DAYBREAK OIL AND GAS, INC.

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

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). þ Yes ¨ 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 January 10, 2013 the registrant had 48,837,939 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. under the laws of the State of Washington on March 11, 1955, the Company was organized to explore for, acquire, and develop mineral properties in the Western United States. In March 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 the 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, they do not include all of the information and footnote disclosures normally required by accounting principles generally accepted in the United States of America for complete financial statements.

In the opinion of management, all adjustments considered necessary for a fair presentation of the financial statements have been included and such adjustments are of a normal recurring nature. Operating results for the nine months ended November 30, 2012 are not necessarily indicative of the results that may be expected for the fiscal year ending February 28, 2013.

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 29, 2012.

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

The Company’s financial statements for the nine months ended November 30, 2012 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 November 30, 2012 has an accumulated deficit of $25,632,922 and a working capital deficit of $3,467,469 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 a net revenue interest in 11 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 for the Company. Daybreak’s average working interest in these wells is 36.14% and the average net revenue interest is 26.86% in these same wells.

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

In the last few years, the Company has disposed of properties in Alabama, Louisiana and Texas that impeded cash flow and growth in the East Slopes Project. These actions have allowed the Company to move forward with a drilling and exploration program in Kern County, California.

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

On October 31, 2012, the Company finalized a loan with a third party that will fund the Company’s near-term development and exploratory well drilling program at its East Slopes Project in Kern County, California. The Company plans to drill five development wells in the next six months. Refer to the discussion under Note 8 for further information on the loan with the third party.

The Company’s financial statements as of November 30, 2012 do not include any adjustments that might result from the Company’s inability to implement or execute the plans to improve its ability to continue as a going concern.

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 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 our trade accounts receivable at November 30, 2012 and February 29, 2012 as all joint interest owners have a history of paying their obligations.

At the Company’s East Slopes Project, there is only one buyer available for the purchase of oil production. At November 30, 2012, this one customer represented 100% of crude oil sales receivable.

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. The allowance balance at November 30, 2012 and February 29, 2012 for these receivables was $239,000 and $-0-, respectively.

Oil and gas property balances at November 30, 2012 and February 29, 2012 are set forth in the table below.

On October 31, 2012, the Company assigned 10% of its working interest in all oil and gas and leasehold assets to a third party in connection with a funding agreement described in further detail in Note 8 below.

On October 31, 2012, the Company entered into a loan agreement with Maximilian Investors LLC (“Maximilian”) and incurred $321,836 in deferred financing costs associated with the loan. These costs are being amortized on a straight line basis over the term of the loan. Refer to Note 8 – Short-Term and Long-Term Borrowings for further discussion of the Maximilian loan. Amortization expense for the nine months ended November 30, 2012 amounted to $6,705. Unamortized deferred financing costs amounted to $315,131 as of November 30, 2012.

Other assets as of November 30 and February 29, 2012 consisted of the following:

On March 1, 2009, the Company became the operator for its East Slopes Project. Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project’s four earning wells. The Company subsequently sold the same 25% working interest on June 11, 2009. Of the $1.5 million default, $283,843 remains unpaid and is included in the November 30, 2012 accounts payable balance.

On May 18, 2012, the Company entered into a loan agreement with Luberski, Inc. (“Luberski“) as lender and another party as co-borrower, pursuant to which the Company and the co-borrower together borrowed a principal amount of $1,500,000. The Company’s share in the loan amounted to $719,062 with the remainder of the loan proceeds paid to the co-borrower. The loan bore interest at a rate of 5% per month, which interest was to be paid by the co-borrower, had a term of 120 days, and was eligible to be prepaid at any time in part or in full without premium or penalty. The loan called for a minimum interest payment of $150,000. The Company recognized $123,318 in deferred financing fees associated with this loan. Either the Company’s or the co-borrower’s failure to repay the principal at maturity would constitute an event of default and give the lender the right to call the loan due. The loan was a joint and several obligation of the Company and the co-borrower, and was secured by the Company’s currently producing leases in Kern Country, California and certain personal property, accounts receivable and net profits of the co-borrower as well as a personal unconditional guarantee of the loan by the co-borrower’s sole managing member.

On October 31, 2012, the Company paid Luberski $1,500,000 pursuant to the terms of a Settlement and Release Agreement between Luberski and the Company. The payment satisfied the Company’s indebtedness and as a result of the payoff, the Company recognized a loss on settlement of debt of $780,938. Additionally, under terms of the settlement agreement, the Company agreed to allow Luberski to pursue collection of other amounts owed in connection with the loan from the co-borrower before the Company pursues any action against the co-borrower for amounts owed to the Company. The security interest granted by Daybreak in favor of Luberski in the Company’s Kern County, California leases was terminated in connection with the payoff.

On May 22, 2012, the Company paid Well Works, LLC, a Utah limited liability company, $595,744 representing the outstanding principal balance and all interest and fees due in regards to the secured convertible promissory note between the Company and Well Works that was executed on September 17, 2010. The security interest granted by Daybreak in favor of Well Works in the Company’s Kern County, California leases was terminated in connection with the payoff.

On August 21, 2012, the Company’s President and Chief Executive Officer loaned the Company $15,000 to reduce the outstanding balance on the Company’s Line of Credit with UBS Bank. The loan is a non-interest bearing loan. Repayment will be made upon a mutually agreeable date in the future.

On January 31, 2012, the Company issued a $35,100 non-interest bearing note to the Company’s President and Chief Executive Officer. The term of the note provided for repayment on such date as may be agreed to by the Company and its President. Proceeds from the note were used to pay an extension fee related to a loan from a third party.

On June 20, 2011, the Company issued a $200,000 non-interest bearing note to the Company’s President and Chief Executive Officer. The term of the note provided for repayment on or before June 30, 2011, or such date as may be agreed to by the Company and its President. Proceeds from the note were used to meet the escrow requirement on a loan commitment from a third party that was announced in June 2011.

On October 31, 2012, the Company entered into a loan agreement with Maximilian which provides 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 bears annual interest of 18% and a monthly commitment fee of 0.5%. The loan is secured by a perfected first priority security interest in substantially all of the assets of the Company, including the Company’s leases in Kern County, California. The 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 November 30, 2012 amounted to $9,603. Unamortized debt discount amounted to $506,035 as of November 30, 2012.

The Company borrowed an initial amount from the credit facility of $1,650,691 in which $1,500,000 was used to settle the loan with Luberski and the remaining amount was used to pay for the related loan fees and closing costs. Future advances under the facility will primarily be used for oil and gas exploration and development activities. The Company recognized $321,836 in deferred financing costs associated with this loan.

The loan agreement contained customary covenants for loans of such type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property. In the event of a default, all of the Company’s obligations under the loan agreement may be accelerated by the lender, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

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 deferred financing cost and is being amortized over the term of the loan. Amortization expense of deferred financing costs for the three months ended November 30, 2012 was $6,705.

