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Hemisphere Energy Corp – ‘20-F’ for 12/31/14

On:  Thursday, 4/30/15, at 3:30pm ET   ·   For:  12/31/14   ·   Accession #:  1062993-15-2274   ·   File #:  0-55253

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 4/30/15  Hemisphere Energy Corp            20-F       12/31/14   15:1.5M                                   Newsfile Corp/FA

Document/Exhibit                   Description                      Pages   Size 

 1: 20-F        Annual Report of a Foreign Private Issuer --        HTML   1.03M 
                          form20f                                                
 2: EX-4.3      Instrument Defining the Rights of Security Holders  HTML     41K 
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 3: EX-4.4      Instrument Defining the Rights of Security Holders  HTML     62K 
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 4: EX-4.5      Instrument Defining the Rights of Security Holders  HTML     62K 
                          -- exhibit4-5                                          
 5: EX-4.6      Instrument Defining the Rights of Security Holders  HTML     62K 
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 6: EX-4.7      Instrument Defining the Rights of Security Holders  HTML     63K 
                          -- exhibit4-7                                          
 7: EX-4.8      Instrument Defining the Rights of Security Holders  HTML     62K 
                          -- exhibit4-8                                          
 8: EX-12.1     Statement re: Computation of Ratios -- exhibit12-1  HTML     11K 
 9: EX-12.2     Statement re: Computation of Ratios -- exhibit12-2  HTML     12K 
10: EX-13.1     Annual or Quarterly Report to Security Holders --   HTML      9K 
                          exhibit13-1                                            
11: EX-13.2     Annual or Quarterly Report to Security Holders --   HTML      9K 
                          exhibit13-2                                            
12: EX-15.1     Letter re: Unaudited Interim Financial Information  HTML      8K 
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13: EX-15.2     Letter re: Unaudited Interim Financial Information  HTML      9K 
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14: EX-15.3     Letter re: Unaudited Interim Financial Information  HTML     11K 
                          -- exhibit15-3                                         
15: EX-99.1     Miscellaneous Exhibit -- exhibit99-1                HTML     30K 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 20-F

[   ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

OR

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________________ to ____________________

OR

[   ] SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 000-55253

HEMISPHERE ENERGY CORPORATION
(Exact name of Registrant as specified in its charter)

Province of British Columbia, Canada
(Jurisdiction of incorporation or organization)

2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9
(Address of principal executive offices)

Dorlyn Evancic, Chief Financial Officer
Telephone: (604) 685-9255
Email: info@hemisphereenergy.ca
2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9
(Name, Telephone, E-Mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Securities registered or to be registered pursuant to Section 12(g) of the Act: Common shares, no par value

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:75,368,498

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [   ]      No [X]

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes [   ]      No [   ]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X]      No [   ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [   ]      No [   ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See the definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [   ]                        Accelerated filer [   ]                        Non-accelerated filer [X]

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

If “Other” has been checked in response to previous question, indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 [   ]      Item 18 [   ]

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [   ]      No [X]

TABLE OF CONTENTS

i

In this Form 20-F, the terms “we”, “our”, “us”, “our company” and “Hemisphere” refer, unless the context requires otherwise, to Hemisphere Energy Corporation and its subsidiaries, if any, through which it conducts business.

ABBREVIATIONS

ii

BARREL OF OIL EQUIVALENCY

Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

CONVERSIONS

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units):

CURRENCY

All amounts are expressed in Canadian dollars unless otherwise stated. See the information under the heading “Item 3.A. Selected Financial Data – Exchange Rate Data” for relevant information about the rates of exchange between Canadian dollars and United States dollars.

FORWARD-LOOKING STATEMENTS

Certain of the statements in this Form 20-F may be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements include, without limitation, statements regarding:

• financial and business prospects and financial outlook;
• reserve and production estimates;
• drilling plans;
• activities to be undertaken in various areas;
• timing of drilling;
• recompletion and tie-in of wells;
• tax horizon;
• timing of development of undeveloped reserves;

iii

• commodity prices and foreign exchange rates; and
• planned capital expenditures, the timing thereof and the method of funding.

Forward-looking statements reflect management's expectations regarding future plans and intentions, growth, results of operations, performance and business prospects and opportunities. Words such as “may”, “will”, “should”, “could”, “anticipate”, “believe”, “expect”, “intend”, “plan”, “potential”, “continue” and similar expressions may be used to identify these forward-looking statements. These statements reflect management's current beliefs and are based on information currently available to management.

Forward-looking statements involve significant risk and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements, including, but not limited to, risks associated with:

• the inherently speculative nature of oil and gas exploration, development and production;
• operational hazards and geological problems;
• volatility in prices and markets for oil and natural gas;
• obtaining additional financing and restrictive terms in future debt financing;
• failure to realize anticipated benefits of acquisitions and dispositions;
• dependence on operators of certain of our assets and on our joint venture partners;
• restricted access to pipelines, storage and processing facilities;
• unavailability of equipment and qualified personnel;
• estimating oil and natural gas reserves;
• intense competition in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas;
• laws and government regulations, including environmental regulation, legislative and regulatory initiatives related to climate change and licensing and permitting;
• changes to the royalty regime;
• currency fluctuations;
• hedging activities;
• title deficiencies;
• inadequate insurance coverage and uninsurable loss;
• management of growth;
• grant and maintenance of appropriate licenses and leases and working interests in licenses and leases;
• seasonal and unexpected weather patterns;
• non-payment or default by third parties;
• loss of key management personnel;
• reassessment of our income tax returns;
• litigation;
• conflicts of interest among our directors and officers;
• title deficiencies and aboriginal title and rights claims;
• restrictive regulation on the marketing of oil and natural gas; and
• recently adopted accounting pronouncements.

The recovery and reserve estimates of our reserves provided in this Form 20-F are estimates only and there is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. In addition, forward-looking statements may include statements attributable to third party industry sources. There can be no assurances that the plans, intentions or expectations upon which such forward-looking statements are based will occur.

Forward-looking statements or information are based on a number of factors and assumptions that have been used to develop those statements and information but which may prove to be incorrect. Although we believe that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because we can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things:

iv

• the impact of increasing competition;
• the general stability of the economic and political environment in which we operate;
• the timely receipt of any required regulatory approvals;
• our ability to obtain qualified staff, equipment and services in a timely and cost efficient manner;
• drilling results;
• the ability of the operator of the projects in which we have an interest to operate the project in a safe, efficient and effective manner;
• our ability to obtain financing on acceptable terms;
• well production rates and decline rates;
• the ability to replace and expand our oil and natural gas reserves through acquisition, development of exploration;
• the timing and costs of pipeline, storage and facility construction and expansion and our ability to secure adequate product transportation;
• future oil and natural gas prices;
• currency, exchange and interest rates;
• the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which we operate; and
• our ability to successfully market our oil and natural gas products.

This list is not exhaustive of the factors that may affect any of our forward-looking statements. Some of the important risks and uncertainties that could affect forward-looking statements are described further under the heading “Item 3.D. Risk Factors”. If one or more of these risks or uncertainties materializes, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected, estimated or projected. Forward-looking statements in this document are not a prediction of future events or circumstances, and those future events or circumstances may not occur. Given these uncertainties, users of the information included in this Form 20-F, including investors and prospective investors are cautioned not to place undue reliance on such forward-looking statements.

The forward-looking statements in this Form 20-F speak only as to the date of filing and are based on our beliefs, opinions and expectations at the time they are made. Except as required by applicable law, including the securities laws of the United States and Canada, we do not intend to update any of the forward-looking statements to conform these statements to actual results.

v

PART I

ITEM 1.                     IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2.                     OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3.                     KEY INFORMATION

A.                     Selected Financial Data

Selected Year End Financial Data

We have selected financial data and information in the following tables for the fiscal years ended February 28, 2011, February 29, 2012, and December 31, 2012, 2013 and 2014 that were derived from our audited financial statements. These audited financial statements have been audited by Smythe Ratcliffe LLP. Certain prior years’ comparative figures have been reclassified, if necessary.

The information in the following tables should be read in conjunction with the information appearing under the heading “Item 5. Operating and Financial Review and Prospects” and the our audited annual financial statements for the fiscal year ended December 31, 2014 under the heading “Item 18. Financial Statements”.

On March 1, 2011, we adopted International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”), for financial reporting purposes, using a transition date of March 1, 2010. Our annual audited financial statements for the year ended February 29, 2012, including February 28, 2011 required comparative information, have been prepared in accordance with IFRS, as issued by the International Accounting Standards Board. Financial statements prior to the fiscal year ended February 28, 2011 were prepared in accordance with pre-changeover Canadian generally accepted accounting principles (“Canadian GAAP”).

On August 20, 2012, we announced that we changed our fiscal year-end date from February 28 to December 31. In accordance with relevant legislation, we prepared our first annual audited financial statements as at and for the ten months ended December 31, 2012 with comparative information as at and for the twelve months ended February 29, 2012.

Pursuant to Release No. 33-8879 of the United States Securities and Exchange Commission (“SEC”), “Acceptance from Foreign Private Issuers of Financial Statements Prepared in Accordance with International Reporting Standards Without Reconciliation to U.S. GAAP,” we have included selected financial data prepared in compliance with IFRS without reconciliation to U.S. GAAP.

The following table is a summary of our selected financial information for each of our four most recently completed financial years. All information, except number of shares, is in Canadian dollars. The information is presented in accordance with IFRS.

1

Note:

Exchange Rate Data

The following table sets forth, for each period indicated, the high, low and average exchange rates for Canadian dollars expressed in United States dollars, provided by the Bank of Canada. The exchange rates set forth in the following table demonstrate trends in exchange rates, but the actual exchange rates used throughout this Form 20-F may vary. The average exchange rate is calculated by using the average on the last day of each month during the relevant period. On April 28, 2015, the noon exchange rate for 1 Canadian dollar expressed in United States dollars as reported by the Bank of Canada, was Cdn$1.00 = US$0.8319.

B.                     Capitalization and Indebtedness

Not applicable.

C.                     Reasons for the Offer and Use of Proceeds

Not applicable.

D.                     Risk Factors

Investors should carefully consider the risk factors set out below and consider all other information contained here and in our other public filings before making an investment decision. The risks set out below are not an exhaustive list, nor should they be taken as a complete summary or description of all the risks associated with our business and the oil and natural gas business generally.

2

Risks Related to Our Company’s Business and Industry

Exploration, development and production of oil and gas resources are inherently speculative, and a failure to add new reserves would have a material adverse effect on our financial condition and results of operations.

Without the continual addition of new reserves, any existing reserves we may have at any particular time will decline over time as such existing reserves are depleted and rate of production slows, and therefore our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Future increase in our reserves and replacement of our existing reserves will depend not only on our ability to explore and develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects. No assurance can be given that we will be able to continue to locate satisfactory properties for acquisition or participation. In addition, if acquisitions or participations are identified, our management may determine that current markets, the terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. Further, future acquisitions or participations that management decides to pursue may involve unprofitable efforts from dry wells and from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. There is no assurance that we will discover or acquire any further commercial quantities of oil and natural gas to replace our existing reserves or increase our reserves in the future. Lastly, if commodity prices were to drop significantly, we could defer our capital expenditure and drilling programs which would delay adding new reserves to maintain our cash flows and could have a material adverse effect on our financial condition.

Our future oil and gas exploration, development and production operations are hazardous and subject to uncertainty, and these hazards and uncertainties could adversely affect our business, financial condition, results of operations and prospects.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards of drilling operations such as fire, explosion, blowouts, cratering, sour gas releases, spills and extreme weather conditions, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury, and including geological problems such as unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. In particular, we may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to us. Such risks and hazards may delay or greatly increase the cost of operations, may adversely affect the development of new wells or the production from successful wells and may cause losses that could have a material adverse effect on our business, financial condition, results of operations and prospects.

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly which could adversely affect our net production revenue and oil and natural gas operations, reserves and our ability to budget for and project the return on acquisitions and on development and exploration projects.

The prices of oil and natural gas prices may be volatile and subject to fluctuation, and any material decline in prices could result in a reduction of our net production revenue and the volumes of our reserves and could negatively impact our ability to budget for and project the return on acquisitions and on development and exploration projects.The price of oil declined from approximately US$80/bbl in November, 2014 to below US$45/bbl through January, 2015 and has subsequently fluctuated between US$43/bbl and as high as US$55/bbl.

Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control. These factors include economic conditions, in the United States and Canada, the actions of the Organization of the Petroleum Exporting Countries (“OPEC”), governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. The economics of producing from some wells may change as a result of lower prices, which could result in reduced production of oil or gas and a reduction in the volumes of our reserves. We might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in our expected net production revenue and a reduction in our oil and gas acquisition, development and exploration activities.

3

In addition, any substantial and extended decline in the price of oil and gas would have an adverse effect on the carrying value of our reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on our business, financial condition, results of operations and prospects. In particular, bank borrowings available to us may, in part, be determined by our borrowing base. A sustained material decline in prices from historical average prices could reduce our borrowing base, therefore reducing the bank credit available to us which could require that a portion, or all, of any of our outstanding bank debt be repaid.

Further, petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, OPEC actions and the ongoing credit and liquidity concerns. Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and on development and exploration projects.

If we are unable to generate sufficient funds from our operations and other financing sources, we may not be able to undertake or complete future drilling programs or fund our ongoing activities, which would adversely affect our business, financial condition, results of operations and prospects.

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times or to fund the substantial capital expenditures that we may incur for the acquisition, exploration, development and production of oil and natural gas reserves in the future, which insufficiency may cause us to seek financing that could be limited, unavailable or available only on unfavorable terms. Failure to obtain such financing on a timely basis could cause us to forfeit our interest in certain properties, miss certain acquisition opportunities and reduce or terminate our operations. Additional debt or equity financing may not be available to meet our financing requirements or, if available, it may not be on terms acceptable to us. The market events and conditions witnessed over the past several years, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to and reductions in commodity prices. The continued uncertainty in the global economic situation means that we may continue to face restricted access to capital and increased borrowing costs. To the extent that our cash flow from our reserves is insufficient, whether as a result of lower oil and natural gas prices or otherwise, and that external sources of capital are limited, unavailable or available only on unfavourable terms, our ability to make capital investments, maintain existing properties, undertake or complete future drilling programs or to generally carry out our oil and natural gas acquisition, exploration and development activities may be constrained, and, as a result, our business, financial condition, results of operations and cash flow may be materially and adversely affected.

We may not be able to obtain future debt financing, or only under restrictive terms, which may adversely impact our exploration and production activities.

From time to time, we may enter into transactions to acquire assets or the shares of other organizations. These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither our notice of articles nor articles limit the amount of indebtedness that we may incur. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

In addition, the terms of the indebtedness we may incur could include covenants imposing significant restrictions on us, including limitations on our ability to encumber or charge our assets or properties in order to secure any further indebtedness and restrictions on our ability to amalgamate with or merge into any other entity or sell, transfer, lease or otherwise dispose of all or substantially all of our properties or assets, without first repaying the indebtedness in full. These restrictions may affect our ability to operate our business and may limit our ability to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial condition and results of operations.

4

We may not realize anticipated benefits of acquisitions and dispositions, which could adversely affect our business, financial condition, results of operations and prospects.

Achieving the benefits of acquisitions and dispositions of businesses and assets in our ordinary course of business depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, our ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses with our operations and the timing of dispositions to coincide with an advantageous price. The integration of acquired business may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided and assets required to provide such services. In this regard, non-core assets are periodically disposed of, so that we can focus our efforts and resources more efficiently. Depending on the state of the market for such non-core assets at the time of sale, certain of our non-core assets, if disposed of, could be expected to realize less than their carrying value on our financial statements. An inability on our part to realize anticipated benefits of acquisitions and dispositions, whether because of a failure to consolidate functions and integrate operations and procedures in a timely and efficient manner, to combine the acquired businesses with our operations or to dispose of businesses and assets at an opportune time, could adversely affect our business, financial condition, results of operations and prospects.

We depend upon operators of certain of our assets and on joint venture partners, and any failure of an operator or joint venture partner to perform, or any disputes or disagreement with an operator or joint venture partner, could adversely affect our business, financial condition, results of operations and prospects.

We do not operate all of our projects and we own certain of our projects with joint venture partners. For those projects that we do not operate, we have limited ability to exercise influence over the operations of our projects, or the associated costs of operations, that are operated by other companies. Our return on assets operated by others depends upon a number of factors that may be outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices. In addition, we own certain of our interests through joint venture or similar arrangements. Joint ventures involve risks not otherwise present when exploring and developing properties directly, including, for example, that a joint venture partner may not pay its share of obligations, we may incur liabilities as a result of an action taken by a joint venture partner and that we may be required to devote significant management time to the requirements of the joint venture for which we will not receive a commensurate return. Failure of an operator to perform, or disputes with operators or other participants, may result in delays, litigation or operational impasse. The risks described above or the failure to resolve disagreements could result in significant cost and delay, or adversely affect the ability of the parties to operate and develop the relevant projects, which could adversely affect our business, financial condition, results of operations and prospects.

Our ability to market oil and natural gas depends on our ability to transport our product to market, and restricted access to pipelines, storage and processing facilities may adversely affect our business, financial condition, results of operations and prospects.

The lack of firm pipeline capacity and the pro-rationing of capacity on the inter-provincial pipeline systems continues to affect the oil and natural gas industry in western Canada, which, along with potential deliverability uncertainties related to the proximity of our reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities, may limit our ability to produce and market our oil and gas production, and therefore we may receive discounted pricing. There is no guarantee that current pipeline construction projects, including projects to increase rail handling and transportation of oil and other liquid hydrocarbons, presently pending before various regulatory bodies will be approved or will ameliorate conditions. As a result, even if we are able to engage in successful exploration and production activities, we may not be able to effectively market the oil and natural gas that we produce, which could adversely affect our business, financial condition, results of operations and prospects.

Unavailability of equipment and qualified personnel could delay our exploration and production activities which may adversely affect our business, financial condition, results of operations and prospects.

There can be no assurance that sufficient drilling and completion equipment, services and supplies will be available when needed or that qualified personnel will be available. Our oil and 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 limited equipment or access restrictions may affect the availability of such equipment to us. Similarly, if the demand for, and wage rates of, qualified rig crews rise in the drilling industry, then the oil and gas industry may experience shortages of qualified personnel to operate drilling rigs. Unavailability of equipment and qualified personnel could each delay our exploration and development activities, which could adversely affect our business, financial condition, results of operations and prospects.

5

Our reserve estimates depend on many assumptions that may prove to be inaccurate and are subject to revision based on production history, and material inaccuracies in the reserve estimates or the underlying assumptions, or revision based on production history, may adversely affect the quantities and present value of our reserves.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. Our reserves and associated cash flow information included in this Form 20-F are estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times may vary. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from estimates thereof and such variations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater resources than us which can increase competitive pressures and could have an adverse effect on our business, financial condition, results of operations and prospects.

The petroleum industry is competitive in all its phases. We compete with numerous other industry participants in the search for, and the acquisition of, oil and natural gas properties, and without the acquisition of suitable oil and gas properties our ability to increase our reserves in the future may be impaired. In addition, we compete with other industry participants for the sourcing and availability of equipment, raw materials and component parts necessary in petroleum and natural gas exploration and development. As demand for drilling rigs and related equipment and services increases, delays and increased pricing may occur, either of which could result in delays in our planned projects and adversely affect our business. Further, we compete with other industry participants in the distribution and marketing of oil and gas with respect to price, methods, pipeline access and reliability of delivery and availability of imported products, all of which may be affected by factors beyond our control and which could adversely affect the our financial condition and results of operations. Our competitors include oil and natural gas companies that have substantially greater financial and technical, resources, staff and facilities than us, and therefore may be able to take advantage of opportunities not available to us, obtain drilling rigs and related equipment and services that we cannot and secure superior means of distribution and marketing of oil and gas, each of which could have an adverse effect on our business, financial condition, results of operations and prospects.

