Daybreak Oil and Gas, Inc.

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

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

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

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

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

At October 12, 2017 the registrant had 51,532,364 outstanding shares of $0.001 par value common stock.

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

Originally incorporated as Daybreak Uranium, Inc., (“Daybreak Uranium”) under the laws of the State of Washington on March 11, 1955, Daybreak Uranium was organized to explore for, acquire, and develop mineral properties in the Western United States. During 2005, management of the Company decided to enter the crude oil and natural 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 crude oil and natural gas production is sold under contracts which are market-sensitive. Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, crude 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 crude oil and natural gas, the establishment of and compliance with production quotas by crude 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 six months ended August 31, 2017 are not necessarily indicative of the results that may be expected for the fiscal year ending February 28, 2018.

These financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended February 28, 2017.

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 crude oil and natural gas properties to determine the amount of any impairment of crude oil and natural gas properties;

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

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

The Company’s financial statements for the six months ended August 31, 2017 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 crude oil and natural gas exploration industry and as of August 31, 2017 has an accumulated deficit of $37,315,826 and a working capital deficit of $14,477,866 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 (“NRI”) in 20 producing crude oil wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”). The revenue from these wells has created a steady and reliable source of revenue. The Company’s average working interest (“WI”) in these wells is 36.6% and the NRI is 28.4% for these same wells.

The Company anticipates its revenue will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project in California and as our exploratory drilling project begins in Michigan. However, given the current decline and instability in hydrocarbon prices, the timing of any drilling activity in California and Michigan will be dependent on a sustained improvement in hydrocarbon prices and a successful refinancing or restructuring of the Company’s credit facility.

The Company believes that our liquidity will improve when there is a sustained improvement in hydrocarbon prices. Daybreak’s sources of funds in the past have included the debt or equity markets and the sale of assets. While the Company has experienced revenue growth, which has resulted in positive cash flow from its crude oil and natural gas properties, it has not yet established a positive cash flow on a company-wide basis. It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future. However, the Company cannot offer any assurance that it will be successful in executing the aforementioned plans to continue as a going concern.

Daybreak’s financial statements as of August 31, 2017 do not include any adjustments that might result from the inability to implement or execute the Company’s plans to improve its ability to continue as a going concern.

In May 2014, the FASB issued ASC updated No. 2014-09, Revenue from Contracts with Customers (Topic 606 (ASU 2014-09). Under the amendments in this update, recognition of revenue occurs when a customer obtains control of promised goods or services in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the new standard requires that reporting companies disclose the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2017. Early adoption is not permitted. The new standard is required to be applied either retrospectively to each prior reporting period presented, or retrospectively with the cumulative effect of applying the update recognized at the date of initial application. The Company is still in the process of evaluating the new standard against its existing accounting policies.

Substantially all of the Company’s trade accounts receivable result from crude oil and natural gas sales or joint interest billings to its working interest partners. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions including lower crude oil prices as well as other related factors. Trade accounts receivable are not collateralized.

At the Company’s East Slopes project in California there is only one buyer available for the purchase of all crude oil production. The Company has no natural gas production in California. At August 31, 2017 and February 28, 2017 this one customer represented 100.0% of crude oil sales receivable. If this buyer is unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its crude oil production.

The Company’s accounts receivable balances from California crude oil sales of $84,282 and $83,405 at August 31, 2017 and February 28, 2017, respectively were from one customer, Plains Marketing. Crude oil sales receivables balances of $84,282 and $83,405 at August 31, 2017 and February 28, 2017 represent crude oil sales that occurred in August and February 2017, respectively.

Joint interest participant receivables balances of $60,159 and $55,154 at August 31, 2017 and February 28, 2017, respectively represent amounts due from working interest partners in California, where the Company is the Operator. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at August 31, 2017 and February 28, 2017 as the joint interest owners have a history of paying their obligations.

At August 31, 2017, the Company owed our principal lender, Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in these notes to the financial statements as “Maximilian”), an aggregate $9,090,094 or approximately 85.0% of the Company’s total debt. Since January of 2016, a series of waivers on a quarterly basis were granted by Maximilian for the principal and interest payments that had not been made. The Company did not receive a waiver for the months of August through October 2017 and is currently considered to be in default on its credit facility loan with Maximilian. As a result of this concentration of debt, the Company may be susceptible to any economic challenges faced by Maximilian. For further information on the Maximilian credit facility and loan balances refer to Note 9.

Crude oil and natural gas property balances at August 31, 2017 and February 28, 2017 are set forth in the table below.

During the six months ended August 31, 2017, a $51,486 reduction in unproved crude oil and natural gas properties was recorded to properly recognize geologic and geophysical lease expenses associated with our Michigan exploratory joint drilling project development.

On March 1, 2009, the Company became the operator for its East Slopes Project. Additionally, the Company at that time assumed certain original partners’ default liability of approximately $1.5 million representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning well program. The Company subsequently sold the same 25% working interest on June 11, 2009. Of the $1.5 million default, $244,849 remains unpaid and is included in both the August 31, 2017 and February 28, 2017 accounts payable balances.

The August 31, 2017 and February 28, 2017 accounts payable – related parties balances of approximately $1.5 million and $1.4 million respectively, were comprised primarily of deferred salaries of the Company’s Executive Officers and certain employees; directors’ fees; expense reimbursements; and deferred interest payments on a 12% Subordinated Notes owed to the Company’s President and Chief Executive Officer. Payment of these deferred items has been delayed until the Company’s cash flow situation improves.

During the six months ended August 31, 2017 the credit adjusted risk free rate (CARFR) percentage used in the calculation of the asset retirement obligation (“ARO”) was revised from 10% to 15% to more accurately reflect the Company’s current cost of funds. This revision resulted in a $40,108 reduction in the ARO liability balance shown on the Company’s Balance Sheet at August 31, 2017. The ARO balance at August 31, 2017 is set forth in the table below:

As of August 31, 2017 and February 28, 2017, the Company had a loan balance of $250,100 with the Company’s Chairman, President and Chief Executive Officer which were obtained during the years ended February 29, 2012 and February 28, 2013, that was used for a variety of corporate purposes including an escrow requirement on a loan commitment; maturity extension fees on third party loans; and a reduction of principal on the Company’s credit line with UBS Bank. These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.

The Company has an existing $890,000 line of credit for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer. At August 31, 2017 and February 28, 2017, the Line of Credit had an outstanding balance of $804,638 and $817,622, respectively . On July 10, 2017 a portion of the outstanding credit line balance, $700,000, was converted to a 24 month fixed term annual interest rate of 3.244% with interest payable monthly. The remaining balance of the credit line has a stated reference rate of 0.249% + 337.5 basis points with interest payable monthly. Interest was $17,015 and $17,140 for the six months ended August 31, 2017 and 2016, respectively. The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

On October 31, 2012, the Company entered into a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in these notes to the financial statements as “Maximilian”), which provided for a revolving credit facility of up to $20 million, that matured on October 31, 2016, with a minimum commitment of $2.5 million. On October 31, 2016 through the Fourth Amendment to the Amended and Restated Loan and Security Agreement, the maturity date of the loan was changed to February 28, 2020.

