Daybreak Oil and Gas

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

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

(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 July 11, 2014 the registrant had 57,145,236 outstanding shares of $0.001 par value common stock.

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

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.

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, these 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 three months ended May 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.

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

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.

The Company’s financial statements for the three months ended May 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 May 31, 2014 has an accumulated deficit of $27,730,232 and a working capital deficit of $3,410,021 which raises substantial doubt about the Company’s ability 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 6,400 acres in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky. Daybreak currently has a net revenue interest in nine producing oil wells in the Twin Bottoms Field. The Company’s average working interest in these nine 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 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 May 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.

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.

Substantially all of the Company’s trade accounts receivable result from crude oil and natural gas 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 May 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 May 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.

The Company’s oil and natural gas revenues accounts receivable from California and Kentucky operations at May 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 May 31, 2014 and February 28, 2014 are set forth in the table below:

During the three months ended May 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 May 31, 2014 and February 28, 2014 as set forth in the table below.

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

Production revenue receivable balances of $245,000 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 May 31, 2014 and February 28, 2014 are set forth in the table below:

Deferred financing costs at May 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 three months ended May 31, 2014. For the three months ended May 31, 2014, the Company recognized amortization expense of $103,562.

At May 31, 2014, the Company had advanced $6,150,000 to App through its credit facility. Note receivable balances at May 31, 2014 and February 28, 2014 are set forth in the table below:

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, $261,349 remains unpaid and is included in the May 31, 2014 accounts payable balance.

The May 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.

As of May 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.

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 May 31, 2014, the Line of Credit had an outstanding balance of $881,064. Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $7,835 for the three months ended May 31, 2014. The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

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 $7,513 for the three months ended May 31, 2014.

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

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

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 $34,474 for the three months ended May 31, 2014. Unamortized debt discount amounted to $308,579 at May 31, 2014.

In 2012, 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.

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 provision blocker 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-to-warrant exchange occurred so that Maximilian could remain at the 9.99% threshold of the Company’s common shares issued and outstanding. The Company determined that the share-to-warrant exchange did not result in any incremental fair value.

During the three months ended May 31, 2014, the Company received multiple advances from Maximilian totaling $3,500,000 in aggregate that were used to participate in the multi-well drilling program at the Twin Bottoms Field in Kentucky; and, the advance of funds to App through a long-term note receivable. 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 May 31, 2014 and February 28, 2014 are set forth in the table below:

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

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 May 31, 2014, there were 737,565 shares issued and outstanding, that had not been converted into our common stock. As of May 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.

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 three months ended May 31, 2014 are set forth in the table below:

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value common stock of which 57,005,236 shares were issued and outstanding as of May 31, 2014. In comparison, at February 28, 2014, a total of 55,509,411 shares were issued and outstanding. The increase of 1,495,825 shares was attributable as shown below:

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

There were no warrants that expired during the three months ended May 31, 2014. During the three months ended May 31, 2014, there were 50,000 warrants exercised 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 three months ended May 31, 2014 in connection with the Maximilian share-for-warrants exchange. The remaining outstanding warrants as of May 31, 2014, have a weighted average exercise price of $0.11, a weighted average remaining life of 2.13 years, and an intrinsic value of $1,942,783.

At May 31, 2014, a total of 2,882,010 shares of restricted stock had been awarded and remained outstanding under the 2009 Plan, and 2,893,750 of the shares had fully vested. A total of 1,011,740 Common Stock shares remained available at May 31, 2014 for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is set forth in the table below:

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.

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 three months ended May 31, 2014, the Company recognized compensation expense related to the above restricted stock grants in the amount of $1,887. Unamortized compensation expense amounted to $628 as of May 31, 2014.

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 May 31, 2014, Daybreak had estimated net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $21,637,940 which will begin to expire, if unused, beginning in 2024. The valuation allowance increased $72,900 and $464,360 for the three months ended May 31, 2014 and the year ended February 28, 2014, respectively. 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.

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 May 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.

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 three months ended May 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.

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:

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:

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;

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 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.

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.

We have a limited operating history of oil and natural gas production and minimal proven reserves, production and cash flow. To date, we have had limited revenues and have not been able to generate sustainable positive earnings on a Company-wide basis. Our management cannot provide any assurances that Daybreak will ever operate profitably. As a result of our limited operating history, 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”).

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 three months ended May 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 investments within the East Slopes Project area during the remainder of the current fiscal year.

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.

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. We have a 37.5% working interest in all wells at the Bear Property. The Bear #1, Bear #2, Bear #3 and Bear #4 wells have an NRI to Daybreak of 26.1%. In May and June 2013, we drilled three additional development wells; the Bear #5, Bear #6 and Bear #7 on this property. We have a NRI of 30.1% in these three wells. In November 2013, we drilled two additional development wells; the Bear #8, Bear #9 on this property. We have a NRI of 31.7% in the Bear #8 and Bear #9 wells. Our 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.

