DAYBREAK OIL & GAS, INC. - Quarter Report: 2013 August (Form 10-Q)

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION

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PART I

FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

DAYBREAK OIL AND GAS, INC.

Balance Sheets – Unaudited

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

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DAYBREAK OIL AND GAS, INC.

Statements of Operations – Unaudited

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

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DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows – Unaudited

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

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DAYBREAK OIL AND GAS, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION:

Organization

Originally incorporated as Daybreak Uranium, Inc., (“Daybreak Uranium”) under the laws of the State of Washington on March 11, 1955, Daybreak Uranium was organized to explore for, acquire, and develop mineral properties in the Western United States.  During 2005, management of the Company decided to enter the oil and gas exploration and production industry.  On October 25, 2005, the Company shareholders approved a name change from Daybreak Mines, Inc. to Daybreak Oil and Gas, Inc. (referred to herein as “Daybreak” or the “Company”) to better reflect the business of the Company.

All of the Company’s oil and gas production is sold under contracts which are market-sensitive.  Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

Basis of Presentation

The accompanying unaudited interim financial statements and notes for the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q for quarterly reports under Section 13 or 15 (d) of the Securities Exchange Act of 1934 (the “Exchange Act”).  Accordingly, they do not include all of the information and footnote disclosures normally required by accounting principles generally accepted in the United States of America for complete financial statements.

In the opinion of management, all adjustments considered necessary for a fair presentation of the financial statements have been included and such adjustments are of a normal recurring nature.  Operating results for the six months ended August 31, 2013 are not necessarily indicative of the results that may be expected for the fiscal year ending February 28, 2014.

These financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended February 28, 2013.

Use of Estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions.  These estimates and assumptions may affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and revenues and expenses during the reporting period.  Actual results could differ materially from those estimates.  The accounting policies most affected by management’s estimates and assumptions are as follows:

·

The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any impairment of proved properties;

·

The valuation of unproved acreage and proved oil and gas properties to determine the amount of any impairment of oil and gas properties;

·

Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment; and

·

Estimates regarding abandonment obligations.

Reclassifications

Certain reclassifications have been made to conform the prior period’s financial information to the current period’s presentation.  These reclassifications had no effect on previously reported net loss or accumulated deficit.

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NOTE 2 — GOING CONCERN:

Financial Condition

The Company’s financial statements for the six months ended August 31, 2013 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  The Company has incurred net losses since entering the oil and gas exploration industry and as of August 31, 2013 has an accumulated deficit of $26,992,669 and a working capital deficit of $4,476,230 which raises substantial doubt about the Company’s ability to continue as a going concern.

Management Plans to Continue as a Going Concern

The Company continues to implement plans to enhance Daybreak’s ability to continue as a going concern.  Daybreak currently has a net revenue interest in 18 producing wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”).  The revenue from these wells has created a steady and reliable source of revenue.  The Company’s average working interest in these wells is 36.7% and the average net revenue interest is 28.0% for these same wells.  In late Spring 2013, the Company successfully drilled seven additional development wells at its Sunday, Bear, Black and Ball locations.

The Company anticipates revenues will continue to increase as it participates in the drilling of more wells in California.  Daybreak plans to continue its development drilling program at a rate that is compatible with its cash flow and funding opportunities.

Additionally, the Company has become involved in a shallow oil play in an existing gas field in Lawrence County, Kentucky, through its acquisition of a 25% working interest in approximately 6,100 acres in two large contiguous acreage blocks in the Twin Bottoms Field in Lawrence County, Kentucky (the “Kentucky Acreage”).  The initial drilling plan is for six wells to be drilled and completed before the end of 2013.  The first well was drilled on September 4, 2013 and has been completed.  Production will begin as soon as production facilities are in place.

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company has experienced revenue growth from its oil properties, it has not yet established a positive cash flow on a company-wide basis.  It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future.  However; the Company cannot offer any assurance that the Company will be successful in executing the aforementioned plans to continue as a going concern.

Daybreak’s financial statements as of August 31, 2013 do not include any adjustments that might result from the Company’s inability to implement or execute the plans to improve its ability to continue as a going concern.

NOTE 3 — RECENT ACCOUNTING PRONOUNCEMENTS:

There are no new accounting pronouncements issued or effective that have had, or are expected to have, a material impact on the Company’s financial statements.

NOTE 4 — CONCENTRATION OF CREDIT RISK:

Substantially all of the Company’s trade accounts receivable result from crude oil sales or joint interest billings to its working interest partners.  This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors.  Trade accounts receivable are generally not collateralized.  There were no allowances for doubtful accounts for the Company’s trade accounts receivable at August 31, 2013 and February 28, 2013 as all joint interest owners have a history of paying their obligations in a timely manner.

At the Company’s East Slopes Project, there is only one buyer available for the purchase of oil production.  At August 31, 2013, this one customer represented 100% of crude oil sales receivable.  If this buyer is unable to resell its products or if they lose a significant sales contract; then the Company may incur difficulties in selling its oil and gas production.

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Allowances for doubtful accounts in receivables of loan commitments and other receivables relate to amounts due from third parties that were involved in arranging financing transactions for the Company that have not yet been consummated.  Accounts receivable – Loan commitment refund and other receivables balances at August 31, 2013 and February 28, 2013 are set forth in the table below:

NOTE 5 — PREPAID DRILLING COSTS:

During the six months ended August 31, 2013 the Company was engaged in an eight well drilling program at its East Slopes Project in Kern County, California.  The Company had prepayments to certain of its vendors in the eight well drilling program of $32,813 at August 31, 2013 and $722 at February 28, 2013.

On August 28, 2013, the Company acquired a 25% working interest in a shallow oil play in an existing gas field project in Lawrence County, Kentucky.  At August 31, 2013, the Company had prepayments to the operator of this project of $201,200 for drilling costs.

NOTE 6 — OIL AND GAS PROPERTIES:

Oil and gas property balances at August 31, 2013 and February 28, 2013 are set forth in the table below.

On August 28, 2013, the Company acquired a 25% working interest in a shallow oil play in an existing gas field project in Lawrence County, Kentucky.  As of August 31, 2013, unproved oil and gas properties include the fair value of common shares and warrants issued to Maximilian Investors LLC, a related party, amounting to $1.07 million. Refer to the discussion in Note 12 –Short-Term and Long-Term Borrowings for further information on the issuance of shares and warrants.

NOTE 7 — PRODUCTION REVENUE RECEIVABLE:

Production revenue receivable balance of $350,000 represents amounts due the Company from a portion of the sale price of a 25% working interest in East Slopes Project in Kern County, California that was acquired through the default of certain original working interest partners in the project.  Management believes this receivable is fully collectible and is currently in discussions to establish a specific timeline for payment.

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NOTE 8 — DEFERRED FINANCING COSTS:

Deferred financing costs at August 31, 2013 and February 28, 2013 are set forth in the table below:

Amortization expense of deferred financing costs for the six months ended August 31, 2013 was $48,849.  Deferred financing costs as of August 31, 2013 of $902,900 include the fair value of common shares and warrants issued to Maximilian Investors LLC amounting to $804,816.  Refer to the discussion in Note 12 – Short-Term and Long-Term Borrowings for further information on the deferred financing costs.

NOTE 9 — LONG-TERM NOTE RECEIVABLE:

On August 28, 2013, the Company amended its credit facility with Maximilian Investors LLC as a part of a financing transaction in which the Company extended to App Energy, LLC, a Kentucky limited liability company (“App”) a credit facility for the development of a shallow oil project in an existing gas field in Lawrence County, Kentucky.  (See Note 12 – Short-Term and Long-Term Borrowings).