Our operations are subject to various laws and governmental regulations, including permitting, and the implementation of new regulations or the modification of existing regulations could have an adverse effect on our business, financial condition, results of operations and prospects.

The exploration, production, pricing, marketing and transportation of oil and natural gas are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time. Governments may regulate or intervene with respect to exploration and production practices and activities, price, taxes, royalties and the exportation of oil and natural gas. Also, in order to conduct oil and natural gas operations, we will require licenses and permits from various governmental authorities. There can be no assurance that we will be able to obtain all of the licenses and permits that may be required to conduct operations that it may wish to undertake. Governmental regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for natural gas and crude oil and increase our costs, any of which may have an adverse effect on our business, financial condition, results of operations and prospects.

6

Our operations are subject to various environmental laws and regulation, which require compliance that can be burdensome and expensive.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material, the suspension or revocation of necessary licenses and permits, and civil liability for pollution damage. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. No assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on our business, financial condition, results of operations and prospects.

Legislative and regulatory initiatives related to climate change could have an adverse effect on our operations and on the demand for oil and gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to a warming of the Earth's atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. There has been much public debate with respect to Canada's and Provincial Governments’ respective strategies with respect to climate change and the control of greenhouse gases. See the discussion under the heading “Item 4.B. Government Regulations – Environmental and Climate Change Regulation”. Any existing or future legislative or regulatory initiatives that restrict or reduce emissions of greenhouse gases could result in increased operating and compliance costs to us and, further, may adversely affect demand for the fossil fuels we produce, including by increasing the cost of combusting fossil fuels and by creating incentives for the use of alternative fuels and energy. Implementation of such initiatives for reducing greenhouse gases could accordingly have an adverse impact on the nature of oil and natural gas operations, including ours. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and the evolving legislative requirements, it is not possible to predict the impact on us and our operations and financial condition.

Changes to the royalty regime may reduce our earnings and adversely affect our financial condition and results of operations.

There can be no assurance that the governments of Alberta, British Columbia or Canada will not adopt a new royalty regime or modify the methodology of royalty calculations that would increase the royalties we pay. See the information regarding royalty rates under the heading “Item 4.B. Government Regulations – Provincial Royalties and Incentives”. An increase of royalty rates would reduce our earnings and make certain of our projects uneconomic.

Fluctuations in foreign currency exchange rates could have an adverse effect on our business and results of operations.

World oil and gas prices are quoted in United States dollars and the price received by Canadian producers, including us, is therefore affected by the Canadian/United States dollar exchange rate, which will fluctuate over time. In recent years, the Canadian dollar has increased materially in value against the United States dollar. Material increases in the value of the Canadian dollar negatively impact our production revenues. Future Canadian/United States dollar exchange rate fluctuations could accordingly impact our cash flows and the future value of our reserves as determined by independent evaluators.

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Our future hedging activities may not prove beneficial.

From time to time, we may enter into agreements to receive fixed prices on our 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, we will not benefit from such increases and we may nevertheless be obligated to pay royalties on such higher prices, even though not received by it, after giving effect to such agreements.

We may incur losses as a result of title deficiencies as title to our oil and natural gas producing properties cannot be guaranteed and may be subject to prior recorded or unrecorded agreements, transfer, claims or other defects.

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim, and our actual interest in properties may, therefore, vary from our records. The loss of a property, including the loss of our investment, or the loss of the right to produce all or a portion of oil and gas resources under a property could have a material adverse effect on our business, financial condition, results of operations and prospects.

Exploration and development oil and gas properties involve significant risks that cannot always be covered by insurance or contractual protections, and in the event that a significant accident occurs for which we are not fully insured, our business, financial conditions, results of operations and prospects could be adversely affected.

Our involvement in the exploration for and development of oil and natural gas properties may result in us becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property damage, personal injury or other hazards. Although we maintain insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities. In addition, such risks are not, in all circumstances, insurable or, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the availability of our funds. The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on our business, financial condition, results of operations and prospects.

We may be unable to manage our anticipated growth.

We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expand, train and manage our employee base. Our inability to deal with this growth may have a material adverse effect on our business, financial condition, results of operations and prospects.

We are dependent upon the grant and maintenance of appropriate licenses and leases and if we are unable to meet all obligations necessary to maintain these licenses and leases it could have an adverse effect on our business, financial condition, results of operations and prospects.

Our properties are held in the form of licences and leases and working interests in licences and leases. If we or the holder of a licence or lease fails to meet the specific requirement of such licence or lease, such licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence or lease will be met. The termination or expiration of our licences or leases or the working interests relating to a licence or lease may have a material adverse effect on our business, financial condition, results of operations and prospects.

Seasonal and unexpected weather patterns may lead to a decrease in exploration and production activity which would adversely impact our operations.

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in our exploration and production activity during certain parts of the year, which would adversely impact our operations.

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We may be exposed to third-party credit risk through certain of our business arrangements, and non-payments or defaults by these third parties could have an adverse effect on our financial condition and results of operations.

We may be exposed to third party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our oil and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to us, such failures may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in an ongoing capital program, potentially delaying the program and the results of such program until we find a suitable, alternative partner.

Our business may suffer if we lose key management personnel which could result in us having to cease operations.

Our success depends in large measure on certain key management personnel. Competition for qualified personnel in the oil and natural gas industry is intense, and there can be no assurance that we will be able to attract, retain and replace all personnel necessary for the development and operation of our business. We do not have any key person insurance. The loss of the services of key management personnel may have a material adverse effect on our business, financial condition, results of operations and prospects, and could ultimately cause us to cease operations.

Reassessment of our income tax returns may prove to be detrimental to our business and financial condition.

We file all required income tax returns and believe they are in full compliance with the provisions of the Income Tax Act (Canada) and all other applicable provincial tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment, whether by re-characterization of exploration and development expenditures or otherwise, such reassessment may have an impact on current and future taxes payable and could be detrimental to our business and financial condition.

Our operations are subject to various litigation risks that could impact our financial condition and results of operations.

In the normal course of our operations, we may become involved in, named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, relating to personal injuries, property damage, property taxes, land rights, the environment and contract disputes. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to us and as a result, could have a material adverse effect on our assets, liabilities, business, financial condition and results of operations. Even if we prevail in any such legal proceeding, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from our business operations, which could adversely affect our financial condition.

Conflicts of interest may arise among our directors and officers as a result of their involvement with other oil and gas endeavors leading to the potential loss of personnel which could adversely affect our business, financial condition, results of operations and prospects.

There are potential conflicts of interest to which some of our directors and officers will be subject in connection with our operations. Some of our directors and officers are engaged and will continue to be engaged in the search of oil and gas interests on their own behalf and on behalf of other corporations. Richard Wyman, one of our directors, is also a director of Tower Resources Ltd. and is president and director of Northern Cross (Yukon) Ltd. Such associations may give rise to conflicts of interest from time to time that can be resolved only through our directors and officers exercising such judgment as are consistent with duties to their other business interests and ours. Such conflicts pose the risk that we may enter into a transaction on terms which place us in a worse position than if no conflict existed.

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Conflicts of interest, if any, that arise will be subject to and be governed by procedures prescribed by the Business Corporations Act (British Columbia) (the “BCBCA”) which requires a director or officer of a corporation who is a party to or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with us, to disclose his interest and to refrain from voting on any matter in respect of such contract unless otherwise permitted under the BCBCA.

Our properties and assets may be subject to aboriginal title and rights claims and if such a claim is successfully made in respect of our property or assets, it could adversely affect our business, financial condition, results of operations and prospects.

Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada. We are not aware that any claims have been made in respect of our properties and assets; however, if a claim arose and was successful, our ability to develop such property and assets could be impaired, or we may lose the such property and assets altogether, each of which could have an adverse effect on our business, financial condition, results of operations and prospects.

Restrictive regulation may limit our ability to market oil and natural gas and could adversely affect our business, financial condition, results of operations and prospects

Restrictive regulation implemented in the future could affect our ability to market oil and natural gas.

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 the markets, the value of refined products, the supply/demand balance, and other contractual terms. 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 licence requires a public hearing and the approval of the Governor in Council.

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 a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires a public hearing and the approval of the Governor in Council.

The governments of Alberta and British Columbia 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.

Subject to certain limitations under the North American Free Trade Agreement among the governments of Canada, U.S., and Mexico, effective on January 1, 1994 (“NAFTA”), Canada may impose export restrictions on oil and natural gas to the U.S.

Any inability to market our oil and natural gas due to restrictive regulations could adversely impact our ability to generate revenues from our petroleum assets, business, financial condition, result from operations and prospects.

Recently adopted accounting pronouncements may impact our future results and financial position.

Certain pronouncements have been issued by the IASB that are mandatory for accounting periods after December 31, 2014 or later periods. The new standards, amendments and interpretations, which are set forth under the heading “Item 5. Operating and Financial Review and Prospects – Future Accounting Pronouncements”, have not been early adopted in our financial statements. We cannot predict what impact, if any, the new guidance will have on our future results and financial position.

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Risks Relating to the Common Shares

We have never paid dividends and do not expect to do so in the foreseeable future.

We do not currently pay any dividends on our outstanding common shares. Payments of dividends in the future will be dependent on, among other things, our cash flow, results of operations and financial condition, the need for funds to finance ongoing operations and other considerations, as our board of directors (“Board of Directors”) considers relevant.

Future sales or issuances of equity securities could decrease the value of the common shares, dilute investors' voting power and reduce our earnings per share.

Our constating documents permit it to issue an unlimited number of common shares. Our goal is to continually increase our oil and gas reserves. To achieve that goal, we will require substantial amounts of capital in excess of funds from operations. We may choose to raise the required capital through the issuance of additional common shares or other securities convertible, exercisable or exchangeable for common shares. We may also make future acquisitions through the issuance of shares. We cannot predict the size of future issuances of equity securities or the size and terms of future issuances of debt instruments or other securities convertible, exercisable or exchangeable into common shares or the effect, if any, that future issuances and sales of our securities will have on the market price of the common shares. Any transaction involving the issuance of previously authorized but unissued shares, or securities convertible, exercisable or exchangeable into common shares, including exercises of presently outstanding options, would result in dilution to holders of common shares.

Re-sales of substantial amounts of the common shares, or the availability of such securities for re-sale, could adversely affect the prevailing market price for the common shares and dilute our earnings per share. A decline in the market price of the common shares could impair our ability to raise additional capital through the sale of securities should we have the desire to do so.

The market price of our common shares may be volatile and your investment in our common shares could suffer a decline in value.

The market price of common shares may fluctuate due to a variety of factors relative to our business, including announcements of new developments, fluctuations in our operating results, sales of the common shares in the marketplace, failure to meet analysts’ expectations, any public announcements made in regards to us, the impact of various tax laws or rates and general market conditions or the worldwide economy. In recent years, stock markets have experience significant price fluctuations, which have been unrelated to the operating performance of the affected companies. There can be no assurance that the market price of our common shares will not experience significant fluctuations in the future, including fluctuations that are unrelated to our performance, and volatility may affect your ability to sell our common shares at an advantageous price.

Since our officers and directors are located in Canada, it may be difficult to enforce any U.S. judgment for claims brought against us or our officers and directors.

We are organized under the laws of the Province of British Columbia, Canada, our assets are located in Canada and many of our officers and directors are residents of Canada. While a cross border treaty exists between the U.S. and Canada relating to the enforcement of foreign judgments, the process of such is cumbersome and in some cases has prevented the enforcement of judgments. As a result, while actions may be brought in Canada, it may be impossible to affect service of process within the U.S. on our officers and directors or to enforce against these persons any judgments in civil and commercial matters, including judgments under U.S. federal securities laws. In addition, a Canadian court may not permit an original action in Canada or enforce in Canada a judgment of a U.S. court based on civil liability provisions of U.S. federal securities laws.

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ITEM 4.                     INFORMATION ON THE COMPANY

A.                     History and Development of the Company General

Our head office is located at 2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9 and our registered office is located at 2900-550 Burrard Street, Vancouver, British Columbia, Canada V6C 0A3. Our telephone number is (604) 685-9255.

We were originally incorporated as “Pan-Cana Development Corp.” on March 6, 1978 under the Company Act (British Columbia) and changed our name to Hemisphere Development Corp. on May 18, 1978. We are currently organized pursuant to the BCBCA, which replaced the Company Act (British Columbia) in 2004. We are a corporation domiciled in British Columbia, Canada.

On December 10, 1999, the shareholders approved a consolidation of our issued and outstanding shares on the basis of one new share for every five old shares and our name was changed to “Northern Hemisphere Development Corp.” effective January 14, 2000, pursuant to the filing of the requisite documentation with the Registrar of companies for the Province of British Columbia.

On April 14, 2009, the shareholders approved a consolidation of our issued and outstanding shares on the basis of one new share for every five old shares and our name was changed to “Hemisphere Energy Corporation” effective April 24, 2009, pursuant to the filing of the requisite documentation with the Registrar of companies for the Province of British Columbia.

Our common shares are publicly traded on the TSX Venture Exchange (the “TSX-V”) as a Tier 1 issuer under the symbol “HME”.

General Development of the Business

We are a junior exploration and production, oil and gas company focused on developing core areas that provide low to medium risk drilling opportunities to increase production, reserves and cash flow. We have production in the Jenner and Atlee Buffalo areas of southeast Alberta and the Trutch area of northeast British Columbia. Our continued growth plan is through drilling existing prospects and executing strategic acquisitions and farm-ins.

Three Year History of Our Company

Ten months ended December 31, 2012

On June 14, 2012, we entered into a seismic option and farm-in agreement in the Jenner area which included initial obligations to acquire 3D seismic data and the option to drill a test well with the potential to acquire additional 3D seismic and drill additional wells to earn a maximum of 6.5 sections.

On November 16, 2012, we filed a Notice of Change in Year-End under National Instrument 51-102 - Continuous Disclosure Obligations ("NI 51-102") changing our fiscal year-end from February 28 to December 31 to better align financial reporting with the calendar year and industry peers. The transition year from March 1, 2012 to December 31, 2012 included reporting the nine months ended November 30, 2012, followed by the ten months ended December 31, 2012.

On December 20, 2012, we closed the first tranche of a non-brokered private placement resulting in the issuance of 1,829,300 units for gross proceeds of $1,189,045. Each unit consisted of one common share and one-half of a non-transferable warrant entitling the holder to purchase one common share at the price of $0.90 until December 20, 2013.

During the year, we successfully drilled eight oil wells (7 horizontal and 1 vertical). We also expanded our landholdings through Crown land sales, acquiring 2.25 sections (1,440 acres) in southeast Alberta. Existing facilities at Jenner were upgraded, adding a heated free-water-knockout separator for greater fluid handling capacity and reduction of operating costs.

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Fiscal year ended December 31, 2013

On January 25, 2013, we closed the second and final tranche of a non-brokered private placement resulting in the issuance of 86,900 units for gross proceeds of $56,485. Each unit consisted of one common share and one-half of a non-transferable warrant entitling the holder to purchase one common share at the price of $0.90 until January 25, 2014.

On April 24, 2013, we increased our credit facility from $5.5 million to $9.5 million (the "Credit Facility") as a result of reserve additions and production increases from our 2012 drilling activity.

On May 14, 2013, we successfully graduated to Tier 1 on the TSX-V. Tier 1 is the premier tier and is reserved for the most advanced issuers with the most significant financial resources on the TSX-V.

On October 16, 2013, we entered into a formal letter of intent with an intermediate Canadian producer to purchase certain oil and gas assets in the Atlee Buffalo area of southeast Alberta. This acquisition included 100% working interest in 8.25 sections of contiguous land spanning two large Glauconitic oil pools at a cost of $3.35 million and an effective date of June 1, 2013. This acquisition subsequently closed on November 18, 2013 and was funded by the Credit Facility, which was increased to $10.5 million contemporaneously with the closing of the acquisition.

On December 10, 2013, we closed a Bought Deal Equity Financing (the "2013 Financing") with a syndicate of underwriters for aggregate gross proceeds to us of $4.3 million to accelerate our capital program focused on Jenner and the newly acquired Atlee Buffalo property. The 2013 Financing resulted in the issuance of 4,182,550 units, comprised of one common share and one half of one warrant entitling the holder to purchase one common share at the price of $0.75 until December 10, 2014, and 3,077,000 common shares issued on “CEE flow-through” basis.

During 2013, we successfully drilled two horizontal oil wells in North Jenner. We also expanded our landholdings through Crown land sales, acquiring 13.75 sections (8,800 acres) in southeast Alberta. We upgraded our main oil battery by increasing our water handling capacity and debottlenecking our oil processing system as a means to optimize fluid rates at a number of existing wells and increase base oil production.

Fiscal year ended December 31, 2014

On March 13, 2014, we announced our Board of Directors approved the adoption of an Advance Notice Policy (the "Policy"). The purpose of the Policy is to: (i) facilitate an orderly and efficient annual general or, where the need arises, special meeting, process, (ii) ensure that all shareholders receive adequate notice of the director nominations and sufficient information regarding all director nominees, and (iii) allow shareholders to register an informed vote after having been afforded reasonable time for appropriate deliberation. The Policy was ratified by our shareholders at our annual general and special meeting held June 6, 2014.

On May 14, 2014, we closed a Bought Deal Equity Financing (the "2014 Financing") with a syndicate of underwriters for aggregate gross proceeds of $10.0 million to accelerate our capital program focused on Atlee Buffalo and Jenner. The 2014 Financing resulted in the issuance of 13,333,500 common shares.

On September 9, 2014, we announced the promotion of Mr. Ian Duncan from Vice President of Engineering to Chief Operating Officer and the appointment of Ms. Ashley Ramsden-Wood to Vice President of Engineering.

On October 7, 2014, we appointed Mr. Richard Wyman to the Board of Directors.

Effective November 28, 2014, we successfully increased the Credit Facility to $15.0 million as a result of the drilling activities and production growth from our 2014 capital program.

During the year, we successfully drilled 10 horizontal oil wells in Atlee Buffalo, two horizontal oil wells in Jenner, and one vertical test well in Jenner. We expanded our landholdings through Crown land sales acquiring 2,560 hectares in southeast Alberta. We installed a solution gas compressor at our main production facility in Jenner to increase volume through-put. We also acquired 3D seismic in each of the Atlee Buffalo and Jenner areas.

Financings

In addition to production revenue, we have financed operations through funds from loans, private placements of common shares, bought deal equity financings of common shares, common shares issued for property and shares issued upon exercise of stock options and share purchase warrants. See the table and accompanying notes under the heading “Item 10.A. Share Capital – Common Shares” which summarizes our issuances of common shares for the past three fiscal years.

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Capital Expenditures

We are focused on developing core areas that provide low to medium risk drilling opportunities to increase production, reserves and cash flow. Our continued growth plan is through drilling existing prospects and executing strategic acquisitions and farm-ins.

Past Capital Expenditures

The following table sets forth our principal capital expenditures and divestitures since the beginning of our last three financial years to December 31, 2014.

Notes:

During the year ended December 31, 2014, we successfully drilled 10 horizontal oil wells in Atlee Buffalo, two horizontal oil wells in Jenner, and one vertical test well in Jenner. We also completed the construction of two multi-well batteries and multiple pipelines in Atlee Buffalo, various equipment upgrades and replacements and the installation of a solution gas compressor at the main production facility in Jenner. During the year, we closed an acquisition in the Atlee Buffalo area for proceeds of $510,000 which included an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to our existing land base. We also expanded our landholdings through Crown land sales acquiring 7,520 acres in southeast Alberta. Lastly, we shot two 3D seismic surveys in the Jenner and Atlee Buffalo areas to evaluate future drilling locations and reserve potential.

These capital expenditures were funded by our credit facility, cash flows from our oil and natural gas and a bought-deal equity financing which closed on May 14, 2014 for aggregate gross proceeds of $10,000,125.

