Surge Energy Inc
Annual Report 2013

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ANNUAL INFORMATION FORM For the Year Ended December 31, 2013 Dated March 19, 2014 TABLE OF CONTENTS Definitions ....................................................................................................................................................... 4 Abbreviations and Conversion .......................................................................................................................... 6 Non-IFRS Measures .......................................................................................................................................... 7 Notes on Reserves Data and Other Oil and Natural Gas Information .................................................................. 7 Special Note Regarding Forward Looking Statements ........................................................................................ 9 Surge Energy Inc. ............................................................................................................................................ 11 Development of the Business ......................................................................................................................... 12 General .................................................................................................................................................................. 12 2011 ....................................................................................................................................................................... 12 USA Acquisitions ............................................................................................................................................... 12 Credit Facility .................................................................................................................................................... 12 Prospectus Financing ........................................................................................................................................ 12 TSX Graduation ................................................................................................................................................. 13 2012 ....................................................................................................................................................................... 13 Pradera Acquisition .......................................................................................................................................... 13 Credit Facility .................................................................................................................................................... 13 Other Acquisitions ............................................................................................................................................ 13 2013 ....................................................................................................................................................................... 13 Management Changes and Private Placement ................................................................................................ 13 North Dakota Disposition ................................................................................................................................. 14 Shaunavon Acquisition and Public Offering of Subscription Receipts ............................................................. 14 Saskatchewan and Manitoba Acquisitions ....................................................................................................... 14 Wainwright Asset Acquisition and Public Offering of Subscription Receipts ................................................... 15 Credit Facility .................................................................................................................................................... 15 Events subsequent to December 31, 2013 ............................................................................................................ 15 SE Saskatchewan Asset Acquisition and Public Offering of Subscription Receipts .......................................... 15 Description of the Business ............................................................................................................................ 15 Corporate Strategy ................................................................................................................................................ 15 Competition ........................................................................................................................................................... 16 Seasonal Factors .................................................................................................................................................... 17 Environmental Regulation ..................................................................................................................................... 17 Personnel ............................................................................................................................................................... 17 Principal Producing Properties ........................................................................................................................ 17 Western Alberta .................................................................................................................................................... 17 Southeast Alberta .................................................................................................................................................. 18 Saskatchewan ........................................................................................................................................................ 19 Williston Basin ....................................................................................................................................................... 20 Statement of Reserves Data ........................................................................................................................... 21 Summary of Oil and Gas Reserves – Forecast Prices and Costs ............................................................................ 21 Net Present Value of Future Net Revenue – Forecast Prices and Costs ............................................................... 22 Additional Information Concerning Future Net Revenue – Forecast Prices and Costs (Undiscounted) ............... 22 Future Net Revenue by Production Group – Forecast Prices and Costs ............................................................... 23 Pricing Assumptions – Forecast Prices and Costs .................................................................................................. 23 Reconciliation of Changes in Reserves .................................................................................................................. 23 Additional Information Relating to Reserves Data ........................................................................................... 24 Undeveloped Reserves .......................................................................................................................................... 24 Significant Factors or Uncertainties Affecting Reserves Data ............................................................................... 25 Future Development Costs .................................................................................................................................... 25 Other Oil and Gas Information ........................................................................................................................ 26 Oil and Gas Wells ................................................................................................................................................... 26 Properties with no Attributed Reserves ................................................................................................................ 26 Additional Information Concerning Abandonment and Reclamation Costs ......................................................... 27 Tax Horizon ............................................................................................................................................................ 27 Costs Incurred ........................................................................................................................................................ 27 Drilling Activity ....................................................................................................................................................... 27 Planned Capital Expenditures ................................................................................................................................ 27 Production Estimates ............................................................................................................................................. 27 Production History ................................................................................................................................................. 28 Average Daily Production Volume ................................................................................................................... 28 Prices Received, Royalties Paid, Production Costs and Netback- Crude Oil .................................................... 28 Prices Received, Royalties Paid, Production Costs and Netback- Natural Gas................................................. 28 Prices Received, Royalties Paid, Production Costs and Netback- Combined ................................................... 29 Production Volume by Field .................................................................................................................................. 