Form 6-K HEMISPHERE ENERGY CORP For: Dec 31

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

Form 6-K

REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16 OR 15d-16 OF
THE SECURITIES EXCHANGE ACT OF 1934

For the month of April, 2015.

Commission File Number: 000-55253

Hemisphere Energy Corporation
(Translation of registrant's name into English)

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

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F [X]              Form 40-F [   ]

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1) [   ]

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7) [   ]

DOCUMENTS FILED AS PART OF THIS FORM 6-K

See the Exhibit Index hereto.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

2

EXHIBIT INDEX

HEMISPHERE ENERGY ANNOUNCES YEAR-END 2014
FINANCIAL AND OPERATING RESULTS

TSX-V: HME

Vancouver, British Columbia, April 22, 2015 – Hemisphere Energy Corporation (TSX-V: HME) ("Hemisphere" or the "Company") is pleased to announce its financial and operating results for the year ended December 31, 2014.

Hemisphere focused on developing its Atlee Buffalo and Jenner oil assets in 2014 resulting in substantial year-over-year growth both financially and operationally. A bought deal financing for $10.0 million was closed in May 2014 which allowed the Company to accelerate its first phase of development in Atlee Buffalo, southeast Alberta. Two back-to-back drilling programs took place in the summer and fall which contributed to production and reserves increases.

2014 Highlights

Selected financial and operational highlights should be read in conjunction with Hemisphere’s audited annual financial statements and related Management’s Discussion and Analysis for the year ended December 31, 2014. These reports, including the Company’s Annual Information Form for the year ended December 31, 2014, are available on SEDAR at www.sedar.com and on Hemisphere’s website at www.hemisphereenergy.ca. All amounts are expressed in Canadian dollars.

Financial and Operating Summary

As announced April 21, 2015, the Company has restated certain financial information for the year ended December 31, 2013 (the "2013 Restatement") which has been disclosed in Note 4 of the audited annual financial statements for the year ended December 31, 2014.

The material changes included in the 2013 Restatement affect the Company’s impairment, depletion, and decommissioning costs and will have a positive impact, significantly reducing the Company’s 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 International Financial Reporting Standards and a change in accounting policy applied retrospectively, Hemisphere’s petroleum and natural gas interests increased by $4.0 million. In addition, Hemisphere has incorporated the Alberta Energy Regulator 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.

The decision to restate followed an audit review and the impact was confirmed during the finalization of the Company’s 2014 audited annual financial statements. The 2013 Restatement has been released in conjunction with the filing of the Company’s audited annual financial statements for the year ended December 31, 2014.

2015 Outlook

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

At current oil prices, Hemisphere’s production remains cash flow positive due to its low operating costs. The Company is presently optimizing its production base in the Jenner and Atlee Buffalo core areas while minimizing operating costs. Field estimated production for the first quarter of 2015 is approximately 980 boe/d (86% oil and NGL). Hemisphere will continue to focus on reducing its current net debt of approximately $10.6 million to expand its financial flexibility to pursue potential acquisitions and maximize long-term shareholder value. Hemisphere is well positioned to act quickly in response to a positive change in commodity prices with a large variety of low-risk development opportunities.

Annual General and Special Meeting of Shareholders

Hemisphere’s Annual General and Special Meeting of Shareholders is being held in the Pender Room of Oceanic Plaza, 1035 West Pender Street, Vancouver, British Columbia on Friday, June 5, 2015 at 9:00 a.m. (Pacific Daylight Time).

About Hemisphere Energy Corporation

Hemisphere Energy Corporation is a producing oil and gas company focused on developing conventional oil assets with low risk drilling opportunities. Hemisphere plans continual growth in production, reserves and cash flow by drilling existing projects and executing strategic acquisitions. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol "HME".