During the year ended December 31, 2013, we drilled two new wells in north Jenner and built and upgraded infrastructure in the Jenner area. The infrastructure included pipelines for new well and upgrades to our main Jenner battery. The upgrades included an increase in fluid handling capacity and the installation of a solution gas sweetening tower, which allows us to sell our gas. We also completed a property acquisition of oil and gas assets in the Atlee Buffalo area of southeast Alberta from an intermediate Canadian producer effective June 1, 2013.

During the ten months ended December 31, 2012, we drilled and completed eight wells in the Jenner area and built infrastructure at our main Jenner battery. The infrastructure included pipelines for new wells and upgrading our main production facility with a new water disposal pump and heated free-water-knockout separator to allow for greater fluid handling capacity.

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The following table sets forth additions to property and equipment and exploration and evaluation assets.

Reconciliation

The following table provides reconciliation from total capital expenditures to the cash flows used for equipment and resource properties for the twelve months ended December 31, 2014, twelve months ended December 31, 2013 and ten months ended December 31, 2012.

Notes:

Present capital expenditures

We currently have no capital expenditure programs in progress and have delayed any future capital expenditure programs subject to improvements in market conditions and commodity prices. See the discussion under the heading “Item 6.B Liquidity and Capital Resources”.

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B.                     Business Overview

General

We are a junior exploration and production, oil and gas company focused on developing core areas that provide low to medium risk drilling opportunities to increase production, reserves and cash flow. We have production in the Jenner and Atlee Buffalo areas of southeast Alberta and the Trutch area of northeast British Columbia. Our continued growth plan is through drilling existing prospects and executing strategic acquisitions and farm-ins.

Operations and Principal Activities

Our operations and principal activities consist of the exploration for and production of oil and natural gas.

Daily Production

The following table sets forth our average daily production for the three months ended December 31, 2014 and December 31, 2013, and the years ended December 31, 2014 and December 31, 2013.

The increases in oil production for the three and twelve months ended December 31, 2014 can be attributed to the successful development of our Atlee Buffalo and Jenner areas which resulted in twelve new producing oil wells during the year, four of which came on in the fourth quarter of 2014. Gas production increased in 2014 as a result of higher gas volumes being realized from the Atlee Buffalo wells and the installation of a solution gas compressor at the Jenner facility which has increased gas volume throughput.

Summary of Operations Highlights

The following table sets forth our production, average realized prices and revenue for each of the last three fiscal years.

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Marketing and Customers

We market oil and natural gas production from our properties. We sell oil and natural gas to purchasers at market prices. Some of the our natural gas contracts have terms of greater than twelve months and all of our oil contracts have terms of twelve months or less. We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. The market for our oil and natural gas production is well-established. We have no export sales.

Commodity Price Environment

Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The market for oil and natural gas is beyond our control and prices are difficult to predict. Please see the discussion under the heading “Item 5.D. Trends.”

Seasonality

The exploration for and development of oil and natural gas reserves is dependent on access to areas where production is to be conducted. We have properties in Alberta and British Columbia which are accessible by heavy equipment in winter only when the ground is frozen, typically between December to early April. For this reason drilling and pipeline construction ceases over the remainder of the year, limiting growth to winter only. Production operations continue year round in these areas once production is established. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.

In addition, the demand for, and the price of, natural gas increases during the colder winter months and decreases during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Crude oil and the demand for heating oil are also impacted by seasonal factors, with generally higher prices in the winter. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Extreme cold weather may result in sharp increases in the price paid to producers for their production of natural gas.

Human Resources

As at December 31, 2014, we had eight full-time head office employees and one full-time field employee. Additionally, we had five part-time consultants and two full-time field contractors.

Competition

The oil and gas industry is competitive in all its phases. We compete 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. Our competitors include resource companies that have greater financial resources, staff and facilities than us. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. We believe that our competitive position is equivalent to that of other oil and gas issuers of similar size and at a similar stage of development. See the information under the heading “Item 3.D. Risk Factors – Competition in the oil and natural gas industry is intense, and many of our competitors have greater resources than us which can increase competitive pressures and could have an adverse effect on our business, financial condition, results of operations and prospects”.

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Specialized Skill and Knowledge

We rely on specialized skills and knowledge to gather, interpret and process geophysical data, operate production facilities and numerous additional activities required to produce oil and natural gas. We have employed a strategy of contracting consultants and other service providers to supplement the skills and knowledge of our permanent staff in order to provide the specialized skills and knowledge to undertake our oil and natural gas operations effectively.

Government Regulations

Provincial Royalties and Incentives

General

Other than relatively small amounts held by private parties and First Nations, natural resources in Canada are owned by each Province, respectively. As such, royalties fall primarily under provincial jurisdiction. Provincial royalty regimes are a significant factor in the profitability of crude oil, natural gas liquids, sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties.

Provincial Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of 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.

Occasionally, the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays, and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Generally, royalty holidays and reductions reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and increase the net income and funds from operations of such producers.

Alberta

In Alberta, producers of oil and natural gas from Crown lands are required to pay annual rental payments, currently at a rate of $3.50 per ha, and make monthly royalty payments in respect of oil and natural gas produced.

Under the current “Alberta Royalty Framework” (“ARF”), royalty rates for oil and natural gas are set by a single sliding rate formula which is applied monthly using separate variables to account for production rates and market prices. The maximum royalty payable under the ARF for oil is 40%, and the maximum royalty payable for natural gas is 36%. The Government of Alberta also levies royalties on volumes of propane, butane, pentanes plus, bitumen and sulphur produced from Crown lands.

There are several incentive programs currently in effect to stimulate oil and gas investment in Alberta. The Natural Gas Deep Drilling Program provides royalty incentives for deep natural gas wells. A new-well incentive program applies to wells beginning production of conventional oil and natural gas and provides for a maximum 5% royalty rate for the first 12 months of production, up to a maximum of 50,000 barrels or 500 MMcf of natural gas. The Emerging Resource and Technologies Initiative is intended to accelerate technological development and facilitate the development of unconventional resources and applies similar 5% royalty rates to horizontal gas and oil wells, coal bed methane wells and shale gas wells. An Enhanced Oil Recovery program encourages the injection of fluids such as hydrocarbons, carbon dioxide, nitrogen, chemicals and other approved substances for the recovery of additional oil.

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Producers of oil and natural gas from freehold lands in Alberta are required to pay a freehold mineral tax levied by the Government of Alberta on the value of oil and natural gas production from non-Crown lands. The freehold mineral tax is levied on an annual basis on calendar year production using a formula that takes into consideration, among other things, the volume of monthly production, a specified rate of tax for both oil and gas and the percentages that the owners hold in the title. On average, the tax levied is 4% of revenues reported from fee simple mineral title properties.

British Columbia

Producers of oil and natural gas from Crown lands in British Columbia are required to pay annual rental payments with respect to the Crown leases (currently at a rate of $7.50 per ha), and make monthly payments in respect of royalties and freehold production taxes due in respect of oil and gas produced from Crown and freehold lands.

The amount payable as a royalty in British Columbia in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month, and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (“old oil”), between October 31, 1975, and June 1, 1998 (“new oil”), or after June 1, 1998 (“third-tier oil”). The royalty rates are calculated in three stages, which take into account the vintage of the oil, if the oil produced has already been sold and any royalty exempt value applicable. Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production or 11,450 m3 produced, whichever comes first; and the royalties for third-tier oil are the lowest reflecting the higher costs of exploration and extraction that the producers would incur.

The royalty payable on natural gas produced from British Columbia Crown lands is determined by a sliding scale based on a reference price, which is the greater of the average net price obtained by the producer, and a prescribed minimum price. For non-conservation gas (not produced in association with oil), the royalty rate depends on the date of acquisition of the oil and natural gas tenure rights and the spud date of the well and may also be impacted by the select price, a parameter used in the royalty rate formula to account for inflation. Royalty rates are fixed for certain classes of non-conservation gas when the reference price is below the select price. Conservation gas is subject to a lower royalty rate than non-conservation gas as an incentive for the production and marketing of natural gas, which might otherwise have been flared.

The Government of British Columbia has several royalty credit and royalty reduction programs intended to increase the competitiveness of low productivity natural gas wells, including the Deep Royalty Credit Program, the Deep ReEntry Royalty Credit Program, the Deep Discovery Royalty Credit Program, the Coalbed Gas Royalty Reduction and Credit Program, the Marginal Royalty Reduction Program, the Ultra-Marginal Royalty Reduction Program, and the Net Profit Royalty Reduction Program.

Oil produced from an oil well that is located on either Crown or freehold land and completed in a new pool discovered subsequent to June 30, 1974 may also be exempt from the payment of a royalty for the first 36 months of production or 11,450 m3 of production, whichever occurs first.

The Government of British Columbia also maintains an Infrastructure Royalty Credit Program which provides royalty credits for up to 50% of the lesser of the estimated completion cost and the completion cost of certain approved road construction or pipeline infrastructure projects intended to improve, or make possible, the access to new and underdeveloped oil and gas areas.

The Petroleum and Natural Gas Royalty and Freehold Production Tax Regulation was amended effective April 1, 2013 to provide for a 3% minimum royalty on affected wells with deep well/deep re-entry credits. The 3% minimum royalty applies to deep wells when the net royalty payable would otherwise be zero for a production month.

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Producers of oil and natural gas from freehold lands in British Columbia are required to pay monthly freehold production taxes to the Government of British Columbia. For oil, the level of the freehold production tax is based on the volume of monthly production. For natural gas, the freehold production tax is determined using a sliding scale formula based on the reference price similar to that applied to natural gas production on Crown land, and depends on whether the natural gas is conservation gas or non-conservation gas.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. 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. Oil and natural gas located in such provinces can also be privately owned 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 Governments of Alberta and British Columbia has implemented legislation providing for the reversion to the Crown of mineral rights of deep, non-productive geological formations at the conclusion of the primary term of a lease or license. On March 29, 2007, British Columbia’s policy of deep rights reversion was expanded 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.

In Alberta, for leases and licenses issued subsequent to January 1, 2009, shallow rights reversion is applied at the conclusion of the primary term of the lease or license. Although Alberta Energy had previously announced that shallow rights reversions would be implemented for leases and licences that had been granted prior to January 1, 2009 by the service of reversion notices at the end of their primary terms, in April 2013, it communicated to industry that it was deferring the service of such notices indefinitely.

Environmental and Climate Change Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation, which may be amended from time to time. Such legislation provides for restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material, the suspension or revocation of necessary licenses and permits, and civil liability for pollution damage.

Alberta

Environmental legislation in Alberta is consolidated in the Environmental Protection and Enhancement Act (Alberta) (the “EPEA”) and the Oil and Gas Conservation Act (Alberta) (the “OGCA”). The EPEA and OGCA impose environmental standards, reporting and monitoring obligations, and penalties for non-compliance.

The Province of Alberta has a single regulator for upstream oil and gas, oil sands and coal development activity, the Alberta Energy Regulator (the “AER”). The objective is 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. On June 17, 2013, the AER assumed the functions and responsibilities of the former Energy Resources Conservation Board, including those found under the Oil and Gas Conservation Act (“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 (Alberta). On March 29, 2014, the AER assumed the energy related functions and responsibilities of AESRD in the areas of environment and water under the EPEA and the Water Act (Alberta), 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 restructuring of the agencies implementing regulation has not been accompanied by substantive amendments to the underlying Provincial Government policy or legislation.

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The Alberta Land Use Framework (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 Government of Alberta. It calls for the development of 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”) was proclaimed in force in Alberta on October 1, 2009 and provides the legislative authority to implement the policies contained in the ALUF. Regional plans established pursuant to the ALSA 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, leases, licenses, 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.

The first regional plan under the ALSA, the Lower Athabasca Regional Plan (the “LARP”), came into effect on September 1, 2012. The LARP covers the northeast corner of Alberta and the entirety of the Athabasca oil sands region. In July 2014, the Government of Alberta approved the South Saskatchewan Regional Plan (the “SSRP”) which covers approximately 83,764 square kilometres and includes 45% of the provincial population. The SSRP was released in draft form in 2013. 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.

The Government of Alberta enacted the Climate Change and Emissions Management Act (the “CCEMA”) on December 4, 2003, amending it 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 similar to the Updated Action Plan and aims for a 50% reduction from 1990 emissions relative to GDP by 2020. Facilities in Alberta emitting more than 100,000 tonnes of carbon dioxide equivalent a year are subject to compliance with the CCEMA. As at year-end 2014, we did not have an interest in any facilities in Alberta that emit more than 100,000 tonnes of carbon dioxide equivalent per year.

British Columbia

In British Columbia, the Oil and Gas Activities Act (the "OGAA") governs conventional oil and gas producers, shale gas producers and other operators of oil and gas facilities. Under the OGAA, the British Columbia Oil and Gas Commission (the "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 Commission is required to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity. In addition, the Petroleum and Natural Gas Act (British Columbia) requires proponents to obtain various approvals before undertaking exploration or production work. 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.

In February 2008, the Government of British Columbia announced a revenue-neutral carbon tax that took effect July 1, 2008. This tax is consumption-based and applied at the time of retail sale or consumption of virtually all fossil fuels purchased or used in British Columbia. The current tax level is $30 per tonne of carbon dioxide equivalent. British Columbia is currently undertaking a comprehensive review of the carbon tax, and may or may not make changes to its carbon tax regime. In order to make the tax revenue-neutral, British Columbia has implemented tax credits and reductions in order to offset the tax revenues that the Government of British Columbia would otherwise receive from the tax.

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On April 3, 2008, British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act (the "Cap and Trade Act") which received royal assent on May 29, 2008 and partially came into force by regulation of the Lieutenant Governor in Council. Unlike the emissions intensity approach taken by the federal government and the Government of Alberta, the Cap and Trade Act establishes an absolute cap on GHG emissions. Although more specific details of British Columbia's cap and trade plan have not yet been finalized, on January 1, 2010, new reporting regulations came into force requiring all British Columbia facilities emitting over 10,000 tonnes of carbon dioxide equivalents per year to begin reporting their emissions. Facilities reporting emissions greater than 25,000 tonnes of carbon dioxide equivalents per year are required to have their emissions reports verified by a third party. Regulations pertaining to proposed offsets and emissions trading remain in development. As at year-end 2014, we did not have an interest in any facilities in British Columbia that emit more than 25,000 tonnes of carbon dioxide equivalent per year.

Federal

Pursuant to the Jobs, Growth and Long-term Prosperity Act (the “Prosperity Act”) which received Royal Assent on June 29, 2012, 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 into force on July 6, 2012. The changes to the environmental legislation under the Prosperity Act are intended to provide for more efficient and timely environmental assessments of projects that previously had been subject to overlapping legislative jurisdiction.

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 which will be applied to regulated sectors on either a facility-specific, sector-wide or company-by-company basis. Facility-specific targets apply to the upstream oil and gas, oil sands, petroleum refining and natural gas pipelines sectors. Unless a minimum regulatory threshold applies, all facilities within a regulated sector will be subject to the emissions intensity targets.

Although draft regulations for the implementation of the Updated Action Plan were intended to become binding on January 1, 2010, only regulations pertaining to carbon dioxide emissions from coal-fired generation of electricity have been enacted to date. Further, 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. As a result, it is unclear to what extent, if any; the proposals contained in the Updated Action Plan will be implemented.

Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting legislative requirements, it is not currently possible to predict either the nature of those requirements or the impact on us and our operations and financial condition at this time.

The North American Free Trade Agreement

Canada is free to determine under NAFTA whether exports of energy resources to the U.S. or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon 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 voluntary measures which only restrict the volume of exports; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export price requirements, any prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates disciplines on regulators to ensure fair implementation of any regulatory changes, to minimize disruption of contractual arrangements and to avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.

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C.                     Organizational Structure

We are not part of a group and do not have any subsidiaries.

D.                     Property, Plants and Equipment

Head Office

Our head office is located in rented premises of approximately 4,000 square feet at 2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9. We began occupying these premises on June 1, 2014. The monthly base rent is $15,936.

Oil & Gas Properties

Core Assets

We have two producing core assets located in southeast Alberta.

Jenner

Jenner is located approximately 200 kilometers southeast of Calgary. We first entered the area in 2010 and own 28,360 gross acres (25,650 net acres) as of December 31, 2014. The property has eight oil pools defined by 3D seismic and 30 identified locations. We have two, owned and operated, oil processing and water disposal facilities in Jenner with the capability for expansion.

Atlee Buffalo

Atlee Buffalo is located 220 kilometers southeast of Calgary. We made our first acquisition in the area in late 2013 and own 7,360 gross acres (7,192 net acres) as of December 31, 2014. The property has two oil pools delineated by vertical wells and 65 identified locations. Based on internal mapping, Atlee Buffalo has high original-oil-in-place and low current recovery factors.

Non-core Assets

Trutch (Tommy Lakes) is located 250 kilometres northwest of Fort St. John, British Columbia. We own 35,612 gross acres (21,525 net acres) as of December 31, 2014, which includes non-operated wells producing liquids rich natural gas.

We also have various working interests in non-core assets located in southern Alberta.

Reserve Data

The standards of the SEC require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, our results have been calculated utilizing the 12-month average price for each of the years presented.

In 2013, we retained McDaniel & Associates Consultants Ltd. (“McDaniel”), independent petroleum engineering consultants based in Calgary, Alberta, to evaluate our properties. Our reserves reports prepared by McDaniel were completed March 11, 2015 and May 27, 2014 and have effective dates of December 31, 2014 and December 31, 2013, respectively (together the “McDaniel Reports”). The McDaniel Reports evaluated our oil, NGL and natural gas reserves.

We have also retained Sproule Associates Limited (“Sproule”), independent petroleum engineering consultants, based in Calgary, Alberta, to evaluate our properties. Our reserves reports prepared by Sproule were completed September 12, 2014 and have an effective date of December 31, 2012 (the “Sproule Report”). The Sproule Report evaluated our proved crude oil, natural gas and NGL reserves.

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All properties evaluated are in Canada and specifically in Alberta and British Columbia.

The tables below are a summary of the oil, NGL and natural gas reserves attributable to our properties and the net present values of future net revenue attributable to such reserves as evaluated in the McDaniel Reports and Sproule Report based on 12 month SEC compliant constant pricing. The tables summarize the data contained in the McDaniel Reports and Sproule 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 values 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, future capital expenditures and well abandonment costs for only those wells assigned reserves by McDaniel and Sproule. It should not be assumed that the undiscounted or discounted net present values of future net revenue attributable to reserves estimated by McDaniel and Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized below. The recovery and reserve estimates of oil, NGL and natural gas reserves provided are estimates only. Actual reserves may be greater than or less than the estimates provided.

The McDaniel Reports and the Sproule Report are based on certain factual data we have supplied to McDaniel and Sproule and on McDaniel’s and Sproule’s 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) we have supplied to McDaniel and Sproule. McDaniel and Sproule accepted this data as presented and neither title searches nor field inspections were conducted.

The recovery and reserve estimates on our properties described in this Form 20-F are estimates only. The actual reserves on our properties may be greater or less than those calculated. See the information under “Item 3.D. Risk Factors – Our reserve estimates depend on many assumptions that may prove to be inaccurate and are subject to revision based on production history, and material inaccuracies in the reserve estimates or the underlying assumptions, or revision based on production history, may adversely affect the quantities and present value of our reserves”.

Controls Over Reserve Report Preparation

Our reserve estimates reports as of December 31, 2014 and December 31, 2013 were prepared by independent qualified reserve evaluators, McDaniel, and our reserve estimates report as of December 31, 2012 was prepared by independent qualified reserve auditors, Sproule. To ensure accuracy and completeness of the data prior to disclosure of reserve estimates to the public, our Reserves Committee does the following in accordance with applicable laws: (1) reviews our procedures for providing information to the independent qualified reserve evaluators, (2) meets with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the qualified reserves evaluators to report without reservation, (3) reviews the reserves data with management and the independent qualified reserves evaluator. If the Reserves Committee is satisfied with results of its evaluation it will approve the content of our reserve disclosure. If any concerns arise in the reserve committee’s evaluation, the reserves committee will work with management and the independent qualified reserves evaluators to resolve the issues before disclosure of reserves is made public.