29 Share Capital .................................................................................................................................................. 29 Common Shares ..................................................................................................................................................... 29 Preferred Shares .................................................................................................................................................... 29 Dividend Policy .............................................................................................................................................. 29 Escrowed Securities........................................................................................................................................ 30 Market for Securities ...................................................................................................................................... 30 Directors and Officers ..................................................................................................................................... 30 Corporate Cease Trade Orders .............................................................................................................................. 32 Bankruptcies .......................................................................................................................................................... 33 Penalties or Sanctions ........................................................................................................................................... 33 Conflicts of Interest ............................................................................................................................................... 33 Audit Committee ............................................................................................................................................ 33 Composition of the Audit Committee, Charter and Review of Services ............................................................... 33 Education and Experience of Members ................................................................................................................ 34 External Auditor Service Fees ................................................................................................................................ 35 Industry Conditions ........................................................................................................................................ 35 Legal Proceedings And Regulatory Actions ...................................................................................................... 52 Interest of Management and Others in Material Transactions ......................................................................... 53 Auditor, Transfer Agent and Registrar ............................................................................................................. 53 Interest of Experts .......................................................................................................................................... 53 Additional Information ................................................................................................................................... 54 Schedule “A” – Form 51-101F2 Reports On Reserves Data By Independent Qualified Reserves Evaluators or Auditors Schedule “B” – Form 51-101F3 Report Of Management And Directors On Reserves Data And Other Information Schedule “C” – Audit Committee Charter - 3 - 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 $470 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 the Bank of Nova Scotia, the Canadian Imperial Bank of Commerce, the Alberta Treasury Branches, JP Morgan Chase Bank, N.A. and the Toronto Dominion Bank and bearing interest at bank rates; “Flagstone” means Flagstone Energy Inc.; “Fort Calgary” means Fort Calgary Resources Ltd.; “Manitoba Asset Acquisition” means the acquisition by the Corporation of the petroleum and natural gas properties and related assets in southwest Manitoba by the Corporation pursuant to the share purchase and sale agreement dated October 22, 2013 between 1779275 Alberta Ltd., Fort Calgary and the Corporation; “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; “Pradera” means Pradera Resources Inc., a private corporation incorporated under the ABCA and amalgamated with a wholly-owned subsidiary of the Corporation to form Surge Oil Inc.; “Pradera Acquisition” means the indirect acquisition by the Corporation on January 6, 2012 of all of the issued and outstanding shares of Pradera; “Pradera Acquisition Agreement” means the agreement entered into by the Corporation and Pradera dated December 15, 2011 whereby the Corporation agreed to acquire all of the issued and outstanding common shares of Pradera for consideration of approximately $106 million, consisting of 7.9 million Common Shares and approximately $33 million in cash including the assumption of net debt; “Preferred Shares” means the preferred shares of the Corporation; “Renegade” means Renegade Petroleum Ltd.; “Saskatchewan Acquisition” means the acquisition by the Corporation of all of the issued and outstanding shares of Flagstone pursuant to the pre-acquisition agreement dated October 22, 2013 between Flagstone and the Corporation; “SE Saskatchewan Asset Acquisition” means the acquisition by the Corporation of the SE Saskatchewan Assets from Renegade pursuant to the terms of the asset sale agreement dated as of January 13, 2014, between Renegade and the Corporation; “SE Saskatchewan Assets” means the petroleum and natural gas properties and related assets in southeast Saskatchewan acquired by the Corporation pursuant to the SE Saskatchewan Asset Acquisition; “SE Saskatchewan Financing” means the $70,005,600 short form prospectus bought deal subscription receipt financing of the Corporation which closed on February 4, 2014; “Shaunavon Asset Acquisition” means the acquisition by the Corporation of the petroleum and natural gas properties and related assets in southwest Saskatchewan acquired by the Corporation pursuant to the asset sale agreement dated June 11, 2013 between Cenovus Energy Inc. and the Corporation; “Shaunavon Financing” means the $225,000,000 short form prospectus bought deal subscription receipt financing of the Corporation which closed on July 3, 2013; “Sproule” means Sproule Associates Limited, independent oil and gas reservoir engineers; “Surge Reserves Report” means the consolidated independent engineering report dated February 14, 2014 and effective December 31, 2013 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; “Tax Act” means the Income Tax Act (Canada), R.S.C. 1985, c.l. (5th Supp.), as amended, including the regulations promulgated thereunder; “TSX” means the Toronto Stock Exchange; “TSXV” means the TSX Venture Exchange; “Wainwright Asset Acquisition” means the acquisition by the Corporation of the Wainwright Assets from an oil and gas company located in Calgary, Alberta, pursuant to the terms of an asset sale agreement dated November 5, 2013 between the vendor and the Corporation; “Wainwright Assets” means the petroleum and natural gas properties and related assets in central Alberta acquired by the Corporation pursuant to the Wainwright Asset Acquisition; and “Wainwright Financing” means the $55,020,000 short form prospectus bought deal subscription receipt financing of the Corporation which closed on November 28, 2013. Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All dollar amounts set forth in this Annual Information Form, including “dollar”, “$” and “CAD$” are in Canadian dollars, except where otherwise indicated. “US$” means United States dollars. - 5 - 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 - 6 - 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 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. “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. - 7 - 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. 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 - 8 - 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; the size of the oil and natural gas reserves of the Corporation and anticipated future cash flows from such reserves;   oil and natural gas production levels;   projections of market prices and costs;  supply and demand for oil and natural gas;  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;  tax horizon; - 9 - timing of development of undeveloped reserves;   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. 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. - 10 - General SURGE ENERGY INC. The Corporation is a Calgary, Alberta based, public company whose Common Shares are listed on the TSX under the symbol “SGY”. The Corporation was incorporated on January 26, 1998 under the ABCA as “Zapata Capital Inc.” and completed its initial public offering of 1,000,000 Common Shares on August 21, 1998 under the Alberta Stock Exchange’s junior capital pool program. On June 18, 1999, the Corporation acquired all of the issued and outstanding shares of 744997 Alberta Ltd., a private corporation, as the Corporation’s major transaction under the Alberta Stock Exchange’s junior capital pool program and amalgamated with 744997 Alberta Ltd. on that date under the name “Zapata Energy Corporation”. On June 25, 2010, the Corporation changed its name to “Surge Energy Inc.” by way of articles of amendment. On December 31, 2010, the Corporation amalgamated with its wholly owned subsidiary Breaker Resources Ltd. by way of articles of amalgamation and continued under the name “Surge Energy Inc.”. On October 21, 2011, the Common Shares commenced trading on the TSX and ceased trading on the TSXV. On December 31, 2012, the Corporation amalgamated with is wholly owned subsidiary Surge Oil Inc. by way of articles of amalgamation and continued under the name “Surge Energy Inc.”