UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended February 28, ~~2022~~2023

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.~~IRS Employer Identification No.)
1101 N. Argonne Road, Suite A-211, Spokane Valley, WA		99212
1414 S. Friendswood Drive, Suite 212, Friendswood, TX		77546
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (~~509~~281) ~~232~~996-~~7674~~4176

Securities registered pursuant to Section 12(b) of the Exchange Act: None

Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, $0.001 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

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. Yes þ No ¨

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

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

Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer þ	Smaller reporting company ☑
			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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262 (b)) by the registered public accounting firm that prepared or issued its audit report. ¨

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ¨

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to Section 240.10D-1(b). ¨

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

The aggregate market value of the voting and non-voting stock held by non-affiliates of the registrant, based on the closing price of $0.~~035~~05 on August 31, ~~2021~~2022, as reported by the OTC Pink® Open Market was $12,~~810~~821,~~516~~727.

At ~~June 14,~~January ~~2022~~23, 2024, the registrant had 384,~~735~~734,~~402~~902 outstanding shares of $0.001 par value Common ~~common stock~~Stock.

DOCUMENTS INCORPORATED BY REFERENCE:

Part III of the Form 10-K incorporates by reference certain portions of the registrant’s proxy statement for its 2022 Annual Meeting of Shareholders to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this report.

TABLE OF CONTENTS

		PAGE
PART I		4
ITEM 1.	BUSINESS	4
ITEM 1A.	RISK FACTORS	1013
ITEM 1B.	UNRESOLVED STAFF COMMENTS	2126
ITEM 2.	PROPERTIES	2227
ITEM 3.	LEGAL PROCEEDINGS	2935
ITEM 4.	MINE SAFETY DISCLOSURES	2935
PART II		3036
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	3036
ITEM 6.	[RESERVED]	3442
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	3543
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	5060
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	5161
	Report of Independent Registered Public Accounting Firm (PCAOB ID: 206)	5161
	Balance Sheets as of February 28, 2022 and February 28, 2021	52
	Balance Sheets as of February 28, 2023 and February 28, 2022	62
	Statements of Operations for the Years Ended February 28, 2022 and February 28, 2021	53
	Statements of Operations for the Years Ended February 28, 2023 and February 28, 2022	63
	Statements of Changes in Stockholders’ Deficit for the Years Ended February 28, 2022 and February 28, 2021	54
	Statements of Changes in Stockholders’ Equity (Deficit) for the Years Ended February 28, 2023 and February 28, 2022	64
	Statements of Cash Flows for the Years Ended February 28, 2022 and February 28, 2021	55
	Statements of Cash Flows for the Years Ended February 28, 2023 and February 28, 2022	65
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	7687
ITEM 9A.	CONTROLS AND PROCEDURES	7787
ITEM 9B.	OTHER INFORMATION	7888
ITEM 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	7888
PART III		7989
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE	7989
ITEM 11.	EXECUTIVE COMPENSATION	7995
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	79101
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	79104
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	79107
PART IV		80108
ITEM 15.	EXHIBITS, AND FINANCIAL STATEMENT SCHEDULES	80108
ITEM 16.	FORM 10-K SUMMARY	83111
SIGNATURES		84112
GLOSSARY OF TERMS		85113

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This ~~annual~~Annual ~~report~~Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, contained in this Annual Report that include information concerning our possible or assumed future results of operations, business strategies, need for financing, competitive position and potential growth opportunities represent management’s belief and assumptions based on currently available information and they do not consider the effects of future legislation or regulations. Forward-looking statements include statements relating to future events or our future financial or operating performance, including statements regarding guidance, industry prospects or future results of operations or financial position, made in this Annual Report on Form 10-K. These forward-looking statements are based on our current expectations, assumptions, estimates and projections for the future of our business and our industry and are not statements of historical fact. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will” and similar expressions identify forward-looking statements. Examples of forward-looking statements include statements about the following:

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 and natural gas properties.

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

General economic and business conditions;

National and international pandemic such as the novel coronavirus COVID-19 outbreak;

Exposure to market risks in our financial instruments;

Fluctuations in worldwide prices and demand for crude oil and natural gas;

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

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

Changes to our reserve estimates or the recovery of crude oil and natural gas quantities that is less than our reserve estimates;

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

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

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

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

Our ability to 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-K; in our other public filings and press releases; and discussions with Company management.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. These risks and uncertainties, as well as other risks and uncertainties that could cause our actual results to differ significantly from management’s expectations, are described in greater detail in Item 1A of Part 1, “Risk Factors”. We specifically undertake no obligation to publicly update or revise any information contained in a 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.

PART I

ITEM 1. BUSINESS

Historical Background

Daybreak Oil and Gas, Inc. (referred to herein as “we,” “our,” “us,” “Daybreak” or the “Company”) was originally incorporated in the State of Washington on March 11, 1955 as Daybreak Uranium, Inc. The Company was organized to explore for, acquire and develop mineral properties throughout the Western United States. In August 1955, we acquired the assets of Morning Sun Uranium, Inc. By the late 1950’s, we ceased to be a producing mining company and thereafter engaged in mineral exploration only. In May 1964, to reflect the diversity of our mineral holdings, we changed our name to Daybreak Mines, Inc. By February 1967, we had ceased all exploration operations. After that time, our activities were confined to annual assessment and maintenance work on our Idaho mineral properties and other general and administrative functions. In November 2004, we sold our last remaining mineral rights covering approximately 340 acres in Shoshone County, Idaho.

Effective March 1, 2005, we undertook a new business direction for the Company; that of an exploration, development and production company in the crude oil and natural gas industry. In October of 2005, to better reflect this new direction of the Company, our shareholders approved changing our name to Daybreak Oil and Gas, Inc. Our Common Stock is quoted on the ~~OTC~~OTCMarkets ~~Pink® Open Market~~ under the symbol DBRM in the Expert Market.

Our corporate office is located at ~~1101 N. Argonne Road, Suite A-211, Spokane Valley, Washington 99212-2699. Our telephone number is (509) 232-7674. Additionally, we have a regional operations office located at~~ 1414 S. Friendswood Dr., Suite 212, Friendswood, Texas 77546. The telephone number of our office in Friendswood is (281) 996-4176.

Market Conditions, Commodity Prices, and Interest Rates

Commodity prices experienced continued volatility during 2022 - 2023 fiscal year due to ongoing geopolitical events and fluctuating supply/demand factors. In addition, global markets experienced supply shortages and corresponding significant inflation across a wide variety of products, services, and wages. As a result, the U.S. Federal Reserve and other international central banks began tightening monetary policies during this period, including increasing short-term borrowing rates. This changing monetary policy has impacted credit and capital markets with generally increased costs of borrowing and heightened volatility in capital markets. Any downward volatility in the price of crude oil and natural gas will have a prolonged and substantial negative impact on our profitability and cash flow from our producing California properties. It is beyond our ability to accurately predict crude oil prices over any substantial length of time.

Crude Oil and Natural Gas Overview

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

Our long-term success depends on, among many other factors, the acquisition and drilling of commercial grade crude oil and natural gas properties and on the prevailing sales price for crude oil and natural gas along with controlling the 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 periods of market volatility, such as we have experienced ~~since~~ ~~June~~in ofthe ~~2014~~last two years, will and does have a material adverse effect on our results of operations and financial condition.

The Company’s focus is to pursue crude oil and natural gas drilling opportunities through joint ventures with industry partners as a means of limiting our drilling risk. Prospects are generally brought to us by other crude oil and natural gas companies or individuals. We identify and evaluate prospective crude oil and natural gas properties to determine both the degree of risk and the commercial potential of the project. We seek projects that offer a mix of low risk with a potential of steady reliable revenue as well as projects with a higher risk, but that may also have a larger return.

Modern technology including 3-D seismic helps us identify potential crude oil and natural gas reservoirs and to mitigate our risk. The Company conducts 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. We seek to maximize the value of our asset base by exploring and developing properties that have both production and reserve growth potential. Currently, our core areas of activity are located in Kern County, California and Michigan, although new opportunities may ultimately be secured in other areas.

In some instances, such as with our California crude oil operations, we strive to be the operator of our crude oil and natural gas properties. As the operator, we are more directly in control of the timing; costs of drilling and completion; and production operations on our projects. We are compensated by our other working interest partners for the additional duties performed by Daybreak as operator. In other instances, we may not serve as operator where we have concluded that the existing operator has existing operational knowledge, equipment and personnel in place, and operates competently and prudently and with the same operational goals that we would have if we served as operator. However, we have our own personnel onsite during critical operations such as drilling, fracturing and completion operations.

Modern technology including 3-D seismic helps us identify potential crude oil and natural gas reservoirs and to mitigate our risk. The Company conducts 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. We seek to maximize the value of our asset base by exploring and developing properties that have both production and reserve growth potential. Currently, our core areas of activity are in the counties of Kern, Monterey and Contra Costa located in the Central Valley or San Francisco Bay area of California, although new opportunities may ultimately be secured in other areas.

In some instances, we strive to be the operator of our crude oil and natural gas properties. As the operator, we are more directly in control of the timing; costs of drilling and completion; and production operations on our projects. We are compensated by our other working interest partners for the additional duties performed by Daybreak as operator. In other instances, we may not serve as operator where we have concluded that the existing operator has existing operational knowledge, equipment and personnel in place, and operates competently and prudently and with the same operational goals that we would have if we served as operator. However, we have our own personnel onsite during critical operations such as any drilling, fracturing and completion operations.

Acquisition of Reabold Subsidiary in May 2022

On May 25, 2022, the Company finalized the acquisition of Reabold California, LLC (“Reabold”) from a third party for 160,964,489 shares of the Company’s Common Stock valued at $6,599,544 and cash consideration of $263,619. As Operator, Reabold has a 50% working interest and 40% net revenue interest in 10 producing or shut-in wells in Monterey and Contra Costa Counties in the Sacramento Basin of California. The acquisition of Reabold was approved at a Special Meeting of Shareholders held on May 20, 2022. Approximately 82% or 51,054,229 shares of the Company’s 62,510,204 issued and outstanding shares of the Company’s Common Stock were present or represented by proxy at the meeting. The proposal for the Reabold acquisition was passed with over a 99.6% approval vote.

Known Trends and Uncertainties

As we continue to pursue our two developmental drilling ~~program~~programs in our California properties, the timing of these activities continues to be determined by current crude oil and natural gas prices; the availability of drilling funds; and in California, the length and timing of the drilling permit approval process including other regulatory approval regulations as described below in the section titled “Regulation”. Additionally, our drilling programs are also very sensitive to drilling costs. We attempt to control these costs through drilling efficiencies by working with service providers to receive acceptable unit costs.

In order to continue our ~~drilling~~two ~~program~~oilfield inprojects in California, we must be able to realize an acceptable margin between our expected cash flows from new production and the cost to drill and complete new wells. If any combination of a decrease in crude oil and natural gas prices; the availability of drilling funds; and/or, the rising costs of drilling, completion and other field services occurs in future periods, we may be forced to modify or discontinue a planned drilling program.

All of ~~the~~our ~~Company’s~~ crude oil and natural gas production in California 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 hydrocarbon prices and demand for crude oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. Some of these factors include the level of global demand for and price of petroleum products, foreign supply of crude oil and natural gas, the establishment of and compliance with production quotas by oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. Because of the size of our Company, we are highly susceptible to downward changes in the price we receive for our hydrocarbon sales especially crude oil.

California Crude Oil Prices

The ~~price~~prices we receive for crude oil sales in California isfrom our Kern County, California, “East Slopes” project and from our wholly owned Reabold subsidiary are based on prices posted for Midway-Sunset and Buena Vista crude oil delivery contracts, ~~less~~respectively. ~~deductions~~All posted pricing is subject to adjustments that vary by grade of crude oil, ~~sold~~transportation costs, market differentials and ~~transportation costs~~other local conditions. ~~The~~Both the posted Midway-Sunset ~~price~~and Buena Vista prices generally ~~moves~~move in correlation to, ~~and at a discount to,~~ prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas ~~Intermediate~~ intermediate (“WTI”) crude oil, Cushing, Oklahoma delivery contracts. ~~We do not currently have any natural gas revenues.~~

There continues to be a significant amount of volatility in hydrocarbon prices and a corresponding fluctuation in our realized sale price of crude oil does exist. An example of this is that in June of 2014 the monthly average price of WTI oil was $105.79 per barrel and our realized price per barrel of crude oil was $98.78 while in April 2020, the monthly average price of WTI crude oil was $16.55 and our monthly realized price was $16.96 per barrel. Finally, in February 2022, the monthly average price of WTI oil was $91.64 per barrel and our realized price per barrel of crude oil was $87.41. Any downward volatility in the price of crude oil will have a substantial negative impact on our profitability and cash flow from our producing California properties. It is beyond our ability to accurately predict crude oil prices over any substantial length of time. There are many factors beyond our control that influence the price we receive on our crude oil sales.

A comparison of the average WTI price and average realized crude oil sales price at our East Slope Project in California for the twelve months ended February 28, 2022 and February 28, 2021 is shown in the table below:

	Twelve Months Ended
	February 28, 2022		February 28, 2021		Percentage Change
Average twelve month WTI crude oil price	$	73.31	$	39.48		85.7	%
Average twelve month realized crude oil sales price (Bbl)	$	70.75	$	36.91		91.7	%

For the twelve months ended February 28, 2022, the average WTI price was $73.31 and our average realized crude oil sale price was $70.75, representing a discount of $2.56 per barrel or 3.5% lower than the average WTI price. In comparison, for the twelve months ended February 28, 2021, the average WTI price was $39.48 and our average realized sale price was $36.91 representing a discount of $2.57 per barrel or 6.5% lower than the average WTI price. Historically, the sale price we receive for California heavy crude oil has been less than the quoted NYMEX WTI price because of the lower API gravity of our California crude oil in comparison to WTI crude oil API gravity.

A comparison of the average WTI price and average realized crude oil sales price for the twelve months ended February 28, 2023 and February 28, 2022 is shown in the table below:

	Twelve Months Ended
	February 28, 2023		February 28, 2022		Percentage Change
Average twelve-month WTI crude oil price	$	93.13	$	73.31		27.0	%
Average twelve month realized crude oil sales price (Bbl)	$	89.59	$	70.75		26.6	%

For the twelve months ended February 28, 2023, the average WTI price was $93.13, and our average realized crude oil sale price was $89.59, representing a discount of $3.54 per barrel or 3.8% lower than the average WTI price. In comparison, for the twelve months ended February 28, 2022, the average WTI price was $73.31, and our average realized sale price was $70.75 representing a discount of $2.56 per barrel or 3.5% lower than the average WTI price. Historically, the sale price we receive for our East Slopes heavy crude oil has been less than the quoted NYMEX WTI price because of the lower API gravity of our East Slopes crude oil in comparison to quoted WTI crude oil API gravity.

California Crude Oil Revenue and Production

Crude oil revenue in California for the twelve months ended February 28, ~~2022~~2023 increased $~~275~~853,~~206~~153 or 68125.04% to $~~680~~1,~~107~~533,260 in comparison to revenue of $~~404~~680,~~901~~107 for the twelve months ended February 28, ~~2021~~2022. The average sale price of a barrel of crude oil for the twelve months ended February 28, ~~2022~~2023 was $7089.7559 in comparison to $3670.9175 for the twelve months ended February 28, ~~2021~~2022. The increase of $3318.84 or 9126.76% per barrel in the average realized price of a barrel of crude oil accounted for ~~134~~21.92% of the increase in crude oil revenue for the twelve months ended February 28, ~~2022~~2023.

Our net sales volume for the twelve months ended February 28, ~~2022~~2023 was 917,~~613~~114 barrels of crude oil in comparison to 109,~~970~~613 barrels sold for the twelve months ended February 28, ~~2021~~2022. ~~This~~The ~~decrease~~increase in crude oil sales volume of 17,~~357~~501 barrels or 1278.40% was primarily due to ~~fewer~~the ~~well~~Reabold ~~days~~subsidiary acquisition in May of ~~production~~2022 and ~~the~~this ~~natural~~overall increase ~~decline~~in crude oil sales volume accounted for 78.8% of the increase in ~~reservoir pressure~~crude ~~during~~oil revenue for the twelve months ended February 28, ~~2021~~2023.

The gravity of our produced crude oil infrom ~~California~~the East Slopes project in Kern County ranges between 1415° API and 1617° API. Production for the twelve months ended February 28, 2023 and February 28, 2022 was from 20 wells. ~~resulting~~The ingravity ~~7,154 well~~of ~~days~~our ofproduced ~~production~~crude oil from our Reabold subsidiary in ~~comparison~~Monterey toand ~~7,288~~Contra ~~well~~Costs ~~days~~Counties is ofapproximately ~~production~~17° ~~from~~API 20and ~~wells~~38° API, respectively. Production for the twelve months ended February 28, ~~2021~~2023 was primarily from five wells.

California Natural Gas Prices

The price we receive for natural gas sales from our Reabold project is based on ninety-five percent (95%) of the price published in Natural Gas Intelligence (“NGI”) Gas Price Index under the column “Bidweek Averages” for “California”, “PG&E Citygate” less an amount per MMBtu equal to the Silverado Path On System As-Available transport date, less the Silverado Path On System transmission shrinkage rate for Silverado. The price we receive is generally higher than and moves in correlation to prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot Henry Hub natural gas prices. We only have natural gas production from our Reabold subsidiary wells that are located in Contra Costa County in California.

	Twelve Months Ended
	February 28, 2023		February 28, 2022		Percentage Change
Average twelve month Henry Hub natural gas price (Mcf)	$	6.35	$	—		100	%
Average twelve month realized natural gas sales price (Mcf)	$	20.94	$	—		100	%

For the twelve months ended February 28, 2023 the average price per Mcf (1,000 cubic feet) that we received was $20.94 while the average monthly price per Mcf for spot Henry Hub prices was $6.35 for the same twelve month period. The large disparity in the two prices over the twelve-month period was largely due to the price per Mcf we received during the three months ended February 28, 2023 when the average price we received per Mcf was $29.79 and the same three month average price per Mcf for Henry Hub prices was $3.86. In January of 2023 the average price per Mcf we received in California was $58.03 while the monthly average Henry Hub price was $3.39 per Mcf.

California Natural Gas Revenue and Production

We only have natural gas production from our Reabold subsidiary wells that are located in Contra Costa County in California. For the twelve months ended February 28, 2023, natural gas revenue increased $80,026 or 100%. Prior to the Reabold acquisition in May 2022, we did not have any natural gas production. The average sales price per Mcf of our natural gas production was $20.94 and our natural gas sales volume was 3,822 Mcf for the twelve months ended February 28, 2023.

California Natural Gas BOE Net Sales Volume

For the twelve months ended February 28, 2023, our BOE net sales volume of natural gas was 637 barrels representing a 100% from the twelve months ended February 28, 2022. We did not have any natural gas sales volume for the twelve months ended February 28, 2022. We only have natural gas production from our Reabold subsidiary located in Contra Costa County in California that was acquired in May of 2022.

Competition

We compete with other independent crude oil and natural gas companies for exploration prospects, property acquisitions and for the equipment and labor required to operate and develop these properties. Many of our competitors have substantially greater financial and other resources than we have. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can.

We conduct all of our drilling, exploration and production activities onshore in the United States. All of our crude oil assets are located in the United States and all of our revenues are from sales to customers within the United States.

Marketing Arrangements – Principal ~~Customer~~Customers

At ~~our~~both ~~East~~of ~~Slopes~~our ~~Project,~~projects ~~located~~ in ~~Kern County,~~ California, we sell all of our crude oil production to one buyer. At February 28, ~~2022~~2023 and February 28, ~~2021~~2022, this one individual customer ~~represented~~ per project represented 100% of crude oil sales receivable. If this local purchaser is unable to resell their products or if they lose a significant sales contract , then we may incur difficulties in selling our crude oil production.

~~The~~At ~~Company’s~~the ~~accounts~~Reabold ~~receivable~~project ~~for~~wells ~~California~~in Contra Costs County, ~~crude~~California ~~oil~~there ~~sales~~is atalso natural gas production that the Company sells to a single buyer. At February 28, 2023, this one individual customer per project represented 100% of natural gas sales receivable. The Company had no natural gas sales before the Reabold acquisition in May of 2022. ~~and~~If ~~February~~this ~~28,~~local ~~2021~~purchaser ~~are~~is ~~set~~unable ~~forth~~to resell their products or if they lose a significant sales contract then we may incur difficulties in ~~the~~selling ~~table~~our ~~below~~natural gas production.

		February 28, 2022					February 28, 2021
Project	Customer	Accounts Receivable Crude Oil Sales		Percentage			Accounts Receivable Crude Oil Sales		Percentage
California – East Slopes Project (Crude oil)	Plains Marketing	$	117,727		100.0	%	$	108,993		100.0	%

The Company’s accounts receivable for California crude oil and natural gas sales at February 28, 2023 and February 28, 2022 are set forth in the table below:

		February 28, 2023					February 28, 2022
Project	Customer	Accounts Receivable		Percentage			Accounts Receivable		Percentage
California – East Slopes project (crude oil)	Plains Marketing	$	55,900		42.5	%	$	117,727		100.0	%
California – Reabold project (crude oil)	Plains Marketing		59,614		45.3	%		—		—
California – Reabold project (natural gas)	CRC		15,996		12.2	%		—		—
Totals		$	131,510		100.0	%	$	117,727		100.0	%

Joint interest participant receivables balances of $353,009 and $85,339 at February 28, 2023 and February 28, 2022, respectively, represent amounts due from working interest partners in the East Slopes and Reabold projects. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2023 and February 28, 2022.

Title to Properties

As is customary in the crude oil and natural gas industry, we make only a cursory review of title to undeveloped crude oil and natural gas leases at the time we acquire them. However, before drilling operations commence, we search the title, and remedy material defects, if any, before we actually begin drilling the well. To the extent title opinions or other investigations reflect title defects, we (rather than the seller or lessor of the undeveloped property) typically are obligated to cure any such title defects at our expense. If we are unable to remedy or cure any title defects, so that it would not be prudent for us to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. Except for encumbrances we have granted as described below under “Encumbrances,” we believe that we have good title to our crude oil and natural gas properties, some of which are subject to immaterial easements, and restrictions.

Regulation

The exploration and development of crude oil and natural gas properties are subject to various types of federal, state and local laws and regulations. These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, hydraulic fracturing operations, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and specific requirements for the operation of wells. Government actions, including the issuance of certain permits or approvals, by state and local agencies or by federal agencies may be subject to environmental reviews, respectively, under the California Environmental Quality Act (“CEQA”) or the National Environmental Policy Act (“NEPA”), which may result in delays, imposition of mitigation measures or litigation. Failure to comply with such laws and regulations can result in substantial penalties.

Laws and regulations relating to our business frequently change so we are unable to predict the future cost or impact of complying with such laws. Future laws and regulations, including changes to existing laws and regulations, could adversely affect our business. These regulatory burdens generally do not affect us any differently than they affect other companies in our industry with similar types, quantities, and locations of production.

All of the states in which we ~~operate~~have ~~generally~~operated require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of crude oil and natural gas. Such states ~~also~~ have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum rates of production from crude oil and natural gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring of natural gas and requirements regarding the ratability of production. These laws and regulations may limit the amount of crude oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of crude oil and natural gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.

~~These~~The ~~laws~~California ~~and~~Geologic ~~regulations~~Energy Management ~~may~~Division ~~limit~~(“CalGEM”) of the ~~amount~~Department of Conservation is California's primary regulator of the crude oil and natural gas weproduction ~~can~~industry ~~produce~~on ~~from~~private ~~our~~and ~~wells~~state ~~and~~lands, ~~may~~with ~~limit~~additional ~~the~~oversight ~~number~~from ofthe ~~wells~~State orLands ~~the~~Commission’s ~~locations~~administration atof state ~~which~~surface weand ~~can~~mineral ~~drill~~interests. ~~Moreover~~In California, ~~many~~ ~~states~~we ~~impose~~currently operate a ~~production~~20 orwell ~~severance~~crude ~~tax~~oil ~~with~~project ~~respect~~in toKern ~~the~~County ~~production~~ and ~~sale~~a of10 ~~crude~~well crude oil and natural gas ~~within~~project ~~their~~in ~~jurisdiction~~Monterey and Contra Costa Counties. A variety of factors outside of our control can lead to our obtaining ~~States~~drilling dopermits from CalGEM for our operations. CalGEM has not ~~generally~~issued ~~regulate~~any ~~wellhead~~permits ~~prices~~for ornew ~~engage~~production wells to any operators since December 2022. CalGEM currently requires an operator to identify the manner in ~~other~~which the CEQA has been satisfied prior to issuing various state permits, ~~similar~~typically ~~direct~~through ~~economic~~either ~~regulation~~an ofenvironmental ~~production~~review or an exemption by a state or local agency. In Kern County, ~~but~~this ~~there~~requirement ~~can~~has betypically been satisfied by complying with the local crude oil and natural gas ordinance which was supported noby ~~assurance~~an ~~they~~Environmental ~~will~~Impact ~~not~~Report do(“EIR”) socertified inby the ~~future~~Kern County Board of Supervisors in 2015.

In California, where we currently operate a 20 well oilfield project, there is substantial federal and state regulation and oversight of produced water and its disposal. Water regulations in California are currently under review and are subject to change. We produce a substantial amount of water while lifting oil from our reservoirs. While the water we produce is considered to be “fresh water” under current testing standards and is suitable for use for livestock and agricultural purposes, its handling and use are currently under review by regional authorities. As rules change, we may be required to invest in additional water management infrastructure. There is no guarantee that we will not have to incur additional costs in the future in regards to the disposal and use of our produced water.8

~~The~~Our operations in Kern County ~~California~~have ~~Department~~been subject to significant uncertainty over the past several years as a result of ~~Conservation~~ongoing ~~Geologic~~challenges ~~Energy~~to ~~Management~~the ~~Division~~County's ~~(CalGEM)~~ability isto rely ~~California~~on an existing EIR to meet the County's ~~primary~~obligations ~~regulator~~under CEQA. In December 2015 several groups challenged the sufficiency of the EIR for satisfying CEQA requirements in Kern County for crude oil and natural gas ~~industry~~permit onapprovals ~~private~~(“Kern ~~and~~County ~~state~~EIR ~~lands,~~Litigation”). In ~~with~~March ~~additional~~2018 ~~oversight~~a ~~from~~trial court (“Trial Court”) found that the ~~State~~EIR ~~Lands~~inadequately ~~Commission’s~~analyzed ~~administration~~the ofenvironmental ~~state~~impacts ~~surface~~to rangeland and ~~mineral~~road ~~interests.~~paving ~~Government~~mitigation ~~actions,~~for ~~including~~purposes of well work and rejected the ~~issuance~~plaintiffs’ ofother ~~certain~~CEQA ~~permits~~claims. orThe ~~approvals~~plaintiffs appealed. In February 2020, bythe ~~state~~California ~~and~~Fifth ~~local~~District ~~agencies~~Appellate Court (“Appellate Court”) ruled that the plaintiffs’ other CEQA orclaims byhad ~~federal~~merit ~~agencies~~and ~~may~~ordered beKern ~~subject~~County to ~~environmental~~rescind ~~reviews,~~the ~~respectively~~Zoning Ordinance and cease issuing permits. In March 2021, ~~under~~Kern ~~the~~County’s Board ~~California~~of ~~Environmental~~Supervisors ~~Quality~~approved ~~Act~~a revised Zoning Ordinance (~~CEQA~~the “Revised Ordinance”) ~~or the~~and ~~National~~certified a Supplemental Recirculated Environmental ~~Policy~~Impact ~~Act~~Report (~~NEPA~~“SREIR”), ~~which~~for ~~may~~purposes ~~result~~of insatisfying ~~delays,~~CEQA ~~imposition~~requirements with respect to the issuance of ~~mitigation~~oil ~~measures~~and natural orgas ~~litigation~~permits. ~~CalGEM~~A ~~currently~~suit was subsequently filed that same month challenging the sufficiency of the SREIR. In October 2021, the Trial ~~requires~~Court anordered ~~operator~~Kern County to ~~identify~~cease using the ~~manner~~existing EIR to meet CEQA requirements until it determined that the Revised Ordinance complied with CEQA requirements. The Trial Court subsequently identified four deficiencies in ~~which~~the SREIR that needed correction to conform to CEQA. In ~~has~~November ~~been~~2022, ~~satisfied~~upon ~~prior~~the correction of those deficiencies to ~~issuing~~the ~~various~~Trial ~~state~~Court’s ~~permits~~satisfaction, ~~typically~~the ~~through~~Trial Court lifted the suspension ~~either~~on anKern ~~environmental~~County's ~~review~~ability orto anrely ~~exemption~~on bythe existing SREIR to meet CEQA requirements in Kern County (the Discharge Order). In December 2022, the Trial Court denied a ~~state~~motion orto ~~local~~stay ~~agency~~the Discharge Order. The plaintiffs appealed the judgment and Discharge Order and filed a petition requesting a stay of the ordinance pending resolution of the merits of the appeal.

InOn ~~Kern~~January ~~County this requirement has typically been satisfied by complying with the local oil and gas ordinance~~26, ~~which was supported by an Environmental Impact Report (EIR) certified by the Kern County Board of Supervisors in 2015. A group of plaintiffs challenged the EIR and on February 25~~2023, ~~2020,~~the aAppellate ~~California~~ Court ~~of Appeal~~ issued a ~~ruling~~preliminary ~~that~~order ~~invalidates~~on athe ~~portion~~petition ofreinstating ~~the~~a ~~EIR~~suspension ~~until~~of ~~the~~Kern County's ~~makes~~ability ~~certain~~to ~~revisions~~rely toon the ~~EIR~~existing SREIR ~~and~~to ~~recertifies~~meet ~~it.~~CEQA Onrequirements ~~February~~pending ~~12, 2021,~~ the ~~Kern~~outcome ~~County Planning Commission voted to recommend approval~~ of ~~the revisions in~~ a ~~supplementary EIR~~final in order todetermining ~~reestablish~~whether ~~the~~crude ~~county's~~ oil and natural gas permitting ~~system,~~shall ~~though~~remain ~~it must be approved by the county Board of Supervisors~~suspended ~~before~~for ~~becoming effective. This certification was expected to be completed in~~ the ~~first~~duration ~~half~~ of ~~2021; however,~~ the ~~supplemental EIR~~appeals ~~and certification are now in the middle of litigation~~process. AThat ~~court~~order ~~decision~~ is ~~expected~~still ~~sometime in 2022~~pending. ~~After the supplementary EIR is certified, it is expected that CalGEM will rely on Kern County to serve as lead agent for CEQA purposes, reducing unnecessary delays at the state level.~~

7 As a result of the current lack of permits with respect to our Kern County properties, we do not currently plan to drill and complete any additional wells within Kern County until permitting is resumed in Kern County, which may be later in the 2024 calendar year. However, there is no certainty that we will obtain permits on that timeline or at all, which may further adversely affect our future development plans, proved undeveloped reserves, business, operations, cash flows, financial position, and results of operations.

~~The~~Furthermore, ~~California~~the ~~Legislature~~California ~~has~~Legislature and Governor have significantly increased the jurisdiction, duties and enforcement authority of CalGEM, the State Lands Commission and other state agencies with respect to crude oil and natural gas activities in recent years. through legislation and policy pronouncements. For example, 2019 state legislation expanded CalGEM’s duties effective on January 1, 2020 to include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs, and will require CalGEM to study and prioritize idle wells with emissions, evaluate costs of abandonment, decommissioning and restoration, and review and update associated indemnity bond amounts from operators if warranted, up to a specified cap which may be shared among operators. Other 2019 legislation specifically addressed oil and natural gas leasing by the State Lands Commission, including imposing conditions on assignment of state leases, requiring lessees to complete abandonment and decommissioning upon the termination of state leases, and prohibiting leasing or conveyance of state lands for new oil and natural gas infrastructure that would advance production on certain federal lands such as national monuments, parks, wilderness areas and wildlife refuges.

InCalGEM ~~the~~and ~~event~~other westate ~~conduct~~agencies have ~~operations~~also onsignificantly ~~federal~~revised their regulations, ~~state or~~regulatory ~~American~~interpretations ~~Indian~~and ~~crude~~data ~~oil~~collection and ~~natural~~reporting ~~gas~~requirements. ~~leases~~CalGEM issued updated regulations in April 2019 governing management of idle wells, ~~our~~which ~~operations~~include ~~may~~specific beimplementation ~~required~~periods. The updated idle well management regulations require operators to ~~comply~~either ~~with~~submit ~~additional~~annual ~~regulatory~~idle ~~restrictions, including~~well ~~various~~management ~~nondiscrimination~~plans ~~statutes,~~describing ~~royalty~~how they will plug and ~~related~~abandon or ~~valuation~~reactivate ~~requirements~~a ~~and~~specified onpercentage of long-~~site~~term ~~security~~idle ~~regulations,~~wells or pay additional annual fees and ~~other~~perform additional testing to retain greater ~~appropriate~~flexibility ~~permits~~to ~~issued~~return bylong-term idle wells to service in the ~~Bureau~~future. The updated underground injection regulations address injection approvals, project data requirements, testing of ~~Land~~injection ~~Management~~wells, ormonitoring ~~other~~and ~~relevant~~reporting ~~federal~~requirements orwith ~~state~~respect ~~agencies~~to injection parameters, containment and incident response, among other topics.

~~Hydraulic~~In ~~fracturing~~addition, iscertain ~~an important and common practice~~local ~~that~~governments ishave ~~used~~proposed toor ~~stimulate~~adopted ~~production~~ordinances ofthat ~~natural~~would ~~gas~~restrict ~~and/or~~certain ~~oil~~drilling ~~from~~activities ~~dense~~in ~~subsurface~~general ~~rock~~and ~~formations.~~well ~~The~~stimulation, ~~hydraulic fracturing process~~completion ~~involves~~or ~~the~~ injection ofactivities ~~water~~in particular, ~~sand~~impose ~~and~~setback ~~chemicals~~distances ~~under~~from ~~pressure~~certain ~~into~~other ~~the~~land ~~formation~~uses, toor ~~fracture~~ban ~~the~~such ~~surrounding~~activities ~~rock~~outright. ~~and~~For ~~stimulate~~example, ~~production.~~a ~~Hydraulic~~ban ~~fracturing~~on ~~typically~~prohibiting isnew ~~regulated by state~~ crude oil and natural gas ~~commissions,~~wells ~~but~~and the ~~EPA~~phasing ~~has~~out ~~asserted~~of ~~federal regulatory~~existing ~~authority~~wells ~~pursuant to the Safe Drinking Water Act~~ over ~~certain~~a ~~hydraulic~~number ~~fracturing~~of ~~activities~~years ~~involving~~was ~~the~~previously ~~use~~proposed in ofMonterey ~~diesel fuel.~~County, Atwhere ~~the~~we ~~state~~own ~~level,~~mineral ~~several~~rights ~~states~~and have ~~adopted~~production orfrom ~~are~~our ~~considering~~Reabold ~~legal~~acquisition. ~~requirements~~That ~~that~~ban ~~could~~however ~~impose~~was ~~more~~declared ~~stringent~~to ~~permitting,~~be ~~chemical~~preempted ~~disclosure~~by state and ~~well~~federal ~~construction~~regulation. ~~requirements~~Other onlocal ~~hydraulic~~governments ~~fracturing~~have ~~activities.~~sought Ifto ~~new~~ban natural gas or ~~more~~the ~~stringent~~transportation ~~federal,~~of ~~state~~natural orgas ~~local~~through ~~legal~~their ~~restrictions~~cities. ~~relating~~The toCity ~~the~~of ~~hydraulic~~Antioch, ~~fracturing~~located ~~process~~in ~~are~~Contra ~~adopted~~Costa inCounty ~~areas~~ where we ~~operate,~~do wehave ~~could~~both ~~incur~~crude ~~potentially significant~~oil ~~added~~and ~~costs~~natural togas ~~comply~~producing ~~with~~properties has ~~such~~declined ~~requirements,~~to ~~experience~~extend ~~delays or curtailment in~~ the ~~pursuit~~franchise ofagreement ~~exploration,~~for ~~development or~~a ~~production~~natural ~~activities,~~gas ~~and~~pipeline ~~perhaps~~through ~~even~~its becity. ~~precluded~~Several companies, ~~from~~including ~~drilling~~our ~~wells.~~natural Wegas dopurchaser ~~not~~have ~~presently~~challenged ~~use~~the ~~hydraulic~~city’s ~~fracturing~~inconsistent ~~methods~~and ~~in our~~arbitrary ~~crude~~approach ~~oil~~to ~~exploration~~natural ~~and~~gas ~~production in California~~approvals.

On September 16, 2022, the Governor of California signed Senate Bill No. 1137 into law, which established 3,200 feet as the minimum distance between new crude oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public effective January 1, 2023. On January 6, 2023, CalGEM's emergency regulations to support implementation of Senate Bill No. 1137 were approved by the Office of Administrative Law and final regulations were published. The regulations included applicable requirements of notice to property owners and tenants regarding the work performed and offering the sampling of test water wells or surface water before and after drilling; the contents of required notices for new production facilities; the annual submission of a sensitive receptor inventory and sensitive receptor map and the contents and format of the same; and the requirements of statements where operators have determined a location not to be within a health protection zone.

Additional provisions of Senate Bill No. 1137 include, among others, the imposition of health, safety and environmental controls applicable to both current and new wells located within this distance of sensitive receptors related to noise, light, and dust pollution controls and air emission monitoring, and the immediate suspension of operations at production facilities determined to not be in compliance with certain air emission requirements. In December 2022, proponents of a voter referendum (the “Referendum”) collected more than the requisite number of signatures required to put Senate Bill No. 1137 on the 2024 ballot. On February 3, 2023, the Secretary of State of California certified the signatures and confirmed that the Referendum qualifies for the November 2024 ballot. Accordingly, Senate Bill No. 1137 is stayed until it is put to a vote, although any stay could be delayed if there are legal challenges to the Secretary of State's certification. In addition, even during the stay, CalGEM could attempt to initiate rulemaking with regard to setbacks.

Our crude oil production from the East Slopes project in Kern County and from the Reabold project in Monterey County is in rural areas and are unlikely to be affected by Senate Bill No. 1137 should the outcome of the Referendum result in the bill being implemented. Our crude oil production from the Reabold project in Contra Costa County is in area located within distance of the above-mentioned sensitive receptors and would be affected by the outcome of the Referendum result on Senate Bill No. 1137. We would expect the implementation of this law to result in a possible change in our existing development plans and to possibility create a material change to the timing of our plugging and abandonment liabilities.

In the event we conduct operations on federal, state or American Indian crude oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements and on-site security regulations, and other appropriate permits issued by the Bureau of Land Management or other relevant federal or state agencies. In 2019, California legislation specifically addressed oil and natural gas leasing by the State Lands Commission, including imposing conditions on assignment of state leases, requiring lessees to complete abandonment and decommissioning upon the termination of state leases, and prohibiting leasing or conveyance of state lands for new oil and natural gas infrastructure that would advance production on certain federal lands such as national monuments, parks, wilderness areas and wildlife refuges.