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

In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at the rate of two warrants for every dollar raised through the private placement. The warrants have an exercise price of $0.14 and expire on January 29, 2015. The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $116,557 using the following weighted-average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%. The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method. Amortization expense for the nine months ended November 30, 2012 amounted to $16,574. Unamortized debt discount amounted to $63,509 as of November 30, 2012.

The Company has an $890,000 credit line for working capital purposes with UBS Bank USA (“UBS”) established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of the Company’s President and Chief Executive Officer. At November 30, 2012, the Line of Credit had an outstanding balance of $887,332. Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points. The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

The Company is authorized to issue up to 10,000,000 shares of $0.001 par value preferred stock. The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as “Series A Convertible Preferred Stock” (“Series A Preferred”), with a $0.001 par value. The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s Common Stock. During the nine months ended November 30, 2012, there were 8,000 shares of Series A Preferred converted into 24,000 shares of the Company’s Common Stock by one shareholder. At November 30, 2012, there were 898,565 shares of Series A Preferred issued and outstanding.

Holders of Series A Preferred shares earn a 6% annual cumulative dividend based on the original purchase price of the shares. Accumulated dividends do not bear interest and as of November 30, 2012, accumulated and unpaid dividends amounted to $1,257,150. Dividends may be paid in cash or Common Stock at the discretion of the Company and are payable upon declaration by the Company’s Board of Directors. Dividends are earned until the Series A Preferred is converted to Common Stock. No payment of dividends has been declared as of November 30, 2012.

Dividends earned on the Series A Preferred for each fiscal year since issuance and the nine months ended November 30, 2012 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 48,807,939 shares were issued and outstanding as of November 30, 2012. For the nine months ended November 30, 2012, there were 24,000 shares of the Company’s Common Stock issued due to the conversion of Series A Preferred Stock. However, 3,830 shares of the Company’s Common Stock relating to the Company’s 2009 Restricted Stock and Restricted Stock Unit Plan were returned to the Company during the nine months ended November 30, 2012 as discussed in Note 12 below.

Warrants outstanding and exercisable as of November 30, 2012 are set forth in the table below:

There were no warrants exercised or that expired during the nine months ended November 30, 2012. A total of 2,435,517 warrants were issued for services related to financing the Company received during the nine months ended November 30, 2012. Refer to the discussion under Note 8 for further information on the issued warrants. The outstanding warrants as of November 30, 2012, have a weighted average exercise price of $0.39, a weighted average remaining life of 2.90 years, and an intrinsic value of $43,839.

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

At November 30, 2012, a total of 2,992,340 shares of restricted stock had been awarded and remained outstanding under the 2009 Plan, and 2,615,255 of the shares had fully vested. A total of 1,007,660 Common Stock shares remained available at November 30, 2012 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.

In accordance with the award, on July 16, 2012, 154,335 shares were vested and 1,915 shares were returned to the 2009 Plan.

In accordance with the award, on July 22, 2012, 104,335 shares were vested and 1,915 shares were returned to the 2009 Plan.

For the nine months ended November 30, 2012, the Company recognized compensation expense related to the above restricted stock grants of $20,413. Unamortized compensation expense amounted to $21,658 as of November 30, 2012.

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 as follows:

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

At November 30, 2012, Daybreak had estimated net operating loss carryforwards for federal and state income tax purposes of $17,531,157, which will begin to expire, if unused, beginning in 2024. The valuation allowance increased $708,166 for the nine months ended November 30, 2012 and increased $535,710 for the year ended February 29, 2012. Section 382 of the Internal Revenue Code places annual limitations on the Company’s net operating loss 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 the 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.

On July 16, 2012, the Company received notice that it was named as a defendant along with several other parties and up to 100 unnamed John Does in a civil lawsuit for damages for wrongful death, negligence, negligent entrustment, permissive use liability, negligent hiring and premises liability in the death of woman in rural California. The civil suit, case S-1500-CV-276772 SPC, was filed on May 30, 2012 with a summons issued on June 25, 2012, in Kern County, in the State of California, in the Superior Court of the State of California. While the outcome of this lawsuit cannot be predicted with certainty, management feels the lawsuit is totally without merit and expects to be eventually dismissed as a defendant from this lawsuit. Management does not expect this lawsuit to have a material adverse impact on our financial condition or results of operation.

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 November 30, 2012. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

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 and 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 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 laws, and climate change legislation, 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 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 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.

The following MD&A is management’s assessment of the historical financial condition and operating results of the Company for the three and nine month periods ended November 30, 2012 and November 30, 2011 and of our financial condition as of November 30, 2012, and is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes included elsewhere in this Form 10-Q and in our audited financial statements and notes included in our Annual Report on Form 10-K for the fiscal year ended February 29, 2012. Unless otherwise noted, all of our discussion refers to continuing operations at our East Slopes Project in Kern County, California.

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

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

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

We have a limited operating history of oil and 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 29, 2012 and in Part III, Item 1A. Risk Factors of this 10-Q Report.

The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California. Since January 2009, we have participated in the drilling of 14 oil wells in this project. Eleven of those wells have been successful and have been placed on production. Drilling targets are porous and permeable sandstone reservoirs which exist at depths of 1,200 feet to 4,000 feet.

We currently have production from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations. The Sunday and Bear properties each have four producing oil wells. The Black property is the smallest of all currently oil producing reservoirs, and we will most likely drill only one or two development wells at this property. The Ball and Dyer Creek properties were put on production in late October 2010. 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 oil prospects that have been identified from the seismic data, which we plan to drill in the future. We plan to spend approximately $1,500,000 in new capital investments within the East Slopes Project area in the next 12 months.

In November 2008, we made our initial oil discovery drilling the Sunday #1 well. The well was put on production in January 2009. Production is from the Vedder sand at approximately 2,000 feet. During 2009, we drilled three development wells including one horizontal well. The Sunday reservoir is estimated to be approximately 35 acres in size with the potential for at least three more development wells to be drilled in the future. We have a 37.5% working interest with a 26.1% net revenue interest (“NRI”) in the Sunday #1 well. For both the Sunday #2 and Sunday #3 wells, we have a 33.8% working interest with a 24.3% NRI. We also have a 33.8% working interest with a 27.1% NRI in the Sunday #4H well. We expect to drill at least one development well on this property during the last quarter of our 2012-2013 fiscal year.

In February 2009, we made our second oil discovery drilling the Bear #1 well, which is approximately one mile northwest of our Sunday discovery. The well was put on production in May 2009. Production is from the Vedder sand at approximately 2,200 feet. In December 2009, we began a development program by drilling and completing the Bear #2 well. In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells. The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least five more development wells to be drilled in the future. We have a 37.5% working interest with a 26.1% NRI in each of the Bear wells in this property. Effective June 19, 2012, the royalty owner agreed to a reduced royalty interest on future wells for this property to encourage more drilling. Our new NRI for the next four wells drilled on this property will increase to 31.3%. We expect to drill at least three development wells on this property during the last quarter of our 2012 – 2013 fiscal year.