. On December 31, 2013, the Corporation amalgamated with its wholly owned subsidiaries Flagstone Energy Inc. and 1779275 Alberta Ltd. by way of articles of amalgamation and continued under the name “Surge Energy Inc.”. The Corporation is an independent Calgary, Alberta based oil and gas company which acquires interests in petroleum and natural gas rights, and explores for, develops, produces and markets petroleum and natural gas reserves primarily in Western Canada. The Corporation recently transitioned into 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 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 high quality light and medium gravity crude oil reserve, production and cash flow base. The Corporation has operated properties 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, several successful water flood projects, and a strong balance sheet. Management has initiated a risk management/hedging program designed to protect cash flows, fund capital expenditures, and to pay dividends. 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. 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: - 11 - 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. General DEVELOPMENT OF THE BUSINESS The Corporation is an independent Calgary, Alberta based oil and gas company which acquires interests in petroleum and natural gas rights, and explores for, develops, produces and markets petroleum and natural gas reserves primarily in Western Canada. The Corporation recently transitioned into 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. Significant developments of the Corporation over the last three completed financial years are as set forth below: 2011 USA Acquisitions On March 30, 2011 and May 13, 2011, respectively, the Corporation completed two light oil asset acquisitions in North Dakota through its then wholly owned subsidiary, Surge Energy USA Inc. Through the two acquisitions, the Corporation acquired approximately 100 barrels per day (2010 exit rate) of light oil production, 6,000 net acres of highly prospective land in the Spearfish light oil resource play and greater than 100,000 acres of other high working interest, undeveloped land for total consideration of $20.9 million in cash. Credit Facility On May 16, 2011, the Corporation confirmed an increase in the Credit Facility from $90 million to $120 million. Subsequently, on September 12, 2011, the Corporation confirmed a further increase to the Credit Facility from $120 million to $150 million. Prospectus Financing On October 12, 2011, the Corporation completed a short form prospectus bought deal financing pursuant to which 6,897,000 Common Shares were issued at a price of $8.70 per Common Share for aggregate gross proceeds of approximately $60 million. Net proceeds from the financing were used to temporarily reduce bank indebtedness owing under the Credit Facility, and to use the availability created thereunder to fund ongoing exploration and development activities, potential land and asset acquisitions and general corporate purposes. - 12 - TSX Graduation On October 21, 2011, the Common Shares commenced trading on the facilities of the TSX after the Corporation graduated to the TSX from the TSXV. 2012 Pradera Acquisition On December 15, 2011, the Corporation entered into the Pradera Acquisition Agreement providing for the acquisition of all of the issued and outstanding shares of Pradera. The completion of the Pradera Acquisition added approximately 1,200 bbls per day (100 percent light oil) of Slave Point/Gilwood light oil assets to the Corporation’s portfolio. Total consideration of the acquisition was 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 and consist of approximately 1,200 bbl/d of production (100% light oil). The Pradera Acquisition was considered to be a “significant acquisition” under applicable securities laws. 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. Other Acquisitions Excluding the Pradera acquisition, Surge made a number of acquisitions throughout the year in the amount of $9.7 million and disposed of non-core assets for which it received $4.1 million. 2013 Management Changes and Private Placement On May 8, 2013, the Corporation announced the appointment of Mr. Paul Colborne as President and Chief Executive Officer of the Corporation, the resignation of Mr. P Daniel O’Neil as President and Chief Executive Officer, as well as the appointment of Mr. Murray Bye as the Vice President of Production of the Corporation. In connection with his appointment as President and Chief Executive Officer, Mr. Colborne subscribed by private placement (the “Colborne Placement”) for an aggregate of $2.5 million in units of the Corporation at a price of $3.57 per unit (the “Colborne Units”) in two tranches on June 11, 2013 (for $2.25 million) and June 19, 2013 (for $250,000). Each unit was comprised of one Common Share and two Common Share purchase warrants (“Colborne Warrants”). Each Colborne Warrant entitles the holder to purchase one Common Share at $4.46 for a period of five years, subject to vesting based on time and performance of the Common Shares. Specifically, with respect to time vesting, the Colborne Warrants vest as to 1/3 on each of the first three anniversaries of the issuance date and with respect to performance vesting, the Colborne 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 Colborne Warrants vest. The Colborne Warrants are non-transferable, except to a child or spouse of the holder of the Colborne Warrant, a company controlled by such holder or such holder’s child or spouse, or a trust all the beneficiaries of which are such holder or such holder’s child or spouse or any combination thereof, all as approved by the Board. - 13 - 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 “U.S. 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). Shaunavon Acquisition and Public Offering of Subscription Receipts On July 3, 2013, the Corporation completed the Shaunavon Asset Acquisition. Pursuant to the Shaunavon Asset Acquisition, the Corporation acquired certain assets located in southwest Saskatchewan, approximately 100 kilometres southwest of Swift Current, Saskatchewan, 140 kilometres east of the Alberta border (the “Shaunavon Assets”) for total consideration of $242.4 million. The Shaunavon 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 Shaunavon Assets is weighted 100% to medium crude oil and natural gas liquids. The property included 134 gross (133 net) producing oil wells and 49 gross (49 net) non-producing oil wells as at April 1, 2013. Major facilities include 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. Seven satellites are connected to the battery. The Shaunavon Assets consisted of production of approximately 3,468 BOE/d (average production volume for the three months ended September 30, 2013), with 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). The effective date of the Shaunavon Asset Acquisition was July 1, 2013. On July 3, 2013, the Corporation completed the Shaunavon Financing. Pursuant to the Shaunavon Financing, the Corporation issued 15,000,000 units (“July 2013 Units”) at a price of $15.00 per July 2013 Unit, for gross proceeds of $225 million as part of a “bought deal” financing with a syndicate of underwriters. Each July 2013 Unit was comprised of one Common Share at a price of $5.00 per Common Share and two subscription receipts of Surge at a price of $5.00 per subscription receipt. The underwriters also exercised their option to purchase up to an additional 4,500,000 subscription receipts, for proceeds of an additional $22.5 million for aggregate gross proceeds of $247.5 million. The subscription receipts were listed and posted for trading on the TSX under the symbol SGY.R at the open of markets on July 3, 2013, until the conversion of the subscription receipts into Common Shares upon the satisfaction of all conditions to the completion of the Shaunavon Asset Acquisition, which also occurred on July 3, 2013. The gross proceeds from the issuance of Common Shares pursuant to the Shaunavon Financing were used to pay down debt and for general corporate purposes and the gross proceeds from the issuance of subscription receipts pursuant to the Shaunavon Financing were used to partially fund the Shaunavon Asset Acquisition. The Shaunavon Acquisition was considered to be a “significant acquisition” under applicable securities laws. For further particulars regarding the Shaunavon Acquisition, see the material change report of the Corporation dated July 3, 2013 and the business acquisition report dated July 4, 2013. Saskatchewan and Manitoba Acquisitions On November 13, 2013, the Corporation completed the Saskatchewan Acquisition and the Manitoba Asset Acquisition. The Saskatchewan Acquisition involved the $147 million (based on a Surge share price of $6.00 per Common Share) purchase of all of the issued and outstanding shares (“Flagstone Shares”) of Flagstone, 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 Shares was comprised of 20.2 million Common Shares and cash consideration of $3.0 million, plus the assumption of $23 million of debt. Holders of Flagstone Shares that elected to receive cash received $4.55 for each Flagstone Share held, all other holders of Flagstone Shares received 0.7583 of a Common Share for each Flagstone Share held. The Manitoba Asset Acquisition involved the acquisition by the Corporation from Fort Calgary and 1779275 Alberta Ltd. of high quality, high netback, operated, producing light oil assets primarily located in the southwest area of Manitoba (the “Manitoba Assets”) 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. - 14 - Wainwright Asset Acquisition and Public Offering of Subscription Receipts On November 28, 2013, the Corporation completed the Wainwright Financing. Pursuant to the Wainwright Financing, the