The Black property was acquired through a farm-in arrangement with a local operator. The Black property is just south of the Bear property on the same fault system. The Black #1 well was completed and put on production in January 2010. Production is from the Vedder sand at approximately 2,200 feet. In May 2013, we drilled a development well, the Black #2, on this property. We have a 37.5% working interest with a 29.8% NRI in all wells on this property. 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.

The Ball #1-11 well was 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 in 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.

The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010. This well is producing from the Vedder sand and is located to the north of the Bear property on the same trapping fault. 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 in the future.

The oil produced from our acreage is considered to be 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. 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 $13 per barrel of oil for the three months ended May 31, 2014. With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

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 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 would 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.

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.

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.

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.

The Twin Bottoms Field, comprising approximately 7,100 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 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. 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 $2.4 million in new capital investments within the Twin Bottoms Field area in the 2014 - 2015 fiscal year.

The first well, the Grove H-1 was completed in September 2013 and put on production in mid-October 2013. Our second well, the Grove H-3 well was completed in October 2013 and put on production in December 2013. Our third and fourth wells on this lease, the Grove H-4 and Grove H-5, were drilled in December 2013; and they were put on production in February 2014.

In March and April of 2014 we participated in the drilling of four additional wells on the Gerald Grove property. The Grove H-7, Grove H-8, Grove H-9 and Grove H-10 will share a common production facility. First production from these four wells occurred in June 2014.

The first well on this property, the Dillon H-6 well was drilled in October 2013 with first oil sales occurring in March 2014. The delay in production was caused by the unusually severe weather conditions this past winter season in the Twin Bottoms Field of eastern Kentucky.

The Company’s debt obligations, pursuant to a loan agreement entered into by and between Maximilian Resources LLC, a Delaware limited liability company, as lender, and the Company are secured by a perfected first priority security interest in substantially all of the 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 “Non-current Borrowings” in this MD&A.

Results of Operations – Three Months Ended May 31, 2014 compared to the Three Months Ended May 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 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 (Thousand Cubic Feet) is based on the Columbia Gas Transmission Corp. Appalachian Index (TCO Appalachia) whereby we will receive 76% of the Appalachian Index 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.

Historically, the sale price we receive for our California heavy oil sales has been less than the quoted WTI price. However, from March of 2011 through May 31, 2013, we received a premium for our California oil in comparison to the WTI price. For the three months ended May 31, 2014, the average monthly WTI price was $101.68, and the average monthly sale price was $96.37, which was a discount of 5.2% from the average monthly WTI price. In comparison, for the three months ended May 31, 2013, the average monthly WTI price was $93.16 and the average monthly sale price we received was $96.89 resulting in a premium that was 4.0% above the average monthly WTI price. We are unable to forecast if we will again receive a premium for our California heavy oil sales in comparison to the WTI price as there are many factors beyond our control that dictate the price we receive on our oil sales.

Our first sales of oil in Kentucky occurred in October 2013. For the three months ended May 31, 2014, we received an average price of $99.97 in comparison to the average WTI price of $101.68 representing a discount of 1.7% from the average WTI for the same three month period.

Our first natural gas sales in Kentucky also occurred in October 2013. For the three months ended May 31, 2014, we received an average price of $2.66 per Mcf in comparison to the average Henry Hub price of $4.69 per Mcf representing a 43.3% discount from the average Henry Hub price for the same three month period.

Oil and natural gas revenues for the three months ended May 31, 2014 and 2013 are set forth in the following table.

Revenues for the three months ended May 31, 2014 increased $581,825 or 254.5% to $810,429 in comparison to revenue of $228,604 for the three months ended May 31, 2013. In California, revenues increased $201,520 due to an increase in production because of the nine wells that were put on production in late May through mid-June 2013. Same well revenues from the existing 11 wells in California decreased by $31,709 or 318 barrels due to lower average realized prices and lower production levels caused by natural reservoir decline. The average sales price of all hydrocarbon sales in California and Kentucky on a BOE (barrel of oil equivalent) basis for the three months ended May 31, 2014 was $93.77 in comparison to $96.89 for the three months ended May 31, 2013. This decrease of $3.12 or 3.2% in the average monthly sale price of BOE was offset by the increased production from nine new wells in California and five new wells in Kentucky.

Production for the three months ended May 31, 2014 was from 25 wells, 20 wells in California and five wells in Kentucky, resulting in 2,189 well days of production in comparison to 1,032 well days from 13 wells in California for the three months ended May 31, 2013. In California, our net production volume for the three months ended May 31, 2014 was 4,463 barrels of oil in comparison to 2,359 barrels for the three months ended May 31, 2013. This increase of 2,104 barrels or 89.1% was due to production from nine new wells that were put on production in late May through mid-June 2013. In Kentucky, production for the three months ended May 31, 2014 was 4,179 BOE from five wells.