There is also substantial federal and state regulation and oversight of produced water and its disposal. Water regulations in California are currently under review and are subject to change. We produce a substantial amount of water while lifting oil from our reservoirs. In Kern County, the water we produce is considered to be “fresh water” under current testing standards and is suitable for use for livestock and agricultural purposes. In Monterey and Contra Costa Counties, the water we produce is not considered to be “fresh water” and needs to be disposed of under regulated standards. The handling and use of our produced water is currently under review by regional authorities. As rules change, we may be required to invest in additional water management infrastructure. There is no guarantee that we will not have to incur additional costs in the future in regards to the disposal and use of our produced water.

In 2014, at the request of the EPA, CalGEM commenced a detailed review of the multi-decade practice of permitting underground injection wells and associated aquifer exemptions under the Safe Drinking Water Act (“SDWA”). In 2015, the state set deadlines to obtain the EPA’s confirmation of aquifer exemptions under the SDWA in certain formations in certain fields. Since the state and the EPA did not complete their review before the state’s deadlines, the state announced that it will not rescind permits or enforce the deadlines with respect to many of the formations pending completion of the review but has applied the deadlines to others. Several industry groups and operators challenged CalGEM’s implementation of its aquifer exemption regulations.

In March 2017, the Kern County Superior Court issued an injunction barring the blanket enforcement of CalGEM’s aquifer exemption regulations. The court found that CalGEM must find actual harm results from an injection well’s operations and go through a hearing process before the agency can issue fines or shut down operations. During the review, the state has restricted injection in certain

formations or wells in several fields and held certain pending injection permits in abeyance. In September 2021, the EPA issued a letter to the California Natural Resources Agency and the State Water Resources Control Board regarding the state's compliance with the 2015 compliance plan relating to the state's process for approving aquifer exemptions under the SDWA. The letter requested that California take appropriate action by September 2022, or the EPA would consider taking additional action to impose limits on California's administration of the UIC program, withhold federal funds for the administration of the UIC program, and direct orders to oil and natural gas operators injecting into formations not authorized by the EPA, among other measures. The state responded in October 2021 with a proposed compliance plan and a follow-up letter in August 2022 providing a mid-year update, but to date, the EPA has not yet responded.

The trend in California is to impose increasingly stringent restrictions on crude oil and natural gas activities. We cannot predict what actions the Governor of California, the Legislature or state agencies may take in the future, but we could face increased compliance costs, delays in obtaining the approvals necessary for our operations, exposure to increased liability, or other limitations as a result of future actions by these parties. Moreover, new developments resulting from the current and future actions of these parties could also materially and adversely affect our ability to operate, successfully execute drilling plans, or otherwise develop our reserves. Accordingly, recent and future actions by the Governor of California, the Legislature, and state agencies could materially and adversely affect our business, results of operations, and financial condition.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state crude oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuel. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells. We do not presently use hydraulic fracturing methods during our well completion operations in California.

Federal, state, and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

Operational Hazards and Insurance

Our operations are subject to the usual hazards incident to the drilling and production of crude oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.

We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance we maintain are adequate. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

Human Capital

At February 28, ~~2022~~2023, we had ~~four~~five full-time employees ~~and two part-time employees~~. Additionally, we regularly use the services of ~~four~~ consultants on an as-needed basis for accounting, technical, oil field, geological, investor relations and administrative services. None of our employees are subject to a collective bargaining agreement. In our opinion, relations with our employees are good. We may hire more employees in the future as needed. All other services are currently contracted for with independent contractors. We have not obtained “key person” life insurance on any of our officers or directors. As we continue to manage the business ongoing, we are focused on retaining and developing our existing employees who are critical to the business.

8 11

Long-Term Success

Our long-term success depends on the successful acquisition, exploration and development of commercial grade crude oil and natural gas properties as well as the prevailing prices for crude oil and natural gas to generate future revenues and operating cash flow. Crude oil and natural gas prices are extremely volatile and are affected by many factors outside of our control. 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 price instability, ~~such as was experienced from February 2020 through January 2021,~~ has had and will likely continue to have a material adverse effect on our results of operations and financial condition. Such pricing factors are beyond our control, and have resulted and will result in negative fluctuations of our earnings. We believe; however, that even in this volatile pricing environment there are significant opportunities available to us in the crude oil and natural gas exploration and development industry.

Availability of SEC Filings

You may read and copy any materials we file with the U.S. Securities and Exchange Commission (the “SEC”) at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549, on official business days during the hours of 10:00 am to 3:00 pm. You can obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of that site is http://www.sec.gov.

Website / Available Information

Our website can be found at www.daybreakoilandgas.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed with or furnished to the SEC, pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (“the Exchange Act”) can be accessed free of charge on our website at www.daybreakoilandgas.com under the “Shareholder/Financial” section of our website within the “SEC Filings” subsection as soon as is reasonably practicable after we electronically file such material with, or otherwise furnish it to, the SEC.

We have adopted an Ethical Business Conduct Policy Statement to provide guidance to our directors, officers, and employees on matters of business conduct and ethics, including compliance standards and procedures. We also have adopted a Code of Ethics for Senior Financial Officers that applies to our principal executive officer, principal financial officer, principal accounting officer and controller. Copies of our Ethical Business Conduct Policy Statement and Code of Ethics for Senior Financial Officers are available under the “Shareholder/Financial” section of our website at www.daybreakoilandgas.com within the heading “Corporate Governance.” We intend to promptly disclose via a Current Report on Form 8-K or via an update to our website, information on any amendment to or waiver of these codes with respect to our executive officers and directors. Waiver information disclosed via the website will remain on the website for at least 12 months after the initial disclosure of a waiver.

Our Corporate Governance Guidelines and the charters of our Audit Committee, Nominating and Corporate Governance Committee, and Compensation Committee are also available in the “Shareholder/Financial” section of our website at www.daybreakoilandgas.com within the heading “Corporate Governance.” In addition, copies of our Ethical Business Conduct Policy Statement, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines, and the charters of the Committees referenced above are available at no cost to any shareholder who requests them by writing or telephoning us at the following address or telephone number:

Daybreak Oil and Gas, Inc. ~~1101~~1414 NS. ~~Argonne~~Friendswood ~~Road~~Drive, Suite ~~A-211~~212 ~~Spokane Valley~~Friendswood, WATX ~~99212-2699~~77546 Attention: Corporate Secretary Telephone: (~~509~~281) ~~232~~996-~~7674~~4176

Information contained on or connected to our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

912

ITEM 1A. RISK FACTORS

The following risk factors together with other information set forth in this Annual Report on Form 10-K, should be carefully considered by current and future investors in our securities. An investment in our securities involves substantial risks. There are many factors that affect our business, a number of which are beyond our control. Our business, financial condition and results of operations could be materially adversely affected by any of these factors. The nature of our business activities further subjects us to certain hazards and risks. The risks described below are a summary of the known material risks relating to our business. Additional risks and uncertainties not presently known to us or that we currently deem to be immaterial individually or in aggregate may also impair our business operations. If any of these risks actually occur, it could harm our business, financial condition or results of operations and impair our ability to implement our business plan or complete development projects as scheduled. In any such case, the trading price of our Common Stock could decline, and you could lose all, or a part, of your investment.

~~Risks~~Summary ~~Related~~of toRisk ~~Volatile Energy Prices~~Factors

~~Crude~~Risks ~~oil~~Related and natural gas prices are volatile. From January 2020 through February 2021, there was a significant period of depressed commodity prices, that significantly adversely affected, and in the future may continue to ~~adversely~~Our ~~affect, our financial condition, liquidity, results of operations, cash flows, access to capital markets, and ability to grow.~~Business

~~Our~~· ~~revenues,~~Prices ~~operating~~for ~~results, liquidity, cash flows, profitability and valuation of proved reserves depend substantially upon the market prices of~~ crude oil and natural gas. ~~Product~~can ~~prices affect~~fluctuate ~~our~~widely ~~cash flow available for capital expenditures~~ and ~~our~~an ~~ability~~extended toperiod ~~access~~of ~~funds~~low ~~through the capital markets. Declines in commodity~~ prices ~~have~~could ~~historically~~materially and adversely ~~affected~~affect ~~the estimated value of~~ our ~~proved~~financial ~~reserves and our cash flows. The volatile nature of the energy markets makes it difficult to estimate future prices of crude oil and natural gas; however~~condition, ~~any~~results ~~prolonged period~~ of ~~price instability~~operations, ~~such~~ ~~as was experienced from February 2020 through January 2021, has had a material adverse effect on our~~ cash ~~flows,~~flow ~~reserves valuation~~ and ~~availability~~ability ofto ~~funds~~invest in ~~the financial markets. Specifically,~~ our ~~average annual realized price of crude oil sales for the twelve months periods ended February 28, 2022, 2021 and February 29, 2020 was $70~~assets.~~75, $36.91 and $60.25, respectively.~~

~~The~~· ~~commodity~~Hydrocarbon ~~prices~~price wedeclines ~~receive~~may ~~for~~result ~~our~~in ~~crude~~impairments ~~oil and~~of ~~natural gas depend upon factors beyond~~ our ~~control,~~asset ~~including~~carrying ~~among others:~~values.

~~— changes~~· inThe ~~the~~crude ~~supply~~oil of and ~~demand~~natural ~~for~~gas ~~crude~~business ~~oil~~is ~~and~~highly ~~natural~~competitive, ~~gas;~~placing us at an operating disadvantage.

~~— market~~· When we make the determination to invest in crude oil or natural gas properties we rely upon geological and engineering estimates, which involve a high level of uncertainty;.

~~— the~~· ~~level~~Drilling ofis ~~consumer~~a ~~product~~high-risk ~~demands;~~activity and, as a result, we may not be able to adhere to our proposed drilling schedule, or our drilling program may not result in commercially productive reserves.

~~— hurricanes~~· Shortages of oilfield equipment, services and ~~other~~qualified ~~weather~~personnel ~~conditions;~~could delay our drilling program and increase the prices we pay to obtain such equipment, services, and personnel.

~~— domestic~~· ~~governmental~~To ~~regulations~~execute our business plan we will need to develop current projects and ~~taxes;~~expand our operations requiring significant capital expenditures, which we may be unable to fund.

~~— the~~· ~~foreign~~Our ~~supply~~ability ofto reach and maintain profitable operating results is dependent on our ability to find, acquire, and develop crude oil and natural gas; properties.

~~— the~~· ~~price~~Our producing reserves are located in one major geographic area. Concentration of ~~crude~~reserves ~~oil~~in ~~and~~limited ~~natural~~geographic ~~gas~~areas ~~imports~~may disproportionately expose us to operational, regulatory and geological risks.

~~— national~~· Our proved reserves are estimates and ~~international~~depend ~~pandemics~~on ~~like~~many assumptions. Any material inaccuracies in these assumptions could cause the ~~COVID-19;~~quantity and value of our crude oil reserves, and our revenues, profitability and cash flows to be materially different from our estimates.

~~— overall~~· ~~domestic~~We may not be able to replace current production with new crude oil and ~~foreign~~natural ~~economic~~gas ~~conditions~~reserves.

Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

We have reclassified proved undeveloped reserves to unproved reserves due to our inability to commit sufficient capital within the required SEC-defined time period of a five-year development window, which could adversely affect the value of our properties.

Our financial condition will deteriorate if we are unable to retain our interests in our leased crude oil and natural gas properties.

Title deficiencies could render our crude oil and natural gas leases worthless; thus damaging the financial condition of our business.

If we as operator of our crude oil and natural gas projects fail to maintain adequate insurance, our business could be exposed to significant losses.

Recent action by the State of California imposing additional financial assurance requirements related to plugging and abandonment costs, decommissioning, and site restoration on those who acquire the right to operate wells and production facilities could impact our ability to sell or acquire assets in the state of California or increase our costs in connection with the same.

We are subject to economic downturns and the effects of public health events, such as the COVID-19 pandemic, which may materially and adversely affect the demand and the market price for our products.

Risks Related to Environmental Regulation

Our crude oil and natural gas exploration and production and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.

We face various risks associated with the trend toward increased anti-crude oil and natural gas development activity.

Restricted land access could reduce our ability to explore for and develop crude oil and natural gas reserves.

Recent and future actions by the State of California and local governments could result in restrictions to our operations and result in decreased demand for crude oil and natural gas within the state.

Climate change legislation or regulations restricting emission of greenhouse gases (“GHG”) could result in increased operating costs and reduced demand for the crude oil and natural gas we produce.

The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new costs on our operations.

Risks Related to Our Indebtedness

We have experienced significant operating losses in the past and there can be no assurance that we will become profitable in the future.

We have substantial indebtedness. The amount of our outstanding indebtedness and our current inability to meet our debt obligations will have adverse consequences on our business, financial condition and results of operations.

Risks Related to Our Common Stock

We may be unable to continue as a going concern in which case our Common Stock will have little or no value.

The market price of our Common Stock has been volatile, which may cause the investment value of our Common Stock to decline.

Pursuant to SEC rules our Common Stock is classified as a “penny stock” increasing the risk of investment in our Common Stock.

The resale of Common Stock shares offered in private placements could depress the value of other Common Stock shares.

Privately placed issuances of our Common Stock and warrants have and may continue to dilute ownership interests which could have an adverse effect on our stock prices.

We will need to seek to raise additional funds in the future through debt financing, which may impose operational restrictions and may further dilute existing ownership interests.

We do not anticipate paying dividends on our Common Stock, which could devalue the market value of our Common Stock.

We have two Common Stock shareholders that own approximately 42% and 40%, respectively of our outstanding Common Stock shares at February 28, 2023 who may be able to individually or jointly control the operations of the Company.

General Risk Factors

Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of proposed legislation.

We may lose key management personnel which could endanger the future success of our crude oil and natural gas operations.

A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.

RISK FACTORS

Risks Related to Our Business

Prices for crude oil and natural gas can fluctuate widely and an extended period of low prices could materially and adversely affect our financial condition, results of operations, cash flow and ability to invest in our assets.

Our financial condition, results of operations, cash flow and ability to invest in our assets are highly dependent on crude oil and natural gas prices. A sustained period of low prices for crude oil and natural gas would reduce our cash flows from operations and could reduce our access to capital markets, and our ability to grow. Prices for crude oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

· changes in the supply of and demand for crude oil and natural gas;

· market uncertainty;

· the level of consumer product demands;

· hurricanes and other weather conditions;

· domestic governmental regulations and taxes;

· the foreign supply of crude oil and natural gas;

· the price of crude oil and natural gas imports;

· political and economic conditions, including international disputes;

· national and international pandemics like the COVID-19; and

· overall domestic and foreign economic conditions.

These factors make it very difficult to predict future hydrocarbon commodity price movements with any certainty. It is beyond our control and ability to accurately predict when there will be a sustained improvement in hydrocarbon prices. All of our crude oil and natural gas sales are made pursuant to contracts based on spot market prices and are not based on long-term fixed price contracts. Crude oil and natural gas prices do not necessarily fluctuate in direct relation to each other.

The COVID-19 pandemic caused crude oil prices to decline significantly in 2020, and may adversely affect our business, results of operations and financial condition in the future.

The COVID-19 pandemic has adversely affected the global economy, and has resulted in, among other things, travel restrictions, business closures, the institution of quarantining and other mandated and self-imposed restrictions on movement and created supply chain imbalances. As a result, there was an unprecedented reduction in demand for crude oil. The decline in prices adversely affected our revenues and profitability in 2020 and, while energy prices have recovered, may adversely affect the economics of our existing wells and planned future wells. The severity, magnitude and duration of current or future COVID-19 outbreaks, the extent of actions that have been or may be taken to contain or treat their impact, and the impacts on the economy generally and oil prices in particular, are uncertain, rapidly changing and hard to predict.

Supply chain challenges arising in the wake of the COVID-19 pandemic may adversely affect our operations.

Supply and demand imbalances arising from the COVID-19 pandemic have resulted in shortages, backlogs and delayed deliveries of a wide array of products and services, including products and services critical to oil and gas operations. As a result of such supply chain challenges, we may experience unavailability, or delay in delivery, of products and services that are critical to our well operations. Any such delays may result in deferral or reduction of revenues and increased costs, any of which could materially adversely affect our profitability.

Hydrocarbon price declines may result in impairments of our asset carrying values.

Commodity prices have a significant impact on the present value of our proved reserves. Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our crude oil and natural gas properties in certain situations. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required. Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred. For the twelve months ended February 28, ~~2021~~2023, we determined that a non-cash impairment will not be recognized on our California crude oil properties due to the ~~prevailing increase in the~~ current hydrocarbon prices.

Risks Related to Our Business

To execute our business plan we will need to develop current projects and expand our operations requiring significant capital expenditures, which we may be unable to fund.

Our business plan contemplates the execution of our current exploration and development projects and the expansion of our business by identifying, acquiring, and developing additional crude oil and natural gas properties. We plan to rely on external sources of financing to meet the capital requirements associated with these activities. We will have to obtain any additional funding we need through debt and equity markets or the sale of producing or non-producing assets. There is no assurance that we will be able to obtain additional funding when it is required or that it will be available to us on commercially acceptable terms.

Low hydrocarbon price environments and the volatility in prices that we are currently experiencing, as well as operating difficulties and other factors, many of which are beyond our control, are causing our revenues and cash flows from operating activities to decrease and may limit our ability to internally fund our exploration and development activities.

We may make offers to acquire crude oil and natural gas properties in the ordinary course of our business. If these offers are accepted, our capital needs will increase substantially. If we fail to obtain the funding that we need when it is required, we may have to forego or delay potentially valuable opportunities to acquire new crude oil and natural gas properties. In addition, without the necessary funding, we may default on existing funding commitments to third parties and forfeit or dilute our rights in existing crude oil and natural gas property interests.

The crude oil and natural gas business is highly competitive, placing us at an operating disadvantage.

We expect to be at a competitive disadvantage in (a) seeking to acquire suitable crude oil and or natural gas drilling prospects; (b) undertaking exploration and development; and (c) seeking additional financing. We base our preliminary decisions regarding the acquisition of crude oil and or natural gas prospects and undertaking of drilling ventures upon general and inferred geology and economic assumptions. This public information is also available to our competitors.

In addition, we compete with larger crude oil and natural gas companies with longer operating histories and greater financial resources than us. These larger competitors, by reason of their size and greater financial strength, can more easily:

access capital markets;

recruit more qualified personnel;

absorb the burden of any changes in laws and regulation in applicable jurisdictions;

handle longer periods of reduced prices of crude oil and natural gas;

acquire and evaluate larger volumes of critical information; and

compete for industry-offered business ventures.

When we make the determination to invest in crude oil or natural gas properties we rely upon geological and engineering estimates, which involve a high level of uncertainty.

Geologic and engineering data are used to determine the probability that a reservoir of crude oil or natural gas exists at a particular location. This data is also used to determine whether crude oil and natural gas are recoverable from a reservoir. Recoverability is ultimately subject to the accuracy of data including, but not limited to, geological characteristics of the reservoir, structure, reservoir fluid properties, the size and boundaries of the drainage area, reservoir pressure, and the anticipated rate of pressure depletion. Also, an increase in the costs of production operations may render some deposits uneconomic to extract.

The evaluation of these and other factors is based upon available seismic data, computer modeling, well tests and information obtained from production of crude oil and natural gas from adjacent or similar properties. There is a high degree of risk in proving the existence and recoverability of reserves. Actual recoveries of proved reserves can differ materially from original estimates. Accordingly, reserve estimates may be subject to downward adjustment. Actual production, revenue and expenditures will likely vary from estimates, and such variances may be material.

Drilling is a high risk activity and, as a result, we may not be able to adhere to our proposed drilling schedule, or our drilling program may not result in commercially productive reserves.

Our future success will partly depend on the success of our drilling programs. The future cost or timing of drilling, completing, and producing wells is inherently uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including:

unexpected drilling conditions;

well integrity issues and surface expressions;

pressure or irregularities in formations;

equipment failures or accidents;

compliance with landowner requirements;

current crude oil and natural gas prices and estimates of future crude oil and natural gas prices;

availability, costs and terms of contractual arrangements with respect to pipelines and related facilities to gather, process, transport and market crude oil and natural gas; and

shortages or delays in the availability of drilling rigs and the delivery of equipment and/or services, including experienced labor.

Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.

The demand for qualified and experienced field personnel to drill wells and conduct field operations in the crude oil and natural gas industry can fluctuate significantly, often in correlation with crude oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher crude oil and natural gas prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews, and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be.

To execute our business plan we will need to develop current projects and expand our operations requiring significant capital expenditures, which we may be unable to fund.

Our ability to reach and maintain profitable operating results is dependent on our ability to find, acquire, and develop crude oil and natural gas properties.

Our future performance depends upon our ability to find, acquire, and develop crude oil and natural gas reserves that are economically recoverable. Without successful exploration and acquisition activities, we will not be able to develop reserves or generate production revenues to achieve and maintain profitable operating results. No assurance can be given that we will be able to find, acquire or develop these reserves on acceptable terms. We also cannot assure that commercial quantities of crude oil and natural gas deposits will be discovered that are sufficient to enable us to recover our exploration and development costs.

Our limited capital expenditures and drilling program, when coupled with a sustained depression in crude oil and natural gas prices, will significantly reduce our cash flow and constrain any future drilling, which would have a material adverse effect on our business, financial condition and results of operations.16

~~Historically,~~Our weproducing ~~have made substantial capital expenditures for the exploration and development of crude oil and natural gas~~ reserves. ~~The~~are ~~combination~~located ofin ~~lower~~one ~~hydrocarbon prices and the reduction~~major ofgeographic ~~our~~area. ~~drilling~~Concentration ~~operations has resulted in reduced production and operating cash flows since June~~ of ~~2014.~~reserves ~~A continued sustained volatility~~ in ~~these~~limited ~~hydrocarbon~~geographic ~~prices~~areas ~~combined~~may ~~with~~disproportionately ~~reduced~~expose ~~production~~us ~~and accompanying lower cash flows will continue~~ to ~~adversely~~operational, ~~affect~~regulatory ~~our business~~and ~~financial~~geological ~~condition and results of operations~~risks.

Our ~~proved~~two ~~reserves~~producing projects are ~~estimates~~located ~~and~~in ~~depend~~California. onAs ~~many~~a ~~assumptions.~~result ~~Any~~of ~~material~~this ~~inaccuracies~~concentration, inwe ~~these~~may ~~assumptions~~be disproportionately exposed to the impact of regional conditions which could ~~cause~~negatively impact the ~~quantity~~success and ~~value~~profitability of our operations. Any change in supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation of state or regional regulations, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of crude oil ~~reserves,~~and natural gas have the potential to negatively impact us. Our operations are also exposed to natural disasters and related events common to California, such as wildfires, mudslides, high winds, earthquakes and extreme weather events, and the potential increase to the frequency of drought and flooding. Further, our ~~revenues~~operations may be exposed to power outages, ~~profitability~~mechanical failures, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut in, delay operations and growth plans, decrease cash flows, toincrease beoperating ~~materially~~and ~~different~~capital ~~from~~costs, prevent development of lease inventory before expiration and limit access to markets for our ~~estimates~~products.

~~The~~Our ~~accuracy of estimated~~ proved reserves ~~and~~are ~~estimated future~~estimates ~~net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering~~ and ~~economic data~~depend ~~and~~on ismany ~~subject to various~~ assumptions~~, including assumptions required by the SEC relating to crude oil prices, drilling and operating expenses and other matters~~. ~~Although~~Any wematerial ~~believe~~inaccuracies ~~that~~in ~~our~~these estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, crude oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil reserves will most likely vary from the assumptions ~~and estimates used to determine proved reserves. Any significant variance~~ could ~~materially~~cause ~~affect~~ the ~~estimated~~quantity ~~quantities~~ and value of our crude oil reserves, ~~which in turn could adversely affect our cash flows, results of operations, financial condition~~ and ~~the availability of capital resources. In addition, we may adjust estimates of proved reserves~~ toour ~~reflect production history~~revenues, ~~results of exploration and development~~profitability, ~~prevailing crude oil prices~~ and ~~other~~cash ~~factors,~~flows ~~many of which are beyond our control. Downward adjustments~~ to ~~our~~be ~~estimated~~materially ~~proved~~different ~~reserves~~from ~~could require us to impair the carrying value of~~ our ~~crude oil properties, which would reduce our earnings and increase our stockholders’ deficit~~estimates.

The accuracy of estimated proved reserves and estimated future net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering, and economic data and is subject to various assumptions, including assumptions required by the SEC relating to crude oil prices, drilling and operating expenses and other matters. Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, crude oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of our crude oil reserves, which in turn could adversely affect our cash flows, results of operations, financial condition, and the availability of capital resources. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil prices and other factors, many of which are beyond our control. Downward adjustments to our estimated proved reserves could require us to impair the carrying value of our crude oil properties, which would reduce our earnings and increase our stockholders’ deficit.

The present value of proved reserves will not necessarily equal the current fair market value of our estimated crude oil reserves. In accordance with reserve reporting requirements of the SEC, we are required to establish economic production for reserves on an average historical price. Actual future prices and costs may be materially higher or lower than those required by the SEC. The timing of both the production and expenses with respect to the development and production of crude oil properties will affect the timing of future net cash flows from proved reserves and their present value.

The estimated proved reserve information is based upon reserve reports prepared by an independent engineer. From time to time, estimates of our reserves are also made by our company engineer for use in developing business plans and making various decisions. Such estimates may vary significantly from those of the independent engineers and may have a material effect upon our business decisions and available capital resources.

We may not be able to replace current production with new crude oil and natural gas reserves.

In general, the volume of production from a crude oil and natural gas property declines as reserves related to that property are depleted. The decline rates of production depend upon individual reservoir characteristics. In ~~past~~order ~~years~~to ~~other~~maintain ~~than~~current ~~our~~production ~~East~~levels, ~~Slopes~~we ~~project~~will inbe ~~California,~~required ~~our~~to ~~crude~~find ~~oil~~ and ~~natural~~develop ~~gas~~additional reserves either in properties we currently own or in properties in which we may acquire in the future. Projects that we have been involved in the past have had steep rates of decline and relatively short estimated productive lives. While this is not the situation with our two current projects in California where there are fairly shallow decline curves, there is no guarantee that we will be successful in maintaining our current company-wide production levels.

Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including hydrocarbon prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory and zoning approvals and other factors.

capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory and zoning approvals and other factors.

Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our business and results of operations.

Due to the volatility in crude oil prices and the lack of available drilling capital, we have not drilled any prospective development locations in California since November of 2013.

We ~~may~~have ~~reclassify~~reclassified proved undeveloped reserves to unproved reserves due to our inability to commit sufficient capital within the required five-year development window, which could adversely affect the value of our properties.

The SEC generally requires that any undrilled location can be classified as a proved undeveloped reserve only if a development plan has been adopted indicating that the location is scheduled to be drilled within five years. The reduction of our drilling program in response to depressed crude oil and natural gas prices and a lack of drilling capital has impacted our ability to develop proved undeveloped reserves within such five-year period. IfThe ~~our~~reduction ~~reduced~~in our drilling plans ~~continue~~has ~~over~~limited ~~a significant period of time~~ our ~~future~~ access to capital resources. ~~will~~In bethe ~~limited~~past, ~~and~~ we ~~will~~have ~~also~~had ~~likely further~~to ~~delay~~reclassify ~~the~~a ~~development~~significant amount of our proved undeveloped reserves oras ~~ultimately~~probable ~~suspend~~or ~~such~~possible ~~development~~reserves ~~which~~because ~~could~~they ~~result~~have innot ~~the~~been ~~reclassification of~~drilled awithin ~~significant~~the ~~amount~~SEC-defined oftime ~~our proved undeveloped reserves as probable or possible reserves~~period. AAny ~~significant~~ future reclassification of proved undeveloped reserves ~~could~~may adversely affect the value of our properties.

Our producing reserves are located in one major geographic area. Concentration of reserves in limited geographic areas may disproportionately expose us to operational, regulatory and geological risks.

Our one core producing property is located in Kern County, California. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of crude oil.

When we make the determination to invest in crude oil or natural gas properties we rely upon geological and engineering estimates, which involve a high level of uncertainty.

Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.

Drilling is a high risk activity and, as a result, we may not be able to adhere to our proposed drilling schedule, or our drilling program may not result in commercially productive reserves.

— unexpected drilling conditions;

— well integrity issues and surface expressions;

— pressure or irregularities in formations;

— equipment failures or accidents;

— compliance with landowner requirements;

— current crude oil and natural gas prices and estimates of future crude oil and natural gas prices;

— availability, costs and terms of contractual arrangements with respect to pipelines and related facilities to gather, process, transport and market crude oil and natural gas; and

— shortages or delays in the availability of drilling rigs and the delivery of equipment and/or services, including experienced labor.

Our financial condition will deteriorate if we are unable to retain our interests in our leased crude oil and natural gas properties.

All of our properties are held under interests in crude oil and natural gas mineral leases. If we fail to meet the specific requirements of any lease, such lease may be terminated or otherwise expire. We cannot be assured that we will be able to meet our obligations under each lease. The termination or expiration of our “working interests” (interests created by the execution of a crude oil or natural gas lease) relating to these leases would impair our financial condition and results of operations.

14 We will need significant additional funds to meet capital calls, drilling, and other production costs in our effort to explore, produce, develop and sell the crude oil and natural gas produced by our leases. We may not be able to obtain any such additional funds on acceptable terms.

We will need significant additional funds to meet capital calls, drilling and other production costs in our effort to explore, produce, develop and sell the crude oil and natural gas produced by our leases. We may not be able to obtain any such additional funds on acceptable terms.

Title deficiencies could render our crude oil and natural gas leases worthless; thus damaging the financial condition of our business.

The existence of a material title deficiency can render a lease worthless, resulting in a large expense to our business. We rely upon the judgment of crude oil and natural gas lease brokers who perform the fieldwork and examine records in the appropriate governmental office before attempting to place a specific mineral interest under lease. This is a customary practice in the crude oil and natural gas industry.

We anticipate that we, or the person or company acting as operator on the properties that we lease, will examine title prior to any well being drilled. Even after taking these precautions, deficiencies in the marketability of the title to the leases may still arise. Such deficiencies may render some leases worthless, negatively impacting our financial condition.

If we as operator of our crude oil ~~project~~and ~~fail~~natural gas projects fail to maintain adequate insurance, our business could be exposed to significant losses.

Our crude oil projects are subject to risks ~~inherent~~ inherent in the crude oil and natural gas industry. These risks involve explosions, uncontrollable flows of crude oil, natural gas or well fluids, pollution, fires, earthquakes, and other environmental issues. These risks could result in substantial losses due to injury and loss of life, severe damage to and destruction of property and equipment, pollution, and other environmental damage. As protection against these operating hazards, we maintain insurance coverage to include physical damage and comprehensive general liability. However, we are not fully insured in all aspects of our business. The occurrence of a significant event on any project against which we are not adequately covered by insurance could have a material adverse effect on our financial position.

damage and comprehensive general liability. However, we are not fully insured in all aspects of our business. The occurrence of a significant event on any project against which we are not adequately covered by insurance could have a material adverse effect on our financial position.

In any project in which we are not the operator, we will require the operator to maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. The occurrence of a significant adverse event on any of these projects if they are not fully covered by insurance could result in the loss of all or part of our investment. The loss of any such project investment could have a material adverse effect on our financial condition and results of operations.

~~New~~Recent ~~technologies~~action ~~may~~by ~~cause~~the State ~~our~~of ~~current~~California ~~exploration~~imposing additional financial assurance requirements related to plugging and abandonment costs, decommissioning, and site restoration on those who acquire the right to operate wells and ~~drilling~~production ~~methods~~facilities could impact our ability to ~~become~~sell ~~obsolete~~or acquire assets in the state of California or increase our costs in connection with the same.

~~There~~On ~~have~~October ~~been~~7, ~~rapid~~2023, ~~and~~the ~~significant~~California Governor ~~advancements~~signed into law Assembly Bill 1167 (“AB 1167”), which imposes more stringent financial assurance requirements on inpersons ~~technology~~who inacquire the ~~natural~~right ~~gas~~to ~~and~~operate ~~crude~~a ~~oil~~well ~~industry,~~or ~~including~~production facility in the ~~introduction~~state of ~~new~~California, ~~products~~requiring ~~and~~them ~~services~~to ~~using~~file ~~new~~either ~~technologies.~~an individual Asindemnity ~~competitors~~bond ~~use~~for single-well or ~~develop~~production ~~new~~facility ~~technologies~~acquisitions, weor ~~may~~a blanket indemnity bond for multiple wells or production facilities. The bond imposed on the acquirer will be ~~placed~~in atan aamount ~~competitive~~determined ~~disadvantage~~by the state to sufficiently cover plugging and abandonment costs, decommissioning, and ~~competitive~~site ~~pressures~~restoration, ~~may~~and ~~force~~AB ~~us to~~1167 ~~implement~~prohibits ~~new~~the ~~technologies~~closing atof any acquisition of a ~~substantial~~well ~~increase~~or inproduction ~~cost.~~facility ~~Further,~~until ~~competitors~~a ~~may~~determination ~~obtain~~on ~~patents~~the appropriate ~~which~~bond ~~might~~amount ~~prevent~~has usbeen ~~from~~completed ~~implementing new~~by ~~technologies.~~the Instate ~~addition,~~and ~~competitors~~the ~~may~~bond ~~have~~has ~~greater~~been ~~financial,~~filed. ~~technical~~We ~~and~~are ~~personnel~~still ~~resources~~assessing ~~that~~the ~~allow~~impact ~~them~~of toAB ~~enjoy~~1167. ~~technological~~In ~~advantages~~addition, ~~and~~although ~~may~~AB in1167 ~~the~~has ~~future~~been ~~allow~~signed ~~them~~into tolaw, ~~implement~~Governor ~~new~~Newsom ~~technologies~~has ~~before~~called wefor ~~can.~~further ~~One~~legislative orchanges ~~more~~to ofthese new requirements to mitigate against the ~~technologies~~potential ~~that~~risk weof ~~currently use~~the orimplementation ~~that~~of weAB ~~may~~1167 ~~implement~~ultimately inincreasing the ~~future~~number ~~may~~of ~~become~~orphaned ~~obsolete.~~idle Weor ~~cannot~~low-producing wells bein ~~certain~~California. ~~that~~However, we ~~will~~cannot bepredict ~~able~~what toform ~~implement~~these ~~technologies~~changes ~~on a~~may ~~timely~~ultimately ~~basis~~take or atif athe ~~cost~~legislature ~~that~~will isact ~~acceptable~~on tothe usGovernor’s request. IfImplementation weof ~~are~~this ~~unable~~law may lead to ~~maintain~~the ~~technological~~delay ~~advancements~~or ~~consistent~~additional costs with ~~industry standards~~respect to acquisitions or dispositions, which could impact our ~~operations~~ability ~~and~~to ~~financial~~grow ~~condition~~or ~~may~~explore benew ~~adversely~~strategic ~~affected~~areas – or exit others – within the state of California.

We are subject to economic downturns and the effects of public health events, such as the COVID-19 pandemic, which may materially and adversely affect the demand and the market price for our products.

The severity, magnitude and duration of COVID-19 or another pandemic, the extent of actions that have been or may be taken to contain or treat their impact, and the impacts on the economy generally and oil prices in particular, are uncertain, rapidly changing and hard to predict. This uncertainty could force us to reduce costs, including by decreasing operating expenses and lowering capital expenditures, and such actions could negatively affect future production and our reserves. We may experience labor shortages if our employees are unwilling or unable to come to work because of illness, quarantines, government actions or other restrictions in connection with the pandemic. If our suppliers cannot deliver the materials, supplies and services we need, we may need to suspend operations. In addition, we are exposed to changes in commodity prices which have been and will likely remain volatile. We cannot predict the duration and extent of the pandemic's adverse impact on our operating results.

Additionally, to the extent the COVID-19 pandemic or any resulting worsening of the global business and economic environment adversely affects our business and financial results, it may also have the effect of heightening or exacerbating many of the other risks described in the Risk Factors herein.

Risks related to Environmental Regulation

~~Recent~~Our ~~and~~crude ~~future~~oil ~~actions~~and bynatural ~~the~~gas ~~state~~exploration ~~of California~~and ~~could~~production, ~~result~~and inrelated ~~restrictions~~activities are subject to ~~our~~extensive ~~operations~~environmental regulations, and ~~result~~to inlaws ~~decreased~~that ~~demand~~can ~~for~~give ~~oil~~rise ~~and~~to ~~gas~~substantial ~~within~~liabilities from ~~the~~environmental ~~state~~contamination.

InOur ~~September~~operations ~~2020,~~are ~~Governor~~subject ~~Gavin~~to ~~Newsom~~extensive offederal, ~~California~~state ~~issued~~and anlocal ~~executive~~environmental ~~order~~laws ~~(Order)~~and ~~that~~regulations, ~~seeks~~which toimpose ~~reduce~~limitations ~~both~~on the ~~demand~~discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and ~~supply~~disposal of ~~petroleum~~hazardous ~~fuels~~materials inand ~~the~~of ~~state.~~solid ~~The~~and ~~Order~~hazardous ~~establishes~~wastes, ~~several~~and ~~goals~~impose ~~and~~obligations ~~directs~~to ~~several~~investigate ~~state~~and ~~agencies~~remediate tocontamination ~~take~~in certain ~~actions~~circumstances. ~~with~~Liabilities ~~respect~~ to ~~reducing~~investigate ~~emissions~~or ofremediate ~~GHGs~~contamination, as ~~including,~~well ~~but~~as ~~not limited~~other ~~to:~~liabilities ~~phasing~~concerning ~~out~~hazardous ~~the~~materials ~~sale~~or ofcontamination ~~new~~such ~~emissions-producing~~as ~~passenger~~claims ~~vehicles~~for personal injury or property damage, ~~drayage~~may arise ~~trucks~~at ~~and~~many ~~off-road~~locations, ~~vehicles~~including byproperties ~~2035~~in ~~and~~which we have an ownership interest but no operational control, toproperties ~~the~~we formerly ~~extent~~owned ~~feasible~~or operated, ~~medium~~ and ~~heavy~~sites ~~duty~~where ~~trucks~~our bywastes ~~2045;~~have ~~developing~~been ~~strategies~~treated ~~for~~or ~~the~~disposed ~~closure~~of, ~~and~~as ~~repurposing~~well ofas ~~oil~~at ~~and~~properties ~~gas~~that ~~facilities in~~we ~~California;~~currently ~~and~~own ~~proposing~~or ~~legislation~~operate. Such toliabilities ~~end~~may arise even where the ~~issuance~~contamination ofdoes ~~new~~not ~~hydraulic~~result ~~fracturing~~from ~~permits~~any innoncompliance ~~the~~with ~~state~~applicable byenvironmental ~~2024~~laws. ~~The~~Under a ~~Order~~number ~~also directs~~of ~~the~~environmental ~~California~~laws, ~~Department~~such ofliabilities ~~Conservation,~~may ~~Geologic~~also ~~Energy~~be ~~Management~~joint ~~Division~~and ~~(CalGEM)~~several, tomeaning ~~strictly~~that ~~enforce~~we ~~bonding~~could ~~requirements for~~be ~~oil~~held ~~and~~responsible ~~gas~~for ~~operations~~more ~~and~~than our toshare ~~complete~~of ~~its~~the ~~ongoing~~liability

15 19

~~public~~involved, ~~health~~or ~~and~~even ~~safety~~the ~~review~~entire ofshare. ~~oil~~Environmental requirements ~~production~~generally ~~and~~have ~~propose~~become ~~additional~~more ~~regulations, which~~stringent ~~are~~in ~~expected~~recent toyears, ~~include~~and ~~expanded~~compliance ~~land~~with ~~use~~those ~~setbacks~~requirements ormore ~~buffer zones~~expensive.

