated using forecast prices and costs. Sproule Associates Limited and McDaniel & Associates Consultants Ltd., each an independent qualified reserves evaluator, have evaluated and reviewed the Corporation’s reserves data. The reports of the independent qualified reserves evaluators are presented in Schedule “A” to the Annual Information Form of the Corporation for the year ended December 31, 2014 (the “AIF”). The Reserves Committee of the Board of Directors of the Corporation has: (a) (b) (c) reviewed the Corporation’s procedures for providing information to the independent qualified reserves evaluators; met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and reviewed the applicable reserves data with management and with each of Sproule Associates Limited and McDaniel & Associates Consultants Ltd. The Reserves Committee of the Board of Directors has reviewed the Corporation’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved: (a) (b) the content and filing with securities regulatory authorities of Form 51-101F1, incorporated into the AIF, containing reserves data and other oil and gas information; the filing of Form 51-101F2, which are the reports of the independent qualified reserves evaluators of on the reserves data; and (c) the content and filing of this report. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery. (signed) "Paul Colborne" Paul Colborne, President & Chief Executive Officer and Chairman of the Board of Directors (signed) “Maxwell Lof” Maxwell Lof, Vice-President, Finance and Chief Financial Officer (signed) “Colin Davies” Colin Davies, Director & Chairman of the Reserves Committee March 19, 2015 (signed) “P. Daniel O’Neil” P. Daniel O’Neil, Director SCHEDULE “C” AUDIT COMMITTEE CHARTER SURGE ENERGY INC. AUDIT COMMITTEE CHARTER Role and Objective The Audit Committee is a committee of the Board of Directors of Surge Energy Inc. (the “Corporation”) to which the Board has delegated its responsibility for oversight of the nature and scope of the annual audit, management’s reporting on internal accounting standards and practices, financial information and accounting systems and procedures, financial reporting and statements and recommending, for Board approval, the audited consolidated financial statements and other mandatory disclosure releases containing financial information of the Corporation. The objectives of the Audit Committee are as follows: 1. 2. 3. 4. 5. to assist directors in fulfilling their legal and fiduciary obligations (especially for accountability) in respect of the preparation and disclosure of the financial statements of the Corporation and related matters; to oversee the audit efforts of the external auditors of the Corporation; to maintain free and open means of communication among the directors, the external auditors, the financial and senior management of the Corporation; to satisfy itself that the external auditors are independent of the Corporation; and to strengthen the role of the outside directors by facilitating in depth discussions between directors on the Committee, management and external auditors. The function of the Committee is one of oversight of management and the external auditors in the execution of their responsibilities. Management is responsible for the preparation, presentation and integrity of the financial statements of the Corporation, maintaining appropriate accounting and financial reporting principles and policies and implementing appropriate internal controls and procedures. The external auditors are responsible for planning and carrying out a proper audit of the annual financial statements of the Corporation and reviewing the interim financial statements of the Corporation prior to their filing with securities regulatory authorities and other procedures. Composition of the Committee 1. 2. 3. The Audit Committee shall consist of at least three directors. The Board shall appoint one member of the Audit Committee to be the Chair of the Audit Committee. Each director appointed to the Audit Committee by the Board must be independent. A director is independent if the director has no direct or indirect material relationship with the Corporation. A material relationship means a relationship which could, in the view of the Board, reasonably interfere with the exercise of the director's independent judgment. In determining whether a director is independent of management, the Board shall make reference to National Instrument 52-110 – Audit Committees or the then current legislation, rules, policies and instruments of applicable regulatory authorities. Each member of the Audit Committee shall be “financially literate”. In order to be financially literate, a director must be, at a minimum, able to read and understand financial statements that present a breadth and complexity of accounting issues generally comparable to the breadth and complexity of issues expected to be raised by the Corporation's financial statements. 4. A director appointed by the Board to the Audit Committee shall be a member of the Audit Committee until replaced by the Board or until his or her resignation. Meetings of the Committee 1. 2. The Audit Committee shall convene a minimum of four times each year at such times and places as may be designated by the Chair of the Audit Committee and whenever a meeting is requested by the Board, a member of the Audit Committee, the auditors, or a senior officer of the Corporation. Meetings of the Audit Committee shall correspond with the review of the quarterly financial statements and management discussion and analysis of the Corporation. Notice of each meeting of the Audit Committee shall be given to each member of the Audit Committee. The auditors shall be given notice of each meeting of the Audit Committee at which financial statements of the Corporation are to be considered and such other meetings as determined by the Chair and shall be entitled to attend each such meeting of the Audit Committee. 3. Notice of a meeting of the Audit Committee shall: (a) (b) (c) (d) be in writing; state the nature of the business to be transacted at the meeting in reasonable detail; to the extent practicable, be accompanied by copies of documentation to be considered at the meeting; and be given at least two business days prior to the time stipulated for the meeting or such shorter period as the members of the Audit Committee may permit. 4. 5. 6. 7. 8. A quorum for the transaction of business at a meeting of the Audit Committee shall consist of a majority of the members of the Audit Committee. However, it shall be the practice of the Audit Committee to require review, and, if necessary, approval of certain important matters by all members of the Audit Committee. A member or members of the Audit Committee may participate in a meeting of the Audit Committee by means of such telephonic, electronic or other communication facilities, as permits all persons participating in the meeting to communicate adequately with each other. A member participating in such a meeting by any such means is deemed to be present at the meeting. In the absence of the Chair of the Audit Committee, the members of the Audit Committee shall choose one of the members present to be Chair of the meeting. In addition, the members of the Audit Committee shall choose one of the persons present to be the Secretary of the meeting. The Chairman of the Board, senior management of the Corporation and other parties may attend meetings of the Audit Committee; however the Audit Committee (i) shall meet with the external auditors independent of management as necessary, in the sole discretion of the Committee, but in any event, not less than quarterly; and (ii) may meet separately with management. Minutes shall be kept of all meetings of the Audit Committee and shall be signed by the Chair and the Secretary of the meeting. Duties and Responsibilities of the Committee 1. It is the responsibility of the Audit Committee to oversee the work of the external auditors, including resolution of disagreements between management and the external auditors regarding financial reporting. The external auditors shall report directly to the Audit Committee. C - 2 2. 