Operating Expenses. Total operating expenses for the three months ended May 31, 2014 were $567,109, a decrease of $94,999 or 14.3% compared to $662,108 for the three months ended May 31, 2013. While decreases were achieved in exploration and drilling expenses and depreciation, depletion and amortization (“DD&A”) for the three months ended May 31, 2014, these savings were offset by increases in production expenses and general and administrative (“G&A”) expenses in comparison to the three months ended May 31, 2013.

Operating expenses for the three months ended May 31, 2014 and May 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 costs; and, relate directly to the number of wells that are in production. For the three months ended May 31, 2014, these expenses increased by $55,731 in comparison to the three months ended May 31, 2013. For the three months ended May 31, 2014 we had 25 wells on production in California and Kentucky in comparison to 13 wells in California for the three months ended May 31, 2013. Production expenses represented 15.1% of total operating expenses.

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses. These expenses decreased $174,174 or 96.3% for the three months ended May 31, 2014 due to recognition of $165,590 in dry hole expense from the Chimney #1-1 well during the three months ended May 31, 2013. Exploration and drilling expenses represented 1.2% 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 May 31, 2014, DD&A expenses decreased $27,893 or 18.9% in comparison to the comparative period primarily due to the recognition of an $84,929 impairment of unproved properties due to the unsuccessful drilling of an exploratory well at our Chimney prospect during the three months ended May 31, 2013. DD&A expenses represented 21.2% of total operating expenses.

G&A expenses include the salaries of our six employees, including management. Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as for running a public company. For the three months ended May 31, 2014, these expenses increased $51,337 or 16.9% to $354,819 in comparison to $303,482 for the three months ended May 31, 2013. Accounting, legal and reserve reporting expenses increased approximately $50,000 in aggregate for the three months ended May 31, 2014. This increase was due to timing differences on services and financing projects and responding to a Securities and Exchange Commission comment letter on out 10-K filing for the year ended February 28, 2013. Management and employee salaries, director fees and stock compensation were relatively unchanged for the three months ended May 31, 2014 in comparison to the three months ended May 31, 2013. For the three months ended May 31, 2014, we received, as Operator, administrative overhead reimbursement of $16,820 for the East Slopes Project which was used to directly offset certain employee salaries. For the three months ended May 31, 2013, we received $31,781 in administrative overhead reimbursement. The amount of administrative overhead reimbursement we receive is directly related to the amount of drilling activity that is underway in California. We are continuing a program of reducing all of our G&A costs wherever possible. G&A expenses represented 62.6% of total operating expenses for the three months ended May 31, 2014.

Interest income for the three months ended May 31, 2014 increased $164,786 due to the App Energy funding agreement in comparison to the three months ended May 31, 2013. Refer to the discussion later in the MD&A under the caption “Non-Current Borrowings (App loan Agreement)” for more information on the App Energy funding agreement.

Interest expense for the three months ended May 31, 2014 increased $453,999 or 213.7% in comparison to the three months ended May 31, 2013. The increase in interest expense was primarily due to interest expense associated with our credit facility with Maximilian in which funds are used for drilling in California and Kentucky. During the three months ended May 31, 2014 we received $3.5 million from Maximilian to fund the App Energy and Daybreak drilling program in Kentucky. Refer to the discussion later in this MD&A for more information on the 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 our operating expenses and to fund our development drilling programs in California and Kentucky.

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 the availability of capital resource financing. We plan to spend approximately $700,000 in the current fiscal year in new capital investments in California and $2.4 million in Kentucky; however our actual expenditures may vary significantly from this estimate if our plans for exploration and development activities change during the year. Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.

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

Our working capital deficit decreased approximately $1.3 million or 27.3% to $3,410,021 at May 31, 2014 in comparison to $4,692,050 at February 28, 2014. Included in the working capital deficit is $595,000 due to the financial statement presentation of the 12% Subordinated Notes (“Notes”) being classified as a current liability rather than a non-current liability due to the term of the Notes maturing on January 29, 2015. 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. We anticipate an increase in our cash flow from our East Slope operations in Kern County, California and the Twin Bottoms Field in Lawrence County, Kentucky during the current fiscal year due to an ongoing drilling programs that will result in an increase in the number of wells on production.

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

Major sources of funds in the past for us have included the debt or equity markets. While we have achieved positive cash flow from operations in Kern County, California and Lawrence County, 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 will cause us to seek additional forms of 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. The current uncertainty in the credit and capital markets may restrict our ability to obtain needed capital. 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.

The Company’s financial statements for the three months ended May 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. We have incurred net losses since entering the oil and gas exploration industry and as of three months ended May 31, 2014 have an accumulated deficit of $27,730,232 and a working capital deficit of $3,410,021 which raises substantial doubt about our ability to continue as a going concern.