Our third oil discovery, which was on the Black property, was acquired through a farm-in arrangement with a local operator. The Black property is just south of the Bear property on the same fault system. The Black #1 well was completed and put on production in January 2010. Production is from the Vedder sand at 2,150 feet. The Black reservoir is estimated to be approximately 13 acres in size with the potential for one or two development wells to be drilled in the future. We have a 33.8% working interest with a 26.8% NRI in this property. We expect to drill at least one development well on this property during the last quarter of our 2012 – 2013 fiscal year.

The oil produced from our acreage is considered heavy oil. The oil ranges from 14° to 16° API gravity. All of our oil from the Sunday, Bear and Black properties is processed, stored and sold from the Sunday Central Processing and Storage Facility. The oil must be heated to separate and remove water to prepare it to be sold. We constructed these facilities during the summer and fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines.

The Ball #1-11 well was put on production in late October 2010. Our 3-D seismic data indicates a reservoir approximately 38 acres in size with the potential for at least two development oil wells to be drilled in the future. Oil production from the Ball #1-11 well is being processed at the Dyer Creek production facility. In January 2012, we farmed out to a third party 50% of our working interest covering the Ball and Dyer Creek Fields. In return, the third party will pay Daybreak’s share of the completed well cost on the next Ball well to be drilled. We have a 37.5% working interest with a 31.2% NRI in the Ball #1-11 well. For wells in this field other than the Ball #1-11, we will have a 18.8% working interest with a 15.6% NRI. We anticipate drilling at least one development well at this property after the permitting process has been completed. Drilling will most likely occur in our 2013 – 2014 fiscal year, pending regulatory approval.

The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010. This oil well is producing from the Vedder sand and is located to the north of the Bear property on the same trapping fault. The Dyer Creek property has the potential for at least one development well in the future. Production from the DC67X well is also being processed at the Dyer Creek production facility. We have a 37.5% working interest with a 31.2% NRI in this property. For wells other than the DC67X, we will have a 18.8% working interest with a 15.6% NRI. We anticipate drilling at least one development well at this property during the 2013 – 2014 fiscal year.

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

By utilizing the Sunday and Dyer Creek centralized production facilities our average operating costs have been reduced from over $40 per barrel to under $12 per barrel of oil for the nine months ended November 30, 2012, partially due to certain credits that we received. Without these credits, our average operating costs were approximately $16 per barrel for the nine months ended November 30, 2012. With these centralized facilities and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

This prospect is located in the central portion of our acreage position. The drilling targets are the Vedder and Eocene sands between 2,500 and 4,000 feet deep. We plan to drill an exploratory well in the last quarter of our 2012 – 2013 fiscal year. We estimate that the Breckenridge-Chimney prospect is 60 acres in size with a gross recoverable reserve potential of 1.5 million barrels of oil. 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 Etchegoin and Santa Margarita sands located between 800 and 1,200 feet deep. We drilled an exploratory well on this prospect in December 2011 that was determined to be not viable for commercial production and the well was plugged and abandoned. Utilizing the data received from this well, we expect to drill another exploratory well on this prospect during our 2013 – 2014 fiscal year. The Bull Run wells will require a pilot steam flood and additional production facilities. We estimate that the Bull Run prospect is 70 acres in size with a gross recoverable reserve potential of 873,000 barrels of oil. We have a 37.5% working interest in this prospect.

This prospect is also located in the southern portion of our acreage position. The drilling targets are the Olcese and Eocene sands between 1,000 and 2,000 feet deep. We plan to drill an exploratory well during our 2013 – 2014 fiscal year. We estimate that the Glide Kendall prospect is 200 acres in size with a gross recoverable reserve potential of 1.8 million barrels of oil. We have a 37.5% working interest in this prospect.

This prospect is located in the southern portion of our acreage position. The drilling targets are the Olcese and Etchegoin sands between 1,000 and 2,000 feet deep. We plan to drill an exploratory well in our 2014 – 2015 fiscal year. We estimate that the Sherman Prospect is 100 acres in size with a gross recoverable reserve potential of 300,000 barrels of oil. We have a 37.5% working interest in this prospect.

This prospect is also located in the central portion of our acreage position. The drilling targets are the Vedder and Eocene sands between 2,500 and 4,000 feet deep. We plan to drill an exploratory well in our 2013 – 2014 fiscal year. We estimate that the Tobias prospect is 60 acres in size with a gross recoverable reserve potential of 700,000 barrels of oil. We have a 37.5% working interest in this prospect.

Our net sales volume, revenue and lease operating expenses (“LOE”) by quarter for the East Slopes Project for the last six quarters ended November 30, 2012 are set forth in the following table:

* During the three months ended August 31, 2012, the Company received certain credits from prior years on production expenses related to dehydration expense and property taxes on mineral valuations totaling $34,430, that resulted in lower production expenses than in comparative periods.

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

Results of Operations – Three Months Ended November 30, 2012 compared to the Three Months Ended November 30, 2011

Revenues. Monthly revenues are derived entirely from the sale of our share of oil production. We realized the first revenue from producing wells in our East Slopes Project during February 2009. The price we receive for oil sales is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, OK contracts, less deductions that vary by grade of crude oil sold. Historically, the sale price we receive for California oil sales has been less than the quoted WTI price. However, since March of 2011, we have been receiving a premium for our California oil in comparison to the WTI price. For the three months ended November 30, 2012 the average monthly WTI price was $90.18 and the average monthly sale price was $96.28, resulting in a premium that was 6.8% higher than the average monthly WTI price. For the three months ended November 30, 2011, the average monthly WTI price was $89.67 and the average monthly sale price was $107.79 resulting in a premium that was 20.2% higher than the average monthly WTI price.

For the three months ended November 30, 2012, revenues decreased $60,999 or 21.0% to $229,913 in comparison to revenues of $290,912 for the three months ended November 30, 2011. The average monthly sale price of a barrel of oil for the three months ended November 30, 2012 was $96.28 in comparison to $107.79 for the three months ended November 30, 2011. The decrease of $11.51 or 10.7% in the average monthly sale price of a barrel of oil accounted for $31,086 or 51.0% of the revenue decrease for the three months ended November 30, 2012.

Production for the three months ended November 30, 2012 was from 11 wells for a total of 969 well days in comparison to production from 11 wells with a total of 929 well days for the three months ended November 30, 2011. Due to repair and maintenance issues on the Bear #1 and Bear #3 wells, these wells only produced for 82 and 6 days, respectively, during the three months ended November 30, 2012.