Corporation issued 8,400,000 subscription receipts at a price of $6.55 per subscription receipt, for gross proceeds of $55,020,000 as part of a “bought deal” financing with a syndicate of underwriters. The underwriters exercised their option to purchase up to an additional 1,260,000 subscription receipts, for proceeds of an additional $8,253,000 for aggregate gross proceeds of $63,273,000. The subscription receipts were listed and posted for trading on the TSX under the symbol SGY.N at the open of markets on November 28, 2013, until the conversion of the subscription receipts into Common Shares upon the satisfaction of all conditions to the completion of the Wainwright Asset Acquisition, which occurred on December 3, 2013. The gross proceeds from the issuance of subscription receipts pursuant to the Wainwright Financing were used to partially fund the Wainwright Asset Acquisition. On December 3, 2013, the Corporation completed the Wainwright Acquisition and acquired the Wainwright Assets for consideration of $76.8 million in cash. The Wainwright Assets are located near Wainwright in the Corporation’s core area of Central Alberta. The Wainwright Assets include 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 is weighted 98% to medium crude oil (23° API). The property includes key producing infrastructure, including batteries, pipelines, and water flood facilities. Credit Facility On May 31, 2013, in connection with the disposition of the North Dakota assets, the Credit Facility was decreased from $290 million to $277 million. On July 3, 2013, in connection with the Shaunavon Acquisition the Corporation confirmed an increase in the Credit Facility from $277 million to $350 million. On December 3, 2013, in connection with Saskatchewan Acquisition, the Manitoba Asset Acquisition and the Wainwright Acquisition, the Corporation increased the Credit Facility from $350 million to $470 million. Events subsequent to December 31, 2013 SE Saskatchewan Asset Acquisition and Public Offering of Subscription Receipts On February 4, 2014, the Corporation completed the SE Saskatchewan Financing. Pursuant to the SE Saskatchewan Financing, the Corporation issued 11,112,000 subscription receipts at a price of $6.30 per subscription receipt, for gross proceeds of $70,005,600 as part of a “bought deal” financing with a syndicate of underwriters. The underwriters exercised their option to purchase up to an additional 1,666,800 subscription receipts, for proceeds of an additional $10,500,840 for aggregate gross proceeds of $80,506,440. The subscription receipts were listed and posted for trading on the TSX under the symbol SGY.O at the open of markets on February 4, 2014, until the conversion of the subscription receipts into Common Shares upon the satisfaction of all conditions to the completion of the SE Saskatchewan Asset Acquisition, which occurred on February 14, 2014. The gross proceeds from the issuance of subscription receipts pursuant to the SE Saskatchewan Financing were used to partially fund the SE Saskatchewan Asset Acquisition. On February 14, 2014, the Corporation completed the SE Saskatchewan Acquisition and acquired the SE Saskatchewan Assets for consideration of $109 million in cash. The SE Saskatchewan Assets are located in the Corporation’s core area of southeast Saskatchewan. The SE Saskatchewan Assets include an average working interest of approximately 83% in 14,735 gross (12,226 net) acres of undeveloped land as at January 13, 2014, with an internally estimated value of $3 million. Production from the assets is weighted 97% to light crude oil (36° API). The property includes key producing infrastructure, including batteries, pipelines, and water flood facilities. Corporate Strategy DESCRIPTION OF THE BUSINESS 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 - 15 - 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 high quality light and medium gravity crude oil reserve, production and cash flow base. The Corporation has operated properties 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, several successful water flood projects, and a strong balance sheet. Management has initiated 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 2014 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. - 16 - Seasonal Factors The exploration for and development of oil and natural gas reserves is dependent on access to areas where production is to be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances. 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, 2013, the Corporation has recorded an asset retirement obligation of $85 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 2035 to 2063. 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. Personnel As at December 31, 2013, the Corporation had 53 head office employees and 2 field employees. 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, 2013, is provided below. Western Alberta 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, 2013, this operated property included an average working interest of approximately 95% in approximately 11,680 gross (11,066 net) developed acres and an average working interest of approximately 93% in approximately 8,640 gross (8,026 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. As at December 31, 2013 Surge had drilled a total of 22 gross (17.7 net) horizontal multi-frac wells at Valhalla/Wembley, of which, 8 gross wells (7.44 net) were drilled during 2013. One of the wells drilled in 2013 was a 100% working-interest, Montney, horizontal, multi-frac, development well. This well was successfully completed but is currently suspended, awaiting tie-in to third party facilities able to handle the produced water associated with the Montney formation. The Corporation plans to drill approximately 4 gross (3.4 net) horizontal multi-frac wells at Valhalla/Wembley in 2014. At December 31, 2013 the Corporation has identified approximately 44 gross (36.7 net) horizontal multi-frac Doig oil locations remaining 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 - 17 - 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). In 2013 Surge drilled and completed one horizontal, multi-frac, Slave Point oil well in the main Northern Pool (100% working- interest). A second, successful horizontal well, which has not been fracked (73% working-interest) was completed and brought on production at Nipisi south. A Slave Point water flood in the Northern Pool was successfully implemented in 2013. Two horizontal wells were converted to injection and a third was added early in 2014. The response to the water flood was observed in less than two months, increasing production rates in immediately offsetting wells. Surge anticipates it will expand its water flood program in Nipisi in 2014 with the conversion of at least one more producing well to injection. At December 31, 2013, the Corporation identified 37 gross (37 net) horizontal multi-frac drilling locations in the Slave Point formation. To date in 2014, the Corporation has drilled 1 gross (1 net) horizontal multi-frac Slave Point well in the Northern Pool, offsetting injection support. Surge is evaluating potential additional drilling later in 2014. Windfall The Windfall assets are located in western Alberta near Whitecourt (TWP 59, Range 15, W5M). As at December 31, 2013, this operated property included an average working interest of approximately 98% in approximately 28,160 gross (27,544 net) developed acres and an average working interest of approximately 98% in approximately 28,640 gross (28,024 net) undeveloped acres. Production from this property is derived from 10 horizontal multi-frac wells and nine vertical wells. During 2013, the Corporation continued its horizontal water flood pilot programme. Surge has observed a stabilization in production from offsetting producing wells, where previously observed declines have been reduced. During 2013, the Corporation drilled and placed one net horizontal, multi-frac, Bluesky oil well on production. As at December 31, 2013, the Corporation identified over 37 gross (35.6 net) horizontal multi-frac drilling locations at Windfall. The Corporation plans to convert one additional horizontal multi-frac well into an injector at Windfall in 2014 as a result of positive water flood response from the original injector. Southeast Alberta As at December 31, 2013, in southeastern Alberta, the Corporation held an average working interest of approximately 82% in approximately 124,038 gross (101,561 net) developed acres and an average working interest of approximately 93% in approximately 115,592 gross (107,850 net) undeveloped acres. As at December 31, 2013, the Corporation held interests in 430 gross (310 net) oil wells and 157 gross (125 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. Wainwright This property was purchased December 3, 2013 and is situated within Surge’s core area of southeast/central Alberta. As at December 31, 2013, the Corporation held an average working interest of 80% in approximately 24,054 gross (19,252 net) developed acres and 64% in approximately 5,107 gross (3,291 net) undeveloped acres. Production at Wainwright is from the Sparky formation and is weighted 92% to medium crude oil (23° API). As at March 2014, the property is under water flood with a current recovery factor of 32%. The Surge Reserves Report assigns the proved plus probable reserves at this property as 5.7 MMBOE. See “Statement of Reserves Data”. As at December 31, 2013, there were 249 producing/injecting wells on this property. During 2014, the Corporation will focus on optimizing the existing water flood, and adding to its land position in the area. In 2014, Surge plans on drilling 1 gross (1 net) development, horizontal, multi-frac Sparky oil well. - 18 - Eyehill In 2013 Surge drilled and brought 8 horizontal, multi-frac Sparky oil wells at Eyehill on production. As at December 31, 2013, the oil produced from this property has been approximately 29° API. During 2013, Surge negotiated a 6 section farm-in and purchased an additional 3.25 sections at Crown sales within the play. During 2013, a central battery was constructed to conserve solution gas and facilitate instigation of a water flood in 2014. To date in 2014, 2 gross (2 net) horizontal, multi-frac Sparky wells have been drilled and placed on production. Surge anticipates it will drill another 6 gross (5.4 net) wells during 2014. During 2014, Surge anticipates commencing a water flood program, including the conversion of one well to injection in the second quarter. Provost During 2013 Surge drilled 2 horizontal, multi-frac Sparky oil wells as well as one vertical disposal/source well on this property. The battery on this property was also expanded in preparation for implementing a water flood scheme in 2014. During 2013, Surge executed a 5 section farm-in within the play. During 2014, Surge anticipates drilling 2 gross (2 net) earning, horizontal, multi-frac Sparky wells and commencing with its water flood program, including the conversion of one well to injection in the second quarter. Silver During 2013, the Corporation drilled one gross (one net) horizontal Cummings oil well and one gross (one net) vertical Cummings injection well. During 2013, the Corporation also focused on optimizing its existing Lloyd zone water flood by adding an additional water source well and optimizing the water injection system to accommodate increased Lloyd injection and expansion of the Cummings zone water flood. In 2014 Surge will focus on the optimization of both schemes fluid production. At December 31, 2013, the Corporation identified over 143 gross (137.4 net) drilling locations in all its southeastern Alberta properties. Saskatchewan Shaunavon The Shaunavon property is located in southwestern Saskatchewan, approximately 100 kilometres southwest of Swift Current, Saskatchewan and 140 kilometres east of the Alberta border. Surge purchased this property on July 3, 2013. As at December 31, 2013, this operated property included an average working interest of approximately 99% in approximately 21,835 gross (21,596 net) developed acres and an average working interest of approximately 97% in 13,183 gross (12,787 net) undeveloped acres. The Corporation’s production from this property is weighted 100% to medium crude oil. To date, production from this property has been from the Lower Shaunavon formation only. The property includes 131 gross (130 net) producing oil wells and 7 gross (7 net) non-producing oil wells. Major facilities at this property 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 and disposal water pumps. Seven satellites are connected to the battery. During 2013, this property produced approximately 3,400 BOE/d, with the Surge Reserves Report assigning net proved plus probable reserves at 10.2 MMBOE. See “Statement of Reserves Data”. During 2013, the Corporation drilled 2 gross (2 net) horizontal, multi-frac development oil wells in the Lower Shaunavon. Surge also conducted an extensive pump optimization program on the existing producing wells, yielding an increase in production and an upward technical revision in proven, developed producing reserves. Due to the extensive, existing facilities and gathering system existing on this property, Surge has initiated two, horizontal, water flood pilots on this - 19 - property. Each pilot covers one section. The first pilot test used 200 metre inter-well spacing (8 wells per section) and the second pilot test used 400 metre spacing (4 wells per section). Injection commenced in both pilots late in 2013 and Surge is currently monitoring the progress of both pilots. To date in 2014 Surge has drilled 4 gross (3 net) Lower Shaunavon development wells. To date in 2014, Surge has also drilled its first Upper Shaunavon horizontal, multi-frac well on this property encountering over 1,200 metres of a potential horizontal reservoir section. As of March 2014, this well has been completed with multiple frac stages and is on production. During 2014, the Corporation plans to drill approximately 8 gross (8 net) additional horizontal multi-frac wells at Shaunavon. As at December 31, 2013, the Corporation has identified approximately 269 gross (262 net) drilling locations in the Upper Shaunavon and Lower Shaunavon formations based on 8 wells per section. Dodsland/Forgan Surge purchased this property on November 13, 2013. The property is located in western Saskatchewan in the Kindersley area. As at December 31, 2013, the oil produced on this property has been approximately 37° API from horizontal and horizontal, multi-frac Viking oil wells. During 2014, Surge anticipates drilling 4 gross (4 net) development, horizontal, multi-frac Viking wells in this area. As at December 31, 2013, the Corporation has identified approximately 138 gross (112 net) drilling locations in the Viking. Williston Basin Manson The Manson area of southwest Manitoba is west of Virden, Manitoba. The Corporation purchased this property on November 13, 2013. Oil production is primarily (90%) from the Bakken formation which is 35° API and 10% from the Mannville formation which is 25° API. The Corporation holds an average working interest of 87% in approximately 1,846 gross (1,597 net) acres of developed land and 94% in approximately 13,500 gross (12,675 net) acres of undeveloped land as at December 31, 2013. Production from the assets is weighted 100% to crude oil. After the acquisition of this property, Surge has expanded the Bakken water flood program, initiated in the third quarter of 2013. To date in 2014, two additional wells have been converted to injection and a pipeline has been installed to gather production to a central battery and facilitate water flood implementation throughout the pool. To date in 2014, Surge has also participated with an offsetting joint venture operator in the drilling of 3 (0.56 net) Bakken development wells. In 2014, the Corporation received an additional water flood unit approval for 2 additional sections in the pool. A third unit water flood application has been submitted to the Manitoba Petroleum Branch with approval expected in the second quarter of 2014. Surge anticipates that water flood expansion into portions of these sections will proceed into the third quarter of 2014 with the conversion of 4 wells to injection. As at December 31, 2013, the Corporation has identified approximately 38 gross (36.3 net) drilling locations. In 2014, Surge plans on drilling 3 gross (2.3 net) horizontal Bakken development wells. Macoun The Macoun property, located in southeastern Saskatchewan, was purchased on November 13, 2013. Production at this property is from the Midale formation and is 100% oil (27° API). The Corporation holds an average working interest of 80% in approximately 1,910 gross (1,533 net) acres of developed land and 95% in approximately 5,716 gross (5,444 net) acres of undeveloped land as at December 31, 2013. Since acquiring this property and to date in 2014, the Corporation has drilled 3 gross (1.625 net) wells on this property. A water flood of this pool was initiated in late 2013 with the conversion of one horizontal well to injection. Surge will expand this water flood in 2014 with the conversion of 2 additional wells to injection, pipeline installation and a facility expansion to handle additional produced volumes. For 2014, Surge will drill 7 gross (7 net), additional, development wells. - 20 - As at December 31, 2013, the Corporation has identified approximately 27 gross (23 net) drilling locations. 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, 2013. The Surge Reserves Report is dated February 14, 2014. Sproule evaluated the Corporation’s Alberta properties including Nipisi and Valhalla in western Alberta and the Provost fields in southeast Alberta. Sproule also evaluated a portion of the Corporation’s Williston Basin properties, including Manson 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, including Macoun. Sproule evaluated approximately 78% of the Corporation’s assigned total proved plus probable reserves and approximately 72% of the Corporation’s total proved plus probable future net revenue, discounted at 10%. McDaniel evaluated approximately 22% of the Corporation’s total proved plus probable reserves and approximately 28% 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 - 21 - Light and Medium Crude OilHeavy Crude OilNatural Gas LiquidsNatural GasLight and Medium Crude OilHeavy Crude OilNatural Gas LiquidsNatural Gas(Mbbls)(Mbbls)(Mbbls)(MMcf)(Mbbls)(Mbbls)(Mbbls)(MMcf)ProvedDeveloped Producing13,438.1 5,805.1 1,043.1 32,752.0 11,449.4 4,980.8 694.8 28,740.0 Developed Non-Producing568.8 46.6 58.7 2,822.0 492.6 40.5 39.8 2,482.0 Undeveloped9,574.7 1,374.8 1,041.6 27,637.0 7,934.0 1,083.7 745.6 23,402.0 Total Proved23,581.6 7,226.5 2,143.4 63,211.0 19,876.0 6,105.0 1,480.2 54,624.0 Probable19,581.7 3,298.2 1,218.1 35,209.0 15,603.6 2,773.9 814.4 30,409.0 Total Proved plus Probable43,163.3 10,524.7 3,361.5 98,420.0 35,479.6 8,878.9 2,294.6 85,033.0 Gross ReservesNet Reserves Net Present Value of Future Net Revenue – Forecast Prices and Costs Additional Information Concerning Future Net Revenue – Forecast Prices and Costs (Undiscounted) - 22 - ($M)0%5%10%15%20%ProvedDeveloped Producing971,648 762,965 638,914 555,163 494,380 Developed Non-Producing33,732 25,468 20,539 17,226 14,832 Undeveloped489,215 325,806 232,533 172,274 130,438 Total Proved1,494,595 1,114,239 891,986 744,663 639,650 Probable1,320,684 717,266 472,237 342,279 262,502 Total Proved plus Probable2,815,279 1,831,505 1,364,223 1,086,942 902,151 Before Future Income Tax Expenses and Discounted at($M)0%5%10%15%20%ProvedDeveloped Producing971,608 762,952 638,909 555,160 494,379 Developed Non-Producing33,730 25,468 20,539 17,226 14,832 Undeveloped379,813 248,585 173,931 125,821 92,472 Total Proved1,385,151 1,037,005 833,379 698,207 601,683 Probable983,483 528,783 343,778 245,604 185,398 Total Proved plus Probable2,368,634 1,565,788 1,177,157 943,811 787,081 After Future Income Tax Expenses and Discounted atProvedDeveloped ProducingDeveloped Non-ProducingUndevelopedTotal ProvedProbableTotal Proved plus ProbableDiscounted at 10%/year ($/BOE)Unit Value before Income Tax29.15 20.82 17.02 24.39 19.47 22.43 (Undiscounted) ($M)RevenueRoyaltiesOperating CostsDevelopment CostsAbandonment and Other costsFuture net revenue before income taxesFuture income taxesFuture net revenue after income taxesTotal Proved3,429,938 555,560 1,049,584 290,053 40,146 1,494,594 109,444 1,385,150 Total Proved plus Probable6,277,042 1,134,002 1,826,481 453,560 47,722 2,815,278 446,645 2,368,634 Future Net Revenue by Production Group – Forecast Prices and Costs Notes: 1. 