During the three months ended May 31, 2014, we received crude oil sales revenue from 20 wells in Kern County, California and crude oil and natural gas sales revenue from five wells in Lawrence County, Kentucky. Our commitment to improving corporate profitability remains unchanged. During the three months ended May 31, 2014, we had an operating profit of $242,320. This achievement was accomplished by increasing revenues and controlling all expenses in an aggressive manner.

Our balance sheet at May 31, 2014 reflects total assets of $12,945,800 in comparison to $10,677,910 at February 28, 2014. This increase of approximately $2.3 million is comprised primarily of a $0.4 million increase in oil and gas properties and a $1.9 million increase in notes receivable.

At May 31, 2014, total liabilities were $16,003,316 in comparison to $13,486,654 at February 28, 2014. This increase of approximately $2.5 million was due to increased borrowing through our credit facility for the multi-well drilling costs in Kentucky and our lending activities to a third party associated with the Kentucky drilling.

Our common stock issued and outstanding increased by approximately 1.5 million shares to 57,005,236 at May 31, 2014 in comparison to 55,509,411 at February 28, 2014. This increase in shares was primarily due to the exercise of warrants that were issued to a third party that assisted in arranging our original financing with Maximilian and the exercise of warrants for common stock related to our 12% Subordinated Notes.

Our financial statements for the three months ended May 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. Our financial statements show that the Company has incurred significant operating losses that raise substantial doubt about our ability to continue as a going concern. The accompanying financial statements do not include any adjustments that might result from this uncertainty.

The increase of $257,659 in the accumulated deficit from $27,472,573 at February 28, 2014 to $27,730,232 at May 31, 2014 was due to the net loss for the three months ended May 31, 2014. Approximately $327,493 of the net loss can be attributed to net interest expense related to our financing agreements and $103,562 in amortization of deferred financing costs. We expect to be able to lower our net loss in the current fiscal year because of increased oil sales revenue from more wells being in production.

We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations, investments and capital resource funding. Our cash balances were $119,418 and $500,431 at May 31, 2014 and February 28, 2014, respectively.

Oil revenues increased $581,825 or 254.5% to $810,429 for the three months ended May 31, 2014 in comparison to $228,604 for the three months ended May 31, 2013. This increase was due to putting nine more wells on production in California and five wells on production in Kentucky.

Operating expenses decreased by $94,999 or 14.3% to $567,109 for the three months ended May 31, 2014 in comparison to the three months ended May 31, 2013. The decrease was related to recognition of dry hole expense and impairment of unproved oil properties in California recognized during the three months ended May 31, 2013.

For the three months ended May 31, 2014, we reported an operating profit of $243,320 in comparison to an operating loss of $433,504 for the three months ended May 31, 2013. This increase of 676,824 or 156.1% was due to the increase in revenue of $581,825 from the 14 additional wells that were put on production in California and Kentucky and a decrease in operating expenses of $94,999.

Since entering the oil and gas exploration industry, we have incurred recurring losses with periodic negative cash flow and have depended on external financing and the sale of oil and gas assets to sustain our operations. A net loss of $257,659 was reported for the three months ended May 31, 2014 in comparison to a net loss of $645,670 for the three months ended May 31, 2013. The decrease in net loss of $388,011 or 60.1% for the three months ended May 31, 2014 was due to an increase in revenues and a decrease in operating expenses offset by an increase in interest expense.

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 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 three months ended May 31, 2014, we had a positive cash flow from operating activities of $15,090 in comparison to a positive cash flow of $36,423 for the three months ended May 31, 2013. This decrease of $21,333 was primarily due to a reduction of our accounts payable balances. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

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 three months ended May 31, 2014 was $2,822,363, an increase of $2,242,790 from the $579,573 used in investing activities for the three months ended May 31, 2013. This increase is directly related to the funding of our drilling program in Kentucky, where we drilled four additional wells during the three months ended May 31, 2014. Refer to the caption “Non-current Borrowings – App Loan Agreement for further discussion of the App Energy loan.

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 through financing activities for the three months ended May 31, 2014 was $2,426,260 an increase of $1,841,638 in comparison to the $584,622 provided through financing activities in the three months ended May 31, 2013. For the three months ended May 31, 2014 we received multiple advances of $3,500,000 in aggregate on our loan commitment for drilling in Kentucky. The following is a summary of cash flows provided by, and used in, the Company’s financing activities during the three months ended May 31, 2014.

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.

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 May 31, 2014 the Line of Credit had an outstanding balance of $881,064. Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $31,911 and $32,553 for the three ended May 31, 2014. The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

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.

For the three months ended May 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.

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 for the three months ended May 31, 2014 amounted to $34,474. Unamortized debt discount amounted to $308,579 at May 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 who assisted in the closing of the loan exercised 2,118,900 warrants resulting in the issuance of 1,873,554 shares of the Company’s common stock.

In connection with the Company’s acquisition of a working interest from App Energy, LLC (“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 the caption “App Loan Agreement” in the discussion below for further information).

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; are exercisable for a period of three years expiring on August 28, 2016; and contain an exercise provision blocker 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 properties, 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-to-warrant exchange occurred so that Maximilian could remain at the 9.99% threshold of the Company’s common shares issued and outstanding.

During the three months ended May 31, 2014, the Company received multiple advances totaling $3.5 million in aggregate that were used to participate in the Company’s drilling program in the Twin Bottoms Field in Kentucky and for the advance of funds to App through a long-term note receivable. 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 May 31, 2014 and February 28, 2014 are set forth in the table below:

Non-current debt balances at February 28, 2014 and February 28, 2013 are set forth in the table below:

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 Company’s leases in Lawrence County, Kentucky.

The proceeds of the initial borrowing by App of $2.65 million under the App facility were primarily used to (a) pay loan fees and closing costs, (b) repay indebtedness and (c) finance the drilling of three wells by App in the 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 the 25% working interest approximately 6,400 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 May 31, 2014, the Company advanced $6.1 million to App through its credit facility. The total amount advanced includes fees paid in connection with the loan amounting to $72,000 and settlement of App’s existing obligation to another lender of $200,386 which were paid directly by Maximilian.

Note receivable balances at May 31, 2014 and February 28, 2014 are set forth in the table below:

The Company’s debt obligations, pursuant to a loan agreement entered into by and between Maximilian 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 including the Sunday, Bear, Black, Ball and Dyer Creek properties. For further information on the loan agreement with Maximilian refer to the discussion above under the caption “Non-current Borrowings in this MD&A.

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.

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.

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 oil wells in our East Slopes Project located in Kern County, California. The revenue from these wells has created a steady and reliable source of revenue for the Company. Our average working interest in these wells is 36.8% and the average net revenue interest is 28.4%. During the year ended February 28, 2014, we successfully drilled and put on production nine additional development wells at our Sunday, Bear, Black and Ball locations.

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 6,400 acres in two large contiguous acreage blocks in the Twin Bottoms Field in Lawrence County, Kentucky. The initial drilling program involved drilling five horizontal oil wells which have all been completed and are now producing. Additionally, we have just completed drilling another four horizontal oil wells in Kentucky and production commence in mid to late June 2014 on these wells. Our average working interest in these nine 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.

As a result of our successful drilling activity, we believe that our liquidity will continue to improve. Our sources of funds in the past have included the debt or equity markets and, while the Company does have positive cash flow from its oil and gas 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, we cannot offer any assurance that we will be successful in executing the aforementioned plans to continue as a going concern.

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2014.

As of May 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.

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

As of the end of the reporting period, May 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 May 31, 2014.

There have not been any changes in the Company’s internal control over financial reporting during the three months ended May 31,2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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.

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.

On May 28, 2014, at the request of Maximilian, the Company’s lender and single largest shareholder, 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 to purchase shares of the Company’s common stock. The warrants have an exercise price of $0.10; contain a cash exercise provision; expire on August 28, 2016; and contain an exercise provision blocker 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. No other consideration was given for the common shares exchanged.

The warrants were issued pursuant to the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended, and Regulation D promulgated thereunder, in that the sale and purchase of such securities did not involve any public offering, Maximilian is an “accredited investor” as that term is defined under Rule 501 of Regulation D, Maximilian had access to information about the Company and its investment, Maximilian took the securities for investment and not resale, and the Company took appropriate measures to restrict the transfer of the securities.

Share Exchange Agreement dated as of May 19, 2014, by and between Daybreak Oil and Gas, Inc. and Maximilian Investors LLC.

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

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

Previously filed as an exhibit to Form 10-K dated May 28, 2014 filed on May 29, 2014, and incorporated by reference herein.

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.


DAYBREAK OIL AND GAS, INC.

By:	/s/ JAMES F. WESTMORELAND
	James F. Westmoreland, its
	President, Chief Executive Officer and interim
	principal finance and accounting officer
	(Principal Executive Officer, Principal Financial
	Officer and Principal Accounting Officer)

Date: July 11, 2014


Washington		91-0626366
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

601 W. Main Ave., Suite 1017, Spokane, WA		99201
(Address of principal executive offices)		(Zip code)


Large accelerated filer ¨		Accelerated filer ¨

Non-accelerated filer ¨	(Do not check if a smaller reporting company)	Smaller reporting company þ


