DBRM Daybreak Oil and Gas Inc (CE)

PART I

FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

DAYBREAK OIL AND GAS, INC.

DAYBREAK OIL AND GAS, INC.

DAYBREAK OIL AND GAS, INC.

DAYBREAK OIL AND GAS, INC.

DAYBREAK OIL AND GAS, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION:

Organization

Originally incorporated as Daybreak Uranium, Inc., (“Daybreak Uranium”) under the laws of the State of Washington on March 11, 1955, Daybreak Uranium was organized to explore for, acquire, and develop mineral properties in the Western United States.  During 2005, management of the Company decided to enter the crude oil 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 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.  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, 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.

Basis of Presentation

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

In the opinion of management, all adjustments considered necessary for a fair presentation of the financial statements have been included and such adjustments are of a normal recurring nature.  Operating results for the six months ended August 31, 2019 are not necessarily indicative of the results that may be expected for the fiscal year ending February 29, 2020.

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, 2019.

Use of Estimates

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

·

The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization (“DD&A”) and to determine the amount of any impairment of proved properties;

·

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

·

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

·

Estimates regarding abandonment obligations.

Earnings per Share

The Company follows ASC Topic 260, Earnings per Share, to account for the earnings per share.  Basic earnings per common share (“EPS”) calculations are determined by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period.  Diluted earnings per common share calculations are determined by dividing net income (loss) by the weighted average number of common shares and dilutive common share equivalents outstanding.  During periods when common stock equivalents, if any, are anti-dilutive they are not considered in the computation.

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NOTE 2 — GOING CONCERN:

Financial Condition

The Company’s financial statements for the six months ended August 31, 2019 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 exploration industry and as of August 31, 2019 has an accumulated deficit of $28,584,522 and a working capital deficit of $3,726,194 which raises substantial doubt about the Company’s ability to continue as a going concern.

Management Plans to Continue as a Going Concern

The Company continues to implement plans to enhance its ability to continue as a going concern.  Daybreak currently has 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 average net revenue interest (“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 volatility 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 success in securing financing for its drilling programs.

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 properties, it has not yet established 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, 2019 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.

NOTE 3 — RECENT ACCOUNTING PRONOUNCEMENTS:

Accounting Standards Issued and Adopted

On June 20, 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-07, Compensation-Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting.  The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees.  The amendments specify that Topic 718 applies to all share-based payment transactions in which a grantor acquires goods or services to be used or consumed in a grantor’s own operations by issuing share-based payment awards.  The amendments also clarify that Topic 718 does not apply to share-based payments used to effectively provide (1) financing to the issuer or (2) awards granted in conjunction with selling goods or services to customers as part of a contract accounted for under Topic 606, Revenue from Contracts with Customers.  For public entities, the amendments in this ASU are effective for annual periods beginning after December 15, 2018.  ASC Topic 718 became effective for the Company on March 1, 2019 and did not have a material impact on the Company’s financial statements.

On March 13, 2018, the FASB issued ASU 2018-05, Income Taxes (Topic 740).  The ASU adds seven paragraphs to the Accounting Standards Codification (“ASC”) 740, Income Taxes, that contain SEC guidance related to Staff Accounting Bulletin 118 (“Income Tax Accounting Implications of the Tax Cuts and Jobs Act”) as a result of the tax legislation passed in 2017 known as the “Tax Cuts and Jobs Act” (the “Act”).  Specifically, the staff intended to address situations where the accounting under ASC Topic 740 is incomplete for certain income tax effects of the Act upon issuance of an entity’s financial statements for the reporting period in which the Act was enacted.  The Company notes that it has considered the updates to ASC 740 as a result of the Act and has prepared its financial statements in accordance with the Act.

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In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” and subsequent amendments to the initial guidance: ASU 2018-10, ASU 2018-11, ASU 2018-20 and ASU 2019-01 (collectively, Topic 842).  ASU 2016-02 increases the transparency and comparability of leases among entities and requires an entity to recognize a right-of-use asset (“ROU”) and lease liability for all leases and provide enhanced disclosures.  Recognition, measurement, and presentation of expenses depends on classification as a finance lease or an operating lease.  The Company has determined that it has only operating leases.  ASC 842 supersedes the lease accounting guidance in ASC 840 “Leases”.  On March 1, 2019, the Company adopted Topic 842 using the modified retrospective approach and the impact of the adoption of ASC 842 resulted in the recognition of a right of use asset and lease payable obligation on the Company’s Balance Sheets of approximately $13,787.  Results for reporting periods after March 1, 2019 are presented under Topic 842, while prior periods have not been adjusted.  The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed the Company to carry forward the historical lease classification.  Refer to Note 9 - Leases.

NOTE 4 — CONCENTRATION RISK:

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

NOTE 5 — CRUDE OIL PROPERTIES:

Crude oil property balances at August 31, 2019 and February 28, 2019 are set forth in the table below.

NOTE 6 — ACCOUNTS PAYABLE:

On March 1, 2009, the Company became the operator for its East Slopes Project in California.  Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning well program.  The Company subsequently sold the same 25% working interest on June 11, 2009.  Of the $1.5 million liability, $244,849 remains unpaid and is included in both the August 31, 2019 and February 28, 2019 accounts payable balances.  Payment of this liability has been delayed until the Company’s cash flow situation improves.  On October 17, 2018, a working interest partner in California filed a UCC financing statement in regards to payables owed to the partner by the Company.  At August 31, 2019, the balance owed this working interest partner was $109,371 and is included in the approximate $1.4 million accounts payable balance.

NOTE 7 — ACCOUNTS PAYABLE- RELATED PARTIES:

The August 31, 2019 and February 28, 2019 accounts payable – related parties balances of approximately $0.9 million and $1.9 million respectively, were comprised primarily of deferred salaries of one 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 Chairman, President and Chief Executive Officer.  On August 22, 2019, an agreement was reached between the Company and the Company’s Chairman, President and Chief Executive Officer whereby all deferred salary owed by the Company to this related party was forgiven.  The agreement has an effective date of June 1, 2019.  This agreement resulted in a decrease of approximately $882,043 in net salary payable from the prior related party payables balance.  This agreement also resulted in a decrease of $123,414 in estimated payroll taxes from accounts payable balances.  Additionally, on August 22, 2019 the three Non-Employee Directors of the Company to whom director fees were owed agreed to forgive 50% (fifty percent) of the amounts owed to each individual director.  These agreements had an effective date of June 1, 2019 and resulted in a reduction of $209,688 in the related party payables balance.  The total amount of liability forgiveness was approximately $1.2 million and was recorded as an addition to additional paid in capital (APIC).  Payment of any other deferred items has been delayed until the Company’s cash flow situation improves.

The Company’s Chairman, President and Chief Executive Officer had previously loaned the Company an aggregate $250,100 that was used for a variety of corporate purposes.  In connection with its debt reduction efforts, the Company entered into a Note Payoff Agreement with this related party.  Pursuant to the Note Payoff Agreement, the Company issued as payment in full of the Notes, a production payment interest in certain of the Company’s production revenue from the drilling of future wells in California and Michigan.  The production payment interest was granted for a deemed consideration amount of the balance of the Notes and made pursuant to a Production Payment Interest Purchase Agreement dated as of August 22, 2019.  The grant was made on the same terms as the Company has sold production payment interests to other third parties in the 2018-2019 fiscal year pursuant to its previously disclosed program.  For further information on the production revenue program refer to the “Production Revenue Payable” section below.

12% Note balances at August 31, 2019 and February 28, 2019 are set forth in the table below:

Since December 2018, the Company has been selling interests in certain portions of its future production revenue to fund the drilling of new wells in California and Michigan and to settle some of its historical debt.  The purchasers of production payment interests receive a production revenue payment on future wells to be drilled in California and Michigan in exchange for their purchase.  On August 22, 2019, the Company entered into a Note Payoff Agreement with the Company’s Chairman, President and Chief Executive Officer as payment in full of the $250,100 in Notes referenced above, a production payment interest in certain of the Company’s production revenue from the drilling of future wells in California and Michigan.  The production payment interest was granted for a deemed consideration amount of the balance of the Notes.  The grant was made on the same terms as the Company has sold production payment interests to other third parties in the 2018-2019 fiscal year pursuant to its previously disclosed program.  As of August 31, 2019, the production revenue payment program balance was $950,100 of which $550,100 was owed to a related party - the Company’s Chairman, President and Chief Executive Officer.

The production payment interest entitles the purchasers to receive production payments equal to twice their original amount paid, payable from a percentage of the Company’s future net production payments from wells drilled after the date of the purchase and until the Production Payment Target (as described below) is met.  The Company shall pay fifty percent of its net production payments from the relevant wells to the purchasers until each purchaser has received two times the purchase price (the “Production Payment Target”).  Once the Company pays the purchasers amounts equal to the Production Payment Target, it shall thereafter pay a pro-rated eight percent of $1.3 million on its net production payments from the relevant wells to each of the purchasers.  However, if the Production Payment Target is not met within the first three years, the Company shall pay seventy-five percent of its production payments from the relevant wells to the purchasers until the Production Payment Target is met.

The Company accounted for the amounts received from these sales in accordance with ASC 470-10-25 and 470-10-35 which require amounts recorded as debt to be amortized under the interest method as described in ASC 835-30, Interest Method.  Consequently, the program balance of $950,100 has been recognized as a production revenue payable.  The Company determined an effective interest rate based on future expected cash flows to be paid to the holders of the production payment interests.  This rate represents the discount rate that equates estimated cash flows with the initial proceeds received from the sales and is used to compute the amount of interest to be recognized each period.  Estimating the future cash outflows under this agreement requires the Company to make certain estimates and assumptions about future revenues and payments and such estimates are subject to significant variability.  Therefore, the estimates are likely to change which may result in future adjustments to the accretion of the interest expense and the amortized cost based carrying value of the related payables.

Accordingly, the Company has estimated the cash flows associated with the production revenue payments and determined a discount of $1,666,615 which is being accounted as interest expense over the estimated period over which payments will be made based on expected future revenue streams.  For the six months ended August 31, 2019, amortization of the debt discount on these payables amounted to $215,129 which has been included in interest expense in the statements of operations.

Production revenue payable balances at August 31, 2019 and February 28, 2019 are set forth in the table below:

Encumbrances

On October 17, 2018, a working interest partner in California filed a UCC financing statement in regards to payable amounts owed to the partner by the Company.  As of August 31, 2019, we had no encumbrances on our crude oil project in Michigan.

NOTE 9 — LEASES:

The Company leases approximately 988 rentable square feet of office space from an unaffiliated third party for our corporate office located in Spokane Valley, Washington.  Additionally, we lease approximately 416 and 695 rentable square feet from unaffiliated third parties for our regional operations office in Friendswood, Texas and storage and auxiliary office space in Wallace, Idaho, respectively.  The lease in Friendswood is a 24 month lease that expires in October 2020.  The Company’s lease for Friendswood does not include an option to renew.  The Spokane Valley and Wallace leases are currently on a month-to-month basis.  The Company’s lease agreements do not contain any residual value guarantees, restrictive covenants or variable lease payments.  The Company has not entered into any financing leases.

The Company determines if an arrangement is a lease at inception.  Operating leases are recorded in operating lease right of use assets, net, operating lease liability – current, and operating lease liability – long-term on its balance sheet.

Operating lease assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease.  Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term.  As the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments.  The incremental borrowing rate used at adoption was 5.85%.  Significant judgement is required when determining the Company’s incremental borrowing rate.  Lease expense for lease payments is recognized on a straight-line basis over the lease term.

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The Balance Sheet classification of lease assets and liabilities was as follows:

Future minimum lease payments as of August 31, 2019 under non-cancellable operating leases are as follows:

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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 the Company has 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, 2019 no dividends have been declared or paid.  Dividends earned since issuance for each fiscal year and the six months ended August 31, 2019 are set forth in the table below:

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

At August 31, 2019, the Company had estimated net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $18,153,961 which will begin to expire, if unused, beginning in 2024.  Under the Tax Cuts and Jobs Act, the NOL portion of the loss incurred in the 2018 period of $340,749 and the loss incurred for the six months ended August 31, 2019 in the amount of $185,572 will not expire and will carry over indefinitely.  The valuation allowance increased $61,071 for the six months ended August 31, 2019 and decreased approximately $3,060,558 for the year ended February 28, 2019, 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 2014 currently remain subject to examinations by appropriate tax authorities.  None of our tax returns are under examination at this time.

NOTE 13 — SUBSEQUENT EVENTS:

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, 2019 and in our Annual Report on Form 10-K for the year ended February 28, 2019.  References to “Daybreak”, the “Company”, “we”, “us” or “our” mean Daybreak Oil and Gas, Inc.

Cautionary Statement Regarding Forward-Looking Statements

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

Introduction and Overview

We are an independent crude oil exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing crude oil 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 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 properties and on the prevailing sales prices for crude oil 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 or market volatility, 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 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.

Michigan Acreage Acquisition

In January 2017, Daybreak acquired a 30% working interest in 1,400 acres in the Michigan Basin.  The leases have been secured and multiple targets were identified through a 2-D seismic interpretation.  A 3-D seismic survey was obtained in January and February of 2017.  An analysis of the 3-D seismic survey confirmed the first prospect originally identified on the 2-D seismic, as well as several additional drilling locations.  We have plans to obtain an additional 3-D survey on the second prospect after drilling a well on the first prospect.  The two prospects are independent of each other and the success or lack of results of either prospect does not affect the potential of the other prospect.  The wells will be drilled vertically with conventional completions and no hydraulic fracturing is anticipated.  With the settlement of our debt obligations to a former lender in December 2018, we acquired an additional 40% working interest, bringing our aggregate working interest to 70% in Michigan.  The first well is expected to be drilled in the spring of 2020 if new financing is secured.

There has been a significant amount of volatility in crude oil prices and a 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 and our realized price per barrel of crude oil was $98.78.  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 overall improvement in crude oil prices since February 2016 when the monthly average price of WTI crude oil was $30.32, there is no guarantee that this trend will continue.  Most recently, the monthly average WTI price of crude oil has declined from $70.75 in October 2018 to $54.81 in August 2019 demonstrating the continued volatility in crude oil prices.  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 rebound to 2014 levels, as there are many factors beyond our control that dictate the price we receive on our crude oil sales.

For the six months ended August 31, 2019, the average WTI price was $58.28 and our average realized crude oil sale price was $61.98, representing a premium of $3.70 per barrel or 6.3% higher than the average WTI price.  In comparison, for the six months ended August 31, 2018, the average WTI price was $67.65 and our average realized sale price was $67.39 representing a discount of $0.26 per barrel or 0.4% 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.

California Crude Oil Revenue and Production

Crude oil revenue in California for the six months ended August 31, 2019 decreased $34,290 or 8.7% to $359,413 in comparison to revenue of $393,703 for the six months ended August 31, 2018.  The average sale price of a barrel of crude oil for the six months ended August 31, 2019 was $61.98 in comparison to $67.39 for the six months ended August 31, 2018.  The decrease of $5.41 or 8.0% per barrel in the average realized price of a barrel of crude oil accounted for 92.2% of the decrease in crude oil revenue for the six months ended August 31, 2019.

Our net sales volume for the six months ended August 31, 2019 was 5,799 barrels of crude oil in comparison to 5,842 barrels sold for the six months ended August 31, 2018.  This decrease in crude oil sales volume of 43 barrels or 0.7% was primarily due to the natural decline in reservoir pressure during the six months ended August 31, 2019.

Operating Expenses

Total operating expenses for the six months ended August 31, 2019 were $509,012, a decrease of $51,431 or 9.2% compared to $560,443 for the six months ended August 31, 2018.  Operating expenses for the six months ended August 31, 2019 and 2018 are set forth in the table below:

Production expenses include expenses associated with the production of crude oil.  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, 2019, these expenses increased by $14,987 or 20.1% to $89,543 in comparison to $74,556 for the six months ended August 31, 2018.  For the six months ended August 31, 2019 and 2018, 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, 2019 and 2018 was $15.44 and $12.76, respectively.  Production expenses represented 17.6% and 13.3% of total operating expenses for the six months ended August 31, 2019 and 2018, respectively.

General and administrative (“G&A”) expenses include the salaries of our six full-time employees, including management.  Fifty percent (50%) of certain management salaries were being deferred by the Company for the first three months of the current fiscal year.  However, effective June 1, 2019, the salary deferral program was ended and those base salaries were reduced by half, to the amount currently being paid.  Additionally, director fees are being suspended temporarily.  Both of these compensation changes will be reviewed by the Board of Directors no later than June 1, 2020 based on the financial status of the Company at that time.  Other items included in our G&A expenses are legal and accounting expenses, investor relations fees, travel expenses, insurance expenses and other administrative expenses necessary for an operator of crude oil properties as well as for running a public company.  For the six

months ended August 31, 2019, G&A expenses decreased $58,937 or 13.2% to $388,433 in comparison to $447,370 for the six months ended August 31, 2018.  We received, as Operator, administrative overhead reimbursement of $26,644 during the six months ended August 31, 2019 for the East Slopes Project which was used to directly offset certain employee salaries.  We are continuing a program of controlling our G&A costs wherever possible.  G&A expenses represented 76.3% and 79.8% of total operating expenses for the six months ended August 31, 2019 and 2018, respectively.

Interest expense, net for the six months ended August 31, 2019 decreased $890,530 or 76.5% to $272,935 in comparison to $1,163,465 for the six months ended August 31, 2018.  The decrease in interest expense, net was due to lower interest expense since the settlement of a former credit facility loan in December 2018.

For the three months ended August 31, 2019, the average WTI price was $55.61 and our average realized crude oil sale price was $58.78, representing a premium of 3.17 per barrel or 5.7% higher than the average WTI price.  In comparison, for the three months ended August 31, 2018, the average WTI price was $68.97 and our average realized sale price was $68.69 representing a discount of $0.28 per barrel or 0.4% 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.

California Crude Oil Revenue and Production

Crude oil revenue in California for the three months ended August 31, 2019, decreased $53,715 or 24.8% to $163,055 in comparison to revenue of $216,770 for the three months ended August 31, 2018.  The average sale price of a barrel of crude oil for the three months ended August 31, 2019 was $58.78 in comparison to $68.69 for the three months ended August 31, 2018.  The decrease of $9.91 or 14.4% per barrel in the average realized price of a barrel of crude oil accounted for 58.1% of the increase in crude oil revenue for the three months ended August 31, 2019.

Our net sales volume for the three months ended August 31, 2019 was 2,774 barrels of crude oil in comparison to 3,157 barrels sold for the three months ended August 31, 2018.  This decrease in crude oil sales volume of 383 barrels or 12.1% accounted for 41.9% of the decrease in revenue for the three months ended August 31, 2019.

The gravity of our produced crude oil in California ranges between 14° API and 16° API.  Production for the three months ended August 31, 2019 was from 20 wells resulting in 1,828 well days of production in comparison to 1,840 well days of production for the three months ended August 31, 2018.

Our crude oil sales revenue for the three months ended August 31, 2019 and 2018 are set forth in the following table:

*Our average realized sale price on a BOE basis for the three months ended August 31, 2019 was $58.78 in comparison to $68.69 for the three months ended August 31, 2018, representing a decrease of $9.91 or 14.4% per barrel.

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Production expenses for the three months ended August 31, 2019, increased by $14,077 or 44.3% to $45,826 in comparison to $31,749 for the three months ended August 31, 2018.  For the three months ended August 31, 2019 and 2018 we had 20 wells on production in California.  Production expense on a barrel of oil equivalent (“BOE”) basis for the three months ended August 31, 2019 and 2018 were $16.52 and $10.06, respectively.  Production expenses represented 22.6% and 12.4% of total operating expenses for the three months ended August 31, 2019 and 2018, respectively.

Exploration and drilling expenses for the three months ended August 31, 2019, decreased $847 to $16 in comparison to $863 for the three months ended August 31, 2018.  Exploration and drilling expenses represented 0.0% and 0.3% of total operating expenses for the three months ended August 31, 2019 and 2018, respectively.

DD&A expenses for the three months ended August 31, 2019, decreased $5,379 or 26.6% to $14,856 in comparison to $20,235 for the three months ended August 31, 2018.  DD&A on a BOE basis was $5.36 and $6.41 for the three months ended August 31, 2019 and 2018, respectively.  The decrease in DD&A is directly related to the increase in our reserve estimates in comparison to the prior year reserves.  DD&A expenses represented 7.3% and 7.9% of total operating expenses for the three months ended August 31, 2019 and 2018, respectively.

G&A expenses for the three months ended August 31, 2019, decreased $61,443 or 30.1% to $142,465 in comparison to $203,908 for the three months ended August 31, 2018.  Fifty percent (50%) of certain management salaries were being deferred by the Company for the first three months of the current fiscal year.  However, effective June 1, 2019, the salary deferral program was ended and those base salaries were reduced by half, to the amount currently being paid.  Additionally, director fees are being suspended temporarily.  Both of these compensation changes will be reviewed, the salary deferral program was ended and those base salaries were reduced by half, to the amount currently being paid.no later than June 1, 2020 based on the financial status of the Company at that time.  Other items included in our G&A expenses are legal and accounting expenses, director fees, investor relations fees, travel expenses, insurance expenses and other administrative expenses necessary for an operator of crude oil properties as well as for running a public company.  We received, as Operator in California, administrative overhead reimbursement of $13,322 during the three months ended August 31, 2019 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 70.1% and 79.4% of total operating expenses for the three months ended August 31, 2019 and 2018, respectively.

Capital Resources and Liquidity

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.  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, and our realized sale price per barrel of crude oil was $98.78.  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 overall improvement in crude oil prices since February 2016 when the monthly average price of WTI crude oil was $30.32, there is no guarantee that this trend will continue.  Most recently, the monthly average WTI price of crude oil has declined from $70.75 in October 2018 to $54.81 in August 2019 demonstrating the continued volatility in crude oil prices.  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 continue to rebound as there are many factors beyond our control that dictate the price we receive for our crude oil sales.

In the current fiscal year we plan to spend approximately $525,000 in capital investments in California if new financing is secured.  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, 2019 in comparison to February 28, 2019 are set forth in the table below:

The Company’s financial statements for the six months ended August 31, 2019 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 exploration industry in 2005, and as of the six months ended August 31, 2019, we have an accumulated deficit of $28,584,522 and a working capital deficit of $3,726,194 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.  Sales of interests in our assets may be another source of cash flow.

Changes in Financial Condition

During the six months ended August 31, 2019, we received crude oil sales revenue from 20 wells in California.  Our commitment to improving corporate profitability remains unchanged.  We experienced a decrease in revenues of $34,290 or 8.7% to $359,413 for the six months ended August 31, 2019 in comparison to revenues of $393,703 for the six months ended August 31, 2018.  The decrease of $5.41 or 8.0% per barrel in the average realized price of a barrel of crude oil accounted for 92.2% of the decrease in crude oil revenue for the six months ended August 31, 2019.  For the six months ended August 31, 2019, we had an operating loss of $149,599 in comparison to an operating loss of $166,740 for the six months ended August 31, 2018.