Forward-looking Statements

This news release contains "forward-looking statements" that are based on Hemisphere's current expectations, estimates, forecasts and projections. These forward-looking statements include statements regarding Hemisphere's outlook for our future operations, plans and timing for the commencement or advancement of exploration and development activities on our properties, and other expectations, intention and plans that are not historical fact. The words "estimates", "projects", "expects", "intends", "believes", "plans", or their negatives or other comparable words and phrases are intended to identify forward-looking statements. Such forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from future results expressed or implied by such forward-looking statements. Many of these factors are beyond the control of Hemisphere. Consequently, all forward-looking statements made in this news release are qualified by this cautionary statement and there can be no assurance that actual results or developments anticipated by Hemisphere will be realized. For the reasons set forth above, investors should not place undue reliance on such forward-looking statements. Hemisphere disclaims any intention or obligation to update or revise forward-looking information, whether as a result of new information, future events or otherwise.

A barrel 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.

Definitions and abbreviations

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.

MANAGEMENT’S REPORT

To the Shareholders of Hemisphere Energy Corporation:

Management is responsible for the preparation of the financial statements and the consistent presentation of all other financial information that is publicly disclosed. The financial statements have been prepared in accordance with the accounting policies detailed in the notes to the financial statements and in accordance with IFRS and include estimates and assumptions based on management’s best judgment. Management maintains a system of internal controls to provide reasonable assurance that assets are safeguarded and that relevant and reliable financial information is produced in a timely manner. Independent auditors appointed by the shareholders have examined the financial statements. Their report is presented with the financial statements. The Audit Committee, consisting of independent members of the Board of Directors, has reviewed financial statements with management and the independent auditors. The Board of Directors has approved the financial statements on the recommendation of the Audit Committee.

Vancouver, British Columbia
April 21, 2015

INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Hemisphere Energy Corporation:

We have audited the accompanying financial statements of Hemisphere Energy Corporation, 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 2013, and the ten months ended December 31, 2012, and a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion
In our opinion, the financial statements present fairly, in all material respects, the financial position of Hemisphere Energy Corporation as at December 31, 2014, December 31, 2013 and January 1, 2013, and its financial performance and its cash flows for the years ended December 31, 2014 and 2013, and the ten months ended December 31, 2012 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Comparative Information
Without modifying our opinion, we draw attention to Note 4 to the financial statements as at December 31, 2013 and January 1, 2013, and for the year ended December 31, 2013 and for the ten months ended December 31, 2012, which indicates that the comparative information presented has been restated.

Chartered Accountants

Vancouver, Canada
April 21, 2015

STATEMENTS OF FINANCIAL POSITION
(Expressed in Canadian dollars)

The accompanying notes are an integral part of these financial statements.

On Behalf of the Board of Directors

STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
(Expressed in Canadian dollars)

The accompanying notes are an integral part of these financial statements.

STATEMENTS OF CASH FLOWS
(Expressed in Canadian dollars)

The accompanying notes are an integral part of these financial statements.
Supplemental cash flow information (Note 16)

STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Expressed in Canadian dollars)

The accompanying notes are an integral part of these financial statements.

NOTES TO THE FINANCIAL STATEMENTS
For the years ended December 31, 2014 and December 31, 2013,
and ten months ended December 31, 2012
(Expressed in Canadian dollars)

Hemisphere Energy Corporation (the "Company") was incorporated under the laws of British Columbia on March 6, 1978. The Company’s principal business is the acquisition, exploration, development and production of petroleum and natural gas interests in Canada. It is a publicly traded company listed on the TSX Venture Exchange under the symbol "HME". The Company’s head office is located at Suite 2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9.

These financial statements are prepared in accordance with International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board ("IASB").

These financial statements were authorized for issuance by the Board of Directors on April 21, 2015.

These financial statements have been prepared on a historical cost basis, except for financial instruments and share-based payments, which are stated at their fair values. In addition, these financial statements have been prepared using the accrual basis of accounting, except for cash flow information.

During 2012, the Company changed its year end from February 29 to December 31, resulting in a ten month period presented for the December 31, 2012 financial statements.

These annual financial statements are presented in Canadian dollars, which is the Company’s functional currency.

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 the Company believes 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 the Company’s development and production assets have been impaired. Changes in reported reserves can impact asset carrying values due to changes in expected future cash flows.

The Company’s 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")

The Company’s 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, the Company assesses its 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 by the Company 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 the Company’s decommissioning obligations, see Note 10.

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

The Company measures the cost of its 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 the Company’s share-based payments see Note 13(b).