As at December 31, 2014, our Reserves Committee was composed of Bruce McIntyre (Chairman), Don Simmons, Gregg Vernon, and Richard Wyman. As at the date of this Form 20-F, our Reserves Committee was composed of Bruce McIntyre (Chairman), Don Simmons, Gregg Vernon, and Richard Wyman. Please see the biographical information on the members of the Reserves Committee under the heading “Item 6.A. Directors and Senior Management”.

Summary of Oil and Gas Reserves as of Fiscal Year-End Based on Average Fiscal Year Prices

Notes:

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Total Proved Reserves

The following table compares estimated proved reserves and associated present value, discounted at an annual rate of 10% of the future revenue before income tax as at December 31, 2014.

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The following table provides the reconciliation to standardized measure. The information is in thousands of Canadian dollars.

Notes:

At December 31, 2012, we had six proved undeveloped locations booked. In the twelve months ended December 31, 2013, no proved undeveloped reserves were converted to proved developed reserves.

For the fiscal year ended December 31, 2013, an additional seven proved undeveloped locations were booked on new lands and offsetting discoveries in the 2012 fiscal year. Two of the previously booked proved undeveloped locations were taken off the books, bringing the total proved undeveloped booked locations to eleven at December 31, 2013.

During 2014, 13 wells were drilled, of which five had previously been booked. These five wells were converted from proved undeveloped reserves to proved developed reserves. One previously booked location was taken off the books, and an additional 13 were added. As of December 31, 2014, a total of 18 locations remain booked for future development.

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No proved undeveloped reserves have been booked for more than five years.

Oil and Gas Production, Production Prices and Production Costs

The following table sets forth our total net oil and gas production for the twelve months ended December 31, 2014, twelve months ended December 31, 2013, and ten months ended December 31, 2012. Production came from our properties located in British Columbia and Alberta, Canada.

Note:

The following table sets forth the average prices we received for our production for the twelve months ended December 31, 2014, twelve months ended December 31, 2013, and ten months ended December 31, 2012.

Note:

The following table sets forth the average production costs, including transportation costs, per unit of production for the twelve months ended December 31, 2014, twelve months ended December 31, 2013, and ten months ended December 31, 2012.

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Note:

Drilling and Other Exploratory and Development Activities

During the last three fiscal years, we drilled the following wells in Canada.

Note:

Delivery Commitments

We have no current delivery commitments for either oil or natural gas.

Present Activities

Atlee Buffalo, Alberta

During 2014 we executed three successful drilling programs in Atlee Buffalo that resulted in 10 horizontal oil wells being placed on production. The addition of these wells in 2014 resulted in significant production, reserve and cash flow growth over the previous year. We also shot a substantial 3D seismic program in Atlee Buffalo during the fourth quarter of 2014 to assist in drilling future locations within the area.

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We closed an acquisition in the Atlee Buffalo area which included an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to our existing land base. Additionally, we expanded our landholdings during the year through Crown land sales, acquiring a total of 1.75 sections (1,120 acres) in the surrounding Atlee Buffalo area.

Jenner, Alberta

During 2014, we successfully drilled two horizontal oil wells and one vertical exploration well in Jenner. We also completed a 3D seismic survey in the fourth quarter of 2014.

We expanded our landholdings during the year through Crown land sales, acquiring a total of 10 sections (6,400 acres) in the surrounding Jenner area. We also completed a small acquisition, which included 1.75 sections (1,120 acres) in the Jenner area.

Oil and Gas Properties and Wells

As of December 31, 2014, we had 98 gross (85.7 net) producing or shut-in oil or natural gas wells.

Oil and Gas Properties and Wells

The following table sets forth information for our interest in oil and gas properties as at December 31, 2014 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which a working interest is owned. Net acres are the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

As at December 31, 2014, our developed and undeveloped acres are set forth in the following table.

Our net undeveloped acres as at December 31, 2013, together with expiries for the period from 2015 to 2017 and thereafter, is set forth in the following table.

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ITEM 4A.                 UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 5.                     OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following discussion and analysis of our operating results and financial condition should be read in conjunction with our audited annual financial statements for the years ended December 31, 2014 and December 31, 2013, and related notes included under the heading “Item 18. Financial Statements”.

Our financial statements for the fiscal years ended December 31, 2014 and December 31, 2013, and ten months ended December 31, 2012 are presented in Canadian dollars and have been prepared in accordance with IFRS as issued by the IASB.

Certain forward-looking statements are discussed in this Item 5 with respect to our activities and future financial results. These are subject to risks and uncertainties that may cause projected results or events to differ materially from actual results or events. Readers should also read the “Cautionary Note Regarding Forward-Looking Statements” and the risk factors under the heading “Item 3.D. Risk Factors”.

Critical Accounting Judgments and Estimates

The preparation of these financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that may affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may materially differ from these estimates. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.

The following are the accounting policies that are subject to such judgments and the key sources of estimation uncertainty that we believe could have the most significant impact on the reported results and financial position.

Critical accounting judgments

Reserves

The estimate of oil and natural gas reserves is integral to the calculation of the amount of depletion charged to the statements of loss and comprehensive loss and is also a key determinant in assessing whether the carrying value of any of our development and production assets have been impaired. Changes in reported reserves can impact asset carrying values due to changes in expected future cash flows.

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Our Proved and Probable reserves are evaluated and reported on by independent reserve engineers at least annually in accordance with Canadian Securities Administrators’ National Instrument 51-101 Standards of Disclosure of Oil and Gas Activities ("NI 51-101"). Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is 90% 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. Reserve estimation is based on a variety of factors including engineering data, geological and geophysical data, projected future rates of production, commodity pricing and timing of future expenditures, all of which are subject to significant judgment and interpretation.

Identification of cash-generating units ("CGUs")

Our assets are aggregated into CGUs for the purpose of calculating impairment. CGUs are based on an assessment of the unit’s ability to generate independent cash inflows. The determination of these CGUs was based on management’s judgment in regards to shared infrastructure, geographical proximity, petroleum type and similar exposure to market risk and materiality.

Recoverability of asset carrying values

At each reporting date, we assess our petroleum and natural gas properties and exploration and evaluation assets for possible impairment, to determine if there is any indication that the carrying amounts of the assets may not be recoverable. An assessment is also made at each reporting date to determine whether there is an indication that previously recognized impairment losses no longer exist or have decreased. Determination as to whether and how much an asset is impaired, or no longer impaired, involves management estimates on highly uncertain matters such as future commodity prices, discount rates, production profiles, operating costs, future capital costs and reserves. Changes in circumstances may impact these estimates which may impact the recoverable amount of assets. Any change in the impairment loss or reversal of impairment loss could have a material financial impact in future periods but future depletion expense would be impacted as a result.

Critical accounting estimates

Decommissioning obligations

Decommissioning costs will be incurred many years into the future. Amounts recorded for decommissioning obligations require the use of management’s best estimates of future decommissioning expenditures, expected timing of expenditures and future inflation rates. The estimates are based on internal and third party information and calculations are subject to changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions, and changes in clean up technology. Actual costs and outflows can differ from estimates and may have a material impact on earnings or financial position. For more information on our decommissioning obligations, see Note 10 of the aforementioned financial statements.

Business combination

Business combinations are accounted for using the acquisition method. Under this method, management makes estimates of the fair value of assets acquired and liabilities assumed which includes assessing the value of petroleum and natural gas properties based upon the estimation of recoverable quantities of Proved and Probable reserves being acquired.

Share-based payments

We measure the cost of our share-based payments to directors, officers, employees and consultants by reference to the fair value of the equity instruments using the Black-Scholes option pricing model at the date they are granted. The assumptions used in determining fair value include: expected life of the options, risk-free rates of return and stock price volatility. Changes to assumptions may have a material impact on the amounts presented. For more information on our share-based payments, see Note 13(b) of the aforementioned financial statements.

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Income taxes

Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly, affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.

New and Amended Adopted Accounting Standards

Effective January 1, 2014, we adopted the following accounting policies:

Future Accounting Pronouncements

The IASB International Financial Reporting Interpretations Committee (“IFRIC”) have issued pronouncements effective for accounting periods beginning on or after January 1, 2015. Only those which may have a significant impact on us are discussed below:

Guidance is provided on topics such as the point in which revenue is recognized, accounting for variable consideration, costs of fulfilling and obtaining a contract and various related matters. New disclosures about revenue are also introduced.

Applicable to our annual period beginning on January 1, 2017. We have not yet assessed the impact of this pronouncement.

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Applicable to our annual period beginning on January 1, 2018. We have not yet assessed the impact of this pronouncement.

Financial Instruments and Risk Management

Fair value estimates of financial instruments are made at a specific point in time, based on relevant information about financial markets and specific financial instruments. As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, changes in assumptions can significantly affect estimated fair values. Our financial instruments include accounts receivable, reclamation deposits, bank indebtedness, accounts payable and accrued liabilities.

The fair values of accounts receivable, reclamation deposits, bank indebtedness, accounts payable and accrued liabilities approximate their carrying values due to the short-term maturity of these financial instruments.

Our activities expose us to a variety of risks that arise as a result of our exploration, development, production and financing activities. The following provides information about our exposure to any risks associated with the oil and gas industry as well as our objectives, policies and processes for measuring and managing risk.

Business Risk

Oil and gas exploration and development involves a high degree of risk whereby many properties are ultimately not developed to a producing stage. There can be no assurance that our future exploration and development activities will result in discoveries of commercial bodies of oil and gas. Whether an oil and gas property will be commercially viable depends on a number of factors including the particular attributes of the reserve and its proximity to infrastructure, as well as commodity prices and government regulations, including regulations relating to prices, taxes, royalties, land tenure, land use, and environmental protection. The exact effect of these factors cannot be accurately predicted, and the combination of these factors may result in an oil and gas property not being profitable.

Credit risk

Credit risk is the risk of financial loss if a customer or counterparty to a financial instrument fails to meet its payment obligations. This risk arises principally from our receivables from joint operators and oil and natural gas marketers, and reclamation deposits. The credit risk associated with reclamation deposits is mitigated by ensuring these financial assets are placed with major financial institutions with strong investment-grade ratings by a primary ratings agency. The credit risk associated with accounts receivable is mitigated as we monitor monthly balances to limit the risk associated with collections. We do not anticipate any default. There are no balances past due or impaired.

Our maximum exposure to credit risk is set forth in the following table.

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We sell the majority of our oil production to a single oil marketer and, therefore, are subject to concentration risk which is mitigated by our policies and practices related to credit risk, as discussed above. Historically, we have never experienced any collection issues with our oil marketer.

Liquidity risk

Liquidity risk is the risk that we will not be able to meet our financial obligations as they come due. We manage liquidity risk by anticipating operating, investing and financing activities and ensuring that we will have sufficient liquidity to meet our liabilities when they become due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to us.

We prepare expenditure budgets on a quarterly and annual basis which are regularly monitored and updated when necessary in order to review debt forecasts and working capital requirements. All of our financial liabilities have contractual maturities of less than 90 days.

As at December 31, 2014, we had negative working capital of $11,644,609 (December 31, 2013 - $6,330,906), which includes bank indebtedness of $7,184,147 (December 31, 2013 - $4,500,000). We fund our operations through revenue and a demand operating credit facility. All of our financial liabilities have contractual maturities of less than 90 days.

Market risk

Market risk is the risk that changes in market prices, such as, foreign exchange rates, commodity prices, and interest rates will affect the value of the financial instruments. Market risk is comprised of interest rate risk, foreign currency risk, commodity price risk and other price risk.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. Borrowings under our credit facilities are subject to variable interest rates. A one percent change in interest rates would not have a material effect on net loss and comprehensive loss.

Foreign currency risk

Our functional and reporting currency is Canadian dollars. We do not sell or transact in any foreign currency, however commodity prices are largely denominated in US Dollars (“USD”), and as a result the prices that we receive are affected by fluctuations in the exchange rates between the USD and the Canadian dollar. The exchange rate effect cannot be quantified, but generally an increase in the value of the Canadian dollar compared to the USD will reduce the prices received for our crude oil and natural gas sales. We did not have any foreign exchange rate swaps or related contracts in place as at the date of this document.

Commodity price risk

Commodity prices for petroleum and natural gas are impacted by global economic events that dictate the levels of supply and demand, as well as the relationship between the Canadian dollar and the USD. Significant changes in commodity prices may materially impact our ability to raise capital. We have not entered into any commodity hedge contracts as at the date of this document.

Other price risk

Other price risk is the risk that the fair or future cash flows of a financial instrument will fluctuate due to changes in market prices, other than those arising from interest rate risk, foreign currency risk or commodity price risk. We are not exposed to significant other price risk.

A.                     Operating Results

Year ended December 31, 2014 compared to year ended December 31, 2013

1. Revenue

Total revenue for the year ended December 31, 2014 was $16,635,279, representing an increase of $6,062,080 (57%) over the comparable year of 2013, as outlined by commodity in the table below. This increase in revenue is consistent with the 48% growth in total production of 220 boe/d as a result of our drilling programs in the Atlee Buffalo and Jenner areas and the 7% increase in combined average realized price of $4.13/boe for the year.

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2. Royalties

Royalties for year ended December 31, 2014 increased by $1,109,845 to $3,008,377 over the comparable year of 2013. This change in royalties is further described below by oil and natural gas operations.

3. Production and Operating

Operating costs include all costs for gathering, processing, dehydration, compression, water processing, transportation and marketing of the oil, natural gas and NGLs, as well as additional costs incurred periodically for maintenance and repairs. Operating costs for the year ended December 31, 2014 were $4,351,248, which represents an increase of $1,284,074 over the comparable year of 2013. This change in operating costs is further described below by oil and natural gas operations.

Oil Operations

The average realized heavy oil price increased during the year ended December 31, 2014 to $73.87/bbl over the comparable year of 2013. This $2.68/bbl increase in our realized oil price, along with our increased production levels for the 2014 year, had a substantial impact on our oil revenues for the year ended December 31, 2014 which increased by $5,813,666 over the comparable year of 2013. This increase is a reflection of strong WTI pricing and a narrow Western Canadian Select ("WCS") oil differential in the first three quarters of 2014. Also, given that North American crude oil benchmark market prices are denominated in USD, a decrease in the value of the Canadian dollar compared to the USD in 2014 has had a positive impact on our average realized oil price and revenues for the year ended December 31, 2014.

Average oil royalties for the year ended December 31, 2014 increased by $1,086,804, or $0.61/bbl, over the comparable year of 2013. This increase can be attributed to six Jenner oil wells coming off of their royalty holiday in 2014 and that the majority of our 2014 production was from Jenner, which has the highest per boe royalty rate.

Oil operating costs for the year ended December 31, 2014 increased by $942,252 over the comparable year of 2013. This absolute increase in operating costs can be attributed to increases in production from the drilling of new wells. On a per boe basis, our operating costs decreased by $1.15/bbl during the year as a result of realized economies of scale as a result of drilling new wells in the year. We have also reduced the amount of produced water that is processed at third-party facilities, which are subject to processing fees, in order to reduce operating costs.

Oil transportation costs for the year ended December 31, 2014 increased by $312,052 or $0.26/bbl over the comparable year of 2013. This increase can be attributed to the addition of 10 new Atlee Buffalo horizontal wells during the 2014 year which have higher transportation costs associated with trucking production volumes to processing facilities and sales points.

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Natural Gas Operations

Our average realized natural gas price also increased during the year ended December 31, 2014 to $4.08/Mcf over the comparable year of 2013. This $0.63/Mcf increase in our realized natural gas price had a positive effect on our natural gas revenues for the year ended December 31, 2014 which increased by $286,895 over the comparable year of 2013.

Average natural gas royalties for the year ended December 31, 2014 increased by $23,041 over the comparable year of 2013. This increase can be attributed to the 119 Mcf/d increase in gas production as well as the 18% increase in our realized natural gas price for the period.

Natural gas operating expenses for the year ended December 31, 2014 increased by $15,760 over the comparable year of 2013. This increase can be attributed to higher natural gas volumes from Atlee Buffalo which is being processed at a third-party facility and subject to processing fees.

Natural gas transportation costs for the year ended December 31, 2014 increased by $14,010 over the comparable year of 2013. This increase can be attributed to the Atlee Buffalo wells drilled in the 2014 year which, compared to our Jenner wells, have higher gas production and transportation charges.

4. Exploration and Evaluation

Exploration and evaluation expense generally consists of certain geological and geophysical costs, expiry of undeveloped lands and costs of uneconomic exploratory wells. For the years ended December 31, 2014 and 2013, exploration and evaluation expenses were $190,887 and $116,006, respectively, representing an increase of $74,881.

5. Depletion and Depreciation

Depletion and depreciation expense for the year ended December 31, 2014 increased by $1,627,296 to $5,360,989 over the comparable year of 2013.

The significant increase in depletion expense is a result of a change in our accounting for depleting our petroleum and natural gas properties. With the acquisition of our core Jenner and Atlee Buffalo properties, the value of our Proved plus Probable reserves increased substantially. These acquisitions, in combination with our increased access to capital through additional equity financings and banking facilities, have expanded our ability to further the development of exploration assets and Probable reserves. As a result, we changed from using the unit-of-production method based solely on production volumes in relation to total estimated Proved reserves to now include total estimated Proved and Probable reserves.

6. General and Administrative

General and administrative expenses for the year ended December 31, 2014 were $2,654,943, which represents an increase of $777,567 over the comparable year in 2013. The general and administrative costs include share-based payments of $452,780 and $360,434 for the year ended December 31, 2014 and 2013 respectively. Gross general and administrative expenses increased by $870,621 for the year ended December 31, 2014, and we also captured capitalized overhead in the amount of $472,530 for the new wells drilled and capital projects completed in the year. The increase in gross general and administrative costs during the year ended December 31, 2014 can be attributed to increased investor relations activities of $62,048, consulting fees of $107,481, professional fees of $137,510, office relocation costs of $113,563 and staffing costs of $297,953.

We calculate our capitalized general and administrative costs monthly, based on the capital expenditures incurred in that month. This reflects the capital component of overhead costs applied for each well drilled and construction project at the following recovery rates:

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7. Impairment of Property and Equipment

The significant decline in crude oil and natural gas prices in the fourth quarter of 2014 was recognized as an indicator of impairment at year-end. We performed an impairment test on our petroleum and natural gas assets and it was determined that the carrying amount of three cash-generating units ("CGUs") exceeded their recoverable amount. Accordingly, we recognized an impairment charge of $2,702,925 for the year ended December 31, 2014 which represents an increase of $2,146,554 in impairment over the comparable 2013 year.

The recoverable amounts of the CGUs were determined with fair value less costs to sell based on expected future cash flows from Proved plus Probable reserve value, using discount rates specific to the underlying composition of assets residing in each CGU. The pre-tax discount rates ranged from 10% to 15% depending on the nature of the reserves. We also changed our impairment test to include Proved and Probable reserves of all properties to maintain consistency with our depletion policy.

8. Finance Expense

Finance expense for the year ended December 31, 2014 increased by $80,572 over the comparable year in 2013. This increase is primarily the result of the part XII.6 tax incurred on unspent flow-through expenditures and increased accretion expense for the year.

As part of finance expense, we recorded $11,889 in part X11.6 tax for the year ended December 31, 2014. This part XII.6 tax is accumulated on the unspent balance of flow-through expenditures at the end of the quarter. Our required obligation was to incur qualified expenditures of $2,000,050 by December 31, 2014 in connection with our flow-through private placement which closed on December 10, 2013.