InWe ~~October~~have ~~2020,~~incurred ~~the~~expenses ~~Governor~~in ~~issued~~connection anwith ~~executive~~environmental ~~order~~compliance, ~~that~~and ~~establishes~~we aanticipate ~~state~~that ~~goal~~we will continue to ~~conserve~~do atso ~~least~~in ~~30%~~the offuture. ~~California’s~~Failure ~~land~~to ~~and~~comply ~~coastal~~with ~~waters~~extensive byapplicable ~~2030~~environmental laws and ~~directs~~regulations ~~state~~could ~~agencies to~~result ~~implement~~in ~~other~~significant ~~measures~~civil toor ~~mitigate~~criminal ~~climate~~penalties ~~change~~ and ~~strengthen~~remediation ~~biodiversity~~costs. InSome ~~February~~of ~~2021,~~our SBproperties ~~467~~may ~~was~~be ~~introduced in the state~~affected ~~senate.~~by Ifenvironmental ~~passed,~~contamination ~~the~~that ~~bill~~may ~~would~~require ~~ban~~investigation ~~new~~or ~~permits~~remediation. ~~for~~In ~~hydraulic fracturing~~addition, ~~acid~~claims ~~well~~are ~~stimulation~~sometimes ~~treatments,~~made ~~cyclic~~or ~~steaming,~~threatened ~~water flooding~~against ~~and~~companies ~~steam~~engaged ~~flooding – beginning~~ in ~~2022~~crude oil and ~~would~~natural ~~ban~~gas ~~these~~exploration ~~activities~~and inproduction ~~total~~by ~~beginning~~owners inof ~~2027.~~surface ~~The~~estates, ~~bill~~adjoining ~~would~~properties ~~also~~or ~~allow local~~others ~~governments~~alleging todamage ~~prohibit~~resulting ~~such~~from ~~practices~~environmental ~~prior~~contamination toand ~~2027.~~other ~~After~~incidents ~~the bill was introduced one~~ of ~~the~~operation. ~~authors~~Compliance ~~announced that it would also be amended to also add a 2~~with,~~500~~ ~~feet~~and ~~setback~~liabilities for ~~new wells from sensitive receptors. We cannot predict the outcome of this most recent legislative~~remediation ~~effort.~~under, ~~Previous~~these ~~high~~laws ~~profile~~and ~~efforts to pass mandatory setbacks have failed; however~~regulations, ~~any of the foregoing developments~~ and ~~other~~liabilities ~~future actions~~concerning ~~taken~~contamination byor ~~the~~hazardous ~~state~~materials, may ~~materially and~~ adversely affect our ~~operations~~business, financial ~~and~~condition ~~properties~~ and ~~the~~results ~~demand~~of ~~for our products~~operations.

We face various risks associated with the trend toward increased anti-crude oil and natural gas development activity.

In recent years, we have seen significant growth in opposition to crude oil and natural gas development in the United States. Companies in our industry can be the target of opposition to hydrocarbon development from stakeholder groups, including national, state and local governments, regulatory agencies, non-government organizations and public citizens. This opposition is focused on attempting to limit or stop hydrocarbon development. Examples of such opposition include: efforts to reduce access to public and private lands; delaying or canceling permits for drilling or pipeline construction; limiting ore banning industry techniques such as hydraulic fracturing, and/or adding restrictions on or the use of water and associated disposal; imposition of set-backs on crude oil and natural gas sites; delaying or denying air-quality permits; advocating for increased punitive taxation or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm. Recent efforts by the US Administration to modify federal crude oil and natural gas regulations could intensify the risk of anti-development efforts from grass roots opposition.

Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements from these efforts, could have a material adverse effect on our business.

Restricted land access could reduce our ability to explore for and develop crude oil and natural gas reserves.

Our ability to adequately explore for and develop crude oil and natural gas resources is affected by a number of factors related to access to land. Examples of factors which reduce our access to land include, among others:

—· new municipal, state or federal land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;

—· local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;

—· landowner, community and/or governmental opposition to infrastructure development;

—· regulation of federal and Indian land by the Bureau of Land Management;

—· anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, disruption of drilling, or damage to equipment;

—· the presence of threatened or endangered species or of their habitat;

—· Disputes regarding leases; and

—· Disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements.

Reduced ability to obtain new leases could constrain our future growth and opportunity resulting in a material adverse effect on our business, financial condition, results of operations and our cash flows.

16 20

~~Our~~Recent ~~crude~~and ~~oil~~future ~~and~~actions ~~natural~~by ~~gas~~the ~~exploration~~state ~~and production,~~of California and ~~related~~local ~~activities~~governments ~~are~~could ~~subject~~result toin ~~extensive~~restrictions ~~environmental~~to ~~regulations,~~our operations and toresult ~~laws~~in ~~that~~decreased ~~can~~demand ~~give~~for ~~rise~~oil toand ~~substantial~~gas ~~liabilities from~~within ~~environmental~~the ~~contamination~~state.

~~Our~~In ~~operations~~September ~~are~~2020, ~~subject~~Governor toGavin ~~extensive~~Newsom ~~federal,~~of ~~state~~California ~~and~~issued ~~local~~an ~~environmental~~executive ~~laws~~order ~~and~~(the ~~regulations,~~“Order”) ~~which~~that ~~impose~~seeks ~~limitations~~to onreduce both the ~~discharge~~demand offor ~~pollutants~~and ~~into~~supply ~~the~~of ~~environment,~~petroleum ~~establish standards~~fuels ~~for~~in the ~~management,~~state. The ~~treatment,~~Order ~~storage,~~establishes ~~transportation~~several goals and ~~disposal~~directs ofseveral ~~hazardous~~state ~~materials~~agencies ~~and~~to oftake ~~solid~~certain ~~and~~actions ~~hazardous~~with ~~wastes~~respect to reducing emissions of GHGs, ~~and~~including, ~~impose~~but ~~obligations~~not limited to: ~~investigate~~phasing ~~and~~out ~~remediate~~the ~~contamination~~sale inof ~~certain~~new ~~circumstances.~~emissions-producing ~~Liabilities~~passenger tovehicles, ~~investigate~~drayage ortrucks ~~remediate~~and ~~contamination,~~off-road vehicles asby ~~well~~2035 asand, ~~other~~to ~~liabilities~~the ~~concerning~~extent ~~hazardous~~feasible, ~~materials~~medium orand ~~contamination~~heavy ~~such~~duty astrucks ~~claims~~by 2045; developing strategies for ~~personal~~the ~~injury~~repurposing orof ~~property~~crude ~~damage,~~oil ~~may~~and ~~arise~~natural atgas ~~many~~facilities ~~locations,~~in ~~including~~California; ~~properties~~and inproposing ~~which~~legislation weto ~~have~~end anthe ~~ownership~~issuance ~~interest~~of ~~but~~new nohydraulic ~~operational~~fracturing ~~control,~~permits ~~properties~~in wethe ~~formerly~~state by ~~owned~~2024. orThe ~~operated,~~Order ~~and~~also ~~sites~~directs ~~where~~the ~~our~~California ~~wastes~~Department ~~have~~of ~~been~~Conservation, ~~treated~~Geologic orEnergy ~~disposed~~Management ~~of,~~Division as(“CalGEM”) ~~well~~to strictly asenforce atbonding ~~properties~~requirements ~~that~~for weoil ~~currently~~and ~~own~~gas oroperations ~~operate. Such~~and ~~liabilities~~to ~~may~~complete ~~arise~~its ~~even~~ongoing ~~where~~public ~~the~~health ~~contamination~~and ~~does~~safety ~~not~~review ~~result~~of ~~from~~oil ~~any~~production and ~~noncompliance~~propose ~~with~~additional ~~applicable~~regulations, ~~environmental~~which ~~laws.~~are ~~Under a~~expected ~~number~~to ofinclude ~~environmental~~expanded ~~laws,~~land ~~such~~use ~~liabilities~~setbacks ~~may~~or ~~also~~buffer bezones. ~~joint~~In ~~and~~October ~~several~~2020, ~~meaning~~the ~~that~~Governor issued wean ~~could~~executive beorder ~~held~~that ~~responsible~~establishes ~~for~~a ~~more~~state ~~than our~~goal ~~share~~to ofconserve ~~the~~at ~~liability~~least ~~involved,~~30% orof ~~even~~California’s ~~the~~land ~~entire~~and ~~share.~~coastal ~~Environmental~~waters ~~requirements~~by ~~generally~~2030 and ~~have~~directs ~~become~~state ~~more~~agencies ~~stringent~~to inimplement ~~recent years,~~other ~~and~~measures ~~compliance~~to ~~with~~mitigate ~~those~~climate ~~requirements~~change ~~more~~and ~~expensive~~strengthen biodiversity.

WeOn ~~have~~September ~~incurred~~16, ~~expenses~~2022, inthe ~~connection~~Governor ~~with~~of ~~environmental~~California ~~compliance,~~signed ~~and~~Senate weBill ~~anticipate~~No. ~~that~~1137 weinto ~~will~~law, ~~continue~~which toestablished do3,200 sofeet inas the ~~future.~~minimum ~~Failure~~distance tobetween ~~comply~~new ~~with~~crude ~~extensive~~oil ~~applicable~~and ~~environmental~~natural gas production ~~laws~~wells and ~~regulations~~certain ~~could~~sensitive ~~result~~receptors insuch ~~significant~~as ~~civil~~homes, orschools ~~criminal~~and ~~penalties~~businesses ~~and~~open ~~remediation~~to ~~costs.~~the ~~Some~~public ofeffective ~~our~~January ~~properties~~1, ~~may~~2023. beOn ~~affected~~January 6, by2023, ~~environmental~~CalGEM's ~~contamination~~emergency ~~that~~regulations ~~may~~to ~~require~~support ~~investigation~~implementation orof ~~remediation~~Senate Bill No. In1137 ~~addition,~~were ~~claims~~approved ~~are~~by ~~sometimes~~the ~~made~~Office orof ~~threatened~~Administrative ~~against~~Law ~~companies~~and ~~engaged~~final inregulations ~~crude~~were ~~oil~~published. The regulations included applicable requirements of notice to property owners and ~~natural~~tenants ~~gas~~regarding the ~~exploration~~work performed and ~~production~~offering bythe ~~owners~~sampling of test water wells or surface ~~estates,~~water ~~adjoining~~before ~~properties~~and orafter ~~others alleging~~drilling; ~~damage~~the ~~resulting~~contents ~~from~~of ~~environmental~~required notices ~~contamination~~for ~~and~~new ~~other~~production ~~incidents~~facilities; the annual submission of ~~operation.~~a ~~Compliance~~sensitive ~~with,~~receptor inventory and ~~liabilities~~sensitive ~~for~~receptor ~~remediation under,~~map ~~these~~and ~~laws~~the contents and ~~regulations,~~format of the same; and ~~liabilities~~the ~~concerning~~requirements ~~contamination~~of orstatements ~~hazardous~~where ~~materials,~~operators ~~may~~have ~~adversely~~determined ~~affect~~a ~~our~~location ~~business, financial~~not ~~condition~~to ~~and~~be ~~results~~within ofa ~~operations~~health protection zone.

~~Climate~~Additional ~~change~~provisions ~~legislation~~of orSenate ~~regulations~~Bill ~~restricting~~No. 1137 include, ~~emissions~~among others, the imposition of ~~greenhouse~~health, ~~gases~~safety ~~(“GHG”)~~and ~~could~~environmental ~~result~~controls inapplicable ~~increased~~to ~~operating~~both ~~costs~~current and ~~reduced~~new ~~demand~~wells ~~for~~located within this distance of sensitive receptors related to noise, light, and dust pollution controls and air emission monitoring, and the ~~crude~~immediate ~~oil~~suspension of weoperations ~~produce~~at production facilities determined to not be in compliance with certain air emission requirements.

Climate change ~~continues~~legislation toor ~~attract~~regulations ~~considerable public~~restricting and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of ~~GHGs.~~greenhouse ~~These~~gases ~~efforts~~(“GHG”) ~~have~~could ~~included~~result ~~consideration~~in byincreased ~~states~~operating ~~or groupings~~costs ~~of states of cap-~~and~~-trade~~ ~~programs,~~reduced ~~carbon~~demand ~~taxes,~~for ~~GHG~~the ~~reporting~~crude ~~and~~oil ~~tracking programs,~~ and ~~regulations that directly limit~~natural ~~GHG~~gas ~~emissions~~we ~~from certain sources~~produce.

AtClimate ~~the federal level, no comprehensive climate~~ change ~~legislation~~ ~~has~~continues ~~been implemented~~ to ~~date.~~attract ~~However,~~considerable ~~the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to~~ public ~~health~~ and ~~the~~scientific ~~environment and has adopted regulations under existing provisions of the Clean Air Act~~attention. ~~The~~As ~~EPA has~~a ~~also~~result, ~~adopted~~numerous ~~rules~~proposals ~~requiring~~have ~~the~~been ~~monitoring~~made and ~~reporting~~are oflikely ~~GHG~~to ~~emissions~~continue ~~from~~to ~~specified~~be ~~sources~~made inat the ~~United States on an annual basis~~international, ~~including~~national, ~~among others~~ regional, ~~onshore~~ and ~~offshore~~state ~~crude~~levels ~~oil~~of ~~and~~government ~~natural~~to ~~gas~~monitor ~~production facilities~~ and ~~onshore~~limit ~~processing,~~emissions ~~transmission, storage~~of ~~and distribution facilities~~GHGs. InThese ~~October~~efforts ~~2015,~~have ~~the~~included ~~EPA~~consideration ~~amended~~by ~~and~~states ~~expanded~~or groupings ~~the~~of ~~GHG~~states ~~reporting requirements to all segments~~ of ~~the crude oil~~ cap-and-trade ~~natural~~programs, ~~gas~~carbon ~~industry~~taxes, ~~including~~GHG ~~gathering~~reporting and ~~boosting~~tracking ~~facilities~~programs, and ~~blowdowns~~regulations ofthat ~~natural~~directly ~~gas transmission pipelines, and~~limit inGHG ~~January~~emissions ~~2016,~~from ~~the~~certain ~~EPA proposed additional revisions to leak detection methodology~~sources.

~~The~~At ~~adoption~~the ~~and~~federal ~~implementation~~level, ofno ~~any~~comprehensive ~~international,~~climate change ~~federal~~legislation orhas ~~state~~been ~~legislation,~~implemented ~~regulations~~to ordate. ~~other~~However, ~~regulatory~~the ~~initiatives~~EPA ~~that~~has ~~require~~determined ~~reporting~~that emissions of ~~GHGs~~carbon ordioxide, ~~otherwise~~methane ~~restricts~~and ~~emissions of~~other GHGs ~~from~~present an ~~our~~endangerment ~~equipment~~to ~~and~~public ~~operations~~health ~~could~~and ~~cause~~the usenvironment toand ~~incur~~has ~~increased~~adopted ~~costs~~regulations ~~that~~under ~~could~~existing ~~have~~provisions anof ~~adverse~~the ~~effect~~Clean onAir ~~our~~Act. ~~business,~~The ~~financial~~EPA ~~condition~~has ~~and~~also ~~results~~adopted ofrules ~~operations.~~requiring ~~Moreover,~~the ~~such~~monitoring ~~new~~and ~~legislation~~reporting orof ~~regulatory~~GHG ~~programs~~emissions ~~could~~from ~~also~~specified ~~increase~~sources in the ~~cost~~United toStates ~~the~~on ~~consumer,~~an annual ~~and~~basis, ~~thereby~~including, ~~reduce~~among ~~demand~~others, ~~for~~onshore and offshore crude oil and natural gas production facilities and onshore processing, ~~which~~transmission, storage, ~~could~~and ~~reduce~~distribution facilities. In October 2015, the ~~demand~~EPA ~~for~~amended and expanded the GHG reporting requirements to all segments of the crude oil orand natural gas weindustry, ~~produce~~including gathering and boosting facilities and blowdowns of natural gas transmission pipelines, ~~lower~~and in January 2016, the ~~value~~EPA ofproposed ~~our~~additional ~~reserves~~revisions to leak detection methodology.

~~Finally,~~The itadoption ~~should~~and beimplementation ~~noted that some scientists have concluded that increasing concentrations~~ of ~~greenhouse~~any ~~gases in the Earth’s atmosphere may be associated with extreme weather conditions~~international, ~~such as more intense hurricanes~~federal, ~~thunderstorms, tornados and snow~~ or ~~ice~~state ~~storms~~legislation, asregulations ~~well~~or asother ~~rising~~regulatory ~~sea~~initiatives ~~levels.~~that ~~Another~~require ~~possible~~reporting ~~consequence~~ of ~~climate~~GHGs ~~change~~or isotherwise ~~increased~~restricts ~~volatility~~emissions of inGHGs ~~seasonal~~from ~~temperatures.~~our ~~Some~~equipment ~~studies~~and ~~indicate~~operations ~~that climate change~~ could cause ~~some~~us ~~areas~~ to ~~experience~~ ~~temperatures~~incur ~~substantially~~increased ~~hotter~~costs orthat ~~colder~~could ~~than~~have ~~their~~an ~~historical~~adverse ~~averages.~~effect ~~Extreme~~on ~~weather~~our ~~conditions~~business, ~~can interfere with our~~financial ~~production~~condition, and ~~increase~~results ~~our~~of ~~operating expenses~~operations. ~~Such~~Moreover, ~~damage~~such ornew ~~increased~~legislation ~~expenses~~or ~~from~~regulatory ~~extreme~~programs ~~weather~~could ~~may~~also ~~not~~increase bethe ~~fully~~cost ~~insured.~~to Ifthe ~~any~~consumer, ~~such~~and ~~effects~~thereby ~~were~~reduce todemand ~~occur,~~for ~~they~~crude ~~could~~oil ~~have~~and annatural ~~adverse~~gas, ~~effect~~which oncould ~~our~~reduce ~~financial~~the ~~condition~~demand ~~and~~for ~~results~~the ofcrude ~~operations.~~oil Ator ~~this~~natural ~~time,~~gas we ~~have~~produce and ~~not~~lower ~~developed a comprehensive plan to address~~ the ~~legal,~~value ~~economic, social or physical impacts~~ of ~~climate change on~~ our ~~operations~~reserves.

17 Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or

colder than their historical averages. Extreme weather conditions can interfere with our production and increase our operating expenses. Such damage or increased expenses from extreme weather may not be fully insured. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.

The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new costs on our operations.

In August 2022, President Biden signed the Act into law. The Act contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure among other provisions. In addition, the Act imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The Act amends the Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore crude oil and natural gas production categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year thereafter. Calculation of the fee is based on certain thresholds established in the Act. In addition, the multiple incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy away from fossil fuels towards lower- or zero-carbon emission alternatives. The methane charges and various incentives for clean energy industries could decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently materially and adversely affect our business and results of operations.

Risks Related to Our Indebtedness

We have experienced significant operating losses in the past and there can be no assurance that we will become profitable in the future.

We have reported net loss of approximately $~~398,450~~2.4 million for the year ended February 28, ~~2022~~2023, and we have an accumulated deficit through February 28, ~~2022~~2023 of approximately $2931.5 96 million. Without successful exploration and development of our properties and a significant sustained increase in hydrocarbon prices any investment in Daybreak could become devalued or worthless.

WeOur ~~have~~ability ~~substantial~~to ~~indebtedness.~~satisfy ~~The amount~~our ofobligations depends on our ~~outstanding~~future ~~indebtedness~~operating performance and on economic, financial, competitive and other factors, many of which are beyond our ~~current~~control. ~~inability~~Our business does not generate sufficient cash flow to meet our ~~debt~~ongoing obligations, ~~will~~and ~~have~~future ~~adverse~~financings ~~consequences~~may onnot be available to provide sufficient net proceeds, to meet these obligations or to successfully execute our business strategy. Our future performance, in turn, is dependent upon many factors that are beyond our control such as the level of hydrocarbon prices and general economic, financial and ~~condition~~business conditions. We cannot guarantee that our future performance will not be adversely affected by such economic conditions and financial, ~~results~~business ofand ~~operations~~other factors.

AtWe ~~February~~have ~~28,~~substantial ~~2022, we had approximately $4.3 million of consolidated~~ indebtedness ~~comprised of a variety of short-term and long-term borrowings; a line of credit; trade payables; and 12% Subordinated Notes~~. The 12% Notes had a maturity date of January 29, 2019 and the principal balance of $315,000 has not been paid. The level of indebtedness we have affects our operations in a number of ways. We will need to use a portion of our cash flow to meet principal, interest and payables commitments; which reduces the amount ~~of funds we will have available to finance our operations.~~ ~~This lack~~ of ~~funds limits planning for or reacting to changes in~~ our ~~business~~outstanding ~~and~~indebtedness ~~the industry in which we operate~~ and ~~could limit~~ our ~~ability~~ tocurrent ~~make~~inability ~~funds available for other purposes, such as future exploration, development or acquisition activities. Our ability~~ to meet our debt ~~service~~ obligations ~~and reduce our total indebtedness~~ will ~~depend~~have ~~upon~~adverse ~~our~~consequences ~~future~~on ~~performance. Our future performance, in turn, is dependent upon many factors that are beyond~~ our ~~control such as the level of hydrocarbon prices and general economic~~business, ~~financial~~ ~~and business conditions. We cannot guarantee that our future performance will not be adversely affected by such economic conditions and~~ financial condition, ~~business~~ and ~~other~~results ~~factors~~of operations.

~~General~~At ~~Risk~~February ~~Factors~~28, 2023, we had approximately $4.2 million of consolidated indebtedness comprised of a variety of short-term and long-term borrowings; trade payables; and 12% Subordinated Notes. The 12% Notes had a maturity date of January 29, 2019 and the principal balance of $290,000 has not been paid. Our level of indebtedness could affect our business in several ways, including the following:

~~Certain~~· ~~U.S.~~limit ~~federal~~management’s ~~income~~discretion ~~tax~~in ~~deductions~~operating ~~currently available~~our ~~with~~business ~~respect~~and toour ~~crude~~flexibility ~~oil~~in ~~and~~planning ~~natural~~for, ~~gas~~or ~~exploration~~reacting ~~and~~to, ~~development~~changes ~~may~~in beour ~~eliminated~~business asand athe ~~result~~industry ofin ~~proposed~~which ~~legislation.~~we operate;

~~Legislation~~· ~~previously~~require ~~has~~us ~~been proposed that would, if enacted into law, make significant changes~~ to ~~United~~dedicate ~~States~~a ~~federal~~portion ~~income tax laws, including the elimination~~ of ~~certain key~~our ~~U.S.~~cash ~~federal~~flows ~~income~~from ~~tax~~operations ~~incentives currently available~~ to ~~crude~~service ~~oil~~our ~~and~~existing ~~natural gas exploration and production companies. These changes include~~debt, ~~but~~thereby ~~are~~reducing ~~not~~cash limited to: (1) the repeal of the percentage depletion allowance for crude oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain U.S. domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this type of legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available ~~with respect~~ to ~~crude~~finance ~~oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in~~ our ~~Common~~operations ~~Stock as well as affect our financial condition~~ and ~~results~~other ofbusiness ~~operations.~~activities;

We· ~~may~~increase ~~lose~~our ~~key~~vulnerability ~~management~~to ~~personnel~~downturns ~~which~~and ~~could endanger~~adverse ~~the~~developments ~~future~~in ~~success of~~ our ~~crude~~business ~~oil~~ and ~~natural~~the ~~gas~~economy ~~operations.~~generally; and,

~~Our~~· ~~President~~limit ~~and Chief Executive Officer, who is also acting as~~ our ~~interim~~access ~~principal~~to ~~finance~~capital ~~and~~markets ~~accounting~~to ~~officer,~~raise ~~our~~capital ~~Director~~on offavorable ~~Field~~terms ~~Operations, and two of our directors each have substantial experience in the crude oil and natural gas business. The loss of any of these individuals could adversely affect our business. If one~~ or ~~more~~to ~~members~~obtain ofadditional ~~our~~financing ~~management~~for ~~team~~working ~~dies~~capital, ~~becomes~~capital ~~disabled~~expenditures, ~~or voluntarily terminates employment with us~~acquisitions, ~~there~~general iscorporate ~~no assurance that a suitable~~ or ~~comparable~~other ~~substitute will be found~~expenses.

~~A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.~~22

A terrorist attack, anti-terrorist efforts or other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for crude oil and natural gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues. Crude oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of crude oil and natural gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Related to Our Common Stock

We may be unable to continue as a going concern in which case our ~~securities~~Common Stock will have little or no value.

Our financial statements for the year ended February 28, ~~2022~~2023 were 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 inception, which raises substantial doubt about our ability to continue as a going concern. In the event we are not able to continue operations, an investor will likely suffer a complete loss of their investment in our securities.

The market price of our Common Stock has been volatile, which may cause the investment value of our stock to decline.

As of February 28, 2023, Daybreak’s Common Stock (OTC Pink: DBRM) ~~trades~~ traded on the OTC Pink® Open Market under the OTC Markets Group segment, Pink Current Information. Prior to May 1, 2016, our stock had traded on the OTCQB Venture Marketplace. Our transition to the OTC Pink® Open Market was the result of a cost-savings move for the company related to listing fees on the Venture Marketplace.

In September 2023, information on our Common Stock was transferred to the OTC Expert Market. This move to the Expert Market was triggered by a lack of current financial information being available due to delays in the filing of this 10-K filing for the year ended February 28, 2023, and subsequent 10-Q reports. These delays were caused by difficulties in completing the required two-year audit of Reabold California, LLC. following the acquisition in May 2022. The audit was subsequently completed in July 2023. We anticipate that once we are current with our public company filings, our Common Stock will again be quoted on the OTC Pink Open® Market, although we can provide no assurances as to the timing or our ultimate success in this regard.

Because of the limited liquidity of our stock, shareholders may be unable to sell their shares at or above the cost of their purchase prices. The trading price of our shares has experienced wide fluctuations and these shares may be subject to similar fluctuations in the future.

The trading price of our Common Stock may be affected by a number of factors including events described in these risk factors, as well as our operating results, financial condition, announcements of drilling activities, general conditions in the crude oil and natural gas exploration and development industry including volatility in crude oil and natural gas prices, and other events or factors. The instability and volatility in hydrocarbon prices that has occurred since June 2014, has had a corresponding material and mostly adverse impact on our revenues and a similar direct material adverse impact on the trading price of our Common Stock.

In recent years, broad stock market indices, in general, and smaller capitalization companies, in particular, have experienced substantial price fluctuations. In a volatile market, we do experience wide fluctuations in the market price of our Common Stock. These fluctuations may have a negative effect on the market price of our Common Stock.

Pursuant to SEC rules our Common Stock is classified as a “penny stock” increasing the risk of investment in these shares.

Our Common Stock is designated as a “penny stock” and thus may be more illiquid than shares traded on an exchange or on NASDAQ. Penny stocks generally are any non-NASDAQ or non-exchange listed equity securities with a price of less than $5.00, subject to certain exceptions.

The “penny stock” reporting and disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for a stock that is subject to these rules. The market liquidity for the shares could be severely and adversely affected by limiting the ability of broker-dealers to sell these shares.

We have a limited operating history on which to base an investment decision.

To date, while we generally have had positive cash flow from our operations in California, we have not yet generated sustainable positive cash flow or earnings on a company-wide basis. We cannot provide any assurances that we will ever operate profitably especially in the current low-priced hydrocarbon environment. As a result of our limited operating history, we are more susceptible to business risks. These risks include unforeseen capital requirements, failure to establish business relationships, and competitive disadvantages against larger and more established companies.

The resale of shares offered in private placements could depress the value of the shares.

In the past, shares of our Common Stock have been offered and sold in private placements at significant discounts to the trading price of the Common Stock at the time of the offering. Sales of substantial amounts of Common Stock eligible for future sale in the public market, or the availability of shares for sale, including shares issued upon exercise of outstanding warrants, could adversely affect the prevailing market price of our Common Stock and our ability to raise capital by an offering of equity securities.

~~Privately placed issuances of our Common Stock, Preferred Stock and warrants have and may continue to dilute ownership interests which could have an adverse effect on our stock prices.~~23

~~Our~~Privately ~~authorized~~placed ~~capital~~issuances ~~stock consists~~ of ~~200,000,000 shares~~our of Common Stock and ~~10,000,000~~warrants ~~shares~~have ofand ~~preferred~~may ~~stock.~~continue Asto ofdilute ~~February~~ownership ~~28,~~interests ~~2022,~~which ~~there~~could ~~were~~have ~~67,802,273~~an ~~shares~~adverse ofeffect ~~Common~~on ~~Stock issued~~our ~~and~~stock ~~outstanding~~prices.

~~Historically~~Our weauthorized ~~have~~capital ~~issued,~~stock ~~and~~consists ~~likely~~of ~~will continue to issue~~500, ~~additional~~ 000,000 shares of ~~our~~ Common Stock. inAs ~~connection with the compensation~~ of ~~personnel,~~February ~~future acquisitions~~28, ~~private placements~~2023, ~~possible~~ ~~equity~~there ~~swaps~~were ~~for~~384,734,902 ~~debt~~shares orof ~~for~~Common ~~other~~Stock ~~business~~issued ~~purposes~~and outstanding. ~~Future~~With ~~issuances~~the filing of ~~substantial~~our ~~amounts~~Company’s ofSecond ~~these~~Amended ~~equity~~and ~~securities~~Restated ~~could have~~Articles aof ~~material~~Incorporation ~~adverse~~with ~~effect on~~ the ~~market~~Washington ~~price~~Secretary of ~~our~~State ~~Common Stock, and would result~~ in ~~further~~May ~~dilution~~2022, ofwe ~~the ownership interests~~no oflonger ~~our~~have ~~existing~~any ~~shareholders~~preferred stock.

Historically we have issued, and likely will continue to issue, additional shares of our Common Stock in connection with the compensation of personnel, future acquisitions, private placements, possible equity swaps for debt or for other business purposes. Future issuances of substantial amounts of these equity securities could have a material adverse effect on the market price of our Common Stock and would result in further dilution of the ownership interests of our existing shareholders.

We will need to seek to raise additional funds in the future through debt financing, which may impose operational restrictions and may further dilute existing ownership interests.

We expect to seek to raise additional capital in the future to help fund our acquisition, development, and production of crude oil and natural gas reserves. In the past, we have obtained debt financing through commercial loans and credit facilities. Subsequent debt financing, if available, may require restrictive covenants, which may limit our operating flexibility. Future debt financing may also involve debt instruments that are convertible into or exercisable for Common Stock. The conversion of the debt -to -equity financing may dilute the equity position of our existing shareholders.

We do not anticipate paying dividends on our Common Stock, which could devalue the market value of these securities.

We have not paid any cash dividends on our Common Stock since the Company’s inception in 1955. We do not anticipate paying cash dividends in the foreseeable future. Any dividends paid in the future will be at the complete discretion of our Board of Directors. For the foreseeable future, we anticipate that we will retain any revenues that we may generate from our operations. These retained revenues will be used to finance and develop the growth of the Company. Prospective investors should be aware that the absence of dividend payments could negatively affect the market value of our Common Stock. Investors must rely on sales of their Common Stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our Common Stock.

20 We have two shareholders that own approximately 42% and 40%, respectively, of our outstanding Common Stock shares at February 28, 2023, who may be able to individually or jointly control the operations of the Company.

We face certain risks associated with having these two large shareholders. Individually or jointly they may be able to:

control the elections of persons to the Board of Directors and may elect persons less qualified than would be elected absent the two large shareholders;

influence the Board of Directors to enter into transactions with related or third parties that are more favorable to such parties than would be negotiated by an independent Board of Directors;

control all matters requiring approval by the shareholders including any future issuances of a material number of securities or changes to the Company’s Articles of Incorporation and By-laws, and other major transactions; and,

delay, defer or prevent a change in control or otherwise prevent shareholders other than these two affiliates from influencing our direction and future.

General Risk Factors

Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of proposed legislation.

From time to time, legislation has been proposed that would, if enacted into law, make significant changes to United States federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to crude oil and natural gas exploration and production companies. These changes include, but are not limited to: (1) the repeal of the percentage depletion allowance for crude oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and

development costs, (3) the elimination of the deduction for certain U.S. domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures.

However, it is unclear whether any such changes will be enacted and, if enacted, how soon any such changes could become effective. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced demand for our products. The passage of this type of legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to crude oil and natural gas exploration and development or could increase costs, and any such change could negatively impact the value of an investment in our Common Stock as well as have a negative effect on our financial condition and results of operations.

We may lose key management personnel which could endanger the future success of our crude oil and natural gas operations.

Our President and Chief Executive Officer, who is also acting as our interim principal finance and accounting officer, our Chief Operating Officer and our Director of Field Operations, along with three of our directors have substantial experience in the crude oil and natural gas business. The loss of any of these individuals could adversely affect our business. If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that a suitable or comparable substitute will be found.

A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.

ITEM 1B. UNRESOLVED STAFF COMMENTS

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

2126

ITEM 2. PROPERTIES

We conduct all of our drilling, exploration and production activities in the United States. All of our crude oil assets are located in the United States, and all of our revenues are derived from sales to customers within the United States. During the ~~year~~twelve months ended February 28, ~~2022~~2023, we were involved in ~~the~~two ~~operation~~crude ofoil and natural gas projects in California: a 20 well oilfield project in Kern County, California and a 10 well crude oil and natural gas project in Monterey and Contra Costa Counties in central California.

We have not filed any estimates of total, proved net crude oil or natural gas reserves with any federal agency other than this report to the SEC for the fiscal year ended February 28, ~~2022~~2023. Throughout this Annual Report on Form 10-K, crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).

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, of which 20 wells were successful. We have been the Operator at the East Slopes Project since March 2009.

Our 20 producing 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. ~~Our~~We ~~average~~have ~~working~~no ~~interest~~natural ~~and~~gas ~~NRI~~production inassociated ~~these~~with 20the ~~producing~~East ~~crude~~Slopes ~~oil wells is 36~~Project.~~6% and 28.4%, respectively.~~

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

Sunday Central Processing and Storage Facility

The crude oil produced from our acreage in California is considered heavy crude oil. The crude oil ranges from 14° to 16° API gravity. All of the crude oil from our five producing properties is processed, stored and sold from the Sunday central processing and storage facility. The crude oil must be heated to separate and remove water to prepare it to be sold. We constructed these facilities during the summer and fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines. In 2013, we completed an upgrade to this facility including the addition of a second crude oil storage tank to handle the additional crude oil production from the wells drilled in 2013.

By utilizing the Sunday centralized production facility our average production expenses have been reduced from over $40 per barrel in 2009 to around $24 per barrel of crude oil for the year ended February 28, 2022. With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

California Producing Properties

Sunday Property

In November 2008, we made our initial crude oil discovery drilling the Sunday #1 well. The well was put on production in January 2009. Production is from the Vedder Sand at approximately 2,000 feet. During 2009, we drilled three development wells including one horizontal well: the Sunday #2, Sunday #3 and Sunday #4H wells, respectively. During May and June 2013, we drilled two additional development wells: the Sunday #5 and Sunday #6. We have a 37.5% working interest with a 26.1% net revenue interest (“NRI”) in the Sunday #1 well. For the Sunday #2 and Sunday #3 wells, we have a 33.8% working interest with a 24.3% NRI. In the Sunday #4H well, we have a 33.8% working interest with a 27.1% NRI. In both the Sunday #5 and Sunday #6 wells we have a 37.5% working interest and a NRI of 30.1%. Our average working interest and NRI for the Sunday property six producing wells in aggregate is 35.6% and 27.0%, respectively. The Sunday reservoir is estimated to be approximately 35 acres in size with the potential for at least five more development wells to be drilled in the future.

Bear Property

In February 2009, we made our second crude oil ~~discovery~~ discovery drilling the Bear #1 well, which is approximately one mile northwest of our Sunday discovery. The well was put on production in May 2009. Production is from the Vedder Sand at approximately 2,200 feet. In December 2009, we began a development program on this property by drilling and completing the Bear #2 well. In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells. In May and June 2013, we drilled three additional development wells, the Bear #5, Bear #6 and Bear #7, on this property. In November 2013, we drilled and put on production two additional development wells: Bear #8 and Bear #9. The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least eleven more development wells to be drilled in the future.

In December 2009, we began a development program on this property by drilling and completing the Bear #2 well. In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells. In May and June 2013, we drilled three additional development wells, the Bear #5, Bear #6 and Bear #7, on this property. In November 2013, we drilled and put on production two additional development wells: Bear #8 and Bear #9. We have a 37.5% working interest in all wells on the Bear property. Our NRI in the Bear #1, Bear #2, Bear #3 and Bear #4 wells is 26.1%. For the Bear #5, Bear #6 and Bear #7 wells our NRI is 30.1%. Our NRI in the Bear #8 and Bear #9 wells is 31.7%. The average working interest and NRI for the Bear property for the ten producing wells in aggregate is 37.5% and 28.7%, respectively. The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least eleven more development wells to be drilled in the future.

Black Property

The Black property was acquired through a farm-in arrangement with a local operator. The Black property is just south of the Bear property on the same fault system. The Black #1 well was completed and put on production in January 2010. Production is from the Vedder Sand at approximately 2,200 feet. In May 2013, we drilled a development well, the Black #2, on this property. ~~We have a 33.8% working interest with a 26.8% NRI in the two producing wells on this property.~~ The Black reservoir is estimated to be approximately 13 acres in size with the potential for at least three more development wells to be drilled in the future.

Ball Property

The Ball #1-11 well was put on production in late October 2010. In June 2013 we drilled a development well, the Ball #2-11, on this property. Production on this property is from the Vedder Sand at approximately 2,500 feet. WeThe ~~have~~Ball areservoir ~~37.5%~~is ~~working~~estimated ~~interest~~to ~~with~~be ~~a 31.7% NRI in the two producing wells on this property. Our 3-D seismic data indicates a reservoir of~~ approximately 38 acres in size with the potential for at least three more development wells to be drilled in the future.

Dyer Creek Property

The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010. This well produces from the Vedder Sand and is located to the north of the Bear property on the same trapping fault. ~~We have a 37.5% working interest with a 31.7% NRI in all wells on this property.~~ The Dyer Creek property has the potential for at least one development well in the future.

Sunday Central Processing and Storage Facility

The crude oil produced from our acreage in the East Slopes project is considered heavy crude oil. The crude oil ranges from 15° to 17° API gravity. All of the crude oil from our five producing properties is processed, stored and sold from the Sunday central processing and storage facility. The crude oil must be heated to separate and remove water to prepare it to be sold. In 2013, we completed an upgrade to this facility including the addition of a second crude oil storage tank to handle the additional crude oil production from the wells drilled in 2013. In 2022, we added a second 3,000 Bbl wash tank to assist in processing the current production at the facility.

Monterey and Contra Costa Counties, California (Reabold California, LLC)

In May 2022, we acquired Reabold California, LLC (“Reabold”) from a third party. This property includes producing wells in both Monterey and Contra Costa counties of California. Reabold is a wholly owned subsidiary of Daybreak.

Monterey County Properties

The Burnett Lease and the Doud Lease are located in close proximity to each other in the Salinas Valley near Greenfield in Monterey County, California. They are part of a geological feature named the Monroe Swell. The Burnett Lease presently has two directional wells that are being produced from a depth of 2,900’ from the Beedy Sand zone. The crude oil being produced is approximately 17° API gravity. We have future plans of drilling one horizontal well on this lease and to convert an old well bore into a salt water disposal well (“SWD”). We are currently permitting the SWD well. The Doud Lease has four directional well bores that are temporarily shut-in awaiting further evaluation. The produced crude oil is approximately 23° API gravity. We have future plans of drilling one additional directional well on this lease. The SWD well for the Burnett Lease will be utilized for the Doud lease as well.

Contra Costa County Property

The Brentwood Lease is located in the southern portion of the Sacramento Basin in the East Bay region of the San Francisco Bay area near the City of Brentwood in Contra-Costa County, California. This lease is part of a geological feature named the Meganos Unconformity and produces both crude oil and natural gas. As of February 28, 2023, there were two directional wells producing from this lease. A work over was successfully completed on a third well to decrease water production and to increase crude oil production. This third well will be put back on production once the Sunflower Alliance lawsuit with the State of California is settled and a SWD permit has been approved. The wells are producing from the Second Massive Sand from a depth of between 4,000’ 4,500’. The crude oil being produced is approximately 38° gravity.

California Drilling Plans

We plan to drill ~~four~~three development wells and one SWD well in our East Slopes project area in the ~~2022~~2024 – ~~2023~~2025 fiscal year once additional financing is put in place. When new financing is secured, the capital investment required for the ~~four~~three development wells and one SWD well is approximately $~~525~~800,000.

In the Monterey and Contra Costa County project areas we plan to drill two disposal wells, one in each county, which will allow us to return to production the 10 wells that were a part of the Reabold acquisition. We are awaiting the settlement of the Sunflower lawsuit against the State of California and CalGEM before we can receive final regulatory approval to proceed with these projects. We do not anticipate proceeding with these projects in the 2023 – 2024 fiscal year.

Sunflower Lawsuit

Sunflower Alliance v. California Department of Conservation, Geologic Energy Management Division. This case challenges the state agency’s compliance with the California Environmental Quality Act (CEQA) with respect to the PAL Reabold 072-00-0001 Project, for wastewater injection into an existing well. The Petition was filed on December 29, 2021 in the Alameda County Superior Court. The Petitioner seeks an order setting aside the state agency’s approval of a wastewater injection permit; damages are not sought in the lawsuit. On February 22, 2022, Real Party in Interest Reabold California, LLC filed a motion to transfer the case to the Contra Costa County Superior Court. On March 22, 2022, the Alameda County Superior Court ordered the case transferred to the Contra Costa County Superior Court. On August 15, 2022, the Contra Costa County Superior Court provided notice that the transfer has been completed and the case filed in that court. On December 22, 2022, the Superior Court issued an order finding CEQA deficiencies, and directing the state agency to rescind its approval of the project. On September 7, 2023, an appeal of the Superior Court order was filed in the California Court of Appeal, First appellate District, Division 5. The California Attorney General is defending the state agency, which disputes Petitioner’s claims. At this time, it is unclear when the litigation will be resolved. If successful, the lawsuit would prevent Reabold from injecting wastewater into an existing well until any CEQA deficiencies are addressed.

The Company is not aware of any environmental claims existing as of January 23, 2024. 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.

Encumbrances

On October 17, 2018, a working interest partner in ~~California~~the Kern County project filed a UCC financing statement in regards to payables owed to the partner by the Company.

On December 22, 2020, the Company entered into a Secured Promissory Note (the “Westmoreland Note”), as borrower, with James Forrest Westmoreland and Angela Marie Westmoreland, Co-Trustees of the James and Angela Westmoreland Revocable Trust, or its assigns (the “Noteholder”), as the lender. James F. Westmoreland is the Company’s Chairman, President and Chief Executive Officer. Pursuant to the Westmoreland Note, the Noteholder loaned the Company an aggregate principal amount of $155,548. The obligations under the Westmoreland Note are secured by a lien on and security interest in the Company’s oil and gas assets located in Kern County, California, as described in a Deed of Trust entered into by the Company in favor of the Noteholder to secure the obligations under the Westmoreland Note. Such lien shall be a first priority lien, subject only to a pre-existing lien filed by a working interest partner of the Company.

Reserves

Crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”). The following table sets forth our estimated net quantities of proved reserves as of February 28, ~~2022~~2023.

23 As of February 28, 2023, our total crude oil and natural gas reserves were comprised of our working interest in East Slopes Project located in Kern County, California and the Reabold Project located in Monterey and Contra Costa Counties also in California. Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years.

As of February 28, 2022, our total reserves were comprised of our working interest in East Slopes Project located in Kern County, California.

	Proved Reserves
Reserve Category	Crude Oil (Barrels)	Natural Gas (Mcf)	Total Crude Oil Equivalents (BOE)	Percent of Oil Equivalents (BOE)
Developed	384,189	58,330	393,910	100.0	%
Undeveloped	—	—	—	—
Total Proved	384,189	58,330	393,910	100.0	%

	Proved Reserves
Reserve Category	Crude Oil (Barrels)	Natural Gas (Mcf)	Total Crude Oil Equivalents (BOE)	Percent of Oil Equivalents (BOE)
Developed	117,844	—	117,844	22.8	%
Undeveloped	399,311	—	399,311	77.2	%
Total Proved	517,155	—	517,155	100.0	%

Changes in our estimated total net proved reserves (BOE) for the twelve months ended February 28, ~~2022~~2023 are set forth in the table below.

	~~Proved Reserves (BOE)~~	Proved Reserves (BOE)
Balance as of February 28, 2021		434,223
Revisions		3,052
Discoveries and extensions		89,493
Production		(9,613	)
Balance as of February 28, 2022		517,155
Revisions		(393,076	)
Discoveries and extensions		—
Purchase of minerals		287,582
Production		(17,751	)
Balance as of February 28, 2023		393,910

Revisions. Net upward revisions of 36,~~052~~235 BOE of developed reserves in aggregate were due to the higher net crude oil and natural gas prices inwe ~~California~~received during the twelve months ended February 28, ~~2022~~2023 increasing the economic life of our proved reserves, offset by the removal of 399,311 BOE of proved undeveloped reserves that have remained for a period greater than five years as of February 28, 2023.

Discoveries and extensions. For the twelve months ended February 28, ~~2022~~2023, ~~net~~we ~~extensions~~had ofno ~~89,493~~discoveries ~~BOE~~or ~~reserves~~extensions ~~were~~of ~~added in California due to an increase in economic PUD locations~~reserves.

~~Production.~~Purchase ~~Production~~of inminerals. For ~~California~~the twelve ~~was~~months ~~9,613~~ended ~~BOE~~February in28, ~~aggregate~~2023, ofwe ~~proved~~acquired ~~reserves~~through ~~for~~ the ~~twelve~~Reabold ~~months~~subsidiary ~~ended~~acquisition ~~February 28~~287,582 ~~2022~~BOE of developed reserves.

AsProduction. ofProduction ~~February~~was 2817,751 ~~2022,~~BOE in ~~our~~aggregate ~~total~~of ~~proved~~developed ~~undeveloped~~ reserves ~~were~~for ~~comprised~~the oftwelve ~~our~~months ~~interests~~ended inFebruary ~~Kern County~~28, ~~California~~2023.

Changes in our estimated net proved undeveloped reserves (BOE) for the twelve months ended February 28, ~~2022~~2023 are set forth in the table below.

	Proved Undeveloped Reserves (BOE)
	Proved Reserves (BOE)
Balance as of February 28, 2021		339,103
Revisions		(29,285	)
Discoveries and extensions		89,493
Balance as of February 28, 2022		399,311
Revisions		(399,311	)
Balance as of February 28, 2023		—

Revisions. ~~There~~A ~~were~~downward ~~net~~revision ~~downward~~of ~~revisions~~399,311 BOE of 29proved undeveloped reserves occurred for the twelve months ended February 28,~~285~~ ~~BOE~~2023. inUnder ~~aggregate~~the ~~due~~guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to ~~lower~~be ~~estimated~~considered ~~reservoir~~proved ~~production~~undeveloped ofreserves ~~our~~since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years.

~~Discoveries~~Our ~~and~~estimated ~~extensions.~~net ~~For~~proved ~~the~~developed producing reserves ~~twelve~~in ~~months~~California ~~ended~~at February 28, ~~2022,~~2023 ~~there~~are ~~were~~set ~~89,493~~forth ~~BOE~~ in ~~extensions~~the ~~due~~table ~~to an increase in economic PUD locations in California~~below.

Our estimated net proved developed producing reserves in California at February 28, 2022 are set forth in the table below.

	Proved Developed Reserves
		Natural	Total Oil	Percent of Oil
Location	Oil (Barrels)	Gas (Mcf)	Equivalents (BOE)	Equivalents (BOE)
East Slopes Project	116,019	—	116,019	29.5	%
Reabold Project	268,170	58,330	277,891	70.5	%
California Total	384,189	58,330	393,910	100.0	%

	Proved Developed Reserves
		Natural	Total Oil	Percent of Oil
Location	Oil (Barrels)	Gas (Mcf)	Equivalents (BOE)	Equivalents (BOE)
California	117,844	—	117,844	100.0	%

Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years.

24 30

Our estimated ~~net~~ proved ~~undeveloped~~ reserves in(BOE) and PV-10 valuation in California at February 28, ~~2021~~2023 are set forth in the table below.

	Proved Undeveloped Reserves
	Proved Reserves
		Natural	Total Oil		Percent of Oil
			PV-10 as a
Location	Oil (Barrels)	Gas (Mcf)	Equivalents (BOE)		Equivalents (BOE)
	Total Oil	PV-10 of	Percentage of
California	399,311	—	399,311		100.0	%
Location	Equivalents (BOE)	Proved Reserves	Proved Reserves
East Slopes Project	116,019	2,045,924	18.5	%
Reabold Project	277,891	8,990,030	81.5	%
California Total	393,910	11,035,954	100.0	%

The ~~Company~~present ~~has~~value ~~273,265~~of ~~Bbls~~future ofnet ~~proved~~cash ~~undeveloped~~flows from proved reserves, ~~that~~before ~~have~~deductions ~~remained~~for ~~undeveloped~~estimated ~~for~~future aincome ~~period~~taxes ~~greater~~and ~~than~~asset ~~five~~retirement ~~years.~~obligations, ~~These~~discounted ~~proved~~at ~~undeveloped~~10% ~~reserves~~(“PV-10”), was ~~have~~approximately ~~remained~~$11.0 ~~undeveloped due~~million toat ~~depressed~~February ~~crude~~28, ~~oil~~2023 ~~and~~an ~~natural~~increase ~~gas~~of ~~prices~~approximately ~~and~~$4.8 amillion ~~lack~~or 77.4% from the PV-10 reserve valuation of ~~capital~~approximately ~~available~~$6.2 ~~for~~million ~~drilling~~at February 28, 2022. ~~Under~~This ~~our~~increase ~~current~~is ~~drilling~~primarily ~~plans,~~due weto ~~intend~~the acquisition of the Reabold project in California. The commodity prices used to ~~convert~~estimate ~~all~~proved ~~273~~reserves and their related PV-10 at February 28,~~265~~ ~~BOE~~2023 orwere ~~100.0%~~based ofon the ~~proved~~12-month ~~undeveloped~~unweighted arithmetic ~~reserves~~average ~~disclosed~~of asthe first-day-of-the-month price for the twelve month period from March 2022 through February 2023. The WTI benchmark average price for the twelve months ended February 28, 2022 ~~into~~was ~~proved~~$93.55 ~~developed~~per ~~reserves within~~barrel of crude oil in comparison to $71.69 in the ~~next~~prior ~~five~~year reserve ~~years~~report.

~~Our~~These ~~estimated~~benchmark ~~proved~~average ~~reserves~~prices ~~(BOE)~~were further adjusted for crude oil quality and ~~PV-10~~gravity, ~~valuation~~ transportation fees and other price differentials resulting in an average realized price in California for atthe February 28, 2023 reserve report of $90.43 in comparison to $68.80 in the February 28, 2022 ~~are~~reserve ~~set~~report. ~~forth~~Adverse changes in any price differential would reduce our cash flow from operations and the ~~table~~PV-10 ~~below~~of our proved reserves. Operating costs were not escalated.

	Proved Reserves
			PV-10 as a
	Total Oil	PV-10 of	Percentage of
Location	Equivalents (BOE)	Proved Reserves	Proved Reserves
California	517,155	6,191,944	100.0	%

The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10”), was approximately $6.2 million at February 28, 2022 an increase of approximately $4.5 million or 287.5% from the PV-10 reserve valuation at February 28, 2021. This increase is due to the increase in the base price of crude oil in the current report in comparison to the base price of crude oil in the February 28, 2021 report; and an increase in both PDP and PUD reserve totals. . The commodity prices used to estimate proved reserves and their related PV-10 at February 28, 2022 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the twelve month period from March 2021 through February 2022. The WTI benchmark average price for the twelve months ended February 28, 2022 was $71.69 per barrel of crude oil in comparison to $38.64 in the prior year reserve report.

These benchmark average prices were further adjusted for crude oil quality and gravity, transportation fees and other price differentials resulting in an average realized price in California for the February 28, 2022 reserve report of $68.80 in comparison to $36.14 in the February 28, 2021 reserve report. Adverse changes in any price differential would reduce our cash flow from operations and the PV-10 of our proved reserves. Operating costs were not escalated.

PV-10 is not a generally accepted accounting principal (“GAAP”) financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our financial statements. The PV-10 of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a comparable basis.

Reserve Estimation

~~All~~Our ~~of our~~ estimated proved developed reserves of ~~517~~116,~~155 BOE~~019 BOE for the East Slopes project in Kern County for the twelve months ended February 28, ~~2022~~2023 were derived from engineering reports prepared by PGH Petroleum and Environmental Engineers, LLC (“PGH”) of Austin, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.

PGH is an independent petroleum engineering consulting firm registered in the State of Texas, and Frank J. Muser, a Petroleum Engineer, is the technical person at PGH primarily responsible for evaluating the proved reserves covered by their report. Mr. Muser graduated from the University of Texas at Austin with a Bachelor of Science degree in Chemical Engineering. He is a licensed Professional Engineer in the states of Texas, Alabama, Kansas, North Dakota, and West Virginia and has been employed by PGH as a staff engineer since 2012. Mr. Muser has over 20 years of extensive crude oil and natural gas experience working in both private industry and for the State of Texas. The services provided by PGH are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about the evaluations performed by PGH, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K.

25 Our estimated proved developed reserves of 277,891 BOE for the Reabold project in Monterey and Contra Costa Counties for the twelve months ended February 28, 2023 were derived from engineering reports prepared by PETROtech Resources Company (“PETROtech”) of Bakersfield, California in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.

~~Our~~PETROtech ~~internal~~is ~~controls~~an ~~over~~independent ~~the~~petroleum ~~reserve reporting~~engineering ~~process~~consulting ~~are~~firm ~~designed~~registered toin ~~result~~the inState ~~accurate~~of California, and ~~reliable~~Bradford ~~estimates~~DeWitt, ina ~~compliance~~Petroleum ~~with~~Engineer, ~~applicable~~is ~~regulations~~the ~~and~~technical ~~guidance.~~person ~~Internal~~at ~~reserve~~PETROtech ~~preparation~~primarily isresponsible ~~performed~~for byevaluating ~~Bobby~~the ~~Ray~~proved ~~Greer,~~reserves ~~Director~~covered ofby ~~Field~~their ~~Operations~~report. Mr. ~~Greer~~DeWitt ishas a ~~1984~~Bachelor ~~graduate~~ of ~~University~~Arts ofdegree ~~Southern~~from ~~Mississippi in~~the ~~Hattiesburg, Mississippi with a Bachelor~~ University of ~~Science~~California ~~Degree~~– inLos ~~Geology~~Angeles (“U.C.L.A”) and is a ~~certified~~Master ~~Petroleum~~of ~~Geologist~~Science ~~and~~degree ~~a member,~~ in ~~good standing,~~Engineering offrom the ~~American~~University ~~Association~~ of ~~Petroleum~~Southern California ~~Geologists~~(“U.S.C.”). ~~and~~He is a registered ~~professional~~petroleum ~~geologist~~engineer in ~~Mississippi.~~the ~~Mr.~~State ~~Greer~~of ~~has over~~California. 35The ~~years~~services ofprovided ~~experience~~by inPETROtech are ~~petroleum~~not ~~exploration,~~audits ~~reservoir~~of ~~analysis,~~our ~~drilling~~reserves ~~rig~~but ~~construction,~~instead ~~oilfield~~consist ~~operations~~of ~~and~~complete ~~management.~~engineering

Although we believe that the estimates of reserves prepared by Mr. Greer have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage an independent petroleum engineering consultant to prepare an annual evaluation of our estimated proved reserves. We provide to PGH for their analysis all pertinent data needed to properly evaluate our reserves. We consult regularly with PGH during the reserve estimation process to review properties, assumptions, and any new data available. Additionally, the Company’s senior management reviewed and approved all Daybreak reserve report information contained in this Annual Report on Form 10-K.31

~~Under~~evaluations ~~current~~of ~~SEC~~the ~~standards,~~respective ~~proved~~properties. ~~reserves~~For ~~are~~more ~~those~~information ~~quantities~~about ofthe ~~crude~~evaluations ~~oil~~performed ~~and natural gas, which,~~ by ~~analysis of geoscience and engineering data~~PETROtech, ~~can~~refer ~~be estimated with reasonable certainty~~ to bethe ~~economically~~copy producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of ~~confidence~~their ~~that~~report ~~the~~filed ~~quantities of~~as ~~crude~~Exhibit ~~oil and/or natural gas actually recovered will equal or exceed the estimate~~99.2 ~~Reasonable~~to ~~certainty~~this ~~can~~Annual ~~be established using techniques~~Report ~~that~~on ~~have~~Form ~~been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty~~10-K.

~~Reliable~~Our ~~technology~~internal controls over the reserve reporting process are designed to result in accurate and reliable estimates in compliance with applicable regulations and guidance. Internal reserve preparation is performed by Bobby Ray Greer, Director of Field Operations. Mr. Greer is a ~~grouping~~1984 graduate of ~~one~~University orof ~~more~~Southern ~~technologies~~Mississippi in Hattiesburg, ~~(including~~Mississippi ~~computational~~with ~~methods)~~a ~~that~~Bachelor ~~have~~of ~~been~~Science ~~field-tested~~Degree in Geology and ~~have~~is ~~demonstrated~~a tocertified ~~provide~~Petroleum ~~reasonably~~Geologist ~~certain~~and ~~results~~a ~~with~~member, ~~consistency~~in good standing, of the American Association of Petroleum Geologists and ~~repeatability~~is a registered professional geologist in ~~the~~Mississippi. ~~formation~~Mr. ~~being~~Greer ~~evaluated~~has orover 40 years of experience in anpetroleum ~~analogous~~exploration, ~~formation~~reservoir analysis, drilling rig construction, oilfield operations and management.

Although we believe that the estimates of reserves prepared by Mr. Greer have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage an independent petroleum engineering consultant to prepare an annual evaluation of our estimated proved reserves. We provide to PGH and PETROtech, for their analysis, all pertinent data needed to properly evaluate our reserves. We consult regularly with PGH and PETROtech during the reserve estimation process to review properties, assumptions, and any new data available. Additionally, the Company’s senior management reviewed and approved all Daybreak reserve report information contained in this Annual Report on Form 10-K.

Under current SEC standards, proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability. The technical data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Generally, crude oil and natural gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations. Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technical data to assess the reservoir continuity. In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities. Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data. When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of crude oil derived through volumetric calculations.

The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering, and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves and future cash flows are based on various assumptions and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable crude oil reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the crude oil and natural gas industry in general are subject.

Delivery Commitments

As of February 28, ~~2022~~2023, we had no commitments to provide any fixed or determinable quantities of crude oil or natural gas in the near future under contracts or agreements.

Summary Operating Data

The following table sets forth our net share of annual production in each project for the periods shown. One barrel of crude oil equivalent (“BOE”) is roughly equivalent to 6,000 cubic feet or 6 Mcf of gas.

26 As of February 28, 2023, our total reserves were comprised of our working interest in projects located in Kern, Monterey and Contra Costa counties, all located in California. We only have natural gas production from our project in Contra Costa County. Prior to the acquisition of our Reabold subsidiary acquisition in May of 2022, we had no natural gas production.

As of February 28, 2022, our total reserves were comprised of our working interest in East Slopes Project located in Kern County, California.

	For the Twelve Months Ended February 28,
	2023		2022		2021
Crude Oil and Natural Gas Production Data:
Crude oil		17,114		9,613		10,970
Natural gas (BOE)		637		—		—
Total (BOE)		17,751		9,613		10,970

	For the Twelve Months Ended February 28/29,
	2022		2021		2020
Crude Oil and Natural Gas Production Data:
California crude oil		9,613		10,970		11,013
Total (BOE)		9,613		10,970		11,013

The following table sets forth our net share of crude oil and natural gas revenue by project area for the periods shown.

	For the Twelve Months Ended February 28/29,
	For the Twelve Months Ended February 28,
	2022		2021		2020
	2023		2022		2021
Crude Oil and Gas Revenue:
California crude oil		680,107		404,901		663,512
Crude oil – Kern County (East Slopes)	$	728,439	$	680,107	$	404,901
Total	$	680,107	$	404,901	$	663,512
Crude Oil – Monterey and Contra Costa Counties (Reabold)		804,821		—		—
Natural gas – Contra Costa County (Reabold)		80,026		—		—
Total revenue	$	1,613,286	$	680,107	$	404,901

The following table sets forth the average realized sales price from each project area for the periods shown.

	For the Twelve Months Ended February 28/29,
	For the Twelve Months Ended February 28,
	2022		2021		2020
	2023		2022		2021
Average Realized Price:
Crude oil – California (Bbl)	$	70.75	$	36.91	$	60.25
Crude oil (Bbl) – Kern County (East Slopes)	$	90.38	$	70.75	$	36.91
Crude oil (Bbl) – Monterey and Contra Costa Counties (Reabold)	$	88.89	$	—	$	—
Natural gas (Mcf) – Contra Costa County (Reabold)	$	20.94	$	—	$	—
Annual Crude oil and natural gas (BOE) realized sales price	$	90.88	$	70.75	$	36.91

The following table sets forth the average production expense (BOE) for the periods shown.

	For the Twelve Months Ended February 28/29,
	2022		2021		2020
	2023		2022		2021
Average Production Expense (BOE):
California	$	24.06	$	17.12	$	16.43
Kern County	$	42.44	$	24.06	$	17.12
Monterey and Contra Costa Counties	$	85.86	$	—	$	—
Annual Average production expense (BOE)	$	62.97	$	24.06	$	17.12

Gross and Net Acreage

The following table sets forth our interests in developed and undeveloped crude oil lease acreage in California held by us as of February 28, ~~2022~~2023. These ownership interests generally take the form of working interests in crude oil leases that have varying terms. Developed acreage includes leased acreage that is allocated or assignable to producing wells. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, regardless of whether or not the acreage contains proved reserves. Gross acres represents the total number of acres in which we have an interest. Net acres represents the sum of our fractional working interests owned in the gross acres.

	Developed						~~Undeveloped~~	Undeveloped						~~Total~~		Total
	Gross		~~Net~~	Net			~~Gross~~	Gross		~~Net~~		Net		~~Gross~~		Gross	~~Net~~			Net
California		800		292				2,694			1,010				3,494			1,302
California – Kern County		800			292				2,694				1,010				3,494				1,302
Average working interest				36.5	%						44.2	%						42.7	%
California – Monterey and Contra Costa Counties		360			180				4,372				2,186				4,732				2,366
Total		1,160			472				7,066				3,196				8,226				3,668
Average working interest					36.5	%							44.2	%							42.7	%

Undeveloped Acreage Expirations

~~The~~We ~~following~~have ~~table~~no ~~sets forth expiration dates of our~~ gross and net undeveloped ~~acres~~acreage in California expiring ~~for~~over the next three years ~~shown~~as all of our gross and net acreage is currently held by production.

Twelve Months Ended February 28, 2022

Twelve Months Ended February 28, 2023

Twelve Months Ended February 29, 2024

Gross

Net

Gross

Net

Gross

Net

California

—

Average working interest

—

In all cases the drilling of a commercial crude oil or natural gas well will hold acreage beyond the lease expiration date. In the past we have been able to, and expect in the future to be able to extend the lease terms of some of these leases. Based on our evaluation of prospective economics, we have allowed acreage to expire from time to time and we expect to allow additional acreage to expire in the future. In California, we have previously determined that there is no likely benefit to pursuing any drilling opportunities on the majority of the expiring leases, so the expiration of these leases is expected to be immaterial to our operations. Further, none of our proved undeveloped reserves have been assigned to locations that are scheduled to be drilled after the expiration of the current leases. In California, all of our proved undeveloped reserves are assigned to leases that are currently held by production (“HBP”).

Producing Wells

The following table sets forth our gross and net productive crude oil wells in California as of February 28, ~~2022~~2023. Productive wells are producing wells and wells capable of production. Gross wells represent the total number of wells in which we have an interest. Net wells represent the sum of our fractional working interests owned in the gross wells.

Property Location	~~Gross~~	Gross Wells	~~Net~~		Net Wells
California		20		7.3
Kern County (East Slopes)		20			7.3
Average working interest				36.5	%
Monterey and Contra Costa Counties (Reabold)		10			5.0
Total		30			12.3
Weighted average - working interest					41.0	%

Drilling Activity

~~The~~In ~~following table sets forth our exploratory and development well drilling activity in California for~~ the ~~periods~~past ~~shown.~~three Weyears, we have had no drilling activity occur ~~in the past three years~~ due to the volatility of crude oil prices and the lack of available drilling capital.

Twelve Months Ended

February 28, 2022

February 28, 2021

February 29, 2020

Property Location

Productive

Dry

Productive

Dry

Productive

Dry

California

Exploratory

—

Developmental

—

Total

—

ITEM 3. LEGAL PROCEEDINGS

Sunflower Lawsuit

Sunflower Alliance v. California Department of Conservation, Geologic Energy Management Division. This case challenges the state agency’s compliance with the California Environmental Quality Act (CEQA) with respect to the PAL Reabold 072-00-0001 Project, for wastewater injection into an existing well. The Petition was filed on December 29, 2021 in the Alameda County Superior Court. The Petitioner seeks an order setting aside the state agency’s approval of a wastewater injection permit; damages are not sought in the lawsuit. On February 22, 2022, Real Party in Interest Reabold California, LLC filed a motion to transfer the case to the Contra Costa County Superior Court. On March 22, 2022, the Alameda County Superior Court ordered the case transferred to the Contra Costa County Superior Court. On August 15, 2022, the Contra Costa County Superior Court provided notice that the transfer has been completed and the case filed in that court. On December 22, 2022, the Superior Court issued an order finding CEQA deficiencies, and directing the state agency to rescind its approval of the project. On September 7, 2023, an appeal of the Superior Court order was filed in the California Court of Appeal, First Appellate District, Division 5. The California Attorney General is defending the state agency, which disputes Petitioner’s claims. At this time, it is unclear when the litigation will be resolved. If successful, the lawsuit would prevent Reabold from injecting wastewater into an existing well until any CEQA deficiencies are addressed.

Neither the Company, nor any of our officers or directors is a party to any material legal proceeding or litigation, and such persons know of no material legal proceeding or contemplated or threatened litigation. There are no judgments against us or our officers or directors. None of our officers or directors has been convicted of a felony or misdemeanor relating to securities or performance in corporate office.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

2935

PART II

~~Our~~As of February 28, 2023, our Common Stock iswas quoted on the OTC Pink Open Market under the symbol “DBRM”. Prior to May 1, 2016, our stock had traded on the OTCQB Venture Marketplace. Our transition to the OTC Pink Open Market resulted from a cost-savings program for the company and related to listing fees on the Venture Marketplace.

~~The~~In ~~following~~September ~~table~~2023, ~~sets~~information ~~forth~~on our Common Stock became available in the ~~high~~OTC ~~and~~Expert ~~low~~Market. ~~closing~~This move to the Expert Market was triggered by a lack of current financial information being ~~sales~~available ~~prices~~due ~~for~~to ~~our~~delays ~~Common~~in ~~Stock~~the filing of this 10-K filing for the ~~two~~year ~~most~~ended ~~recent~~February ~~twelve~~28, ~~month~~2023 ~~periods~~and ~~shown~~subsequent 10-Q reports. ~~The~~We ~~quotations~~anticipate that ~~reflect~~once ~~inter-dealer~~we ~~prices,~~are ~~without retail~~current ~~mark-up,~~in ~~mark-down~~our orpublic ~~commission~~company ~~and~~filings ~~may~~our ~~not~~Common ~~represent~~Stock ~~actual~~will ~~transactions.~~again ~~The~~be ~~information~~quoted ison ~~derived~~the ~~from~~OTC ~~information~~Pink ~~received~~Open Market, although we ~~from~~can ~~online~~provide ~~stock~~no ~~quotation~~assurances ~~services~~as to the timing or our ultimate success in this regard.

	Twelve Months Ended February 28, 2022				Twelve Months Ended February 28, 2021
	High		Low		High		Low
First Quarter		0.0670		0.0200		0.013		0.006
Second Quarter		0.0379		0.0220		0.012		0.007
Third Quarter		0.0530		0.0230		0.015		0.006
Fourth Quarter		0.0683		0.0225		0.029		0.006

The following table sets forth the high and low closing sales prices for our Common Stock for the two most recent twelve month periods shown. The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions. The information is derived from information received from online stock quotation services.

As of June 14, 2022, the Company had 1,703 shareholders of record of its Common Stock. This number does not include an indeterminate number of shareholders whose shares are held by brokers in street name.

	Twelve Months Ended February 28, 2023				Twelve Months Ended February 28, 2022
	High		Low		High		Low
First Quarter		0.04675		0.033		0.0670		0.0200
Second Quarter		0.0522		0.037		0.0379		0.0220
Third Quarter		0.0522		0.031		0.0530		0.0230
Fourth Quarter		0.0412		0.022		0.0683		0.0225

As of January 23, 2024, the Company had 1,700 shareholders of record of its Common Stock. This number does not include an indeterminate number of shareholders whose shares are held by brokers in street name.

Transfer Agent

~~Effective~~The ~~December 22, 2020, the Company appointed Sedona Equity Registrar & Transfer, Incorporated (“Sedona”) as its~~ transfer agent ~~and~~for ~~shareholder~~our ~~support~~Common ~~provider.~~Stock ~~By December~~is 28ClearTrust, ~~2020, all of the Company's directly held shares of common stock, files and information has been transferred from Computershare~~ ~~to Sedona. In this capacity~~LLC, ~~Sedona~~16540 ~~will~~Pointe ~~manage~~Village ~~all stock registry requests for shareholders~~Dr, ~~including~~Suite ~~change~~210 ~~of address~~Lutz, ~~certificate replacement~~Florida ~~and transfer of shares~~33558. ~~All~~Their ~~stock~~website ~~and~~address ~~investment information will automatically transfer to Sedona from our former Transfer Agent and Registrar, Computershare, and no action~~ is: ~~required on the part of the shareholder~~https://www.cleartrustonline.com.

~~The~~On December 18, 2023, the Board of Directors of Daybreak appointed ClearTrust LLC “ClearTrust”) as its transfer agent ~~for~~and ~~our~~shareholder support provider. By December 31, 2023, all the Company's directly held shares of Common Stock, isfiles and information were transferred from Sedona Equity Registrar & Transfer, ~~143~~Incorporated (“Sedona”) Wto ClearTrust. ~~Helena~~In ~~Drive~~this ~~Phoenix~~capacity, AZClearTrust ~~85023.~~will ~~Their~~now ~~website~~manage all stock registry requests for shareholders, including change of address, certificate replacement and transfer of shares. All stock and investment information has automatically transferred to ClearTrust from our former Transfer Agent and Registrar, Sedona, and no action is: ~~www~~required on the part of the shareholder.~~sedonaequity.com.~~

Dividend Policy

The Company has not declared or paid cash dividends or made any distributions on its ~~common~~Common ~~stock~~Stock since its inception in 1955.

During the twelve months ended February 28, 2022, the Company paid the shareholders of its Series A Convertible Preferred stock all accrued and accumulated dividends that were associated with the Series A Convertible Preferred stock with ~~common~~Common ~~stock~~Stock. For more information on this issuance please refer to Note 12 13 of the financial statements that are included in this 10-K filing. The Company does not anticipate that it will pay cash dividends or or make any cash distributions on its ~~common~~Common ~~stock~~Stock in the foreseeable future.

Preferred Stock

~~The~~With ~~Company~~the isfiling ~~authorized~~of tothe ~~issue~~Company’s upSecond ~~to 10,000,000~~Amended ~~shares~~and ofRestated ~~Preferred~~Articles ~~Stock with a par value~~ of ~~$0.001.~~Incorporation ~~Our Preferred Stock may be entitled to preference over the Common Stock~~ with ~~respect to~~ the ~~distribution~~Washington ofSecretary ~~assets~~ of ~~the~~State ~~Company~~ in ~~the~~May ~~event of liquidation~~2022, ~~dissolution, or winding-up of~~ the Company, ~~whether~~no ~~voluntarily or~~longer ~~involuntarily,~~has ~~or in the event of~~ any ~~other~~preferred ~~distribution of assets of the Company among its shareholders for the purpose of winding-up its affairs~~stock. The ~~authorized~~Company ~~but~~has ~~unissued~~only ~~shares of Preferred Stock may be divided into and issued in designated series from time to time by~~ one orclass ~~more resolutions adopted by the Board~~ of ~~Directors. The directors in their sole discretion shall have the power to determine the relative powers~~stock, ~~preferences,~~which ~~and~~is ~~rights~~Common ~~of each series of Preferred~~ Stock.

With the filing of our Second Amended and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, the Company no longer has any preferred stock shares. We only have one class of stock and that is common stock.

Series A Convertible Preferred Stock

~~The~~At ~~Company~~February ~~designated~~28, 22022,~~400,000~~ ~~shares~~there ofwere ~~the~~no ~~10,000,000 preferred~~issued or outstanding shares asof Series A ~~Convertible~~ Preferred ~~Stock~~stock ~~(“Series~~that Ahad ~~Preferred”),~~not ~~with~~been aconverted ~~$0.001~~into ~~par~~our ~~value~~Common Stock. InWith ~~July~~the ~~2006,~~filing ~~we completed~~of athe ~~private~~Company’s ~~placement~~Second Amended and Restated Articles of ~~the~~Incorporation ~~Series~~with Athe ~~Preferred~~Washington ~~that~~Secretary ~~resulted~~of State in May 2022, the ~~issuance~~Company ofno ~~1,399,765~~longer ~~Series~~has Aany ~~Preferred~~preferred ~~shares~~stock. The toCompany ~~100~~has ~~accredited investors~~only one class of stock, which is Common Stock.

During the twelve months ended February 28, 2022, the Company proposed to all 56 remaining Series A shareholders, who had not previously converted to the Company’s common stock, the conversion of their Series A shares into three shares of the Company’s common stock. Included with this proposal, the Company offered to pay any accrued Series A dividend, on a pro rata basis, with 1,100,000 shares of common stock. In order for the conversion to occur and the dividend to be paid, a majority of the Series A shares had to vote to accept the conversion proposal. With a majority of 53.6%, the outstanding shares voted in favor of the mandatory conversion and dividend issuance. There were 46.4% of the outstanding shares who chose to vote no; not to vote or had their notices of the conversion vote returned to the Company as an invalid address. As a result of the affirmative vote, 709,568 shares of Series A Preferred stock was converted to 2,128,704 shares of common stock and 1,100,000 shares of common stock were issued to satisfy the accumulated dividend of $2,449,979. At February 28, 2022, there were no outstanding shares of Series A Preferred stock remaining.

The following is a summary of the rights and preferences of the Series A Preferred.

Conversion:

At February 28, 2022, there were no shares ~~issued~~of Series ~~and~~A ~~outstanding~~Preferred stock that had not been converted into our Common Stock. AsThe conversions of ~~February~~Series ~~28,~~A ~~2021,~~Preferred ~~there~~that ~~were~~have 44occurred ~~accredited~~since ~~investors who had~~the ~~converted 690,197~~ Series A Preferred ~~shares~~was ~~into~~first ~~2,070,591~~issued ~~shares~~in ofJuly ~~Daybreak~~2006 ~~Common~~are ~~Stock~~set forth in the table below.

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	Shares of Series A Preferred Converted to Common Stock		Shares of Common Stock Issued from Conversion		Number of Accredited Investors
Year Ended February 29, 2008		102,300		306,900		10
Year Ended February 28, 2009		237,000		711,000		12
Year Ended February 28, 2010		51,900		155,700		4
Year Ended February 28, 2011		102,000		306,000		4
Year Ended February 29, 2012		—		—		—
Year Ended February 28, 2013		18,000		54,000		2
Year Ended February 28, 2014		151,000		453,000		9
Year Ended February 28, 2015		3,000		9,000		1
Year Ended February 29, 2016		10,000		30,000		1
Year Ended February 28, 2017		—		—		—
Year Ended February 28, 2018		14,997		44,991		1
Year Ended February 28, 2019		—		—		—
Year Ended February 29, 2020		—		—		—
Year Ended February 28, 2021		—		—		—
Year Ended February 28, 2022		709,568		2,128,704		56
Totals		1,399,765		4,199,295		100

Dividends:

~~Holders~~During ofthe ~~Series~~twelve Amonths ~~Preferred~~ended ~~shall~~February be28, ~~paid dividends~~2022, inall ~~the~~accumulated ~~amount~~dividends of 6%$2,449,979 ofwere ~~the~~paid ~~original~~through ~~purchase~~the ~~price~~issuance ~~per~~of ~~annum.~~1,100,000 ~~Dividends~~shares ~~may~~of beCommon ~~paid~~Stock. inAt ~~cash~~a orspecial ~~Common~~meeting ~~Stock~~of atshareholders on ~~the~~May ~~discretion~~20, of2022 the Company~~. Dividends~~’s ~~are~~shareholders ~~cumulative~~approved ~~from~~ the ~~date~~Second ofAmended ~~the~~and ~~final~~Restated ~~closing~~Articles of ~~the private placement~~Incorporation, ~~whether~~which ~~or not in any dividend period or periods~~eliminated wethe ~~have~~classification ~~assets~~of ~~legally available for~~ the ~~payment~~Series ofA ~~such~~Preferred ~~dividends~~stock. ~~Accumulations~~Cumulative of dividends earned on ~~shares~~our of Series A Preferred dostock ~~not bear~~for ~~interest.~~each ~~Dividends are payable upon declaration by the Board of Directors. During the~~ twelve ~~months ended February 28, 2022, all~~month ~~accumulated~~period ~~dividends~~since ofissuance ~~$2,449,979~~are ~~were~~set ~~paid~~forth ~~through~~in the ~~issuance~~table ~~of 1,100,000 shares of common stock~~below.