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.

The Company classifies its financial assets in the following categories: held-to-maturity, fair value through profit or loss ("FVTPL"), loans and receivables, and available-for-sale ("AFS"). The classification depends on the purpose for which the financial assets were acquired. Management determines the classification of financial assets at recognition.

Held-to-maturity

Held-to-maturity financial assets are recognized on a trade-date basis and are initially measured at fair value using the effective interest rate method. The Company has no assets classified as held-to-maturity.

Financial assets at fair value through profit or loss

Financial assets at FVTPL are initially recognized at fair value with changes in fair value recorded through profit or loss.

Loans and receivables

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are classified as current assets or non-current assets based on their maturity date. Loans and receivables are carried at amortized cost less any impairment. Loans and receivables are comprised of accounts receivable and reclamation deposits.

Available-for-sale financial assets

AFS financial assets are non-derivatives that are either designated as available-for-sale or not classified in any of the other financial asset categories. Changes in the fair value of AFS financial assets are recognized as other comprehensive income and classified as a component of equity.

Management assesses the carrying value of any AFS financial assets at least annually and any impairment charges are also recognized in profit or loss. When financial assets classified as AFS are sold, the accumulated fair value adjustments recognized in other comprehensive income are included in profit or loss. The Company does not have any financial instruments classified as AFS.

Borrowings and other financial liabilities

Borrowings and other financial liabilities are non-derivatives and are recognized initially at fair value, net of transaction costs incurred, and are subsequently stated at amortized cost. Any difference between the amounts originally received, net of transaction costs, and the redemption value is recognized in profit or loss over the period to maturity using the effective interest method.

Borrowings and other financial liabilities are classified as current or non-current based on their maturity date. Financial liabilities are comprised of accounts payable and accrued liabilities and bank indebtedness.

Fair value measurements of financial instruments are required to be classified using a fair value hierarchy that reflects the significance of inputs in making the measurements. The levels of the fair value hierarchy are defined as follows:

Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

Level 3 - Inputs for the asset or liability that are not based on observable market data.

Additional disclosure on the measurement of financial instruments is provided in Note 5.

Revenue from the sale of petroleum and natural gas is recorded when title passes to an external party and is based on volumes delivered to customers at contractual delivery points and rates, and collectability is reasonably assured. The costs associated with delivery, including operating and maintenance costs, transportation and royalty expenses, are recognized during the same period in which the related revenue is earned and reported.

Some of the Company’s petroleum and natural gas activities are jointly conducted with other venturers who have direct ownership in and jointly control the operations of the ventures. Accordingly the financial statements reflect the Company’s share of joint assets, liabilities, revenues and expenses.

Expenditures made by the Company before acquiring the legal right to explore in a specific area do not meet the definition of an asset and therefore are expensed as incurred.

Costs incurred once the legal right to explore has been acquired are capitalized as exploration and evaluation assets. These costs include, but are not limited to, exploration license expenditures, leasehold property acquisition costs, evaluation costs, drilling costs directly attributable to an identifiable well, and directly attributable general and administrative costs. These costs are accumulated in cost centers by property and are not subject to depletion until technical feasibility and commercial viability has been determined.

Exploration and evaluation assets are assessed for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount.

The technical feasibility and commercial viability are considered to be determinable when Proved and Probable reserves have been identified. A review of each exploration license or field is carried out, at each reporting date, to ascertain whether Proved and Probable reserves have been discovered. Upon determination of Proved and Probable reserves, exploration and evaluation assets attributable to those reserves are tested for impairment and reclassified from exploration and evaluation assets to petroleum and natural gas properties.

Items of property and equipment, which include petroleum and natural gas development and production assets, are measured at cost less accumulated depletion and depreciation and impairment losses.

Gains and losses on disposal of an item of property and equipment, including petroleum and natural gas properties, are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized in profit or loss.

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property and equipment are recognized as petroleum and natural gas properties only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized petroleum and natural gas properties generally represent costs incurred in developing Proved and/or Probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property and equipment are recognized in profit or loss as incurred.