Our balance sheet at August 31, 2019 reflects total assets of approximately $0.88 million in comparison to approximately $0.91 million at February 28, 2019.  The decrease of $36,014 is primarily due to cash outflow from operations and depletion of our crude oil properties.

At August 31, 2019, total liabilities were approximately $5.2 million in comparison to approximately $6.0 million at February 28, 2019.  The decrease in liabilities of $834,625 was primarily due to debt forgiveness in related party accounts payable.

The issued and outstanding shares of common stock at August 31, 2019 increased by 2,000,000 shares in comparison to the February 28, 2019 balance of 51,532,364 shares as a result of the settlement of certain accounts payable.  The common stock issuance was valued at $6,000.

Additional paid in capital (APIC) increased $1,219,145 to $24,216,904 at August 31, 2019 from $22,997,759 as a result of forgiveness of related party deferred salaries and director’s fess effective June 1, 2019.

Cash Flow Used In Operating Activities

Cash flow from operating activities is derived from the production of our crude oil 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, 2019, cash flow used in operating activities was $35,893 in comparison to cash flow used in operating activities of $57,943 for the six months ended August 31, 2018.  This decrease in our cash flow used in operating activities for the six months ended August 31, 2019 was due to a reduction in our non-cash operating expenses, our liability balances and our net loss.  Changes in non-cash account balances primarily relating to DD&A and amortization of debt discount.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

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Cash Flow Used In Investing Activities

Cash flow from investing activities is derived from changes in crude oil property balances and any lending activities.  Cash flow used in our investing activities for the six months ended August 31, 2019 was $-0- in comparison to cash flow used in our investing activities of $12,227 for the six months ended August 31, 2018.

12% Note balances – accrued interest at August 31, 2019 and February 28, 2019 are set forth in the table below:

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The accrued interest owed on the 12% Subordinated Note to the related party is presented on our Balance Sheets under the caption Accounts payable – related party rather than under the caption Accrued interest.

Line of Credit

The Company has an existing $890,000 line of credit for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of its Chairman, President and Chief Executive Officer.  On July 10, 2017 a $700,000 portion of the outstanding line of credit balance was converted to a 24 month fixed term annual percentage interest rate of 3.244% with interest payable monthly.  On July 10, 2019, the 24 month fixed term loan amount of $700,000 was renewed at the same annual percentage interest rate of 3.244% for an additional 24 months.  The remaining principal balance of the line of credit has a stated reference rate of 0.249% + 337.5 basis points with interest payable monthly.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

During the six months ended August 31, 2019 and 2018, the Company received advances on the line of credit of $49,000 and $33,300, respectively.  During the six months ended August 31, 2019 and 2018, the Company made payments to the line of credit of $30,000 and $80,000, respectively.  Interest converted to principal for the six months ended August 31, 2019 and 2018 was $15,684 and $15,046, respectively.  At August 31, 2019 and February 28, 2019, the line of credit had an outstanding balance of $861,537 and $826,853, respectively.

Note Payable

In December 2018, we were able to settle an outstanding balance owed to one of our third-party vendors.  This settlement resulted in a $120,000 note payable issued to the vendor.  Additionally, we agreed to issue 2,000,000 shares of the Company’s common stock to the vendor as a part of the settlement.  Based on the closing price of the Company’s common stock on the date of the settlement, the value of the common stock transaction was determined to be $6,000.  The common stock shares were issued during the six months ended August 31, 2019.  The note has a maturity date of January 1, 2022 and bears an interest rate of 10% rate per annum.  Monthly interest is accrued and payable on January 1^st of each anniversary date through maturity of the note.  At August 31, 2019, the accrued interest on the Note was $8,000.