In connection with the Company’s acquisition of a working interest from App Energy, LLC, a Kentucky limited liability company (“App Energy”) in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013. The amendment increased the amount of the credit facility to $90 million and reduced the annual interest rate to 12%. The Company evaluated the amendment of the revolving credit facility under ASC 470-50-40 and determined that the Company’s borrowing capacity under the amended loan agreement exceeded its borrowing capacity under the old loan agreement. Consequently, the unamortized discount and deferred financing costs as of the date of amendment are being amortized over the term of the amended loan agreement.

On October 31, 2016, the Company entered into a Fourth Amendment to the Amended and Restated Loan and Security Agreement with Maximilian, which amended the Company’s loan agreement with Maximilian (the “Restructuring Agreement”). Pursuant to the Restructuring Agreement, in exchange for the proceeds it received from the Kentucky Sale, Maximilian and the Company have agreed to a commitment by Maximilian to advance up to $250,000 in financing to the Company over the following six month period and the pursuit of the Michigan exploratory joint drilling project using the $250,000 set aside from the Kentucky Sale.

As a result of the decline in hydrocarbon prices that started in June of 2014, the Company has been unable to make any type of interest or principal payments required under the amended terms of its credit facility with Maximilian since December of 2015. Under the terms of the Restructuring Amendment all unpaid interest is currently being accrued. Since January of 2016, a series of waivers on a quarterly basis were granted by Maximilian for the principal and interest payments that had not been made. The Company did not receive a waiver for the months of August through October 2017 and is currently considered to be in default on its credit facility. Maximilian is continuing to work with the Company in restructuring the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue. Further, our lender is under no obligation to advance us any additional funding. A change of control or management of our lender, among other reasons, could also result in our loan being called due and payable.

During the six months ended August 31, 2017, we received $35,000 in advances under the terms of the credit facility.

As of August 31, 2017, the Company had received $94,650 in aggregate from multiple advances starting in the year ended February 28, 2017 from Maximilian under a separate promissory note agreement dated January 17, 2017 and amended on February 10, 2017 regarding the development of an exploratory joint drilling project in Michigan. Advances under this agreement are subject to a 5% (five percent) per annum interest rate. If a well that the Company elects to participate in is scheduled to be spudded at the Michigan exploratory joint drilling project on or before December 31, 2017, then the advances under the promissory note must be repaid in full upon the earlier of (a) the time that is ten days prior to the first well being spudded on the Michigan exploratory joint drilling project or (b) December 31, 2017. If there is not a well scheduled to be spudded at the Michigan exploratory joint drilling project on or before December 31, 2017 that the Company elects to participate in, then the Company will assign to Maximilian its working interest in the Michigan exploratory joint drilling project, in full payment and satisfaction of the advances under the promissory note. Advances under the promissory note may be prepaid at any time without penalty. In the event of a default of any of the Company’s obligations under the promissory note, the amounts due may be called immediately due and payable at Maximilian’s option.

In accordance with the guidance found in ASC-470-10-45, the entire balance of the Maximilian loan is presented under the current liabilities section of the balance sheets. In accordance with the guidance found in ASC 835-30 the net amount of the deferred finance costs associated with the credit facility are included with the debt discount as a reduction of the loan balance shown on the Balance Sheets as of August 31, 2017 and February 28, 2017, respectively.

Current debt balances at August 31, 2017 and February 28, 2017 are set forth in the table below:

Deferred financing costs at August 31, 2017 and February 28, 2017 relating to the original and the amended credit facility with Maximilian, are set forth in the table below:

Deferred financing cost balances of $37,764 and $238,598 at August 31, 2017 and February 28, 2017, respectively includes the fair value of common shares and warrants issued to Maximilian and to a third party that assisted in both the original and the amended financing transactions. The unamortized deferred financing costs are netted against debt in the balance sheets. Amortization expense of deferred financing costs was $200,834 and $215,047 for the six months ended August 31, 2017 and 2016, respectively.

The Company’s debt obligations, pursuant to the above mentioned credit facility loan agreement and promissory notes entered into by and between Maximilian and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and two mortgages; one covering its leases in California and the other covering its leases in Michigan. On July 13, 2017, in connection with receiving the latest payment waiver from Maximilian, the California and Michigan properties were cross-collateralized for the credit facility loan and the promissory note.

The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a January 2010 private placement offering to accredited investors, resulted in $595,000 in gross proceeds (of which $250,000 was from a related party) to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th. On January 29, 2015, the Company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes for an additional two years to January 29, 2017. Effective January 29, 2017, the maturity date of the Notes and the expiration date of the warrants that were issued in conjunction with the Notes were extended for an additional two years to January 29, 2019. There are ten noteholders, holding 980,000 warrants, who have not yet exercised their warrants. The exercise price of the associated warrants was lowered from $0.14 to $0.07 as a part of the Note maturity extension. The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes. The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes. The Black-Scholes valuation encompassed the following weighted average assumptions: a risk free interest rate of 1.22%; volatility of 378.73%; and dividend yield of 0.0%. 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, 2018. Amortization expense was $7,269 and $-0- at August 31, 2017 and 2016, respectively. The unamortized debt discount at August 31, 2017 and February 28, 2017 was $20,595 and 27,864, respectively.

12% Note balances at August 31, 2017 and February 28, 2017 are set forth in the table below:

12% Note balances – related parties at August 31, 2017 and February 28, 2017 are set forth in the table below:

Effective October 31, 2016, the Company finalized the sale of its interest in the Twin Bottoms Field in Kentucky. The sale included Daybreak’s working interest in 14 producing horizontal crude oil wells, its mineral rights, its lease acreage and infrastructure. In accordance with the guidance provided in ASC 205-20, the Company concluded that this sale qualified for presentation as discontinued operations. The Company has no ongoing or future plans to be involved in this segment of its crude oil and natural gas projects. Prior period income statement balances applicable to the Twin Bottoms Field in Kentucky have been reclassified and are included under the Discontinued Operations caption in the statements of operations for August 31, 2016.

Operating income, interest income, operating expenses and interest expense related to Kentucky for the six months ended August 31, 2017 and August 31, 2016 are set forth in the tables below.

The statements of cash flows include certain significant non-cash operating items for discontinued operations in Kentucky during the six months ended August 31, 2016, comprised of depreciation, depletion and amortization (“DD&A”) expense of $96,016 and debt modification fees of $154,883. Cash flow used in investing items related to discontinued operations in Kentucky for the six months ended August 31, 2016 was $1,010.

The Company is authorized to issue up to 10,000,000 shares of preferred stock with a par value of $0.001. The Company’s preferred stock may be entitled to preference over the common stock with respect to the distribution of assets of the Company in the event of liquidation, dissolution, or winding-up of the Company, whether voluntarily or involuntarily, or in the event of any other distribution of assets of the Company among its shareholders for the purpose of winding-up its affairs. The authorized but unissued shares of preferred stock may be divided into and issued in designated series from time to time by one or more resolutions adopted by the Board of Directors. The directors in their sole discretion shall have the power to determine the relative powers, preferences, and rights of each series of preferred stock.

The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as Series A Convertible Preferred Stock (“Series A Preferred”), with a $0.001 par value. At August 31, 2017 and February 28, 2017, there were 709,568 and 724,565 shares issued and outstanding, respectively, that had not been converted into the Company’s common stock. As of August 31, 2017, there are 44 accredited investors who have converted 690,197 Series A Preferred shares into 2,070,591 shares of Daybreak common stock.

The conversions of Series A Preferred that have occurred since the Series A Preferred was first issued in July 2006 is set forth in the table below.