Depletion of petroleum and natural gas properties is determined using the unit-of-production method based on production volumes in relation to total estimated Proved and Probable reserves as determined annually by independent engineers and determined in accordance with NI 51-101. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

The calculation of depletion and depreciation is based on total capitalized costs plus estimated future development costs of Proved and Probable non-producing and undeveloped reserves less the estimated net realizable value of production equipment and facilities after the Proved reserves are fully produced.

Proved reserves are estimated using independent reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids, which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 percent statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as Proved and Probable and a 50 percent statistical probability that it will be less. The equivalent statistical probabilities for the proved component of Proved and Probable reserves are 90 percent and 10 percent, respectively.

Such reserves may be considered commercially producible if management has the intention of developing and producing them. Such intention is based upon:

Reserves may only be considered Proved if supported by either actual production or conclusive formation tests. The area of reservoir considered Proved includes (a) that portion delineated by drilling and defined by as-oil and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of oil and natural gas controls the lower Proved limit of the reservoir.

Reserves that can be produced economically through application of improved recovery techniques such as fluid injection are only included in the Proved classification when successful testing by a pilot project, the operation of an installed program in the reservoir or other reasonable evidence (such as, experience of the dame techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or program was based.

Depreciation of other equipment is provided for on a 20-30% declining balance basis. Depreciation methods, useful lives and residual values are reviewed at each reporting date.

Exploration and evaluation assets are assessed for impairment when they are reclassified to developing and producing assets, as petroleum and natural gas properties, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.

An impairment is recorded when the recoverable amount of an asset is less than the respective carrying amount. Recoverable amount is the higher of its fair value less cost to sell and value in use. Fair value is the price that would be received from selling an asset in an orderly transaction between market participants. Fair value less costs to sell can be determined by using an observable market or by using discounted future net cash flows of Proved and Probable reserves using forecasted prices and costs. Value in use is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or CGU.

Exploration and evaluation assets are grouped together with the Company's CGUs when they are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to developing and producing assets (petroleum and natural gas properties).

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. A CGU's recoverable amount is the higher of its fair value less costs to sell and its value in use. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of goodwill, if any, allocated to the units and then to reduce carrying amounts of other assets in the unit (group of units) on a pro rata basis.

Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

Decommissioning obligations are measured at the present value of management’s best estimate of expenditures required to settle the present obligation at the statement of financial position date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision.

The Company has a stock option plan that is described in Note 13(b). Share-based payments to employees are measured at the fair value of the instruments issued and are amortized over the vesting periods. Share-based payments to non-employees are measured at the fair value of the goods or services received or the fair value of the equity instruments issued, if it is determined the fair value of the goods or services cannot be reliably measured, and are recorded at the date the goods or services are received. The amount recognized as an expense is adjusted to reflect the number of awards expected to vest. The offset to the recorded cost is to share-based payments reserve. Consideration received on the exercise of stock options is recorded as capital stock and the related share-based payments reserve is transferred to capital stock. Charges for options that are forfeited before vesting are reversed from share-based payments reserve. For those options that expire after vesting, the recorded value is transferred to deficit.

The Company uses the residual value method with respect to the measurement of equity units. The proceeds from the issue of units is allocated between common shares and share purchase warrants on a residual value basis, wherein the fair value of the common shares is based on the market close on the date the units are issued; the balance, if any, is allocated to the attached warrants. Share issue costs are netted against share proceeds.

The Company may, from time to time, issue flow-through common shares to finance its petroleum and natural gas exploration activities. Canadian income tax law permits the Company to renounce to the flow-through shareholders the income tax attributes of certain petroleum and natural gas exploration and evaluation costs financed by such shares. A liability is recognized for any premium on the flow-through shares and is subsequently reversed as the Company incurs qualifying Canadian exploration expenses.

In circumstances where the Company has issued flow-through shares by way of a unit offering, the proceeds are allocated first to common shares based on the market close at the time the units are priced, and any residual value is allocated next to the warrants reserve based on the fair value of the warrant component using the Black-Scholes option pricing model on grant date. Any remaining residual value is then recognized as a liability for the premium on the flow-through shares.

Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss, except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current income tax expense is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred income tax is recognized using the balance sheet liability method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred income tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred income tax assets and liabilities are offset if there is a legally enforceable right to offset and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred income tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Basic loss per share is calculated by dividing the profit or loss attributable to common shareholders of the Company by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the profit or loss attributable to common shareholders and the weighted-average number of shares outstanding for the effects of dilutive instruments such as options and warrants.

The Company uses the treasury stock method to compute the dilutive effect of options, warrants and similar instruments. Under this method the dilutive effect on earnings per share is calculated presuming the exercise of outstanding options, warrants and similar instruments. It assumes that proceeds received from the exercise of stock options and warrants would be used to repurchase common shares at the average market price during the year. However, the calculation of diluted loss per share excludes the effects of various conversions and exercise of options and warrants that would be anti-dilutive.

Shares held in escrow other than where their release is subject to the passage of time are excluded from the computation of loss per share until the conditions for their release are satisfied.

Effective January 1, 2014, the Company adopted the following:

The IASB or IFRIC have issued pronouncements effective for accounting periods beginning on or after January 1, 2015. Only those which may significantly impact the Company are discussed below:

The five steps in the model are as follows:

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 the Company's annual period beginning on January 1, 2017. The Company has not assessed the impact of this pronouncement.

Applicable to the Company's annual period beginning on January 1, 2018. The Company has not assessed the impact of this pronouncement.

The Company’s financial statements for the periods ended December 31, 2013, January 1, 2013 and December 31, 2012, have been restated for the following items:

Property and equipment

Depreciation and depletion

The Company changed its accounting for depleting its petroleum and natural gas properties. The Company’s acquisition of its core Jenner and Atlee Buffalo properties resulted in higher Proved plus Probable reserves. With the Company’s additional equity financings and banking facilities, its ability and plans have expanded to further the development of its exploration assets and Probable reserves. As a result, the Company changed from using the unit-of-production method based on production volumes in relation to total estimated Proved reserves to total estimated Proved and Probable reserves. This both accurately reflects the change in circumstance and aligns the Company’s method of estimating depletion with the majority of petroleum and natural gas producing companies. The change in accounting policy has been applied retrospectively, and accordingly, the Company has revised certain prior year amounts.

Impairment

As a result of the Company changing its accounting to include Proved and Probable reserves, the impairment of property and equipment has been revised. In addition, the Company reassessed its indicators of impairment on its core petroleum and natural gas properties, which resulted in a decrease of impairment of $5,084,200 for the year ended December 31, 2013.

Decommissioning obligations

In determining decommissioning obligations, the Company has changed its estimate using the information as set out by the Alberta Energy Regulator ("AER") in Directive 011, as its primary source of estimating future abandonment and reclamation costs.

The following table outlines the effect of the changes made to the financial statements as originally filed:

Impact on the Statements of Financial Position as at December 31, 2013 and January 1, 2013

Impact on the Statements of Loss and Comprehensive Loss for the year ended December 31, 2013, and the 10 months ended December 31, 2012

Impact on the Statements of Cash Flows for the year ended December 31, 2013, and the 10 months ended December 31, 2012

As shown in the table above, all adjustments affected only non-cash items; therefore, there was no impact to cash provided by operating activities and no impact to cash used in investing activities or cash provided by financing activities.

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. At December 31, 2014, the Company's financial instruments include accounts receivable, reclamation deposits, bank indebtedness, and accounts payable and accrued liabilities.

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

The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production and financing activities such as credit risk, liquidity risk and market risk. This note presents information about the Company’s exposure to each of these risks. Management sets controls to manage such risks and monitors them on an ongoing basis pertaining to market conditions and the Company’s activities.

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its payment obligations. This risk arises principally from the Company’s receivables from joint operators and oil and natural gas marketers, and reclamation deposits. The credit risk associated with reclamation deposits is minimized substantially by ensuring this financial asset is 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 the Company monitors monthly balances to limit the risk associated with collections. The Company does not anticipate any default. There are no balances past due or impaired.

The maximum exposure to credit risk is as follows:

The Company sells the majority of its oil production to a single oil marketer and, therefore, is subject to concentration risk which is mitigated by management’s policies and practices related to credit risk, as discussed above. The Company historically has never experienced any collection issues with its oil marketer.