ITEM 1.	FINANCIAL STATEMENTS	3
	Balance Sheets at May 31, 2014 and February 28, 2014 (Unaudited)	3
	Statements of Operations for the Three Months Ended May 31, 2014 and May 31, 2013 (Unaudited)	4
	Statements of Cash Flows for the Three Months Ended May 31, 2014 and May 31, 2013 (Unaudited)	5
	NOTES TO UNAUDITED FINANCIAL STATEMENTS	6

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	15
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30
ITEM 4.	CONTROLS AND PROCEDURES	30



ITEM 1.	LEGAL PROCEEDINGS	31
ITEM 1A.	RISK FACTORS	31
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	31
ITEM 6.	EXHIBITS	32
Signatures		33


	As of May 31,		As of February 28,
	2014		2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	119,418	$	500,431
Accounts receivable:
Oil and gas sales		347,379		330,343
Joint interest participants		264,842		338,950
Loan commitment refund and other receivables, net		28,243		30,039
Current portion – production revenue receivable		120,000		120,000
Prepaid expenses and other current assets		23,506		29,397
Current portion – note receivable		2,058,247		793,727
Total current assets		2,961,635		2,142,887
OIL AND GAS PROPERTIES, net, successful efforts method
Proved properties		3,312,246		2,914,965
Unproved properties		1,269,424		1,261,156
PREPAID DRILLING COSTS		358,380		14,915
NON-CURRENT portion – production revenue receivable		125,000		155,000
DEFERRED FINANCING COSTS, net		1,377,597		1,326,600
NON-CURRENT portion – note receivable		3,435,383		2,756,273
OTHER ASSETS		106,135		106,114
Total assets	$	12,945,800	$	10,677,910

LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,721,538	$	2,158,546
Accounts payable – related parties		946,003		952,652
Accrued interest		147,448		1,587
Notes payable – related party		250,100		250,100
12% Notes payable, net		332,199		327,871
12% Notes payable – related party, net		240,580		237,395
Current portion – debt, net		1,852,724		2,024,417
Line of Credit		881,064		882,369
Total current liabilities		6,371,656		6,834,937
LONG TERM LIABILITIES:
Non-current portion – debt, net		9,609,065		6,629,638
Asset retirement obligation		22,595		22,079
Total liabilities		16,003,316		13,486,654
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ DEFICIT:
Preferred stock - 10,000,000 shares authorized, $0.001 par value;		-		-
Series A Convertible Preferred stock – 2,400,000 shares authorized, $0.001 par value, 6% cumulative dividends; 737,565 shares issued and outstanding		738		738
Common stock – 200,000,000 shares authorized; $0.001 par value, 57,005,236 and 55,509,411 shares issued and outstanding, respectively		57,005		55,509
Additional paid-in capital		24,614,973		24,607,582
Accumulated deficit		(27,730,232)		(27,472,573)
Total stockholders’ deficit		(3,057,516)		(2,808,744)
Total liabilities and stockholders’ deficit	$	12,945,800	$	10,677,910


	Three Months Ended May 31,		Three Months Ended May 31,
	2014		2013
REVENUE:
Oil and gas sales	$	810,429	$	228,604

OPERATING EXPENSES:
Production		85,530		29,799
Exploration and drilling		6,783		180,957
Depreciation, depletion, amortization and impairment		119,977		147,870
General and administrative		354,819		303,482
Total operating expenses		567,109		662,108
OPERATING PROFIT (LOSS)		243,320		(433,504)

OTHER INCOME (EXPENSE):
Interest income		164,838		52
Interest expense		(665,817)		(212,218)
Total other income (expense)		(500,979)		(212,166)

NET LOSS		(257,659)		(645,670)

Cumulative convertible preferred stock dividend requirement		(33,461)		(40,313)

NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(291,120)	$	(685,983)

NET LOSS PER COMMON SHARE – Basic and diluted	$	(0.01)	$	(0.01)

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING – Basic and diluted		57,194,488		48,851,619


	Three Months Ended
	May 31, 2014		May 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(257,659)	$	(645,670)
Adjustments to reconcile net loss to net cash provided by operating activities:
Stock compensation		1,887		6,722
Depreciation, depletion and impairment and ARO expense		119,977		147,870
Amortization of debt discount		41,987		38,147
Amortization of deferred financing costs		103,562		20,362
Non-cash interest income		(21)		(52)
Changes in assets and liabilities:
Accounts receivable – oil and gas sales		(17,036)		15,764
Accounts receivable – joint interest participants		74,108		(294,632)
Accounts receivable – other		31,796		(200)
Prepaid expenses and other current assets		5,891		6,220
Accounts payable and other accrued liabilities		(235,653)		673,262
Accounts payable – related parties		(6,649)		73,630
Accrued interest		152,900		(5,000)
Net cash provided by operating activities		15,090		36,423