Our net share of production for the three months ended November 30, 2012 was 2,388 barrels of oil in comparison to 2,699 barrels for the three months ended November 30, 2011. The decrease in production of 311barrels or 11.5% for the three months ended November 30, 2012 in comparison to the three months ended November 30, 2011 was due to repair and maintenance issues on the Bear #1 and Bear #3 wells, in addition to the normal production decline in our oil wells. The assignment to a third party of a 10% working interest in our Kern County leases resulted in a reduction of 71 barrels of oil for sale in the three months ended November 30, 2012. The decline in our net share of production accounted for $29,913 or 49.0% of the decrease in revenues for the three months ended November 30, 2012. A table of our revenues for the three months ended November 30, 2012 and 2011 is set forth below:

Operating Expenses. Total operating expenses for the three months ended November 30, 2012 increased by $89,449 or 17.5% to $600,095 in comparison to $510,646 for the three months ended November 30, 2011. Aggregate decreases of $149,551 occurred in the following expense categories: production expenses; exploration and drilling; depreciation, depletion and amortization (“DD&A”) and general and administrative (“G&A”) expenses. These decreases were offset by an allowance for doubtful accounts of $239,000 that resulted in the increase in total operating expenses. Operating expenses for the three months ended November 30, 2012 and 2011 are set forth in the table below:

Production expenses include expenses directly associated with the generation of oil and gas revenues, road maintenance and well workover expenses. For the three months ended November 30, 2012, these expenses decreased by $28,237 or 42.5% to $38,223 in comparison to $66,460 for the three months ended November 30, 2011. Approximately $3,026 of the decrease in production expenses is directly related to the assignment of 10% of our working interest to a third party that supplied long-term financing to the Company. Production expenses are directly related to the number of wells that were producing during the three months ended November 30, 2012 and 2011, our percentage of working interest ownership in those wells. Production expenses represented approximately 6.4% of total operating expenses.

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses. For the three months ended November 30, 2012 these expenses decreased $38,607 or 91.8%, to $3,455 in comparison to $42,062 for the three months ended November 30, 2011. Exploration and drilling expenses for the three months ended November 30, 2012, decreased primarily as a result of the expiration of certain leases that were not renewed. Exploration and drilling expenses represented approximately 0.6% of total operating expenses.

DD&A expense relating to equipment, proven reserves and property costs, along with impairment are another component of operating expenses. DD&A expense decreased $3,158 or 5.6% to $53,424 for the three months ended November 30, 2012 in comparison to $56,582 for the three months ended November 30, 2011 primarily due to a larger proven reserve base used in the DD&A calculation and lower production levels and a lower net working interest. DD&A expense represented approximately 8.9% of total operating expenses.

Bad debt expense for the three months ended November 30, 2012, resulted from the creation of an allowance for doubtful accounts in regards to refunds the Company is due from financing initiatives that have not closed.

G&A expenses include the salaries of six employees, including management. Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as in running a public company. For the three months ended November 30, 2012, G&A expenses decreased $79,549 or 23.0% to $265,993 in comparison to $345,542 for the three months ended November 30, 2011. Significant decreases were realized in accounting and legal ($29,400) and management and employee salaries and stock compensation. Management and employee salaries and stock compensation, which comprised 58.2% of our G&A expense and stock compensation decreased $40,894 or 20.9% for the three months ended November 30, 2012 in comparison to the three months ended November 30, 2011. These categories were responsible for $70,294 in aggregate of the decrease in G&A expenses in comparison to the three months ended November 30, 2011. For the three months ended November 30, 2012 and 2011, we received, as Operator, administrative overhead reimbursement of $9,820 and $18,160, respectively, for the East Slopes Project, which was used to directly offset certain employee salaries. We are continuing a program of reducing all of our G&A costs wherever possible. G&A costs represented 44.3% of total operating expenses for the three months ended November 30, 2012.

Interest income for the three months ended November 30, 2012 decreased $64 to $120 compared to $184 for the three months ended November 30, 2011, due to lower average cash balances.

Interest expense for the three months ended November 30, 2012 decreased $98,471 or 52.2% to $90,297 in comparison to $188,768 for the three months ended November 30, 2011. This decrease was primarily due to larger interest expense for the three months ended November 30, 2011 from a previous loan from a third party.

Loss on settlement of debt for the three months ended November 30, 2012 resulted from the settlement of indebtedness paid to Luberski, Inc. in connection with the borrowing by Daybreak and a co-borrower of $1,500,000 in May 2012, as discussed in Note 8 of the Notes to Unaudited Financial Statements included herein.

Due to the nature of our business, as well as the relative immaturity of the Company, 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 will fluctuate according to the number and percentage ownership of producing wells, as well as the amount of revenues being contributed by such wells. 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 and impairment expense will depend upon the factors cited above and the size of our reserve base. 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.

Results of Operations – Nine Months Ended November 30, 2012 compared to the Nine Months Ended November 30, 2011

Revenues. For the nine months ended November 30, 2012, the average monthly WTI price was $93.22 and the average monthly sale price was $99.00 resulting in a premium that was 6.2% higher than the average monthly WTI price. For the nine months ended November 30, 2011, the average monthly WTI price was $95.80 and the average monthly sale price was $104.88 resulting in a premium that was 9.5% higher than the average monthly WTI price.

Total revenues for the nine months ended November 30, 2012 decreased $260,919 or 26.0% to $742,034 in comparison to revenues of $1,002,953 for the nine months ended November 30, 2011. The average monthly sale price of a barrel of oil for the nine months ended November 30, 2012 was $99.00 in comparison to $104.88 for the nine months ended November 30, 2011. The decrease of $5.88 or 5.6% in the average sale price of a barrel of oil accounted for $56,222 or 21.6% of the revenue decrease for the nine months ended November 30, 2012.

Production for the nine months ended November 30, 2012 was from 11 wells for a total of 2,876 well days in comparison to production from 11 wells with a total of 2,929 well days for the nine months ended November 30, 2011. Our net share of production for the nine months ended November 30, 2012 was 7,495 barrels of oil in comparison to 9,563 barrels for the nine months ended November 30, 2011. The decrease in production of 2,068 barrels or 21.6% was due to repair and maintenance issues on the Bear #1 and Bear #3 wells and the normal production decline in our wells. The decline in our net share of production accounted for $204,697 or 78.5% of the revenue decrease for the nine months ended November 30, 2012. A table of our revenues for the nine months ended November 30, 2012 and 2011 is set forth below:

Operating Expenses. Total operating expenses for the nine months ended November 30, 2012 decreased by $86,113 or 5.7% to $1,433,388 in comparison to $1,519,501 for the nine months ended November 30, 2011. Aggregate decreases of $325,133 occurred in the following expense categories: production expenses; exploration and drilling; depreciation, depletion and amortization (“DD&A”) and general and administrative (“G&A”) expenses. These decreases were offset by an allowance for doubtful accounts of $239,000 that resulted in the net decrease in total operating expenses. Operating expenses for the nine months ended November 30, 2012 and 2011 are set forth in the table below:

Production expenses for the nine months ended November 30, 2012 decreased by $84,448 or 50.8% to $81,855 in comparison to $166,303 for the nine months ended November 30, 2011. Approximately $34,430 of the decrease in production expenses is directly related to recognition of certain credits from prior years that we received relating to dehydration expenses and property taxes on minerals valuation during the nine months ended November 30, 2012. Production expenses are directly related to the number of wells that were producing during the nine months ended November 30, 2012 and 2011, our percentage of working interest ownership in those wells. Production expenses represented approximately 5.7% of total operating expenses.