Cumulative dividends earned for each twelve month period since issuance are set forth in the table below:

Fiscal Year Ended	Shareholders at Period End		Accumulated Dividends
February 28, 2007		100	$	155,311
February 29, 2008		90		242,126
February 28, 2009		78		209,973
February 28, 2010		74		189,973
February 28, 2011		70		173,707
February 29, 2012		70		163,624
February 28, 2013		68		161,906
February 28, 2014		59		151,323
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
February 29, 2020		56		128,063
February 28, 2021		56		127,714
February 28, 2022		—		96,340
			$	2,449,979

At a special meeting of shareholders on May 20, 2022 the Company’s shareholders approved the Second Amended and Restated Articles of Incorporation, which eliminates the classification of the Series A Preferred.

Common Stock

The Company is authorized to issue up to ~~200~~500,000,000 shares of $0.001 par value Common Stock of which 67384,~~802~~734,~~273~~902 and 6067,~~491~~802,~~122~~273 shares were issued and outstanding as of February 28, ~~2022~~2023, and February 28, ~~2021~~2022, respectively.

	Common Stock Balance			~~Par Value~~	Par Value
Common stock, Issued and Outstanding, February 28, 2019		51,532,364
Common Stock, Issued and Outstanding, February 28, 2021		60,491,122
Share issuances during the twelve months ended February 29, 2020		2,000,000		$	2,000
Shares issued for Series A Preferred conversion		2,128,704			$	2,129
Common stock, Issued and Outstanding, February 29, 2020		53,532,364
Shares issued for Series A accumulated dividend		1,100,000			$	1,100
Share issuances during the twelve months ended February 28, 2021		6,958,758		$	6,959
Shares issued for debt conversion of accrued salaries		1,397,880			$	1,398
Common stock, Issued and Outstanding, February 28, 2021		60,491,122
Shares issued for debt conversion of accrued directors fees		317,708			$	318
Shares issued for Series A Preferred conversion		2,128,704		$	2,129
Shares issued for conversion of 12% Note principal and interest – related party		1,144,415			$	1,144
Shares issued for Series A accumulated dividend		1,100,000		$	1,100
Shares issued for investment principal in production revenue program		1,222,444			$	1,222
Shares issued for debt conversion of accrued salaries		1,397,880		$	1,398
Common Stock, Issued and Outstanding, February 28, 2022		67,802,273
Shares issued for debt conversion of accrued directors fees		317,708		$	318
Shares issued for conversion of 12% Note principal and interest		78,934			$	79
Shares issued for conversion of 12% Note principal and interest – related party		1,144,415		$	1,144
Shares issued for conversion of convertible note		27,764,706			$	27,765
Shares issued for investment principal in production revenue program		1,222,444		$	1,222
Shares issued for acquisition of crude oil and natural gas properties		160,964,489			$	160,964
Common stock, Issued and Outstanding, February 28, 2022		67,802,273
Shares issued for sale of stock		125,000,000			$	125,000
Shares issued for financing fees		3,125,000			$	3,125
Share adjustment due to recording error		(500	)		$	1
Common Stock, Issued and Outstanding, February 28, 2023		384,734,902

During the twelve months ended February 28, ~~2022~~2023, there were 316,933,129 shares of Common Stock issued. Common Stock shares issued for the Reabold subsidiary acquisition were 160,964,489. Share issuances in connection with fundraising were 155,889,706. Another 78,934 shares were issued through the conversion of a 12% Note and interest to our Common Stock. During the twelve months ended February 28, 2022, there were 7,311,151 shares of ~~common~~Common ~~stock~~Stock issued as a part of the Company’s restructuring of its balance sheet in accordance with the conditions of the Equity Exchange Agreement between Reabold California, LLC, Gaelic Resources Ltd, and the Company. Of the total 7,311,151 shares issues, there were 4,082,447 shares issued to satisfy related party debt. Another 3,228,704 shares were issued to satisfy the Series A Preferred stock conversion and associated accumulated dividend of $2,449,979. ~~During~~In ~~the~~December ~~twelve~~2023, ~~months~~we ~~ended~~were ~~February~~notified ~~28,~~of ~~2021,~~a ~~there~~system ~~were~~error ~~6,958,758~~that had occurred in the recording of street stock shares held by the nominee. Accordingly, the number of ~~common~~our ~~stock~~issued and outstanding shares ~~valued~~was atreduced ~~$27~~by 500 shares as of February 28,~~835~~ ~~issued~~2023. toThe acommon ~~related~~stock ~~party~~par tovalue ~~settle~~of athis ~~convertible~~adjustment ~~note~~was ~~payable~~$0.50.

32 38

All shares of Common Stock are equal to each other with respect to voting, liquidation, dividend and other rights. Owners of shares of Common Stock are entitled to one vote for each share of Common Stock owned at any shareholders’ meeting. Holders of shares of Common Stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefore; and upon liquidation, are entitled to participate pro rata in a distribution of assets available for such a distribution to shareholders.

There are no conversion, preemptive, or other subscription rights or privileges with respect to any shares of our Common Stock. Our stock does not have cumulative voting rights, which means that the holders of more than 50% of the voting power of the shares voting in an election of directors, acting together (as applicable), may elect all of the directors if they choose to do so. In such event, the holders of the remaining shares aggregating less than fifty percent (50%) would not be able to elect any directors. Each common shareholder has the right to vote in person or by proxy one vote for every share of stock standing in his or her name on the books of the Company on the record date.

Warrants

During the twelve months ended February 29, 2020 there were 2.1 million warrants issued to a third party for investor relations services. The fair value of the warrants, ~~was~~as determined by the Black-Scholes pricing model, was $17,689, and is being amortized over the three -year vesting period of the warrants. The Black-Scholes valuation encompassed the following assumptions: a risk-free interest rate of 1.68%; volatility rate of 260.23%; and a dividend yield of 0.0%.

The warrant contains a vesting blocking provision that prevents the vesting of any warrants that such vesting would cause the warrant holder’s beneficial ownership (as such term is defined in Section 13d-3 of the Securities Exchange Act of 1934, as amended) to exceed more than four and ninety-nine one-hundredths percent (4.99%) of the Company’s outstanding Common Stock. The foregoing restriction may not be waived by either party. The warrants vest in equal parts over a three -year period beginning on January 2, 2020 and all warrants ~~expire~~expired on January 2, 2024.

As of February 28, ~~2022~~2023, and February 28, ~~2021~~2022, there were ~~893~~2,~~333~~100,000 and ~~528~~893,~~507~~333 exercisable warrants. At February 28, ~~2022~~2023, both the outstanding warrants and the exercisable warrants had a weighted average exercise price of $0.01; a weighted average remaining life of 10.8483 years, and an intrinsic value of $2025,~~265~~200. The recorded amount of warrant expense for the twelve months ended February 28, ~~2021~~2023, and February 28, ~~2021~~ 2022 was $~~4,913~~-0- and $54,~~897~~913, respectively. The warrant expense was fully amortized at February 28, 2022.

Warrant activity for the twelve months ended February 28, ~~2022~~2023, and February 28, ~~2021~~2022 is set forth in the table below:

	Warrants		Weighted Average Exercise Price
Warrants outstanding, February 29, 2020		2,100,000	$	0.01
Warrants outstanding, February 28, 2021		2,100,000	$	0.01
Changes during the twelve months ended February 28,2021:
Changes during the twelve months ended February 28, 2022:
Issued		—
Expired / Cancelled / Forfeited		—
Warrants outstanding, February 28. 2021		2,100,000	$	0.01
Warrants outstanding, February 28, 2022		2,100,000	$	0.01
Warrants exercisable, February 28, 2021		528,507
Warrants exercisable, February 28, 2022		893,333
Changes during the twelve months ended February 28, 2022:
Changes during the twelve months ended February 28, 2023:
Issued		—	$
Expired / Cancelled / Forfeited		—
Warrants outstanding, February 28, 2022		2,100,000	$	0.01
Warrants outstanding, February 28, 2023		2,100,000	$	0.01
Warrants exercisable, February 28, 2022		893,333	$	0.01
Warrants exercisable, February 28, 2023		2,100,000	$	0.01

3339

~~ITEM~~Recent 6.Sales ~~RESERVED~~of Unregistered Securities; Use of Proceeds from Registered Securities

34On December 15, 2021, Daybreak finalized agreements with its directors, executive officers, and other employees with respect to the forgiveness and conversion of related party debts into shares of the Company’s Common Stock (the “Related Party Debt Conversion”) at a conversion rate of $0.45 per share of Common Stock. Completing this Related Party Debt Conversion was a condition to closing the Equity Exchange Agreement dated as of October 20, 2021 entered into by and among the Company, Reabold California LLC, a California limited liability company (“Reabold”), and Gaelic Resources Ltd., a private company incorporated in the Isle of Man and the 100% owner of Reabold (“Gaelic”), pursuant to which Daybreak would acquire Reabold in exchange for issuing 160,964,489 shares of its Common Stock to Gaelic (the foregoing transaction, the “Equity Exchange”).

The following is a description of the debts converted, amounts of debt, and shares of Common Stock agreed to be issued in exchange:

Description of Debt Converted	Dollar Amount Converted		Shares of Common Stock Issued
Accrued deferred salary amounts owed to employees	$	629,046.00		1,397,880
Accrued deferred director fees	$	142,968.75		317,708
12% Subordinated Note Payable, related party	$	514,986.35		1,144,415
Interest in Production Payment program, related party	$	550,100.00		1,222,444
Total	$	1,837,101.10		4,082,447

The shares of Common Stock issued pursuant to the Related Party Debt Conversion were issued in reliance upon exemptions from registration requirements pursuant to Section 4(a)(2) under the Securities Act of 1933, as amended, and Regulation D promulgated thereunder, and pursuant to applicable state securities laws and regulations, in that the sale and purchase of such securities will not involve any public offering, the recipients of the shares are each either an “accredited investor” as that term is defined under Rule 501 of Regulation D, or the Company has furnished or will, a reasonable prior to sale furnish, to each investor the information specified by paragraph (b)(2) of Rule 501 of Regulation D. All Related Party Debt Conversion shares were issued on February 22, 2022.

On January 25, 2022, Daybreak obtained the approval of a majority of the outstanding shares of the Company’s Series A Preferred shares to convert each Series A Preferred share to three (3) shares of Daybreak’s Common Stock, par value $0.001. The accrued and unpaid dividends of $2,449,979 with respect to the Series A Preferred Stock (the “Series A Conversion”) were converted into 1,100,000 shares of Common Stock. The Series A Conversion was undertaken in connection with the Equity Exchange Agreement (the “Exchange Agreement”) dated as of October 20, 2021 by and between Daybreak, Reabold, and Gaelic, pursuant to which the parties propose for (i) Gaelic to irrevocably assign and transfer all of its ownership interests in Reabold to Daybreak, and (ii) Daybreak to issue approximately 160,964,489 shares of its Common Stock to Gaelic (the “Daybreak Shares”), which, resulted in Reabold becoming a wholly-owned subsidiary of Daybreak and Gaelic becoming the owner of Daybreak Shares (the foregoing transaction, the “Equity Exchange”).

The Series A Conversion was voted on by holders of the Series A Preferred shares as of November 30, 2021, to be effective as of that date. Pursuant to the Series A Conversion, a total of 709,568 Series A Preferred shares of the Company plus accrued and unpaid dividends converted into a total of 3,228,704 shares of Daybreak Common Stock. The shares of Common Stock issued pursuant to the Series A Conversion were issued in reliance upon exemptions pursuant to Section 3(a)(9) under the Securities Act of 1933, as amended, and pursuant to applicable state securities laws and regulations, in that the shares of common were issued by the Company to its existing security holders in exchange for Series A preferred stock, and no commission or other remuneration was paid or given directly or indirectly for soliciting such exchange. All Series A Conversion shares and related dividend conversion shares were issued on February 21, 2022.

On March 22, 2022, a 12% Subordinated Note holder that was not a related party converted a $25,000 Note plus accrued interest of $10,520 to Daybreak Common Stock shares. A total of 78,934 shares were issued at a conversion rate of $0.45 per share of Common Stock. The shares of Common Stock were issued in reliance upon exemptions from registration requirements pursuant to Section 4(a)(2) under the Securities Act of 1933, as amended, and Regulation D promulgated thereunder, and pursuant to applicable state securities laws and regulations, in that the sale and purchase of such securities will not involve any public offering. The recipient of the shares is an “accredited investor” as that term is defined under Rule 501 of Regulation D.

On May 25, 2022, the Company finalized the above-mentioned acquisition of Reabold through the Equity Exchange, and there were 160,964,489 shares of the Company’s common stock valued at $6,599,544 issued for the Reabold crude oil and natural gas properties.

On May 26, 2022, Daybreak completed the sale of 125,000,000 shares of its Common Stock, par value $0.001, to Portillion for a purchase price of $0.02 per share, or $2,500,000 in the aggregate, pursuant to the Subscription Agreement dated May 5, 2022 (the “Capital Raise”). In connection with the closing of the Capital Raise, Daybreak also paid Portillion (1) an incentive fee equal to 20% of the subscription amount, payable 17.5% in cash ($437,000) and 2.5% in additional shares of Common Stock (3,125,000 shares); and (2) an equity exchange fee equal to 3% of the subscription amount. The Common Stock was issued pursuant to the exemption from registration promulgated under Regulation S of the Securities Act of 1933, as amended.

The sale and purchase of the shares did not involve any public offering, the offer and sale of the shares took place outside the United States, Daybreak reasonably believes the purchaser to be an “accredited investor” as that term is defined under Rule 501 of Regulation D, the purchaser had access to information about Daybreak and its investment, the purchaser took the securities for investment and not resale, and Daybreak took appropriate measures to restrict the transfer of the securities. The source of funds of Portillion’s purchase of shares of the Company was CitiBank. Daybreak is not aware of any arrangements, including any pledge by any person of securities of the Company or any of its parents, the operation of which may at a subsequent date result in another change in control of the Company.

On May 5, 2022, Kamran Sattar, the purchaser of a convertible promissory note in the amount of $200,000 (the “Convertible Note”) issued by the Company as of February 15, 2022 notified the Company that he had elected to convert the Convertible Note. The Convertible Note converted by its terms at a price per share of $0.0085, and the total principal balance of the note plus accrued interest, totaling $236,000, converted into 27,764,706 shares of Common Stock, par value, $0.001, of the Company. Mr. Sattar has sole voting power and sole dispositive power over these shares.

ITEM 6. [RESERVED]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following management’s discussion and analysis (“MD&A”) is management’s assessment of the financial condition, changes in our financial condition and our results of operations and cash flows for the twelve months ended February 28, ~~2022~~2023 and February 28, ~~2021~~2022. This MD&A should be read in conjunction with the audited financial statements and the related notes and other information included elsewhere in this Annual Report on Form 10-K.

Safe Harbor Provision

Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations 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 facts contained in this MD&A report, including statements regarding our current expectations and projections about future results, intentions, plans and beliefs, business strategy, performance, prospects and opportunities, are inherently uncertain and are forward-looking statements. For more information about forward-looking statements, please refer to the section labeled “Cautionary Statement About Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.

Introduction and Overview

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

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

Our operations are focused on identifying and evaluating prospective crude oil and natural gas properties and funding projects that we believe have the potential to produce crude oil or natural gas in commercial quantities. We conduct all of our drilling, exploration and production activities in the United States, and all of our revenues are derived from sales to customers within the United States. We are currently in the process of developing atwo multi-well oilfield projects; one in Kern County, California and anthe ~~exploratory~~other ~~project~~in Monterey and Contra Costa Counties in ~~Michigan~~California.

Our management cannot provide any assurances that Daybreak will ever operate profitably. While, in the past, we have ~~experienced~~had positive cash flow ~~in the past~~ from our crude oil operations in the East Slopes project 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 more fully described in Item 1A. Risk Factors of this Annual Report on Form 10-K for the fiscal year ended February 28, ~~2022~~2023.

Throughout this Annual Report on Form 10-K, crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).

Year-to-Date Results

Below is brief summary of our two crude oil and natural gas ~~project~~projects in California. Refer to our discussion in Item 2. Properties, in this Annual Report on Form 10-K for more information on ~~our~~ our East Slopes Project in Kern County, California and our Reabold subsidiary project in Monterey and Contra Costa Counties, also in California.

~~Kern County, California (East Slopes Project)~~43

~~The~~Kern ~~East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield~~County, California. ~~Drilling~~(East ~~targets~~Slopes ~~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~~. The crude oil produced from our acreage in the Vedder Sand is considered heavy crude oil. The~~)

35 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 of the East Slopes Project since March 2009.

The crude oil produced from our acreage in the Vedder Sand is considered heavy crude oil. The produced crude oil ranges from 14° to 16° API (American Petroleum Institute) gravity and must be heated to separate and remove water prior to sale. During the twelve months ended February 28, ~~2022~~2023 we had production from 20 vertical or horizontal crude oil wells. Our average working interest and NRI in these 20 wells is 36.6% and 2827.46%, respectively. ~~We have been the Operator at the East Slopes Project since March 2009.~~

~~Results~~Monterey ofand ~~Operations~~Contra –Costa ~~For the years ended February 28~~Counties, ~~2022~~California ~~and~~(Reabold ~~February 28, 2021~~project)

Monterey County Properties

The Burnett Lease and the Doud Lease are located in close proximity to each other in the Salinas Valley near Greenfield in Monterey County, California. They are part of a geological feature named the Monroe Swell. The Burnett Lease presently has two directional wells that are being produced from a depth of 2,900’ from the Beedy Sand zone. The crude oil produced is approximately 17° API gravity. We have future plans of drilling one horizontal well on this lease and to convert an old well bore (Burnett #1) into a salt water disposal well (“SWD”). We are currently permitting the SWD well. The Doud Lease has four directional well bores that are temporarily shut-in awaiting further evaluation. The crude oil produced is approximately 23° API gravity. We have a working interest of 50% and a net revenue interest of 40% in both of these leases.

The Brentwood Lease is located in the southern portion of the Sacramento Basin in the East Bay region of the San Francisco Bay area near the City of Brentwood in Contra-Costa County, California. This lease is part of a geological feature named the Meganos Unconformity and produces both crude oil and natural gas. As of February 28, 2023 there were two directional wells producing from this lease. A work over was successfully completed on a third well to decrease water production and to increase crude oil production. This third well will be put back on production once the Sunflower Alliance lawsuit with the State of California is settled and a SWD permit has been approved. The wells are producing from the Second Massive Sand from a depth of between 4,000’ 4,500’. The crude oil being produced is approximately 38° gravity. We have a working interest of 50% and a net revenue interest of 40% in this lease. We only have natural gas production from our project in Contra Costa County. Prior to the acquisition of our Reabold subsidiary in May of 2022, we had no natural gas production.

Results of Operations – For the years ended February 28, 2023, and February 28, 2022

California Crude Oil Prices

The ~~price~~prices we receive for crude oil sales in California isfrom the East Slopes project and from our Reabold subsidiary project are based on prices posted for Midway-Sunset ~~crude~~and Buena Vista crude oil delivery contracts, ~~contracts,~~respectively. ~~less~~All ~~deductions~~posted pricing is subject to adjustments that vary by grade of crude oil, ~~sold~~transportation costs, market differentials and ~~transportation~~other ~~costs~~local conditions. ~~The~~Both the posted Midway-Sunset ~~price~~and Buena Vista prices generally ~~moves~~move in correlation to~~, and at a discount to,~~ prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas ~~Intermediate~~intermediate (“WTI”) crude oil, Cushing, Oklahoma delivery contracts. ~~We do not have any natural gas revenues in California.~~

~~There~~A ~~continues~~comparison ~~to be a significant amount~~ of ~~volatility in hydrocarbon prices and a corresponding fluctuation in our realized sale price of crude oil does exist. An example of this volatility is that in June of 2014~~ the ~~monthly~~ average ~~price of~~ WTI ~~oil~~price ~~was $105.79 per barrel~~ and ~~our~~ average realized ~~price per barrel of~~ crude oil ~~was $98.78~~sales ~~while in April 2020, the monthly average~~ price offrom ~~WTI crude oil was $16.55 and~~ our ~~monthly~~two ~~realized~~projects ~~price was $16.96 per barrel. Finally,~~ in ~~February~~California ~~2022,~~for the ~~monthly~~twelve ~~average~~months ~~price~~ended ofFebruary ~~WTI~~28, ~~oil~~2023, ~~was $91.64 per barrel~~ and ~~our realized price per barrel of crude oil was $87.41. This volatility in crude oil prices has continued throughout most of the fiscal year ended~~ February 28, 2022. is ~~Any~~shown ~~downward volatility~~ in the ~~price~~table of crude oil will have a prolonged and substantial negative impact on our profitability and cash flow from our producing California properties. It is beyond our ability to accurately predict crude oil prices over any substantial length of time. below:

A comparison of the average WTI price and average realized crude oil sales price at our East Slopes Project in California for the twelve months ended February 28, 2022 and February 28, 2021 is shown in the table below:

	Twelve Months Ended
	February 28, 2023		February 28, 2022		Percentage Change
Average twelve-month WTI crude oil price	$	93.13	$	73.31		27.0%
Average twelve month realized crude oil sales price (Bbl)	$	89.59	$	70.75		26.6%

	Twelve Months Ended
	February 28, 2022		February 28, 2021		Percentage Change
Average twelve month WTI crude oil price	$	73.31	$	39.48		85.7	%
Average twelve month realized crude oil sales price (Bbl)	$	70.75	$	36.91		91.7	%

For the twelve months ended February 28, ~~2022~~2023, the average WTI price was $7393.3113 and our average realized crude oil sale price was $7089.7559, representing a discount of $23.5654 per barrel or 3.58% lower than the average WTI price. In comparison, for the twelve months ended February 28, ~~2021~~2022, the average WTI price was $3973.4831 and our average realized sale price was $3670.9175 representing a discount of $2.5756 per barrel or 63.5% lower than the average WTI price. Historically, the sale price we receive for ~~California~~our East Slopes heavy crude oil has been less than the quoted NYMEX WTI price because of the lower API gravity of our ~~California~~East Slopes crude oil in comparison to quoted WTI crude oil API gravity.

California Crude Oil Revenue and Production

Crude oil revenue in California for the twelve months ended February 28, ~~2022~~2023 increased $~~275~~853,~~206~~153 or 68125.04% to $~~680~~1,~~107~~533,260 in comparison to revenue of $~~404~~680,~~901~~107 for the twelve months ended February 28, ~~2021~~2022. The average sale price of a barrel of crude oil for the twelve months ended February 28, ~~2022~~2023 was $7089.7559 in comparison to $3670.9175 for the twelve months ended February 28, ~~2021~~2022. The increase ~~of $33.84 or 91.7% per barrel~~ in the average realized sales price of a$18.84 ~~barrel~~or ~~of crude~~26.6% ~~oil~~per ~~accounted~~barrel accounted for ~~134~~21.92% of the increase in crude oil revenue for the twelve months ended February 28, ~~2022~~2023.

Our net sales volume of crude oil for the twelve months ended February 28, ~~2022~~2023 was 917,~~613~~114 barrels of crude oil in comparison to 109,~~970~~613 barrels sold for the twelve months ended February 28, ~~2021~~2022. The ~~This~~increase ~~decrease~~ in crude oil sales volume of 17,~~357~~501 barrels or 1278.40% was primarily due to ~~fewer~~the ~~well~~acquisition ~~days~~of our Reabold subsidiary in May of ~~production~~2022 and ~~the~~this ~~natural~~overall ~~decline~~increase in ~~reservoir pressure~~crude ~~during~~oil sales volume accounted for 78.8% of the increase in crude oil revenue for the twelve months ended February 28, ~~2021~~2023.

36 Our crude oil sales revenue for the twelve months ended February 28, 2023 and 2022 is set forth in the table below:

Our crude oil sales revenue from California is set forth in the table below:

	Twelve Months Ended February 28, 2023					Twelve Months Ended February 28, 2022
Project	Revenue		Percentage			Revenue		Percentage
East Slopes project – crude oil sales	$	728,439		47.5	%	$	680,107		100.0	%
Reabold project – crude oil sales		804,821		52.5	%		—		—
Crude oil Totals	$	1,533,260		100.0	%	$	680,107		100.0	%

	Twelve Months Ended February 28, 2022					Twelve Months Ended February 28, 2021
Project	Revenue		Percentage			Revenue		Percentage
Total crude oil revenues*	$	680,107		100.0	%	$	404,901		100.0	%

*Our crude oil average realized sale price for the twelve months ended February 28, 2023 was $89.59 in comparison to $70.75 for the twelve months ended February 28, 2022, representing an increase of $18.84 or 26.6% per barrel.

*OurOf ~~average realized~~the ~~sale~~$853,153 ~~price~~or on125.4% aincrease ~~BOE~~in ~~basis~~crude oil revenue for ~~the~~ twelve months ended February 28, ~~2021~~2023 ~~was~~approximately $~~70.75~~672,040 inor ~~comparison to $36~~78.918% ~~for~~can ~~the~~be ~~twelve~~attributed ~~months ended~~to ~~February~~the ~~28,~~increase ~~2021,~~in ~~representing~~sales anvolume ~~increase~~mainly ofdue to ~~$33.84~~our orReabold ~~91.7%~~subsidiary ~~per barrel~~acquisition.

OfCalifornia ~~the~~Natural ~~$275,206~~Gas ~~or 68.0% increase in revenue for twelve months ended February 28, 2022 approximately $371,212 or 134.9% can be attributed to the increase in the realized price of crude oil.~~Prices

The price we receive for natural gas sales from our Reabold subsidiary in California is based on ninety-five percent (95%) of the price published in Natural Gas Intelligence (“NGI”) Gas Price Index under the column “Bidweek Averages” for “California”, “PG&E Citygate” less an amount per MMBtu equal to the Silverado Path On System As-Available transport date, less the Silverado Path On System transmission shrinkage rate for Silverado. The price we receive generally moves in correlation to prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot Henry Hub natural gas prices. We only have natural gas production from our Reabold subsidiary wells that are located in Contra Costa County in California.

	Twelve Months Ended
	February 28, 2023		February 28, 2022		Percentage Change
Average twelve month Henry Hub natural gas price (Mcf)	$	6.35	$	—		100	%
Average twelve month realized natural gas sales price (Mcf)	$	20.94	$	—		100	%

California Natural Gas Revenue and Production

We only have natural gas production from our Reabold subsidiary wells that are located in Contra Costa County in California. For the twelve months ended February 28, 2023, natural gas revenue was $80,026 representing a 100% in natural gas revenue. The average sales price per Mcf of our natural gas production was $20.94 and our natural gas sales volume was 3,822 Mcf for the twelve months ended February 28, 2023. Prior to the acquisition of our Reabold subsidiary in May 2022, we did not have any natural gas production.

California Natural Gas BOE Net Sales Volume

Total California Crude Oil and Natural Gas Revenue and Production

Crude oil and natural gas sales revenue for the twelve months ended February 28, 2023 and 2022 is set forth in the table below:

	Twelve Months Ended February 28, 2023					Twelve Months Ended February 28, 2022
Project	Revenue		Percentage			Revenue		Percentage
East Slopes project – crude oil sales	$	728,439		45.1	%	$	680,107		100.0	%
Reabold project – crude oil sales		804,821		49.9	%		—		—
Reabold project – natural gas sales		80,026		5.0	%		—		—
Total California crude oil and natural gas sales revenue	$	1,613,286		100.0	%	$	680,107		100.0	%

*Our average realized sale price on a BOE basis for the twelve months ended February 28, 2023 was $90.88 in comparison to $70.75 for the twelve months ended February 28, 2022, representing an increase of $20.13 or 28.5% per barrel. We only have natural gas production from our project in Contra Costa County. Prior to the acquisition of our Reabold subsidiary in May of 2022, we had no natural gas production.

Of the $933,179 or 137.2% increase in revenue for twelve months ended February 28, 2023 approximately $739,633 or 79.3% can be attributed to the increase in sales volume mainly due to our Reabold subsidiary acquisition.

Operating Expenses

Total operating expenses increased $~~187~~2,~~178~~956,413 or 24314.82% to $~~940~~3,~~886~~897,299 for the twelve months ended February 28, ~~2022~~2023 in comparison to $~~753~~940,~~708~~886 for the twelve months ended February 28, ~~2021~~2022. Our operating expenses are set forth in the table below:

	Twelve Months Ended February 28, 2022									Twelve Months Ended February 28, 2021
	Twelve Months Ended February 28, 2023											Twelve Months Ended February 28, 2022
	Expenses		~~Percentage~~	Percentage			~~BOE Basis~~	BOE Basis		~~Expenses~~		Expenses	~~Percentage~~		Percentage	~~BOE Basis~~		BOE Basis
Production expenses	$	~~231~~1,~~275~~103,825		~~24.6%~~	28.3	%				$	~~187,858~~	$	231,275	~~24.9%~~		24.6	%
Exploration and drilling expenses		~~56,213~~—		~~6.0%~~	—	%					83		56,213	~~0.0%~~		6.0	%
Depreciation, Depletion, Amortization (“DD&A”)		49,590		5.3%							60,063			8.0%
Depreciation, depletion, amortization (“DD&A”)		504,118			12.9	%							49,590			5.3	%
General and Administrative (“G&A”) expenses		603,808		64.1%							505,704			67.1%
Impairment expense		711,873			18.3	%
Total operating expenses	$	940,886		100.0%			$	97.88		$	753,708			100.0%		$	68.71
Transaction (acquisition) expenses		573,472			14.7	%							—			—
General and administrative (“G&A”) expenses		1,004,011			25.8	%							603,808			64.1	%
Total operating expenses	$	3,897,299			100.0	%		$	219.55			$	940,886			100.0	%	$	97.88

Production expenses include expenses associated with the production of crude oil and natural gas. These expenses include pumper salaries, electricity, road maintenance, control of well insurance, property taxes and well maintenance and workover expenses; and, relate directly to the number of wells that are on production. For the twelve months ended February 28, 2022, these expenses increased $43,417, or 23.1% to $231,276 in comparison to $187,858 for the twelve months ended February 28, 2021. We had 20 wells on production in California for the twelve months ended February 28, 2022 and February 28, 2021. Production expenses on a BOE basis in California for the twelve months ended February 28, 2022 and February 28, 2021 were $24.06 and $17.12, respectively. Production expenses represented 24.6% and 24.9% of total operating expenses for the twelve months ended February 28, 2022 and February 28, 2021, respectively.46

~~Exploration~~Production ~~and drilling~~ expenses include ~~geological~~expenses associated with the production of crude oil and ~~geophysical~~natural ~~(“G&G”)~~gas. These expenses asinclude ~~well~~contract aspumper, ~~leasehold~~electricity, road maintenance, ~~plugging~~control ~~and~~of well ~~abandonment~~insurance, ~~(“P&A”)~~property taxes, well maintenance and workover expenses ; and, ~~dry~~relate ~~hole~~directly ~~expenses~~to the number of wells that are on production. ~~These~~For the twelve months ended February 28, 2023, these expenses increased $56872,~~130~~550, or 377.3% to $561,~~213~~103,825 in comparison to $231,275 for the twelve months ended February 28, 2022. At February 28, 2023, we had 24 wells on production in comparison to ~~$83~~20 wells on production for the twelve months ended February 28, ~~2021~~2022. The increase in producing wells was due to the acquisition of our Reabold subsidiary that occurred in May of 2022. The increase in production expenses for the twelve months ended February 28, 2023, was primarily due to the ~~write~~replacement ~~off~~and upgrading of ~~exploration~~pumps in seven wells of the East Slopes project for $56,549 and the expenses associated ~~related~~with tosalt water disposal of $426,838 from the Reabold properties. A salt water disposal well is currently being permitted ~~Michigan~~which, ~~prospect~~when put into operation is expected to significantly lower operating costs of the Reabold project. ~~Exploration~~Production expenses on a BOE basis for the twelve months ended February 28, 2023 and ~~drilling~~February 28, 2022 were $62.18 and $24.06, respectively. Production expenses represented 628.03% and 024.06% of total operating expenses for the twelve months ended February 28, ~~2022~~2023 and February 28, ~~2021~~ 2022, respectively.

~~Depreciation,~~Exploration ~~Depletion,~~and ~~Amortization~~drilling expenses include geological and geophysical (“DDG&AG”) ~~expense~~ ~~relates~~expenses toas ~~equipment,~~well ~~proven~~as ~~reserves~~leasehold ~~and property costs~~maintenance, plugging and isabandonment ~~another~~(“P&A”) ~~component~~expenses and ofdry ~~operating~~hole expenses. These expenses decreased $1056,~~473~~130 ~~or 17.4%~~ to $~~49,590~~-0- for the twelve months ended February 28, ~~2022~~2023 in comparison to $6056,~~063 for the twelve months ended February~~130 ~~28, 2021. The primary reason~~ for the decrease in DD&A expense was due to higher realized crude oil prices thus increasing the estimated economic life of our reserves in comparison to our reserve report from the prior year. On a BOE basis, DD&A expense in California for the twelve months ended February 28, 2022 ~~and February 28, 2021 was $5~~.16 Exploration and ~~$5.48,~~drilling ~~respectively. DD&A~~ expenses represented ~~5.3~~-0-% and 86.0% of total operating expenses for the twelve months ended February 28, ~~2022~~2023 and February 28, ~~2021~~2022, respectively.

~~General~~Depreciation, ~~and~~Depletion, ~~administrative~~ Amortization (“GDD&A”) expense relates to equipment, proven reserves and property costs, and is another component of operating expenses. These expenses increased $98454,~~104~~528 or 19916.46% to $~~603~~504,~~808~~118 for the twelve months ended February 28, ~~2022~~2023 in comparison to $~~505~~49,~~704~~590 for the twelve months ended February 28, ~~2021~~2022. The primary reason for the increase in GDD&A ~~expenses~~expense was ~~primary~~ due to ~~employees~~ ~~returning to work after temporary lay-offs~~the ~~due~~recognition toof the ~~COVID-19~~Reabold ~~epidemic~~subsidiary wells and ~~increases~~equipment inand ~~travel,~~their ~~insurance~~projected ~~rates,~~production ~~legal~~life. ~~fees,~~On ~~and~~a ~~fundraising.~~BOE ~~Other~~basis, ~~items~~DD&A ~~included~~expense in California ~~our~~for ~~G&A expenses~~the ~~are~~twelve ~~legal~~months ~~and~~ended ~~accounting~~February ~~expenses~~28, ~~investor relations fees~~2023, ~~travel~~and ~~expenses,~~February ~~insurance~~28, ~~Sarbanes-Oxley~~2022 ~~(“SOX”)~~was ~~compliance expenses~~$28.40 and ~~other~~$5.16, ~~administrative~~respectively. DD&A expenses ~~necessary~~represented ~~for~~12.9% anand ~~operator~~5.3% of ~~oil~~total ~~and~~operating ~~gas~~expenses ~~properties as well as~~ for the ~~management~~twelve amonths ~~public company.~~ended ~~For~~February ~~the~~28, ~~year~~2023, ~~ended~~and February 28, 2022, ~~we received, as Operator~~respectively.

37 Impairment expense of $711,873 for the twelve months ended February 28, 2023 is due to the write down of proven undeveloped reserves in our Reabold subsidiary project. Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years. Impairment expense represented 18.3% and 0% of total operating expenses for the twelve months ended February 28, 2023 and February 28, 2022, respectively.

ofFor the ~~East~~twelve ~~Slopes~~months ~~project~~ended inFebruary ~~California~~28, ~~administrative overhead~~2023, ~~reimbursement~~we incurred transaction expenses of $53573,~~287,~~472 ~~which~~related ~~was~~to ~~used~~the acquisition of funding and to ~~directly~~acquire ~~offset~~the ~~certain~~Reabold ~~employee~~crude ~~salaries~~oil and natural gas properties located in central California. WeFor ~~are~~the ~~continuing~~twelve amonths ~~program~~ended ofFebruary ~~reducing~~28, ~~all~~2022, ~~of our~~we ~~G&A~~did ~~costs~~not ~~wherever~~incur ~~possible.~~any ~~G&A~~related expenses. Transaction expenses represented 6414.17% and 670.10% of total operating expenses for the twelve months ended February 28, ~~2022~~2023 and February 28, ~~2021~~2022, respectively.

~~Interest~~General ~~expense~~and administrative (“G&A”) expenses include the salaries of five employees, ~~net~~including ~~decreased~~management. 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 operation of crude oil and natural gas properties as well as for the management of a public company. For the twelve months ended February 28, 2023, G&A expenses increased $17400,~~728~~203 or 766.53% to $~~220~~1,~~085~~004,011 in comparison to $603,808 for the twelve months ended February 28, 2022. The primary reasons for the increase in ~~comparison~~G&A expense are related to the expenses of both the special shareholders and the annual shareholders meetings, in the amount of approximately $~~237~~131,~~813~~394 in aggregate, approximately $120,000 in legal and accounting fees related to the acquisition and an increase in SEC reporting expense of approximately $53,800 during the twelve months ended February 28, 2023. We are continuing a program of controlling our G&A costs wherever possible. G&A expenses represented 25.8% and 64.1% of total operating expenses for the twelve months ended February 28, ~~2021~~2023 and February 28, 2022, respectively.

~~During~~Interest expense, net for the twelve months ended February 28, ~~2022,~~23 decreased ~~the~~$74,861 ~~Company~~or ~~recognized~~34.0% ato ~~gain~~$145,224 onin ~~asset~~comparison ~~disposal~~to of $9220,~~614.~~085 ~~The~~for ~~gain was~~ the ~~result~~twelve ofmonths anended ~~insurance~~February ~~settlement~~28, ~~on the theft of a company vehicle that was fully depreciated~~2022.

During the twelve months ended February 28, 2022, the Company recognized a gain on ~~debt~~asset ~~forgiveness~~disposal ~~in the amount~~ of $729,~~800~~614. ~~due~~The togain ~~notification~~was ~~that~~ the ~~SBA~~result ~~had~~of ~~approved~~an ~~the~~insurance ~~company’s application~~settlement ~~for~~on ~~loan~~the ~~forgiveness~~theft onof ~~the~~a ~~PPP~~company vehicle ~~2nd~~that ~~Draw~~was ~~loan~~fully depreciated. ~~During~~Additionally, during the twelve months ended February 28, ~~2021~~2022, the Company recognized a gain on debt forgiveness in the amount of $7472,~~355~~800 due to notification that the SBA had approved the company’s application for loan forgiveness on the PPP ~~initial~~2nd Draw loan.

Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially quarter-to-quarter and year-to-year. Our revenues are dependent upon both hydrocarbon production levels and the price we receive for hydrocarbon sales. Production costs will fluctuate according to the number and percentage ownership of producing wells the period of time the wells have been producing, as well as the amount of revenues being generated by each well. 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, plus the size of our proven reserve 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; to fund our development drilling in California; and, future drilling programs in other geographic locations.47

Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially quarter-to-quarter and year-to-year. Our revenues are dependent upon both hydrocarbon production levels and the price we receive for hydrocarbon sales. Production costs will fluctuate according to the number and percentage ownership of producing wells the period of time the wells have been producing, as well as the amount of revenues being generated by each well. 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, plus the size of our proven reserve 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; to fund our development drilling in California; and future drilling programs in other geographic locations.

Capital Resources and Liquidity

Our primary financial resource is our base of crude oil and natural gas reserves. Our ability to fund our capital expenditure program is dependent upon the prices we receive from our crude oil and natural gas sales and the availability of capital resource financing. There continues to be a significant amount of volatility in hydrocarbon prices and a corresponding ~~fluctuation~~volatility in our realized sale price of crude oil and natural gas does exist. AnOne example of this volatility is that in ~~June of~~March ~~2014~~2022, ~~the monthly average price of WTI crude oil was $105.79 per barrel and~~ our realized price per barrel of crude oil was $98108.7808, while in ~~April~~November ~~2020~~2022, ~~the~~it ~~monthly average price of WTI crude oil~~ was $1684.5540 and in ~~our~~February ~~monthly~~2023 ~~realized~~it ~~price~~ was $1671.9685 per barrel. ~~Finally,~~Another example of this volatility is that in ~~February~~ June 2022, ~~the~~our ~~monthly~~realized ~~average~~ price per Mcf of ~~WTI~~natural gas ~~oil~~in California was $9111.6403, ~~per~~while ~~barrel~~in ~~and~~November ~~our~~2022 ~~realized~~it ~~price~~was ~~per~~$7.59 ~~barrel~~and ofin ~~crude~~January ~~oil~~2023 it was $8758.4103 per Mcf. This volatility in crude oil and natural gas prices has continued throughout ~~most of~~ the fiscal year ended February 28, ~~2022~~2023. Any downward volatility in the price of crude oil and natural gas will have a prolonged and substantial negative impact on our profitability and cash flow from our producing California properties. It is beyond our ability to accurately predict crude oil prices over any substantial length of time. When new financing is secured, we plan to drill ~~four~~three development wells and one SWD well for aan approximate total of $~~565~~800,000.

~~Off-Balance~~Changes ~~Sheet~~in ~~Arrangements~~our capital resources at February 28, 2023 are set forth in the table below:

As of February 28, 2022, we did not have any relationships with unconsolidated entities or financial partners, such as entities often referred to as structured finance or special purpose entities, which have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.

	February 28, 2023			February 28, 2022			Increase (Decrease)			Percentage Change
Cash	$	299,410		$	139,573		$	159,837			114.5	%
Restricted cash	$	275,000		$	—		$	275,000			100.0	%
Current assets	$	1,153,963		$	416,651		$	737,312			177.0	%
Total assets	$	7,715,392		$	975,704		$	6,739,688			690.8	%
Current liabilities	$	(3,254,246	)	$	(3,404,735	)	$	(150,489	)		(4.4	%)
Total liabilities	$	(4,505,143	)	$	(4,322,908	)	$	182,235			4.2	%
Working capital deficit	$	(2,100,283	)	$	(2,988,084	)	$	(887,801	)		(29.7	%)

~~Factors~~Our ~~such~~working ascapital ~~changes~~deficit decreased approximately $0.89 million or 29.7% from a deficit of approximately $2.99 million at February 28, 2022 to a deficit of approximately $2.1 million at February 28, 2023. The decrease in ~~operating~~the ~~margins~~working ~~and~~capital deficit was primarily due to the proceeds we received in ~~availability~~connection with the sale of ~~capital~~Common ~~resources~~Stock ~~could~~and the acquisition of our Reabold California, LLC subsidiary current assets. We anticipate an increase orin ~~decrease~~our cash flow will occur when we are able to return to our ~~ultimate~~planned ~~level~~drilling ofprogram ~~expenditures~~that ~~during~~will result in an increase in the number ~~next~~of ~~fiscal~~successful ~~year~~wells on production.

Changes in our capital resources at February 28, 2022 are set forth in the table below:

	February 28, 2022			February 28, 2021			Increase (Decrease)			Percentage Change
Cash	$	139,573		$	33,528		$	106,045			316.3%
Current Assets	$	416,651		$	283,239		$	133,412			47.1%
Total Assets	$	975,704		$	912,125		$	63,579			7.0%
Current Liabilities	$	(3,404,735	)	$	(4,469,074	)	$	(1,064,339	)		(23.8%)
Total Liabilities	$	(4,322,908	)	$	(6,029,265	)	$	(1,706,357	)		(28.3%)
Working Capital Deficit	$	(2,988,084	)	$	(4,185,835	)	$	(1,197,751	)		(28.6%)

Our working capital deficit decreased approximately $1.2 million or 28.6% from a deficit of approximately $4.2 million at February 28, 2021 to a deficit of approximately $3.0 million at February 28, 2022. The decrease in the working capital deficit was primarily due to a restructuring of our balance sheet by converting related party debt to common stock. This reduction was offset by an increase in accrued interest and the issuance of a short-term convertible note. For the twelve months ended February 28, 2022. we continued to have ongoing positive cash flow from our crude oil operations in California however, we were unable to generate sufficient cash flow to cover all of our general and administrative (“G&A”) and interest expense requirements.

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. We will have to rely on the capital markets to fund future operations and growth. Our business model is focused on acquiring exploration or development properties as well as existing production. Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of crude oil and natural gas producing properties, which will 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 may also cause us to seek additional capital from sources outside of the Company. The current uncertainty in the credit and capital markets, as well as the instability and volatility in crude oil prices since June of 2014 has restricted our ability to obtain needed capital. No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all.48

~~The~~Daybreak ~~Company’s~~has ~~financial~~ongoing ~~statements~~capital ~~for~~commitments ~~the~~to ~~twelve~~develop ~~months~~certain ~~ended~~leases ~~February~~pursuant ~~28,~~to ~~2022~~their ~~have~~underlying ~~been~~terms. ~~prepared~~Failure onto ameet ~~going~~such ~~concern~~ongoing ~~basis,~~commitments ~~which~~may ~~contemplates~~result in the ~~realization~~loss of ~~assets~~the ~~and~~right ~~the~~to ~~settlement~~participate ofin ~~liabilities~~future indrilling ~~the~~on ~~normal~~certain ~~course~~leases ofor ~~business.~~the Weloss ~~have~~of ~~incurred~~the alease ~~cumulative~~itself. ~~net~~These ~~loss~~ongoing ~~since~~capital ~~entering~~commitments ~~the~~may ~~crude~~also ~~oil~~cause ~~and~~us ~~natural~~to ~~gas~~seek ~~exploration~~additional ~~industry~~capital infrom ~~2005.~~sources Asoutside of ~~February~~the ~~28,~~Company. ~~2022,~~The wecurrent ~~have~~uncertainty anin ~~accumulated~~the ~~deficit~~credit ofand ~~approximately~~capital ~~$29.5 million~~markets, ~~and~~as awell ~~working~~as ~~capital~~the ~~deficit~~instability ofand volatility ~~approximately~~in ~~$3.0~~crude ~~million~~oil ~~which~~and ~~raises substantial~~natural ~~doubt~~gas ~~about~~prices has restricted our ability to ~~continue~~obtain asneeded ~~a going concern~~capital.

OnThe ~~October~~Company’s ~~20,~~financial ~~2021,~~statements wefor ~~entered~~the ~~into an Equity Exchange~~twelve ~~Agreement~~months ~~(the~~ended ~~“Exchange~~February ~~Agreement”)~~28, by2023 ~~and~~have ~~between~~been ~~Daybreak,~~prepared ~~Reabold~~on ~~California LLC,~~ a ~~California~~going ~~limited~~concern ~~liability company (“Reabold”)~~basis, ~~and~~which ~~Gaelic~~contemplates ~~Resources Ltd., a private company incorporated in~~ the ~~Isle~~realization of ~~Man~~assets and the ~~100% owner of Reabold (“Gaelic”),~~settlement ~~pursuant to which the parties propose for (i) Daybreak to acquire 100% ownership~~ of ~~Reabold,~~liabilities in ~~exchange~~the ~~for~~normal ~~(ii)~~course ~~Daybreak issuing 160,964,489 shares~~ of ~~its~~business. ~~common~~We ~~stock,~~have ~~par~~incurred ~~value~~a ~~$0.001~~cumulative ~~(“Common~~net ~~Stock”)~~loss tosince ~~Gaelic~~entering (the ~~“Exchange~~crude ~~Shares”),~~oil ~~which~~and ~~will~~natural ~~result~~gas exploration industry in ~~Reabold~~2005. ~~becoming~~As ~~a wholly-owned subsidiary~~ of ~~Daybreak~~February ~~named~~28, ~~“Daybreak~~2023, ~~LLC”~~we ~~and~~have ~~Gaelic~~an ~~becoming~~accumulated ~~the~~deficit ~~owner~~ of ~~the~~approximately ~~Exchange~~$31.96 ~~Shares~~million and a ~~major~~working ~~shareholder~~capital deficit of ~~Daybreak~~approximately ~~(the~~$2.1 ~~foregoing~~million ~~transaction~~which ~~and~~raises ~~the~~substantial ~~transactions~~doubt ~~contemplated~~about ~~thereby,~~our ~~the~~ability ~~“Equity~~to ~~Exchange”)~~continue as a going concern.

InWe ~~connection~~will ~~with~~need ~~the~~to ~~Equity~~seek ~~Exchange,~~additional ~~and~~financing asfor ~~conditions~~our toplanned ~~closing~~exploration ~~the~~and ~~Equity~~development ~~Exchange,~~activities ~~among~~in ~~other~~California. ~~things~~We wecould ~~also~~obtain ~~propose~~financing tothrough ~~enter~~one ~~into~~or ~~agreements~~more tovarious ~~sell a minimum of $2~~methods,~~500,000~~ ~~of shares~~including ofissuing ~~Daybreak’s~~debt ~~Common Stock~~securities, ~~and~~equity asecurities, ~~minimum~~or ofbank ~~125~~debt,~~000,000~~ ~~shares~~or combinations of ~~Common~~these ~~Stock~~instruments, towhich ~~one~~could orresult ~~more investors~~ in adilution ~~private~~to ~~placement~~existing ~~expected~~security toholders ~~close~~and ~~promptly~~increased ~~following~~debt ~~the~~and ~~closing~~leverage. ofNo ~~the~~assurance ~~Equity~~can ~~Exchange~~be ~~(the~~given ~~“Capital~~that ~~Raise”),~~we ~~with~~will ~~the~~be ~~proceeds~~able ofto ~~the~~obtain ~~Capital Raise~~funding tounder beany ~~used~~loan tocommitments or ~~repay~~any inadditional ~~full~~financing ~~the~~on ~~Company’s~~favorable ~~line~~terms, ofif ~~credit~~at ~~with~~all. ~~UBS~~Sales ~~Bank~~of ~~and~~interests ~~for~~in ~~drilling~~our ~~and~~assets ~~exploration~~may ~~activities~~be ~~and~~another ~~other working~~source ~~capital~~of ~~purposes~~cash flow.

39 Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.

AsAccounts ofPayable February 28, 2022, all of the conditions for the closing of the Exchange Agreement have not yet been met. The Company is continuing to work towards satisfying all of the Exchange Agreement conditions including having certain conditions of the Exchange Agreement approved by the Company’s shareholders. Please refer to Note 16 – ~~Subsequent~~Related ~~Events in the Notes to these financial statements.~~Parties

In California at the East Slopes Project, two of the vendors that the Company uses for services are partially owned by a related party, the Company’s Chief Operating Officer. The Company’s Chief Operating Officer is 50% owner in both Great Earth Power (“Great Earth”) and ABPlus Net Holdings (“ABPlus”). Great Earth began providing a portion of the solar power electrical service for production operations in July 2020. ABPlus began providing portable tank rentals to the Company as a part of its water treatment and disposal operations in September 2020. The services provided by Great Earth and ABPlus are competitive with other vendors and save the Company significant expense.

For the twelve months ended February 28, 2023, and February 28, 2022, Great Earth provided services valued at $15,663 and $20,300, respectively. For the twelve months ended February 28, 2023, and February 28, 2022, ABPlus provided services valued at $11,520, respectively. At February 28, 2023 and February 28, 2022, Great Earth was owed $613 and $1,400, respectively. At February 28, 2023 and February 28, 2022, ABPlus was owed $960, respectively. Amounts owed to Great Earth and ABPlus represent a portion of the accounts payable amount presented on the balance sheets.

Cash Flows

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

	Twelve Months Ended February 28, 2022			Twelve Months Ended February 28, 2021			Increase (Decrease)			Percentage Change
	Twelve Months Ended February 28, 2023			Twelve Months Ended February 28, 2022			Increase (Decrease)			Percentage Change
Net cash (used in) operating activities	$	(13315,~~356~~117	)	$	(~~143~~13,~~526~~356	)	$	~~(130~~301,~~170~~761	)		~~(90~~2,259.~~7%)~~4	%
Net cash (used in) investing activities	$	(16386,~~232~~160	)	$	—(16,232	)	$	16369,~~232~~928			~~100~~2,279.0%	%
Net cash provided by financing activities	$	~~135~~1,~~633~~136,114		$	83135,~~011~~633		$	521,~~622~~000,481			63737.~~4%)~~6	%

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. Cash flow used in our operating activities for the twelve months ended February 28, ~~2022~~2023 was $13315,~~356~~117 in comparison to cash flow used in our operating activities of $~~143~~13,~~526~~356 for the twelve months ended February 28, ~~2021~~2022. Changes in our cash flow ~~operating~~used for operating activities for the twelve months ended February 28, ~~2022~~2023 in comparison to the twelve months ended February 28, ~~2021~~2022 ~~were~~ increased $~~130~~301,~~170~~761 and ~~consisted~~ were mainly a result of ~~increases~~the expense of our annual shareholders meeting and the Reabold subsidiary acquisition. We had increases in our non-cash expenses of $211,~~650~~266,587, primarily from recognition of impairment of ~~Michigan~~proved ~~unproved~~undeveloped ~~crude~~locations ~~oil~~acquired ~~properties~~in the Reabold acquisition of $55711,~~978;~~873 and an increase in DD&A of $454,498, a decrease in changes in assets of $10107,~~865;~~445 athat ~~decrease~~was offset by an increase in changes in liabilities of $16569,~~160~~884 and the ~~decrease~~increase in our net loss for the year of approximately $~~113,815~~2.0 million. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Our expenditures in operating activities consist primarily of exploration and drilling expenses, production expenses, geological, geophysical and engineering services and maintenance of existing mineral leases. Our expenses also consist of consulting and professional services, employee compensation, legal, accounting, travel and other G&A expenses that we have incurred in order to address normal and necessary business activities of a public company in the crude oil exploration and production industry.49

Our expenditures in operating activities consist primarily of exploration and drilling expenses, production expenses, geological, geophysical and engineering services and maintenance of existing mineral leases. Our expenses also consist of consulting and professional services, employee compensation, legal, accounting, travel and other G&A expenses that we have incurred in order to manage normal and necessary business activities of a public company in the crude oil exploration and production industry.

Cash Flow Used in Investing Activities

Cash flow from investing activities is derived from changes in oil and gas property balances, fixed asset balances and any lending activities. For the twelve months ended February 28, ~~2022~~2023 we used cash flow of $16386,~~232~~160 in comparison to no cash flow used for investing activities of $16,232 for the twelve months ended February 28, ~~2021~~2022. The change in cash flow used in investing activities of $369,928 was primarily related to the Reabold acquisition.

Cash Flow Provided by 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 $~~135~~1,~~633~~136,114 for the twelve months ended February 28, ~~2022~~2023 in comparison to ~~$83,011~~cash ~~for~~flow ~~the~~provided ~~twelve~~by ~~months~~our ~~ended~~financing ~~February 28,~~activities ~~2021.~~of ~~For the twelve months ended February 28, 2022, we received~~ $72135,~~800~~633 ~~in comparison to $74,355~~ for the twelve months ended February 28, ~~2021 under the paycheck protection program (PPP)~~2022. For the twelve months ended February 28, ~~2022~~2023, ~~and~~we ~~February~~secured ~~28,~~a ~~2021,~~capital weraise ~~made payments~~ of $601,~~000~~987,500 ~~respectively,~~net onof ~~the~~transaction ~~UBS~~expenses ~~Bank~~from ~~line~~the sale of ~~credit balances. We received $200~~125,000,000 ~~from~~shares aof ~~convertible~~our ~~note~~Common ~~payable~~Stock. ~~with~~We aalso ~~third~~paid ~~party during~~off the ~~twelve~~balance ~~months ended February 28, 2022. Finally, we made insurance premium financing payments~~ of $68808,~~568 and $74,553 during~~182 on the ~~twelve~~line ~~months~~of ~~ended~~credit ~~February~~with ~~28,~~UBS ~~2022~~Bank ~~and~~during ~~February 28, 2021, respectively. The following is a summary of~~ the ~~Company’s financing activities for the~~ twelve months ended February 28, ~~2022~~2023.

40 Short-Term and Long-Term Borrowings

Debt (short-term and long-term borrowings)

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 being issued to the vendor. Additionally, the Company agreed to issue 2,000,000 shares of the Company’s ~~common~~Common ~~stock~~Stock as a part of the settlement agreement. Based on the closing price of the Company’s ~~common~~Common ~~stock~~Stock on the date of the settlement agreement, the value of the ~~common~~Common ~~stock~~Stock transaction was determined to be $6,000. The ~~common~~Common ~~stock~~Stock shares were issued during the twelve months ended February 29, 2020. The note ~~has~~had a maturity date of January 1, 2022 and bears an interest rate of 10% rate per annum. ~~Monthly~~The note principal has not been paid and the Company is considered to be in default. There is no default interest rate associated with the note. Interest is accrued monthly and is payable on January 1st of each anniversary date ~~until maturity~~ of the note. At February 28, ~~2022~~2023, the note principal and a portion of the accrued interest had not been paid and was outstanding. The accrued interest on the Note was $3826,000 and $2638,000 at February 28, ~~2022~~ 2023 and February 28, ~~2021~~2022, respectively.

Note Payable – Related Party

On December 22, 2020, the Company entered into a ~~Secured~~ Secured Promissory Note (the “Westmoreland Note”), as borrower, with James Forrest Westmoreland and Angela Marie Westmoreland, Co-Trustees of the James and Angela Westmoreland Revocable Trust, or its assigns (the “Noteholder”), as the lender. James F. Westmoreland is the Company’s Chairman, President and Chief Executive Officer. Pursuant to the Note, the Noteholder loaned the Company an aggregate principal amount of $155,548. After the deduction of loan fees of $10,929 the net proceeds from the loan were $144,619. The loan fees are being amortized as original issue discount (“OID”) over the term of the loan. The interest rate of the loan is 2.25%. The Westmoreland Note requires monthly payments on the Note balance until repaid in full. The maturity date of the Westmoreland Note is December 21, 2035. For the twelve months ended February 28, ~~2022~~2023, the Company made principal payments of $8,~~599~~ 829 and amortized debt discount of $729. The obligations under the Westmoreland Note are secured by a lien on and security interest in the Company’s oil and gas assets located in Kern County, California, as described in a Deed of Trust entered into by the Company in favor of the Noteholder to secure the obligations under the Westmoreland Note. Such lien shall be a first priority lien, subject only to a pre-existing lien filed by a working interest partner of the Company.

The Company may prepay the Note at any time. Upon the occurrence of any Event of Default and expiration of any applicable cure period, and at any time thereafter during the continuance of such Event of Default, the Noteholder may at its option, by written notice to the Company: (a) declare the entire principal amount of the Note, together with all accrued interest thereon and all other amounts payable hereunder, immediately due and payable; (b) exercise any of its remedies with respect to the collateral set forth in the Deed of Trust; and/or (c) exercise any or all of its other rights, powers or remedies under applicable law.50

~~Current~~The ~~portion~~Company may prepay the Westmoreland Note at any time. Upon the occurrence of ~~note~~any ~~payable~~Event ~~–related~~of ~~party~~Default and expiration of any applicable cure period, and at any time thereafter during the ~~balances~~continuance of such Event of Default, the Noteholder may at ~~February~~its 28option, ~~2022~~by written notice to the Company: (a) declare the entire principal amount of the Westmoreland Note, together with all accrued interest thereon and ~~February~~all 28other amounts payable hereunder, ~~2021~~immediately ~~are~~due and payable; (b) exercise any of its remedies with respect to the collateral set forth in the ~~table~~Deed ~~below:~~of Trust; and/or (c) exercise any or all of its other rights, powers or remedies under applicable law.

	February 28, 2022			February 28, 2021
Note payable –related party, current portion	$	8,829		$	8,598
Unamortized debt issuance expenses		(729	)		(728	)
Note payable – related party, current portion, net	$	8,100		$	7,870

Current portion of note payable – related party balances at February 28, 2023 and February 28, 2022 are set forth in the table below:

Note payable –related party long-term balances at February 28, 2022 and February 28, 2021 are set forth in the table below:

	February 28, 2023			February 28, 2022
Note payable –related party, current portion	$	9,065		$	8,829
Unamortized debt issuance expenses		(728	)		(729	)
Note payable – related party, current portion, net	$	8,337		$	8,100

	February 28, 2022			February 28, 2021
Note payable – related party, non-current	$	136,710		$	145,540
Unamortized debt issuance expenses		(9,350	)		(10,080	)
Note payable – related party, non-current, net	$	127,360		$	135,460

Note payable –related party long-term balances at February 28, 2023 and February 28, 2022 are set forth in the table below:

	February 28, 2023			February 28, 2022
Note payable – related party, non-current	$	127,645		$	136,710
Unamortized debt issuance expenses		(8,622	)		(9,350	)
Note payable – related party, non-current, net	$	119,023		$	127,360

Future estimated payments on the outstanding note payable – related party are set forth in the table below:

Twelve month periods ending February 28/29,
2023			8,829
2024		9,065
2024			9,065
2025		9,309
2025			9,309
2026		9,558
2026			9,558
2027		9,815
2027			9,815
2028		10,078
Thereafter		88,885	~~98,963~~
Total	$	$136,710	~~145,539~~

Short-term Convertible Note Payable

During the twelve months ended February 28, 2022, the Company executed a convertible promissory note with a third party for $200,000. The interest rate iswas 18% per annum and iswas payable in kind (“PIK”) solely by additional shares of the Company’s ~~common~~Common ~~stock~~Stock. Regardless of when the conversion ~~occurs~~occurred, a full 12 months of interest would ~~will~~ be payable upon conversion. ~~The~~On ~~maturity~~May ~~date of the note is the date of the closing of the transactions contemplated by the Equity Exchange Agreement with Reabold California~~5, ~~LLC and Gaelic Resources~~2022, ~~Ltd. as described above under~~ the ~~Capital~~Company ~~Resources and~~received ~~Liquidity~~notice ~~caption~~of ~~found in this Item 7, Management’s Discussion and Analysis (MD&A). The~~ conversion ~~price was to be determined by one~~ of ~~two cases. In Case 1,~~ the ~~conversion~~promissory ~~price would be $0~~note.~~017~~ ~~and in Case 2, the conversion price would be $0.0085.~~ The ~~Case~~face ~~1 conversion~~amount ~~price scenario would apply if the terms~~ of the ~~Equity~~note ~~Exchange~~and ~~Agreement were met by a Long Stop Date of April 29~~$36,000 ~~2022.~~in ~~The Case~~interest ~~2 conversion price scenario would apply if the terms of the Equity Exchange Agreement~~ were ~~not~~converted ~~met~~at by a ~~Long~~rate ~~Stop Date~~ of ~~April 29, 2022. The terms of the Equity Exchange Agreement were not met by the Long Stop Date of April 29, 2022 and the conversion price was determined to be the~~ $0.0085 ~~rate.~~per ~~Under~~share ~~ASC~~into ~~855-10-55-1~~27,764,706 ~~the~~share ~~Company~~of ~~determined that a derivate issue did not exist since~~ the Company’s ~~was~~Common ~~able to~~Stock ~~determine~~during the ~~impact~~twelve ofmonths ~~the~~ended ~~subsequent~~February ~~event~~28, 2023.

On May 5, 2022, the Company received notice from the third party of their intent to convert the note principal and interest in the amount of $236,000 at the conversion price of $0.0085. Consequently, 27,764,706 shares of the Company’s common stock were issued to the third party to satisfy the obligation.

12% Subordinated Notes

The Company’s 12% Subordinated Notes (“the “Notes”) issued pursuant to a January 2010 private placement offering to accredited investors, ~~resulted~~had ina ~~$595,000~~balance inat ~~gross~~February ~~proceeds (of which $250~~28,~~000~~ ~~was~~2023 ~~from a related party) to the Company~~ and ~~accrue~~February 28, ~~interest~~2022 atof ~~12% per annum~~$290,000 ~~payable semi-annually on January 29th~~ and ~~July 29th. On January 29~~$315, ~~2015~~000, ~~the~~respectively. ~~Company~~The ~~and~~original ~~12 of the 13 holders of the Notes agreed to extend the~~ maturity date of ~~the~~January ~~Notes for~~29, an2015 ~~additional~~had ~~two~~been ~~years~~extended to January 29, 2017. and ~~Effective~~then ~~January 29, 2017, the maturity date of the Notes~~ was extended ~~for an additional two years~~ to January 29, 2019. ~~The~~Interest ~~980,000~~accrues ~~warrants~~at ~~held~~12% byper ~~ten~~annum, ~~noteholders~~payable ~~expired~~semi-annually on January ~~29,~~29th ~~2019~~and July 29th.

The Company has informed the remaining Note holders that the payment of principal and ~~final~~ interest will be late and is subject to future financing being completed and the Company’s cash flow. The Notes principal of $~~565~~290,000 ~~was~~ ~~payable~~has innot ~~full~~been atpaid and interest continues to accrue on the ~~amended~~unpaid ~~maturity~~principal ~~date~~balance. ofThe accrued interest on the 12% Notes, ~~and~~at ~~has~~February ~~not~~28, ~~been~~2023 ~~paid.~~and ~~Interest~~February ~~continues~~28, to2022 ~~accrue~~was on$159,508 ~~the~~and ~~unpaid~~ $~~565~~135,~~000 principal~~229, ~~balance~~respectively. The terms of the Notes, state that should the Board of Directors, ~~on any future maturity date,~~ decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s Common ~~common~~Stock ~~stock~~ at a conversion rate equal to 75% of the average closing price of the Company’s ~~common~~Common ~~stock~~Stock over the 20 consecutive trading days preceding December 31, 2018.

As a result of the Company restructuring its balance sheet through conversions of debt to common stock, the related party 12% Noteholder chose to convert the principal and accrued interest of their Notes to the Company’s common stock. The related party Note for $250,000 and accrued interest of $264,986 were converted to common stock at a rate of approximately $0.45 for every dollar of principal and interest resulting in 1,144,415 shares of common stock being issued. The accrued interest on the 12% Notes at February 28, 2022 and February 28, 2021 was $135,229 and $340,042, respectively.51

~~12%~~During ~~Note~~the ~~balances~~twelve atmonths ended February 28, ~~2021~~2023, one 12% Note holder chose to convert the principal balance and ~~February~~accrued interest into the Company’s Common Stock. The $25,000 Note 28and accrued interest of $10,520 ~~2021~~were ~~are~~converted ~~set~~at ~~forth~~a rate of approximately $0.45 for every dollar of principal and interest resulting in 78,934 ~~the~~shares ~~table~~of ~~below:~~Common Stock being issued.

	February 28, 2022		February 28, 2021
12% Subordinated notes – third party	$	315,000	$	315,000
12% subordinated notes – related party		—		250,000
12% Subordinated notes balance	$	315,000	$	565,000

12% Note balances at February 28, 2023 and February 28, 2022 are set forth in the table below:

The accrued interest at February 28, 2021 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.

	February 28, 2023		February 28, 2022
12% Subordinated notes – third party	$	290,000	$	315,000
12% subordinated notes – related party		—		—
12% Subordinated notes balance	$	290,000	$	315,000

Line of Credit

~~The~~At February 28, 2022, the Company ~~has~~had an existing $890,000 line of credit for working capital purposes with UBS Bank USA ~~(“UBS”),~~that was established pursuant to a Credit Line Agreement dated October 24, 2011 ~~that~~and iswas secured by the personal guarantee of our President and Chief Executive Officer. OnDuring ~~November 10, 2021,~~ the ~~Company~~twelve ~~was~~months ~~notified~~ended ~~that~~February ~~effective January 1~~28, ~~2022~~2023, aand ~~new~~February ~~interest~~28, ~~rate~~2022, ~~benchmark~~ the ~~UBS~~Company ~~Variable~~did ~~Rate~~not ~~(UBSVR)~~receive ~~would~~any ~~replace~~advances ~~the~~on ~~existing 30-day LIBOR (“London Interbank Offered Rate”) benchmark. The UBSVR is comprised of~~ the ~~compounded~~line ~~30-day average~~ of ~~the Secured Overnight Financing Rate (SOFR) plus a fixed spread adjustment of 0~~credit.~~110%. The Company’s new all-on rate will consist of the UBSVR plus its current spread over LIBOR.~~

~~During~~On ~~the~~May ~~twelve~~26, ~~months~~2022, ~~ended~~the ~~February~~Company paid ~~28,~~off ~~2022~~the ~~and~~outstanding ~~February~~balance ~~28,~~of ~~2021~~$809, we930 ~~did~~on ~~not~~the ~~receive~~line ~~any~~of ~~advances~~credit. onThe payoff of the line of credit, ~~respectively.~~was ~~During~~previously approved under terms of the ~~twelve~~Equity ~~months~~Exchange ~~ended~~Agreement ~~February~~in ~~28,~~which ~~2022~~the ~~and~~Company ~~February~~acquired ~~28, 2021,~~the weReabold ~~made~~property ~~payments~~in toCalifornia. ~~the~~The line of credit ofpayoff ~~$60,000,~~was ~~respectively.~~a ~~Interest~~part of ~~converted~~the touse ~~principal~~of ~~for~~proceeds from the ~~twelve~~Company’s ~~months~~sale ~~ended~~of Common Stock to a third party. At February 28, ~~2022~~2023, and February 28, ~~2021~~2022, ~~was~~the line of credit had an outstanding balance of $~~27,278~~-0- and $28808,~~503~~182, respectively. AtDuring ~~February~~the ~~28,~~twelve ~~2022~~months ~~and~~ended February 28, ~~2021~~2022, the Company made payments to the line of credit ~~had an~~of ~~outstanding~~$60,000. ~~balance~~Interest ofconverted ~~$808~~to principal for the twelve months ended February 28,~~182~~ ~~and~~2022 was $~~840~~27,~~904, respectively~~278.

Production Revenue Payable

~~Since~~During ~~December~~the ~~2018~~twelve months ended February 28, 2019, and February 29, 2020, the Company ~~has~~conducted ~~been conducting~~ a fundraising program to raise $1.3 million to fund the drilling of future wells in California and to settle some of its ~~existing~~ historical debt. The purchasers of a production revenue payment ~~interests~~interest are to receive a production revenue payment interest on future wells to be drilled in California in exchange for their purchase. OnThe ~~August~~Company ~~22,~~shall ~~2019,~~pay ~~the~~seventy-five ~~Company~~percent (75%) ~~entered~~of ~~into~~its afuture ~~Note~~net ~~Payoff~~production ~~Agreement~~revenue ~~with~~from the ~~Company’s~~relevant ~~Chairman,~~wells ~~President~~to ~~and~~the ~~Chief Executive~~purchasers ~~Officer~~until aseach ~~payment~~purchaser inhas ~~full~~received oftwo times the ~~$250,100~~purchase price ~~that~~(the ~~had~~“Production ~~been~~Payment ~~loaned~~Target”). toOnce the Company ~~during~~pays the ~~years~~purchaser ~~ended~~group ~~February~~amounts ~~29,~~equal ~~2012 and February 28, 2013. Pursuant~~ to the ~~Note~~Production ~~Payoff Agreement~~Payment Target, ~~the~~it ~~Company~~shall ~~issued~~thereafter pay a ~~production~~pro-rated ~~payment~~eight ~~interest~~percent in(8%) ~~certain~~ of ~~the~~$1.3 ~~Company’s production~~million ~~revenue~~on ~~from~~its ~~the~~net ~~drilling of future wells in California. The~~ production ~~payment~~payments ~~interest~~from ~~was~~the ~~granted~~relevant ~~for a deemed consideration~~wells ~~amount~~to of the ~~balance~~purchaser ~~of the Notes~~group. ~~The~~However, ~~grant~~if ~~was~~the ~~made~~total onraise ~~the~~amount ~~same~~is ~~terms~~less asthan the ~~Company~~target ~~has~~$1.3 ~~sold~~million, ~~production~~then the payment ~~interests~~will tobe ~~other~~a proportionate ~~third~~amount ~~parties~~of in the ~~2018-2019~~eight ~~fiscal~~percent ~~year pursuant to its previously disclosed program~~(8%).

The ~~production~~Company ~~payment~~accounted ~~interest~~for ~~entitles~~ the amounts received from ~~purchasers~~these tosales ~~receive~~in ~~production~~accordance ~~payments~~with ~~equal~~ASC to470-10-25 ~~twice~~and ~~their~~470-10-35 ~~original~~which ~~amount~~require ~~paid,~~amounts ~~payable~~recorded ~~from~~as adebt ~~percentage~~to ofbe ~~the Company’s~~amortized ~~future~~under ~~net~~the ~~production~~interest ~~payments~~method as ~~from~~described ~~wells~~in ~~drilled~~ASC ~~after~~835-30, ~~the~~Interest ~~date~~Method. ofConsequently, the ~~purchase~~program ~~and~~balance ~~until~~of ~~the~~$873,281 ~~Production~~has ~~Payment Target~~been (recognized as ~~described~~a ~~below)~~production ~~is met~~revenue payable. The Company ~~shall~~determined ~~pay~~an ~~seventy-five~~effective ~~percent~~interest ~~(75%)~~rate ofbased ~~its~~on ~~net~~future ~~production~~expected ~~payments~~cash ~~from~~flows ~~the relevant~~to ~~new~~be ~~wells~~paid to the ~~purchasers~~holders ~~until~~of ~~each~~the ~~purchaser~~production payment ~~has~~interests. ~~received~~This ~~two~~rate ~~times~~represents the ~~purchase~~discount ~~price~~rate ~~(the~~that ~~“Production~~equates ~~Payment Target”).~~estimated ~~Once~~cash flows with the ~~Company~~initial ~~pays~~proceeds received from the sales ~~purchasers~~and ~~amounts~~is ~~equal~~used to compute the ~~Production~~amount ~~Payment~~of ~~Target,~~interest itto ~~shall~~be ~~thereafter~~recognized ~~pay~~each aperiod. Estimating the future cash outflows under this agreement ~~pro-rated~~requires ~~eight~~the ~~percent~~Company ~~(8%)~~to ofmake ~~$1.3~~certain ~~million~~estimates onand ~~its~~assumptions ~~net~~about ~~production~~future revenues and payments ~~from~~and ~~the~~such ~~relevant~~estimates ~~wells~~are subject to ~~each~~significant variability. ofTherefore, the ~~purchasers. However,~~estimates ifare ~~the~~likely ~~total~~to ~~raised~~change iswhich ~~less~~may ~~than~~result ~~the~~in ~~target~~future ~~$1.3~~adjustments ~~million,~~to ~~then~~the accretion of the ~~payment~~interest ~~will~~expense and bethe aamortized ~~proportionate~~cost ~~amount~~based carrying value of the ~~eight percent~~related ~~(8%)~~payables.

~~The~~Accordingly, the Company ~~accounted~~has ~~for~~estimated the ~~amounts~~cash ~~received~~flows ~~from~~associated ~~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~~production asrevenue ~~described~~payments inof ~~ASC 835-30~~$913,395 ~~Interest~~and ~~Method.~~determined ~~Consequently,~~a ~~the~~discount ~~program balance~~ of $~~950~~78,~~100~~136 ~~has been recognized~~ as ~~a production~~of ~~revenue~~February ~~payable.~~28, ~~The~~2023, ~~Company~~which ~~determined~~is anbeing accounted ~~effective~~as interest ~~rate~~expense ~~based~~over onthe ~~future~~estimated ~~expected~~period ~~cash~~over ~~flows~~which topayments will be ~~paid~~made tobased ~~the holders~~on ofexpected ~~the~~future ~~production~~revenue ~~payment interests~~streams. ~~This rate represents~~ For the ~~discount~~twelve ~~rate~~months ~~that~~ended ~~equates~~February ~~estimated~~28, ~~cash~~2023, ~~flows with the initial proceeds received from the sales~~ and isFebruary ~~used~~28, to2022, ~~compute~~amortization ~~the amount~~ of ~~interest to be recognized each period. Estimating~~ the ~~future~~ ~~cash~~debt ~~outflows~~discount ~~under~~on ~~this~~these ~~agreement~~payables ~~requires~~amounted ~~the Company~~ to ~~make certain estimates and assumptions about future revenues and~~$56,156 ~~payments~~ and ~~such~~$95,974, ~~estimates are subject to significant variability. Therefore~~respectively, ~~the~~which ~~estimates~~has ~~are~~been ~~likely~~included ~~to change which may result~~ in ~~future adjustments to the accretion of the~~ interest expense ~~and~~in the ~~amortized~~statements ~~cost based carrying value~~ of ~~the related payables~~operations.

Accordingly, the Company has estimated the cash flows associated with the production revenue payments and determined a discount of $941,259 as of February 28, 2022, 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 twelve months ended February 28, 2022 and February 28, 2021, amortization of the debt discount on these payables amounted to $95,974 and $115,151, respectively, which has been included in interest expense in the statements of operations.52

43 Production revenue payable balances at February 28, 2023, and February 28, 2022 are set forth in the table below:

As a result of the Company restructuring its balance sheet through conversions of debt to common stock the related party with the production revenue interest chose to convert the original principal investment of $550,100 to the Company’s common stock at a rate of approximately $0.45 for every dollar of principal and interest resulting in 1,222,444 shares of common stock being issued. The outstanding interest discount to debt of $232,170 was treated as a gain on debt forgives by the Company.

	February 28, 2023			February 28, 2022
Estimated payments of production revenue payable	$	913,395		$	941,259
Less: unamortized discount		(40,114	)		(124,134	)
		873,281			817,125
Less: current portion		(56,915	)		(78,877	)
Net production revenue payable – long term	$	816,366		$	738,248

As of February 28, 2022 and February 28, 2021, the production revenue payment program balance was $817,125 and $1,503,422, respectively. Production revenue payable balances at February 28, 2020 and February 28, 2021 are set forth in the table below:

	February 28, 2022			February 28, 2021
Estimated payments of production revenue payable	$	941,259		$	2,000,258
Less: unamortized discount		(124,134	)		(496,836	)
		817,125			1,503,422
Less: current portion		(78,877	)		(111,753	)
Net production revenue payable – long term	$	738,248		$	1,391,669

Paycheck Protection Program (PPP) Loan

In March 2020, the Coronavirus Aid, Relief, and Economic Security Act commonly referred to as the CARES Act became law. One component of the CARES Act was the paycheck protection program (“PPP”) which provides small business with the resources needed to maintain their payroll and cover applicable overhead. The PPP is implemented by the Small Business Administration (“SBA”) with support from the Department of the Treasury. The Company applied for, and was accepted to participate in this program. On May 11, 2020, the Company received funding for approximately $74,355. On February 12, 2021, the Company applied for loan forgiveness under the provisions of Section 1106 of the CARES Act. Loan forgiveness was subject to the sole approval of the SBA. On February 23, 2021, the SBA notified our lender that the loan was forgiven and repaid the loan in full.

On March 4, 2021, the Company applied for, and was accepted to participate in the SBA PPP Second Draw program with funding pursuant to the Economic Aid Act that was passed in December, 2020. On March 15, 2021, Daybreak received funding for $72,800. The Company applied for full loan forgiveness for the PPP Second Draw PPP loan and on October 6, 2021, the SBA notified our lender that the loan was forgiven and repaid the loan in full.

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.

Capital Commitments

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

Leases

The Company ~~leases~~formally leased approximately 988 rentable ~~square~~ square feet of office space from an unaffiliated third party for our corporate office located in Spokane Valley, Washington. ~~Additionally~~This office was closed in March of 2023 when the corporate office was consolidated with our Friendswood, weTexas regional operations office. We currently lease approximately 416 and 695 rentable square feet from unaffiliated third parties for our ~~regional~~new ~~operations~~corporate office in Friendswood, ~~Texas~~ Texas and storage and auxiliary office space in Wallace, Idaho, respectively. The lease in Friendswood is a 12-month lease that ~~expires~~ expired in October 2023 ~~2022~~and was subsequently renewed until October 31, 2024, and as such is considered a short-term lease. The Company has elected to not apply the recognition requirements of ASC 842 to this short-term lease. The ~~Spokane Valley and~~ Wallace ~~leases~~lease ~~are~~is 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.

Rent expense for the twelve months ended February 28, ~~2021~~2023, and February 28, ~~2021~~2022 was $23,~~489~~889 and $23,~~589~~489, respectively.

Crude Oil and Natural Gas Reserves

Daybreak’s total net proved developed crude oil and ~~undeveloped crude~~natural ~~oil~~gas reserves on a per barrel of oil equivalent (“BOE”) basis increased by 82276,~~932~~066 BOE, or 19234.13%, to ~~517~~393,~~155~~ 910 BOE at February 28, ~~2022~~2023 compared to ~~434~~117,~~223~~844 BOE at February 28, ~~2021~~2022. ~~These reserves are all located in our California East Slopes project.~~ The primary reason for the ~~overall~~ increase in ~~our~~developed ~~total proven~~ reserves was ~~primarily due to higher hydrocarbon prices from~~ the ~~past year lowering~~ ~~the~~acquisition ~~economic~~of ~~life~~ our ~~wells.~~Reabold ~~The~~subsidiary ~~year-to-year~~in ~~reserve~~May ~~increase~~of ~~consisted~~2022. ofOf aour ~~22,724~~proved ~~barrel~~developed orreserves ~~23.9%~~at ~~increase~~February in28, ~~our~~2023, ~~PDP~~the ~~reserves~~Reabold ~~and a~~subsidiary 60represented 277,~~208~~891 ~~barrel~~BOE or ~~17.8~~71% ~~increase~~of in our ~~PUD~~total ~~reserves.~~proved ~~Our~~developed ~~production of PDP~~ reserves. ~~for~~The ~~the~~East ~~year~~Slopes ~~ended~~project ~~February~~represented 28116,019 ~~2022~~BOE ~~was~~or ~~9,613~~29% ~~BOE and~~of ~~was~~our aproved ~~part~~developed reserves. ofUnder the ~~overall~~guidance ~~change~~provided inby ~~PDP~~Rule ~~reserves.~~4-10(a)(31)(ii) ~~The~~of 82Regulation S-X,~~932~~ ~~increase~~we inhave ~~the~~no ~~PUD~~ reserves ~~was~~that ~~all~~qualify ~~due~~ to ~~upward~~be ~~revisions~~considered ~~again because~~proved ofundeveloped ~~higher~~reserves ~~crude~~since ~~oil~~any ~~prices~~proved inundeveloped ~~the past year. Our~~ reserves that were ~~fully~~previously ~~engineered~~considered byto ~~PGH~~be ~~Petroleum~~proved ~~and~~undeveloped ~~Environmental~~reserves ~~Engineers,~~have ~~LLC of Austin,~~remained ~~Texas~~undeveloped infor ~~accordance~~a ~~with~~period ~~generally~~greater ~~accepted~~than ~~petroleum~~five ~~engineering~~years. ~~and~~These ~~evaluation~~proved ~~principles~~developed ~~and~~reserves ~~definitions~~are ~~and~~all ~~guidelines~~located ~~established by~~in ~~the SEC. For further information on~~ our ~~reserve~~California ~~report,~~East ~~refer~~Slopes toand ~~exhibit~~Reabold subsidiary 99projects.~~1 of this Annual Report on Form 10-K.~~

The East Slopes project reserves and the Reabold project reserves were fully engineered by PGH Petroleum and Environmental Engineers, LLC of Austin, Texas and PETROtech Resources off Bakersfield, California, respectively. Both reserve reports were prepared in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. For further information on our reserve report, refer to Exhibit 99.2 of this Annual Report on Form 10-K.

Changes in Financial Condition

During the year ended February 28, ~~2022~~2023, we received crude oil and natural gas sales revenue from 20 wells in our East Slopes ~~Project~~project in Kern County, ~~California. Our commitment to improving corporate profitability remains unchanged. Since June 2014, there has been significant volatility in hydrocarbon prices~~ and aeight ~~corresponding~~wells ~~fluctuation~~ in our ~~realized~~ ~~sale~~Reabold ~~price of crude oil does exist. An example of this volatility is that in June of 2014 the monthly average price of WTI crude~~subsidiary ~~oil was $105.79 per barrel and our realized price per barrel of crude oil was $98.78 while~~ in ~~April~~Monterey ~~2020, the monthly average price of WTI crude oil was $16.55~~ and ~~our~~Contra ~~monthly~~Costa ~~realized~~Counties ~~price~~all ~~was~~located ~~$16.96 per barrel. Finally,~~ in February 2022, the monthly average price of WTI oil was $91.64 per barrel and our realized price per barrel of crude oil was $87.41. This volatility in crude oil prices has continued throughout most of the fiscal year ended February 28, 2022. Any downward volatility in the price of crude oil will have a prolonged and substantial negative impact on our profitability and cash flow from our producing California ~~properties~~. ItFor ~~is beyond our ability to accurately predict crude oil prices over any substantial length of time. During~~ the twelve months ended February 28, ~~2022~~2023, and February 28, ~~2021~~2022, crude oil and natural gas sales revenue from California was $~~680~~1,~~107~~613,286 and $~~404~~680,~~901~~107, respectively. Of the $~~275~~933,~~206~~179 increase in revenue during the twelve months ended February 28, 2022, $~~371~~193,~~212~~546 or ~~134~~20.97% can be attributed to the increase in our average realized crude oil sales price. The increase in sales volume of 8,138 Bbls BOE accounted for $739,633 or 79.3% of the increase in revenue. For the twelve months ended February 28, ~~2022~~2023, and February 28, ~~2021~~2022, we had an operating loss of $~~260~~2,~~780~~284,013 and $~~348~~260,~~807~~779, respectively. Our commitment to improving corporate profitability remains unchanged.

Our balance sheet at February 28, ~~2022~~2023 reflects total assets of approximately $07.987 million, an increase of approximately $~~63,000~~6.7 million in comparison to approximately $0.9198 million at February 28, ~~2021~~ 2022. This increase of approximately $~~63,000~~6.7 million in total assets was largely due to anthe ~~increase~~acquisition ~~in current assets~~ of ~~approximately~~our ~~$133,000~~Reabold ~~offset by~~subsidiary ~~a decrease~~ in May ~~long-term assets~~ of ~~approximately $70,000~~2022. Our cash balance increased by approximately $~~106~~160,000.

At February 28, ~~2022~~2023, total liabilities were approximately $4.35 million, aan ~~decrease~~increase of approximately $10.72 million in comparison to approximately $64.03 million at February 28, ~~2021~~2022. This ~~decrease~~increase was primarily due to ~~conversion~~the recognition of ~~related~~the ~~party~~ARO ~~debt~~liability toassociated ~~common~~with ~~stock~~the ~~through~~crude ~~the~~oil ~~restructuring~~and ofnatural ~~our~~gas ~~balance~~wells ~~sheet~~acquired in the Reabold acquisition.

Common Stock shares issued and outstanding at February 28, ~~2022~~2023 and February 28, ~~2021~~2022 were 67384,~~802~~734,~~273~~902 and 6067,~~491~~802,~~122~~273, respectively. OfThe ~~the~~increase ~~total~~in ~~7,311,151~~Common Stock shares ~~issued~~of ~~during the twelve months ended February 28~~316, ~~2022~~932,629 ~~there~~is ~~were~~directly related ~~4,082,447 shares issued~~ to ~~satisfy~~either ~~related~~the ~~party~~acquisition ~~debt.~~of ~~Another~~our ~~3,228,704~~Reabold ~~shares~~subsidiary ~~were~~or ~~issued to satisfy~~ the ~~Series~~issuance ~~A Preferred stock conversion and associated accumulated dividend. The February 28, 2022 and February 28, 2021 balances~~ of ~~Series A~~Common ~~Preferred~~ Stock shares ~~issued~~for financing and ~~outstanding~~a ~~were~~share ~~-0-~~issuance adjustment ~~and~~of ~~709,568,~~500 ~~respectively~~shares.

As of February 28, 2023, and February 28, 2022, there were 2,100,000 and 893,333 outstanding and exercisable Common Stock warrants. At February 28, 2023, both the outstanding warrants and the exercisable warrants had a weighted average exercise price of $0.01. All outstanding and exercisable warrants expired on January 2, 2024.

Accumulated Deficit

Our financial statements for the twelve months ended February 28, ~~2022~~2023, and February 28, ~~2021~~2022 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. Our financial statements show that the Company has incurred significant operating losses that raise substantial doubt about our ability to continue as a going concern. The accompanying financial statements do not include any adjustments that might result from this uncertainty.

45 The increase of approximately $2.9 million in the accumulated deficit from approximately $29.5 million at February 28, 2022 to $31.96 million at February 28, 2023 was primarily due to one-time expenses associated with completing the acquisition of our Reabold subsidiary including holding both an annual meeting and a special shareholders meeting; associated public company filing expenses; impairment of certain crude oil and natural gas assets; along with an increase in the lease operating expenses related to disposal of the produced water from the Reabold wells.

The increase of approximately $102,000 in the accumulated deficit from approximately $29.4 million at February 28, 2021 to $29.5 million at February 28, 2022 was due to the net loss for the year of approximately $398,450 offset by related party debt forgiveness of approximately $337,825 and issuance of the Series A Preferred stock accumulated divided of $29,480 and settlement of related party receivables and payables of $11,454.

Cash Balance

We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations, investments and capital resource funding. Our cash balances were $~~139~~299,~~573~~410 and $33139,~~528~~573 at February 28, ~~2022~~2023 and February 28, ~~2021~~2022, respectively. The Company has restricted cash in the amount of $275,000 relating to cash used to secure operator bonds for our crude oil and natural gas wells.

Crude oil and natural gas revenues

Crude oil and natural gas revenues increased $~~275~~933,~~206~~ 179 or 68137.02% to $~~680~~1,~~107~~613,286 for the twelve months ended February 28, ~~2022~~2023, in comparison to $~~404~~680,~~901~~107 for the twelve months ended February 28, ~~2021~~2022. Of the $~~275~~933,~~206~~179 increase in revenue during the twelve months ended February 28, ~~2022~~2023, $~~371~~739,~~212~~633 or ~~134~~79.93% can be attributed to the increase in ~~our~~ ~~average realized~~ crude oil and natural gas sales ~~price~~volume primarily due to the acquisition of our Reabold subsidiary.

Operating Expenses

Operating expenses for the twelve months ended February 28, ~~2022~~2023 increased approximately $~~187,178~~3.0 million or 24314.82% to approximately $~~940,886~~3.9 million in comparison to approximately $~~753~~940,~~708~~886 for the year ended February 28, 2022. This increase was primarily due to one-time expenses associated with completing the acquisition of our Reabold ~~2021~~subsidiary including holding both an annual meeting and a special shareholders meeting; associated public company filing expenses; impairment of certain crude oil and natural gas assets; along with an increase in the lease operating expenses related to disposal of the produced water from the Reabold wells.

Operating Loss

For the twelve months ended February 28, ~~2022~~2023, and February 28, ~~2021~~2022, we reported operating losses of approximately $~~260,779~~2.3 million and $~~348~~260,~~807~~779, respectively. The ~~decrease~~increase in the operating loss for the twelve months ended February 28, ~~2022~~2023, of approximately $~~88,028~~2.0 million was primary due to ~~increases~~one-time inexpenses associated with completing the acquisition of our Reabold subsidiary including holding both an annual meeting and a special shareholders meeting; associated public company filing expenses; impairment of certain crude oil ~~sales~~and ~~revenue~~natural ~~due~~gas assets; along with an increase in the lease operating expenses related to ~~higher~~disposal ~~energy~~of ~~prices~~the produced water from the Reabold wells.

Net Loss

Since entering the crude oil and natural gas exploration industry, we have incurred net losses with periodic negative cash flow and have depended on external financing and the sale of crude oil and natural gas assets to sustain our operations. For the twelve months ended February 28, ~~2022~~2023 we reported a net loss of approximately $~~398,450~~2.4 million in comparison to net loss of $~~512~~398,~~265~~450 for the twelve months ended February 28, ~~2021~~2022.

Management Plans to Continue as a Going Concern

We continue to implement plans to enhance ~~Daybreak’s ability~~our ability to continue as a going concern. ~~The~~Daybreak ~~Company~~ currently has a net revenue interest in 20 producing crude oil wells in ~~our~~Kern County, California (the “East Slopes ~~Project~~” ~~located~~project) and a 10 well crude oil and natural gas project in ~~Kern~~Monterey ~~County~~and Contra Costa Counties, California (the “Reabold”) project). At the Reabold project, five of these wells are currently shut-in awaiting our receiving water disposal permit approvals. The revenue from these wells has created a steady and reliable source of revenue for the Company. Our average working interest in ~~these~~the East Slopes wells is 36.6% and the average net revenue interest is 28.4%. Our average working interest in the Reabold wells is 50.0% and the average net revenue interest is 40.0%.

WeOn ~~anticipate~~May ~~revenues~~25, ~~will~~2022, ~~continue~~we tofinalized ~~increase~~the acquisition of asReabold California, LLC (“Reabold”) from a third party for 160,964,489 shares of the Company’s ~~participates~~Common inStock ~~the~~valued at ~~drilling~~$6,599,544 and cash consideration of ~~more~~$263,619. ~~wells~~The inacquisition ~~the~~of ~~East~~Reabold ~~Slopes~~was ~~Project~~approved inat ~~California.~~a ~~However~~Special ~~given~~Meeting ~~the~~of ~~current~~Shareholders ~~decline~~held on May ~~and~~20, ~~instability~~2022. inApproximately ~~hydrocarbon~~82% ~~prices~~or 51,054,229 shares of the ~~timing~~Company’s 62,510,204 issued and outstanding shares of ~~any~~the Company’s ~~drilling~~Common ~~activity~~Stock inwere ~~California~~present ~~will~~or berepresented ~~dependent~~by onproxy aat ~~sustained~~the ~~improvement in~~meeting. ~~hydrocarbon~~The ~~prices~~proposal ~~and~~for athe ~~successful~~Reabold ~~refinancing~~acquisition orwas passed ~~restructuring~~with ofover ~~our~~a ~~current~~99.6% ~~credit~~approval ~~facility~~vote.

WeAt ~~believe~~the ~~that~~same ~~our~~special ~~liquidity~~meeting ~~will~~of ~~improve~~shareholders ~~when~~held ~~there~~on isMay a20, ~~sustained~~2022, ~~improvement~~approval inwas ~~hydrocarbon~~granted ~~prices.~~to ~~Our~~Amend ~~sources~~and ofRestate ~~funds in~~ the ~~past~~Company’s ~~have~~Articles ~~included~~of ~~the~~Incorporation. ~~debt~~This orallowed ~~equity~~for ~~markets~~the ~~and~~increase in the ~~sale~~ number of ~~assets.~~authorized ~~While~~Common ~~the~~Stock ~~Company~~shares ~~does~~of ~~have~~the ~~positive~~Company ~~cash flow~~ from ~~its~~200,000,000 ~~crude~~shares ~~oil~~to ~~and natural gas properties~~500,000,000 itshares. ~~has~~The ~~not~~increase ~~yet~~in ~~established~~Common aStock ~~positive~~shares ~~cash~~gave ~~flow~~the onCompany aenough ~~company-wide~~authorized ~~basis.~~Common ItStock ~~will~~shares ~~be necessary for the Company~~ to ~~obtain~~complete ~~additional funding from~~ the ~~private~~transaction orfor ~~public debt or equity markets in~~ the ~~future~~Reabold project. ~~However~~Also, weall ~~cannot offer any assurance that we will be successful in executing~~ the ~~aforementioned~~preferred ~~plans~~stock toclassification ~~continue~~was ~~as a going concern~~eliminated.

46 In conjunction with the Company’s efforts to acquire Reabold, and as a condition of closing the acquisition, the Company was able to secure a capital raise of $2,500,000 through the issuance of shares of the Company’s Common Stock. The commitment for that capital raise was executed on May 5, 2022, and subsequently 128,125,000 shares were issued of which 3,125,000 were an incentive to the investor.

On October 20, 2021, the Company entered into an Equity Exchange Agreement (the “Exchange Agreement”) by and between Daybreak, Reabold California LLC, a California limited liability company (“Reabold”), and Gaelic Resources Ltd., a private company incorporated in the Isle of Man and the 100% owner of Reabold (“Gaelic”), pursuant to which the parties propose for (i) Daybreak to acquire 100% ownership of Reabold, in exchange for (ii) Daybreak issuing 160,964,489 shares of its common stock, par value $0.001 (“Common Stock”) to Gaelic (the “Exchange Shares”), which will result in Reabold becoming a wholly-owned subsidiary of Daybreak and Gaelic becoming the owner of the Exchange Shares and a major shareholder of Daybreak (the foregoing transaction and the transactions contemplated thereby, the “Equity Exchange”).55

AtWe aanticipate ~~special~~revenues ~~meeting~~will ofcontinue ~~shareholders~~to ~~held~~increase ~~on May 20,~~as ~~2022,~~we ~~shareholders~~participate ~~approved~~in the ~~Equity~~drilling ~~Exchange~~of ~~Agreement~~more ~~between~~wells ~~Daybreak,~~in ~~Reabold~~both ~~California,~~the ~~LLC~~East ~~(“Reabold”)~~Slopes and ~~Gaelic Resources,~~Reabold ~~Ltd.~~projects ~~(“Gaelic”)~~in California. AsOur asources ~~result~~ of ~~this~~funds ~~approval,~~in onthe ~~May~~past have ~~25,~~included ~~2022,~~ the ~~Company~~debt ~~proceeded~~or ~~with~~equity markets and the ~~acquisition~~sale of ~~Reabold~~assets. While we have experienced periodic revenue growth, which has resulted ~~and~~in ~~its~~positive ~~producing~~cash flow from its crude oil and natural gas properties, inwe ~~California.~~have ~~The~~not ~~acquisition~~yet ~~was~~established ~~completed~~a bypositive ~~Daybreak~~cash ~~issuing~~flow ~~160,964,489~~on ~~common~~a company-wide ~~stock~~basis. ~~shares~~It will be necessary for us to ~~Gaelic~~obtain additional funding from the private or public debt or equity markets in the future. However, we ~~along~~cannot ~~with~~offer any assurance that our efforts will be successful in executing the ~~customary~~aforementioned ~~closing~~plans ~~terms~~to ~~and~~continue ~~conditions~~as ~~for~~a ~~acquisitions~~going concern. Our financial statements as of ~~this~~February ~~nature~~28, 2023, and February 28, 2022 do not include any adjustments that might result from the inability to implement or execute our plans to improve our ability to continue as a going concern.

~~Also~~Off-Balance ~~during~~Sheet the special meeting of shareholders, approval was granted to Amend and Restate the Company’s Articles of Incorporation. This would allow for the increase in the number of authorized common stock shares of the Company from 200,000,000 shares to 500,000,000 shares. The increase in common stock shares will give the Company enough authorized common stock shares to complete the transaction with Reabold and Gaelic. Also, all the Preferred stock classification was eliminated.Arrangements

InAs ~~conjunction~~of ~~with~~February ~~the~~28, ~~Company’s~~2023, ~~efforts~~we todid ~~acquire~~not ~~Reabold,~~have ~~and~~any relationships aswith aunconsolidated ~~condition~~entities ofor ~~closing~~financial ~~the acquisition~~partners, ~~the~~such ~~Company~~as ~~was~~entities often referred to ~~secure~~as astructured ~~capital~~finance ~~raise~~or ofspecial $2purpose entities,~~500,000~~ which ~~through~~have been established for the ~~issuance~~purpose of ~~shares~~facilitating ofoff-balance ~~the Company’s~~sheet ~~common~~arrangements ~~stock.~~or ~~The~~other ~~commitment~~contractually ~~for~~narrow ~~that~~or ~~capital~~limited ~~raise~~purposes. As ~~was~~such, ~~executed~~we onare ~~May~~not 5,materially ~~2022,~~exposed ~~and~~to ~~subsequently~~any ~~128~~financing,~~125~~ liquidity,~~000~~ ~~shares~~market ~~were issued~~or credit risk that could arise if we had engaged in such relationships.

~~Summary~~Commitments ~~of Critical Accounting Policies~~ and ~~Estimates~~Contingencies

~~Critical~~Various ~~accounting~~lawsuits, ~~policies~~claims, threatened ~~are~~legal ~~policies~~actions, ~~that~~and ~~are both~~other ~~most~~contingencies ~~important~~arise toin the ~~portrayal~~ordinary course of ~~the~~our ~~Company’s~~business ~~financial~~activities. ~~condition~~In ~~and~~our ~~results~~opinion, ~~and~~the ~~that~~disposition of ~~require~~any ~~management’s~~such ~~most difficult,~~matters ~~subjective~~is ornot ~~complex judgments~~expected, ~~often~~individually asor ain ~~result of~~ the ~~need~~aggregate, to ~~make~~have ~~estimates~~a ~~about~~material ~~the~~adverse effect ofon ~~matters that are inherently uncertain. Management’s discussion and analysis of~~ our ~~financial condition and~~ results of operations ~~are based on our financial statements~~, ~~which have been prepared in conformity with accounting principles generally accepted in the United States of America. The~~ ~~preparation of these~~ financial ~~statements~~condition ~~requires~~or ~~management~~cash toflows. ~~make estimates~~However, ~~judgments and assumptions that affect~~ the ~~reported~~results ~~amounts~~ of ~~assets~~legal ~~and~~actions ~~liabilities~~cannot ~~and~~be ~~disclosure~~predicted ofwith ~~contingent~~certainty. ~~assets~~Therefore, ~~and~~it ~~liabilities~~is atpossible that ~~the~~our ~~date~~results of ~~the~~operations, financial ~~statements~~condition ~~and~~or ~~the~~cash ~~reported amounts~~flows ofcould ~~revenues and expenses during the reporting period. Accounting estimates are considered to~~ be ~~critical~~materially ifadversely ~~(1)~~affected ~~the~~in ~~nature~~any ~~of the~~particular ~~estimates~~period ~~and~~by ~~assumptions is material due to~~ the ~~levels of subjectivity and judgment necessary to account for highly uncertain matters~~ orunfavorable ~~the~~resolution ~~susceptibility~~ of ~~such~~one ~~matters to changes; and (2) the impact of the estimates and assumptions on financial condition~~ or ~~operating performance~~more islegal ~~material~~actions. ~~Actual results could differ from the estimates and assumptions used.~~

~~On an ongoing basis~~We, weas ~~evaluate~~an ~~our~~owner ~~estimates,~~or ~~including those~~lessee ~~related~~and tooperator ~~revenue~~of ~~recognition,~~oil ~~bad~~and gas ~~debts~~properties, ~~cancellation~~are ~~costs associated with long term commitments, investments, intangible assets, assets~~ subject to ~~disposal,~~various ~~income taxes~~federal, ~~service~~state ~~contracts, contingencies~~ and ~~litigation.~~local Welaws ~~base our estimates on historical experience~~ and onregulations ~~various~~relating ~~other assumptions that are believed~~ to bedischarge ~~reasonable~~of ~~under~~materials ~~the circumstances~~into, ~~the~~and ~~results~~ protection of, ~~which form~~ the ~~basis~~environment. ~~for~~These ~~making estimates~~laws and ~~judgments~~regulations ~~about~~may, ~~the~~among ~~carrying value of assets and liabilities that are not readily apparent from~~ other ~~sources. Estimates~~things, by ~~their~~impose ~~nature,~~liability ~~are based~~ on ~~judgment~~the ~~and~~lessee ~~available~~under ~~information.~~an ~~These~~oil ~~judgments~~ and ~~uncertainties~~gas dolease ~~affect~~ for the ~~application~~cost of ~~these critical~~pollution ~~accounting~~cleanup ~~policies.~~resulting ~~There~~from isoperations aand ~~strong~~subject ~~likelihood~~the ~~that~~lessee ~~materially~~to ~~different~~liability ~~amounts~~for ~~could~~pollution bedamages. ~~reported~~In ~~under~~some ~~different conditions~~instances, orwe ~~using~~may ~~different~~be ~~assumptions.~~directed ~~Therefore,~~to ~~actual~~suspend ~~results~~or ~~could~~cease ~~differ~~operations ~~from~~in ~~those~~the ~~estimates~~affected ~~and~~area. ~~could~~We ~~have~~maintain ainsurance ~~material~~coverage ~~impact~~that onis ~~our~~customary ~~financial statements,~~in ~~and~~the itindustry, although iswe ~~possible~~are ~~that~~not ~~such~~fully ~~changes~~insured ~~could~~against ~~occur~~all inenvironmental ~~the near term~~risks.

Sunflower Alliance v. California Department of Conservation, Geologic Energy Management Division. This case challenges the state agency’s compliance with the California Environmental Quality Act (CEQA) with respect to the PAL Reabold 072-00-0001 Project, for wastewater injection into an existing well. The Petition was filed on December 29, 2021 in the Alameda County Superior Court. The Petitioner seeks an order setting aside the state agency’s approval of a wastewater injection permit; damages are not sought in the lawsuit. On February 22, 2022, Real Party in Interest Reabold California, LLC filed a motion to transfer the case to the Contra Costa County Superior Court. On March 22, 2022, the Alameda County Superior Court ordered the case transferred to the Contra Costa County Superior Court. On August 15, 2022, the Contra Costa County Superior Court provided notice that the transfer has been completed and the case filed in that court. On December 22, 2022, the Superior Court issued an order finding CEQA deficiencies, and directing the state agency to rescind its approval of the project. On September 7, 2023, an appeal of the Superior Court order was filed in the California Court of Appeal, First Appellate District, Division 5. The California Attorney General is defending the state agency, which disputes Petitioner’s claims. At this time, it is unclear when the litigation will be resolved. If successful, the lawsuit would prevent Reabold from injecting wastewater into an existing well until any CEQA deficiencies are addressed.

Summary of Significant Accounting Policies and Estimates

Significant accounting policies are policies that are both most important to the portrayal of the Company’s financial condition and results, and that require management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain. Management’s discussion and analysis of our financial condition and results of operations are based on our financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Accounting

estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.

On an ongoing basis, we evaluate our estimates, including those related to revenue recognition, bad debts, cancellation costs associated with long term commitments, investments, intangible assets, assets subject to disposal, income taxes, service contracts, contingencies and litigation. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making estimates and judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Estimates, by their nature, are based on judgment and available information. These judgments and uncertainties do affect the application of these significant accounting policies. There is a strong likelihood that materially different amounts could be reported under different conditions or using different assumptions. Therefore, actual results could differ from those estimates and could have a material impact on our financial statements, and it is possible that such changes could occur in the near term.

Proved Crude Oil and Natural Gas Reserves

Our estimates of proved and proved developed reserves are a major component of our depletion calculation. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. Proved reserves are defined by the SEC as those quantities of crude oil and natural gas which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserve estimates if the extraction is by means not involving a well.

Although our external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in crude oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.

While the estimates of our proved reserves at February 28, ~~2022~~2023 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could differ materially from our actual results.

Successful Efforts Accounting Method

We use the successful efforts method of accounting for natural gas and oil producing activities as opposed to the alternate acceptable full cost method. We believe that net assets and net income are more conservatively measured under the successful efforts method of accounting than under the full cost method, particularly during periods of active exploration. Costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred. All exploratory dry holes and geological and geophysical costs are charged against earnings during the periods they occur. Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred. The geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. Costs to operate and maintain wells and field equipment are expensed as incurred.

Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on proved reserves. Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their proved developed reserves. Support equipment and other property and equipment are depreciated over their estimated useful lives.

Pursuant to Financial Accounting Standards Board Codification (“ASC”) Topic 360, “Property, Plant and Equipment,” we review proved oil and natural gas properties and other long-lived assets for impairment. These reviews are predicated by events and circumstances, such as downward revision of the reserve estimates or commodity prices that indicate a decline in the recoverability of the carrying value of such properties. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amounts of the properties are reduced to their estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production, future capital expenditures and a risk-adjusted discount rate. The charge is included in DD&A.

Unproved crude oil and natural gas properties that are individually significant are also periodically assessed for impairment of value. For the twelve months ended February 28, 2022, our unproved properties in Michigan and the balance of $55,978 was written off to exploration expense. An impairment loss for unproved crude oil and natural gas properties is recognized at the time of impairment by providing an impairment allowance.

On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income. Deposits and advances for services expected to be provided for exploration and development or for the acquisition of crude oil and natural gas properties are classified as long-term other assets.

Deposits and advances for services expected to be provided for exploration and development or for the acquisition of crude oil and natural gas properties are classified as long-term other assets.

Revenue Recognition

The Company recognizes revenue under ASC 606, Revenue from Contracts with Customers (“Topic 606”). Under Topic 606, revenue ~~will~~is generally be recognized upon delivery of our ~~produced~~ produced crude oil and natural gas volumes to our customers. Our customer sales contracts include ~~only~~ crude oil sales from both the East Slopes and Reabold projects and natural gas sales from some of the Reabold project. Both of these projects are located in California. Each unit of commodity product (crude oil barrel) ofor ~~commodity~~natural ~~product~~gas MMBTU) represents a separate performance obligation which is sold at variable prices, ~~determinable~~ determinable on a monthly basis. The pricing provisions of our crude oil and natural gas contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, product quality and prevailing supply and demand conditions in the geographic areas in which we operate. We ~~will~~ allocate the transaction price to each performance obligation and recognize revenue upon delivery of the commodity product when the customer obtains control. Control of our produced crude oil volumes passes to our customers when the oil is measured by a trucking oil ticket. The Company has no control over the crude oil after this point and the measurement at this point dictates the amount on which the customer's payment is based. Control of our produced natural gas volumes passes to our customers when the natural gas is measured at the purchaser’s gas line meter. The Company has no control over the natural gas after this point and the measurement at this point dictates the amount on which the customer’s payment is based. Our crude oil and natural gas revenue streams include volumes burdened by royalty and other joint owner working interests. Our revenues are recorded and presented on our financial statements net of the royalty and other joint owner working interests. Our revenue stream does not include any payments for services or ancillary items other than for the sale of crude oil and natural gas. We record revenue in the month our crude oil and natural gas production is delivered to the purchaser.

The Company has no control over the crude oil after this point and the measurement at this point dictates the amount on which the customer's payment is based. Our crude oil revenue stream includes volumes burdened by royalty and other joint owner working interests. Our revenues are recorded and presented on our financial statements net of the royalty and other joint owner working interests. Our revenue stream does not include any payments for services or ancillary items other than sale of crude oil. We record revenue in the month our crude oil production is delivered to the purchaser.

Suspended Well Costs

We account for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities – Oil and Gas” (“ASC 932”). ASC 932 states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the economic and operating feasibility of the well. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management's evaluation of capitalized exploratory well costs.

In addition, ASC 932 requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year, designating the number of wells the aging is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation.

Share Based Payments

Share based awards are accounted for under FASB Topic ASC 718, “Compensation-Stock Compensation” (“ASC 718”). ASC 718 requires compensation costs for all share-based payments granted to be based on the grant date fair value. The value of the portion of the award that is ultimately expected to vest is recognized as expense ratably over the requisite service periods.

See Note 3 - Summary of Significant Accounting Policies in the Company's financial statements for a full discussion of our significant accounting policies.

4959

ITEM 7A. 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.

5060

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Daybreak Oil and Gas, Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of of Daybreak Oil and Gas, Inc. (the “Company”) as of February 28, ~~2022~~2023 and February 28, ~~2021~~2022, and the related statements of operations, changes in stockholders’ equity (deficit), and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of February 28, ~~2022~~2023 and February 28, ~~2021~~2022, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Going Concern Matter

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency that raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

Critical audit matters, are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.

/s/ MaloneBailey, LLP

www.malonebailey.com

We have served as the Company's auditor since 2006.

Houston, Texas

~~June~~January 1523, ~~2022~~ 2024

5161

DAYBREAK OIL AND GAS, INC.

Balance Sheets

As of February 28, ~~2022~~2023 and February 28, ~~2021~~2023

	As of February 28, 2022			As of February 28, 2021
	As of February 28, 2023			As of February 28, 2022
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	~~139~~299,~~573~~410		$	33139,~~528~~573
Restricted cash		275,000			—
Accounts receivable:
Crude oil sales		~~117~~131,~~727~~510			~~108~~117,~~993~~727
Joint interest participants		85353,~~339~~009			7985,~~411~~339
Prepaid expenses and other current assets		7495,~~012~~034			6174,~~307~~012
Total current assets		~~416~~1,~~651~~153,963			~~283~~416,~~239~~651
OIL AND GAS PROPERTIES, successful efforts method, net
Proved properties		536,032			556,456
Proved developed properties		5,126,200			536,032
Unproved properties		—			55,978
Prepaid drilling costs		16,452			16,452
PREPAID DRILLING COSTS		16,452			16,452
Vehicles and Equipment, net		3,416			6,569
Vehicles and Equipment, net		6,569			—
Goodwill – crude oil and natural gas properties		1,415,361			—
Total long-term assets		~~559~~6,~~053~~561,429			~~628~~559,~~886~~053
Total assets	$	~~975~~7,~~704~~715,392		$	~~912~~975,~~125~~704
LIABILITIES AND STOCKHOLDERS’ DEFICIT
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	12,~~649~~129,~~119~~208		$	1,~~710~~649,~~922~~119
Accounts payable - related parties		49,228			988,966
Accounts payable – related parties		21,937			49,228
Accrued interest		176,229			123,659
Revenue payable		192,341			—
Accrued interest		185,508			176,229
Accrued expenses		250,000			—
Note payable		120,000			120,000
Note payable - related party, current, net of unamortized discount of $729 and $728, respectively		8,100			7,870
Note payable – related party, current, net of unamortized discount of $728 and $729, respectively		8,337			8,100
Convertible Note payable, related party		~~200,000~~—			—200,000
12% Note payable		~~315~~290,000			315,000
12% Note payable - related party		—			250,000
Line of credit		—			808,182
Line of credit		808,182			840,904
Production revenue payable, current, net of unamortized discount		56,915			78,877
Production revenue payable, current, net of unamortized discount		78,877			111,753
Total current liabilities		3,254,246			3,404,735
Total current liabilities		3,404,735			4,469,074
LONG TERM LIABILITIES:
Note payable - related party, net of current portion and net of unamortized discount of $9,350 and $10,080, respectively		127,360			135,460
Note payable – related party, net of current portion and net of unamortized discount of $8,620 and $9,350, respectively		119,023			127,360
Production revenue payable, net of current portion and net of unamortized discount		~~738~~816,~~248~~366			1738,~~391,669~~248
Asset retirement obligation		52315,~~565~~509			3352,~~062~~565
Total long-term liabilities		~~918~~1,~~173~~250,898			1918,~~560,191~~173
Total liabilities		4,~~322~~505,~~908~~144			64,~~029~~322,~~265~~908
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ DEFICIT:
STOCKHOLDERS’ EQUITY (DEFICIT):
Preferred stock - 10,000,000 shares authorized, $0.001 par value;		—			—
Common Stock- 500,000,000 shares authorized; $0.001 par value, 384,734,902 and 67,802,273 shares issued and outstanding, respectively		384,734			67,802
Series A Convertible Preferred stock - 2,400,000 shares authorized, $0.001 par value, 6% cumulative dividends; 709,568 shares issued and outstanding		—			710
Additional paid-in capital		34,785,207			26,115,450
Common stock- 200,000,000 shares authorized; $0.001 par value, 67,802,273 and 60,491,122 shares issued and outstanding, respectively		67,802			60,491
Accumulated deficit		(31,959,693	)		(29,530,456	)
Additional paid-in capital		26,115,450			24,250,556
Total stockholders’ equity (deficit)		3,210,248			(3,347,204	)
Accumulated deficit		(29,530,456	)		(29,428,897	)
Total liabilities and stockholders’ equity (deficit)	$	7,715,392		$	975,704
Total stockholders’ deficit		(3,347,204	)		(5,117,140	)
Total liabilities and stockholders' deficit	$	975,704		$	912,125

~~Series~~The Aaccompanying ~~Convertible~~notes ~~Preferred~~are ~~Stock~~ an integral part of these financial statements.