2. 3. Including solution gas and other by-products. Including by-products, but excluding solution gas from oil wells. Based on net reserves volumes. Pricing Assumptions – Forecast Prices and Costs Both Sproule and McDaniel employed the following pricing and inflation rate assumptions as of December 31, 2013 in their evaluations contained in the Surge Reserves Report in estimating reserves data using forecast prices and costs. The weighted average historical prices received by the Corporation for 2013 are also reflected in the table below. Escalated thereafter at a rate of +1.5% per annum. Reconciliation of Changes in Reserves The following table sets forth a combined reconciliation of the Corporation’s gross reserves as at December 31, 2013, derived from the Surge Reserves Report using forecast prices and cost estimates, reconciled to the gross reserves of the Corporation as at December 31, 2012. - 23 - ProvedLight and Medium Crude Oil (1)Heavy OilNatural Gas (2)Proved plus ProbableLight and Medium Crude Oil (1)Heavy OilNatural Gas (2)7,565 6.89 1,094,693 21.91 258,508 28.05 Future Net Revenue Before Income Taxes and Discounted at 10% ($M)Per Unit Future Net Revenue Before Income Taxes and Discounted at 10%(3) ($BOE)688,733 23.65 11,023 6.75 195,688 30.83 Natural GasYearWTI Cushing Oklahoma 40˚ API (US$/bbl)Edmonton Par Price 40˚ API (CAD$/bbl)Cromer Medium 35˚ API (CAD$/bbl)AECO Gas Price (CAD$/MMBtu)Pentanes plus FOB Field Gate (CAD$/bbl)Butanes FOB Field Gate (CAD$/bbl)Inflation rates (%/Yr)Exchange rate (US$/CAD$)2013 (Surge Actual)97.9893.2491.593.13104.8670.290.80.971201494.6592.6490.644.00103.5069.051.50.94201588.3789.3187.313.9999.7866.571.50.94201684.2589.6387.634.00100.1466.811.50.94201795.52101.6299.624.93113.5375.741.50.94201896.96103.14101.145.01115.2476.881.50.94201998.41104.69102.695.09116.9778.031.50.94202099.89106.26104.265.18118.7279.201.50.942021101.38107.86105.865.26120.5080.391.50.942022102.91109.47107.475.35122.3181.601.50.942023104.45111.12109.125.43124.1482.821.50.942024106.02112.78110.785.52126.0184.061.50.94Medium and Light Crude OilNGL 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: - 24 - Light and Medium Crude OilHeavy OilNatural Gas LiquidsNatural GasBOE(Mbbls)(Mbbls)(Mbbls)(MMcf)(MBOE)ProvedBalance at December 31, 201211,967 4,994 1,724 56,710 28,137 Extensions and Improved Recovery4,463 - 664 17,543 8,050 Technical Revisions(1,075) (560) (59) (6,449) (2,769) Acquisitions11,665 3,310 2 1,079 15,156 Dispositions(1,195) - (3) (8) (1,199) Economic Factors50 28 - (171) 49 Production(2,103) (810) (185) (4,993) (3,931) Balance at December 31, 201323,771 6,962 2,142 63,711 43,493 Light and Medium Crude Oil Heavy Oil Natural Gas Liquids Natural Gas BOE (Mbbls)(Mbbls)(Mbbls)(MMcf)(MBOE)ProbableBalance at December 31, 201210,635 1,829 767 28,541 17,987 Extensions and Improved Recovery2,133 - 418 10,999 4,384 Technical Revisions(731) (666) 34 (4,844) (2,171) Acquisitions8,536 2,071 1 507 10,692 Dispositions(985) - (1) (4) (987) Economic Factors57 8 1 (38) 60 Production- Balance at December 31, 201319,645 3,242 1,219 35,161 29,966 Light and Medium Crude Oil Heavy Oil Natural Gas Liquids Natural Gas BOE (Mbbls)(Mbbls)(Mbbls)(MMcf)(MBOE)Proved plus ProbableBalance at December 31, 201222,602 6,824 2,490 85,251 46,124 Extensions and Improved Recovery6,596 - 1,081 28,542 12,434 Technical Revisions(1,806) (1,226) (25) (11,293) (4,940) Acquisitions20,201 5,381 2 1,585 25,848 Dispositions(2,180) - (4) (12) (2,186) Economic Factors107 36 1 (209) 109 Production(2,103) (810) (185) (4,993) (3,931) Balance at December 31, 201343,416 10,203 3,361 98,872 73,459 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: 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. 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). - 25 - Light and Medium Crude OilHeavy OilNatural Gas LiquidsNatural GasProved(Mbbls)(Mbbls)(Mbbls)(MMcf)Prior to 2010697.0 339.6 39.0 4,145.9 20101,201.5 84.6 263.3 6,839.0 20113,343.7 302.3 721.5 19,281.0 20122,955.3 1,191.3 306.6 8,393.0 20136,215.5 366.1 574.8 15,195.3 Light and Medium Crude OilHeavy OilNatural Gas LiquidsNatural GasProbable(Mbbls)(Mbbls)(Mbbls)(MMcf)Prior to 20101,220.5 285.4 175.3 9,668.3 20101,023.9 236.4 136.2 3,932.0 20112,269.7 161.2 398.0 11,128.0 20126,703.2 457.2 197.8 5,731.0 20139,567.4 196.5 350.5 9,370.2 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. Oil and Gas Wells OTHER OIL AND GAS INFORMATION The following table sets forth the number and status of the Corporation's wells effective December 31, 2013. Properties with no Attributed Reserves The following table summarizes, effective December 31, 2013, 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. - 26 - Proved Reserves ($M)Proved plus Probable Reserves ($M)2014107,834 155,954 201578,235 112,967 201665,752 92,618 201734,192 72,241 Remaining Years4,040 19,780 Total Undiscounted290,053 453,560 Forecast Prices and CostsGrossNetGrossNetGrossNetGrossNetGrossNetGrossNetAlberta4843641651101581007716042161559573British Columbia001100100000Manitoba8580008847440022Saskatchewan2632341111106656441110Total83267816711217711888570422015910885Water Inj/DispOilProducingNon-ProducingNatural GasWater Inj/DispOilNatural GasGross AcresNet AcresNet Acres Expiring within One YearAlberta473,280 397,969 79,674 British Columbia- - - Manitoba26,133 26,710 22,024 Saskatchewan82,767 78,600 11,104 Total582,180 503,278 112,802 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, net of estimated salvage value, included in the Surge Reserves Report for 578 net wells under the proved reserves category is $40.2 million undiscounted ($13.0 million discounted at 10%), of which a total of $3.2 million is estimated to be incurred in 2014, 2015 and 2016. 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 2017. Costs Incurred The following table summarizes capital expenditures incurred by the Corporation during the year ended December 31, 2013. 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, 2013. Planned Capital Expenditures The Corporation has announced a planned capital expenditure budget of approximately $116 million for 2014. Surge has allocated approximately $89 million to its 2014 drilling program, $16 million to water flood implementation and optimization, $11 million to a combination of facilities, plants, land, acquisitions, corporate and capitalized general and administrative expenditures. The Corporation is planning to drill 38 gross (36.1 net) wells in 2014 targeting high quality light and medium gravity oil, with the majority of the activity at Valhalla/Wembley (4 gross, 3.4 net wells), western Alberta (1 gross, 1 net wells), southeastern Alberta (11 gross, 10.4 net wells), Saskatchewan (12 gross, 12 net), Williston Basin (10 gross, 9.3 net). Production Estimates The following table discloses for each product type the total volume of production estimated by Sproule and McDaniel in the Surge Reserves Report for 2014 in the estimates of future net revenue from gross proved and gross proved plus probable reserves disclosed above. - 27 - Proved PropertiesUnproved PropertiesProperty DispositionsExploration CostsDevelopment CostsTotal ($M)616,074 - (44,603) 8,051 117,495 Property Acquisition CostsGrossNetGrossNetLight and Medium Oil- - 34.00 28.12 Natural Gas- - - - Service - - 2.00 2.00 Dry- - 1.00 1.00 Total- - 37.00 31.12 Exploration WellsDevelopment Wells Production History The following table discloses, on a quarterly basis for the year ended December 31, 2013, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the Corporation. Average Daily Production Volume Prices Received, Royalties Paid, Production Costs and Netback- Crude Oil Prices Received, Royalties Paid, Production Costs and Netback- Natural Gas - 28 - Light and Medium OilNatural GasNatural Gas LiquidsBOE%(bbls/d)(Mcf/d)(bbls/d)(BOE/d)ProvedWilliston Basin1,81314401,83711%SW Saskatchewan3,33918113,37020%SE Alberta4,2233,095644,80329%Western Alberta3,08616,8675966,49339%Total Proved12,46120,28766116,503100%Proved Plus ProbableWilliston Basin2,45515402,48113%SW Saskatchewan3,86818513,89921%SE Alberta4,6643,608765,34128%Western Alberta3,44717,7336297,03137%Total Proved Plus Probable14,43321,67970618,752100%Mar 31, 2013Jun 30, 2013Sep 30, 2013Dec 31, 2013Natural Gas (Mcf/d)16,689 14,442 13,696 9,958 Light and Medium Crude Oil (bbls/d)6,479 6,584 9,280 9,919 NGL (bbls/d)375 382 445 435 Total (BOE/d)9,636 9,373 12,008 12,014 Three Months Ended($ per Bbl)Mar 31, 2013Jun 30, 2013Sep 30, 2013Dec 31, 2013Prices Received63.48 69.83 80.68 67.79 Royalties Paid(11.34) (12.96) (15.02) (12.53) Transportation Costs(2.25) (2.44) (1.99) (2.00) Production Costs(12.20) (11.52) (12.60) (12.32) Netback (1)37.69 42.91 51.07 40.94 Three Months Ended($ per Mcf)Mar 31, 2013Jun 30, 2013Sep 30, 2013Dec 31, 2013Prices Received4.32 4.06 3.24 4.01 Royalties Paid(0.38) (0.48) (0.17) 0.15 Transportation Costs(0.35) (0.48) (0.40) (0.50) Production Costs(3.40) (3.77) (3.75) (3.96) Netback (1)0.19 (0.67) (1.08) (0.30) Three Months Ended Prices Received, Royalties Paid, Production Costs and Netback- Combined 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, 2013. SHARE CAPITAL The Corporation is authorized to issue an unlimited number of Common Shares and an unlimited number of Preferred Shares issuable in series. As at March 19, 2014, there were 179.5 million Common Shares and no Preferred Shares issued and outstanding. 