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company’s approach to managing liquidity risk is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when they become due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company.

At December 31, 2014, the Company 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). The Company funds its operations through production revenue and a demand operating credit facility (Note 12). All of the Company’s financial liabilities have contractual maturities of less than 90 days.

Market risk is the risk that changes in market prices, such as foreign exchange rates, other 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 is the risk that future cash flows will fluctuate as a result of changes in market interest rates. Borrowings under the Company’s 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.

The Company’s functional and reporting currency is the Canadian dollar. The Company does not sell or transact in any foreign currency; however, commodity prices are largely denominated in United States dollars ("USD"), and as a result the prices that the Company receives 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 by the Company for its crude oil and natural gas sales. The Company did not have any foreign exchange rate swaps or related contracts in place as at the date of this document.

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 the Company’s ability to raise capital. The Company has not entered into any commodity hedge contracts as at the date of this document.

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

The Company manages its capital with the following objectives:

The Company monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the Company and industry in general. The capital structure of the Company is composed of shareholders’ equity and the undrawn component of the Company’s credit facilities. The Company may manage its capital structure by issuing new shares, repurchasing outstanding shares, obtaining additional financing from the Company’s credit facilities, issuing new debt instruments or other financial or equity–based instruments, adjusting capital spending or disposing of assets. The capital structure is reviewed on an ongoing basis.

The Company’s capital structure as at December 31, 2014 and 2013 is as follows:

As at December 31, 2014, the Company had total available credit facilities of $15,000,000 (December 31, 2013 - $10,500,000) of which the Company had drawn $7,184,147 (December 31, 2013 - $4,500,000) (Note 12). At December 31, 2014, the Company was subject to externally imposed capital requirements as described in Note 12.

Exploration and evaluation assets consist of the Company’s exploration projects, which are pending the determination of Proved and Probable reserves. A transfer from exploration and evaluation assets to property and equipment is made when the well has come on production or the exploration project has been completed. For the year ended December 31, 2014, the Company transferred $993,271 (December 31, 2013 - $1,185,051) to property and equipment.

Property acquisitions not constituting a business combination

On February 28, 2014, the Company closed an acquisition of a non-producing property for proceeds of $100,000 which included 1.75 sections (1,120 acres) in the surrounding Jenner area.

On May 29, 2014, the Company closed an acquisition in the Atlee Buffalo property for proceeds of $510,000 which included an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to the Company’s existing Atlee property.

During the year ended December 31, 2014, the Company also purchased property mineral lease rights for total proceeds of $247,296 in various Crown land sales through the Alberta Department of Energy. The leases purchased were located in both Jenner and Atlee Buffalo.

On November 14, 2013, the Company closed the acquisition of the oil and gas assets in the Atlee Buffalo property in southeastern Alberta. The Company acquired a 100% working interest in land and tangible assets in the Atlee Buffalo property for total cash consideration of $3,155,195 (net of June to September 2013 net production revenue). The fair value of the net assets acquired was equal to the cash consideration paid, and no goodwill or bargain purchase gain was recorded in the transaction.

During the 2013 fiscal year, the Company also purchased properties for total expenditures of $132,582 in various Crown land sales through the Alberta Department of Energy. These properties were all located in Jenner.

During the year ended December 31, 2014, the Company performed an assessment of potential impairment indicators, and management determined that with the recent decline in commodity prices that an impairment test on its petroleum and natural gas assets was required. It was determined that the carrying amount of three CGUs exceeded their recoverable amounts aggregating $25,389,350 for the year ended December 31, 2014 (year ended December 31, 2013 - $145,800; ten months ended December 31, 2012 - $442,000). Accordingly, the Company recognized an impairment charge of $2,702,925 for the year ended December 31, 2014 (year ended December 31, 2013 - $556,371; ten months ended December 31, 2012 - $184,938). The recoverable amounts were determined with fair value less costs to sell using a discounted cash flow method and categorized in Level 3 of the fair value hierarchy. Key assumptions in the determination of cash flows from reserves include crude oil and natural gas prices, loss factors and 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. The following table show the future commodity price estimates used by the Company’s independent reserves evaluator at December 31, 2014 and 2013: