DAYBREAK OIL & GAS, INC. - Quarter Report: 2014 August (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x          QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended August 31, 2014

OR

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

For the transition period from   ______________   to   _______________

Commission File Number: 000-50107

DAYBREAK OIL AND GAS, INC.

(Exact name of registrant as specified in its charter)

(509) 232-7674

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   ¨ Yes   þ No

At October 10, 2014 the registrant had 51,448,373 outstanding shares of $0.001 par value common stock.

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, 2014 are not necessarily indicative of the results that may be expected for the fiscal year ending February 28, 2015.

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, 2014.

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, 2014 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, 2014 has an accumulated deficit of $27,615,718 and a working capital deficit of $3,240,056 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 its ability to continue as a going concern.  Daybreak currently has an average 36.8% working interest and 28.4% net revenue interest in 20 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.

Additionally, the Company has become involved in a shallow oil play in an existing gas field in Lawrence County, Kentucky, through its acquisition of an average 25% working interest in approximately 7,300 acres in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky.  The Company has nine horizontal oil wells on production in Kentucky and is in the process of completing and bringing onto production an additional four horizontal oil wells also in Kentucky.  Daybreak’s average working interest in these thirteen oil wells is 22.5% and the average net revenue interest is 19.7% in these same wells.

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

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company has experienced revenue growth, which has resulted in positive cash flow from its oil and gas properties, it has not yet established a consistent 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 it will be successful in executing the aforementioned plans to continue as a going concern.

Daybreak’s financial statements as of August 31, 2014 do not include any adjustments that might result from the inability to implement or execute Daybreak’s plans to improve our 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, 2014 and February 28, 2014, as all joint interest owners have a history of paying their obligations.

At the Company’s East Slopes project in California, there is only one buyer available for the purchase of all oil production.  At the Company’s Twin Bottoms Field project located in Lawrence County, Kentucky, there is only one buyer available for the purchase of its oil production and only one buyer available for the purchase of its natural gas production.  At August 31, 2014 and February 28, 2014 these three individual customers represented 100.0% of crude oil and natural gas revenues accounts receivable.  If these buyers are unable to resell their 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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The Company’s oil and natural gas revenues accounts receivable from California and Kentucky operations at August 31, 2014 and February 28, 2014 are set forth in the table below.

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, 2014 and February 28, 2014 are set forth in the table below:

NOTE 5 — PREPAID DRILLING COSTS:

During the six months ended August 31, 2014 the Company was engaged in a multi-well drilling program at the Twin Bottoms Field in Lawrence County, Kentucky.  The Company had made prepayments for drilling costs at August 31, 2014 and February 28, 2014 as set forth in the table below.

NOTE 6 — OIL AND GAS PROPERTIES:

Oil and gas property balances at August 31, 2014 and February 28, 2014 are set forth in the table below.

NOTE 7 — PRODUCTION REVENUE RECEIVABLE:

Production revenue receivable balances of $215,000 in aggregate represent 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.  Production revenue receivable balances at August 31, 2014 and February 28, 2014 are set forth in the table below:

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NOTE 8 — DEFERRED FINANCING COSTS:

Deferred financing costs at August 31, 2014 and February 28, 2014 relate to the original and the amended credit facility with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in these notes to the financial statements as “Maximilian”), are set forth in the table below:

Deferred financing costs of loan commissions increased $154,559 for the six months ended August 31, 2014. The Company recognized amortization expense of $209,844 for the six months ended August 31, 2014.

NOTE 9 — NOTE RECEIVABLE:

At August 31, 2014, the Company had advanced $7,750,000 to App Energy, LLC, a Kentucky limited liability company (“App”) through its credit facility.  Note receivable balances at August 31, 2014 and February 28, 2014 are set forth in the table below:

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 partners’ default liability of approximately $1.5 million 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, $258,349 remains unpaid and is included in the August 31, 2014 accounts payable balance.

NOTE 11 — ACCOUNTS PAYABLE- RELATED PARTIES:

The August 31, 2014 and February 28, 2014 accounts payable – related parties balances were comprised primarily of salaries of the Company’s Executive Officers and certain employees; directors’ fees; expense reimbursements; and interest to the Company’s President and Chief Executive Officer on the 12% Subordinated Notes further described in Note 12 – Current and Non-Current Borrowings below.  Payment of these items has been deferred until the Company’s cash flow situation improves.

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

Current Debt

Note Payable – Related Party

As of August 31, 2014 and February 28, 2014, the Company’s President and Chief Executive Officer had 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.

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Line of Credit

The Company has an existing $890,000 line of credit 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, 2014, the Line of Credit had an outstanding balance of $880,010.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $15,641 for the six months ended August 31, 2014.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

12% Subordinated Notes

The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a March 2010 private placement (of which $250,000 was from a related party) 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.  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.

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 was $15,372 for the six months ended August 31, 2014.

For the six months ended August 31, 2014, there was one 12% Subordinated noteholder who exercised the warrants associated with the 12% Note.  A total of 50,000 warrants were exercised and resulted in 50,000 shares of Common Stock being issued to the noteholder.

Current Notes balances at August 31, 2014 and February 28, 2014 are set forth in the table below:

Current Notes, related party balances at August 31, 2014 and February 28, 2014 are set forth in the table below:

Non-current Debt

Maximilian Loan

On October 31, 2012, the Company entered into a loan agreement with Maximilian, 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 original term of the loan.  Amortization expense was $69,263 for the six months ended August 31, 2014.

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The Company also issued 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.  On March 10, 2014, one of the third parties exercised 2,118,900 warrants resulting in the issuance of 1,873,554 shares of the Company’s common stock.

Maximilian Loan - Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App in the Twin Bottoms Field in Lawrence County, Kentucky, 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 personal property of the Company, and a mortgage on 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 – 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 Maximilian, 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; and contain an exercise blocker provision that prevents any exercise of the warrants if such exercise and related issuance of common stock would increase the Maximilian holdings of the Company’s common stock to more than 9.99% of the Company’s currently issued and outstanding shares at the time of the exercise.  The Company also granted to Maximilian 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 its Kentucky acreage, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.

On May 28, 2014 at Maximilian’s request, the Company finalized a share-for-warrant exchange agreement in which Maximilian returned to the Company 427,729 common shares and was in turn issued the same number of warrants containing the same provisions as the originally issued warrants.  This share-for-warrant exchange occurred so that Maximilian would hold no more than 9.99% of the Company’s common shares, issued and outstanding.  The Company determined that the share-for-warrant exchange did not result in any incremental fair value.

On August 21, 2014, the Company entered into a First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement (the “Amendment”) with Maximilian under its Amended and Restated Loan and Security Agreement dated as of August 28, 2013.  The Amendment secured for the Company an additional advance of $2,200,000 under its credit facility with Maximilian since the advances made by Maximilian had already exceeded its minimum funding commitment.  Additionally, Maximilian agreed to temporarily reduce the required monthly payment made by the Company until it has paid $1,000,000 less than payments required by the previous agreement.  Furthermore, Maximilian agreed to reduce the regular interest rate applicable to the loan from 12% per annum to 9% per annum and the default interest rate by 3%.

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The additional advance, the reduction in the required monthly payment and the reduction in the interest rate were facilitated through the Company’s acquisition of 5,694,823 shares of its common stock held by Maximilian.  The repurchased shares were cancelled and restored to the status of authorized, but unissued stock.  The Company paid for the share repurchase transaction through an advance of $1,708,447 under the existing loan agreement with Maximilian.

During the six months ended August 31, 2014, the Company received multiple advances from Maximilian of approximately $5.7 million in aggregate that were used to participate in the multi-well drilling program at the Twin Bottoms Field in Kentucky and to advance funds to App through a long-term note receivable.  The Company made principal payments of approximately $1.7 million to Maximilian during the six months ended August 31, 2014.  The Company has recognized $154,559 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, 2014 and February 28, 2014 are set forth in the table below:

Non-current debt balances at August 31, 2014 and February 28, 2014 are set forth in the table below:

NOTE 13 — STOCKHOLDERS’ DEFICIT:

Series A Convertible 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.  At August 31, 2014, there were 737,565 shares issued and outstanding, that had not been converted into our common stock.  As of August 31, 2014, there are 41 accredited investors who have converted 662,200 Series A Preferred shares into 1,986,600 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.

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Holders of Series A Preferred shall be paid dividends, in the amount of 6% of the original purchase price per annum. Dividends are cumulative from the date of the final closing of the private placement, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.  Dividends earned since issuance for each fiscal year and the six months ended August 31, 2014 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 51,448,373 shares were issued and outstanding as of August 31, 2014.  In comparison, at February 28, 2014, a total of 55,509,411 shares were issued and outstanding.  The decrease of 4,061,038 shares was attributable as shown below:

NOTE 14 — WARRANTS:

Warrants outstanding and exercisable as of August 31, 2014 are set forth in the table below:

There were no warrants that expired during the six months ended August 31, 2014.  During the six months ended August 31, 2014, there were 50,000 warrants exercised for a total of $7,000 that had been issued in conjunction with the 12% subordinated Notes and 2,118,900 warrants exercised that were issued in conjunction with financing the Company received in 2012 for a total of 2,168,900 warrants that were exercised in aggregate.  There were 427,729 warrants issued during the six months ended August 31, 2014 in connection with the Maximilian share-for-warrants exchange.  The remaining outstanding warrants as of August 31, 2014, have a weighted average exercise price of $0.11, a weighted average remaining life of 1.88 years, and an intrinsic value of $711,365.

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NOTE 15 — RESTRICTED STOCK AND RESTRICTED STOCK UNIT PLAN:

At August 31, 2014, a total of 2,986,220 shares of restricted stock had been awarded and remained outstanding under the 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”).  There were 3,000,000 shares that were fully vested under the 2009 Plan.  A total of 1,013,780 common stock shares remained available at August 31, 2014 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, 2014, the Company recognized compensation expense related to the above restricted stock grants in the amount of $2,515.  For the six months ended August 31, 2014, there were 2,040 shares of the Company’s common stock relating to the 2009 Plan that were returned to the 2009 Plan to satisfy an employee’s payroll tax liability upon the vesting of the 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:

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, 2014, Daybreak had estimated net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $21,353,215 which will begin to expire, if unused, beginning in 2024.  The valuation allowance decreased approximately $3,071 for the six months ended August 31, 2014 and increased by $464,360 for the year ended February 28, 2014. 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.

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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, 2014.  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.

NOTE 18 — SUBSEQUENT EVENTS:

As of October 10, 2014, the Company had advanced an additional $300,000 to App Energy, LLC through its credit facility with the Company.

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

The following discussion is management’s assessment of the current and historical financial and operating results of the Company and of our financial condition.  It is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q for the six months ended August 31, 2014 and in our Annual Report on Form 10-K for the year ended February 28, 2014.  References to “Daybreak”, the “Company”, “we”, “us” or “our” mean Daybreak Oil and Gas, Inc.

Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) are intended to be covered by the safe harbor provided for under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.

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:

·

Our future operating results;

·

Our future capital expenditures;

·

Our future financing;

·

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:

·

General economic and business conditions;

·

Exposure to market risks in our financial instruments;

·

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

·

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

·

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;

·

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

·

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

·

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

·

Our ability to continue as a going concern;

·

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

·

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.

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Introduction and Overview

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 natural 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 natural 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 natural 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 natural gas properties and funding projects that we believe have the potential to produce oil or natural gas in commercial quantities.  We conduct all of our drilling, exploration and production activities in the United States, and all of our revenues are derived from sales to customers within the United States.  Currently, we are in the process of developing two multi-well oilfield projects; one in Kern County, California and the other in Lawrence County, Kentucky.

Our management cannot provide any assurances that Daybreak will continue to sustain profitability.  As a small company, we are more susceptible to the numerous business, investment and industry risks that have been described in Item 1A. Risk Factors of our Annual Report on Form 10-K for the fiscal year ended February 28, 2014 and in Part III, Item 1A. Risk Factors of this 10-Q Report.  Throughout this Quarterly Report on Form 10-Q, oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).

Year-to-Date Results

For the six months ended August 31, 2014, we have been successful in accomplishing the following objectives:

·

Continuing our drilling program in Kentucky – We have brought four additional horizontal oil wells onto production. Additionally, we have successfully drilled another four additional horizontal oil wells that should be brought on production in October 2014.

·

Improving cash flow – Our oil and natural gas revenue has grown by 162% in comparison to the six months ended August 31, 2013, while the average realized hydrocarbon price has declined.

·

Reducing net loss – We achieved a net profit for the most recently completed quarter and have reduced our net loss for the year to less than $145,000 in comparison to a net loss of over $900,000 for the six months ended August 31, 2013.

Below is summary of our oil and natural gas projects in California and 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.  Drilling targets are porous and permeable sandstone reservoirs which exist at depths of 1,200 feet to 4,500 feet.  Since January 2009, we have participated in the drilling of 25 wells in this project.  During the six months ended August 31, 2014, we had production from 20 wells.  We have been the Operator at the East Slopes Project since March 2009.

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 nine 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 investment within the East Slopes Project area during the remainder of the current fiscal year.

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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.  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 new wells.  Our average working interest and NRI for the Sunday property in aggregate is 35.6% and 27.0%, respectively.  The Sunday reservoir is estimated to be approximately 35 acres in size with the potential for at least five more development wells to be drilled in the future.

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 on this property by drilling and completing the Bear #2 well.  In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells.  In May and June 2013, we drilled three additional development wells; the Bear #5, Bear #6 and Bear #7 on this property.  In November 2013, we drilled and put on production two additional development wells; the Bear #8 and Bear #9.  We have a 37.5% working interest in all wells at the Bear Property.  Our NRI in the Bear #1, Bear #2, Bear #3 and Bear #4 wells is 26.1%.  For the Bear #5, Bear #6 and Bear #7 wells our NRI is 30.1%.  Our NRI in the Bear #8 and Bear #9 wells is 31.7%.  The average working interest and NRI for the Bear property in aggregate is 37.5% and 28.7%, respectively.  The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least ten more development wells to be drilled in the future.

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 and is on the same fault system.  The Black #1 well was completed and put on production in January 2010.  In May 2013, we drilled a development well, the Black #2 on this property.  Production for both of these wells is from the Vedder sand at approximately 2,200 feet.  We have a 37.5% working interest with a 29.8% NRI in all wells on this property.  The Black reservoir is estimated to be approximately 13 acres in size with the potential for at least three more development wells to be drilled in the future.

Ball Property

The Ball #1-11 well was drilled and put on production in late October 2010.  In June 2013, we drilled a development well the Ball #2-11, on this property.  Production on this property is from the Vedder sand at approximately 2,500 feet.  We have a 37.5% working interest with a 31.2% NRI in all wells on this property.  Our 3-D seismic data indicates a reservoir approximately 38 acres in size with the potential for at least three more development wells to be drilled in the future.

Dyer Creek Property

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

Sunday Central Processing and Storage Facility

The oil produced from our acreage in California is considered heavy oil.  The oil ranges from 14° to 16° API (American Petroleum Institute) gravity.  All of the oil from our five producing 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 completed an upgrade program to this facility including the addition of a second oil storage tank to handle the additional oil production from the wells drilled in 2013.

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By utilizing the Sunday centralized production facility our average operating costs have been reduced from over $40 per barrel in 2009 to a monthly average of approximately $11 per barrel of oil for the six months ended August 31, 2014.  With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

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.  Utilizing the data received from a previously drilled well that was not commercially successful, we expect to drill another exploratory well on this prospect during 2015.  Future 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.  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 estimate that the Glide Kendall prospect is 200 acres in size.  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 estimate that the Sherman Prospect is 100 acres in size.  We have a 37.5% working interest in this prospect.

Tobias Prospect

This prospect is also located in the central portion of our acreage position.  The drilling targets are the Vedder and Eocene sands between 2,000 and 4,500 feet deep.  We estimate that the Tobias prospect is 60 acres in size.  We have a 37.5% working interest in this prospect.

California Drilling Plans

We currently expect to drill as many as six additional wells in California in the fall of 2014 and the spring of 2015.  These planned wells represent a combination of both exploratory drilling and development well drilling.  Planned drilling activity will be undertaken as soon as possible after all applicable regulatory permits are received and financing is in place.

Lawrence County, Kentucky (Twin Bottoms Field)

The Twin Bottoms Field, comprising approximately 7,300 acres in two large contiguous blocks, is located in the Appalachian Basin of eastern Kentucky.  Log data from existing vertical gas wells in the field indicate the existence of proved oil reserves in the Berea Oil Sand, located at approximately 2,000 feet.  The lateral leg of each well will be between 2,000 feet and 4,500 feet in length.  We have an average 25% working interest and an average NRI of 21.9% in all horizontal wells in this project.  The oil produced from our acreage in Kentucky is light crude oil measuring between 42° and 44° API gravity.  We are not the Operator of the Twin Bottoms Field project, but we rely on the experience of the current Operator and their knowledge of this Field.  We plan to spend approximately $1.5 million in new capital investments within the Twin Bottoms Field during the remainder of the 2014-2015 fiscal year.

Gerald Grove Property

As of August 31, 2014, we had eight producing horizontal oil wells on this property.  Our first well, the Gerald Grove H-1 was put on production in mid-October 2013.  Our second well, the Gerald Grove H-3 was put on production in December 2013.  The Gerald Grove H-4 and Grove H-5, our third and fourth wells, were put on production in February of this year.  The next four horizontal oil wells on this property, the Gerald Grove H-7, Gerald Grove H-8, Gerald Grove H-9 and Gerald Grove H-10 were put on production in June and July of this year.

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Dwight Dillon Property

Our first horizontal oil well on this property, the Dwight Dillon H-6 well was put on production in March of this year.

Kentucky Drilling Plans

In August and September of 2014, we continued our development well drilling program in Kentucky by drilling four additional horizontal oil wells.  Two of these new wells, the Lyons H-23 and Lyons H-24 have undergone hydraulic fracturing and joint production facilities are under construction.  The third and fourth wells, the Jackson H-20 and Dillon H-22, are scheduled to be hydraulically fractured in early October.  We expect to have all four of these wells on production by the end of October 2014.  If the fall and winter weather cooperates and local conditions permit and financing is in place, we plan on continuing our drilling activity through the end of our fiscal year.

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement entered into by and between Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in this MD&A as “Maximilian”), as lender, and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and a mortgage on our leases in Kern County, California encompassing the Sunday, Bear, Black, Ball and Dyer Creek properties.  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, 2014 compared to the Three Months Ended August 31, 2013

Revenues.  Our revenues are derived entirely from the sale of our share of oil and natural gas production.  The price we receive for oil sales in both California and Kentucky is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs.  The price we receive for natural gas sales in Kentucky per Mcf is based on the Columbia Gas Transmission Corp. Appalachia Index (“TCO Appalachia”) whereby we will receive 76% of the TCO Appalachia price per dekatherm (DTH) less $0.25 compression cost for each Mcf of gas delivered.  We do not have any natural gas production in California.

California Oil Sales

For the three months ended August 31, 2014, the average monthly WTI price was $101.97 and our average realized monthly sale price was $94.45, representing a discount of $7.52 per barrel or 7.4% lower than the average monthly WTI price.  In comparison, for the three months ended August 31, 2013, the average monthly WTI prices was $102.34 and our average realized monthly sale price was $98.79 representing a discount of $3.55 per barrel or 3.5% lower than the average monthly WTI price.  Historically, the sale price we receive for California heavy oil has been less than the quoted WTI price because of the lower API gravity of our California oil in comparison to WTI oil API gravity.

Kentucky Oil Sales

Our first oil sales in Kentucky occurred in October 2013.  For the three months ended August 31, 2014, our average realized monthly sale price was $99.86 in comparison to the average WTI price of $101.97 representing a discount of $2.11 per barrel or 2.1% from the average monthly WTI price.  The average monthly WTI price for the three months ended August 31, 2013 was $102.34 per barrel.  While we receive a premium to WTI price for our Kentucky oil, our transportation and handling costs result in a realized sales price that is generally lower than the quoted WTI price.

Kentucky Natural Gas sales

Our first natural gas sales in Kentucky also occurred in October 2013.  For the three months ended August 31, 2014, we received an average price of $2.80 per Mcf in comparison to the average Henry Hub price of $4.15 per Mcf representing a $1.35 or 32.5% discount from the average Henry Hub price.  The average Henry Hub price for the three months ended August 31, 2013 was $3.63 per Mcf.

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Our oil and natural gas revenues for the three months ended August 31, 2014 and 2013 are set forth in the table below:

Revenues for the three months ended August 31, 2014 increased $566,088 or 118.4% to $1,044,296 in comparison to revenue of $478,208 for the three months ended August 31, 2013.  In California, oil revenues decreased $94,160 due to both a decrease in the average realized sales price and the production volume.  The decline in the realized sales price was responsible for approximately $21,022 of the decline while the lower production volume was responsible for the remaining $73,138 of the decline.  The lower production volume in California was due to natural reservoir pressure decline.  There are no comparative numbers in oil or natural gas sales in Kentucky for the three months ended August 31, 2013, since there was no production during that time period.  The average realized sales price of all hydrocarbon sales in California and Kentucky on a BOE basis for the three months ended August 31, 2014 was $93.32 in comparison to $98.79 for California oil sales for the three months ended August 31, 2013.  This decrease of $5.47 or 5.5% in the average monthly realized sale price of BOE was offset by the oil and natural gas production from nine new wells in Kentucky.

Production for the three months ended August 31, 2014 was from 29 wells, 20 wells in California and nine wells in Kentucky, resulting in 2,434 well days of production in comparison to 1,594 well days from 18 wells in California and no wells in Kentucky for the three months ended August 31, 2013.  In California, our net production volume for the three months ended August 31, 2014 was 4,066 barrels of oil in comparison to 4,841 barrels for the three months ended August 31, 2013.  This decrease of 775 barrels or 16.0% was due to the natural decline in reservoir pressure for the three months ended August 31, 2014.  In Kentucky, production for the three months ended August 31, 2014 was 7,202 BOE from nine wells.