Holders of Series A Preferred shall accrue dividends, in the amount of 6% of the original purchase price per annum. Dividends may be paid in cash or common stock at the discretion of the Company. Dividends are cumulative whether or not in any dividend period or periods we have assets legally available for the payment of such dividends. Accumulations of dividends on Series A Preferred do not bear interest. Dividends are payable upon declaration by the Board of Directors. As of August 31, 2017 no dividends have been declared or paid. Dividends earned since issuance for each fiscal year and the six months ended August 31, 2017 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 51,532,364 and 51,487,373 shares were issued and outstanding as of August 31, 2017 and February 28, 2017, respectively. For the six months ended August 31, 2017, there was one shareholder of Series A Preferred that converted 14,997 shares to 44,991 shares of the Company’s common stock. Issuances of common stock since February 28, 2017 are set forth in the table below:

Warrants outstanding and exercisable as of August 31, 2017 are set forth in the table below:

Warrant activity for the six months ended August 31, 2017 is set forth in the table below:

During the six months ended August 31, 2017 there were no warrants issued or exercised. Additionally, there were no warrants that expired. As of August 31, 2017, the remaining outstanding warrants have a weighted average exercise price of $0.05, a weighted average remaining life of 1.02 years, and an intrinsic value of -$0-.

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

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

At August 31, 2017, Daybreak had estimated net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $27,232,135 which will begin to expire, if unused, beginning in 2024. The valuation allowance increased $547,324 and $1,303,816 for the six months ended August 31, 2017 and the year ended February 28, 2017, respectively. Section 382 of the Internal Revenue Code places annual limitations on the Company’s net operating loss (NOL) carryforward.

The above estimates are based on management’s decisions concerning elections which could change the relationship between net income and taxable income. Management decisions are made annually and could cause estimates to vary significantly. The Company files federal income tax returns with the United States Internal revenue Service and state income tax returns in various state tax jurisdictions. As a general rule the Company’s tax returns for the fiscal years after 2012 currently remain subject to examinations by appropriate tax authorities. None of our tax returns are under examination at this time.

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

The Company, as an owner or lessee and operator of oil and natural 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 natural gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of August 31, 2017. There can be no assurance, however, that current regulatory requirements will not change or that past non-compliance with environmental issues will not be discovered on the Company’s oil and natural gas properties.

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

The following discussion is management’s assessment of the current and historical financial and operating results of the Company and of our financial condition. It is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q for the six months ended August 31, 2017 and in our Annual Report on Form 10-K for the year ended February 28, 2017. References to “Daybreak”, the “Company”, “we”, “us” or “our” mean Daybreak Oil and Gas, Inc.

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

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

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

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

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

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

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

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

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

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

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

Our reserve estimates are determined through a subjective process and are subject to revision.

Should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended February 28, 2017 and in this Form 10-Q occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically undertake no obligation to publicly update or revise any information contained in any forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except as required by law.

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

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

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

Our operations are focused on identifying and evaluating prospective crude oil and natural gas properties and funding projects that we believe have the potential to produce crude oil or natural gas in commercial quantities. We conduct all of our drilling, exploration and production activities in the United States, and all of our revenues are derived from sales to customers within the United States. Currently, we are in the process of developing a multi-well oilfield project in Kern County, California and an exploratory joint drilling project in Michigan. During the twelve months ended February 28, 2017, we sold all or our working interest in the Twin Bottoms Field in Kentucky.

Our management cannot provide any assurances that Daybreak will ever operate profitably. We have not been able to generate sustained positive earnings on a Company-wide basis. As a small company, we are more susceptible to the numerous business, investment and industry risks that have been described in Item 1A. Risk Factors of our Annual Report on Form 10-K for the fiscal year ended February 28, 2017 and in Part III, Item 1A. Risk Factors of this 10-Q Report. Throughout this Quarterly Report on Form 10-Q, crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of crude oil equivalent (“BOE”).

Below is brief summary of our crude oil projects in California and Michigan. Refer to our discussion in Item 2. Properties, in our Annual Report on Form 10-K for the year ended February 28, 2017 for more information on the California project or the sale of our working interest in the Twin Bottoms Field in Lawrence County, Kentucky.

The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California. Drilling targets are porous and permeable sandstone reservoirs that exist at depths of 1,200 feet to 4,500 feet. Since January 2009, we have participated in the drilling of 25 wells in this project. We have been the Operator at the East Slopes Project since March 2009.

The crude oil produced from our acreage from the Vedder Sand is considered heavy oil. The crude oil ranges from 14° to 16° API gravity and must be heated to separate and remove water prior to sale. Our crude oil wells in the East Slopes Project produce from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations. The Sunday property has six producing wells, while the Bear property has nine producing wells. The Black property is the smallest of all currently producing reservoirs, and currently has two producing wells at this property. The Ball property also has two producing wells while the Dyer Creek property has one producing well.

During the six months ended August 31, 2017 we had production from 20 vertical crude oil wells. Our average working interest and NRI in these 20 wells is 36.6% and 28.4%, respectively.

There are several other similar prospects on trend with the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic characteristics. Some of these prospects, if successful, would utilize the Company’s existing production facilities. In addition to the current field development, there are several other exploratory prospects that have been identified from the seismic data, which we plan to drill in the future.

Planned drilling activity and implementation of our oilfield development plan will not begin until there is a sustained improvement in crude oil prices and financing is acquired. We do not plan to make any new capital investments within the East Slopes Project area for the remaining 2017 – 2018 fiscal year.

In January 2017, Daybreak acquired a 30% working interest in 1,400 acres in the Michigan Basin where we have two shallow crude oil prospects. The leases have been secured and multiple targets have been identified through a 2-D seismic interpretation. A 3-D seismic survey was obtained in January and February of 2017. An analysis of the seismic survey confirmed the prospect identified on the 2-D seismic, as well as identified several additional drilling locations. We will obtain an additional 3-D survey to better delineate the other locations before a drilling program commences. The first well is expected to be drilled during the first half of 2018. We plan to spend approximately $300,000 in new capital investments within the Michigan acreage area in the 2017-2018 fiscal year.

The Company’s debt obligations, pursuant to a credit facility loan agreement and promissory notes entered into by and between Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC, a Delaware limited liability company, as lender, (either party, as appropriate, is referred to in this Quarterly Report on Form 10-Q as “Maximilian”), and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and two mortgages; one covering our leases in California and the other covering our leases in Michigan. On July 13, 2017, in connection with receiving the latest payment waiver from Maximilian, the California and Michigan properties were cross-collateralized for the credit facility loan and the promissory note. For further information on the credit facility loan agreements and promissory note with Maximilian refer to the discussion under the caption “Current debt (Short-term borrowings)” in the MD&A portion of this Quarterly report on Form 10-Q.

Results of Operations – Six months ended August 31, 2017 compared to the six months ended August 31, 2016 (Continuing Operations)

The price we receive for crude oil sales in California is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs. Effective June 1, 2017, we were able to negotiate with our crude oil purchaser the use of a more favorable crude oil pricing schedule. We do not have any natural gas revenues in California.

There has been a significant amount of volatility in crude oil prices and dramatic decline in our realized sale price of crude oil since June of 2014, when the monthly average price of WTI crude oil was $105.79 per barrel. This decline in the price of crude oil has had a substantial negative impact on our cash flow from our producing California properties. While there has been an improvement in crude oil prices for the six months ended August 31, 2017 in comparison to the six months ended August 31, 2016 there is no guarantee that this trend will continue. It is beyond our ability to accurately predict how long crude oil prices will continue to remain at these lower price levels; when or at what level they may begin to stabilize; or when they may start to rebound as there are many factors beyond our control that dictate the price we receive on our crude oil sales.

A comparison of the average WTI price and average realized crude oil sales price at our East Slopes Project in California for the six months ended August 31, 2017 and 2016 is shown in the table below:

For the six months ended August 31, 2017, the average WTI price was $48.12 and our average realized crude oil sale price was $41.99, representing a discount of $6.13 per barrel or 12.7% lower than the average WTI price. In comparison, for the six months ended August 31, 2016, the average WTI price was $43.86 and our average realized sale price was $33.64 representing a discount of $10.22 per barrel or 23.3% lower than the average WTI price. Historically, the sale price we receive for California heavy crude oil has been less than the quoted WTI price because of the lower API gravity of our California crude oil in comparison to the API gravity of quoted WTI crude oil.

Crude oil revenue in California for the six months ended August 31, 2017 increased $39,473 or 17.2% to $268,763 in comparison to revenue of $229,290 for the six months ended August 31, 2016. The average sale price of a barrel of crude oil for the six months ended August 31, 2017 was $41.99 in comparison to $33.64 for the six months ended August 31, 2016. The increase of $8.36 or 24.8% per barrel in the average realized price of a barrel of crude oil accounted for 100% of the increase in crude oil revenue for the six months ended August 31, 2017.

Our net sales volume for the six months ended August 31, 2017 was 6,400 barrels of crude oil in comparison to 6,817 barrels sold for the six months ended August 31, 2016. This decrease in crude oil sales volume of 417 barrels or 6.1% was primarily due to the natural decline in reservoir pressure during the six months ended August 31, 2017.

The gravity of our produced crude oil in California ranges between 14° API and 16° API. Production for the six months ended August 31, 2017 was from 20 wells resulting in 3,661 well days of production in comparison to 3,656 well days of production for the six months ended August 31, 2016.

Our crude oil sales revenue for the six months ended August 31, 2017 and 2016 are set forth in the following table:

*Our average realized sale price on a BOE basis for the six months ended August 31, 2017 was $41.99 in comparison to $33.64 for the six months ended August 31, 2016, representing an increase of $8.36 or 24.8% per barrel.

Total operating expenses for the six months ended August 31, 2017 were $749,603, an increase of $98,323 or 15.1% compared to $651,280 for the six months ended August 31, 2016. The increase was due to the exploration work associated with our new Michigan exploratory joint drilling project in the amount of $80,437. Operating expenses for the six months ended August 31, 2017 and August 31, 2016 are set forth in the table below:

Production expenses include expenses associated with the production of crude oil and natural gas. These expenses include contract pumpers, electricity, road maintenance, control of well insurance, property taxes and well workover expenses; and, relate directly to the number of wells that are in production. For the six months ended August 31, 2017, these expenses increased by $12,165 or 15.2% to $92,225 in comparison to $80,060 for the six months ended August 31, 2016. The increase of $12,165 was primarily due to higher utility expenses than in the comparative period ended August 31, 2016. For the six months ended August 31, 2017 and 2016, we had 20 wells on production in California. Production expense on a barrel of oil equivalent (“BOE”) basis for the six months ended August 31, 2017 and 2016 was $14.41 and $11.74, respectively. Production expenses represented 12.3% of total operating expenses for the six months ended August 31, 2017.

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance, plugging and abandonment (“P&A”) expenses and dry hole expenses. These expenses increased $94,410 to $94,993 for the six months ended August 31, 2017 in comparison to $583 the six months ended August 31, 2016. The two primary reasons for the year-to-year increase was the G&G work on the new Michigan exploratory joint drilling project for $80,437 and the P&A operations on two non-producing well bores in California for $14,550 representing $94,986 in aggregate. Exploration and drilling expenses represented 12.7% of total operating expenses for the six months ended August 31, 2017.

DD&A expenses relate to equipment, proven reserves and property costs, along with impairment and is another component of operating expenses. For the six months ended August 31, 2017, DD&A expenses decreased $4,558 or 8.2% to $51,336 in comparison to $55,894 for the six months ended August 31, 2016. DD&A on a BOE basis was $8.02 and $8.20 for the six months ended August 31, 2017 and 2016, respectively. The decrease in DD&A is directly related to the level of our crude oil production volume in California. DD&A expenses represented 6.8% of total operating expenses for the six months ended August 31, 2017.

G&A expenses include the salaries of our six full-time employees, including management. Fifty percent (50%) of certain employee’s salaries are currently being deferred until the Company’s cash flow improves, however the entire salary expense is recognized under G&A on the statements of operations. 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 natural gas properties as well as for running a public company. For the six months ended August 31, 2017, G&A expenses decreased $3,694 or 0.7% to $511,049 in comparison to $514,743 for the six months ended August 31, 2016. We received, as Operator in California, administrative overhead reimbursement of $28,644 during the six months ended August 31, 2017 for the East Slopes Project which was used to directly offset certain employee salaries. We are continuing a program of reducing all of our G&A costs wherever possible. G&A expenses represented 68.2% of total operating expenses.

Interest expense for the six months ended August 31, 2017 decreased $809,756 or 45.9% to $955,545 in comparison to $1,765,301 for the six months ended August 31, 2016. The decrease in interest expense was due to a lower loan balance on our credit facility with Maximilian since the proceeds from the Kentucky project sale were used to pay-down a portion of the loan balance. Refer to the discussion below under the caption Current debt (Short-term borrowings) in this MD&A for more information on the Maximilian loans.

Results of Operations – Three months ended August 31, 2017 compared to the three months ended August 31, 2016 (Continuing Operations)

A comparison of the average WTI price and average realized crude oil sales price at our East Slopes Project in California for the three months ended August 31, 2017 and 2016 is shown in the table below:

For the three months ended August 31, 2017, the average WTI price was $46.62 and our average realized crude oil sale price was $42.36, representing a discount of $4.26 per barrel or 9.1% lower than the average WTI price. In comparison, for the three months ended August 31, 2016, the average WTI price was $46.04 and our average realized sale price was $35.47 representing a discount of $10.57 per barrel or 23.0% lower than the average WTI price. Historically, the sale price we receive for California heavy crude oil has been less than the quoted WTI price because of the lower API gravity of our California crude oil in comparison to the API gravity of quoted WTI crude oil.

Crude oil revenue in California for the three months ended August 31, 2017 increased $10,895 or 8.8% to $135,039 in comparison to revenue of $124,144 for the three months ended August 31, 2016. The average sale price of a barrel of crude oil for the three months ended August 31, 2017 was $42.36 in comparison to $35.47 for the three months ended August 31, 2016. The increase of $6.89 or 19.4% per barrel in the average realized price of a barrel of crude oil accounted for 100% of the increase in crude oil revenue for the three months ended August 31, 2017.

Our net sales volume for the three months ended August 31, 2017 was 3,188 barrels of crude oil in comparison to 3,500 barrels sold for the three months ended August 31, 2016. This decrease in crude oil sales volume of 312 barrels or 8.9% was primarily due to the natural decline in reservoir pressure during the three months ended August 31, 2017.

The gravity of our produced crude oil in California ranges between 14° API and 16° API. Production for the three months ended August 31, 2017 was from 20 wells resulting in 1,828 well days of production in comparison to 1,827 well days of production for the three months ended August 31, 2016.

