UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended August 31, 2019

OR

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

For the transition period from   ______________   to   _______________

Commission File Number: 000-50107

DAYBREAK OIL AND GAS, INC.

(Exact name of registrant as specified in its charter)

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)

(509) 232-7674

(Registrant’s telephone number, including area code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
n/a	n/a	n/a

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.

Large accelerated filer¨	Accelerated filer¨
Non-accelerated filerþ	Smaller reporting companyþ
	Emerging growth company  ¨

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 11, 2019 the registrant had 53,532,364 outstanding shares of $0.001 par value common stock.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	3
	Balance Sheets at August 31, 2019 and February 28, 2019 (Unaudited)	3
	Statements of Operations for the Three and Six Months Ended August 31, 2019 and August 31, 2018 (Unaudited)	4
	Statements of Changes in Stockholders’ Deficit for the Three and Six Months Ended August 31, 2019 and 2018 (Unaudited)	5
	Statements of Cash Flows for the Six Months Ended August 31, 2019 and August 31, 2018 (Unaudited)	6
	NOTES TO UNAUDITED FINANCIAL STATEMENTS	7
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	28
ITEM 4.	CONTROLS AND PROCEDURES	28
PART II - OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	29
ITEM 1A.	RISK FACTORS	29
ITEM 6.	EXHIBITS	30
Signatures		31

2

PART I

FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

DAYBREAK OIL AND GAS, INC.

Balance Sheets – Unaudited

	As of August 31, 2019		As of February 28, 2019
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	13,185	$	30,078
Accounts receivable:
Crude oil sales		94,682		75,410
Joint interest participants		47,652		54,883
Prepaid expenses and other current assets		10,505		23,176
Total current assets		166,024		183,547
LONG-TERM ASSETS:
Crude oil properties, successful efforts method, net
Proved properties		627,834		656,624
Unproved properties		55,978		55,768
Prepaid drilling costs		16,452		16,452
Operating lease, right-of-use asset		10,089		-
Total long-term assets		710,353		728,844
Total assets	$	876,377	$	912,391
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,406,811	$	1,511,286
Accounts payable – related parties		903,658		1,920,897
Accrued interest		49,114		24,059
Notes payable – related party		-		250,100
12% Notes payable		315,000		315,000
12% Notes payable – related party		250,000		250,000
Line of credit		861,537		826,853
Production revenue payable - current, net of unamortized discount		97,474		247,868
Operating lease liability - current		8,624		-
Total current liabilities		3,892,218		5,346,063
LONG TERM LIABILITIES:
Note payable		120,000		120,000
Production revenue payable, net of unamortized discount and current portion		1,144,343		528,720
Operating lease liability, long-term		1,465		-
Asset retirement obligation		31,727		29,595
Total long-term liabilities		1,297,535		678,315
Total liabilities		5,189,753		6,024,378
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 shares issued and outstanding		710		710
Common stock – 200,000,000 shares authorized; $0.001 par value, 53,532,364 and 51,532,364 shares issued and outstanding, respectively		53,532		51,532
Additional paid-in capital		24,216,904		22,997,759
Accumulated deficit		(28,584,522)		(28,161,988)
Total stockholders’ deficit		(4,313,376)		(5,111,987)
Total liabilities and stockholders’ deficit	$	876,377	$	912,391

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

3

DAYBREAK OIL AND GAS, INC.