Operating Expenses.  Total operating expenses for the three months ended August 31, 2014 increased by $33,471 or 6.8% to $522,603, compared to $489,132 for the three months ended August 31, 2013.

Operating expenses for the three months ended August 31, 2014 and August 31, 2013 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 expenses; and, relate directly to the number of wells that are in production.  For the three months ended August 31, 2014, these expenses decreased by $6,201 or 7.2% in comparison to the three months ended August 31, 2013.  For the three months ended August 31, 2014 we had 20 wells on production in California and nine in Kentucky in comparison to 18 wells in California and none in Kentucky for the three months ended August 31, 2013.  On a BOE basis production expenses in California were $8.86 per barrel for the three months ended August 31, 2014 in comparison to $17.80 per barrel for the three months ended August 31, 2013.  In Kentucky, on a BOE basis, production expenses were $6.12 per barrel for the three months ended August 31, 2014.  Combined LOE for both California and Kentucky on a BOE basis was $7.11 per barrel.  Production expenses represented 15.2% of total operating expenses.

Production expenses in California and Kentucky for the three months ended August 31, 2014 and 2013 are set forth in the table below:

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Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses decreased $47,710 or 88.8% to $6,027 for the three months ended August 31, 2014 in comparison to $53,737 the three months ended August 31, 2013.  The primary reason for the decrease in exploration and drilling expenses was due to recognition of dry hole expenses in California for the three months ended August 31, 2013.  Exploration and drilling expenses represented 1.1% 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, 2014, DD&A expenses increased $114,667 to $171,516 in comparison to $56,849 for the three months ended August 31, 2013.  The increase in DD&A is directly related to our involvement in the Twin Bottoms Field oil well project in Kentucky and the depletion of those associated reserves.  We were not involved with the Kentucky project during the three months ended August 31, 2013.  DD&A expenses represented 32.8% of total operating expenses.

G&A expenses include the salaries of six full-time and two part-time 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, 2014, these expenses decreased $27,285 or 9.3% to $265,105 in comparison to $292,390 for the three months ended August 31, 2013.  Management and employee salaries and director fees were reduced by $17,308 or 10.2% for the three months ended August 31, 2014 largely due to reduced stock compensation expense from stock awards being fully amortized in comparison to the three months ended August 31, 2013.  Travel expenses decreased $8,450 or 75.3% because of the amount of drilling activity during the three months ended August 31, 2014 in comparison to the three months ended August 31, 2013.  For the three months ended August 31, 2014, we received, as Operator, administrative overhead reimbursement of $16,176 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 50.7% of total operating expenses for the three months ended August 31, 2014.

Interest income for the three months ended August 31, 2014 increased $289,950 in comparison to the three months ended August 31, 2013 primarily due to interest income earned on the Note receivable from App Energy. For further discussion on this Note refer to the App Loan Agreement under Long-term Financing section in this MD&A.

Interest expense for the three months ended August 31, 2014 increased $435,275 in comparison to the three months ended August 31, 2013.  The increase in interest expense was primarily from higher loan balances on our credit facility due to drilling program and lending activities in Kentucky, and the acquisition of our common stock shares from Maximilian.  The credit facility activity is discussed further in the MD&A section of this 10-Q report under the caption “Long-Term Borrowings – Maximilian Loan.”

Results of Operations – Six Months Ended August 31, 2014 compared to the Six Months Ended August 31, 2013

California Oil Sales

For the six months ended August 31, 2014, the average monthly WTI price was $101.83 and our average realized monthly sale price was $95.46 representing a discount of $6.37 per barrel or 6.3% lower than the average monthly WTI price.  In comparison, for the six months ended August 31, 2013, the average monthly WTI prices was $97.75 and our average realized monthly sale price was $98.17, representing a premium of $0.42 per barrel or 0.4% higher than the average monthly WTI pricing.  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 of 2013, we did receive a premium for our California oil in comparison to the WTI price.  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.

Kentucky Oil Sales

For the six months ended August 31, 2014, our average realized monthly sale price was $99.90 in comparison to the average WTI price of $101.83 representing a discount of $1.93 per barrel or 1.9% from the average monthly WTI price.  The average monthly WTI price for the six months ended August 31, 2013 was $97.75 per barrel.  Since our first sales of oil in Kentucky occurred in October 2013, we have no comparative sales numbers for the six months ended August 31, 2013.

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Kentucky Natural Gas Sales

For the six months ended August 31, 2014, we received an average price of $2.87 per Mcf in comparison to the average Henry Hub price of $4.42 per Mcf representing a $1.55 per Mcf or 35.1% discount from the average Henry Hub price.  The average Henry Hub price for the six months ended August 31, 2013 was $3.82 per Mcf.

Our oil and natural gas revenues for the six months ended August 31, 2014 and 2013 are set forth in the table below:

Revenues for the six months ended August 31, 2014 increased $1,147,913 or 162.4% to $1,854,725 in comparison to revenue of $706,812 for the six months ended August 31, 2013.  In California, oil revenues increased $107,360 due to an increase in production volume offset by a decrease in the average realized sales price.  The increase in production resulted in an increase of $126,889 in revenue offset by $19,529 due to the lower realized sales price.  There are no comparative numbers in oil or natural gas sales in Kentucky for the six months ended August 31, 2013, since there was no production during that time period.  The average realized sales price of all hydrocarbon sales in California and Kentucky on a BOE basis for the six months ended August 31, 2014 was $91.71 in comparison to $98.17 for California oil sales for the six months ended August 31, 2013.  This decrease of $6.46 or 6.6% in the average monthly realized sale price of BOE was offset by the oil and natural gas production from nine new wells in Kentucky.