The Company’s loan agreement with App, dated August 28, 2013, provides for a revolving credit facility of up to $40 million, maturing on August 28, 2017, with a minimum commitment of $2.65 million (the “Initial Advance”).  All funds advanced to App, as borrower, by Daybreak, as lender, are to be borrowed by Daybreak under its amended loan agreement with Maximilian.  The Initial Advance bears interest of 16.8% per annum, and subsequent loans under the loan agreement bear interest at a rate of 12% per annum.  The App loan agreement also provides for a monthly commitment fee of 0.6% on the outstanding principal balance of the loans.  The obligations under the App loan agreement are secured by a perfected first priority security interest in substantially all of the assets of App, including the Company’s leases in Lawrence County, Kentucky, an indemnity provided by App’s manager, John A. Piedmonte, Jr. and a guarantee by certain affiliates of App.

The App loan agreement contains customary covenants for loan of such type, including, among other things, covenants that restrict App’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The App loan agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of App’s obligations under the App loan agreement could be accelerated by the Company, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

The proceeds of the initial borrowing by App of $2.65 million under the App revolving credit facility were primarily used to (a) pay loan fees and closing costs, (b) repay App’s indebtedness and (c) finance the drilling of three wells by App in the Kentucky Acreage.  Future advances under the facility will primarily be used for oil and gas exploration and development activities.

In connection with the App loan agreement, App also granted to the Company a 25% working interest in the Kentucky Acreage, as described above.  The fair value of the 25% working interest was determined to be $1,073,091 and was recorded as unproved oil and gas properties. Refer to Note 12 for further discussion on the related fair value.

At August 31, 2013, the Company had advanced $798,800 to App through its credit facility.  The total amount advanced includes fees paid in connection with the loan amounting to $72,000 and settlement of App’s existing obligation to another lender of $200,386 which were paid directly by Maximilian Investors LLC and $27,616 of interest withheld by Daybreak which is reported as deferred interest in the balance sheets.

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NOTE 10 — ACCOUNTS PAYABLE:

On March 1, 2009, the Company became the operator for its East Slopes Project.  Additionally, the Company, at that time, assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning well program.  The Company subsequently sold the same 25% working interest on June 11, 2009.  Of the $1.5 million default, $268,313 remains unpaid and is included in the August 31, 2013 accounts payable balance.

NOTE 11 — ACCOUNTS PAYABLE- RELATED PARTIES:

The August 31, 2013 and February 28, 2013 accounts payable – related parties balances were comprised primarily of salaries of the Company’s Executive Officers and certain employees; directors’ fees; expense reimbursements; related party consulting fees; and interest to the Company’s President and CEO on the 12% Subordinated Notes further described in Note 12 – Short-Term and Long-Term Borrowings below.  Payment of these deferred items has been delayed until the Company’s cash flow situation improves.

NOTE 12 — SHORT-TERM AND LONG-TERM BORROWINGS:

Line of Credit

During the year ended February 29, 2012, the Company entered into an $890,000 credit line for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer.  At August 31, 2013, the Line of Credit had an outstanding balance of $884,361.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $15,903 for the six months ended August 31, 2013.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

Short-Term Note Payable – Related Party

The balance as of August 31, 2013 of $250,100 represents non-interest bearing notes issued by the Company to its President and Chief Executive Officer.  Repayment of the notes will be made upon a mutually agreeable date in the future.

Long-Term Borrowings

12% Subordinated Notes

On January 13, 2010, the Company commenced a private placement of 12% Subordinated Notes (“Notes”).  On March 16, 2010, the Company closed its private placement of Notes to 13 accredited investors resulting in total gross proceeds of $595,000.  Interest on the Notes accrues at 12% per annum, payable semi-annually.  The note principal is payable in full at the expiration of the term of the Notes, which is January 29, 2015.  Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s Common Stock at a conversion rate equal to 75% of the average closing price of the Company’s Common Stock over the 20 consecutive trading days preceding December 31, 2014.  A $250,000 Note was sold to a related party, the Company’s President and Chief Executive Officer.  The terms and conditions of the related party Note were identical to the terms and conditions of the other participants’ Notes.

In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at the rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.14 and expire on January 29, 2015. The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $116,557 using the following weighted-average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%.  The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method.  Amortization expense for the six months ended August 31, 2013 amounted to $12,813.  Unamortized debt discount amounted to $44,335 as of August 31, 2013.

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Notes Payable balances at August 31, 2013 and February 28, 2013 are set forth in the table below:

Notes Payable – Related Party balances at August 31, 2013 and February 28, 2013 are set forth in the table below:

Maximilian Loan

On October 31, 2012, the Company entered into a loan agreement with Maximilian Investors LLC (“Maximilian”, or “Lender”), a related party, which provided for a revolving credit facility of up to $20 million, maturing on October 31, 2016, with a minimum commitment of $2.5 million.  The loan had annual interest of 18% and a monthly commitment fee of 0.5%.  The Company also granted Maximilian a 10% working interest in its share of the oil and gas leases in Kern County, California.  The relative fair value of this 10% working interest amounting to $515,638 was recognized as a debt discount and is being amortized over the term of the loan. Amortization expense for the six months ended August 31, 2013 amounted to $64,028.  Unamortized debt discount amounted to $410,448 as of August 31, 2013.

The Company also issued in 2012, 2,435,517 warrants to third parties who assisted in the closing of the loan.  The warrants have an exercise price of $0.044; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on October 31, 2017.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $98,084 and included the following assumptions: a risk free interest rate of 0.72%; stock price of $0.04, volatility of 153.44%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the revolving credit facility.

Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App, the Company amended its loan agreement with Maximilian on August 28, 2013. The amended loan agreement provided for an increase in the revolving credit facility from $20 million to $90 million and a reduction in the annual interest rate from 18% to 12%.  The monthly commitment fee of 0.5% per month on the outstanding principal balance remained unchanged.  Advances under the amended loan agreement will mature on August 28, 2017.  The obligations under the amended loan agreement continue to be secured by a perfected first priority security interest in substantially all of the assets of the Company, including the Company’s leases in Kern County, California.  The amended loan agreement, also provided for the revolving credit facility to be divided into two borrowing sublimits.  The first borrowing sublimit is $50 million and is for borrowing by the Company, primarily for its ongoing oil and gas exploration and development activities.  The second borrowing sublimit, of $40 million, is for loans to be extended by the Company, as lender, to App, as borrower pursuant to a Loan and Security Agreement entered into between the Company and App on August 28, 2013 (See Note 9 – Long-term Note Receivable).

The amended loan agreement contains customary covenants for loans of such type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The amended loan agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of the Company’s obligations under the amended loan agreement could be accelerated by the Lender, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

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As consideration for Maximilian facilitating the Company’s transactions with App and entering into the amended loan agreement, the Company (a) issued to Maximilian approximately 6.1 million common shares, representing 9.99% of the Company’s outstanding common stock on a fully-diluted basis at the time of grant, and (b) issued approximately 6.1 million warrants to purchase shares of the Company’s common stock representing the right to purchase up to an additional 9.99% of the Company’s outstanding common stock on a fully-diluted basis, calculated as of the date of grant.  The warrants have an exercise price of $0.10; contain a cash exercise provision and are exercisable for a period of three years expiring on August 28, 2016.  The Company also granted to the Lender a 50% net profits interest, after the Company recovers its investment, in the Company’s 25% working interest in the Kentucky Acreage.

The fair value of the 6.1 million shares was determined to be $979,608 based on the Company’s stock price on the grant date of $0.16.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $898,299 and included the following assumptions: a risk free interest rate of 2.48%; stock price of $0.16, volatility of 184.53%; and a dividend yield of 0.0%.   The Company determined that the common shares and warrants were issued in connection with the increase in the Company’s borrowing limit and App’s $40 million revolving credit facility for which the Company was granted a 25% working interest.  Consequently, the fair value of the common shares and warrants totaling to $1,877,907 was allocated to deferred financing costs ($804,816) and unproved oil and gas properties ($1,073,091) based on the amount of the increase in the revolving credit facility that is attributable to Daybreak and App.