Our crude oil sales revenue for the three months ended August 31, 2017 and 2016 are set forth in the following table:

*Our average realized sale price on a BOE basis for the three months ended August 31, 2017 was $42.36 in comparison to $35.47 for the three months ended August 31, 2016, representing an increase of $6.89 or 19.4% per barrel.

Total operating expenses for the three months ended August 31, 2017 were $328,470, an increase of $32,662 or 11.0% compared to $295,808 for the three months ended August 31, 2016. Operating expenses for the three months ended August 31, 2017 and August 31, 2016 are set forth in the table below:

For the three months ended August 31, 2017, production expenses increased by $5,417 or 13.9% to $44,457 in comparison to $39,040 for the three months ended August 31, 2016. The increase of $5,417 was primarily due to higher utility expenses than in the comparative period ended August 31, 2016. For the three months ended August 31, 2017 and 2016 we had 20 wells on production in California. Production expense on a barrel of oil equivalent (“BOE”) basis for the six months ended August 31, 2017 and 2016 were $13.95 and $11.16, respectively. Production expenses represented 13.5% of total operating expenses for the three months ended August 31, 2017.

For the three months ended August 31, 2017, exploration and drilling expenses increased $2,520 to $2,646 in comparison to $126 for the three months ended August 31, 2016. The primary reason for the increase was due to G&G expenses on the new Michigan exploratory joint drilling project. Exploration and drilling expenses represented 0.8% of total operating expenses for the three months ended August 31, 2017.

For the three months ended August 31, 2017, DD&A expenses decreased $3,052 or 10.6% to $25,617 in comparison to $28,669 for the three months ended August 31, 2016. DD&A on a BOE basis was $8.04 and $8.19 for the three months ended August 31, 2017 and 2016, respectively. The decrease in DD&A is directly related to the level of our crude oil production volume in California. DD&A expenses represented 7.8% of total operating expenses for the three months ended August 31, 2017.

For the three months ended August 31, 2017, G&A expenses increased $27,777 or 12.2% to $255,750 in comparison to $227,973 for the three months ended August 31, 2016. Fifty percent (50%) of certain employee’s salaries are currently being deferred until the Company’s cash flow improves, however the entire salary expense is recognized under G&A on the statements of operations. The primary reason for the increase was the timing on receiving certain vendor invoices. We received, as Operator in California, administrative overhead reimbursement of $13,322 during the three months ended August 31, 2017 for the East Slopes Project which was used to directly offset certain employee salaries. We are continuing a program of reducing all of our G&A costs wherever possible. G&A expenses represented 77.9% of total operating expenses for the three months ended August 31, 2017.

Interest expense for the three months ended August 31, 2017 decreased $430,957 or 47.5% to $475,653 in comparison to $906,610 for the three months ended August 31, 2016. The decrease in interest expense was due to a lower loan balance on our credit facility with Maximilian since the proceeds from the Kentucky project sale were used to pay-down a portion of the loan balance. The credit facility activity is discussed further in the discussion of the Maximilian Loan Agreement (Credit Facility) under the Current Debt (Short-Term Borrowings) section of this MD&A.

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

Our primary financial resource is our proven crude oil reserve base. Our ability to fund any future capital expenditure programs is dependent upon the prices we receive from crude oil sales, the success of our drilling programs in California and Michigan and the availability of capital resource financing. Since June 2014, there has been a significant decline in the WTI price of crude oil and consequently in the realized price we receive from crude oil sales in California. This decline in the price of crude oil has had a substantial negative impact on our cash flow, financial statements and our ability to implement an aggressive drilling program in both California and Michigan.

In the current fiscal year we plan to spend approximately $75,000 in capital investments in California and $300,000 in Michigan. However, our actual expenditures may vary significantly from this estimate if our plans for exploration and development activities change during the year or if we are unable to obtain financing to fund these capital investments. Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the current fiscal year.

Changes in our capital resources at August 31, 2017 in comparison to February 28, 2017 are set forth in the table below:

Our working capital deficit increased $1,324,938 or 10.1% to $14,477,866 at August 31, 2017 in comparison to $13,152,928 at February 28, 2017. The increase in our working capital deficit was primarily due to our loss on continuing operations of $1,436,357.

While we have ongoing positive cash flow from our crude oil operations in California, we have not yet been able to generate sufficient cash flow to cover all of our G&A and interest expense requirements. We anticipate an increase in our cash flow will occur when we are able to return to our planned drilling program that will result in an increase in the number of wells on production.

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

Major sources of funds in the past for us have included the debt or equity markets and the sale of assets. We will have to rely on the 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 crude oil and natural gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources.

Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms. Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself. These ongoing capital commitments will cause us to seek additional forms of financing through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these instruments which could result in dilution to existing security holders and increased debt and leverage. The current uncertainty in the credit and capital markets as well as the decline in crude oil prices since June of 2014 has restricted our ability to obtain needed capital. No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all. The sale of all or part of interests in our assets may be another source of cash flow available to us.

The Company’s financial statements for the six months ended August 31, 2017 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 crude oil and natural gas exploration industry in 2005, and as of the six months ended August 31, 2017, we have an accumulated deficit of $37,315,826 and a working capital deficit of $14,477,866 which raises substantial doubt about our ability to continue as a going concern.

In the current fiscal year, we will continue to seek additional financing for our planned exploration and development activities in California and Michigan. We could obtain financing through one or more various methods, including issuing debt securities, equity securities, or 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.

During the six months ended August 31, 2017, we received crude oil sales revenue from 20 wells in California. Our commitment to improving corporate profitability remains unchanged. During the six months ended August 31, 2017, we had an operating loss of $480,840. We experienced an increase in revenues of $39,473 or 17.2% to $268,763 for the six months ended August 31, 2017 in comparison to revenues of $229,290 for the six months ended August 31, 2016. The $8.36 per barrel increase in the realized sale price we received on a BOE basis from $33.64 to $41.99 was all due to an improvement in the realized sales price of oil.

Our balance sheet at August 31, 2017 reflects total assets of approximately $1.1 million in comparison to approximately $1.3 million at February 28, 2017. This decrease of approximately $0.2 million is due to DD&A expense, a decline in our cash available balances and exploratory work done in Michigan.

At August 31, 2017, total liabilities were approximately $15.3 million in comparison to approximately $14.1 million at February 28, 2017. The increase in liabilities of approximately $1.3 million was due to increases in payables and our credit facility balance with Maximilian.

The change in our common stock issued and outstanding balance of 51,532,364 shares at August 31, 2017 in comparison to the 51,487,373 shares at February 28, 2017 was due to the conversion of 14,997 shares of Series A Preferred to 44,991 shares of our common stock.

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 natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. For the six months ended August 31, 2017, cash flow used in operating activities was $44,179 in comparison to cash flow provided by operating activities of $28,499 for the six months ended August 31, 2016. This decrease in operating cash flow of $72,678 or 255.0% is directly related to a decline in our receivables balances; an increase in our payables balances; and, an increase in accrued interest offset by our net loss for the six months ended August 31, 2017. Non-cash account balances relating to DD&A; amortization of debt discount; deferred financing costs and debt modification fees were $310,905 in aggregate for the six months ended August 31, 2017. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash flow from investing activities is derived from changes in oil and gas property balances and any lending activities. Cash flow provided by investing activities for the six months ended August 31, 2017 was -$0- a decline of $1,340 from the cash flow provided by investing activities for the six months ended August 31, 2016. This decline was due to a decline in drilling activity because of lower hydrocarbon prices in the energy markets.