Accretion expense represents the adjusted present value of our decommissioning obligations which include the abandonment and reclamation costs associated with wells and facilities. As part of finance expense, we recognized an increase in accretion expense of $60,263 to $66,776 for the year ended December 31, 2014. The increase is due to the increased decommissioning obligations associated with new wells acquired in 2014 as well as those new wells drilled in the Jenner and Atlee Buffalo areas. We also changed our estimate of decommissioning obligations by using the information as set by the Alberta Energy Regulator (“AER”) in Directive 011, as our primary source of estimating future abandonment and reclamation costs.

8. Flow-through Share Premium Recovery

In connection with the flow-through private placement completed on December 10, 2013, we have fulfilled our obligation to incur qualified expenditures of $2,000,050 by December 31, 2014. The qualified expenditures were spent on two 3D seismic programs in the Jenner and Altee Buffalo areas as well as the drilling of a vertical test well in Jenner. At December 31, 2014 the balance in flow-through premium liability has been reduced to nil and transferred to flow-through share premium recovery.

9. Gain on Disposition

We disposed of a vertical treater from our Jenner facility in the first quarter of 2014, which resulted in a small gain of $2,942 for the year ended December 31, 2014.

10. Deferred Tax Expense

We realized an income tax expense for the year ended December 31, 2014 in the amount of $129,552 as compared to an income tax recovery of $357,573 for year ended December 31, 2013.

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Year ended December 31, 2013 compared to the ten months ended December 31, 2012

Restatement of Previously Reported Results

We have restated certain financial information for the year ended December 31, 2013 (the "2013 Restatement") which has been disclosed in Note 4 of our audited annual financial statements for the year ended December 31, 2014.

The material changes included in the 2013 Restatement affect impairment, depletion, and decommissioning costs and will have a positive impact, significantly reducing the loss in December 2013 by $3.3 million from $3.8 million to $0.5 million.

As a result of the adjustment of impairment and depletion costs due to the effects of IFRS and a change in accounting policy applied retrospectively, our petroleum and natural gas interests increased by $4.0 million. In addition, we have incorporated the AER’s updated decommissioning directive, which resulted in an increase in decommissioning liability of $0.7 million. The 2013 Restatement affects only non-cash items and therefore has no impact on cash flow.

1. Revenue

For the twelve months ended December 31, 2013, total revenue increased by $2,697,476, or 34%, over the ten months ended December 31, 2012. This increase is consistent with the 14% growth in production as a result of our drilling programs in the Jenner area and the 6% increase in our average combined realized price.

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2. Royalties

Royalties for the twelve months ended December 31, 2013 increased by $526,649 over the comparable period of 2012 which can be attributed to the newly drilled oil wells in Jenner which are subject to Alberta Crown royalties and gross overriding royalties.

3. Production and Operating

Operating costs for the twelve months ended December 31, 2013 was $3,067,174, which is an increase of $1,220,643 over the comparable period of 2012. This increase in operating costs can be attributed to third party processing fees for our recently drilled wells in 2013. For 2014, we are negotiating reduced rates for the third party facility processing.

Oil Operations

Our average realized oil price increased during the twelve months ended December 31, 2013 to $71.19/bbl over the ten months ended December 31, 2012. This $4.43/bbl increase in our realized heavy oil price contributed to an increase in our oil revenues of $2,188,261 for the year ended December 31, 2013 over the comparable period of 2012. This increase is a reflection of strong WTI pricing, combined with narrowing WCS heavy oil differentials during 2013.

Average oil royalties paid for the twelve months ended December 31, 2013 increased by $473,861 over those paid in the ten months ended December 31, 2012. This increase can be attributed to the new wells drilled in the Jenner area which are subject to Alberta Crown royalties and gross overriding royalties.

Oil operating expenses increased during the twelve months ended December 31, 2013 by $984,101, or $5.15/boe, over the ten months ended December 31, 2012. This increase in operating costs can be attributed to third party processing fees for the recently drilled wells in 2013.

Oil transportation costs paid for the twelve months ended December 31, 2013 increased by $119,677 over the ten months ended December 31, 2012. This increase in transportation costs can be attributed to our increase in oil production for the twelve months ended December 31, 2013 as well as third party fees and trucking costs associated with getting these volumes to sale.

Natural Gas Operations

Our average realized gas price increased during the twelve months ended December 31, 2013 to $3.45/Mcf over the ten months ended December 2012. This increase of $1.38/Mcf in our realized natural gas price had a substantial impact on our natural gas revenues for the year ended December 31, 2013, which increased by $494,872 over the ten months ended December 31, 2012. This increase in realized natural gas price is also consistent with the increase in the Alberta 30 day spot AECO prices.

Average gas royalties paid for the twelve months ended December 31, 2013 increased by $52,788, or $0.61/boe, over those paid in the ten months ended December 31, 2012. This increase is consistent with our increase in gas production of 313 Mcf/d and our $1.38/Mcf increase in our realized natural gas price in the period.

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Natural gas operating expenses for the twelve months ended December 31, 2013 increased by $105,395 over those paid in the ten months ended December 31, 2012. This increase in natural gas operating expenses can be attributed to the relative increase in our gas production of 313 Mcf/d.

Natural gas transportation costs paid for the twelve months ended December 31, 2013 increased by $11,470 over those paid in the ten months ended December 31, 2012. This increase in natural gas transportation costs can be attributed to the relative increase in our gas production of 313 Mcf/d which is charged a transportation cost in order to get it to sales.

4. Exploration and Evaluation

Throughout the year, expenditures were made on some of our non-producing properties, including property leases and licenses, reclamation costs and other general expenses. Exploration and evaluation expenses for the twelve months December 31, 2013 was $116,006 as compared to $120,882 for the ten months ended December 31, 2012.

5. Depletion and Depreciation

Depletion and depreciation expense for the twelve months ended December 31, 2013 increased by $1,220,642 over the comparable period of 2012. This can mainly be attributed to the increase in depletion relative to our acquisition of the Atlee Buffalo property in the fourth quarter of 2013, as well as the development of two producing oil wells during the current fiscal year.

6. General and Administrative

General and administrative expenses for the twelve months ended December 31, 2013 were $1,877,376 and increased by $349,871 over the ten months ended December 31, 2012. The general and administrative costs for the twelve months ended December 31, 2013 and ten months ended December 31, 2012 include share-based payments of $360,464 and $282,872, respectively. We also captured capitalized overhead in the amount of $287,159 for the new wells drilled in the year.

The increase in general and administrative costs can be attributed to increased investor relations activities of $114,563, increased professional fees of $59,648 and higher travel and personnel costs of $274,510 as a result of our ongoing expansion.

We calculate our capitalized overhead monthly, based on the capital expenditures incurred in that month. This reflects the capital component of overhead costs applied for each well drilled and construction project at the recovery rates discussed in the general and administrative section of the operating results for the year ended December 31, 2014.

7. Impairment of Property and Equipment

During the year ended December 31, 2013, we performed an impairment test on our petroleum and natural gas assets. It was determined that the carrying amount of two cash-generating units ("CGUs") exceeded their recoverable amount due to a decline in estimated reserve volumes. Accordingly, we recognized an impairment charge of $556,371 for the twelve months ended December 31, 2013 as compared to $184,938 for the ten months ended December 31, 2012.

8. Finance Expense

Finance expense for the twelve months ended December 31, 2013 increased by $155,317 from the comparable period ended December 31, 2012. This increase is the result of interest charged on our outstanding bank debt, which increased by $3,465,000 over the ten months ended December 31, 2012.

9. Gain on Disposition

We disposed of a small gas gathering line for our Sylvan Lake property, which resulted in a gain on disposal of $3,889.

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10. Deferred Tax Recovery

We realized an income tax recovery for the twelve months ended December 31, 2013 in the amount of $357,573 as compared to an income tax expense of $312,307 for the ten months ended December 31, 2012.

B.                     Liquidity and Capital Resources

Bank Credit Facility

We have a demand operating credit facility in the amount of $15,000,000 with Alberta Treasury Branches (“ATB”) under the Commitment Letter. The credit facility is secured by a general security agreement and a floating charge on all of our lands. The credit facility bears interest at the bank’s prime rate plus 1.75% as well as a standby charge for any undrawn funds.

Pursuant to the terms of the demand operating credit facility, we have provided a covenant in the Commitment Letter that at all times our working capital ratio shall not be less than 1.0 to 1.0. The working capital ratio is defined under the terms of the Commitment Letter as current assets including the undrawn portion of the revolving operating demand line credit facility, to current liabilities, excluding any current bank indebtedness. We have maintained compliance with this covenant at all times.

As at December 31, 2014, we had drawn a total of $7,184,147 from the credit facility (December 31, 2013 - $4,500,000).

Cash Balances

We had cash and cash equivalents of nil as at December 31, 2014 and nil as at December 31, 2013.

Financial Contracts

We had no financial contracts as at December 31, 2014 or December 31, 2013.

Working Capital Position

We fund our operations through three key areas: operations funds flow, equity financings through the capital markets and our demand operating credit facility.

• Funds flow from operations. We generated funds flow from operations for the year ended December 31, 2014 of $6,673,033 (year ended December 31, 2013 - $3,789,202).

• Equity financings. On May 14, 2014, we closed a bought deal financing for gross proceeds of $10,000,125. Upon the receipt of proceeds we paid off our outstanding bank debt which had reached $8,075,000. An additional $921,007 was paid in legal and finders’ fees in conjunction with the closing of the financing. Finally, the remaining $1,004,118 was used to fund exploration activities, seismic, drilling and related geological work for our Atlee Buffalo summer drilling program. See the table under the heading “Item 10.A. Share Capital – Common Shares” which summarizes our issuances of common shares for the past three fiscal years and from January 1 to April 28, 2015.

• Demand operating credit facility. We currently have total credit facilities limit of $15,000,000, as described under the heading “Item 5.B. Liquidity and Capital Resources”, of which the full amount is available.

In our opinion, funds available from these three sources provide sufficient working capital for our present requirements and to carry out future capital expenditure programs and corporate expenses. We have delayed any capital expenditure programs subject to improvements in market conditions and commodity prices.

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We continue to monitor the current market conditions and will apply a conservative approach to capital spending during this time of low commodity prices. We have no drilling commitments or material land expiries in 2015, and have deferred drilling activity until the second half of 2015.

At current oil prices,our production remains cash flow positive due to our low operating costs. We are presently optimizing our production base in the Jenner and Atlee Buffalo core areas while minimizing operating costs. At this time, we will focus on reducing net debt in order to expand our financial flexibility to pursue potential acquisitions and maximize long-term shareholder value.

Further, in conjunction with an equity financing that closed in November 2013, we were required to spend $2,000,050 in flow-through dollars as part of an exploratory program by December 31, 2014. We spent this capital on geological and geophysical activities in the fourth quarter of 2014 which included two 3D seismic programs, one in Atlee Buffalo and one in Jenner, as well as drilling a vertical test well in Jenner.

Finally, as at December 31, 2014, we had the following rental commitments over the next five fiscal years set forth in the following table.

As at December 31, 2014, we had negative working capital of $11,644,609, which includes bank indebtedness of $7,184,147. All of our financial liabilities have contractual maturities of less than 90 days.

As at December 31, 2013, we had negative working capital of $6,330,906, which included bank indebtedness of $4,500,000.

As at December 31, 2012, we had negative working capital of $3,927,595, which included bank indebtedness of $1,035,000.

Capital Resources

Twelve Months Ended December 31, 2014

During the year ended December 31, 2014, we successfully drilled 10 horizontal oil wells in Atlee Buffalo, two horizontal oil wells in Jenner, and one vertical test well in Jenner. We also completed the construction of two multi-well batteries and multiple pipelines in Atlee Buffalo, various equipment upgrades and replacements and the installation of a solution gas compressor at the main production facility in Jenner. During the year, we closed an acquisition in the Atlee Buffalo area for proceeds of $510,000 which included an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to our existing land base. We also expanded our landholdings through Crown land sales acquiring 7,520 acres in southeast Alberta. Lastly, we shot two 3D seismic surveys in the Jenner and Atlee Buffalo areas to evaluate future drilling locations and reserve potential.

Twelve Months Ended December 31, 2013

During the twelve months ended December 31, 2013, we drilled two new wells in north Jenner and built and upgraded infrastructure in the Jenner area. The infrastructure included pipelines for new well and upgrades to our main Jenner battery. The upgrades included an increase in fluid handling capacity and the installation of a solution gas sweetening tower, which allows us to sell our gas. We also completed a property acquisition of oil and gas assets in the Atlee Buffalo area of southeast Alberta from an intermediate Canadian producer effective June 1, 2013. These expenditures were funded through our credit facility as well as a bought-deal equity financing for aggregate gross proceeds of $4,300,453.

Ten Months Ended December 31, 2012

During the ten months ended December 31, 2012, we drilled and completed eight wells in the Jenner area and built infrastructure at our main Jenner battery. The infrastructure included pipelines for new wells and upgrading our main production facility with a new water disposal pump and heated free-water-knockout separator to allow for greater fluid handling capacity. These expenditures were funded through our credit facility, as well as through a private placement for gross proceeds of $1,189,045 and the exercise of 1,752,047 share purchase warrants for proceeds of $1,051,228.

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C.                     Research and Development, Patents and Licences, etc.

None.

D.                     Trend Information

Our oil, which represents over 91% of our total revenue for the year ended December 31, 2014, is sold through a Canadian marketer and is benchmarked to the WTI index. Over the past three years, WTI crude oil prices have been relatively stable on a global basis. However, in recent months the price of oil has fallen from highs of over US$100/bbl in July 2014 to lows of just over US$40/bbl in March 2015.

General consensus for the reasoning behind this price drop is a combination of weak world demand due to slowing economic growth in many countries, coupled with surging North American oil supply due to high prices and increased development over the past several years. Through early 2014 supply and demand were well balanced, but by late 2014 supply was predicted to grow much faster than demand. As prices started to slide, OPEC made the decision in November 2014 to maintain their market share of oil production rather than cut back to curb the drop in oil price. The price of oil declined from approximately US$80/bbl in November, 2014 to below US$45/bbl through January, 2015 and has subsequently fluctuated between US$43/bbl and as high as US$55/bbl.

The Short-Term Energy and Summer Fuels Outlook– Market Prices and Uncertainty Report (“STEO”) of the U.S. Energy Information Administration (“EIA”), dated April 2015, suggested that initial data from the first quarter of 2015 shows increased oil consumption in response to low oil prices. It also noted possible increases in supply of oil coming from countries such as Libya, Iraq, and Iran given the potential of sanctions being lifted in response to a nuclear framework deal being reached. Notably, the EIA stated that oil market uncertainty remains at elevated levels and the potential for large upward or downward shifts in price remain.

The EIA observed in the STEO that natural gas consumption in 2015 and 2016 will average higher than in 2014 due to low prices, which have fallen significantly to less than US$3/MMBtu (Henry Hub Index) since highs of US$6/MMBtu in February 2014. Natural gas production growth will remain significant, but storage inventories are expected to remain relatively balanced with no significant price changes expected near-term.

E.                     Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

F.                     Tabular Disclosure of Contractual Obligations

The following table sets forth our known contractual obligations as of December 31, 2014 relating to our corporate office and petroleum producing properties. We have no long term debt or loan obligations.

Notes:

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G.                     Safe Harbor

Not applicable.

ITEM 6.                     DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A.                     Directors and Senior Management

The following table sets forth the name, office held, functions and areas of experience within our company and principal business activities performed outside our company of each of our directors and senior management.

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Notes:

Don Simmons, P. Geol. (37 years of age) – President, Chief Executive Officer and Director

Mr. Simmons has extensive experience in petroleum geology and a proven track record of discovering oil and gas in Western Canada and internationally. Initially, Mr. Simmons served as our Vice President Exploration and became President and Chief Executive Officer in February 2008. Prior to joining Hemisphere, Mr. Simmons was a geologist at a private oil and gas company, Sebring Energy, until its sale in 2007. Prior thereto, he spent five years with EnCana working on various projects in southeast Alberta and Ecuador. Mr. Simmons holds a Bachelor of Science degree in Geological Sciences from Queen’s University and is a member of the Association of Professional Engineers and Geoscientists of Alberta.

Charles O’Sullivan, B.Sc. (72 years of age) – Chairman and Director

Mr. O’Sullivan founded Hemisphere in 1977. He was President from 1977 to 2001 and remains an active Director and Chairman of the Board. From 1977 to 1983 and under Mr. O’Sullivan’s direction, we participated in 86 successful oil and gas wells in the U.S., including the deep Tomcat #1 well. At the time, this well, in the Anadarko Basin, Oklahoma, was the biggest gas well ever drilled in the continental U.S. Mr. O’Sullivan also founded Northern Continental Resources Inc. in 1986, to explore for uranium in the Athabasca Basin of Saskatchewan. He served as Chairman until our company was merged in 2009. Subsequently, the merged company was purchased by Rio Tinto for $640 million in 2011. Mr. O’Sullivan graduated with a Bachelor of Science degree in geophysics in 1965.

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Frank Borowicz, QC, CA (Hon) (66 years of age) – Director

Mr. Borowicz has over 35 years of experience in corporate governance and regulatory compliance. He is a retired partner of the international law firm Davis LLP and is a Governor of the Vancouver Board of Trade. He served as Chairman of the BC Industry Training Authority and is an independent director of several public and private companies. Educated at Harvard, Dalhousie and Loyola, Mr. Borowicz is a member of the Institute of Corporate Directors, is a Queens Counsel, and is an honourary member of the Institute of Chartered Accountants.

Bruce McIntyre, P.Geol. (60 years of age) – Director

Mr. McIntyre has over 35 years of oil and gas experience and a proven track record of finding quality oil and gas reserves. Mr. McIntyre was most recently Executive Director of New Zealand Energy Corp. until June 2014 and previously, President from April 2011 to July 2012. Prior thereto, Mr. McIntyre was President and Chief Executive Officer of Sebring Energy Inc., a private Alberta-based exploration and production company that was sold in July 2007. He has also held various other management positions including President CEO and co-founder of Sommer Energy Ltd., President and CEO of TriQuest Energy Corp., President and Chief Executive Officer of BXL Energy Ltd. and Exploration Manager for Gascan Resources Ltd. Mr. McIntyre is a member of the American Association of Petroleum Geologists, has a Professional Geologist designation with the Association of Professional Engineers and Geoscientists of Alberta and an Honorary Member of the Canadian Society of Petroleum Geologists (Past President 2002). Mr. McIntyre holds a Bachelor of Science Degree in Geology (Honours) from Carleton University and an Advanced Executive Certificate in General Management from Queen’s University.

Gregg Vernon, P.Eng. (60 years of age) – Director

Mr. Vernon is a designated professional engineer with over 35 years of international oil and gas industry experience, including managing and administrating major projects in China, Eastern Canada and South America. He is currently the interim President and Chief Executive Officer of Petrodorado Energy Ltd. and President of Bochica Oil & Gas Inc. (private company). Previously, Mr. Vernon was the interim Chief Operating Officer of PetroMagdalena Energy Corp. (formerly Alange Energy Corp.), a Canadian-based international oil and gas exploration and production company until its sale in 2012. He is one of the founders of Petro Andina Resources Ltd., a Canadian company with operations in South America. He is a University of Alberta graduate with his degree in Engineering and is a member of the Society of Petroleum Engineers.

Richard Wyman, B.Sc., MBA (58 years of age) – Director

Mr. Wyman has over 30 years of oil and gas industry experience. He began his career as a reservoir engineer with Esso Resources Canada Ltd. in Calgary prior to becoming a corporate finance associate with Wood Gundy in London. He returned to Canada and became an analyst in the corporate finance and treasury department of Gulf Canada Limited in Calgary and Toronto and then as an oil and gas equities research analyst with Peters & Co. Ltd. Following his tenure at Peters & Co. Ltd., Mr. Wyman became a founding shareholder and Director of Smart Pipeline Services Ltd. and Northern Cross (Yukon) Ltd. He returned to a capital market role as Vice President and Senior Oil and Gas Analyst with Canaccord Genuity under its rebranding process in 2004. In 2010, Mr. Wyman returned to the industry as President and a Director of Northern Cross (Yukon) Ltd, a private junior oil and gas, exploration and development company with assets located in Yukon. Mr. Wyman received a Bachelor of Applied Science degree in Chemical Engineering (Hons) from Queen's University in 1978 and a Masters of Business Administration from the International Management Institute at the University of Geneva in 1985.

Ian Duncan, P. Eng. (32 years of age) – Chief Operating Officer

Mr. Duncan is a professional engineer with a range of experience in many different areas within the oil and gas industry, including drilling, production and facility operations. Mr. Duncan joined Hemisphere in January 2011 and was quickly promoted to Vice President, Engineering in May 2011. He was appointed Chief Operating Officer September 1, 2014. Previously, Mr. Duncan was with Solaris MCI, an engineering consulting firm providing facilities engineering services to Encana in the Horn River Shale Basin. Prior thereto, Mr. Duncan spent four years with Talisman Energy Inc. on various exploration projects including Bakken Oil in Saskatchewan and Marcellus Shale Gas in Pennsylvania. Mr. Duncan holds a Bachelor of Science degree in Chemical Engineering from the University of Alberta and is a member of the Association of Professional Engineers and Geoscientists of Alberta.

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Dorlyn Evancic, CGA (51 years of age) – Chief Financial Officer

Mr. Evancic has over 25 years of experience in corporate finance and management which includes senior executive positions in a number of public corporations. He has served as Hemisphere’s Chief Financial Officer since July 2007. Previously, Mr. Evancic was Chief Financial Officer of Guyana Frontier Mining Corp, Chief Financial Officer of Northern Continental Resources, and also a Director and Chief Financial Officer of Gemco Minerals Inc. Prior to working in the natural resource industry, Mr. Evancic’s experience included Director of Administration and Finance of Leisure Canada Inc., Vice President of Operations for Urban Resource Technologies Inc. and Financial Controller of Neptune Food Services. He has been a member of the Certified General Accountants Association since 1989.

Andrew Arthur, P. Geol. (53 years of age) – Vice President, Exploration

Mr. Arthur has over 24 years of both domestic and international oil and gas industry experience. He began consulting for Hemisphere in January 2012 and was appointed Vice President, Exploration in July 2012. Throughout his career, he has been a key technical member in many exploration and development projects having drilled several hundred wells across the Western Canada Sedimentary Basin. Exposure to all facets of the oil and gas industry has led him to progressively senior exploration roles. Mr. Arthur graduated with his B.Sc. Geology (Honours) from the University of British Columbia in 1985. With sponsorship from the Geological Survey of Canada, he continued at the University of British Columbia, completing his Master of Science in Geology in 1987. Mr. Arthur is a member of the Association of Professional Engineers and Geoscientists of Alberta.

Ashley Ramsden-Wood, P.Eng. (35 years of age) – Vice President, Engineering

Ms. Ramsden-Wood is a professional engineer with over 12 years of oil and gas industry experience with a focus on British Columbia, Alberta and Saskatchewan. Ms. Ramsden-Wood joined Hemisphere as a consultant in June 2012 and was appointed as Vice President, Engineering effective September 1, 2014. Ms. Ramsden-Wood started her career at Petro-Canada as a Reservoir Engineer and then moved on to exploitation/area engineering roles at NAL Resources where she gained extensive experience in planning and implementing capital projects and development plans, preparing economic valuations, and evaluating acquisitions. Ms. Ramsden-Wood holds a Bachelor of Science degree in Chemical Engineering from the University of British Columbia and is a member of the Association of Professional Engineers and Geoscientists of Alberta.

4. Family Relationships

There are no family relationships among our directors and executive officers.

5. Other Arrangements

There is no arrangement or understanding with major shareholders, customers, suppliers or others, pursuant to which any person was selected as a director of our Board of Directors or a member of our senior management.

B.                     Compensation

The total compensation plan for our executive officers is comprised of base salary, cash bonus and stock options. The total compensation plan for our directors is comprised of stock options, with the exception of our Chairman who receives an annual retainer. There is no policy or target regarding cash and non-cash elements of our compensation program. The Compensation/Nominating Committee of our Board of Directors annually reviews the total compensation of our executive officers against compensation goals and objectives and makes the recommendations to our Board of Directors concerning the individual components of the executives’ compensation. We do not provide executive officers with any personal benefits, nor do we provide any additional cash compensation to our executive officers for serving as directors.

The following table sets for the short-term benefits, which are primarily salaries and wages, and share-based payments, paid to our officers and directors for our fiscal years ended December 31, 2014 and 2013.

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Director Compensation

Base Salary or Consulting Fees

During the year ended December 31, 2014, we paid $40,000 in director fees. These fees were charged for services provided by the Chairman of our Board of Directors. The following table sets forth compensation paid to our directors who are not executive officers during the fiscal year ended December 31, 2014.

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Notes:

Outstanding Option-Based Awards

We have no pension plan or other arrangement for non-cash compensation for our directors, except incentive stock options. The following table discloses the particulars of all awards outstanding for directors who are not executive officers as at December 31, 2014, including awards granted before this most recently completed fiscal year.

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Notes:

Executive Officer Compensation

The following table summarizes compensation paid to the executive officers, directly or indirectly, during our three most recently completed fiscal years.

Notes:

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Outstanding Option-Based Awards

The following table sets forth the particulars of all awards for each executive officer outstanding as at December 31, 2014, including any awards granted before the most recently completed fiscal year.

Notes:

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Stock Option Plan

The purpose of the Stock Option Plan is to assist in attracting, retaining and motivating our directors, officers and employees and to closely align the personal interests of such directors, officers and employees with our interests and the interests of our shareholders. The allocation of stock options under the Stock Option Plan is determined by our Board of Directors upon recommendation from the Compensation/Nominating Committee of our Board of Directors which, in determining such allocations, considers such factors as previous grants to individuals, our overall performance, share price, the role and performance of the individual in question, the amount of time directed to our affairs and time expended in serving on our committees.

Options are granted from time to time under the Stock Option Plan as determined by our Board of Directors upon recommendation from the Compensation/Nominating Committee of our Board of Directors, including options granted to executive officers. Previous grants of options under the Stock Option Plan are taken into account when the granting of new options is being considered. There were no repricings of Stock Options under the Stock Option Plan or otherwise during our most recently completed fiscal year ended December 31, 2014. We do not have any share-based awards in place.

The following information is intended as a summary of the terms of the Stock Option Plan and is qualified in its entirety by the full text of the Stock Option Plan.

• Number of Shares Reserved. The number of common shares that may be reserved for issuance under the Stock Option Plan will be 10% of the issued common shares at the time common shares are reserved for issuance as a result of the grant of a stock option, less any common shares reserved for issuance under stock options granted under share compensation arrangements other than the Stock Option Plan.
• Administration. The Stock Option Plan is to be administered by our Board of Directors or by a committee to which such authority is delegated by our Board of Directors from time to time.
• Option Holders. The Stock Option Plan provides that stock options may be issued to our employees, officers, directors and consultants or any of our subsidiaries, a company wholly-owned by such employee, to a Consultant Entity (as defined in the Stock Option Plan) of a consultant or to eligible tax accounts established by or for the consultant or employee under which he or she is the beneficiary.
• Board Discretion. The Stock Option Plan provides that, generally, the number of shares subject to each stock option, the exercise price, the expiry time, the extent to which such stock option is exercisable and other terms and conditions relating to such stock options shall be determined by our Board of Directors or any committee to which such authority is delegated by our Board of Directors from time to time.
• Maximum Term of Options. Stock options granted under the Stock Option Plan will be for a term not exceeding ten years from the date of grant.
• Maximum Options per Person. The number of common shares reserved for issuance to any one option holder pursuant to stock options granted under the Stock Option Plan during any twelve month period may not exceed 5% (or, in the case of a consultant, 2%) of our issued and outstanding common shares at the time of grant. The number of common shares reserved for issuance to any person who is engaged in investor relations activities is limited to an aggregate of 2% of our issued and outstanding common shares at the time of grant.
• Disinterested Shareholder Approval. Disinterested shareholder approval (as defined in the TSX- V corporate finance manual) is required for the grant to Insiders (as defined in the Stock Option Plan), within a 12 month period, of a number of stock options which, when added to the number of outstanding incentive stock options granted to Insiders within the previous 12 months, exceed 10% of our issued shares.
• No assignment. The stock options may not be assigned or transferred.

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• Termination Prior to Expiry. Generally, stock options must expire and terminate on a date stipulated by our Board of Directors or the committee appointed by our Board of Directors at the time of grant and, in any event, must terminate within a reasonable time, which may not exceed 12 months, following the date on which the option holder ceases to be an employee, officer, director or consultant, subject to certain conditions as more fully described in the Stock Option Plan. If an option holder dies, the stock options of the deceased option holder will be exercisable by his or her legal representatives for a period not exceeding 12 months or the balance of the term of the stock options, whichever is shorter. If an option holder has a Disability (as defined in the Stock Option Plan), the stock options of the option holder with that Disability will be exercisable for a period not exceeding 12 months or the balance of the term of the stock options, whichever is shorter.
• Vesting. Subject to the discretion of our Board of Directors or the committee appointed by our Board of Directors, stock options granted under the terms of the Stock Option Plan will fully vest on the date of grant of such stock options. In accordance with the policies of the TSX-V, stock options issued to consultants performing investor relations must vest in stages over a minimum of twelve months with no more than one-quarter (¼) of the stock options vesting in any three (3) month period.
• Hold Period. Any stock options granted under the terms of the Stock Option Plan where the exercise price is based on any discount to the market price (market price will be the closing trading price of our common shares on the day immediately preceding the date of the option grant, and may be less than this price if it is within the discounts permitted by the TSX-V and applicable regulatory authority) and all shares issued on the exercise of such stock options, if exercised prior to the expiration of the applicable four month TSX-V hold period, will be subject to a four month TSX-V hold period from the date the stock options are granted.
• Full Payment for Shares. We will not issue shares pursuant to stock options granted under the Stock Option Plan unless and until the shares have been fully paid for.
• Reduction of Exercise Price. The exercise price of stock options granted to Insiders may not be decreased without disinterested shareholder approval.
• TSXV’s Rules and Policies Apply. In the event of an inconsistency between the terms of the Stock Option Plan and the rules and policies of the TSX-V and applicable the securities commissions, the rules and policies of the TSX-V and securities commissions will govern.
• Termination of Plan. Subject to all necessary regulatory approvals, our Board of Directors or the committee appointed by our Board of Directors may terminate or suspend the plan.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth details of our compensation plans under which our equity securities were authorized for issuance at the end of our most recently completed fiscal year.

Note:

Termination and Change of Control Benefits

We have an executive employment agreement with each executive officer which provides termination notice of twelve months without just cause, including termination as a result of a change of control, for which each executive officer would be compensated by an annual base salary of twelve months plus the average annual bonus amount, if any, paid over the two years immediately prior to termination, in addition to the vesting of all stock options. Under a change of control, the executive employment agreements between us and each executive officer state that the executive agrees to remain employed by us during the period commencing with any act taken and any person, or the announcement of an intention to take such act, which may result in a change of control and ending with the final conclusion of all matters associated with such act or announcement.

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Assuming an executive officer was terminated on December 31, 2014, based on annualized base salaries for the current executive officers as at such time, the following table summarizes the estimated compensation to which each current executive officer would have been entitled.

All stock options granted to NEOs immediately vest; however, should an exercise of the stock option take place, the common shares are subject to a hold period of four months plus one day from the day of grant. The value of stock options held by each NEO at December 31, 2014 (based on the closing market price of the common shares at December 31, 2014 of $0.38) was $51,000 for Mr. Simmons, $16,000 for Mr. Duncan, $21,050 for Mr. Evancic, $Nil for Mr. Arthur, and $Nil for Ms. Ramsden-Wood.

Pension, Retirement or Similar Benefits

We have no pension plans that provide for payments or benefits to any director or executive officer at, following or in connection with retirement. We also do not have any deferred compensation plans relating to any director or executive officer. Accordingly, we have no amounts set aside or accrued to provide pension, retirement or similar benefits.

C.                     Board Practices

Term of Office

Each director holds office until the next annual general meeting or until his office is earlier vacated in accordance with the articles or with the provisions of the BCBCA. A director appointed or elected to fill a vacancy on our Board of Directors also holds office until the next annual general meeting. The directors were elected at our Annual General and Special Meeting of the shareholders held on June 6, 2014. The term of office of the officers expires at the discretion of the directors.

Service Contracts

See the information under the heading “Item 6.B. – Termination and Change of Control Benefits” for particulars of Don Simmons’ executive employee agreement with us. Other than as disclosed in this Form 20-F, we do not have any service contracts with directors which provide for benefits upon termination of employment.

Committees of the Board

Our Board of Directors has four committees: Corporate Governance Committee, Compensation/Nominating Committee, Reserves Committee, and Audit Committee.

Corporate Governance Committee

The Corporate Governance Committee assists our Board of Directors in the oversight of our corporate governance policies and responsibilities for good governance practices. The following directors serve on our Corporate Governance Committee: Frank Borowicz (Chairman), Charles O’Sullivan and Don Simmons.

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The mandate of the Corporate Governance Committee is to:

• Assist our Board of Directors in fulfilling their oversight responsibilities with respect to good governance practices as defined in National Policy 58-201 Corporate Governance Guidelines and National Instrument 58-101 Disclosure of Corporate Governance Practices.
• Meet annually and at the request of the Corporate Governance Committee Chairman.
• Annually review and amending (if required) our corporate policies, and making recommendations to our Board of Directors.
• Annually review the corporate governance disclosure in our information circular for recommendation to our Board of Directors.

Compensation/Nominating Committee

The Compensation/Nominating Committee assists our Board of Directors in the oversight of our recruitment, retention and motivation of directors, officers and employees in regard to the competitive conformity of compensation and corporate objectives. The Compensation/Nominating Committee also assists our Board of Directors in the oversight of recruiting new directors, as required. The following directors serve on our Compensation/Nominating Committee: Charles O’Sullivan (Chairman), Frank Borowicz and Bruce McIntyre.

The mandate of the Compensation/Nominating Committee is to:

• Assist our Board of Directors in fulfilling their oversight responsibilities with respect to cash and stock compensation of new and existing executives and employees, and nominating new directors, as required.
• Approve stock option grants for employees and consultants.
• Approve cash compensation and stock option grants for officers and directors to recommend to our Board of Directors for approval.
• Meet annually and at the request of the Compensation/Nominating Committee Chairman.
• Review executive compensation packages of our peer group.
• Annually review the Statement of Executive Compensation disclosure in our Information Circular for recommendation to our Board of Directors.
• Identify the competencies and skills represented by the directors and make recommendations to our Board of Directors.
• Recommend director nominees to shareholders at our annual general meeting.

Reserves Committee

The Reserves Committee assists our Board of Directors in the oversight of the integrity in our petroleum and natural gas reserves. The following directors serve on our Reserves Committee: Bruce McIntyre, (Chairman), Don Simmons, Gregg Vernon, and Richard Wyman.

The mandate of the Reserves Committee is to:

• Assist our Board of Directors in fulfilling their oversight responsibilities with respect to the annual review of our petroleum and natural gas reserves.
• Meet annually to review and approve the year-end independent reserves evaluation and corresponding disclosures as prepared by management under applicable laws.
• Annually review the Statement of Reserves and Other Oil and Natural Gas Information in our Annual Information Form for recommendation to our Board of Directors.

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Audit Committee

The Audit Committee assists our Board of Directors in the oversight of our integrity in financial reporting as outlined in National Instrument 52-110 Audit Committees (“NI 52-110”). The Audit Committee consists of no less than three directors, each of whom is “financially literate” and “independent” as defined under NI 52-110, and is annually appointed by our Board of Directors. The Chair of the Audit Committee is appointed by our Board of Directors at the same time as the member appointment. The following directors serve on our Audit Committee: Bruce McIntyre (Chairman), Frank Borowicz, Gregg Vernon and Richard Wyman.

The mandate of the Audit Committee is to:

• Assist our Board of Directors in fulfilling their oversight responsibilities with respect to the review of financial statements and other relevant public disclosures, compliance with legal and regulatory requirements relating to financial reporting, the external auditors’ qualifications and independence, and the performance of the internal audit function and the external auditors.
• Meet quarterly to review and approve the quarterly financial statements and management’s discussion and analysis for recommendation to our Board of Directors.
• Meet annually to review and approve the audited annual financial statements and management’s discussion and analysis for recommendation to our Board of Directors.
• Annually review the performance of the external auditors.
• Nominating the external auditors for recommendation to our shareholders at the annual general meeting of the shareholders.
• Advise our Board of Directors on the remuneration of the external auditors based on the time required to complete the audit and preparation of the audited annual financial statements, and the difficulty of the audit and performance of the standard auditing procedures under generally accepted auditing standards, Generally Accepted Accounting Principles of Canada and IFRS and the Public Company Accounting Oversight Board standards.

External Auditors

Our external auditors are the independent representatives of the shareholders, yet are also accountable to our Board of Directors and the Audit Committee. The external auditors complete their audit procedures and reviews with professional independence, free from any undue interference from management or directors. The Audit Committee directs and ensures that the management fully co-operates with the external auditors in the course of carrying out their professional duties. The Audit Committee will have access to direct communications with the external auditors, if required.

The external auditors are prohibited from providing any non-audit services to us, without the written consent of the Audit Committee unless such non-audit services are De Minimus Non-Audit Services as outlined in section 2.4 of NI 52-110. In determining whether the external auditors will be granted permission to provide non-audit services, the Audit Committee is to consider that the benefits to us from the provision of such services, outweighs the risk of any compromise to or loss of the independence of the external auditors in carrying out their auditing mandate.

Notwithstanding the above non-audit services, the external auditors are prohibited at all times from carrying out any of the following services, while they are appointed as our external auditors:

• Act as our agent for the sale of all or substantially all of the undertaking of Hemisphere; and

• Perform any non-audit consulting work for any of our directors or senior officers in their personal capacity, but not as a director, officer or insider of any other entity that is not associated or related to us.

The Audit Committee has the power to terminate the services of the external auditors, with or without the approval of our Board of Directors, acting reasonably.

Annual Review

The Corporate Governance Committee annually reviews the Audit Committee Charter and recommends any amendments to the Board of Directors for approval.

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D.                     Employees

As at December 31, 2014, we had eight full-time head office employees and one full-time field employee. Additionally, we had five part-time consultants and two full-time field contractors.

E.                     Share Ownership

Shareholdings of Directors and Executives

The shareholdings of common shares of our directors and executive officers and the percent of common shares outstanding on a diluted basis as at April 28, 2015 are set forth in the following table.

Notes:

All percentages are based on 82,663,498 fully diluted shares outstanding as of April 28, 2015.

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Stock Options Outstanding

Our directors and executive officers to whom outstanding stock options have been granted, the number of common shares subject to such options, the price per option, the grant date and the expiration date are set forth in the following table as at April 28, 2015. All options vest immediately; however, if exercised, the common shares are subject to a four-month plus one-day hold period from the date of grant.

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Our employees are eligible to participate in our Stock Option Plan. A summary of the some of the relevant parts of the Stock Option Plan is given under the heading “Item 6.B. – Stock Option Plan”.

ITEM 7.                    MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A.                    Major Shareholders

To the best of our knowledge, there are no persons or company who beneficially own, directly or indirectly, or exercise control or direction over, securities carrying more than 5% of the voting rights attached to any class of our voting securities, except for Alpha Capital, which owns 5,290,500 shares representing 7.0% of the voting rights of our common shares as of April 20, 2015.

The voting rights of our major shareholders do not differ from the voting rights of holders of the common shares who are not our major shareholders.

To the best of our knowledge, there has been no significant change in the percentage ownership held by any major shareholders during the past three years.