CASH FLOWS FROM INVESTING ACTIVITIES:
Prepaid drilling costs		(343,465)		(154,701)
Advances for oil and gas properties		-		(92,048)
Note receivable		(1,943,630)		-
Deferred interest		655		-
Additions to oil and gas properties		(535,923)		(332,824)
Net cash used in investing activities		(2,822,363)		(579,573)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from warrant exercise		7,000		-
Proceeds from note payable		3,500,000		607,835
Payment on note payable		(726,740)		(14,213)
Payment of deferred financing fees		(345,000)		-
Payments on line of credit		(9,000)		(9,000)
Net cash provided by financing activities		2,426,260		584,622

NET INCREASE (DECREASE)IN CASH AND CASH EQUIVALENTS		(381,013)		41,472
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		500,431		79,996
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	119,418	$	121,468

CASH PAID FOR:
Interest	$	382,575	$	175,029
Income taxes	$	-	$	-

SUPPLEMENTAL CASH FLOW INFORMATION:
Unpaid additions to oil and gas properties	$	10,914	$	228,229
Conversion of warrants	$	1,874	$	-
Share-to-warrant exchange	$	428	$	-
Interest converted to principal	$	7,695	$	-
ARO asset and liability increase	$	-	$	13,887
Unpaid deferred financing fees	$	-	$	34,138
Conversion of preferred stock to common stock	$	-	$	24


		At May 31, 2014			At February 28, 2014
Project	Customer	Revenue Receivable		Percentage	Revenue Receivable		Percentage
California – East Slopes Project (Oil)	Plains Marketing	$	251,074	72.3%	$	244,384	74.0%
Kentucky – Twin Bottoms Field (Oil)	Appalachian Oil		89,729	25.8%		85,120	25.8%
Kentucky – Twin Bottoms Field (Gas)	Jefferson Gas		6,576	1.9%		839	0.2%
		$	347,379	100.0%	$	330,343	100.0%


	May 31, 2014		February 28, 2014
Loan commitment and other receivables	$	267,243	$	269,039
Allowance for doubtful accounts		(239,000)		(239,000)
Balance	$	28,243	$	30,039


	May 31, 2014		February 28, 2014
California	$	16,452	$	16,452
Kentucky		341,928		(1,537)
Balance	$	358,380	$	14,915


	May 31, 2014		February 28, 2014
Proved leasehold costs	$	2,236	$	2,236
Unproved leasehold costs		1,269,424		1,261,156
Costs of wells and development		1,050,404		492,970
Capitalized exploratory well costs		3,978,208		4,018,899
Total cost of oil and gas properties		6,300,272		5,775,261
Accumulated depletion, depreciation, amortization and impairment		(1,718,602)		(1,599,140)
Net oil and gas properties	$	4,581,670	$	4,176,121


	May 31, 2014		February 28, 2014
Production revenue receivable – current	$	120,000	$	120,000
Production revenue receivable – non-current		125,000		155,000
	$	245,000	$	275,000


	May 31, 2014		February 28, 2014
Deferred financing costs – loan fees	$	151,139	$	151,139
Deferred financing costs – loan commissions		630,662		476,103
Deferred financing costs – fair value of warrants		530,488		530,488
Deferred financing costs – fair value of common stock		419,832		419,832
		1,732,121		1,577,562
Accumulated amortization		(354,524)		(250,962)
Balance	$	1,377,597	$	1,326,600


	May 31, 2014		February 28, 2014
Note receivable – current	$	2,058,247	$	793,727
Note receivable – non-current		3,435,383		2,756,273
	$	5,493,630	$	3,550,000


	May 31, 2014		February 28, 2014
12% Subordinated Notes	$	345,000	$	345,000
12% Subordinated Notes discount		(12,801)		(17,129)
	$	332,199	$	327,871


Fiscal Period	Shares of Series A Preferred Converted to Common Stock	Shares of Common Stock Issued from Conversion	Number of Accredited Investors
Year Ended February 29, 2008	102,300	306,900	10
Year Ended February 28, 2009	237,000	711,000	12
Year Ended February 28, 2010	51,900	155,700	4
Year Ended February 28, 2011	102,000	306,000	4
Year Ended February 29, 2012	-	-	-
Year Ended February 28, 2013	18,000	54,000	2
Year Ended February 28, 2014	151,000	453,000	9
Three Months Ended May 31, 2014	-	-	-
Totals	662,200	1,986,600	41


Grant Date	Shares Awarded	Vesting Period	Shares Vested⁽¹⁾	Shares Returned⁽²⁾	Shares Outstanding (Unvested)
4/7/2009	1,900,000	3 Years	1,900,000	-	-
7/16/2009	25,000	3 Years	25,000	-	-
7/16/2009	625,000	4 Years	619,130	5,870	-
7/22/2010	25,000	3 Years	25,000	-	-
7/22/2010	425,000	4 Years	312,880	5,870	106,250
	3,000,000		2,882,010⁽¹⁾	11,740	106,250