Cash flow from financing activities is derived from changes in long-term liability account balances or in equity account balances, excluding retained earnings. Cash flow provided by our financing activities was $5,000 for the six months ended August 31, 2017 in comparison to cash flow used in our financing activities of $12,860 for the six months ended August 31, 2016. This increase of $17,860 in cash flow was due to an advance we received from our Maximilian Credit Facility offset by principal payments on the UBS Line of Credit. The Maximilian Credit Facility is discussed further under the caption “Current Debt (Short-Term Borrowings) – Maximilian Loan Agreement (Credit Facility)” in this MD&A.

The following discussion is a summary of cash flows provided by, and used in, the Company’s financing activities at August 31, 2017.

At August 31, 2017 and February 28, 2017, the Company had a loan balance of $250,100 with the Company’s Chairman, President and Chief Executive Officer which were obtained during the years ended February 29, 2012 and February 28, 2013, that was used for a variety of corporate purposes including an escrow requirement on a loan commitment; maturity extension fees on third party loans; and a reduction of principal on the Company’s credit line with UBS Bank. These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.

The Company has an existing $890,000 line of credit for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer. At August 31, 2017 and February 28, 2017, the Line of Credit had an outstanding balance of $804,638 and $817,622, respectively. On July 10, 2017, a portion of the outstanding credit line balance, $700,000, was converted to a 24 month fixed term annual interest rate of 3.244% with interest payable monthly. The remaining balance of the credit line has a stated reference rate of 0.249% + 337.5 basis points with interest payable monthly. Interest was $17,015 and $17,140 for the six months ended August 31, 2017 and 2016, respectively. The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

On October 31, 2012, the Company entered into a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in this Quarterly Report on Form 10-Q as “Maximilian”), which provided for a revolving credit facility of up to $20 million, that matured on October 31, 2016, with a minimum commitment of $2.5 million. On October 31, 2016 through the Fourth Amendment to the Amended and Restated Loan and Security Agreement, the maturity date of the loan was changed to February 28, 2020.

On October 31, 2016, the Company entered into a Fourth Amendment to the Amended and Restated Loan and Security Agreement with Maximilian, which amended the Company’s loan agreement with Maximilian (the “Restructuring Agreement”). Pursuant to the Restructuring Agreement, in exchange for the proceeds it received from the Kentucky Sale, Maximilian and the Company have agreed to a commitment by Maximilian to advance up to $250,000 in financing to the Company over the next six months and the pursuit of the Michigan exploratory joint drilling project using the $250,000 set aside from the Kentucky Sale. The Company recognized a gain on debt settlement in aggregate of approximately $3.9 million through the sale of the Kentucky property and reduction in the outstanding credit facility balance.

During the six months ended August 31, 2017, we received $35,000 in advances under the terms of the line of credit.

As a result of the decline in hydrocarbon prices that started in June of 2014, the Company has been unable to make any type of interest or principal payments required under the amended terms of its credit facility with Maximilian since December of 2015. Under the terms of the Restructuring Amendment all unpaid interest is currently being accrued. Since January 2016, a series of waivers on a quarterly basis were granted by Maximilian for the principal and interest payments that had not been made. The Company did not receive a waiver for the months of August through October 2017 and is currently considered to be in default on its credit facility. Maximilian is continuing to work with the Company in restructuring the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue. Further, our lender is under no obligation to advance us any additional funding. A change of control or management of our lender, among other reasons, could also result in our loan being called due and payable.

As of August 31, 2017, the Company had received $94,650 in aggregate from multiple advances starting in the year ended February 28, 2017 from Maximilian under a separate promissory note agreement dated January 17, 2017 and amended on February 10, 2017 regarding the development of an exploratory joint drilling project in Michigan. Advances under this agreement are subject to a 5% (five percent) per annum interest rate. If a well that the Company elects to participate in is scheduled to be spudded on the Michigan exploratory joint drilling project on or before December 31, 2017, then the advances under the promissory note must be repaid in full upon the earlier of (a) the time that is ten days prior to the first well being spudded on the Michigan exploratory joint drilling project or (b) December 31, 2017. If there is not a well scheduled to be spudded at the Michigan exploratory joint drilling project on or before December 31, 2017 that the Company elects to participate in, then the Company will assign to Maximilian its working interest in the Michigan exploratory joint drilling project, in full payment and satisfaction of the advances under the promissory note. Advances under the promissory note may be prepaid at any time without penalty. In the event of a default of any of the Company’s obligations under the promissory note, the amounts due may be called immediately due and payable at Maximilian’s option.

Current debt balances at August 31, 2017 and February 28, 2017 are set forth in the table below:

Deferred financing costs at August 31, 2017 and February 28, 2017 relating to the original and the amended credit facility with Maximilian, are set forth in the table below:

Deferred financing costs of $37,764 and $238,598 at August 31, 2017 and February 28, 2017, respectively includes the fair value of common shares and warrants issued to Maximilian and to a third party that assisted in both the original and the amended financing transactions. The unamortized deferred financing costs are netted against debt in the balance sheets. Amortization expense of deferred financing costs was $200,834 and $215,047 for the six months ended August 31, 2017 and 2016, respectively.

12% Note balances at August 31, 2017 and February 28, 2017 are set forth in the table below:

12% Note balances – related parties at August 31, 2017 and February 28, 2017 are set forth in the table below:

On April 6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted common stock and restricted common stock unit awards. Subject to adjustment, the total number of shares of Daybreak common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan. We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance. Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.

At August 31, 2017, a total of 3,000,000 shares of restricted stock had been awarded under the 2009 Plan, with 2,986,220 shares outstanding and fully vested. A total of 1,013,780 common stock shares remained available at August 31, 2017 for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is set forth in the table below:

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

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

For the six months ended August 31, 2017 and 2016, the Company did not recognize any stock compensation expense related to the above restricted stock grants since all issuances have been fully amortized.

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2017.

As of August 31, 2017, 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, August 31, 2017, an evaluation was conducted by Daybreak management, including our President and Chief Executive Officer, who is also serving as our interim principal finance and accounting officer, as to the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Exchange Act. Such disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods specified by the SEC rules and forms. Additionally, it is vital that such information is accumulated and communicated to our management, including our President and Chief Executive Officer, in a manner to allow timely decisions regarding required disclosures. Based on that evaluation, our management concluded that our disclosure controls were effective as of August 31, 2017.

There have not been any changes in the Company’s internal control over financial reporting during the three months ended August 31, 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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

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

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

In addition to the other information set forth in this Form 10-Q Report, you should carefully consider the various factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended February 28, 2017, which could materially affect our business, financial condition or future results. Our Annual Report is available from the SEC at www.sec.gov. The risks described in this report are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial could have a material adverse effect on our business, financial condition or future results of operations.