Exploration and drilling expenses decreased by $57,845 or 59.1% to $40,005 for the nine months ended November 30, 2012, in comparison to $97,850 for the nine months ended November 30, 2011. Exploration and drilling expenses for the nine months ended November 30, 2012, decreased primarily as a result of the expiration of certain leases that were not renewed. Exploration and drilling expenses represented approximately 2.8% of total operating expenses.

DD&A and impairment expenses for the nine months ended November 30, 2012 decreased $38,946 or 18.4% to $172,544 in comparison to $211,490 for the nine months ended November 30, 2011, primarily due to a larger proven reserve base used in the DD&A calculation and lower production levels and a lower net working interest. DD&A expenses represented approximately 12.0% of total operating expenses.

Bad debt expense for the nine months ended November 30, 2012, resulted from the creation of an allowance for doubtful accounts in regards to refunds the Company is due from financing initiatives that have not closed.

G&A expenses include the salaries of six employees, including management. Other items included in our G&A are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, SOX compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as well as in running a public company. G&A expense decreased $143,874, or 13.8% to $899,984 for the nine months ended November 30, 2012 in comparison to $1,043,858 for the nine months ended November 30, 2011. A significant decrease of $102,934 was realized in management and employee salaries and stock compensation for the nine months ended November 30, 2012. Management and employee salaries and stock compensation, which comprised 52.9% of our G&A expense decreased due to the elimination of the Sr. Vice President – Exploration position and also certain stock grants being fully amortized during the nine months ended November 30, 2012. Additionally, legal and accounting expense decreased by $29,332 or 19.1%. For the nine months ended November 30, 2012 and 2011, we received, as Operator, administrative overhead reimbursement of $29,129 and $50,646, respectively, for the East Slopes Project which was used to directly offset certain employee salaries. We are continuing a program of reducing all of our G&A costs wherever possible. G&A costs represented 62.8% of total operating expenses for the nine months ended November 30, 2012.

Interest income for the nine months ended November 30, 2012 decreased $169 or 33.0% to $343 in comparison to $512 for the nine months ended November 30, 2011 due to lower average cash balances.

Interest expense increased 5.0% or $15,271 to $321,481 for the nine months ended November 30, 2012 compared to $306,210 for the nine months ended November 30, 2011. The increase was due to interest expense associated with the loan we received from Maximilian.

Due to the nature of our business, as well as the relative immaturity of the Company, 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 costs will fluctuate according to the number and percentage ownership of producing wells, as well as the amount of revenues being contributed by such wells. 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 and impairment costs will depend upon the factors cited above and the size of our reserve base. G&A costs will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.

Our primary financial resource is our oil reserves base. Our ability to fund a future capital expenditure program is dependent upon the level of 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 $1,500,000 in new capital investment within the East Slopes Project area in the next 12 months. Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures.

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

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

We have repositioned Daybreak to better meet our corporate goals and objectives by disposing of assets that impeded our cash flow and growth in the East Slopes Project. In the last few years, we have disposed of properties in Alabama, Louisiana and Texas. These actions have allowed us to move forward with our drilling and exploration program in Kern County.

The Company’s financial statements for the nine months ended November 30, 2012 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 nine months ended November 30, 2012 have an accumulated deficit of $25,632,922 and a working capital deficit of $3,467,469 which raises substantial doubt about our ability to continue as a going concern.

Changes in our capital resources at November 30, 2012 in comparison to February 29, 2012 are set forth in the table below:

We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations, investments and financing. At November 30, 2012 our cash balance was $-0- and at February 29, 2012 our cash balance was $73,392. The decrease of $73,392 was due to meeting financial commitments from ongoing operations as well as G&A expenses.

Our working capital deficit increased $246,093 to $3,467,469 at November 30, 2012 in comparison to a deficit of $3,221,376 at February 29, 2012. We have not yet been able to generate sufficient cash flow to cover all of our G&A and interest expenses. This is the primary factor for the increase in our working capital deficit. We anticipate an increase in our cash flow from our East Slope operations in Kern County, California during the current fiscal year due to additional drilling that is scheduled to occur.

During the nine months ended November 30, 2012, we reported an operating loss of $691,354 in comparison to an operating loss of $516,548 for the nine months ended November 30, 2011. This increase in the operating loss of $174,806 or 33.8% from the comparative nine months ended November 30, 2011 was primarily due to the recognition of an allowance for doubtful accounts dealing with refunds due the Company in connection with financing transactions that have not yet been completed. Additionally lower revenues of $60,999 resulting from lower prices for oil sold and a decrease in production due to the natural decline in our wells contributed to the operating loss.

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 $1,793,430 was reported for the nine months ended November 30, 2012 in comparison to a net loss of $822,246 for the nine months ended November 30, 2011. The increase in the net loss of $971,184 for the nine months ended November 30, 2012 was due to the recognition of an allowance for doubtful accounts of $239,000 as discussed above and the loss on settlement of debt in regards to the payoff of the Luberski loan from May 2012 of $780,938.

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 receivables, payables or other non-oil property asset account balances. For the nine months ended November 30, 2012, we had an increase in positive cash flow from operating activities of $92,617 or 147.4% to $155,450, in comparison to a positive cash flow of $62,833 for the nine months ended November 30, 2011. This increase in positive cash flow was primarily the result of a decrease in receivables and prepaid expenses and an increase in payables offset by a decrease in our revenue for the nine months ended November 30, 2012. 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 and Other Assets account balances. Cash used in investing activities for the nine months ended November 30, 2012 was $182,142, in comparison to $170,665 for the nine months ended November 30, 2011. This increase of $11,477 or 6.7% in cash used in investing activities was primarily a result of ongoing preparations for our drilling program in California and infrastructure improvements that occurred during the nine months ended November 30, 2012.

Cash flow from financing activities is derived from changes in long-term account balances or in equity account balances excluding retained earnings. For the nine months ended November 30, 2012 cash used in financing activities was $46,700 in comparison to cash provided by financing activities of $275,713 for the nine months ended November 30, 2011. The following is a summary of cash flows provided by, and used in, the Company’s financing activities.

On May 18, 2012, the Company entered into a loan agreement with a Luberski, Inc. (“Luberski“) as lender and another party as co-borrower, pursuant to which the Company and the co-borrower together borrowed a principal amount of $1,500,000. The Company’s share in the loan amounted to $719,062 with the remainder of the loan proceeds paid to the co-borrower. The loan bore interest at a rate of 5% per month, which interest was to be paid by the co-borrower, had a term of 120 days, and was eligible to be prepaid at any time in part or in full without premium or penalty. The loan called for a minimum interest payment of $150,000. The Company recognized $123,318 in deferred financing fees associated with this loan. Either the Company’s or the co-borrower’s failure to repay the principal at maturity would constitute an event of default and give the lender the right to call the loan due. The loan was a joint and several obligation of the Company and the co-borrower, and was secured by the Company’s producing leases in Kern Country, California and certain personal property, accounts receivable and net profits of the co-borrower as well as a personal unconditional guarantee of the loan by the co-borrower’s sole managing member.

On October 31, 2012, the Company paid Luberski, Inc. (“Luberski”) $1,500,000 pursuant to the terms of a Settlement and Release Agreement dated as of October 31, 2012 by and between Luberski Inc. and the Company. The payment satisfied the Company’s indebtedness and as a result of the payoff, the Company recognized a loss on settlement of debt of $780,938. Additionally, under terms of the settlement agreement, the Company agreed to allow Luberski to pursue collection of other amounts owed in connection with the loan from the co-borrower before the Company pursues any action against the co-borrower for amounts owed to the Company. The security interest granted by Daybreak in favor of Luberski in the Company’s Kern County, California leases was terminated in connection with the payoff.

During the year ended February 29, 2012, the Company entered into an $890,000 credit line for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer. At November 30, 2012, the Line of Credit had an outstanding balance of $887,332. Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $16,285 for the nine months ended November 30, 2012. The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

On January 31, 2012, the Company issued a $35,100 non-interest bearing note to the Company’s President and Chief Executive Officer. The term of the note provided for repayment on such other date as may be agreed to by the Company and its President. Proceeds from the note were used to pay an extension fee related to a loan from a third party.

On June 20, 2011, we issued a $200,000 non-interest bearing note to our President and Chief Executive Officer. The term of the note provided for repayment on or before June 30, 2011, or such other date as may be agreed to by Daybreak and our President. Proceeds from the note were used to meet the escrow requirement on a loan commitment from a third party that was announced in June 2011. The escrow requirement amount of $200,000 is reflected as an account receivable on the Company’s Balance Sheets and will be refunded to the Company upon closing of funding from the third party.

On October 31, 2012, the Company entered into a loan agreement with Maximilian which provides 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 bears annual interest of 18% and a monthly commitment fee of 0.5%. The loan is secured by a perfected first priority security interest in substantially all of the assets of the Company, including the Company’s leases in Kern County, California. The 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 amortized over the term of the loan. Amortization expense for the three months ended November 30, 2012 amounted to $9,603. Unamortized debt discount amounted to $506,035 as of November 30, 2012.

The loan agreement contained customary covenants for loans of such type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property. In the event of a default, all of the Company’s obligations under the loan agreement may be accelerated by the Lender, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

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 deferred financing cost and is being amortized over the term of the loan. Amortization expense for the three months ended November 30, 2012 was $6,705.

The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a March 2010 private placement, resulted in $595,000 in gross proceeds to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th. The note principal is payable in full at the expiration of the term of the Notes, which is January 29, 2015. In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement. The warrants have an exercise price of $0.14 and expire on January 29, 2015. The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $116,557 using the following weighted average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%. The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method. Amortization expense for the nine months ended November 30, 2012 amounted to $10,673. Unamortized debt discount amounted to $69,411 as of November 30, 2012.

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

On April 6, 2009, the Board approved the 2009 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 stock and restricted stock unit awards. Subject to adjustment, the total number of shares of Daybreak’s common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.

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.

In accordance with the award, on July 16, 2012, 154,335 shares were vested and 1,915 shares were returned to the 2009 Plan.

In accordance with the award, on July 22, 2012, 104,335 shares were vested and 1,915 shares were returned to the 2009 Plan.

We are continuing to execute the Company’s business plan of developing Daybreak’s acreage position in Kern County, California. The Company will continue to focus our efforts on drilling both development and exploration wells in the current fiscal year as cash flow and funding allow. Along with stable oil prices, the increase in production from new wells will increase our net cash flow from operations.

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

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 29, 2012.

As of November 30, 2012, 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, November 30, 2012, 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 November 30, 2012.

There have not been any changes in the Company’s internal control over financial reporting during the three months ended November 30, 2012 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.

The following risk factors could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements and update the Risk Factors included in our Annual Report on Form 10-K for the fiscal year ended February 29, 2012. In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements. Except as set forth below, there have been no material changes to the risks previously disclosed in our “Risk Factors” described in Part 1, Item 1A, of the Annual report on Form 10-K for the year ended February 29, 2012, as filed with the U.S. Securities and Exchange Commission on May 25, 2012, and available at www.sec.gov.

The amount of our outstanding indebtedness continues to increase and our ability to make payments towards such indebtedness could have adverse consequences on future operations.

Our outstanding indebtedness at November 30, 2012 was approximately $5,449,178, which was comprised of a variety of short-term and long-term borrowings and related party notes and payables; a line of credit, trade payables and 12% Subordinated Notes. The level of indebtedness affects our operations in a number of ways. We will need to use a portion of our cash flow to pay principal and interest and meet payables commitments, which will reduce the amount of funds we will have available to finance our operations. This lack of funds could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate and could limit our ability to make funds available for other purposes, such as future exploration, development or acquisition activities. Our ability to meet our debt service obligations and reduce our total indebtedness will depend upon our future performance. Our future performance, in turn, is dependent upon many factors that are beyond our control such as general economic, financial and business conditions. We cannot guarantee that our future performance will not be adversely affected by such economic conditions and financial, business and other factors.

The Maximilian loan referenced in the MD&A under the “Cash Flow from Financing Activities” section of this 10-Q report is secured by a perfected, first priority security interest in substantially all of the assets of the Company, including our leases in the Company’s East Slopes Project. If the lender were to institute foreclosure proceedings upon our leases securing this loan, the Company would lose all of its primary leases.