3. The Audit Committee shall, in the exercise of its powers, authorities and discretion so authorized, conform to any regulations or restrictions that may from time to time be made or imposed upon it by the Board or the legislation, policies or regulations governing the Corporation and its business. It is the responsibility of the Audit Committee to satisfy itself on behalf of the Board that the Corporation’s system of internal controls over financial reporting and disclosure controls and procedures are satisfactory for the purpose of: (a) (b) identifying, monitoring and mitigating the principal risks; ensuring compliance with legal, ethical and regulatory requirements; and to review with the external auditors their assessment of the internal controls over financial reporting and the disclosure controls of the Corporation, their written reports containing recommendations for improvement, and management’s response and any follow-up to any identified weaknesses. 4. It is the responsibility of the Audit Committee to review the annual financial statements of the Corporation and, if deemed appropriate, recommend the financial statements to the Board for approval. This process should include but be not to be limited to: (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) reviewing and accepting, if appropriate, the annual audit plan of the external auditors of the Corporation, including the scope of audit activities, and monitor such plan’s progress and results during the year; reviewing changes in accounting principles, or in their application, which may have a material impact on the current or future years’ financial statements; reviewing significant accruals, reserves or other estimates such as any impairment calculation; reviewing the methods used to account for significant unusual or non-recurring transactions; ascertaining compliance with covenants under loan agreements; reviewing disclosure requirements for commitments and contingencies; reviewing adjustments raised by the external auditors, whether or not included in the financial statements; reviewing unresolved differences between management and the external auditors; obtain explanations of significant variances with comparative reporting periods; review of business systems changes and implications; review of authority and approval limits; review the adequacy and effectiveness of the accounting and internal control policies of the Corporation and procedures through inquiry and discussions with the external auditors and management; confirm through private discussion with the external auditors and the management that no management restrictions are being placed on the scope of the external auditors’ work; review of tax policy issues; and review of emerging accounting issues that could have an impact on the Corporation. 5. It is the responsibility Audit Committee to review the interim financial statements of the Corporation and, if deemed appropriate, to recommend the financial statements to the Board for approval and to review all related management discussion and analysis. The Audit Committee must be satisfied that adequate procedures are in place C - 3 for the review of the Corporation’s disclosure of all other financial information and shall periodically assess the accuracy of those procedures. 6. The Audit Committee shall have the authority to: (a) (b) (c) (d) inspect any and all of the books and records of the Corporation, its subsidiaries and affiliates; discuss with the management and senior staff of the Corporation, its subsidiaries and affiliates, any affected party and the external auditors, such accounts, records and other matters as any member of the Audit Committee considers necessary and appropriate; engage independent counsel and other advisors as it determines necessary to carry out its duties; and to set and pay the compensation for any advisors employed by the Audit Committee. 7. With respect to the appointment of external auditors by the Board, the Audit Committee shall: (a) (b) (c) (d) (e) recommend to the Board the appointment of the external auditors; review the performance of the external auditors and make recommendations to the Board regarding the replacement or termination of the external auditors when circumstances warrant; oversee the independence of the external auditors by, among other things, requiring the external auditors to deliver to the Audit Committee, on a periodic basis, a formal written statement delineating all relationships between the external auditors and the Corporation and its subsidiaries; recommend to the Board the terms of engagement of the external auditor, including the compensation of the auditors and a confirmation that the external auditors shall report directly to the Committee; and when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change. Audit Committee shall review annually with the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of the Corporation and its subsidiaries. The Audit Committee must pre-approve all non-audit services to be provided to the Corporation or its subsidiaries by external auditors. The Audit Committee may delegate, to one or more members, the authority to pre-approve non-audit services, provided that the member report to the Audit Committee at the next scheduled meeting and such pre-approval and the member comply with such other procedures as may be established by the Audit Committee form time to time. The Audit Committee shall review the risk management policies and procedures of the Corporation (i.e. hedging, litigation and insurance coverage and make appropriate recommendations to the Board with respect thereto. including the annual review of insurance), 8. 9. 10. 11. The Audit Committee shall establish and maintain procedures for: (a) (b) the receipt, retention and treatment of complaints received by the Corporation regarding accounting controls, or auditing matters; and the confidential, anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters. 12. The Audit Committee shall review and approve the Corporation’s hiring policies regarding employees and former employees of the present and former external auditors or auditing matters. C - 4 13. 14. 15. The Chairman of the Audit Committee shall review and approve the expenses incurred by the President and Chief Executive Officer. The Audit Committee shall periodically report the results of reviews undertaken and any associated recommendations to the Board. The Audit Committee shall assess, on an annual basis, the adequacy of this Mandate and the performance of the Audit Committee. C - 5 

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