As of March 31, 2015, our registrar and transfer agent reported we have 49 registered holders of our shares who are U.S. residents, with combined holdings of 1,175,450 common shares.

To the extent of our knowledge, we are not directly or indirectly owned or controlled by another corporation, any foreign government, or any other natural or legal person, severally or jointly.

As of the date of this Form 20-F, there were no arrangements known to us which may, at a subsequent date, result in a change of control.

B.                    Related Party Transactions

Other than in the ordinary course of business, since the beginning of the preceding three financial years, there have been no transactions or loans between us and:

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Compensation

For information regarding compensation for our directors and senior management, please see the information under the heading “Item 6.B. Compensation”.

C.                     Interests of Experts and Counsel

Not applicable.

ITEM 8.                     FINANCIAL INFORMATION

A.                     Financial Statements and Other Financial Information

Our financial statements are stated in Canadian dollars and are prepared in accordance with IFRS, as issued by the IASB, the application of which, in our case, conforms in all material respects for the periods presented with the United States generally accepted accounting principles.

Included in this Form 20-F are our audited financial statements for the years ended December 31, 2014 and December 31, 2013, which comprise the statements of financial position as at December 31, 2014, December 31, 2013 and January 1, 2013, and the statements of loss and comprehensive loss, changes in shareholders’ equity and cash flows for the years ended December 31, 2014 and December 31, 2013 and the ten months ended December 31, 2012, the independent auditors’ report by Smythe Ratcliffe LLP, Chartered Accountants, a summary of significant accounting policies and the notes to the audited financial statements.

These financial statements can be found under the heading “Item 18. Financial Statements”.

Export Sales

Export sales do not constitute any portion of our sales.

Legal Proceedings

To our knowledge, there have not been any legal or arbitration proceedings, including those relating to bankruptcy, receivership or similar proceedings, those involving any third party, and governmental proceedings pending or known to be contemplated, which may have, or have had in the recent past, significant effect our financial position or profitability.

Also, to our knowledge, there have been no material proceedings in which any director, any member of senior management, or any of our affiliates is either a party adverse to us or our subsidiaries or has a material interest adverse to us or our subsidiaries.

Policy on Dividend Distributions

We have not declared or paid any dividends since our incorporation. Payments of dividends in the future will be dependent on, among other things, our cash flow, results of operations and financial condition, the need for funds to finance ongoing operations and other considerations, as our Board of Directors considers relevant.

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B.                     Significant Changes

None.

ITEM 9.                     THE OFFER AND LISTING

A.                     Offer and Listing Details

Our common shares are listed for trading on the TSX-V under the symbol “HME”. Our high and low market prices of the common shares on the TSX-V for the five most recent full financial years, for each full financial quarter for the two most recent full financial years and for each of the most recent six months are set forth in the following table.

Note:

On April 28, 2015, the closing price of our common shares on the TSX-V was $0.305 per common share.

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Transfers of Common Shares

Our common shares, no par value, are in registered form and the transfer of our common shares is managed by our transfer agent in Canada, Computershare Investor Services Inc., located at 510 Burrard Street, Vancouver, BC V6C 3A8, (Tel: 800-564-6253).

B.                     Plan of Distribution

Not applicable.

C.                     Markets

Our common shares, no par value, are currently traded on the TSX-V under the symbol “HME”.

There is currently no market for the common shares in the United States, and there is no assurance that any will develop or, if developed, will be maintained.

D.                     Selling Shareholders

Not applicable.

E.                     Dilution

Not applicable.

F.                     Expenses of the Issue

Not applicable.

ITEM 10.                     ADDITIONAL INFORMATION

A.                     Share Capital

Not applicable.

B.                     Memorandum and Articles of Association

Incorporation

We are incorporated under the BCBCA. Our British Columbia incorporation number is BC00172034.

Objects and Purposes of Our Company

The articles do not contain a description of our objects and purposes.

Voting on Certain Proposal, Arrangement, Contract or Compensation by Directors

Other than as disclosed below, the articles do not restrict directors’ power to (a) vote on a proposal, arrangement or contract in which the directors are materially interested or (b) to vote compensation to themselves or any other members of their body in the absence of an independent quorum.

The BCBCA does, however, contain restrictions in this regard. The BCBCA provides that a director who holds a disclosable interest in a contract or transaction into which we have entered or proposes to enter is not entitled to vote on any directors’ resolution to approve that contract or transaction, unless all the directors have a disclosable interest in that contract or transaction, in which case any or all of those directors may vote on such resolution. A director who holds a disclosable interest in a contract or transaction into which we have entered or proposes to enter and who is present at the meeting of directors at which the contract or transaction is considered for approval may be counted in the quorum at the meeting whether or not the director votes on any or all of the resolutions considered at the meeting. A director or senior officer generally holds a disclosable interest in a contract or transaction if (a) the contract or transaction is material to us; (b) we have entered, or proposed to enter, into the contract or transaction, and (c) either (i) the director or senior officer has a material interest in the contract or transaction or (ii) the director or senior officer is a director or senior officer of, or has a material interest in, a person who has a material interest in the contract or transaction. A director or senior officer does not hold a disclosable interest in a contract or transaction merely because the contract or transaction relates to the remuneration of the director or senior officer in that person’s capacity as director, officer, employee or agent of our company or of an affiliate of our company.

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Borrowing Powers of Directors

The articles provide that we, if authorized by our Board of Directors, may:

• borrow money in the manner and amount, on the security, from the sources and on the terms and conditions that they consider appropriate;
• issue bonds, debentures and other debt obligations either outright or as security for any of our liabilities or obligations or any other person and at such discounts or premiums and on such other terms as they consider appropriate;
• guarantee the repayment of money by any other person or the performance of any obligation of any other person; and
• mortgage, charge, whether by way of specific or floating charge, grant a security interest in, or give other security on, the whole or any part of our present and future assets and our undertaking.

Qualifications of Directors

Under the articles, a director is not required to hold a share in our capital as qualification for his or her office but must be qualified as required by the BCBCA to become, act or continue to act as a director.

Share Rights

Please see the summary of our authorized capital under the heading “Item 10.A. Share Capital – Common Shares”.

Procedures to Change the Rights of Shareholders

The articles state that we may by resolution of our directors: (a) create one or more classes or series of shares or, if none of the shares of a class or series of shares are allotted or issued, eliminate that class or series of shares; (b) increase, reduce or eliminate the maximum number of shares that we are authorized to issue out of any class or series of shares or establish a maximum number of shares that we are authorized to issue out of any class or series of shares for which no maximum is established; (c) if we are authorized to issue shares of a class of shares with par value: (i) decrease the par value of those shares, (ii) if none of the shares of that class of shares are allotted or issued, increase the par value of those shares, (iii) subdivide all or any of our unissued or fully paid issued shares with par value into shares of smaller par value, or (iv) consolidate all or any of our unissued or fully paid issued shares with par value into shares of larger par value; (d) subdivide all or any of our unissued or fully paid issued shares without par value; (e) change all or any of our unissued or fully paid issued shares with par value into shares without par value or all or any of our unissued shares without par value into shares with par value; (f) alter the identifying name of any of our shares; (g) consolidate all or any of our unissued or fully paid issued shares without par value; or (h) otherwise alter our shares or authorized share structure when required or permitted to do so by the BCBCA.

Meetings

Each director holds office until the next annual general meeting or until his office is earlier vacated in accordance with the articles or with the provisions of the BCBCA. A director appointed or elected to fill a vacancy on our Board of Directors also holds office until the next annual general meeting.

The articles provide that the annual meetings of shareholders must be held at such time in each calendar year and not more than 15 months after the last annual general meeting and at such place as our Board of Directors may from time to time determine. The directors may, at any time, call a meeting of the shareholders.

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The holders of not less than five percent of our issued shares that carry the right to vote at a meeting may requisition our directors to call a meeting of shareholders for the purposes stated in the requisition.

Under the articles, the quorum for the transaction of business at a meeting of our shareholders is one or more persons, present in person or by proxy.

The articles state that in addition to those persons who are entitled to vote at a meeting of the shareholders, the only other persons entitled to be present at the meeting are our directors, our president (if any), our secretary (if any), our lawyer or auditor, any persons invited to be present at the meeting by our directors or by the chair of the meeting and any person entitled or required under the BCBCA or the articles to be present at the meeting.

Limitations on Ownership of Securities

Except as provided in the Investment Canada Act (Canada), there are no limitations specific to the rights of non-Canadians to hold or vote the common shares under the laws of Canada or British Columbia, or in the our charter documents.

Change in Control

There are no provisions in the articles or in the BCBCA that would have the effect of delaying, deferring or preventing a change in our control, and that would operate only with respect to a merger, acquisition or corporate restructuring involving us or our subsidiaries.

Ownership Threshold

The articles or the BCBCA do not contain any provisions governing the ownership threshold above which shareholder ownership must be disclosed. Securities legislation in Canada, however, requires that we disclose in our information circular for our annual general meeting, holders who beneficially own more than 10% of our issued and outstanding shares. Most state corporation statutes do not contain provisions governing the threshold above which shareholder ownership must be disclosed. Upon the effectiveness of this Form 20-F, we expect that the United States federal securities laws will require us to disclose, in an annual report on Form 20-F, holders who own 5% or more of our issued and outstanding shares.

C.           Material Contracts

There are no other contracts, other than those disclosed in this Form 20-F and those entered into in the ordinary course of our business, that are material to us and which were entered into in the most recently completed fiscal year or which were entered into before the most recently completed fiscal year but are still in effect as of the date of this Form 20-F:

• Stock Option Plan. The Stock Option Plan was last approved by our shareholders on June 6, 2014. See the discussion under the heading “Item 6.B. – Stock Option Plan”.
• Shareholders Rights Plan Agreement. The Shareholders Rights Plan Agreement sets forth the terms of the Shareholder Rights Plan, which was last approved by our shareholders and extended for two years at our Annual General and Special Meeting Held on June 6, 2014. See the discussion under the heading “Item 6.B. – Shareholder Rights Plan.”
• Advance Notice Policy. The Advance Notice Policy was approved by our Board of Directors on March 13, 2014 and was subsequently ratified by our shareholders on June 6, 2014. See the discussion under the heading “Item 4.A. – Three Year History for the Fiscal year ended December 31, 2014.”
• Demand Operating Credit Facility. We have a demand operating credit facility in the amount of $15,000,000 with ATB under a commitment letter dated September 25, 2013, as amended effective June 23, 2014 and November 28, 2014. The demand operating credit facility is secured by a general security agreement and a floating charge on all our lands. The demand operating credit facility bears interest at ATB’s prime rate plus 1.75% as well as a standby charge for any undrawn funds.
• Executive Employment Agreement with Don Simmons. We entered into an executive employment agreement with Don Simmons effective September 1, 2014 pursuant to which he agreed to serve as our President and Chief Executive Officer.

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• Executive Employment Agreement with Dorlyn Evancic. We entered into an executive employment agreement with Dorlyn Evancic effective September 1, 2014 pursuant to which he agreed to serve as our Chief Financial Officer.
• Executive Employment Agreement with Ian Duncan. We entered into an executive employment agreement with Ian Duncan effective September 1, 2014 pursuant to which he agreed to serve as our Chief Operating Officer.
• Executive Employment Agreement with Andrew Arthur. We entered into an executive employment agreement with Andrew Arthur effective September 1, 2014 pursuant to which he agreed to serve as our Vice President, Exploration.
• Executive Employment Agreement with Ashley Ramsden-Wood. We entered into an executive employment agreement with Ashley Ramsden-Wood effective September 1, 2014 pursuant to which she agreed to serve as our Vice President, Engineering.

D.           Exchange Controls

There are no government laws, decrees or regulations in Canada that restrict the export or import of capital or that affect the remittance of dividends, interest or other payments to non-resident holders of the common shares. Any remittances of dividends to U.S. residents and to other non-residents are, however, subject to withholding tax. See the information under the heading “Item 10.E. Taxation”.

There are no limitations under the laws of Canada or in our organizing documents on the right of foreigners to hold or vote our securities, except that the Investment Canada Act may require review and approval by the Minister of Industry (Canada) of certain acquisitions of our “control” by a “non-Canadian”. The threshold for acquisitions of control is generally defined as being one-third or more of our voting shares. If the investment is potentially injurious to national security it may be subject to review under the Investment Canada Act notwithstanding the percentage interest acquired or amount of the investment. “Non-Canadian” generally means an individual who is not a Canadian citizen, or a corporation, partnership, trust or joint venture that is ultimately controlled by non-Canadians.

E.           Taxation

Certain Canadian Federal Income Taxation Considerations

The following summarizes the principal Canadian federal income tax consequences applicable to the holding and disposition of our common shares by a holder who, for purposes of the Income Tax Act (Canada) (the “Tax Act”) and the Canada-U.S. Tax Convention (as defined below under “Certain United States Federal Income Tax Considerations”), is, or is deemed to be, resident in the United States, holds the common shares as capital property and does not use or hold the common shares in the course of carrying on a business in Canada (a “Holder”). The common shares will generally be considered to be capital property unless the Holder holds the common shares in the course of carrying on a business, or acquires the common shares in a transaction or transactions considered to be an adventure in the nature of trade.

This summary is based on the current provisions of the Tax Act, the regulations thereunder, all amendments thereto publicly proposed by the government of Canada, the published administrative practices of the Canada Revenue Agency and the current provisions of the Canada-U.S. Tax Convention. This summary does not otherwise take into account or anticipate any changes in law, whether by way of legislative, judicial or administrative action or interpretation, nor does it address any provincial, territorial or foreign (including without limitation, any United States) tax considerations.

This summary is of a general nature only and it is not intended to be, nor should it be construed to be, legal or tax advice to any particular Holder. Accordingly, Holders are urged to consult with their own tax advisors about the specific tax consequences of acquiring, holding and disposing of common shares.

A Holder will be liable to pay a Canadian withholding tax on every dividend that is or is deemed to be paid or credited to the Holder on the Holder’s common shares. The rate of withholding tax under the Tax Act is 25% of the gross amount of the dividend paid. However, the Canada-U.S. Tax Convention will reduce that withholding tax rate, provided the Holder is eligible for benefits under the Canada-U.S. Tax Convention. Where applicable, the general rate of withholding tax under the Canada-U.S. Tax Convention will be 15% of the gross amount of the dividend, but if the Holder is a company that owns at least 10% of the voting stock of our company, the rate of withholding tax will be reduced to 5%. We will be required to withhold the applicable tax from the dividend payable to the Holder and to remit that tax to the Receiver General for Canada on account of the Holder. Not all persons who are residents of the United States will qualify for benefits under the Canada-U.S. Tax Convention. Holders are advised to consult their own tax advisors in this regard.

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A Holder will generally not be subject to tax under the Tax Act in respect of a capital gain realized on the disposition or deemed disposition of a common share, unless the common share constitutes “taxable Canadian property” to the Holder for purposes of the Tax Act. Provided that the common shares are listed on a “designated stock exchange” for purposes of the Tax Act (which includes the TSX) at the time of disposition, the common shares will generally not constitute “taxable Canadian property” to a Holder unless, at any time during the 60-month period immediately preceding the disposition (i) the Holder, together with persons with whom the Holder does not deal at “arm’s length” for the purposes of the Tax Act, owned 25% or more of the issued shares of any class of our shares and, as such time, (ii) more than 50% of the fair market value of the common shares was derived directly or indirectly from one or a combination of real or immovable property situated in Canada, “Canadian resource properties” or “timber resource properties” (as such terms are defined in the Tax Act), or options or interests in respect of any such properties.

Even if the common shares are taxable Canadian property to a Holder, any taxable capital gain resulting from the disposition of such shares will not be included in computing the Holder’s income for the purposes of the Tax Act if the shares constitute “treaty protected property” for the purpose of the Tax Act.

Provided the common shares are listed at the time of disposition on the TSX or other “recognized stock exchange” for purposes of the Tax Act, a Holder who disposes of common shares will not be required to satisfy the obligations imposed under Section 116 of the Tax Act and, as such, the purchaser of such shares will not be required to withhold any amount on the purchase price paid.

Holders whose common shares may constitute “taxable Canadian property” should consult their own tax advisors.

Certain United States Federal Income Tax Considerations

The following is a general summary of certain material U.S. federal income tax considerations applicable to a U.S. Holder (as defined below) arising from and relating to the acquisition, ownership and disposition of our common shares.

This summary is for general information purposes only and does not purport to be a complete analysis or listing of all potential U.S. federal income tax considerations that may apply to a U.S. Holder arising from and relating to the acquisition, ownership, and disposition of our common shares. In addition, this summary does not take into account the individual facts and circumstances of any particular U.S. Holder that may affect the U.S. federal income tax consequences to such U.S. Holder, including without limitation specific tax consequences to a U.S. Holder under an applicable tax treaty. Accordingly, this summary is not intended to be, and should not be construed as, legal or U.S. federal income tax advice with respect to any U.S. Holder. This summary does not address the U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences to U.S. Holders of the acquisition, ownership, and disposition of our common shares. In addition, except as specifically set forth below, this summary does not discuss applicable tax reporting requirements. Each prospective U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership, and disposition of our common shares.

No legal opinion from U.S. legal counsel or ruling from the Internal Revenue Service (the “IRS”) has been requested, or will be obtained, regarding the U.S. federal income tax consequences of the acquisition, ownership, and disposition of our common shares. This summary is not binding on the IRS, and the IRS is not precluded from taking a position that is different from, and contrary to, the positions taken in this summary. In addition, because the authorities on which this summary are based are subject to various interpretations, the IRS and the U.S. courts could disagree with one or more of the conclusions described in this summary.

Scope of this Summary

Authorities

This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations (whether final, temporary, or proposed), published rulings of the IRS, published administrative positions of the IRS, the Convention Between Canada and the United States of America with Respect to Taxes on Income and on Capital, signed September 26, 1980, as amended (the “Canada-U.S. Tax Convention”), and U.S. court decisions that are applicable and, in each case, as in effect and available, as of the date of this document. Any of the authorities on which this summary is based could be changed in a material and adverse manner at any time, and any such change could be applied on a retroactive or prospective basis which could affect the U.S. federal income tax considerations described in this summary. This summary does not discuss the potential effects, whether adverse or beneficial, of any proposed legislation.

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U.S. Holders

For purposes of this summary, “U.S. Holder” means a beneficial owner of our common shares that is for U.S. federal income tax purposes:

• an individual who is a citizen or resident of the United States;
• a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) organized under the laws of the United States, any state thereof or the District of Columbia;
• an estate whose income is subject to U.S. federal income taxation regardless of its source; or
• a trust that (1) is subject to the primary supervision of a court within the United States and the control of one or more U.S. persons for all substantial decisions or (2) has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person.

U.S. Holders Subject to Special U.S. Federal Income Tax Rules Not Addressed

This summary does not address the U.S. federal income tax considerations applicable to U.S. Holders that are subject to special provisions under the Code, including, but not limited to, the following U.S. Holders that: (a) are tax-exempt organizations, qualified retirement plans, individual retirement accounts, or other tax-deferred accounts; (b) are financial institutions, underwriters, insurance companies, real estate investment trusts, or regulated investment companies; (c) are broker-dealers, dealers, or traders in securities or currencies that elect to apply a mark-to-market accounting method; (d) have a “functional currency” other than the U.S. dollar; (e) own our common shares as part of a straddle, hedging transaction, conversion transaction, constructive sale, or other arrangement involving more than one position; (f) acquired our common shares in connection with the exercise of employee stock options or otherwise as compensation for services; (g) hold our common shares other than as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment purposes); or (h) own, have owned or will own (directly, indirectly, or by attribution) 10% or more of the total combined voting power of our outstanding shares. This summary also does not address the U.S. federal income tax considerations applicable to U.S. Holders who are: (a) U.S. expatriates or former long-term residents of the U.S.; (b) persons that have been, are, or will be a resident or deemed to be a resident in Canada for purposes of the Income Tax Act (Canada) (the “Tax Act”); (c) persons that use or hold, will use or hold, or that are or will be deemed to use or hold our common shares in connection with carrying on a business in Canada; (d) persons whose our common shares constitute “taxable Canadian property” under the Tax Act; or (e) persons that have a permanent establishment in Canada for the purposes of the Canada-U.S. Tax Convention. U.S. Holders that are subject to special provisions under the Code, including, but not limited to, U.S. Holders described immediately above, should consult their own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership and disposition of our common shares.