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: October 13, 2017


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

1101 N. Argonne Road, Suite A 211, Spokane Valley, WA		99212
(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

		Emerging growth company ¨


ITEM 1.	FINANCIAL STATEMENTS	3
	Balance Sheets at August 31, 2017 and February 28, 2017 (Unaudited)	3
	Statements of Operations for the Three and Six Months Ended August 31, 2017 and August 31, 2016 (Unaudited)	4
	Statements of Cash Flows for the Six Months Ended August 31, 2017 and August 31, 2016 (Unaudited)	5
	NOTES TO UNAUDITED FINANCIAL STATEMENTS	6
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16
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 6.	EXHIBITS	31
Signatures		32


	As of August 31, 2017		As of February 28, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,824	$	42,003
Accounts receivable:
Crude oil and natural gas sales		84,282		83,405
Joint interest participants		60,159		55,154
Other receivables, net		5,044		4,489
Prepaid expenses and other current assets		17,485		24,197
Restricted short-term time deposit		100,080		100,060
Total current assets		269,874		309,308
CRUDE OIL AND NATURAL GAS PROPERTIES, successful efforts method, net
Proved properties		765,982		853,552
Unproved properties		31,187		59,375
PREPAID DRILLING COSTS		16,452		41,078
Total assets	$	1,083,495	$	1,263,313

LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,940,226	$	1,727,955
Accounts payable – related parties		1,529,316		1,414,481
Accrued interest		1,171,130		446,232
Notes payable – related party		250,100		250,100
Debt - current, net of deferred financing costs of $37,764 and $238,598, respectively		9,052,330		8,805,846
Line of credit		804,638		817,622
Total current liabilities		14,747,740		13,462,236
LONG TERM LIABILITIES:
12% Notes payable, net of discount of $11,482 and $15,535, respectively		303,518		299,465
12% Notes payable – related party, net of discount of $9,113 and $12,329, respectively		240,887		237,671
Asset retirement obligation		57,175		93,409
Total liabilities		15,349,320		14,092,781
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; 709,568 and 724,565 shares issued and outstanding, respectively		710		725
Common stock – 200,000,000 shares authorized; $0.001 par value, 51,532,364 and 51,487,373 shares issued and outstanding, respectively		51,532		51,487
Additional paid-in capital		22,997,759		22,997,789
Accumulated deficit		(37,315,826)		(35,879,469)
Total stockholders’ deficit		(14,265,825)		(12,829,468)
Total liabilities and stockholders’ deficit	$	1,083,495	$	1,263,313


	For the Three Months Ended August 31,				For the Six Months Ended August 31,
	2017		2016		2017		2016
REVENUE:
Crude oil and natural gas sales	$	135,039	$	124,144	$	268,763	$	229,290

OPERATING EXPENSES:
Production		44,457		39,040		92,225		80,060
Exploration, drilling and abandonment		2,646		126		94,993		583
Depreciation, depletion, and amortization		25,617		28,669		51,336		55,894
General and administrative		255,750		227,973		511,049		514,743
Total operating expenses		328,470		295,808		749,603		651,280
OPERATING LOSS		(193,431)		(171,664)		(480,840)		(421,990)

OTHER INCOME (EXPENSE):
Interest income		14		23		28		45
Interest expense		(475,652)		(906,610)		(955,545)		(1,765,301)
Total other income (expense)		(475,638)		(906,587)		(955,517)		(1,765,256)

LOSS FROM CONTINUING OPERATIONS		(669,069)		(1,078,251)		(1,436,357)		(2,187,246)

DISCONTINUED OPERATIONS (Note 10)
Income from discontinued operations		-		38,831		-		79,312

NET LOSS		(669,069)		(1,039,420)		(1,436,357)		(2,107,934)

Cumulative convertible preferred stock dividend requirement		(32,191)		(32,871)		(64,900)		(65,743)

NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(701,260)	$	(1,072,291)	$	(1,501,257)	$	(2,173,677)

NET INCOME (LOSS) PER COMMON SHARE
Loss on continuing operations	$	(0.01)	$	(0.02)	$	(0.03)	$	(0.04)
Income on discontinued operations		-		0.00		-		0.00

NET LOSS PER COMMON SHARE, basic and diluted	$	(0.01)	$	(0.02)	$	(0.03)	$	(0.04)

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic and diluted		51,532,364		51,487,373		51,514,818		51,487,373


	Six Months Ended
	August 31, 2017		August 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,436,357)	$	(2,107,934)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, accretion and impairment expense		51,336		151,910
Amortization of debt discount		7,269		55,912
Amortization of deferred financing costs		200,834		215,047
Debt modification fees		-		775,562
Reclass of unproved crude oil and natural gas properties to exploration expense		51,486		-
Non-cash interest income		(20)		(37)
Changes in assets and liabilities:
Accounts receivable - oil and natural gas sales		(877)		(37,529)
Accounts receivable - joint interest participants		(5,005)		52,589
Accounts receivable – other		(555)		(502,061)
Prepaid expenses and other current assets		8,040		21,033
Accounts payable and other accrued liabilities		239,937		92,874
Accounts payable - related parties		114,835		120,735
Accrued interest		724,898		1,190,398
Net cash provided by (used in) operating activities		(44,179)		28,499

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties		-		(1,010)
Prepaid drilling costs		-		2,350
Net cash provided by investing activities		-		1,340

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from debt		35,000		-
Additions to line of credit		-		17,140
Payments on line of credit		(30,000)		(30,000)
Net cash provided by (used in) financing activities		5,000		(12,860)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(39,179)		16,979
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		42,003		6,995
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,824	$	23,974

CASH PAID FOR:
Interest	$	22,544	$	62,922
Income taxes	$	-	$	-

SUPPLEMENTAL CASH FLOW INFORMATION:
Unpaid additions to oil and natural gas properties	$	-	$	13,297
Proceeds of debt paid directly to accounts payable vendor	$	10,650	$	-
Revision to asset retirement obligation	$	40,108	$	-
Increase in note receivable for interest added to principal	$	-	$	538,794
Interest converted to principal on long term debt	$	-	$	1,149,261
Conversion of preferred stock to common stock	$	45	$	-
Accrued interest added to line of credit balance	$	17,016	$	-


	August 31, 2017		February 28, 2017
Proved leasehold costs	$	115,119	$	115,119
Costs of wells and development		2,293,668		2,293,668
Capitalized exploratory well costs		1,341,494		1,341,494
Capitalized asset retirement costs		16,389		56,497
Total cost of crude oil and natural gas properties		3,766,670		3,806,778
Accumulated depletion, depreciation, amortization and impairment		(3,000,688)		(2,953,226)
Net proved crude oil and natural gas properties	$	765,982	$	853,552
Michigan unproved crude oil and natural gas properties		31,187		59,375
Total net proved and unproved crude oil and natural gas properties	$	797,169	$	912,927


	Asset Retirement Obligation
Balance, February 28, 2017	$	93,409
Revision to asset retirement obligation		(40,108)
Accretion for the six months ended August 31, 2017		3,874
Balance, August 31, 2017	$	57,175


	August 31, 2017		February 28, 2017
Credit facility balance	$	8,995,444	$	8,960,444
Less unamortized discount and debt issuance costs		(37,764)		(238,598)
Subtotal – O&G operating debt		8,957,680		8,721,846
Michigan exploratory joint drilling debt		94,650		84,000
Net debt	$	9,052,330	$	8,805,846


	August 31, 2017		February 28, 2017
Deferred financing costs – loan fees	$	181,648	$	181,648
Deferred financing costs – loan commissions		630,662		630,662
Deferred financing costs – fair value of warrants		530,488		530,488
Deferred financing costs – fair value of common stock		419,832		419,832
		1,762,630		1,762,630
Accumulated amortization		(1,724,866)		(1,524,032)
	$	37,764	$	238,598


	August 31, 2017		February 28, 2017
12% Subordinated Notes	$	315,000	$	315,000
Debt discount		(11,482)		(15,535)
Net 12% Subordinated Note balance	$	303,518	$	299,465


	August 31, 2017		February 28, 2017
12% Subordinated Notes – related party	$	250,000	$	250,000
Debt discount		(9,113)		(12,329)
Net 12% Subordinated Note – related party balance	$	240,887	$	237,671


	For the Six Months Ended
	August 31, 2017		August 31, 2016
Crude oil and natural gas sales revenue	$	-	$	208,063
Interest income		-		551,283
Production, exploration and drilling expenses		-		(49,602)
Depreciation, Depletion and Amortization (“DD&A”) expenses		-		(96,016)
Interest expense		-		(534,416)
Income (loss) from discontinued operations	$	-	$	79,312


	For the Three Months Ended
	August 31, 2017		August 31, 2016
Crude oil and natural gas sales revenue	$	-	$	99,733
Interest income		-		270,550
Production, exploration and drilling expenses		-		(20,077)
Depreciation, Depletion and Amortization (“DD&A”) expenses		-		(33,966)
Interest expense		-		(277,409)
Income (loss) from discontinued operations	$	-	$	38,831


Fiscal Period	Shares of Series A Preferred Converted to Common Stock	Shares of Common Stock Issued from Conversion	Number of Accredited Investors
Year ended February 29, 2008	102,300	306,900	10
Year ended February 28, 2009	237,000	711,000	12
Year ended February 28, 2010	51,900	155,700	4
Year ended February 28, 2011	102,000	306,000	4
Year ended February 29, 2012	-	-	-
Year ended February 28, 2013	18,000	54,000	2
Year ended February 28, 2014	151,000	453,000	9
Year ended February 28, 2015	3,000	9,000	1
Year ended February 29, 2016	10,000	30,000	1
Year ended February 28, 2017	-	-	-
Six months ended August 31, 2017	14,997	44,991	1
Totals	690,197	2,070,591	44


	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining
12% Subordinated Notes	1,190,000	$0.07	1.42	980,000
Warrants issued in 2012 for debt financing	2,435,517	$0.044	0.17	316,617
Warrants issued for Kentucky oil project	3,498,601	$0.04	1.00	3,498,601
Warrants issued for Kentucky debt financing	2,623,951	$0.04	1.00	2,623,951
Warrants issued for Kentucky debt financing	309,503	$0.214	1.00	309,503
Warrants issued in share-for-warrant exchange	427,729	$0.04	1.00	427,729
	10,485,301			8,156,401


					Increase		Percentage
	August 31, 2017		February 28, 2017		(Decrease)		Change
Cash	$	2,824	$	42,003	$	(39,179)	(93.3%)
Current Assets	$	269,874	$	309,308	$	(39,434)	(12.7%)
Total Assets	$	1,083,495	$	1,263,313	$	(179,818)	(14.2%)
Current Liabilities	$	(14,747,740)	$	(13,462,236)	$	1,285,504	9.5%
Total Liabilities	$	(15,349,320)	$	(14,092,781)	$	1,256,539	8.9%
Working Capital Deficit	$	(14,477,866)	$	(13,152,928)	$	1,324,938	10.1%


Grant Date	Shares Awarded	Vesting Period	Shares Vested⁽¹⁾	Shares Returned⁽²⁾	Shares Outstanding (Unvested)
4/7/2009	1,900,000	3 Years	1,900,000	-	-
7/16/2009	25,000	3 Years	25,000	-	-
7/16/2009	625,000	4 Years	619,130	5,870	-
7/22/2010	25,000	3 Years	25,000	-	-
7/22/2010	425,000	4 Years	417,090	7,910	-
	3,000,000		2,986,220⁽¹⁾	13,780⁽²⁾	-


Fiscal Period Ended	Shareholders at Period End	Accumulated Dividends
Year ended February 28, 2007	100	$	155,311
Year ended February 29, 2008	90		242,126
Year ended February 28, 2009	78		209,973
Year ended February 28, 2010	74		189,973
Year ended February 28, 2011	70		173,707
Year ended February 29, 2012	70		163,624
Year ended February 28, 2013	68		161,906
Year ended February 28, 2014	59		151,323
Year ended February 28, 2015	58		132,634
Year ended February 29, 2016	57		130,925
Year ended February 28, 2017	57		130,415
Six months ended August 31, 2017	56		64,900
Total Accumulated Dividends		$	1,906,817


	Common Stock Balance	Par Value
Common stock, Issued and Outstanding, February 28, 2017	51,487,373
Conversion of Series A Convertible Preferred Stock to common stock	44,991	$	45
Common stock, Issued and Outstanding, August 31, 2017	51,532,364


	Number of Warrants	Weighted Average Exercise Price
Warrants outstanding, February 28, 2017	8,156,401	$0.05

Changes during the six months ended August 31, 2017:
Issued	-
Expired / Cancelled / Forfeited	-
Warrants outstanding, August 31, 2017	8,156,401	$0.05

Warrants exercisable, August 31, 2017	8,156,401	$0.05


	August 31, 2017		February 28, 2017
Computed at U.S. and state statutory rates (40%)	$	(574,542)	$	(1,387,422)
Permanent differences		27,218		83,606
Changes in valuation allowance		547,324		1,303,816
Total	$	-	$	-


	August 31, 2017		February 28, 2017
Deferred tax assets:
Net operating loss carryforwards	$	10,892,854	$	10,425,780
Crude oil and natural gas properties		57,907		32,488
Stock based compensation		88,723		88,723
Other		22,213		(32,618)
Less valuation allowance		(11,061,697)		(10,514,373)
Total	$	-	$	-


	Six Months Ended August 31, 2017			Six Months Ended August 31, 2016
Project	Revenue		Percentage	Revenue		Percentage
California – East Slopes Project	$	268,763	100.0%	$	229,290	100.0%


	Six Months Ended August 31, 2017					Six Months Ended August 31, 2016
	Expenses		Percentage	BOE Basis		Expenses		Percentage	BOE Basis
Production expenses	$	92,225	12.3%			$	80,060	12.3%
Exploration and drilling expenses		94,993	12.7%				583	0.1%
Depreciation, depletion, amortization (“DD&A”)		51,336	6.8%				55,894	8.6%
General and administrative (“G&A”) expenses		511,049	68.2%				514,743	79.0%
Total operating expenses	$	749,603	100.0%	$	117.129	$	651,280	100.0%	$	95.54


	Three Months Ended
	August 31, 2017		August 31, 2016		Percentage Change
Average three month WTI crude oil price	$	46.62	$	46.04	1.3%
Average three month realized crude oil sales price (Bbl)	$	42.36	$	35.47	19.4%


	Three Months Ended August 31, 2017			Three Months Ended August 31, 2016
Project	Revenue		Percentage	Revenue		Percentage
California – East Slopes Project	$	135,039	100.0%	$	124,144	100.0%


	Six Months Ended August 31, 2017		Six Months Ended August 31, 2016		Increase (Decrease)		Percentage Change
Net cash provided by (used in) operating activities	$	(44,179)	$	28,499		(72,678)	(255.0%)
Net cash provided by investing activities	$	-	$	1,340		(1,340)	(100.0%)
Net cash provided by (used in) financing activities	$	5,000	$	(12,860)		17,860	138.9%