The Company evaluated the amendment of the revolving credit facility under ASC 470-50-40 and determined that the Company’s borrowing capacity under the amended loan agreement exceeded its borrowing capacity under the old loan agreement.  Consequently, the unamortized discount and deferred financing costs as of the date of amendment of approximately $354,164 and the new deferred financing costs, as mentioned above, were amortized over the term of the amended loan agreement.

During the six months ended August 31, 2013 the Company received multiple advances totaling $2,400,000 in aggregate that were used to participate in the Company’s recently completed eight well drilling program at its East Slopes Project in Kern County, California and the drilling at its interest in the Kentucky Acreage and in the extension of the long-term note receivable to App.  The Company has recognized $125,109 in deferred financing costs associated with these advances which are being amortized over the amended term of the revolving credit facility.

Current debt balances at August 31, 2013 and February 28, 2013 are set forth in the table below:

Non-current debt balances at August 31, 2013 and February 28, 2013 are set forth in the table below:

NOTE 13 — STOCKHOLDERS’ DEFICIT:

Series A Convertible Preferred Stock

The Company is authorized to issue up to 10,000,000 shares of $0.001 par value preferred stock.  The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as Series A Convertible Preferred Stock (“Series A Preferred”), with a $0.001 par value.  The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s Common Stock.

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At August 31, 2013, there were 880,565 shares of Series A Preferred issued and outstanding, held by accredited investors that had not been converted into the Company’s Common Stock.  During the six months ended August 31, 2013, there was one shareholder that converted 8,000 Series A Preferred shares to 24,000 shares of Common Stock.  At August 31, 2013, there have been 33 accredited investors who have converted 519,200 Series A Preferred shares into 1,557,600 shares of Daybreak Common Stock.  The conversions of Series A Preferred that have occurred since the Series A Preferred was first issued in July 2006 is set forth in the table below.

Holders of Series A Preferred earn a 6% annual cumulative dividend based on the original purchase price of the shares.  Accumulated dividends do not bear interest and as of August 31, 2013, the accumulated and unpaid dividends amounted to $1,386,942.  Dividends may be paid in cash or Common Stock at the discretion of the Company and are payable upon declaration by the Board of Directors.  Dividends are earned until the Series A Preferred is converted to Common Stock.  No payment of dividends has been declared as of August 31, 2013.

Dividends earned since issuance of the Series A Preferred for each fiscal year and the six months ended August 31, 2013 are set forth in the table below:

Common Stock

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock of which 54,980,411 shares were issued and outstanding as of August 31, 2013.  For the six months ended August 31, 2013 there were 6,146,552 shares issued, of which 24,000 were through conversion of Series A Preferred stock and 6,122,552 were issued in connection with the Maximilian loan as described in Note 12 – Short-Term and Long-Term Borrowings.

NOTE 14 — WARRANTS:

Warrants outstanding and exercisable as of August 31, 2013 are set forth in the table below:

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There were no warrants exercised during the six months ended August 31, 2013.  During the six months ended August 31, 2013, there were 1,624,012 warrants that expired.  These warrants had been issued to placement agents in conjunction with the Spring 2006 and July 2006 placements of the Company’s Common Stock.  There were 6,122,552 warrants issued during the six months ended August 31, 2013 in connection with the Maximilian loan as described in Note 12 — Short-Term and Long Term Borrowings.  The remaining outstanding warrants as of August 31, 2013, have a weighted average exercise price of $0.09, a weighted average remaining life of 3.01 years, and an intrinsic value of $983,357.

NOTE 15 — RESTRICTED STOCK AND RESTRICTED STOCK UNIT PLAN:

On April 6, 2009, the Board of Directors (the “Board”) of the Company approved the 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of the Company and its affiliates to be eligible to receive restricted stock and restricted stock unit awards (“Awards”).  Subject to adjustment, the total number of shares of the Company’s Common Stock that will be available for the grant of Awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an Award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.

At August 31, 2013, a total of 2,882,010 shares of restricted stock had been awarded and remained outstanding under the 2009 Plan, and 2,893,750 of the shares had fully vested.  A total of 1,011,740 Common Stock shares remained available at August 31, 2013 for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan issuances is set forth in the table below:

⁽¹⁾

Does not include shares that were withheld to satisfy such tax liability upon vesting of a restricted award by a Plan Participant, and subsequently returned to the 2009 Plan.

⁽²⁾

Reflects the number of common shares that were withheld pursuant to the settlement of the number of shares with a fair market value equal to such tax withholding liability, to satisfy such tax liability upon vesting of a restricted award by a Plan Participant.

For the six months ended August 31, 2013, the Company recognized compensation expense related to the above restricted stock grants in the amount of $8,659.  Unamortized compensation expense amounted to $6,282 as of August 31, 2013.  For the six months ended August 31, 2013, there were 4,080 shares of the Company’s Common Stock relating to the 2009 Plan returned to the 2009 Plan to satisfy an employee’s payroll tax liability upon the vesting of shares.

NOTE 16 — INCOME TAXES:

Reconciliation between actual tax expense (benefit) and income taxes computed by applying the U.S. federal income tax rate and state income tax rates to income from continuing operations before income taxes is set forth in the table below:

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Tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred liabilities are set forth in the table below:

At August 31, 2013, Daybreak had estimated net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $19,644,145 which will begin to expire, if unused, beginning in 2024.  The valuation allowance increased $360,068 for the six months ended August 31, 2013 and increased by $879,259 for the year ended February 28, 2013. Section 382 of the Internal Revenue Code places annual limitations on the Company’s NOL carryforward.

The above estimates are based on management’s decisions concerning elections which could change the relationship between net income and taxable income.  Management decisions are made annually and could cause estimates to vary significantly.

NOTE 17 — COMMITMENTS AND CONTINGENCIES:

Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities.  While the ultimate outcome of any future contingency is not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment.  These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages.  In some instances, the Company may be directed to suspend or cease operations in the affected area.  The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of August 31, 2013.  There can be no assurance, however, that current regulatory requirements will not change or that past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

As of October 11, 2013, the Company had received additional advances from its revolving credit facility with Maximilian of $2,784,200 in aggregate, of which $1,845,200 was in turn advanced to App.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Statement Regarding Forward-Looking Statements

All statements other than statements of historical fact contained in this MD&A report are inherently uncertain and are forward-looking statements.  Statements that relate to results or developments that we anticipate will or may occur in the future are not statements of historical fact.  Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will” and similar expressions identify forward-looking statements.  Examples of forward-looking statements include, without limitation, statements about the following:

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Our future operating results;

·

Our future capital expenditures;

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Our future financing;

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Our expansion and growth of operations; and

·

Our future investments in and acquisitions of oil and natural gas properties.