	May 31, 2014		February 28, 2014		Increase (Decrease)		Percentage Change
Cash	$	119,418	$	500,431	$	(381,013)	(76.1%)
Current Assets	$	2,961,635	$	2,142,887	$	818,748	38.2%
Total Assets	$	12,945,800	$	10,677,910	$	2,267,890	21.2%
Current Liabilities	$	(6,371,656)	$	(6,834,937)	$	463,281	(6.8%)
Total Liabilities	$	(16,003,316)	$	(13,486,654)	$	(2,516,662)	18.7%
Working Capital	$	(3,410,021)	$	(4,692,050)	$	1,282,029	(27.3%)


Fiscal Period	Warrants Exercised	Shares of Common Stock Issued	Number of Accredited Investors
Year Ended February 28, 2014	100,000	100,000	1
Three Months Ended May 31, 2014	50,000	50,000	1
Totals	150,000	150,000	2


	May 31, 2014		February 28, 2014
12% Subordinated Notes, related party	$	250,000	$	250,000
12% Subordinated Notes discount, related party		(9,420)		(12,605)
	$	240,580	$	237,395


	May 31, 2014		February 28, 2014
Maximilian Note	$	1,991,679	$	2,163,405
Maximilian Note Discount		(138,955)		(138,988)
	$	1,852,724	$	2,024,417


Fiscal Period	Shareholders at Period End	Earned Dividends
Year Ended February 28, 2007	100	$	155,311
Year Ended February 29, 2008	90		242,126
Year Ended February 28, 2009	78		209,973
Year Ended February 28, 2010	74		189,973
Year Ended February 28, 2011	70		173,707
Year Ended February 29, 2012	70		163,624
Year Ended February 28, 2013	68		161,906
Year Ended February 28, 2014	59		151,323
Three Months Ended May 31, 2014	59		33,461
Total Accumulated Dividends		$	1,481,404


	Common Stock Balance	Valuation
Common stock, Issued and Outstanding, February 28, 2014	55,509,411
Exercise of warrants issued with 12% Subordinated Notes	50,000	$	50
Cashless exercise of warrants issued in connection with financing	1,873,554	$	1,874
Common stock to warrant exchange (Maximilian)	(427,729)	$	(428)
Common stock, Issued and Outstanding, May 31, 2014	57,005,236


	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining
12% Subordinated notes	1,190,000	$0.14	0.50	1,040,000
Warrants issued in 2010 for services	150,000	$0.14	1.00	150,000
Warrants issued in 2012 for debt financing	2,435,517	$0.044	3.50	316,617
Warrants issued for Kentucky oil project	3,498,601	$0.10	2.25	3,498,601
Warrants issued for Kentucky debt financing	2,623,951	$0.10	2.25	2,623,951
Warrants issued for Kentucky debt financing	309,503	$0.214	4.25	309,503
Warrants issued in share-for-warrant exchange	427,729	$0.10	2.25	427,729
	10,635,301			8,366,401


	May 31, 2014		February 28, 2014
Computed at U.S. and state statutory rates (40%)	$	(103,063)	$	(559,340)
Permanent differences		30,163		94,980
Changes in valuation allowance		72,900		464,360
Total	$	-	$	-


	May 31, 2014		February 28, 2014
Deferred tax assets:
Net operating loss carryforwards	$	8,655,176	$	8,344,222
Oil and gas properties		(1,047,396)		(832,267)
Stock based compensation		88,471		87,716
Other		(35,122)		(11,442)
Less valuation allowance		(7,661,129)		(7,588,229)
Total	$	-	$	-


	Three Months Ended May 31, 2014			Three Months Ended May 31, 2013
Project	Revenue		Percentage	Revenue		Percentage
California - East Slopes Project (Oil)	$	430,124	53.1%	$	228,604	100.0%
Kentucky – Twin Bottoms Field (Oil)		373,171	46.0%		-	-
Kentucky – Twin Bottoms Field (Natural Gas)		7,134	0.9%		-	-
	$	810,429	100.0%	$	228,604	100.0%


	Three Months Ended May 31, 2014		Three Months Ended May 31, 2013
Production expenses	$	85,530	$	29,799
Exploration and drilling		6,783		180,957
DD&A		119,977		147,870
G&A		354,819		303,482
Total operating expenses	$	567,109	$	662,108


ISSUER PURCHASES OF EQUITY SECURITIES
Period	(a) Total Number of Shares (or Units) Purchased	(b) Average Price Paid per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
March 1, 2014 – March 31, 2014	0	N/A	0	0
April 1, 2014 – April 30, 2014	0	N/A	0	0
May 1, 2014 – May 31, 2014	427,729	$0(1)	0	0
Total	427,729		0	0