Production for the six months ended August 31, 2014 was from 20 wells in California and nine wells in Kentucky resulting in 4,599 well days of production in comparison to 2,626 well days from 18 wells in California for the six months ended August 31, 2013.  In California, our net production volume for the six months ended August 31, 2014 was 8,529 barrels of oil in comparison to 7,200 barrels for the six months ended August 31, 2013.  This increase of 1,329 barrels or 18.5% was primary due to an additional two wells that went on production in November 2013.  In Kentucky there was no production for the six months ended August 31, 2014.

Operating Expenses.  Total operating expenses for the six months ended August 31, 2014 decreased by $61,528 or 5.3% to $1,089,712 in comparison to $1,151,240 for the six months ended August 31, 2013.

Operating expenses for the six months ended August 31, 2014 and 2013 are set forth in the table below:

For the six months ended August 31, 2014, production expenses increased by $49,530 or 42.7% in comparison to $115,955 for the six months ended August 31, 2013.  This increase in production expenses is primary due to the addition of nine new development wells in Kentucky.  For the six months ended August 31, 2014 we had 20 wells on production in California and nine in Kentucky in comparison to 18 wells in California and none in Kentucky for the six months ended August 31, 2013.  On a BOE basis production expenses in California were $10.77 per barrel for the six months ended August 31, 2014 in comparison to $16.10 per barrel for the six months ended August 31, 2013.  In Kentucky, on a BOE basis, production expenses were $6.49 per barrel for the six months ended August 31, 2014.  Combined LOE for both California and Kentucky on a BOE basis was $8.32 per barrel.  Production expenses represented 15.2% of total operating expenses.

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Production expenses for California and Kentucky for the six months ended August 31, 2014 and 2014 are set forth in the table below:

For the six months ended August 31, 2014 exploration and drilling expenses decreased $221,884 or 94.5% in comparison to $234,694 for the six months ended August 31, 2013.  The primary reason for the decrease in exploration and drilling expenses was due to recognition of dry hole expenses in California for the six months ended August 31, 2013.  There was no dry hole expense for the six months ended August 31, 2014.  Exploration and drilling expenses represented 1.2% of total operating expenses.

For the six months ended August 31, 2014, DD&A expenses increased $86,774 or 42.4% to $291,493 in comparison to $204,719 for the six months ended August 31, 2013.  The increase in DD&A is directly related to our involvement in the Twin Bottoms Field oil well project in Kentucky and the depletion of those associated reserves.  We were not involved with the Kentucky project during the six months ended August 31, 2013.  DD&A expenses represented 26.7% of total operating expenses.

For the six months ended August 31, 2014 G&A expenses increased $24,052 or 4.0% to $619,924 in comparison to $595,872 for the six months ended August 31, 2013.  Management and employee salaries and director fees were reduced by $27,517 or 8.1% for the six months ended August 31, 2014 largely due to reduced stock compensation expense from stock awards being fully amortized in comparison to the six months ended August 31, 2013.  Press release expense was reduced by $9,820 or 69.2% for the six months ended August 31, 2014 in comparison to the six months ended August 31, 2013.  This savings was realized by changing vendors for the press release services.  This trend of reduced expenses were offset by increases in legal, accounting and reserve report expense of $61,808 or 116.3% primarily due to additional expenses associated with responding to an SEC comment letter on our Form 10-K filing for the year ended February 28, 2013.  Additionally, travel expenses increased $2,182 or 15.4% due to the timing of our drilling activity during the six months ended August 31, 2014 in comparison to the six months ended August 31, 2013.  For the six months ended August 31, 2014, we received, as Operator, administrative overhead reimbursement of $32,997 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 56.8% of total operating expenses for the six months ended August 31, 2014.

Interest income for the six months ended August 31, 2014 increased $454,736 to $454,846 in comparison to $110 for the six months ended August 31, 2013 primarily due to interest income earned on the Note receivable from App Energy.  For further discussion on this Note refer to the App Loan Agreement under Long-term Financing section in this MD&A.

Interest expense for the six months ended August 31, 2014 increased $888,874 to $1,363,004 in comparison to $474,130 for the six months ended August 31, 2013.  The increase in interest expense was primarily from higher loan balances on our credit facility due to drilling program and lending activities in Kentucky, and the acquisition of our common stock shares from Maximilian.  The credit facility activity is discussed further 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.

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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 another $2.2 million during the remainder of our 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 or financing is unavailable.  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.

Changes in our capital resources at August 31 2014 in comparison to February 28, 2014 are set forth in the table below:

Our working capital deficit decreased $1,451,994 or 30.9% to $3,240,056 at August 31, 2014 in comparison to $4,692,050 at February 28, 2014.  This decrease in the working capital deficit was primarily due to an increase in revenue from an additional four new development wells that were put on production in Kentucky during the six months ended August 31, 2014. For the three months ended August 31, 2014 we generated a net profit of $114,514. While we have ongoing positive cash flow from our operations in California and Kentucky we have not yet been able to generate sufficient cash flow to cover all of our G&A and interest expense requirements on a consistent basis.  We anticipate an increase in our cash flow from our operations in Kern County, California and Lawrence County, Kentucky during the current fiscal year will contribute to the continuing reduction in our working capital deficit and improved net profit results.

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 California and Kentucky, 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, 2014 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.  Since entering the oil and gas exploration industry, we have incurred quarterly net losses until this last quarter ended August 31, 2014.  As of August 31, 2014, we have an accumulated deficit of $27,615,718 and a working capital deficit of $3,240,056 which raises substantial doubt about our ability to continue as a going concern.

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In the current fiscal year, we will 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.

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 Provided by (Used In) Operating Activities

Cash flow from operating activities is derived from the production of our oil and gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances.  For the six months ended August 31, 2014, we had a positive cash flow from operating activities of $97,529 in comparison to a cash flow deficit of $657,574 for the six months ended August 31, 2013.  This is an improvement of $755,103 in our cash flow from our operating activities for the six months ended August 31, 2014.  Non-cash account balances relating to DD&A; amortization of debt discount and deferred financing costs; and stock compensation accounted for an increase of $248,942 for the six months ended August 31, 2014.  Changes in our receivables and payables balances accounted for a net decrease of $306,458 in our cash flow for the six months ended August 31, 2014.  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, 2014 was $4,029,956, an increase of $2,746,680 from the $1,283,276 used in investing activities for the six months ended August 31, 2013.  This increase was due to the two drilling programs of four wells each that were undertaken in Kentucky during the six months ended August 31, 2014 and advances made to App Energy for the same drilling programs.  Advances to App Energy during the six months ended August 31, 2014 were $2,716,040.  Effective August 21, 2014, in connection with amending our credit facility with Maximilian, we also amended the terms of the App Energy loan to eliminate App Energy’s right under the original loan agreement to waive up to three required monthly payments.  Refer to Note 9 – 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.  Cash provided by our financing activities was approximately $3.7 million for the six months ended August 31, 2014 in comparison to cash used in our financing activities of approximately $2.0 million for the six months ended August 31, 2013.  We received advances on our loan commitment for drilling activities in California and Kentucky of approximately $5.7 million in aggregate offset by payments on our credit line, note payable and deferred financing fees.

The following discussion is a summary of cash flows provided by, and used in, the Company’s financing activities at August 31, 2014.

Current Borrowings

Related Party

During the years ended February 29, 2012 and February 28, 2013, the Company’s President and Chief Executive Officer 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.

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Line of Credit

The Company has an existing $890,000 line of credit 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, 2014 the Line of Credit had an outstanding balance of $880,010.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $15,641 for the six months ended August 31, 2014.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

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 (of which $250,000 was issued to a related party) to the Company and accrues interest at 12% per annum, payable semi-annually on January 29th and July 29th.  The note principal is payable in full at the maturity 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.

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 was $15,372 for the six months ended August 31, 2014.

For the six months ended August 31, 2014, there was one 12% Subordinated noteholder who exercised the warrants associated with the 12% Note.  A total of 50,000 warrants were exercised and resulted in 50,000 shares of common stock being issued to the noteholder.

The 12% Note warrants that have been exercised are set forth in the table below.

Current Notes balances at August 31, 2014 and February 28, 2014 are set forth in the table below:

Current Notes, related party balances at August 31, 2014 and February 28, 2014 are set forth in the table below:

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Non-current Borrowings

Maximilian Loan

On October 31, 2012, the Company entered into a loan agreement with Maximilian, 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 was $69,264 for the six months ended August 31, 2014.

The Company also issued 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.  On March 10, 2014, one of the third parties exercised 2,118,900 warrants resulting in the issuance of 1,873,554 shares of the Company’s common stock.

Maximilian Loan - Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App in the Twin Bottoms Field in Lawrence County, Kentucky, 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 personal property of the Company, and a mortgage on 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 – Note Receivable).

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 Maximilian, 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; and contain an exercise blocker provision that prevents any exercise of the warrants if such exercise and related issuance of common stock would increase the Maximilian holdings of the Company’s common stock to more than 9.99% of the Company’s currently issued and outstanding shares at the time of the exercise.  The Company also granted to Maximilian 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 its Kentucky acreage, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.

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On May 28, 2014 at Maximilian’s request, the Company finalized a share-for-warrant exchange agreement in which Maximilian returned to the Company 427,729 common shares and was in turn issued the same number of warrants containing the same provisions as the originally issued warrants.  This share-for-warrant exchange occurred so that Maximilian would hold no more than 9.99% of the Company’s common shares issued and outstanding.  The Company determined that the share-for-warrant exchange did not result in any incremental fair value.

On August 21, 2014, the Company entered into a First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement (the “Amendment”) with Maximilian under its Amended and Restated Loan and Security Agreement dated as of August 28, 2013.  The Amendment secured for the Company an additional advance of $2,200,000 under its credit facility with Maximilian since the advances made by Maximilian had already exceeded its minimum funding commitment. Additionally, Maximilian agreed to temporarily decrease the required monthly payment made by the Company until a savings of $1,000,000 was realized by the Company.  The combined $3,200,000 in additional capital will be used by the Company for additional development well drilling on its Twin Bottoms Field acreage in Kentucky and to loan funds to App, its Kentucky drilling partner, for its portion of the development well drilling.  Furthermore, Maximilian agreed to reduce the regular interest rate applicable to the loan from 12% per annum to 9% per annum and the default interest rate by 3%.

The additional advance, the reduction in the required monthly payment and the reduction in the interest rate were facilitated through our acquisition of 5,694,823 shares of our common stock held by Maximilian.  The repurchased shares were cancelled and restored to the status of authorized, but unissued stock.  We paid for the share repurchase transaction through an advance of $1,708,447 under the existing loan agreement with Maximilian.