We have based these forward-looking statements on assumptions and analyses made in light of our experience and our perception of historical trends, current conditions, and expected future developments.  However, you should be aware that these forward-looking statements are only our predictions and we cannot guarantee any such outcomes.  Future events and actual results may differ materially from the results set forth in or implied in the forward-looking statements.  Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

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General economic and business conditions;

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Exposure to market risks in our financial instruments;

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Fluctuations in worldwide prices and demand for oil and natural gas;

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Our ability to find, acquire and develop oil and gas properties;

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Fluctuations in the levels of our oil and natural gas exploration and development activities;

·

Risks associated with oil and natural gas exploration and development activities;

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Competition for raw materials and customers in the oil and natural gas industry;

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Technological changes and developments in the oil and natural gas industry;

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Legislative and regulatory uncertainties, including proposed changes to federal tax law and climate change legislation, and potential environmental liabilities;

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Our ability to continue as a going concern;

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Our ability to secure financing under any commitments as well as additional capital to fund operations; and

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Other factors discussed elsewhere in this Form 10-Q and in our other public filings, press releases, and discussions with Company management.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  We specifically undertake no obligation to publicly update or revise any information contained in any forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except as required by law.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Introduction and Overview

The following MD&A is management’s assessment of the historical financial and operating results of the Company for the three and six month periods ended August 31, 2013 and August 31, 2012 and of our financial condition at August 31, 2013, and is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes included elsewhere in this Form 10-Q and in our audited financial statements and notes included in our Annual Report on Form 10-K for the year ended February 28, 2013.

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We are an independent oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities, and selling the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment. A secondary means of generating returns can include the sale of either producing or non-producing lease properties.

Our longer-term success depends on, among many other factors, the acquisition and drilling of commercial grade oil and gas properties and on the prevailing sales prices for oil and natural gas along with associated operating expenses. The volatile nature of the energy markets makes it difficult to estimate future prices of oil and natural gas; however, any prolonged period of depressed prices would have a material adverse effect on our results of operations and financial condition.

Our operations are focused on identifying and evaluating prospective oil and gas properties and funding projects that we believe have the potential to produce oil or gas in commercial quantities. We are currently in the process of developing a multi-well oilfield project in Kern County, California and a shallow oil project in an existing gas field in Lawrence County, Kentucky.

Kern County, California (East Slopes Project)

The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California.  Since January 2009, we have participated in the drilling of 22 wells in this project.  During the six months ended August 31, 2013 we had production from 18 wells including production from seven wells that were drilled and put on production in late May and early June 2013.  Drilling targets are porous and permeable sandstone reservoirs which exist at depths of 1,200 feet to 4,500 feet.

We currently have production from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations.  The Sunday property has six producing wells, while the Bear property has seven producing wells.  The Black property is the smallest of all currently producing reservoirs, and currently has two producing wells at this property.  The Ball property also has two producing wells while the Dyer Creek property has one producing well.  There are several other similar prospects on trend with the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic characteristics.  Some of these prospects, if successful, would utilize the Company’s existing production facilities.  In addition to the current field development, there are several other exploratory prospects that have been identified from the seismic data, which we plan to drill in the future.  We plan to spend approximately $700,000 in new capital investments within the East Slopes Project area during the remainder of the current fiscal year.

Producing Properties

Sunday Property

In November 2008, we made our initial oil discovery drilling the Sunday #1 well.  The well was put on production in January 2009.  Production is from the Vedder sand at approximately 2,000 feet.  During 2009, we drilled three development wells including one horizontal well.  The Sunday reservoir is estimated to be approximately 35 acres in size with the potential for at least one more development well to be drilled in the future.  We have a 37.5% working interest with a 26.1% net revenue interest (“NRI”) in the Sunday #1 well.  For both the Sunday #2 and Sunday #3 wells, we have a 33.8% working interest with a 24.3% NRI.  We also have a 33.8% working interest with a 27.1% NRI in the Sunday #4H well.  During May and June 2013, we drilled two additional development wells; the Sunday #5 and Sunday #6 on this property.  We have a 37.5% working interest and a NRI of 30.1% in both of these newly producing wells.

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Bear Property

In February 2009, we made our second oil discovery drilling the Bear #1 well, which is approximately one mile northwest of our Sunday discovery.  The well was put on production in May 2009.  Production is from the Vedder sand at approximately 2,200 feet.  In December 2009, we began a development program by drilling and completing the Bear #2 well.  In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells.  The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least three more development wells to be drilled in the future.  We have a 37.5% working interest with a 26.1% NRI in the Bear #1, Bear #2, Bear #3 and Bear #4 wells on this property.  In May and June 2013, we drilled three additional development wells; the Bear #5, Bear #6 and Bear #7 on this property.  We have a 37.5% working interest and a NRI of 30.1% in these three newly producing wells.  We expect to drill at least three more development wells on this property during the 2013 calendar year.

Black Property

The Black property was acquired through a farm-in arrangement with a local operator.  The Black property is just south of the Bear property on the same fault system.  The Black #1 well was completed and put on production in January 2010.  Production is from the Vedder sand at 2,150 feet.  The Black reservoir is estimated to be approximately 13 acres in size.  In May 2013, we drilled a development well, the Black #2, on this property.  We have a 37.5% working interest with a 29.8% NRI in all wells on this property.

Sunday Central Processing and Storage Facility

The oil produced from our acreage is considered heavy oil.  The oil ranges from 14° to 16° API gravity.  All of the oil from the Sunday, Bear and Black properties is processed, stored and sold from the Sunday Central Processing and Storage Facility.  The oil must be heated to separate and remove water to prepare it to be sold.  We constructed these facilities during the summer and fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines.  We have started an upgrade program to this facility to handle the additional oil production from the new wells completed in May and June 2013, as well as for the future wells to be drilled during the Fall of 2013 and calendar year 2014.

Ball Property

The Ball #1-11 well was put on production in late October 2010.  Our 3-D seismic data indicates a reservoir approximately 38 acres in size with the potential for at least two development wells to be drilled in the future.  Production from the Ball #1-11 well is being processed at the Dyer Creek production facility.  In June 2013, we drilled a development well; the Ball 2-11 on this property.  We have a 37.5% working interest in both the Ball #1-11 and Ball #2-11 wells.  Our NRI in both wells is 31.2%.  We anticipate drilling at least one more development well on this property during calendar year 2013.

Dyer Creek Property

The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010.  This well is producing from the Vedder sand and is located to the north of the Bear property on the same trapping fault.  The Dyer Creek property has the potential for at least one development well in the future.  Production from the DC67X well is also being processed at the Dyer Creek production facility.  We have a 37.5% working interest with a 31.2% NRI in the DC67X well.

Dyer Creek Processing and Storage Facility

The Dyer Creek Processing and Storage Facility serves the Ball and Dyer Creek properties and includes previously abandoned infrastructure that we have refurbished.  The oil produced into this facility has a similar API gravity to the oil at the Sunday production facility and the oil must also be heated to separate and remove water in preparation for sale.

Centralized Oil Processing and Storage Facilities

By utilizing the Sunday and Dyer Creek centralized production facilities our average operating costs have been reduced from over $40 per barrel in 2009 to a monthly average of approximately $16 per barrel of oil for the six months ended August 31, 2013.  With these centralized facilities and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

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Eight Well Drilling Program - Spring 2013

In May and June 2013, we participated in the drilling of seven development wells and one exploratory well in the East Slopes Project in Kern County, California.  We successfully drilled and have completed seven development wells on the Sunday, Bear, Black and Ball locations.  An exploratory well at the Breckenridge/Chimney location was not successful.

We are currently planning a Fall 2013 drilling program to include at least four more development wells at the Bear and Ball locations.

Exploration Properties

Bull Run Prospect

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Etchegoin and Santa Margarita sands located between 800 and 1,200 feet deep.  We drilled an exploratory well on this prospect in December 2011 that was determined to be not viable for commercial production and the well was plugged and abandoned.  Utilizing the data received from this well, we expect to drill another exploratory well on this prospect during 2014.  The Bull Run wells will require a pilot steam flood and additional production facilities.  We estimate that the Bull Run prospect is 70 acres in size with a gross recoverable reserve potential of 873,000 barrels of oil.  We have a 37.5% working interest in this prospect.

Glide-Kendall Prospect

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Olcese and Eocene sands between 1,000 and 2,000 feet deep.  We plan to drill an exploratory well during 2014.  We estimate that the Glide Kendall prospect is 200 acres in size with a gross recoverable reserve potential of 1.8 million barrels of oil.  We have a 37.5% working interest in this prospect.

Sherman Prospect

This prospect is also located in the southern portion of our acreage position.  The drilling targets are the Olcese and Etchegoin sands between 1,000 and 2,000 feet deep.  We plan to drill an exploratory well in the fall of 2014.  We estimate that the Sherman Prospect is 100 acres in size with a gross recoverable reserve potential of 300,000 barrels of oil.  We have a 37.5% working interest in this prospect.

Tobias Prospect

Breckenridge-Chimney Prospect

This prospect is located in the central portion of our acreage position.  The drilling targets are the Vedder and Eocene sands between 2,500 and 4,000 feet deep.  In June 2013, we drilled an exploratory well at this prospect that was not successful.  As a result, we do not currently plan to drill any more wells at this location.

Lawrence County, Kentucky (Twin Bottoms Project)

Effective August 28, 2013, we acquired a 25% working interest in approximately 6,100 acres in two large contiguous acreage blocks in the Twin Bottoms Field in Lawrence County, Kentucky from App Energy, LLC, a Kentucky limited liability company.  The initial drilling program will be six horizontal wells drilled to a vertical depth of approximately 2,000’ with horizontal legs between 2,500’ and 3,500’.  We have a NRI of 21.9% in all wells in this project.

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The first well in the drilling program was spud on September 4, 2013 and hydraulic fracturing operations were completed on September 26, 2013.  Production will begin once production facilities are in place.  The vertical top hole of the second well was spud on October 3, 2013.  Horizontal drilling commenced October 8, 2013, and the well reached total depth on October 10, 2013.  The well was successful and will be completed in the near future.  The drilling rig will be moved to a third well and will commence drilling the horizontal leg the week of October 14, 2013.  Current plans call to drill and complete the initial six wells of the drilling program before the end of calendar year 2013.

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement entered into by and among Maximilian Investors LLC, a Delaware limited liability company, as lender, and the Company are secured by a perfected first priority security interest in substantially all of the assets of the Company, including our leases in Kern County, California and Lawrence County, Kentucky.  This includes mortgages on the Sunday, Bear, Black, Ball and Dyer Creek Properties in California.  For further information on the loan agreement refer to the discussion under the caption “Long-Term Borrowings” in this MD&A.

Results of Operations – Three Months Ended August 31, 2013 compared to the Three Months Ended August 31, 2012

Revenues.  Monthly revenues are derived entirely from the sale of our share of oil production.  We realized the first revenue from producing wells in our East Slopes Project during February 2009.  The price we receive for oil sales is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma contracts, less deductions that vary by grade of crude oil sold.

Historically, the sale price we receive for California heavy oil has been less than the quoted WTI price.  However, from March of 2011 through May 31, 2013 we received a premium for our California oil in comparison to the WTI price.  For the three months ended August 31, 2013, the average monthly WTI price was $102.34 and the average monthly sale price we received was $98.66, resulting in a discount of $3.68 per barrel or 3.6% lower than the average monthly WTI price.  This compares to the three months ended August 31, 2012 when the average monthly WTI price was $88.11 and the average monthly sale price was $93.10, resulting in a premium that was $4.99 per barrel or 5.7% higher than the average monthly WTI pricing.  We are unable to forecast if we will again receive a premium for our oil in comparison to the WTI price as there are many factors beyond our control that dictate the price we receive for our oil.

The East Slopes Project represented 100% of total revenue for the three months ended August 31, 2013 and August 31, 2012, as set forth in the table below:

Revenues for the three months ended August 31, 2013 increased $229,059 or 91.9% to $478,208 in comparison to revenue of $249,149 for the three months ended August 31, 2012.  The average monthly sale price of a barrel of oil for the three months ended August 31, 2013 was $98.61 in comparison to $93.10 for the three months ended August 31, 2012.  The increase of $5.51 or 5.9% in the average monthly sale price of a barrel of oil accounted for $14,567 or 6.4% of the revenue increase for the three months ended August 31, 2013.

Production for the three months ended August 31, 2013 was from 18 wells resulting in 1,594 well days of production in comparison to 906 well days for the three months ended August 31, 2012.  We had 582 well days of production from the seven new development wells that were drilled in late May and early June 2013.  Our net sales volume for the three months ended August 31, 2013 was 4,841 barrels of oil in comparison to 2,669 barrels for the three months ended August 31, 2012.  This increase in oil sales of 2,171 barrels or 81.3% was due to the seven new development wells.  Sales volume from the 11 wells that were producing in the comparative period was 2,440 barrels a decrease of 230 barrels from the three months ended August 31, 2013.  The decrease was due to the natural production decline in our oil wells.  The increase in sales volume in aggregate accounted for $214,492 or 93.6% of the revenue increase for the three months ended August 31, 2013.

Operating Expenses.  Total operating expenses for the three months ended August 31, 2013 increased by $124,435 or 34.1% to $489,132, compared to $364,697 for the three months ended August 31, 2012.

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Operating expenses for the three months ended August 31, 2013 and August 31, 2012 are set forth in the table below:

Production expenses include expenses associated with the generation of oil and gas revenues, road maintenance, control of well insurance, property taxes and well workover costs.  These expenses generally relate directly to the number of wells that are in production.  For the three months ended August 31, 2013, these expenses increased by $84,217 in comparison to the three months ended August 31, 2012.  This increase in production expenses is primarily due to the addition of seven new development wells and the replacement of a downhole pump in one of our existing wells. Additionally, in the comparative period we received certain production credits of $38,537 that were reflected in lower overall production expenses during the comparative period.  Production expenses represented 17.6% of total operating expenses.

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses increased $32,930 for the three months ended August 31, 2013 in comparison to the three months ended August 31, 2012.  Drilling expenses increased $42,172 due to dry hole expense from the Chimney #1-1 well in June 2013.  Exploration and drilling expenses represented 11.0% of total operating expenses.

DD&A expenses relate to equipment, proven reserves and property costs, along with impairment, and is another component of operating expenses.  For the three months ended August 31, 2013, DD&A expenses decreased $3,305 or 5.5% in comparison to the three months ended August 31, 2012.  DD&A expenses represented 11.6% of total operating expenses.

G&A expenses include the salaries of six employees, including management.  Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as for running a public company.  For the three months ended August 31, 2013, these expenses increased $10,593 or 3.8% to $292,390 in comparison to $281,797 for the three months ended August 31, 2012.  Accounting and legal expenses decreased $6,589 in aggregate for the three months ended August 31, 2012. Management and employee salaries, director fees and stock compensation were relatively unchanged for the three months ended August 31, 2013 in comparison to the three months ended August 31, 2012.  Advertising, marketing and press release expense increased by $16,164 for the three months ended August 31, 2013, primarily due to public announcements relating to the seven new development wells being brought into production.  For the three months ended August 31, 2013, we received, as Operator, administrative overhead reimbursement of $21,376 for the East Slopes Project which was used to directly offset certain employee salaries.  We are continuing a program of reducing all of our G&A costs wherever possible.  G&A expenses represented 59.8% of total operating expenses for the three months ended August 31, 2013.

Interest income for the three months ended August 31, 2013 decreased $61 or 51.3% in comparison to the three months ended August 31, 2012 due to lower average cash balances.

Interest expense for the three months ended August 31, 2013 increased $119,919 in comparison to the three months ended August 31, 2012.  The increase in interest expense was primarily due to higher balances on our credit facility due to advances made to fund the eight well drilling program in May and June 2013.  This financing transaction is further discussed in the MD&A section of this 10-Q report under the caption “Long-Term Borrowings – Maximilian Loan.”

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Results of Operations – Six Months Ended August 31, 2013 compared to the Six Months Ended August 31, 2012

Revenues.  For the six months ended August 31, 2013, the average monthly WTI price was $97.75 and the average monthly sale price we received was $97.79, or approximately the same as the average monthly WTI price.  This compares to the six months ended August 31, 2012 when the average monthly WTI price was $94.75 and the average monthly sale price we received was $100.44, resulting in a premium of $5.69 per barrel or 6.0% higher than the average monthly WTI pricing.  We are unable to forecast if we will again receive a premium for our oil in comparison to the WTI price as there are many factors beyond our control that dictate the price we receive for our oil.

The East Slopes Project represented 100% of total revenue for the six months ended August 31, 2013 and August 31, 2012, as set forth in the table below:

Revenues for the six months ended August 31, 2013 increased $194,690 or 38.0% to $706,812 in comparison to revenue of $512,122 for the six months ended August 31, 2012.  The average monthly sale price of a barrel of oil for the six months ended August 31, 2013 was $97.79 in comparison to $100.44 for the six months ended August 31, 2012.  The decrease of $2.65 per barrel or 2.6% in the average monthly sale price of a barrel of oil was offset by the increase in oil sales volume.

Production for the six months ended August 31, 2013 was from 18 wells resulting in 2,626 well days of production in comparison to 1,907 well days for the six months ended August 31, 2012.  We had 612 well days of production from the seven new development wells that were drilled in late May and early June 2013.  Our net sales volume for the six months ended August 31, 2013 was 7,200 barrels of oil in comparison to 5,107 barrels for the six months ended August 31, 2012.  This increase in oil sales of 2,093 barrels or 41.0% was due to the seven new development wells.  Sales volume from the 11 wells that were producing in the comparative period was 4,725 barrels a decrease of 381 barrels from the six months ended August 31, 2013.  The decrease was due to the natural production decline in our oil wells. The increase sales volume in aggregate accounted for 1006% of the revenue increase for the six months ended August 31, 2013.

Operating Expenses.  Total operating expenses for the six months ended August 31, 2013 increased by $317,947 or 38.2% to $1,151,240, compared to $833,293 for the six months ended August 31, 2012.

Operating expenses for the six months ended August 31, 2013 and August 31, 2012 are set forth in the table below:

Production expenses include expenses associated with the generation of oil and gas revenues, road maintenance, control of well insurance, property taxes and well workover costs.  These expenses generally relate directly to the number of wells that are in production.  For the six months ended August 31, 2013, these expenses increased by $72,323 in comparison to the six months ended August 31, 2012.  This increase in production expenses is primarily due to the addition of seven new development wells and the replacement of a downhole pump in one of our existing wells. Additionally, in the comparative period we received certain production credits of $38,537 that were reflected in lower overall production expenses during the comparative period.  Production expenses represented 10.1% of total operating expenses.

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Exploration and drilling expenses include G&G expenses as well as leasehold maintenance and dry hole expenses.  These expenses increased $198,144 for the six months ended August 31, 2013 in comparison to the six months ended August 31, 2012.  Drilling expenses increased to $211,762 due to dry hole expense from the Chimney #1-1 well in June 2013.  Exploration and drilling expenses represented 20.4% of total operating expenses.

DD&A expenses relate to equipment, proven reserves and property costs, along with impairment, and is another component of operating expenses.  For the six months ended August 31, 2013, DD&A expenses increased $85,599 in comparison to the six months ended August 31, 2012 due to the $84,929 impairment of the Chimney leasehold.  DD&A expenses represented 17.8% of total operating expenses.

G&A expenses include the salaries of six employees, including management.  Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as for running a public company.  For the six months ended August 31, 2013, these expenses decreased $38,119 or 6.0% to $595,872 in comparison to $633,991 for the six months ended August 31, 2012.  Accounting and legal expenses decreased $53,671 in aggregate for the six months ended August 31, 2012 due to timing differences for the six months ended August 31, 2012.  Management and employee salaries, director fees and stock compensation were relatively unchanged for the six months ended August 31, 2013 in comparison to the six months ended August 31, 2012.  Advertising, marketing and press release expense increased by $24,448 for the six months ended August 31, 2013, primarily due to the seven new development wells being brought into production.  For the six months ended August 31, 2013, we received, as Operator, administrative overhead reimbursement of $53,157 for the East Slopes Project which was used to directly offset certain employee salaries.  We are continuing a program of reducing all of our G&A costs wherever possible.  G&A expenses represented 51.8% of total operating expenses for the six months ended August 31, 2013.

Interest income for the six months ended August 31, 2013 decreased $113 or 50.7% in comparison to the six months ended August 31, 2012 due to lower average cash balances.

Interest expense for the six months ended August 31, 2013 increased $242,946 in comparison to the six months ended August 31, 2012.  The increase in interest expense was primarily due to advances made through our existing credit facility to fund the eight well drilling program in May and June 2013.  This financing transaction is further discussed in the MD&A section of this 10-Q report under the caption Long-Term Borrowings – Maximilian Loan.

Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially on a quarter-to-quarter and year-to-year basis.  Production expenses and revenues will fluctuate according to the number and percentage ownership of producing wells as well as the amount of revenues we receive based on the price of oil.  Exploration and drilling expenses will be dependent upon the amount of capital that we have to invest in future development projects, as well as the success or failure of such projects.  Likewise, the amount of DD&A expense will depend upon the factors cited above including the size of our proven reserves base and the market price of energy products.  G&A expenses will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.  An ongoing goal of the Company is to improve cash flow to cover the current level of G&A expenses and to fund our development drilling programs in California and Kentucky.

Capital Resources and Liquidity

Our primary financial resource is our proven oil reserves base.  Our ability to fund any future capital expenditure programs is dependent upon the prices we receive from oil sales, the success of our exploration and development program in Kern County, California and Lawrence County, Kentucky and the availability of capital resource financing.  We plan to spend approximately $700,000 in the current fiscal year in new capital investments; however our actual expenditures may vary significantly from this estimate if our plans for exploration and development activities change during the year.  Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.

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Changes in our capital resources at August 31, 2013 in comparison with February 28, 2013 are set forth in the table below:

Our working capital deficit increased $699,848 or 18.5% to $4,476,230 at August 31, 2013 in comparison to $3,776,382 at February 28, 2013.  This increase in the working capital deficit was primarily due to expenses incurred during May and June 2013 in our recently completed eight well drilling program.  While we have ongoing positive cash flow from our operations in California we have not yet been able to generate sufficient cash flow to cover all of our G&A and interest expense requirements.  We anticipate an increase in our cash flow from our operations in Kern County, California and Lawrence County, Kentucky during the current fiscal year.

Our business is capital intensive.  Our ability to grow is dependent upon favorably obtaining outside capital and generating cash flows from operating activities necessary to fund our investment activities.  There is no assurance that we will be able to achieve profitability.  Since our future operations will continue to be dependent on successful exploration and development activities and our ability to seek and secure capital from external sources, should we be unable to achieve sustainable profitability this could cause any equity investment in the Company to become worthless.

Major sources of funds in the past for us have included the debt or equity markets.  While we have achieved positive cash flow from operations in Kern County, California, we will have to rely on these capital markets to fund future operations and growth.  Our business model is focused on acquiring exploration or development properties as well as existing production.  Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of oil and gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources.

Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company.  The current uncertainty in the credit and capital markets, and the economic downturn, may restrict our ability to obtain needed capital.

The Company’s financial statements for the six months ended August 31, 2013 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  We have incurred net losses since entering the oil and gas exploration industry and as of six months ended August 31, 2013 have an accumulated deficit of $26,992,669 and a working capital deficit of $4,476,230 which raises substantial doubt about our ability to continue as a going concern.