On July 25, 2012, the Company issued 24,000 shares of Common Stock to an accredited investor pursuant to the terms of a Daybreak private placement offering held in July 2006, during which the accredited investor received shares of Daybreak Series A Convertible Preferred Stock, the terms of which are disclosed in the Company’s Amended and Restated Articles of Incorporation. Each share of Series A Convertible Preferred Stock can be converted by the shareholder at any time into three shares of the Company’s Common Stock. Pursuant to the terms of the Series A Convertible Preferred Stock, the Common Stock was issued to the accredited investor upon the conversion of 8,000 shares of Series A Convertible Preferred Stock by the accredited investor, in reliance on an exemption from registration provided by Section 3(a)(9) of the Securities Act of 1933 relating to securities exchanged by the issuer with its existing security holders exclusively where no commission or other remuneration is paid or given directly or indirectly for soliciting such exchange.

As of November 30, 2012, 31 accredited investors have converted 501,200 Series A Convertible Preferred shares into 1,503,600 shares of Daybreak Common Stock. At November 30, 2012, there were 898,565 Series A Convertible Preferred shares outstanding, held by accredited investors that had not been converted into the Company’s Common Stock. The table below shows the conversions of Series A Convertible Preferred that have occurred since the Series A Convertible Preferred was first issued in July 2006.

Loan and Security Agreement dated as of October 31, 2012, by and between Daybreak Oil and Gas, Inc., as borrower, and Maximilian Investors LLC, as lender

Promissory Note dated as of October 31, 2012, by Daybreak Oil and Gas, Inc. in favor of Maximilian Investors LLC

Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of October 31, 2012, executed by Daybreak Oil and Gas, Inc., in favor of Maximilian Investors LLC

Assignment and Assumption Agreement dated as of October 31, 2012, by and between Daybreak Oil and Gas, Inc., as assignor, and Maximilian Investors LLC, as assignee

Settlement and Release Agreement dated as of October 31, 2012, by and be and between Daybreak Oil and Gas, Inc. and Luberski Inc.

Promissory Note, dated January 31, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland

Promissory Note, August 21, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland

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 exhibit to Form 8-K on November 5, 2012 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: January 11, 2013


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 November 30, 2012 and February 29, 2012 (Unaudited)	3
	Statements of Operations for the Three and Nine Months Ended November 30, 2012 and November 30, 2011 (Unaudited)	4
	Statements of Cash Flows for the Nine Months Ended November 30, 2012 and November 30, 2011 (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	29
ITEM 4.	CONTROLS AND PROCEDURES	29

	PART II - OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	30
ITEM 1A.	RISK FACTORS	30
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	31
ITEM 6.	EXHIBITS	32
SIGNATURES		3 3


	As of November 30,		As of February 29,
	2012		2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	73,392
Accounts receivable:
Oil and gas sales		123,802		192,639
Joint interest participants		85,548		92,220
Loan commitment refund and other receivables, net of allowance for doubtful accounts of $239,000 and $-0-, respectively		14,863		223,750
Prepaid expenses and other current assets		38,701		44,777
Total current assets		262,914		626,778
OIL AND GAS PROPERTIES, net, successful efforts method
Proved properties		1,130,306		1,634,545
Unproved properties		358,165		438,640
PRODUCTION REVENUE RECEIVABLE		350,000		350,000
OTHER ASSETS, net		420,980		105,506
Total assets	$	2,522,365	$	3,155,469

CURRENT LIABILITIES:
Bank overdraft	$	29,220	$	-
Accounts payable and other accrued liabilities		1,846,859		1,663,303
Accounts payable - related parties		692,811		497,315
Accrued interest		24,061		418,531
Note payable		-		150,000
Notes payable - related party		250,100		235,100
Line of Credit		887,332		883,905
Total current liabilities		3,730,383		3,848,154
LONG TERM LIABILITIES:
Notes payable, net of discount of $36,595 and $46,149 respectively		308,405		298,851
Note payable - related party, net of discount of $26,914 and $33,934 respectively		223,086		216,066
Long term debt, net of discount of $506,035 and $-0-, respectively		1,144,656		-
Asset retirement obligation		42,648		44,107
Total liabilities		5,449,178		4,407,178
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; 898,565 and 906,565 shares issued and outstanding, respectively		899		907
Common stock- 200,000,000 shares authorized; $0.001 par value, 48,807,939 and 48,787,769 shares issued and outstanding, respectively		48,808		48,788
Additional paid-in capital		22,656,402		22,538,089
Accumulated deficit		(25,632,922)		(23,839,493)
Total stockholders’ deficit		(2,926,813)		(1,251,709)
Total liabilities and stockholders' deficit	$	2,522,365	$	3,155,469


	For the Three Months Ended November 30,				For the Nine Months Ended November 30,
	2012		2011		2012		2011
REVENUE:
Oil and gas sales	$	229,913	$	290,912	$	742,034	$	1,002,953

OPERATING EXPENSES:
Production expenses		38,223		66,460		81,855		166,303
Exploration and drilling		3,455		42,062		40,005		97,850
Depreciation, depletion, amortization, and impairment		53,424		56,582		172,544		211,490
Bad debt expense		239,000		-		239,000		-
General and administrative		265,993		345,542		899,984		1,043,858
Total operating expenses		600,095		510,646		1,433,388		1,519,501
OPERATING LOSS		(370,182)		(219,734)		(691,354)		(516,548)

OTHER INCOME (EXPENSE):
Interest income		120		184		343		512
Interest expense		(90,297)		(188,768)		(321,481)		(306,210)
Loss on settlement of debt		(780,938)		-		(780,938)		-
Total other income (expense)		(871,115)		(188,584)		(1,102,076)		(305,698)

NET LOSS		(1,241,297)		(408,318)		(1,793,430)		(822,246)

Cumulative convertible preferred stock dividend requirement		(40,323)		(40,664)		(122,436)		(122,942)

NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(1,281,620)	$	(448,982)	$	(1,915,866)	$	(945,188)

NET LOSS PER COMMON SHARE - Basic and diluted	$	(0.03)	$	(0.01)	$	(0.04)	$	(0.02)

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - Basic and diluted		48,807,939		48,787,769		48,797,555		48,790,290


	Nine Months Ended November 30,
	2012		2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,793,430)	$	(822,246)
Adjustments to reconcile net loss to net cash used in operating activities:
Loss on settlement of debt		780,938		-
Bad debt expense		239,000		-
Stock compensation		20,413		68,414
Depreciation, depletion, and impairment expense		172,544		211,490
Amortization of debt discount		26,177		43,955
Amortization of loan origination fees		123,318		11,875
Amortization of deferred financing costs		6,705		-
Non-cash interest income		(343)		(476)
Changes in assets and liabilities:
Accounts receivable - oil and gas sales		68,837		5,882
Accounts receivable - joint interest participants		6,672		65,786
Accounts receivable - other		(30,113)		68,745
Prepaid expenses and other current assets		31,076		(129,480)
Accounts payable and other accrued liabilities		232,458		133,618
Accounts payable - related parties		195,497		224,024
Accrued interest		75,701		181,246
Net cash provided by operating activities		155,450		62,833