Production Revenue Payable

Since December 2018, the Company has been selling interests in certain portions of its future production revenue to fund the drilling of new wells in California and Michigan and to settle some of its historical debt.  The purchasers of production payment interests receive a production revenue payment on future wells to be drilled in California and Michigan in exchange for their purchase.  On August 22, 2019, the Company entered into a Note Payoff Agreement with the Company’s Chairman, President and Chief Executive Officer as payment in full of the $250,100 in Notes referenced above, a production payment interest in certain of the Company’s production revenue from the drilling of future wells in California and Michigan.  The production payment interest was granted for a deemed consideration amount of the balance of the Notes.  The grant was made on the same terms as the Company has sold production payment interests to other third parties in the 2018-2019 fiscal year pursuant to its previously disclosed program.  As of August 31, 2019, the production revenue payment program balance was $950,100 of which $550,100 was owed to a related party - the Company’s Chairman, President and Chief Executive Officer.

The production payment interest entitles the purchasers to receive production payments equal to twice their original amount paid, payable from a percentage of the Company’s future net production payments from wells drilled after the date of the purchase and until the Production Payment Target (as described below) is met.  The Company shall pay fifty percent of its net production payments from the relevant wells to the purchasers until each purchaser has received two times the purchase price (the “Production Payment Target”).  Once the Company pays the purchasers amounts equal to the Production Payment Target, it shall thereafter pay a pro-rated eight percent of $1.3 million on its net production payments from the relevant wells to each of the purchasers.  However, if the Production Payment Target is not met within the first three years, the Company shall pay seventy-five percent of its production payments from the relevant wells to the purchasers until the Production Payment Target is met.

The Company accounted for the amounts received from these sales in accordance with ASC 470-10-25 and 470-10-35 which require amounts recorded as debt to be amortized under the interest method as described in ASC 835-30, Interest Method.  Consequently, the program balance of $950,100 has been recognized as a production revenue payable.  The Company determined an effective interest rate based on future expected cash flows to be paid to the holders of the production payment interests.  This rate represents the discount rate that equates estimated cash flows with the initial proceeds received from the sales and is used to compute the amount of interest to be recognized each period.  Estimating the future cash outflows under this agreement requires the Company to make certain estimates and assumptions about future revenues and payments and such estimates are subject to significant variability.  Therefore, the

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estimates are likely to change which may result in future adjustments to the accretion of the interest expense and the amortized cost based carrying value of the related payables.

Accordingly, the Company has estimated the cash flows associated with the production revenue payments and determined a discount of $1,666,615 which is being accounted as interest expense over the estimated period over which payments will be made based on expected future revenue streams.  For the six months ended August 31, 2019, amortization of the debt discount on these payables amounted to $215,129 which has been included in interest expense in the statements of operations.

Production revenue payable balances at August 31, 2019 and February 28, 2019 are set forth in the table below:

Encumbrances

On October 17, 2018, a working interest partner in California filed a UCC financing statement in regards to payable amounts owed to the partner by the Company.  As of August 31, 2019, we had no encumbrances on our crude oil project in Michigan.

Capital Commitments

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

Restricted Stock and Restricted Stock Unit Plan

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

At August 31, 2019, 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, 2019 for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan issuances is set forth in the table below:

⁽¹⁾

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

⁽²⁾

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

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For the six months ended August 31, 2019 and 2018, the Company did not recognize any stock compensation expense related to the above restricted stock grants since all issuances have been fully amortized.

Management Plans to Continue as a Going Concern

We continue to implement plans to enhance Daybreak’s ability to continue as a going concern.  The Company currently has a net revenue interest in 20 producing crude oil wells in our East Slopes Project located in Kern County, California.  The revenue from these wells has created a steady and reliable source of revenue for the Company.  Our average working interest in these wells is 36.6% and the average net revenue interest is 28.4%.

We anticipate revenues will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project in California and as our drilling operations begin in Michigan.  However given the current volatility 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 our credit facility.

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

Our financial statements as of August 31, 2019 do not include any adjustments that might result from the inability to implement or execute Daybreak’s plans to improve our ability to continue as a going concern.

Critical Accounting Policies

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2019.

Off-Balance Sheet Arrangements

As of August 31, 2019, 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.

ITEM 4.  CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

As of the end of the reporting period, August 31, 2019, 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, 2019.