In the current fiscal year, we continue to seek additional financing for our planned exploration and development activities in both California and Kentucky.  We plan to obtain financing through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these instruments which could result in dilution to existing security holders and increased debt and leverage.  No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all.  Sales of interests in our assets may be another source of cash flow.

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Cash Flows

Changes in the net funds provided by and (used in) our operating, investing and financing activities are set forth in the table below:

Cash Flow (Used In) Provided by Operating Activities

Cash flow from operating activities is derived from the production of our oil and gas reserves and changes in the balances of receivables, payables or other non-energy property asset account balances.  For the six months ended August 31, 2013, we had a cash flow deficit from operating activities of $657,574 in comparison to a positive cash flow of $62,529 for the six months ended August 31, 2012.  This decrease of $720,103, was due to changes in our receivables and payables balances related to our drilling activities in Kern County, California for the six months ended August 31, 2013 in comparison to the six months ended August 31, 2012.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash Flow (Used in) Investing Activities

Cash flow from investing activities is derived from changes in oil and gas property balances and our lending activities associated with the App Energy loan.  Cash used in investing activities for the six months ended August 31, 2013 was $1,283,276, an increase of $1,152,142 from the $131,134 used in investing activities for the six months ended August 31, 2012.  This increase was due to eight well drilling program that was undertaken during May and June 2013 and advances made for drilling in Kentucky on a shallow oil project as well as $498,798 in advances to App Energy.  Refer to Note 9 – Long-Term Note Receivable for further discussion of the App Energy loan.

Cash Flow Provided by Financing Activities

Cash flow from financing activities is derived from changes in long-term liability account balances or in equity account balances, excluding retained earnings.  For the six months ended August 31, 2013 we received advances on our loan commitment for drilling activities in California and Kentucky of approximately $2.1 million in aggregate offset by payments on our credit line, note payable and deferred financing fees.  For the six months ended August 31, 2012, we had no net financing activities.  The following is a summary of cash flows provided by, and used in, the Company’s financing activities during the six months ended August 31, 2013.

Short-Term Borrowings

Related Party

During the years ended February 29, 2012 and February 28, 2013, the Company’s President and Chief Executive Officer has loaned the Company $250,100 in aggregate that has been used for a variety of corporate purposes including an escrow requirement on a loan commitment; extension fees on third party loans; and, a reduction of principal on the Company’s credit line with UBS Bank.  These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.

Line of Credit

During the year ended February 29, 2012, the Company entered into an $890,000 credit line for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer.  At August 31, 2013, the Line of Credit had an outstanding balance of $884,361.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $15,903 for the six months ended August 31, 2013.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

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Long-Term Borrowings

12% Subordinated Notes

The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a March 2010 private placement, resulted in $595,000 in gross proceeds to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th.  The note principal is payable in full at the expiration of the term of the Notes, which is January 29, 2015.  In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.14 and expire on January 29, 2015.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $116,557 using the following weighted average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%.  The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method.  Amortization expense for the six months ended August 31, 2013 amounted to $12,813.  Unamortized debt discount amounted to $44,335 as of August 31, 2013.

Maximilian Loan

On October 31, 2012, the Company entered into a loan agreement with Maximilian Investors LLC (“Maximilian”, or “Lender”) which provided for a revolving credit facility of up to $20 million, maturing on October 31, 2016, with a minimum commitment of $2.5 million.  The loan had annual interest of 18% and a monthly commitment fee of 0.5%.  The Company also granted Maximilian a 10% working interest in its share of the oil and gas leases in Kern County, California. The relative fair value of this 10% working interest amounting to $515,638 was recognized as a debt discount and is being amortized over the term of the loan. Amortization expense for the six months ended August 31, 2013 amounted to $64,568.  Unamortized debt discount amounted to $410,448 as of August 31, 2013.

The Company also issued in 2012, 2,435,517 warrants to third parties who assisted in the closing of the loan.  The warrants have an exercise price of $0.044; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on October 31, 2017.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $98,084 and included the following assumptions: a risk free interest rate of 0.72%; stock price of $0.04, volatility of 153.44%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the loan.

During the six months ended August 31, 2013 the Company received multiple advances totaling $2,400,000 in aggregate that were used to participate in the Company’s recently completed eight well drilling program at its East Slopes Project in Kern County, California and the drilling at its interest in the Kentucky Acreage and in the extension of the long-term note receivable to App.  The Company has recognized $125,109 in deferred financing costs associated with these advances which are being amortized over the term of the revolving credit facility.

Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App, the Company amended its loan agreement with Maximilian on August 28, 2013. The amended loan agreement provided for an increase in the revolving credit facility from $20 million to $90 million and a reduction in the annual interest rate from 18% to 12%.   The monthly commitment fee of 0.5% per month on the outstanding principal balance remained unchanged.  Advances under the amended loan agreement will mature on August 28, 2017.  The obligations under the amended loan agreement continue to be secured by a perfected first priority security interest in substantially all of the assets of the Company, including the Company’s leases in Kern County, California.  The amended loan agreement also provided for the revolving credit facility to be divided into two borrowing sublimits.  The first borrowing sublimit is $50 million and is for borrowing by the Company, primarily for its ongoing oil and gas exploration and development activities.  The second borrowing sublimit, of $40 million, is for loans to be extended by the Company, as lender, to App, as borrower pursuant to a Loan and Security Agreement entered into between the Company and App on August 28, 2013 (See Note 9 – Long-term Note Receivable).

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The amended loan agreement contains customary covenants for loan of such type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The amended loan agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of the Company’s obligations under the amended loan agreement could be accelerated by the Lender, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

As consideration for Maximilian facilitating the Company’s transactions with App and entering into the amended loan agreement, the Company (a) issued to Maximilian approximately 6.1 million common shares, representing 9.99% of the Company’s outstanding common stock on a fully-diluted basis at the time of grant, and (b) issued approximately 6.1 million warrants to purchase shares of the Company’s common stock representing the right to purchase up to an additional 9.99% of the Company’s outstanding common stock on a fully-diluted basis, calculated as of the date of grant.  The warrants have an exercise price of $0.10; contain a cash exercise provision and are exercisable for a period of three years expiring on August 28, 2016.  The Company also granted to the Lender a 50% net profits interest in the Company’s 25% working interest, after the Company recovers its investment, in the Company’s working interest in the Kentucky Acreage, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.

The fair value of the 6.1 million shares was determined to be $979,608 based on the Company’s stock price on the grant date of $0.16.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $898,299 and included the following assumptions: a risk free interest rate of 2.48%; stock price of $0.16, volatility of 184.53%; and a dividend yield of 0.0%.   The Company determined that the common shares and warrants were issued in connection with the increase in Company’s borrowing limit and App’s $40 million revolving credit facility for which the Company was granted a 25% working interest.  Consequently, the fair value of the common shares and warrants totaling to $1,877,907 was allocated to deferred financing costs ($804,816) and unproved oil and gas properties ($1,073,091) based on the amount of the increase in the revolving credit facility that is attributable to Daybreak and App.

The Company evaluated the amendment of the revolving credit facility under ASC 470-50-40 and determined that the Company’s borrowing capacity under the amended loan agreement exceeded its borrowing capacity under the old loan agreement.  Consequently, the unamortized discount and deferred financing costs as of the date of amendment of approximately $400,349 and the new deferred financing costs, as mentioned above, were amortized over the term of the amended loan agreement.