Statements of Operations – Unaudited

	For the Three Months Ended August 31,				For the Six Months Ended August 31,
	2019		2018		2019		2018
REVENUE:
Crude oil sales	$	163,055	$	216,770	$	359,413	$	393,703
OPERATING EXPENSES:
Production		45,826		31,749		89,543		74,556
Exploration and drilling (G&G)		16		863		114		992
Depreciation, depletion, and amortization (DD&A)		14,856		20,235		30,922		37,525
General and administrative		142,465		203,908		388,433		447,370
Total operating expenses		203,163		256,755		509,012		560,443
OPERATING LOSS		(40,108)		(39,985)		(149,599)		(166,740)
OTHER EXPENSE:
Interest expense, net		(118,841)		(581,557)		(272,935)		(1,163,465)
NET LOSS		(158,949)		(621,542)		(422,534)		(1,330,205)
Cumulative convertible preferred stock dividend requirement		(32,191)		(32,191)		(64,382)		(64,382)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(191,140)	$	(653,733)	$	(486,916)	$	(1,394,587)
NET LOSS PER COMMON SHARE, basic and diluted	$	(0.00)	$	(0.01)	$	(0.01)	$	(0.03)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic and diluted		53,532,364		51,532,364		52,872,364		51,532,364

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

4

DAYBREAK OIL AND GAS, INC.

Statements of Changes in Stockholders' Deficit

For the Three Months and Six Months Ended August 31, 2019 and 2018

	Series A Convertible						Additional
	Preferred Stock			Common Stock			Paid-In		Accumulated
	Shares	Amount		Shares	Amount		Capital		Deficit		Total
BALANCE, FEBRUARY 28, 2019	709,568	$	710	51,532,364	$	51,532	$	22,997,759	$	(28,161,988)	$	(5,111,987)
Issuance of common stock for:
Accounts payable settlement	-		-	2,000,000		2,000		4,000		-		6,000
Net loss	-		-	-		-		-		(263,585)		(263,585)
BALANCE, MAY 31, 2019	709,568		710	53,532,364		53,532		23,001,759		(28,425,573)		(5,369,572)
Forgiveness of liabilities to related parties	-		-	-		-		1,215,145		-		1,215,145
Net loss	-		-	-		-		-		(158,949)		(158,949)
BALANCE, AUGUST 31, 2019	709,568	$	710	53,532,364	$	53,532	$	24,216,904	$	(28,584,522)	$	(4,313,376)

	Series A Convertible						Additional
	Preferred Stock			Common Stock			Paid-In		Accumulated
	Shares	Amount		Shares	Amount		Capital		Deficit		Total
BALANCE, FEBRUARY 28, 2018	709,568	$	710	51,532,364	$	51,532	$	22,997,759	$	(38,334,383)	$	(15,284,382)
Net loss	-		-	-		-		-		(708,663)		(708,663)
BALANCE, MAY 31, 2018	709,568		710	51,532,364		51,532		22,997,759		(39,043,046)		(15,993,045)
Net loss	-		-	-		-		-		(621,542)		(621,542)
BALANCE, AUGUST 31, 2018	709,568	$	710	51,532,364	$	51,532	$	22,997,759	$	(39,664,588)	$	(16,614,587)

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

5

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows – Unaudited

	Six Months Ended
	August 31, 2019		August 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(422,534)	$	(1,330,205)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion, amortization and impairment expense		30,922		37,525
Amortization of debt discount		215,129		7,269
Operating lease expense in conjunction with right of use asset		3,698		-
Changes in assets and liabilities:
Accounts receivable – crude oil sales		(19,272)		(20,176)
Accounts receivable - joint interest participants		7,231		5,348
Prepaid expenses and other current assets		12,671		10,773
Accounts payable and other accrued liabilities		24,730		(13,062)
Accounts payable - related parties		74,491		124,081
Operating lease liability in conjunction with right of use asset		(3,698)		-
Accrued interest		40,739		1,120,504
Net cash used in operating activities		(35,893)		(57,943)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to crude oil properties		-		(12,227)
Net cash used in investing activities		-		(12,227)
CASH FLOWS FROM FINANCING ACTIVITIES:
Additions to line of credit		49,000		33,300
Payments on line of credit		(30,000)		(80,000)
Net cash provided by (used in) financing activities		19,000		(46,700)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(16,893)		(116,870)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		30,078		148,564
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	13,185	$	31,694
CASH PAID FOR:
Interest	$	16,702	$	50,752
Income taxes	$	-	$	-
SUPPLEMENTAL CASH FLOW INFORMATION:
Unpaid additions to crude oil properties	$	210	$	-
Non-cash increase to line of credit due to monthly interest	$	15,684	$	15,046
Operating lease – right of use asset and associated liabilities	$	13,787	$	-
Forgiveness of liabilities to related parties	$	1,215,145	$	-
Settlement of related party debt with  production revenue interest	$	250,100	$	-
Common stock issued for settlement of accounts payable		6,000		-

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

6

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.