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. 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 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 Between August and December 2013, the Corporation declared and paid $0.19 in dividends per Common Share. The Corporation did not declare or pay any dividends prior to August 2013. - 29 - ($ per Boe)Mar 31, 2013Jun 30, 2013Sep 30, 2013Dec 31, 2013Prices Received61.78 68.00 78.60 66.52 Royalties Paid(10.93) (12.56) (14.55) (12.13) Production Costs(12.58) (11.97) (12.94) (12.66) Transportation Costs(2.25) (2.46) (2.01) (2.03) Netback (1)36.02 41.01 49.10 39.70 Three Months EndedFieldLight and Medium Oil (bbls/d)Natural Gas (Mcf/d)Natural Gas Liquids (bbls/d)BOE (BOE/d)%SE Alberta2,5422,306282,95427%West Alberta3,06511,3623805,33950%Saskatchewan1,8851101,88718%Manitoba589005895%Total8,08113,67940810,769100% Pursuant to the Corporation’s transition to a sustainable, moderate growth, dividend paying oil and gas company, the Corporation has established a dividend policy of paying monthly dividends to its shareholders. The primary objective of the Corporation’s dividend policy is to provide shareholders with relatively stable, predictable and sustainable monthly dividends. 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 capital, the amount of capital expenditures and other conditions existing from time to time. There can be no guarantee that the Corporation will maintain its dividend policy. Additionally, pursuant to the Credit Agreement, the payment of dividends may be restricted under certain circumstances. None of the securities of the Corporation are subject to escrow. ESCROWED SECURITIES MARKET FOR SECURITIES The Common Shares are listed and posted for trading on the TSX under the trading symbol “SGY” and have traded on such stock exchange since October 21, 2011. The Common Shares previously traded on the TSXV under the same symbol. The following table sets forth the reported 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, 2013. Period 2013 January February March April May June July August September October November December Price Range ($) High 5.68 4.00 3.76 3.46 5.37 5.69 5.94 6.15 6.43 7.30 6.95 6.88 Low 3.45 3.04 2.70 2.68 2.91 4.99 5.09 5.24 5.82 5.86 6.16 6.21 Trading Volume 43,968,584 17,501,066 13,846,285 12,427,521 116,113,700 26,520,809 100,193,700 48,042,514 54,640,490 41,859,420 37,242,725 41,484,662 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: - 30 - Name and Residence Position Principal Occupation During Previous Five Years Paul Colborne Calgary, Alberta Chairman of the Board of Directors, President and Chief Executive Officer Director since April 13, 2010 P. Daniel O'Neil(3) 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 James Pasieka(2) Calgary, Alberta Director since April 13, 2010 Murray Smith(1)(2) Calgary, Alberta Director since June 25, 2010 Colin Davies(3)(4) Calgary, Alberta Director since July 9, 2010 President and Chief Executive Officer of the Corporation since May 8, 2013. President of StarValley Oil & Gas Ltd., a private oil and natural gas company, since October 2006, Chairman of Legacy Oil and Gas Inc. and serves on the board of directors of Crescent Point Energy Corp. and Cequence Energy Ltd. Prior thereto, Mr. Colborne served as a director of Wildstream Exploration Inc. prior to its sale in 2012, Chairman of TriStar Oil & Gas Ltd. until its sale in 2009 and a director of Breaker Energy Ltd. until its sale in 2009. Prior thereto, Mr. Colborne was President and Chief Executive Officer of StarPoint Energy Trust, a publicly traded oil and natural gas income trust, until its merger to form Canetic Resources Trust in January 2006 and was Chairman of Seaview Energy Ltd, and was a director of Westfire Energy Ltd. and Twin Butte Energy Ltd. 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 both Hyperion Exploration Corp. and Cathedral Energy Services. President and Chief Executive Officer of Custom Truck Sales Ltd., a private company operating Kenworth truck dealerships in Saskatchewan and Manitoba, and President of International Fitness Holdings, an operating arm of a private equity firm operating 25 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. and Rocky Mountain Dealerships Inc., which are listed on the TSX. As well, he is a director of Madalena Ventures Inc. and Mountainview Energy Ltd., which are listed on the TSX Venture Exchange, and other public and private oil and gas companies. Partner of the national law firm McCarthy Tétrault LLP since August 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. President of a private consulting company, Murray Smith and Associates and a director of CriticalControl Business Solutions Corp. and Williams Companies Inc. Mr. Smith also serves on the board of four 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 and Director of Corinthian Exploration Corp., a private company with oil and gas assets located in Alberta and North Dakota. Prior thereto, Mr. Davies was President & CEO and Director of Corinthian Energy Corp., a private oil and gas company that was founded in 2004 and amalgamated with Surge Energy Inc. in July 2010. - 31 - Name and Residence Position Principal Occupation During Previous Five Years 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 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 and Consulting Landman with Legacy Oil + Gas Inc. from December 2009 to March 2010. 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. Notes: 1. 2. 3. 4. Member of the audit committee. Member of the compensation, nominating and corporate governance committee. Member of the reserves committee. Member of the environment, health and safety committee. As a group, the directors and executive officers of the Corporation beneficially own, control or direct, directly or indirectly, 4,063,447 Common Shares, representing approximately two percent of the outstanding Common Shares as at March 19, 2014. 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. Corporate Cease Trade Orders To the knowledge of management of the Corporation, 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: a) b) 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 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. - 32 - Bankruptcies To the knowledge of management of the Corporation, 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: a) b) 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 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. Penalties or Sanctions To the knowledge of management of the Corporation, 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: a) b) 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 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. 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. Composition of the Audit Committee, Charter and Review of Services AUDIT COMMITTEE The members of the Audit Committee of the Board of Directors are Keith Macdonald (Chair), Murray Smith and Robert Leach. 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 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. - 33 - 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. Education and Experience of Members The education and experience of each director relevant to the performance of his duties as a member of the Audit Committee are described below. Keith Macdonald Mr. Macdonald is currently the President of Bamako Investment Management Ltd., a private holding and financial consulting company. Mr. Macdonald is Chairman, President, CEO and director of EFL Overseas, Inc. as well as director of Bellatrix Exploration Ltd., Holloman Energy Corporation, Madalena Ventures Inc., Mountainview Energy Ltd., Rocky Mountain Dealerships Inc., WCSB Oil and Gas Royalty Income 2010 Management Corp. and WCSB Oil and Gas Royalty Income 2010-II Management Corp. 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. Murray Smith Mr. Smith is the president of a private consulting company, Murray Smith and Associates and a director of Critical Control Business Solutions and Williams Companies, Inc. Mr. Smith also serves on the board of four 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 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). Robert Leach Mr. Leach is currently the President and Chief Executive Officer of Custom Truck Sales Ltd., a private company operating Kenworth truck dealerships in Saskatchewan and Manitoba. Mr. Leach is also President of International Fitness Holdings, an operating arm of a private equity firm operating 25 health clubs in Alberta. - 34 - Mr. Leach formerly served as the Chairman of the Board of Breaker where he also served as a member of the audit committee. 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. 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. 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. Prior thereto, Collins Barrow Chartered Accountants LLP were the auditors of the Corporation. The following table sets out the aggregate fees billed by KPMG LLP to the Corporation in each of the last two fiscal years. Year 2013 2012 Audit Fees(1) $371,500 $177,500 Audit-Related Fees $42,000 $67,000 Tax Fees(2) $260,384 $101,906 All Other Fees $0 $14,500 Notes: 1. 2. 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 2012 and 2013, 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 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. 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. Surge does not anticipate that, at current commodity prices, such constraint will be alleviated in the near future. 