During the six months ended August 31, 2014, the Company received multiple advances from Maximilian of approximately $5.7 million in aggregate that were used to participate in the multi-well drilling program at the Twin Bottoms Field in Kentucky and to advance of funds to App through a long-term note receivable.  The Company made principal payments of approximately $1.7 million to Maximilian during the six months ended August 31, 2014.  The Company has recognized $154,559 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, 2014 and February 28, 2014 are set forth in the table below:

Non-current debt balances at August 31, 2014 and February 28, 2014 are set forth in the table below:

App Loan Agreement

In connection with amending and restating its loan agreement with Maximilian, on August 28, 2013 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 pursuant to a Loan and Security Agreement between the Company as lender and App as borrower (the “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 Maximilian.  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 App leases in Lawrence County, Kentucky.

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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 Twin Bottoms Field in Lawrence County, Kentucky 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.

In connection with the App Loan Agreement, App also granted to the Company a 25% working interest in approximately 6,400 acres (currently 7,300 acres) in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky 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.

At August 31, 2014, the Company had advanced $7.75 million to App through its credit facility.  Note receivable balances at August 31, 2014 and February 28, 2014 are set forth in the table below:

As of October 10, 2014, the Company had advanced $300,000 to App Energy, LLC through its credit facility with the Company.

Capital Commitments

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 between Maximilian as lender, and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and a mortgage on our leases in Kern County, California encompassing the Sunday, Bear, Black, Ball and Dyer Creek properties.  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.  We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.  Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.

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At August 31, 2014, a total of 2,986,220 shares of restricted stock had been awarded and remained outstanding under the 2009 Plan, and 3,000,000 shares had fully vested.  A total of 1,013,780 common stock shares remained available at August 31, 2014 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, 2014, the Company recognized compensation expense related to the above restricted stock grants in the amount of $2,514.  For the six months ended August 31, 2014, there were 2,040 shares of the Company’s common stock relating to the 2009 Plan that were returned to the 2009 Plan to satisfy an employee’s payroll tax liability upon the vesting of the shares relating to the 2009 Plan.

Management Plans to Continue as a Going Concern

We continue to implement plans to enhance Daybreak’s ability to continue as a going concern.  The Company currently has a net revenue interest in 20 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 36.8% and the average net revenue interest is 28.4%.

Additionally, we have become involved in a shallow oil play in an existing gas field in Lawrence County, Kentucky, through our acquisition of a 25% working interest in approximately 7,300 acres in two large contiguous acreage blocks in the Twin Bottoms Field in Lawrence County, Kentucky.  We now have nine horizontal oil wells on production in Kentucky.  We are in the process of completing and bringing onto production an additional four horizontal oil wells also in Kentucky.  Our average working interest in these thirteen wells is 22.5% and the average net revenue interest is 19.7%.

We anticipate revenues will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project in California and the Twin Bottoms Field in Kentucky.  The Company plans to continue its development drilling program at a rate that is compatible with its cash flow and funding opportunities.

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, 2014.

Off-Balance Sheet Arrangements

As of August 31, 2014, 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

As of the end of the reporting period, August 31, 2014, an evaluation was conducted by Daybreak management, including our President and Chief Executive Officer, who is also serving as our interim principal finance and accounting officer, as to the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Exchange Act.  Such disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods specified by the SEC rules and forms.  Additionally, it is vital that such information is accumulated and communicated to our management, including our President and Chief Executive Officer, in a manner to allow timely decisions regarding required disclosures.  Based on that evaluation, our management concluded that our disclosure controls were effective as of August 31, 2014.

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, 2014 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, 2014, 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.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Items 2(a) and (b) are inapplicable.

(c) Stock Repurchases for the three months ended August 31, 2014:

(1)

On August 21, 2014, in connection with and as consideration for the amendment to the Company’s credit facility with Maximilian and additional advances thereunder (see “Cash Flow Provided by Financing Activities – Non-current Borrowings”), the Company repurchased from Maximilian 5,694,823 shares of its common stock, $0.001 par value (the “Repurchased Shares”), which shares were originally issued to Maximilian in connection with the credit facility and constitute all shares of common stock owned by Maximilian, beneficially and of record. The purchase price for the Repurchased Shares was $1,708,446.90, or $0.30 per share, and was paid as an advance under the credit facility and added to the outstanding principal balance of the loan.  Maximilian continues to hold warrants to purchase up to 6,550,281 shares of common stock of the Company.  (For more information about the terms of the warrants, see “Cash Flow Provided by Financing Activities – Non-current Borrowings.”)  The Company believes that the acquisition of the Repurchased Shares will increase stockholder value by significantly reducing its number of common shares outstanding. The Repurchased Shares were cancelled and restored to the status of authorized but unissued stock.

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ITEM 6.  EXHIBITS

The following Exhibits are filed as part of the report:

Exhibit

Number

Description

10.1⁽¹⁾

First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement, dated August 21, 2014, by and between Daybreak Oil and Gas, Inc. and Maximilian Resources LLC, a Delaware limited liability company.

10.2⁽¹⁾

First Amendment to Loan and Security Agreement, dated August 21, 2014, by and between Daybreak Oil and Gas, Inc. and App Energy, LLC, a Kentucky limited liability company.

31.1⁽¹⁾

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

32.1⁽¹⁾

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

101.INS⁽²⁾

XBRL Instance Document

101.SCH⁽²⁾

XBRL Taxonomy Schema

101.CAL⁽²⁾

XBRL Taxonomy Calculation Linkbase

101.DEF⁽²⁾

XBRL Taxonomy Definition Linkbase

101.LAB⁽²⁾

XBRL Taxonomy Label Linkbase

101.PRE⁽²⁾

XBRL Taxonomy Presentation Linkbase

⁽¹⁾

Filed herewith.

⁽²⁾

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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