If an entity or arrangement that is classified as a partnership (or other “pass-through” entity) for U.S. federal income tax purposes holds our common shares, the U.S. federal income tax consequences to such entity and the partners (or other owners) of such entity generally will depend on the activities of the entity and the status of such partners (or owners). This summary does not address the tax consequences to any such owner. Partners (or other owners) of entities or arrangements that are classified as partnerships or as “pass-through” entities for U.S. federal income tax purposes should consult their own tax advisors regarding the U.S. federal income tax consequences arising from and relating to the acquisition, ownership, and disposition of our common shares.

Ownership and Disposition of Common Shares

The following discussion is subject to the rules described below under the heading “Passive Foreign Investment Company Rules.”

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Taxation of Distributions

A U.S. Holder that receives a distribution, including a constructive distribution, with respect to a common share will be required to include the amount of such distribution in gross income as a dividend (without reduction for any foreign income tax withheld from such distribution) to the extent of our current or accumulated “earnings and profits”, as computed for U.S. federal income tax purposes. To the extent that a distribution exceeds our current and accumulated “earnings and profits”, such distribution will be treated first as a tax-free return of capital to the extent of a U.S. Holder's tax basis in our common shares and thereafter as gain from the sale or exchange of such common shares (see “Sale or Other Taxable Disposition of Common Shares” below). However, we may not maintain the calculations of our earnings and profits in accordance with U.S. federal income tax principles, and each U.S. Holder may have to assume that any distribution by us with respect to our common shares will constitute ordinary dividend income. Dividends received on our common shares by corporate U.S. Holders generally will not be eligible for the “dividends received deduction”. Subject to applicable limitations and provided we are eligible for the benefits of the Canada-U.S. Tax Convention, dividends paid by us to non-corporate U.S. Holders, including individuals, generally will be eligible for the preferential tax rates applicable to long-term capital gains for dividends, provided certain holding period and other conditions are satisfied, including that we not be classified as a PFIC (as defined below) in the tax year of distribution or in the preceding tax year. The dividend rules are complex, and each U.S. Holder should consult its own tax advisor regarding the application of such rules.

Sale or Other Taxable Disposition of Common Shares

A U.S. Holder will recognize gain or loss on the sale or other taxable disposition of our common shares in an amount equal to the difference, if any, between (a) the amount of cash plus the fair market value of any property received and (b) such U.S. Holder’s tax basis in such common shares sold or otherwise disposed of. Any such gain or loss generally will be capital gain or loss, which will be long-term capital gain or loss if, at the time of the sale or other disposition, such common shares are held for more than one year.

Preferential tax rates apply to long-term capital gains of a U.S. Holder that is an individual, estate, or trust. There are currently no preferential tax rates for long-term capital gains of a U.S. Holder that is a corporation. Deductions for capital losses are subject to significant limitations under the Code.

Passive Foreign Investment Company Rules

If we were to constitute a PFIC for any year during a U.S. Holder’s holding period, then certain potentially adverse rules would affect the U.S. federal income tax consequences to a U.S. Holder resulting from the acquisition, ownership and disposition of our common shares. We believe that we were not a PFIC during the tax year ended December 31, 2014 and, based on current business plans and financial expectations, we expect that we should not be a PFIC for the current tax year. However, PFIC classification is fundamentally factual in nature, generally cannot be determined until the close of the tax year in question, and is determined annually. Additionally, the analysis depends, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations. Consequently, there can be no assurance that we have never been and will not become a PFIC for any tax year during which U.S. Holders hold our common shares.

In addition, in any year in which we are classified as a PFIC, a U.S. Holder will be required to file an annual report with the IRS containing such information as Treasury Regulations and/or other IRS guidance may require. A failure to satisfy such reporting requirements may result in an extension of the time period during which the IRS can assess a tax. U.S. Holders should consult their own tax advisors regarding the requirements of filing such information returns under these rules, including the requirement to file an IRS Form 8621.

We generally will be a PFIC under Section 1297 of the Code if, after the application of certain “look-through” rules with respect to subsidiaries in which we hold at least 25% of the value of such subsidiary, for a tax year, (a) 75% or more of our gross income for such tax year is passive income (the “income test”) or (b) 50% or more of the value of our assets either produce passive income or are held for the production of passive income (the “asset test”), based on the quarterly average of the fair market value of such assets. “Gross income” generally includes all sales revenues less the cost of goods sold, plus income from investments and from incidental or outside operations or sources, and “passive income” generally includes, for example, dividends, interest, certain rents and royalties, certain gains from the sale of stock and securities, and certain gains from commodities transactions. Active business gains arising from the sale of commodities generally are excluded from passive income if substantially all (85% or more) of a foreign corporation’s commodities are stock in trade or inventory, depreciable property used in a trade or business or supplies regularly used or consumed in the ordinary course of its trade or business, and certain other requirements are satisfied.

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If we were a PFIC in any tax year during which a U.S. Holder held our common shares, such holder generally would be subject to special rules with respect to “excess distributions” made by us on our common shares and with respect to gain from the disposition of our common shares. An “excess distribution” generally is defined as the excess of distributions with respect to the common shares received by a U.S Holder in any tax year over 125% of the average annual distributions such U.S. Holder has received from us during the shorter of the three preceding tax years, or such U.S. Holder’s holding period for our common shares. Generally, a U.S. Holder would be required to allocate any excess distribution or gain from the disposition of our common shares ratably over its holding period for our common shares. Such amounts allocated to the year of the disposition or excess distribution would be taxed as ordinary income, and amounts allocated to prior tax years would be taxed as ordinary income at the highest tax rate in effect for each such year and an interest charge at a rate applicable to underpayments of tax would apply.

While there are U.S. federal income tax elections that sometimes can be made to mitigate these adverse tax consequences (including the “QEF Election” under Section 1295 of the Code and the “Mark-to-Market Election” under Section 1296 of the Code), such elections are available in limited circumstances and must be made in a timely manner.

U.S. Holders should be aware that, for each tax year, if any, that we are a PFIC, we can provide no assurance that we will satisfy the record keeping requirements of a PFIC, or that we will make available to U.S. Holders the information such U.S. Holders require to make a QEF Election with respect to us or any subsidiary that also is classified as a PFIC. U.S. Holders should consult their own tax advisors regarding the potential application of the PFIC rules to the ownership and disposition of our common shares, and the availability of certain U.S. tax elections under the PFIC rules.

Additional Considerations

Additional Tax on Passive Income

Certain individuals, estates and trusts whose income exceeds certain thresholds will be required to pay a 3.8% Medicare surtax on “net investment income” including, among other things, dividends and net gain from disposition of property (other than property held in certain trades or businesses). U.S. Holders should consult their own tax advisors regarding the effect, if any, of this tax on their ownership and disposition of our common shares.

Receipt of Foreign Currency

The amount of any distribution paid to a U.S. Holder in foreign currency, or on the sale, exchange or other taxable disposition of our common shares, generally will be equal to the U.S. dollar value of such foreign currency based on the exchange rate applicable on the date of receipt (regardless of whether such foreign currency is converted into U.S. dollars at that time). A U.S. Holder will have a basis in the foreign currency equal to its U.S. dollar value on the date of receipt. Any U.S. Holder who converts or otherwise disposes of the foreign currency after the date of receipt may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss, and generally will be U.S. source income or loss for foreign tax credit purposes. Different rules apply to U.S. Holders who use the accrual method. Each U.S. Holder should consult its own U.S. tax advisor regarding the U.S. federal income tax consequences of receiving, owning, and disposing of foreign currency.

Foreign Tax Credit

Subject to the PFIC rules discussed above, a U.S. Holder that pays (whether directly or through withholding) Canadian income tax with respect to dividends paid on our common shares generally will be entitled, at the election of such U.S. Holder, to receive either a deduction or a credit for such Canadian income tax. Generally, a credit will reduce a U.S. Holder’s U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Holder’s income subject to U.S. federal income tax. This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Holder during a year.

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Complex limitations apply to the foreign tax credit, including the general limitation that the credit cannot exceed the proportionate share of a U.S. Holder’s U.S. federal income tax liability that such U.S. Holder’s “foreign source” taxable income bears to such U.S. Holder’s worldwide taxable income. In applying this limitation, a U.S. Holder’s various items of income and deduction must be classified, under complex rules, as either “foreign source” or “U.S. source.” Generally, dividends paid by a foreign corporation should be treated as foreign source for this purpose, and gains recognized on the sale of stock of a foreign corporation by a U.S. Holder should be treated as U.S. source for this purpose, except as otherwise provided in an applicable income tax treaty, and if an election is properly made under the Code. However, the amount of a distribution with respect to our common shares that is treated as a “dividend” may be lower for U.S. federal income tax purposes than it is for Canadian federal income tax purposes, resulting in a reduced foreign tax credit allowance to a U.S. Holder. In addition, this limitation is calculated separately with respect to specific categories of income. The foreign tax credit rules are complex, and each U.S. Holder should consult its own U.S. tax advisor regarding the foreign tax credit rules.

Backup Withholding and Information Reporting

Under U.S. federal income tax law, certain categories of U.S. Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation. For example, U.S. return disclosure obligations (and related penalties) are imposed on individuals who are U.S. Holders that hold certain specified foreign financial assets in excess of certain threshold amounts. The definition of specified foreign financial assets includes not only financial accounts maintained in foreign financial institutions, but also, unless held in accounts maintained by a financial institution, any stock or security issued by a non-U.S. person, any financial instrument or contract held for investment that has an issuer or counterparty other than a U.S. person and any interest in a foreign entity. U. S. Holders may be subject to these reporting requirements unless they hold our common shares in an account at certain financial institutions. Penalties for failure to file certain of these information returns are substantial. U.S. Holders should consult their own tax advisors regarding the requirements of filing information returns, including the requirement to file an IRS Form 8938.

Payments made within the U.S. or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from the sale or other taxable disposition of, our common shares will generally be subject to information reporting and backup withholding tax, at the rate of 28%, if a U.S. Holder (a) fails to furnish such U.S. Holder’s correct U.S. taxpayer identification number (generally on Form W-9), (b) furnishes an incorrect U.S. taxpayer identification number, (c) is notified by the IRS that such U.S. Holder has previously failed to properly report items subject to backup withholding tax, or (d) fails to certify, under penalty of perjury, that such U.S. Holder has furnished its correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Holder that it is subject to backup withholding tax. However, certain exempt persons generally are excluded from these information reporting and backup withholding rules. Backup withholding is not an additional tax. Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Holder’s U.S. federal income tax liability, if any, or will be refunded, if such U.S. Holder furnishes required information to the IRS in a timely manner.

The discussion of reporting requirements set forth above is not intended to constitute a complete description of all reporting requirements that may apply to a U.S. Holder. A failure to satisfy certain reporting requirements may result in an extension of the time period during which the IRS can assess a tax, and under certain circumstances, such an extension may apply to assessments of amounts unrelated to any unsatisfied reporting requirement. Each U.S. Holder should consult its own tax advisor regarding the information reporting and backup withholding rules.

F.           Dividends and Paying Agents

Not applicable.

G.           Statement by Experts

Not applicable.

H.           Documents on Display

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We are subject to the informational requirements of the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a foreign private issuer, we are exempt from the rules and regulations under the Exchange Act prescribing the furnishing and content of proxy statements, and our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions contained in Section 16 of the Exchange Act, with respect to their purchase and sale of our shares. In addition, we are not required to file reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act. However, we are required to file with the SEC, within four months after the end of each fiscal year, an annual report on Form 20-F containing financial statements audited by an independent accounting firm. We publish unaudited interim financial information after the end of each quarter. We furnish this quarterly financial information to the SEC under cover of a Form 6-K.

You may read and copy any of our reports and other information at, and obtain copies upon payment of prescribed fees from, the Public Reference Room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. In addition, the SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

The documents concerning us referred to in this Form 20-F may be viewed at our executive offices during normal business hours.

We are required to file reports and other information with the securities commissions in Canada. You are invited to read and copy any reports, statements or other information, other than confidential filings, that we file with the provincial securities commissions. These filings are also electronically available from SEDAR at www.sedar.com, the Canadian equivalent of the SEC’s electronic document gathering and retrieval system.

I.           Subsidiary Information

Not applicable.

ITEM 11.                     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See the discussion under the heading “Item 5. Operating and Financial Review and Prospects – Financial Instruments and Risk Management” as well as Notes 5 and 6 to our audited financial statements for the years ended December 31, 2014 and December 31, 2013, and ten months ended December 31, 2012 filed as part of this Form 20-F.

ITEM 12.                     DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.

PART II

ITEM 13.                     DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14.                     MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

The Shareholders Rights Plan Agreement between us and Computershare Investor Services Inc., as amended, was originally executed on March 9, 2010. The Shareholder Rights Plan was thereafter approved by our shareholders at our Annual General Meeting held on August 17, 2010, extended for two years at our Annual General and Special Meeting held on August 17, 2012 and extended for two years at our Annual General and Special Meeting held on June 6, 2014. The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any take-over bid for us. The Shareholder Rights Plan provides our Board of Directors and the shareholders with more time to fully consider any unsolicited take-over bid for us; it will allow our Board of Directors to pursue, if appropriate, other alternatives to maximize shareholder value and it will allow additional time for competing bids to emerge. Existing securities legislation in Canada requires a take-over bid to remain open for only thirty-five (35) days. Our Board of Directors does not believe that this period is sufficient to permit them to determine whether there may be alternatives available to maximize shareholder value or whether other bidders may be prepared to pay more for our shares than the Offeror (as defined in the Shareholder Rights Plan). In addition, our Board of Directors is concerned that, while securities legislation has addressed many concerns of unequal treatment of shareholders, there remains the possibility that control or effective control may be acquired pursuant to a private agreement in which a small number of shareholders dispose of shares at a premium to market price which is not shared with the other shareholders. Also, a person may slowly accumulate shares through stock exchange acquisitions which may result, over time, in an acquisition of control without payment of fair value for control or fair sharing of any control premium among all shareholders. The Shareholder Rights Plan addresses these concerns by applying to all acquisitions of 20% or more of our common shares. See the discussion under the heading “Item 6.B. – Shareholder Rights Plan.”

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On March 12, 2014, our Board of Directors approved and adopted the Advance Notice Policy, which was approved by the shareholders on June 6, 2014. The purpose of the Advance Notice Policy is to provide shareholders, the Board of Directors and management with a clear framework for nominating directors. The Advance Notice Policy fixes a deadline by which holders of record of our common shares must submit director nominations to us prior to any annual general or special meeting of shareholders and sets forth the information that a shareholder must include in the notice to us for the notice to be in proper written form in order for any director nominee to be eligible for election at any annual or special meeting of shareholders. A complete copy of the Advance Notice Policy is included as an exhibit to this Form 20-F.

ITEM 15.                     CONTROLS AND PROCEDURES

A.           Disclosure Controls and Procedures

As of the end of the fiscal year ended December 31, 2014, an evaluation of the effectiveness of our company’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, was performed by our company’s management, under the supervision and with the participation of our company’s Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our company’s Chief Executive Officer and Chief Financial Officer have concluded that as a result of the material weaknesses in our internal control over financial reporting disclosed below, our company’s disclosure controls and procedures were not effective to give reasonable assurance that the information required to be disclosed by our company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

B.           Management’s Report on Internal Control over Financial Reporting

Our company’s management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, which in the case of our company is IFRS, and that receipts and expenditures are being made only in accordance with authorizations of management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

It should be noted that because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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Our company’s management (with the participation of our Chief Executive Officer and Chief Financial Officer) conducted an evaluation of our company’s internal control over financial reporting as of December 31, 2014. This evaluation was based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, management has concluded that, as of December 31, 2014, our internal control over financial reporting was not effective because management identified material weaknesses in our internal control over financial reporting. In particular, material weaknesses were identified with respect to (i) our process for evaluating and reviewing impairment indicators over petroleum and natural gas properties and (ii) our process for determining our decommissioning obligations.

We are in the process of enhancing our internal controls in order to remediate these material weaknesses.

C.           Attestation Report of the Registered Public Accounting Firm

Because we are a “non-accelerated filer”, this Form 20-F is not required to include an attestation report of our independent auditors regarding internal control over financial reporting.

D.           Changes in Internal Control Over Financial Reporting

There were no changes to our internal control over financial reporting during the year ended December 31, 2014. However, we are in the process of making changes to our internal control over financial reporting in order to remediate the material weaknesses identified above and strengthen our system of internal control over financial reporting.

ITEM 16A.                  AUDIT COMMITTEE FINANCIAL EXPERT

We do not have a financial expert, as defined by the SEC, serving on our Audit Committee. In 2011, we adopted IFRS to comply with Canadian public company reporting standards. The Audit Committee members do not, as yet, have sufficient experience and in-depth understanding of IFRS to qualify as audit committee financial experts.

ITEM 16B.                  CODE OF ETHICS

Our Board of Directors has adopted a Code of Business Conduct and Ethics that meets the definition of a “code of ethics” in Form 20-F (the “Code”) and which applies toall of our officers, directors and employees and contractors. The Code reflects our commitment to a culture of honesty, transparency and accountability, and outlines the basic principles and policies with which the directors, officers, employees and contractors are expected to comply.

A copy of the Code may be viewed on our website at www.hemisphereenergy.ca. Alternatively, a printed copy may be requested by mail to Suite 2000, 1055 West Hastings Street, Vancouver, British Columbia V6E 2E9, Attention: Annalisa Whittle by email to info@hemisphereenergy.ca or by telephone to (604) 685-9255.

We intend to disclose and summarize any amendment to, or waiver from, any provision of the Code that is required to be so disclosed and summarized, on our website at www.hemisphereenergy.ca.

ITEM 16C.                  PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our external auditor is Smythe Ratcliffe LLP located at Suite 700, 355 Burrard Street, Vancouver, British Columbia V6C 2G8.

The fees billed to us by Smythe Ratcliffe, LLP, our external auditor, in each of the last two fiscal years are as follows:

Notes:

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Pre-Approval Policies and Procedures

The Audit Committee, in accordance with procedures for our company, approved all of the services described above.

In relation to the pre-approval of all audit and audit-related services and fees the charter of the Audit Committee provides that our company’s external auditors are prohibited from providing any non-audit services to our company without the written consent of the Audit Committee unless such non-audit services are De Minimus Non-Audit Services as outlined in section 2.4 of NI 52-110. In determining whether the external auditors will be granted permission to provide non-audit services, the Audit Committee is to consider that the benefits to our company from the provision of such services outweighs the risk of any compromise to, or loss of, the independence of the external auditors in carrying out their auditing mandate.

We did not rely on the de minimus exemption provided by Section (c)(7)(i)(C) of Rule 2-01 of SEC Regulation S-X or of section 2.4 of NI 52-1101 in 2014.

ITEM 16D.                  EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not applicable.

ITEM 16E.                  PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

We did not purchase any common shares in the fiscal year ended December 31, 2014.

ITEM 16F.                  CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

None.

ITEM 16G.                  CORPORATE GOVERNANCE

Not applicable.

ITEM 16H.                  MINE SAFETY DISCLOSURE

Not applicable.

PART III

ITEM 17.                     FINANCIAL STATEMENTS

See “Item 18. Financial Statements”.

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ITEM 18.                     FINANCIAL STATEMENTS

See the “Index to Financial Statements” in this Form 20-F for a list of the financial statements filed as part of this Form 20-F.

ITEM 19.                     EXHIBITS