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 - 35 - 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. 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- - 36 - 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. 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 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. - 37 - 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. 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; - 38 -  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. 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%. 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 percent. - 39 - 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"). Specifically:   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. The Emerging Resource and Technologies Initiative will be reviewed in 2014, and the Government of Alberta has committed to providing industry with three years notice if it decides to discontinue the program. 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. - 40 - 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;  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. - 41 - 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 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. 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. - 42 - 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, British Columbia, 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. On March 29, 2007, British Columbia expanded its policy of deep rights reversion for new leases to provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of their primary term. 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 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 - 43 - 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 30, 2014, the AER is expected to assume 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. 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. In contrast, oilsands companies' tenure has been (or will be) cancelled in conservation areas and no new oilsands tenure will be issued. While new oil sands tenure will be issued in provincial recreation areas, new and existing oil sands tenure will prohibit surface access. The next regional plan to take effect is the South Saskatchewan Regional Plan ("SSRP") which covers approximately 83,764 square kilometres and includes 45 percent of the provincial population. The SSRP was released in draft form in 2013 and is expected to come into force on April 1, 2014. - 44 - 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. British Columbia In British Columbia, the Oil and Gas Activities Act (the "OGAA") impacts conventional oil and gas producers, shale gas producers, and other operators of oil and gas facilities in the province. Under the OGAA, the British Columbia Oil and Gas Commission (the "BCO&G Commission") has broad powers, particularly with respect to compliance and enforcement and the setting of technical safety and operational standards for oil and gas activities. The Environmental Protection and Management Regulation establishes the government's environmental objectives for water, riparian habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGAA requires the BCO&G Commission to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity. In addition, although not an exclusively environmental statute, the Petroleum and Natural Gas Act requires proponents to obtain various approvals before undertaking exploration or production work, such as geophysical licences, geophysical exploration project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole and water-source well authorizations. Such approvals are given subject to environmental considerations and licences and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations. 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. - 45 - 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 current changes have already had an effect on oil and gas producers in Alberta as the May 1, 2013 changes resulted in a significant increase in the number of oil and gas companies in Alberta that are required to post security with the AER. The changes to the AB LLR Program stem from concern that the previous regime significantly underestimated the environmental liabilities of licensees. British Columbia In British Columbia, the BCO&G Commission implements the Liability Management Rating ("LMR") Program, designed to manage public liability exposure related to oil and gas activities by ensuring that permit holders carry the financial risks and regulatory responsibility of their operations through to regulatory closure. Under the LMR Program, the BCO&G Commission determines the required security deposits for permit holders under the OGAA. The LMR is the ratio of a permit holder's deemed assets to deemed liabilities. Permit holders whose deemed liabilities exceed deemed assets will be considered high risk and reviewed for a security deposit. Permit holders who fail to submit the required security deposit within the allotted timeframe may be in non-compliance with the OGAA. 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. - 46 - 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. 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 - 47 - 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, 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 - 48 - 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. 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 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. - 49 - 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. 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 - 50 - 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 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. 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. Forward Looking Information May Prove Inaccurate Readers are cautioned not to place undue reliance on forward looking information. By its nature, forward looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate. 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. On May 23, 2013, the Corporation reached a settlement agreement whereby all third party objections to the Corporation's holding applications at its Valhalla property were withdrawn. The negotiated settlement included compensation by the Corporation of $4,000,000 for gas production from the property over the preceding 30 months, and included a commercial arrangement which accounts for and compensates the parties for any future gas obligations and the withdrawal of a lawsuit filed by one of the objectors. During the year ended December 31, 2013, 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 - 52 - 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 In connection with his appointment as President and Chief Executive Officer, Mr. Colborne subscribed for an aggregate of $2.5 million in Colborne Units at a price of $3.57 per Colborne Unit in two tranches on June 11, 2013 (for $2.25 million) and June 19, 2013 (for $250,000). Each unit was comprised of one Common Share and two Colborne Warrants. Each Colborne Warrant entitles the holder to purchase one Common Share at $4.46 for a period of five years, subject to vesting based on time and performance of the Common Shares. Specifically, with respect to time vesting, the Colborne Warrants vest as to 1/3 on each of the first three anniversaries of the issuance date and with respect to performance vesting, the Colborne 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 Colborne Warrants vest. The Colborne Warrants are non-transferable, except to a child or spouse of the holder of the Colborne Warrant, a company controlled by such holder or such holder’s child or spouse, or a trust all the beneficiaries of which are such holder or such holder’s child or spouse or any combination thereof, all as approved by the Board. The Corporation currently 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 29% of the Corporation’s gross revenues to the Marketing Corporation during the year ended December 31, 2013. Paul Colborne, a senior officer and director of the Corporation, holds 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 has preferential rights over other shareholders in terms of payment of dividends by the Marketing Corporation, and is entitled to receive 35% of the net income of the Marketing Corporation annually as a dividend. 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 Thomas Cotter, the Corporate Secretary of the Corporation, is a partner of the national law firm McCarthy Tétrault LLP, and were partners at Heenan Blaikie LLP prior to August 2013, which laws 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, 2013 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. - 53 - KPMG LLP were appointed auditors of the Corporation on May 5, 2010. KPMG LLP are independent of the Corporation pursuant to the rules of professional conduct of the Institute of Chartered Accountants of Alberta. ADDITIONAL INFORMATION information concerning the Corporation may be found under the Corporation’s profile on SEDAR at Additional 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 2014. Additional financial information is provided in the Corporation’s comparative financial statements and management’s discussion and analysis for the year ended December 31, 2013. - 54 - REPORTS ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS OR AUDITORS SCHEDULE “A” A - 2 A - 3 A - 4 A - 5 A - 6 A - 7 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, 2013, 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, 2013 (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, 2014 (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. 4. 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. 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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