App Loan Agreement

The App Loan Agreement provides for a revolving credit facility of up to $40 million, maturing on August 28, 2017, with a minimum commitment of $2.65 million (the “Initial Advance”).  All funds advanced to App, as borrower, by Daybreak, as lender, are to be borrowed by Daybreak under its Amended Loan Agreement with the Lender.  The Initial Advance bears interest at a rate per annum equal to 16.8%, and subsequent loans under the Loan Agreement bear interest at a rate per annum equal to 12%.  The App Loan Agreement also provides for a monthly commitment fee of 0.6% per month of the outstanding principal balance of the loans.  The obligations under the App Loan Agreement are secured by a perfected first priority security interest in substantially all of the assets of App, including the Company’s leases in Lawrence County, Kentucky.

The proceeds of the initial borrowing by App of $2.65 million under the App facility were primarily used to (a) pay loan fees and closing costs, (b) repay indebtedness and (c) finance the drilling of three wells by App in the Kentucky Acreage in which the Company has a 25% working interest.  Future advances under the facility will primarily be used for oil and gas exploration and development activities.

The App Loan Agreement contains customary covenants for loan of such type, including, among other things, covenants that restrict App’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The App Loan Agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of App’s obligations under the App Loan Agreement could be accelerated by the Company, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

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In connection with the App Loan Agreement, App also granted to the Company the 25% working interest approximately 6,100 acres in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky (the “Kentucky Acreage”), and entered into a corresponding promissory note and a Mortgage, Leasehold Mortgage, Assignment of Production, Security Agreement and Financing Statement, both dated as of August 28, 2013.  App’s manager, John A. Piedmonte, Jr., also entered into a limited Indemnity Agreement in connection with the loan.  The loans under the App Loan Agreement are also guaranteed by certain of App’s affiliates.

Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company.  The current uncertainty in the credit and capital markets, and the economic downturn, may restrict our ability to obtain needed capital.

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement entered into by and among Maximilian Investors LLC, a Delaware limited liability company, as lender, and the Company are secured by a perfected first priority security interest in substantially all of the assets of the Company, including our leases in Kern County, California and Lawrence County, Kentucky.  This includes mortgages on the Sunday, Bear, Black, Ball and Dyer Creek Properties in California.  For further information on the loan agreement refer to the discussion under the caption “Long-Term Borrowings” in this MD&A.

Restricted Stock and Restricted Stock Unit Plan

On April 6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted Common Stock and restricted Common Stock unit awards.  Subject to adjustment, the total number of shares of Daybreak Common Stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.

At August 31, 2013, a total of 2,882,010 shares of restricted stock had been awarded and remained outstanding under the 2009 Plan, and 2,893,750 of the shares had fully vested.  A total of 1,011,740 Common Stock shares remained available at August 31, 2013 for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan issuances is set forth in the table below:

⁽¹⁾

Does not include shares that were withheld to satisfy such tax liability upon vesting of a restricted award by a Plan Participant, and subsequently returned to the 2009 Plan.

⁽²⁾

Reflects the number of common shares that were withheld pursuant to the settlement of the number of shares with a fair market value equal to such tax withholding liability, to satisfy such tax liability upon vesting of a restricted award by a Plan Participant.

For the six months ended August 31, 2013, the Company recognized compensation expense related to the above restricted stock grants in the amount of $8,659.  Unamortized compensation expense amounted to $6,282 as of August 31, 2013.  For the six months ended August 31, 2013, there were 4,080 shares of the Company’s Common Stock relating to the 2009 Plan returned to the 2009 Plan to satisfy an employee’s payroll tax liability upon the vesting of shares.

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Management Plans to Continue as a Going Concern

The Company continues to implement plans to enhance Daybreak’s ability to continue as a going concern.  Daybreak currently has a net revenue interest in 18 producing wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”).  The revenue from these wells has created a steady and reliable source of revenue.  The Company’s average working interest in these wells is 36.7% and the average net revenue interest is 28.0% for these same wells.  In late Spring 2013, the Company has successfully drilled seven additional development wells at its Sunday, Bear, Black and Ball locations.

The Company anticipates revenues will continue to increase as it participates in the drilling of more wells in California.  Daybreak plans to continue its development drilling program at a rate that is compatible with its cash flow and funding opportunities.

Additionally, the Company has become involved in a shallow oil play in an existing gas field in Lawrence County, Kentucky, through its acquisition of a 25% working interest in approximately 6,100 acres in two large contiguous acreage blocks in the Twin Bottoms Field in Lawrence County, Kentucky (the “Kentucky Acreage”).  The initial drilling plan is for six wells to be drilled and completed before the end of 2013.  The first well was drilled on September 4, 2013 and has been completed.  Production will begin as soon as production facilities are in place.

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company has experienced revenue growth from its oil properties, it has not yet established a positive cash flow on a company-wide basis.  It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future.  However the Company cannot offer any assurance that the Company will be successful in executing the aforementioned plans to continue as a going concern.

Critical Accounting Policies

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2013.

Off-Balance Sheet Arrangements

As of August 31, 2013, we did not have any off-balance sheet arrangements or relationships with unconsolidated entities or financial partners that have been, or are reasonably likely to have, a material effect on our financial position or results of operations.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As a smaller reporting company, we are not required to provide the information otherwise required by this Item.

ITEM 4.  CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the six months ended August 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Limitations

Our management does not expect that our disclosure controls or internal controls over financial reporting will prevent all errors or all instances of fraud.  A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met.  Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.

Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected.  These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.  Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls.  The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and any design may not succeed in achieving its stated goals under all potential future conditions.

Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.  Because of the inherent limitation of a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

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PART II

OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

None

ITEM 1A.  RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the period ended February 28, 2013, which could materially affect our business, financial condition or future results. The risks described in this report are not the only risks we face.   Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial could have a material adverse effect on our business, financial condition and results of operations.

Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays.

Our Kentucky drilling operations currently use the process of hydraulic fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. For example, the Environmental Protection Agency (“EPA”) has asserted federal regulatory authority over hydraulic fracturing involving fluids that contain diesel fuel under the Safe Drinking Water Act’s Underground Injection Control Program and has released draft permitting guidance for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states where the EPA is the permitting authority, including Kentucky. Such efforts could have an adverse effect on our oil and natural gas production activities.

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ITEM 6.  EXHIBITS

The following Exhibits are filed as part of the report:

Exhibit

Number

Description

10.1⁽¹⁾

Amended and Restated Loan and Security Agreement dated as of August 28, 2013, by and between Daybreak Oil and Gas, Inc., as borrower, and Maximilian Investors LLC, as lender.

10.2⁽¹⁾

Loan and Security Agreement dated as of August 28, 2013, by and between App Energy, LLC, as borrower, and Daybreak Oil and Gas, Inc., as lender.

10.3⁽¹⁾

Partial Assignment of Interest in Oil and Gas Leases dated as of August 28, 2013, made by App Energy, LLC to Daybreak Oil and Gas, Inc.

10.4⁽¹⁾

Assignment of Net Profits Interest dated as of August 28, 2013, made by Daybreak Oil and Gas, Inc. to Maximilian Investors LLC.

10.5⁽¹⁾

Warrant Agreement dated as of August 28, 2013, by and between Daybreak Oil and Gas, Inc. and Maximilian Investors LLC.

31.1⁽²⁾

Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1⁽²⁾

Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS⁽³⁾

XBRL Instance Document

101.SCH⁽³⁾

XBRL Taxonomy Schema

101.CAL⁽³⁾

XBRL Taxonomy Calculation Linkbase

101.DEF⁽³⁾

XBRL Taxonomy Definition Linkbase

101.LAB⁽³⁾

XBRL Taxonomy Label Linkbase

101.PRE⁽³⁾

XBRL Taxonomy Presentation Linkbase

⁽¹⁾

Previously filed as exhibit to Form 8-K on September 3, 2013, and incorporated by reference herein.

⁽²⁾

Filed herewith.

⁽³⁾

Furnished herewith

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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.

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