7

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.

8

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.

At the Company’s East Slopes project in California there is only one buyer available for the purchase of crude oil production.  The Company has no natural gas production in California.  At August 31, 2019 and February 28, 2019 this one customer represented 100.0% of the crude oil sales receivable balance.  If this buyer is unable to resell its products or if they lose a significant sales contract, the Company may incur difficulties in selling its crude oil production.

The Company’s accounts receivable balances from California crude oil sales of $94,682 and $75,410 at August 31, 2019 and February 28, 2019, respectively were from one customer, Plains Marketing; and represent crude oil sales that occurred in August and February 2019, respectively.

Joint interest participant receivables balances of $47,652 and $54,883 at August 31, 2019 and February 28, 2019, 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, 2019 and February 28, 2019 as the joint interest owners have a history of paying their obligations.

NOTE 5 — CRUDE OIL PROPERTIES:

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

	August 31, 2019		February 28, 2019
Proved leasehold costs	$	115,119	$	115,119
Costs of wells and development		2,285,054		2,285,054
Capitalized exploratory well costs		1,341,494		1,341,494
Cost of proved crude oil properties		3,741,667		3,741,667
Accumulated depletion, depreciation, amortization and impairment		(3,113,833)		(3,085,043)
Proved crude oil properties, net	$	627,834	$	656,624
Michigan unproved crude oil properties		55,978		55,768
Total proved and unproved crude oil properties, net	$	683,812	$	712,392

9

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.

NOTE 8 — SHORT-TERM AND LONG-TERM BORROWINGS:

Notes Payable – Related Party

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% Subordinated Notes

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.  The 980,000 warrants held by ten noteholders expired on January 29, 2019.

The Company has informed the Note holders that the payment of principal and final interest will be late and is subject to future financing being completed.  The Notes principal of $565,000 was payable in full at the amended maturity date of the Notes, and has not been paid.  Interest continues to accrue on the unpaid $565,000 principal balance.  The terms of the Notes, state that should the Board of Directors 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.  There was no unamortized debt discount remaining at August 31, 2019 and February 28, 2019.

10

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

	August 31, 2019		February 28, 2019
12% Subordinated Notes	$	315,000	$	315,000
12% Subordinated Notes, related party		250,000		250,000
Total 12% Subordinated Notes balance	$	565,000	$	565,000

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

	August 31, 2019		February 28, 2019
Accrued interest 12% Subordinated Notes	$	41,010	$	21,955
Accrued interest 12% Subordinated Notes – related party		197,424		182,301
Total accrued interest 12% Subordinated Notes	$	238,434	$	204,256

The accrued interest owed on the 12% Subordinated Note to the related party is presented on the Company’s 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, $700,000 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, the Company was able to settle an outstanding balance owed to one of its third-party vendors.  This settlement resulted in a $120,000 note payable issued to the vendor.  Additionally, the Company 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.

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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:

	August 31, 2019		February 28, 2019
Estimated payments of production revenue payable	$	2,616,714	$	2,020,353
Less: unamortized discount		(1,374,897)		(1,243,765)
		1,241,817		776,588
Less: current portion		(97,474)		(247,868)
Net production revenue payable – long term	$	1,144,343	$	528,720

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:

	August 31, 2019
Assets
Operating lease right-of-use assets, beginning balance	$	13,787
Current period amortization		(3,698)
Total operating lease right-of-use asset	$	10,089
Liabilities
Operating lease liability - current	$	8,624
Operating lease liability - long-term		1,465
Total lease liabilities	$	10,089

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

Fiscal Year Ended	Annual Office Lease Obligation
February 29, 2020	$	4,650
February 28, 2021		6,200
Total lease payments		10,850
Less: imputed interest		761
Operating lease liability		10,089
Less: operating lease liability - current		8,624
Operating lease liability, long-term	$	1,465

Rent expense for the six months ended August 31, 2019 and 2018 was $11,745, respectively.

NOTE 10 — STOCKHOLDERS’ DEFICIT:

Preferred Stock

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.

Series A Convertible Preferred Stock

The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as Series A Convertible Preferred Stock (“Series A Preferred”), with a $0.001 par value.  At August 31, 2019 and February 28, 2019, there were 709,568 shares issued and outstanding, respectively, that had not been converted into our common stock.  As of August 31, 2019, 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 are set forth in the table below.

Fiscal Period Ended	Shares of Series A Preferred Converted to Common Stock	Shares of Common Stock Issued from Conversion	Number of Accredited Investors
Periods prior to February 29, 2014	662,200	1,986,600	41
February 28, 2015	3,000	9,000	1
February 29, 2016	10,000	30,000	1
February 28, 2017	-	-	-
February 28, 2018	14,997	44,991	1
February 28, 2019	-	-	-
August 31, 2019	-	-	-
Totals	690,197	2,070,591	44

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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:

Fiscal Period Ended	Shareholders at Period End	Accumulated Dividends
Periods prior to February 28, 2014		$	1,447,943
February 28, 2015	58		132,634
February 29, 2016	57		130,925
February 28, 2017	57		130,415
February 28, 2018	56		128,231
February 28, 2019	56		127,714
August 31, 2019	56		64,382
		$	2,162,244

Common Stock

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value common stock of which 53,532,364 and 51,532,364 shares were issued and outstanding as of August 31, 2019 and February 28, 2019, respectively.

	Common Stock Balance	Par Value
Common stock, Issued and Outstanding, February 28, 2018	51,532,364
Conversion of Series A Convertible Preferred Stock to common stock	-	$	-
Common stock, Issued and Outstanding, February 28, 2019	51,532,364
Issuance of common stock to settle accounts payable	2,000,000	$	2,000
Common stock, Issued and Outstanding, August 31, 2019	53,532,364

NOTE 11 — INCOME TAXES:

On December 22, 2017, the federal government enacted a tax bill H.R.1, an act to provide for reconciliation pursuant to Titles II and V of the concurrent resolution on the budget for fiscal year 2018, commonly referred to as the Tax Cuts and Jobs Act.  The Tax Cuts and Jobs Act contains significant changes to corporate taxation, including, but not limited to, reducing the U.S. federal corporate income tax rate from 35% to 21% and modifying or limiting many business deductions.  The Company has re-measured its deferred tax liabilities based on rates at which they are expected to be utilized in the future, which is generally 21%.

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:

	August 31, 2019		February 28, 2019
Computed at U.S. and state statutory rates	$	(126,084)	$	3,035,442
Permanent differences		65,013		25,116
New tax law adjustment		-		-
Changes in valuation allowance		61,071		(3,060,558)
Total	$	-	$	-

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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:

	August 31, 2019		February 28, 2019
Deferred tax assets:
Net operating loss carryforwards	$	5,417,142	$	5,361,767
Crude oil properties		43,933		38,237
Stock based compensation		66,187		66,187
Other		27,838		27,838
Less valuation allowance		(5,555,100)		(5,494,029)
Total	$	-	$	-

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 12 — COMMITMENTS AND CONTINGENCIES:

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

The Company, as an owner or lessee and operator of crude oil 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 a crude oil 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, 2019.  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 crude oil properties.

NOTE 13 — SUBSEQUENT EVENTS:

On October 8, 2019, the Company executed an investor relations consulting agreement with an unrelated third-party that replaced a prior investor relations consulting agreement.  The new agreement requires the Company to deliver previously agreed upon 2.1 million warrants with an exercise price of $0.01 per share, a three-year vesting period and adds an expiration date of January 2, 2024 for the warrants.  The new agreement also includes an exercise blocker provision.  

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

The following discussion is management’s assessment of the current and historical financial and operating results of the Company and of our financial condition.  It is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q for the six months ended August 31, 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.

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

·

Our future operating results;

·

Our future capital expenditures;

·

Our future financing;

·

Our expansion and growth of operations; and

·

Our future investments in and acquisitions of crude oil properties.

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

·

General economic and business conditions;

·

Exposure to market risks in our financial instruments;

·

Fluctuations in worldwide prices and demand for crude oil;

·

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

·

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

·

Risks associated with crude oil exploration and development activities;

·

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

·

Technological changes and developments in the crude oil industry;

·

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

·

Our ability to continue as a going concern;

·

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

·

Other factors discussed elsewhere in this Form 10-Q; 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, 2019 and in this Form 10-Q for the six months ended August 31, 2019 occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  We specifically undertake no obligation to publicly update or revise any information contained in any forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except as required by law.

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

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Introduction and Overview

We are an independent 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.

Our management cannot provide any assurances that Daybreak will ever operate profitably.  While we have positive cash flow from our continuing crude oil operations in California, we have not yet generated sustainable positive cash flow or 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, 2019 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, 2019 for more information on our California project and exploratory joint drilling project in Michigan.

Kern County, California (East Slopes Project)

The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California.  Drilling targets are porous and permeable sandstone reservoirs 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 in the Vedder Sand is considered heavy oil.  The gravity of the crude oil ranges from 14° to 16° API (American Petroleum Institute) 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, 2019 we had production from 20 vertical crude oil wells.  Our average working interest (“WI”) and net revenue interest (“NRI”) in these 20 wells is 36.6% and 28.4%, respectively.

We plan on acquiring additional acreage 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.

California Drilling Plans

Planned drilling activity and implementation of our oilfield development plan will not begin until financing is put in place.  We do not plan to make any capital investments within the East Slopes Project area in the 2020 fiscal year if no new financing is in place.  If new financing is secured, we plan to spend approximately $525,000 drilling four development wells in the 2020 fiscal year.

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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.

Encumbrances

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.  As of August 31, 2019, we had no encumbrances on our crude oil project in Michigan.

Results of Operations – Six months ended August 31, 2019 compared to the six months ended August 31, 2018

California Crude Oil Prices

The price we receive for crude oil sales in California is based on prices posted for Midway-Sunset crude oil delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs.  The posted Midway-Sunset price generally moves in correlation to, and at a discount to, prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma delivery contracts.  We do not have any natural gas revenues in California.

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.

A comparison of the average WTI price and average realized crude oil sales price for the six months ended August 31, 2019 and 2018 is shown in the table below:

	Six Months Ended
	August 31, 2019		August 31, 2018		Percentage Change
Average six month WTI crude oil price (Bbl)	$	58.28	$	67.65	(13.9%)
Average six month realized crude oil sales price (Bbl)	$	61.98	$	67.39	(8.03%)

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.

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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.

The gravity of our produced crude oil in California ranges between 14° API and 16° API.  Production for the six months ended August 31, 2019 was from 20 wells resulting in 3,630 well days of production in comparison to 3,677 well days of production for the six months ended August 31, 2018.

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

	Six Months Ended August 31, 2019			Six Months Ended August 31, 2018
Project	Revenue		Percentage	Revenue		Percentage
California – East Slopes Project	$	359,413	100.0%	$	393,703	100.0%

*Our average realized sale price on a BOE basis for the six months ended August 31, 2019 was $61.98 in comparison to $67.39 for the six months ended August 31, 2018, representing a decrease of $5.41 or 8.0% per barrel.

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:

	Six Months Ended August 31, 2019					Six Months Ended August 31, 2018
	Expenses		Percentage	BOE Basis		Expenses		Percentage	BOE Basis
Production expenses	$	89,543	17.6%			$	74,556	13.3%
Exploration and drilling expenses		114	0.0%				992	0.2%
Depreciation, depletion, amortization (“DD&A”)		30,922	6.1%				37,525	6.7%
General and administrative (“G&A”) expenses		388,433	76.3%				447,370	79.8%
Total operating expenses	$	509,012	100.0%	$	87.78	$	560,443	100.0%	$	95.93

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.

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.  For the six months ended August 31, 2019, these expenses decreased $878 to $114 in comparison to $992 the six months ended August 31, 2018.  Exploration and drilling expenses represented 0.0% and 0.2% of total operating expenses for the six months ended August 31, 2019 and 2018, respectively.

Depreciation, depletion and amortization (“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, 2019, DD&A expenses decreased $6,603 or 17.6% to $30,922 in comparison to $37,525 for the six months ended August 31, 2018.  On a BOE basis, DD&A expense was $5.33 and $6.42 for the six months ended August 31, 2019 and 2018, respectively.  DD&A expenses represented 6.1% and 6.7% 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

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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.

Results of Operations – Three months ended August 31, 2019 compared to the three months ended August 31, 2018

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, 2019 and 2018 is shown in the table below:

	Three Months Ended
	August 31, 2019		August 31, 2018		Percentage Change
Average three month WTI crude oil price (Bbl)	$	55.61	$	68.97	(19.4%)
Average three month realized crude oil sales price (Bbl)	$	58.78	$	68.69	(14.4%)

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:

	Three Months Ended August 31, 2019			Three Months Ended August 31, 2018
Project	Revenue		Percentage	Revenue		Percentage
California – East Slopes Project	$	163,055	100.0%	$	216,770	100.0%

*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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Operating Expenses

Total operating expenses for the three months ended August 31, 2019 were $203,163, a decrease of $53,592 or 20.9% compared to $256,755 for the three months ended August 31, 2018.  Operating expenses for the three months ended August 31, 2019 and 2018 are set forth in the table below:

	Three Months Ended August 31, 2019					Three Months Ended August 31, 2018
	Expenses		Percentage	BOE Basis		Expenses		Percentage	BOE Basis
Production expenses	$	45,826	22.6%			$	31,749	12.4%
Exploration and drilling expenses		16	0.0%				863	0.3%
Depreciation, depletion, amortization (“DD&A”)		14,856	7.3%				20,235	7.9%
General and administrative (“G&A”) expenses		142,465	70.1%				203,908	79.4%
Total operating expenses	$	203,163	100.0%	$	73.24	$	256,755	100.0%	$	81.33

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.

Interest expense, net for the three months ended August 31, 2019 decreased $462,716 or 79.6% to $118,841 in comparison to $581,557 for the three 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.

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.

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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:

					Increase		Percentage
	August 31, 2019		February 28, 2019		(Decrease)		Change
Cash	$	13,185	$	30,078	$	(16,893)	(56.2%)
Current Assets	$	166,024	$	183,547	$	(17,523)	(9.5%)
Total Assets	$	876,377	$	912,391	$	(36,014)	(3.9%)
Current Liabilities	$	(3,892,218)	$	(5,346,063)	$	(1,453,845)	(27.2%)
Total Liabilities	$	(5,189,753)	$	(6,024,378)	$	(834,625)	(13.9%)
Working Capital Deficit	$	(3,726,194)	$	(5,162,516)	$	(1,436,322)	(27.8%)

Our working capital deficit decreased approximately $1.4 million or 27.8% to approximately $3.7 million at August 31, 2019 in comparison to approximately $5.2 million at February 28, 2019.  The decrease in our working capital deficit was due to the settlement of accounts payable owed to related parties through a debt forgiveness program.

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.  While we have positive cash flow from our operations in California, 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 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 volatility in the credit and capital markets as well as the decline in crude oil prices from June of 2014 price levels 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.

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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 Flows

Changes in the net funds provided by and (used in) our operating, investing and financing activities are set forth in the table below:

	Six Months Ended August 31, 2019		Six Months Ended August 31, 2018		Increase (Decrease)		Percentage Change
Net cash (used in) operating activities	$	(35,893)	$	(57,943)		(22,050)	(38.1%)
Net cash (used in ) investing activities	$	-	$	(12,227)		12,227	100.0%
Net cash provided by (used in) financing activities	$	19,000	$	(46,700)		65,700	140.7%

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.

Cash Flow Provided By (Used In) Financing Activities

Cash flow from financing activities is derived from changes in long-term liability account balances or in equity account balances, excluding retained earnings.  Cash flow provided by our financing activities was $19,000 for the six months ended August 31, 2019 in comparison to cash flow used in our financing activities of $46,700 for the six months ended August 31, 2018.  This increase of $65,700 provided by our cash flow activities was primarily due to an additional cash advances received from our UBS line of credit.  For the six months ended August 31, 2019, we made total payments of $30,000 to our line of credit with UBS Bank.

The following discussion is a summary of cash flows provided by, and used in, the Company’s financing activities at August 31, 2019.

Current debt (Short-term borrowings)

Related Party Notes

The Company’s Chairman, President and Chief Executive Officer had previously loaned us an aggregate $250,100 that was used for a variety of corporate purposes.  In connection with its debt reduction efforts, we entered into a Note Payoff Agreement with this related party.  Pursuant to the Note Payoff Agreement, we issued as payment in full under the Notes, a production payment interest in certain of our 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 we have 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% Subordinated Notes

Our 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 us and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th.  On January 29, 2015, we 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.  The 980,000 warrants held by ten noteholders expired on January 29, 2019.

We have informed the Note holders that the payment of principal and final interest will be late and is subject to future financing being completed.  The Notes principal of $565,000 was payable in full at the amended maturity date of the Notes, and has not been paid.  Interest continues to accrue on the unpaid $565,000 principal balance.  The terms of the Notes, state that should the Board of Directors decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, we may then elect a mandatory conversion of the unpaid principal and interest into our common stock at a conversion rate equal to 75% of the average closing price of our common stock over the 20 consecutive trading days preceding December 31, 2018.  There was no unamortized debt discount remaining at August 31, 2019 and February 28, 2019.

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

	August 31, 2019		February 28, 2019
12% Subordinated Notes	$	315,000	$	315,000
12% Subordinated Notes, related party		250,000		250,000
Total 12% Subordinated Notes balance	$	565,000	$	565,000

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

	August 31, 2019		February 28, 2019
Accrued interest 12% Subordinated Notes	$	41,010	$	21,955
Accrued interest 12% Subordinated Notes – related party		197,424		182,301
Total accrued interest 12% Subordinated Notes	$	238,434	$	204,256

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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:

	August 31, 2019		February 28, 2019
Estimated payments of production revenue payable	$	2,616,714	$	2,020,353
Less: unamortized discount		(1,374,897)		(1,243,765)
		1,241,817		776,588
Less: current portion		(97,474)		(247,868)
Net production revenue payable – long term	$	1,144,343	$	528,720

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:

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)	-

⁽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.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.  CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the three months ended August 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Limitations

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

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

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

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PART II

OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

None

ITEM 1A.  RISK FACTORS

In addition to the other information set forth in this 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, 2019, 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.

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ITEM 6.  EXHIBITS

The following Exhibits are filed as part of the report:

Exhibit

Number

Description

10.1⁽¹⁾

Consulting Agreement by and between Daybreak Oil and Gas, Inc., and Bear to Bull Investor Relations, LLC, dated October 8, 2019.

31.1⁽¹⁾

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

32.1⁽¹⁾

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

101.INS⁽²⁾

XBRL Instance Document

101.SCH⁽²⁾

XBRL Taxonomy Schema

101.CAL⁽²⁾

XBRL Taxonomy Calculation Linkbase

101.DEF⁽²⁾

XBRL Taxonomy Definition Linkbase

101.LAB⁽²⁾

XBRL Taxonomy Label Linkbase

101.PRE⁽²⁾

XBRL Taxonomy Presentation Linkbase

⁽¹⁾

Filed herewith.

⁽²⁾

Furnished herewith

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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 11, 2019

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