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(182,142)		(170,665)
Net cash used in investing activities		(182,142)		(170,665)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of note payable		-		(600,000)
Proceeds from issuance of notes payable - related party		-		200,000
Payment of deferred financing fees		(40,700)		-
Proceeds from (payments to) line of credit		(6,000)		875,713
Payment to escrow for loan commitment		-		(200,000)
Net cash (used in) provided by financing activities		(46,700)		275,713

NET DECREASE IN CASH AND CASH EQUIVALENTS		(73,392)		167,881
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		73,392		57,380
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	-	$	225,261

CASH PAID FOR:
Interest	$	535,324	$	43,509
Income taxes	$	-	$	-

SUPPLEMENTAL CASH FLOW INFORMATION:
Unpaid additions to oil and gas properties	$	26,050	$	38,148
Interest converted to principal	$	24,427	$	-
Note paid directly from proceeds of note	$	150,000	$	-
Note paid directly to accrued interest and fees	$	445,744	$	-
Note paid directly to pre-paid loan fees	$	123,318	$	-
Debt discount for assignment of working interest		515,638		-
Related party note paid directly to line of credit	$	15,000	$	-
ARO asset and liability reduction due to assignment of working interest	$	4,702	$	-
Deferred financing fees paid directly from proceeds of long-term debt	$	150,691	$	-
Warrants issued for deferred financing fees	$	98,084	$	-
Unpaid deferred financing fees	$	57,361	$	-
Changes to estimates of asset retirement obligation	$	-	$	605
Conversion of preferred stock to common stock	$	24	$	-
Repurchase of stock through payment of payroll taxes	$	173	$	383
Discount on notes payable - Long term	$	-	$	13,850
Discount on notes payable - Short term	$	-	$	30,105


	November 30, 2012		February 29, 2012
Proved leasehold costs	$	2,236	$	2,254
Unproved leasehold costs		361,864		438,640
Costs of wells and development		290,424		470,653
Capitalized exploratory well costs		2,162,618		2,316,305
Capitalized asset retirement costs		26,843		31,545
Total cost of oil and gas properties		2,843,985		3,259,397
Accumulated depletion, depreciation, amortization and impairment		(1,355,514)		(1,186,212)
Net Oil and Gas Properties	$	1,488,471	$	2,073,185


	November 30, 2012		February 29, 2012
Certificate of Deposit (Pledged as Operator Bond in California)	$	105,849	$	105,506
Deferred financing costs, net of amortization of $6,705 and $-0-, respectively		315,131		-0-
	$	420,980	$	105,506


Fiscal Year Ended	Shareholders at Period End	Accumulated Dividends
February 28, 2007	100	$	155,311
February 29, 2008	90		242,126
February 28, 2009	78		209,973
February 28, 2010	74		189,973
February 28, 2011	70		173,707
February 29, 2012	70		163,624
Nine Months Ended November 30, 2012	69		122,436
Total Accumulated Dividends		$	1,257,150


	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining

Placement agent warrants - Spring 2006 Private Placement	802,721	$0.75	0.50	802,721
Placement agent warrants - Spring 2006 Private Placement	401,361	$2.00	0.50	401,361
Placement agent warrants - July 2006 Private Placement	419,930	$1.00	0.75	419,930
12% Subordinated Note warrants	1,190,000	$0.14	2.00	1,190,000
Warrants issued in 2010 for services	150,000	$0.14	2.50	150,000
Warrants issued in 2012 for services	2,435,517	$0.044	4.92	2,435,517
	5,399,529			5,399,529


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	⁽³⁾	-0-	-0-
7/16/2009	25,000	3 Years	25,000	⁽⁴⁾	-0-	-0-
7/16/2009	625,000	4 Years	464,920	⁽⁵⁾	3,830	156,250
7/22/2010	25,000	3 Years	16,665	⁽⁶⁾	-0-	8,335
7/22/2010	425,000	4 Years	208,670	⁽⁷⁾	3,830	212,500
	3,000,000		2,615,255	⁽¹⁾	7,660	377,085


	November 30, 2012		February 29, 2012
Computed at U.S. and state statutory rates (40%)	$	(717,373)	$	(573,035)
Permanent differences		9,207		37,325
Changes in valuation allowance		708,166		535,710
Total	$	-0-	$	-0-


	November 30, 2012		February 29, 2012
Deferred tax assets:
Net operating loss carryforwards	$	7,012,463	$	6,319,866
Oil and gas properties		(139,943)		(147,148)
Stock based compensation		80,256		71,891
Less valuation allowance		(6,952,776)		(6,244,609)
Total	$	-0-	$	-0-


	Three Months Ended
	November 30, 2012		August 31, 2012			May 31, 2012		February 29, 2012		November 30, 2011		August 31, 2011
Sales (Barrels)		2,388		2,669			2,438		3,009		2,699		3,362
Revenue	$	229,913	$	249,149		$	262,973	$	311,171	$	290,912	$	331,684
LOE	$	38,223	$	1,939	*	$	41,693	$	74,076	$	59,138	$	52,466

Average Sales Price	$	96.28	$	93.34		$	107.88	$	103.43	$	107.79	$	98.66

Average LOE	$	16.01	$	0.73		$	17.10	$	25.36	$	24.62	$	17.57


	Three Months Ended November 30, 2012		Three Months Ended November 30, 2011
California – East Slopes Project	$	229,913	$	290,912
Total Revenue	$	229,913	$	290,912


	November 30, 2012		February 29, 2012		Increase (Decrease)		Percentage Change
Cash	$	-	$	73,392	$	(73,392)	(100.0%)
Current Assets	$	262,914	$	626,778	$	(363,864)	(58.1%)
Total Assets	$	2,522,365	$	3,155,469	$	(633,104)	(20.1%)
Current Liabilities	$	3,730,383	$	3,848,154	$	(117,771)	(3.1%)
Total Liabilities	$	5,449,178	$	4,407,178	$	1,042,000	23.6%
Working Capital	$	(3,467,469)	$	(3,221,376)	$	(246,093)	(7.6%)


	Nine Months Ended November 30, 2012		Nine Months Ended November 30, 2011
California – East Slopes Project	$	742,034	$	1,002,953
Total Revenues	$	742,034	$	1,002,953


	Nine Months November 30, 2012		Nine Months November 30, 2011		Increase (Decrease)		Percentage Change
Net cash provided by operating activities	$	155,450	$	62,833	$	92,617	147.4%
Net cash used in investing activities	$	(182,142)	$	(170,665)	$	(11,477)	(6.7%)
Net cash (used in) provided by financing activities	$	(46,700)	$	275,713	$	(322,413)	(116.9%)


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	-0-	-0-	-0-
Nine Months Ended November 30, 2012	8,000	24,000	1
Totals	501,200	1,503,600	31