~~The accompanying notes are an integral part of these financial statements~~62

DAYBREAK OIL AND GAS, INC.

Statements of Operations

For the Twelve Months Ended February 28, ~~2022~~2023 and February 28, ~~2021~~2022

	Twelve Months Ended February 28, 2022			Twelve Months Ended February 28, 2021
	Twelve Months Ended February 28, 2023			Twelve Months Ended February 28, 2022
REVENUE:
Crude oil sales	$	~~680~~1,~~107~~533,260		$	~~404~~680,~~901~~107
Natural gas sales		80,026			—
Total crude oil and natural gas sales	$	1,613,286		$	680,107
OPERATING EXPENSES:
Production		~~231~~1,~~275~~103,825			~~187~~231,~~858~~275
Exploration and drilling		~~56,213~~—			8356,213
Depreciation, depletion and amortization		49504,~~590~~118			6049,~~063~~590
General and administrative		603,808			505,704
Impairment of crude oil and natural gas properties		711,873			—
Total operating expenses		940,886			753,708
Transaction expenses		573,472			—
OPERATING LOSS		(260,779	)		(348,807	)
General and administrative		1,004,011			603,808
Total operating expenses		3,897,299			940,886
OPERATING LOSS		(2,284,013	)		(260,779	)
OTHER INCOME (EXPENSE):
Interest expense, net		(~~220~~145,~~085~~224	)		(~~237~~220,~~813~~085	)
Gain on asset disposal		~~9,614~~—			—9,614
Gain on debt forgiveness – SBA paycheck protection program (PPP) loan		~~72,800~~—			7472,~~355~~800
Total other expenses		(~~137~~145,~~671~~224	)		(~~163~~137,~~458~~671	)
NET LOSS		(398,450	)		(512,265	)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(2,429,237	)	$	(398,450	)
Cumulative convertible preferred stock dividend requirement		—			(127,714	)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(398,450	)	$	(639,979	)
NET LOSS PER COMMON SHARE
Basic and diluted	$	(0.01	)	$	(0.01	)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic and diluted		61312,~~548~~312,~~414~~114			5761,~~916~~548,~~382~~414

~~The~~Crude ~~accompanying~~Oil ~~notes are an integral part of these financial statements~~Sales

53Natural Gas Sales

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

DAYBREAK OIL AND GAS, INC.

Statements of Changes in Stockholders' Equity (Deficit)

For the Twelve Months Ended February 28, ~~2022~~2023 and February 28, ~~2021~~2022

	Series A
		Series A Convertible																Additional
	Convertible																Additional
		Preferred Stock								Common Stock								Paid-In				Accumulated
	Preferred Stock								Common Stock								Paid-In				Accumulated
		Shares				Amount				Shares				Amount				Capital				Deficit				Total
	Shares				Amount				Shares				Amount				Capital				Deficit				Total
BALANCE, FEBRUARY 28, 2021			709,568			$	710				60,491,122			$	60,491			$	24,250,556			$	(29,428,897	)		$	(5,117,140	)
BALANCE, FEBRUARY 29, 2020		709,568			$	710				53,532,364			$	53,532			$	24,223,783			$	(28,916,632	)		$	(4,638,607	)
Issuance of Common Stock for:
Issuance of common stock for:
Conversion of accrued employee salaries			—				—				1,397,880				1,398				627,649				52,530				681,577
Convertible note payable – related party		—			$	—				6,958,758			$	6,959			$	20,876			$	—			$	27,835
Conversion of accrued director fees			—				—				317,708				318				142,651				—				142,969
Recognition of warrants for:
Conversion of 12% Note principal and interest – related party			—				—				1,144,415				1,144				513,842				—				514,986
Investor relations services		—			$	—				—			$	—			$	5,897			$	—			$	5,897
Conversion of production revenue program principal – related party			—				—				1,222,444				1,222				548,878				—				550,100
Net Loss		—			$	—				—			$	—			$	—			$	(512,265	)		$	(512,265	)
Conversion of Series A preferred stock			(709,568	)			(710	)			2,128,704				2,129				(1,419	)			—				—
BALANCE, FEBRUARY 28, 2021		709,568			$	710				60,491,122			$	60,491			$	24,250,556			$	(29,428,897	)		$	(5,117,140	)
Conversion of Series A accumulated dividend			—				—				1,100,000				1,100				28,380				(29,480	)			—
Issuance of common stock for:
Recognition of warrants for:
Conversion of accrued employee salaries										1,397,880				1,398				627,649				52,530				681,577
Investor relations services			—				—				—				—				4,913				—				4,913
Conversion of accrued director fees										317,708				318				142,651								142,969
Debt forgiveness accrued salary - related party			—				—				—				—				—				53,125				53,125
Conversion of 12% Note principal and interest – related party										1,144,415				1,144				513,842								514,986
Debt forgiveness production revenue program interest – related party			—				—				—				—				—				232,170				232,170
Conversion of production revenue program principal – related party										1,222,444				1,222				548,878								550,100
Settlement of receivables and payables – related party			—				—				—				—				—				(11,454	)			(11,454	)
Conversion of Series A preferred stock		(709,568	)			(710	)			2,128,704				2,129				(1,419	)							—
Net Loss			—				—				—				—				—				(398,450	)			(398,450	)
Conversion of Series A accumulated dividend										1,100,000				1,100				28,380				(29,480	)			—
BALANCE, FEBRUARY 28, 2022			—			$	—				67,802,273			$	67,802			$	26,115,450			$	(29,530,456	)		$	(3,347,204	)
Recognition of warrants for:
Issuance of Common Stock for:
Investor relations services																		4,913								4,913
Conversion of 12% Note principal and interest			—				—				78,934				79				35,441				—				35,520
Debt forgiveness accrued salary - related party																						53,125				53,125
Conversion of convertible note			—				—				27,764,706				27,765				208,235				—				236,000
Debt forgiveness production revenue program interest – related party																						232,170				232,170
Acquisition of crude oil and natural gas properties			—				—				160,964,489				160,964				6,438,580				—				6,599,544
Settlement of receivables and payables – related party																						(11,454	)			(11,454
Sale of common stock			—				—				125,000,000				125,000				1,862,500				—				1,987,500
Net Loss																						(398,450	)			(398,450	)
Shares issued for financing fees			—				—				3,125,000				3,125				125,000				—				128,125
BALANCE, FEBRUARY 28, 2022		—			$	—				67,802,273			$	67,802			$	26,115,450			$	(29,530,456	)		$	(3,347,204	)
Adjustment to common stock			—				—				(500	)			(1	)			1				—				—
			—
Net Loss			—				—				—				—				—				(2,429,237	)			(2,429,237	)
BALANCE, FEBRUARY 28, 2023			—			$	—				384,734,902			$	384,734			$	34,785,207			$	(31,959,693	)		$	3,210,248

The accompanying notes are an integral part of these financial statements

Common Stock

Additional Paid-In Capital

Accumulated Deficit

54Series A Convertible Preferred Stock

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

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows

For the Twelve Months Ended February 28, ~~2022~~2023 and February 28, ~~2021~~2022

	Twelve Months Ended
	February 28, 2022			February 28, 2021
	February 28, 2023			February 28, 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(~~398~~2,~~450~~429,237	)	$	(~~512~~398,~~265~~450	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Gain on forgiveness of PPP 2nd draw and 1st draw loans, respectively		(72,800	)		(74,355	)
Common stock shares issued as an incentive		128,125			—
Depreciation, depletion and amortization		49,590			60,063
Gain on forgiveness of PPP 2nd draw		—			(72,800	)
Impairment of unproved crude oil properties		55,978			—
Depreciation, depletion and amortization		504,088			49,590
Amortization of debt discount		96,703			115,272
Impairment of proved crude oil properties		711,873			—
Operating lease expense in conjunction with right of use asset		—			5,857
Impairment of unproved crude oil properties		—			55,978
Warrants issued for investor relations services		4,913			5,897
Amortization of debt discount		56,885			96,703
Warrants issued for investor relations services		—			4,913
Changes in assets and liabilities:
Accounts receivable – crude oil and natural gas sales		(8235,~~734~~034	)		(528,~~083~~734	)
Accounts receivable – joint interest participants		(5,928	)		(41,045	)
Accounts receivable - joint interest participants		(267,670	)		(5,928	)
Prepaid expenses and other current assets		68(21,~~449~~022	)		5468,~~896~~449
Accounts payable and other accrued liabilities		52784,~~922~~819			~~152~~52,~~816~~922
Accounts payable – related parties		64,153			69,078
Accounts payable - related parties		(27,291	)		64,153
Operating lease liability change in conjunction with right of use asset		—			(5,857	)
Accrued interest		(9,279	)		79,848
Accrued interest		79,848			78,200
Net cash used in operating activities		(315,117	)		(13,356	)
Net cash used in operating activities		(13,356	)		(143,526	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to crude oil and natural gas properties		(6417,~~772~~248	)		—(6,772	)
Purchase of fixed asset (used pickup truck)		(9,460	)		—
Acquisition of crude oil and natural gas properties		31,088			—
Net cash used in investing activities		(16,232	)		—
Purchase of fixed asset (used pickup truck)		—			(9,460	)
Net cash used in investing activities		(386,160	)		(16,232	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments to line of credit		(60808,~~000~~182	)		(60,000	)
Proceeds from convertible note payable		200,000			—
Proceeds from sale of Common Stock		1,987,500			—
Insurance financing repayments		(68,568	)		(74,553	)
Proceeds from convertible note payable		—			200,000
Proceeds from note payable – related party		—			144,619
Insurance financing repayments		(34,375	)		(68,568	)
Payments to note payable – related party		(8,~~599~~829	)		(18,~~410~~599	)
Proceeds from SBA PPP 2nd draw loan and 1st draw loans, respectively		~~72,800~~—			7472,~~355~~800
Net cash provided by financing activities		~~135~~1,~~633~~136,114			83135,~~011~~633
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		~~106~~434,~~045~~837			~~(60~~106,~~515~~045	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		33139,~~528~~573			9433,~~043~~528
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	~~139~~574,~~573~~410		$	33139,~~528~~573
CASH PAID FOR:
Interest	$	1433,~~446~~431		$	1514,~~106~~446
Income taxes	$	—		$	—

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

5565

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows (continued)

For the Twelve Months Ended February 28, ~~2022~~2023 and February 28, ~~2021~~2022

	Twelve Months Ended
	February 28, 2022		February 28, 2021
	February 28, 2023		February 28, 2022
SUPPLEMENTAL CASH FLOW INFORMATION:
ARO asset and liability increase due to changes in estimates	$	10,929	$	1,863
Common stock issued for conversion of 12% Subordinated Note	$	35,520	$	—
Unpaid additions to crude oil and natural gas properties	$	—	$	11,871
Common stock issued for conversion of convertible Note	$	236,000	$	—
Non-cash addition to line of credit due to monthly interest	$	27,278	$	28,503
Common stock issued for acquisition of crude oil and natural gas property	$	6,599,544	$	—
Financing of insurance premiums	$	81,154	$	65,088
Goodwill from acquisition of O&G properties	$	1,415,361	$	—
Forgiveness of production revenue payable interest	$	232,170	$	—
ARO asset and liability increase due to acquisition of crude oil and natural gas properties	$	79,622	$	—
Settlement of accrued employee salaries credited to common stock, APIC and accumulated deficit	$	681,577	$	—
ARO asset and liability increase due to changes in estimates	$	159,477	$	10,929
Settlement of accrued director fees credited to common stock and APIC	$	142,969	$	—
Non-cash addition to line of credit due to monthly interest	$	—	$	27,278
Settlement of 12% Note - related party credited to common stock and APIC	$	514,986	$	—
Financing of insurance premiums	$	—	$	81,154
Settlement of production revenue program - related party credited to additional paid in capital	$	550,100	$	—
Forgiveness of production revenue payable interest	$	—	$	232,170
Settlement of Series A accumulated dividend credited to additional paid in capital	$	28,380	$	—
Settlement of accrued employee salaries credited to common stock, APIC and accumulated deficit	$	—	$	681,577
Common stock issued for related party debt	$	—	$	27,835
Settlement of accrued director fees credited to common stock and APIC	$	—	$	142,969
Common stock issued for conversion of Series A preferred stock	$	710	$	—
Settlement of 12% Note – related party credited to common stock and APIC	$	—	$	514,986
Common stock issued for Series A preferred accumulated dividend	$	1,100	$	—
Settlement of production revenue program – related party credited to paid in capital	$	—	$	550,100
Debt forgiveness of related party accrued gross salary and employer payroll taxes	$	53,125	$	—
Settlement of Series A accumulated dividend credited to additional paid in capital	$	—	$	28,380
Settlement of related party receivables and payables	$	11,454	$	—
Common stock issued for conversion of Series A preferred stock	$	—	$	710
Reclassification of related party accounts payable to accounts payable	$	66,719	$	—
Common stock issued for Series A preferred accumulated dividend	$	—	$	1,100
Debt forgiveness of related party accrued gross salary and employer payroll taxes	$	—	$	53,125
Settlement of related party receivables and payables	$	—	$	11,454
Reclassification of related party accounts payable to accounts payable	$	—	$	66,719

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

5666

DAYBREAK OIL AND GAS, INC.

NOTES TO FINANCIAL STATEMENTS

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION:

Originally incorporated as Daybreak Uranium, Inc., (“Daybreak Uranium”) on March 11, 1955, under the laws of the State of Washington, Daybreak Uranium was organized to explore for, acquire, and develop mineral properties in the Western United States. In August 1955, the assets of Morning Sun Uranium, Inc. were acquired by Daybreak Uranium. In May 1964, Daybreak Uranium changed its name to Daybreak Mines, Inc. ~~During~~In March 2005, management of the ~~Company~~ Company decided to enter the crude oil and natural gas exploration, development and production industry. On October 25, 2005, the Company’s ~~shareholders~~ shareholders approved a name change from Daybreak Mines, Inc. to Daybreak Oil and Gas, Inc. (referred to herein as “Daybreak” or the “Company”) to better reflect the business of the Company.

All of the Company’s crude oil and natural gas production is sold under contracts that are market-sensitive. Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, crude oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. These factors include the level of global demand for petroleum products, foreign supply of crude oil and natural gas, the establishment of and compliance with production quotas by crude oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic, crude oil disputes between OPEC members; and national ~~and~~or international pandemics like the coronavirus outbreak.

NOTE 2 — GOING CONCERN:

Financial Condition

Daybreak’s financial statements for the twelve months ended February 28, ~~2022~~2023, and February 28, ~~2021~~2022 have been prepared on a going concern basis, which contemplates the realization of of assets and the settlement of liabilities in the normal course of business. Daybreak has incurred net losses since inception and has ~~accumulated~~ accumulated a deficit of approximately $2931.596 million and a working capital deficit of approximately $32.01 million, which raises substantial doubt about the Company’s ability to continue as a going concern.

Management Plans to Continue as a Going Concern

~~Revenue~~ The Company continues to implement plans to enhance its ability to continue as a going concern. Daybreak currently has a net revenue interest in 20 producing crude oil wells in Kern County, California (the “East Slopes” project) and a 10 well crude oil and natural gas project in Monterey and Contra Costa Counties, California (the “Reabold” project). At the Reabold project, five of these wells are currently shut-in awaiting our receiving water disposal permit approvals. The revenue from these wells has created a steady and reliable source of revenue. The Company’s average working interest in the East Slopes project is 36.6% and the average net revenue interest is 28.4%. In the Reabold project, the Company has a 50.0% working interest and a net revenue interest of 40%.

~~The~~On ~~Company~~May ~~continues~~25, to2022, ~~implement~~the ~~plans~~Company tofinalized ~~enhance~~the ~~its~~acquisition ~~ability~~of toReabold ~~continue~~California, asLLC (“Reabold”) from a ~~going~~third ~~concern.~~party ~~Daybreak~~for ~~currently~~160,964,489 shares ~~has~~of athe ~~net~~Company’s ~~revenue~~Common ~~interest~~Stock invalued 20at ~~producing~~$6,599,544 and ~~crude~~cash ~~oil~~consideration ~~wells~~of in$263,619. ~~its~~The ~~East Slopes~~acquisition ~~Project~~of ~~located~~Reabold inwas ~~Kern~~approved ~~County,~~at ~~California~~a ~~(the~~Special ~~“East~~Meeting ~~Slopes~~of ~~Project”)~~Shareholders held on May 20, 2022. ~~The~~Approximately 82% ~~revenue~~or ~~from~~51,054,229 ~~these~~shares ~~wells~~of ~~has~~the ~~created~~Company’s ~~a steady~~62,510,204 issued and ~~reliable~~outstanding ~~source~~shares of ~~revenue.~~the ~~The~~ Company’s ~~average~~Common ~~working~~Stock ~~interest~~were present inor ~~these~~represented ~~wells~~by isproxy 36at the meeting.6% ~~and~~The proposal for the ~~average~~Reabold ~~net~~acquisition ~~revenue interest~~was ispassed ~~28.4%~~with ~~for~~over ~~these~~a ~~same~~99.6% ~~wells~~approval vote.

InAt ~~December 2019,~~ the ~~2019~~special ~~novel~~shareholders ~~coronavirus~~meeting ~~(“COVID-19") surfaced~~held ~~in Wuhan, China. The World Health Organization declared a global emergency~~ on ~~January~~May 3020, ~~2020, with respect to the outbreak~~ ~~and several countries~~2022, ~~including~~approval ~~the~~was ~~United~~also ~~States,~~granted ~~Japan,~~to ~~parts~~Amend ~~of Europe~~ and ~~Australia~~Restate ~~have~~the ~~initiated~~Company’s ~~travel~~Articles ~~restrictions to and from China. The impacts~~ of ~~the outbreak are unknown and rapidly evolving~~Incorporation. This ~~widespread~~allowed ~~health~~for ~~crisis and~~ the ~~governmental~~increase ~~restrictions~~in ~~associated~~the ~~with~~number ~~it,~~of ~~have~~authorized ~~adversely~~Common ~~affected~~Stock ~~demand~~shares ~~for~~of ~~crude~~the ~~oil,~~Company ~~depressed~~from ~~crude oil prices~~200,000,000 ~~and~~shares ~~affected our ability~~ to ~~access~~500,000,000 ~~capital~~shares. ~~These~~The ~~factors,~~ increase in ~~turn,~~Common ~~have~~Stock ~~had~~shares allowed athe ~~negative~~Company ~~impact~~to onhave ~~our~~enough ~~operations,~~authorized ~~and~~Common ~~financial~~Stock ~~condition~~shares asto ~~evidenced~~complete by the ~~unprecedented~~transaction ~~decline~~for inthe ~~crude~~Reabold ~~oil prices~~project. ~~and~~Also, ~~our~~all ~~revenues~~the ~~during~~Preferred stock ~~this~~classification ~~same~~was ~~time period~~eliminated.

OnIn ~~March~~conjunction ~~27,~~with ~~2020,~~ the ~~Coronavirus~~Company’s ~~Aid,~~efforts ~~Relief~~to acquire Reabold, and ~~Economic~~ ~~Security Act commonly referred to~~ as ~~the~~a ~~CARES~~condition ~~Act became law. One component~~ of ~~the~~closing ~~CARES Act was~~ the ~~paycheck~~acquisition, ~~protection program (“PPP”) which provides small business with~~ the ~~resources needed to maintain their payroll and cover applicable overhead. The PPP is implemented by the Small Business Administration (“SBA”) with support from the Department of the Treasury. The~~ Company ~~applied~~ ~~for, and~~ was ~~accepted~~ to ~~participate~~secure ina ~~this~~capital ~~program.~~raise Onof ~~May 11, 2020, the Company received funding for approximately~~ $742,~~355. In February 2021~~500,000 ~~the~~through ~~Company applied for full loan forgiveness and later that month was notified by our lender that~~ the ~~SBA had forgiven~~issuance ~~our~~of ~~original~~shares ~~loan~~of ~~in full. On March 15, 2021,~~ the Company’s ~~received~~Common ~~$72,800 in funding through the SBA second draw paycheck protection program~~Stock. ~~Second~~The ~~Draw~~commitment ~~PPP~~for ~~loans~~that ~~can~~capital beraise ~~used~~was toexecuted ~~help~~on ~~fund~~May ~~payroll costs~~5, ~~including benefits. Funds can also be used to pay for mortgage interest~~2022, ~~rent~~ and ~~utilities~~subsequently ~~over a 24 week period. The Company applied for~~128,125,000 ~~full~~shares ~~loan~~were ~~forgiveness~~issued onof ~~this~~which ~~PPP second draw loan and on October 6~~3, ~~2021~~125,000 ~~and~~were ~~the~~an ~~SBA~~incentive ~~notified~~to ~~our lender that~~ the ~~loan was forgiven and repaid the loan in full~~investor.

5767

OnThe ~~October~~Company ~~20,~~anticipates ~~2021,~~revenue will continue to increase as the Company ~~entered~~participates ~~into~~in anthe ~~Equity Exchange~~drilling ~~Agreement~~of ~~(the~~more ~~“Exchange~~wells ~~Agreement”)~~in bythe ~~and~~East ~~between~~Slopes ~~Daybreak,~~and Reabold ~~California~~projects ~~LLC,~~in a California. ~~limited~~Daybreak’s ~~liability~~sources ~~company~~of ~~(“Reabold”),~~funds ~~and~~in ~~Gaelic~~the ~~Resources~~past ~~Ltd.,~~have aincluded ~~private~~the ~~company~~debt ~~incorporated~~or inequity markets and the ~~Isle~~sale of ~~Man~~assets. ~~and~~While the ~~100%~~Company ~~owner~~has ofexperienced ~~Reabold~~periodic revenue ~~(“Gaelic”)~~growth, ~~pursuant~~which tohas ~~which~~resulted ~~the~~in ~~parties~~positive ~~propose~~cash ~~for~~flow ~~(i)~~from ~~Daybreak~~its tocrude ~~acquire~~oil ~~100%~~and ~~ownership~~natural ofgas ~~Reabold~~properties, init ~~exchange~~has ~~for~~not ~~(ii) Daybreak~~yet ~~issuing~~established ~~160,964,489~~a ~~shares~~positive cash offlow ~~its~~on ~~common~~a ~~stock,~~company-wide ~~par value $0~~basis.~~001~~ ~~(“Common~~It ~~Stock”)~~will tobe ~~Gaelic~~necessary (for the ~~“Exchange Shares”),~~Company ~~which~~to ~~will~~obtain ~~result~~additional infunding ~~Reabold~~from ~~becoming~~the aprivate ~~wholly-owned~~or ~~subsidiary~~public ofdebt ~~Daybreak~~or equity ~~and~~markets ~~Gaelic~~in ~~becoming~~ the ~~owner~~future. ofHowever, the ~~Exchange Shares~~Company ~~and~~cannot aoffer ~~major~~any ~~shareholder~~assurance ofthat ~~Daybreak~~it ~~(the~~will ~~foregoing~~be ~~transaction~~successful ~~and~~in executing the ~~transactions~~aforementioned plans ~~contemplated~~to ~~thereby,~~continue ~~the~~as ~~“Equity~~a ~~Exchange”)~~going concern.

AtDaybreak’s afinancial ~~special~~statements ~~meeting~~as of ~~shareholders held on May 20,~~February ~~2022~~28, ~~shareholders approved the Equity Exchange Agreement between Daybreak~~2023, ~~Reabold California, LLC (“Reabold”)~~ and ~~Gaelic Resources,~~February ~~Ltd. (“Gaelic”). As a result of this approval~~28, ~~on May 25,~~ 2022, ~~the~~do ~~Company~~not ~~proceeded~~include ~~with~~any ~~the~~adjustments ~~acquisition~~that ofmight ~~Reabold and~~result ~~its~~from ~~producing~~the ~~crude~~inability ~~oil~~to ~~and~~implement ~~natural~~or ~~gas~~execute ~~properties in California. The acquisition was completed by~~ Daybreak ~~issuing 160,964,489 common~~’s ~~stock~~plans ~~shares~~ to ~~Gaelic,~~improve ~~along~~our ~~with~~ability ~~the~~to ~~customary~~continue ~~closing~~as ~~terms~~a ~~and~~going ~~conditions for acquisitions of this nature~~concern.

Also during the special meeting of shareholders, approval was granted to Amend and Restate the Company’s Articles of Incorporation. This would allow for the increase in the number of authorized common stock shares of the Company from 200,000,000 shares to 500,000,000 shares. The increase in common stock shares will give the Company enough authorized common stock shares to complete the transaction with Reabold and Gaelic. Also, all the Preferred stock classification was eliminated.

In conjunction with the Company’s efforts to acquire Reabold, and as a condition of closing the acquisition, the Company was to secure a capital raise of $2,500,000 through the issuance of shares of the Company’s common stock. The commitment for that capital raise was executed on May 5, 2022, and subsequently 128,125,000 shares were issued.

As of February 28, 2022, all of the conditions for the closing of the Exchange Agreement had not yet been met. The Company was continuing to work towards satisfying all of the Exchange Agreement conditions including having certain conditions of the Exchange Agreement approved by the Company’s shareholders. Please refer to Note 16 – Subsequent Events in the Notes to these financial statements.

The Company anticipates revenue will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project in California. 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 periodic revenue growth, which has resulted in positive cash flow from its crude oil and natural gas properties, it has not yet established a positive cash flow on a company-wide basis. It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future. However, the Company cannot offer any assurance that it will be successful in executing the aforementioned plans to continue as a going concern.

Daybreak’s financial statements as of February 28, 2022 and February 28, 2021 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.

NOTE 3 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Use of Estimates and Assumptions

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 reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows:

The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any impairment of proved properties;

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

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

Estimates regarding the timing and cost of future abandonment obligations; and,

Estimates regarding projected cash flows used in determining the production payable discount.

Cash and Cash Equivalents

Cash equivalents include demand deposits with banks and all highly liquid investments with original maturities of three months or less. The Company has in the past maintained balances in financial institutions where deposits may exceed the federally insured deposit limit of $250,000. The Company has not experienced any losses from such accounts and does not believe it is exposed to any significant credit risk on cash.

Restricted Cash

Restricted cash balances include amounts posted with regulatory authorities for reclamation bonds related to the Company’s crude oil and natural gas operations in California.

Accounts Receivable

The Company routinely assesses the recoverability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Actual write-offs may exceed the recorded allowance. Substantially all of the Company’s trade accounts receivable result from crude oil and natural gas sales in California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors. Trade accounts receivable are generally not collateralized. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, ~~2022~~2023 and February 28, ~~2021~~2022.

58 68

Crude Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for crude oil and natural gas property acquisition, exploration, development, and production activities. Costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred. Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred. In addition, the geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. Costs to operate and maintain wells and field equipment are expensed as incurred.

Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on estimated proved reserves. Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their estimated proved developed reserves. Support equipment and other property and equipment are depreciated over their estimated useful lives.

Pursuant to the provisions of Financial Accounting Standards Codification (“ASC”) Topic 360, “Property, Plant and Equipment” the Company reviews proved crude oil and natural gas properties and other long-lived assets for impairment. These reviews are predicated by events and circumstances, such as downward revision of the reserve estimates or commodity prices that indicate a decline in the recoverability of the carrying value of such properties. The Company estimates the future cash flows expected in connection with the properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amounts of the properties are reduced to their estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production, future capital expenditures and a risk-adjusted discount rate. These estimates of future product prices may differ from current market prices of crude oil and natural gas. Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s crude oil and natural gas properties in subsequent periods. Unproved crude oil and natural gas properties that are individually significant are also periodically assessed for impairment of value. An impairment loss for unproved crude oil and natural gas properties is recognized at the time of impairment by providing an impairment allowance.

For the twelve months ended February 28, ~~2022~~2023, the Company recognized an impairment charge of ~~unproved~~$711,873 ~~properties~~for inthe ~~Michigan~~write ~~and~~down ~~wrote~~of ~~down~~proven undeveloped reserves in both the ~~entire~~East ~~$55,978~~Slopes ~~balance~~and inthe Reabold ~~Michigan~~projects. ~~For~~Under the ~~twelve months~~guidance ~~ended~~provided ~~February~~by 28Rule 4-10(a)(31)(ii) of Regulation S-X, ~~2021~~we ~~the~~have ~~Company~~no ~~did~~reserves ~~not~~that ~~recognize~~qualify to be considered proved undeveloped reserves since any ~~impairment~~proved ofundeveloped ~~its~~reserves ~~properties~~that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years.

For the twelve months ended February 28, 2022, the Company recognized an impairment of unproved properties in Michigan and wrote down the entire $55,978 balance in Michigan.

On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income.

Property and Equipment

Vehicles

Machinery and Equipment

Fixed assets are stated at cost. Depreciation on vehicles is provided using the straight-line method over expected useful lives of three years. Depreciation on machinery and equipment is provided using the straight-line method over expected useful life of three years. Depreciation of production facilities and natural gas pipelines are recorded using the unit-of-production method based on estimated reserves.

Long Lived Assets

The Company reviews the carrying value of long-lived assets and identifiable intangibles whenever events or circumstances indicate that the carrying amounts of such assets may not be fully recoverable. The Company evaluates the recoverability of long-lived assets by measuring the carrying amounts of the assets against the estimated undiscounted cash flows associated with these assets. If this evaluation indicates that the future undiscounted cash flows of certain long-lived assets are not sufficient to recover the assets' carrying value, the assets are adjusted to their fair values (based upon discounted cash flows) through recognition of impairment.

Fair Value Measurements

ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. To increase consistency and comparability in fair value measurements and related disclosures, ASC Topic 820 also established a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. We are required to maximize the use of observable inputs and minimize the use of observable inputs when measuring fair value. The hierarchy describes three levels of inputs that may be used to measure fair value:

Level 1 – Quoted prices in active markets for identical assets and liabilities.

Level 2 - Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3 – Unobservable inputs that are supported by little or no market activity and that are financial instruments whose are determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant judgment or estimation.

ASC Topic 820 requires that an entity give consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value. Asset acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying market and income approached using level 3 inputs.

Fair Value of Financial Instruments

The Company’s carrying value of short-term financial ~~instruments~~ instruments including cash, restricted cash, receivables, prepaid expenses, accounts payable, and other accrued liabilities, short-term liabilities and ~~the line of~~ credit lines approximated their fair values due to the relatively short period to maturity for these instruments. The long-term notes payable approximates fair value since the related rates of interest approximate current market rates.

59 The Company’s financial instruments consist of cash, restricted cash, accounts receivable, accounts payable, notes payable and loans. The carrying amount of these financial instruments approximates their fair value due either to length of maturity or interest rates that approximate prevailing market rates unless otherwise disclosed in these financial statements. The Company has no financial assets or liabilities that are measured at fair value on a recurring basis as of February 28, 2023.

Share Based Payments

Stock awards are accounted for under FASB ASC Topic 718, “Compensation-Stock Compensation” (“ASC 718”). Under ASC 718, compensation for all share-based payment awards is based on estimated fair value at the grant date. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.

The Company estimates the fair value of stock purchase warrants on the grant date using the Black-Scholes option pricing model (“Black-Scholes Model”) as its method of valuation for warrant awards granted during the year. The Company’s determination of fair value of warrant awards on the date of grant using an option-pricing model is affected by the Company’s stock price, as well as assumptions regarding a number of subjective variables. These variables include, but are not limited to, the Company’s expected price volatility over the term of the awards and discount rates assumed.

Earnings (Loss) per Share of Common Stock

The Company follows ASC Topic 260, Earnings per Share, to account for the earnings per share. Basic earnings (loss) per common share of(“EPS”) ~~Common~~calculations ~~Stock~~are isdetermined ~~calculated~~ by dividing net earnings (loss) available to ~~common~~Common ~~stockholders~~Stockholders by the weighted average number of common shares issued and ~~outstanding~~ outstanding during the year. Diluted earnings per common share isare ~~computed~~determined ~~based~~by ondividing net income (loss) by the weighted average number of common shares outstanding and, ~~increased~~ by dilutive ~~Common~~common ~~Stock~~share equivalents outstanding. ~~For~~During ~~the~~periods ~~years~~when ~~ended~~common ~~February~~share 28equivalents, ~~2022~~if ~~and February 28~~any, ~~2021, Common Stock equivalents~~ are ~~excluded from the calculations since their effect is~~ anti-dilutive they ~~due~~are tonot ~~the~~considered ~~Company’s~~in ~~net~~the ~~loss~~computation.

Concentration of Credit Risk

Substantially all of the Company’s trade accounts receivable result from crude oil and natural gas sales in California or joint interest billings to its working interest partners in California. 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 crude oil and natural gas prices as well as other related factors. Trade accounts receivable are generally not collateralized.

Customer Concentration

AtAccounts the Company’s East Slopes project in California we deal with only one buyer for the purchase of all crude oil production. The Company has no natural gas production in California. At February 28, 2022 and February 28, 2021, this one individual customer represented 100.0% of crude oil sales receivable from operations. If this buyer is unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its crude oil production.Receivable

~~The~~At both the Company’s ~~accounts~~projects ~~receivable~~ in California there is only one buyer for the purchase of all crude oil ~~sales~~production. atAt February 28, ~~2022~~2023 and February 28, ~~2021~~2022, ~~respectively~~this ~~are~~one ~~set~~individual customer ~~forth~~represented in100% of crude oil sales receivable from operations. If this buyer is unable to resell its products or if they lose a significant sales contract then the ~~table~~Company ~~below~~may incur difficulties in selling its crude oil production.

At the Reabold project wells in Contra Costs County, California there is also natural gas production that the Company sells to a single buyer. At February 28, 2023, this one individual customer per project represented 100% of natural gas sales receivable. The Company had no natural gas sales before the Reabold acquisition in May of 2022. If this local purchaser is unable to resell their products or if they lose a significant sales contract then we may incur difficulties in selling our natural gas production.

The Company’s accounts receivable for California crude oil and natural gas sales at February 28, 2023 and February 28, 2022 are set forth in the table below:

Customer Concentration Risk

		February 28, 2023				February 28, 2022
Project	Customer	Accounts Receivable		Percentage		Accounts Receivable		Percentage
California – East Slopes project (crude oil)	Plains Marketing	$	55,900	42.5	%	$	117,727	100.0	%
California – Reabold project (crude oil)	Plains Marketing		59,614	45.3	%		—	—
California – Reabold project (natural gas)	CRC		15,996	12.2	%		—	—
Totals		$	131,510	100.0	%	$	117,727	100.0	%

Accounts Receivable - Crude Oil Sales		February 28, 2022					February 28, 2021
Project	Customer	Accounts Receivable Crude Oil Sales		Percentage			Accounts Receivable Crude Oil Sales		Percentage
California – East Slopes Project (Crude oil)	Plains Marketing	$	117,727		100.0	%	$	108,993		100.0	%

Revenue Recognition

The Company recognizes revenue under ASC 606, Revenue from Contracts with Customers (“Topic 606”). Under Topic 606, revenue ~~will~~is generally be recognized upon delivery of ~~our~~the Company’s produced crude oil and natural gas volumes to ~~our~~its customers. ~~Our~~Customer ~~customer~~ sales contracts include ~~only~~ crude oil sales from both the East Slopes and Reabold projects and natural gas sales from some of the Reabold project. Both of these projects are located in California. ~~Under~~ ~~Topic~~Each ~~606,~~unit of ~~each~~commodity ~~unit~~product (crude oil barrel) ofor ~~commodity~~natural ~~product~~gas MMBTU) represents a separate performance obligation which is sold at variable prices, determinable on a monthly basis. The pricing provisions of ~~our~~the crude oil and natural gas contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, product quality and prevailing supply and demand conditions in the geographic areas in which wethe ~~operate~~Company operates. WeThe ~~will~~Company ~~allocate~~allocates the transaction price to each performance obligation and recognize revenue upon delivery of the commodity product when the customer obtains control. Control of ~~our~~the produced crude oil volumes passes to ~~our~~the Company’s customers when the oil is measured by a trucking oil ticket. The Company has no control over the crude oil after this point and the measurement at this point dictates the amount on which the customer’'s payment is based. ~~Our~~Control ~~crude~~of ~~oil~~the ~~revenue~~Company’s ~~stream~~produced ~~includes~~natural gas volumes passes ~~burdened~~to byits ~~royalty~~customers ~~and~~when ~~other~~the ~~joint owner~~natural ~~working~~gas ~~interests~~is measured at the purchaser’s gas line meter. ~~Our~~The ~~revenues~~Company ~~are~~has ~~recorded~~no control over the natural gas after this point and ~~presented~~the onmeasurement ~~our~~at ~~financial~~this ~~statements~~point ~~net~~dictates ofthe amount on which the ~~royalty~~customer’s ~~and~~payment ~~other~~is ~~joint~~based. ~~owner~~The ~~working~~crude ~~interests.~~oil ~~Our~~and ~~revenue~~natural ~~stream~~gas ~~does~~revenue ~~not~~streams include ~~any~~volumes ~~payments~~burdened ~~for~~by ~~services~~royalty orand ~~ancillary items~~ other ~~than~~joint ~~sale~~owner ofworking ~~crude oil~~interests. WeThe ~~record~~Company’s ~~revenue~~revenues inare ~~the~~recorded ~~month~~and ~~our~~presented ~~crude~~on ~~oil~~its ~~production~~financial isstatements ~~delivered~~net toof the ~~purchaser~~royalty and other joint owner working interests. The revenue stream

60 71

~~Asset~~does ~~Retirement~~not ~~Obligation~~include ~~(“ARO”)~~any payments for services or ancillary items other than for the sale of crude oil and natural gas. Revenue is recorded in the month crude oil and natural gas production is delivered to the purchaser.

The Company follows the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“ASC 410”), which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This standard requires that the Company recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. The ARO is capitalized as part of the carrying value of the assets to which it is associated, and depreciated over the useful life of the asset. The ARO and the related asset retirement cost are recorded when an asset is first drilled, constructed or purchased. The asset retirement cost is determined and discounted to present value using a credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in the statements of operations. Subsequent adjustments in the cost estimate are reflected in the ARO liability and the amounts continue to be amortized over the useful life of the related long-lived assets.

Suspended Well Costs

The Company accounts for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities – Oil and Gas” (“ASC 932”). ASC 932 states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the economic and operating feasibility of the well. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs.

Income Taxes

The Company follows the provisions of FASB ASC Topic 740, “Income Taxes” (“ASC 740”). As required under ASC 740, the Company accounts for income taxes using an asset and liability approach, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial statements and tax bases of assets and liabilities at the applicable tax rates. A valuation allowance is utilized when it is more likely than not, that some portion of, or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

ASC 740 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under ASC 740, the Company recognizes tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% (percent) likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards.

Use of Estimates and Assumptions

· The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any impairment of proved properties;

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

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

· Estimates regarding the timing and cost of future abandonment obligations; and,

· Estimates regarding projected cash flows used in determining the production payable discount.

Recent Accounting Pronouncements

Accounting Standards Issued and Adopted

The Company does not believe that any recently issued effective pronouncements, or pronouncements issued but not yet effective, if adopted, would have a material effect on the Company’s financial statements.

NOTE 4 — ACCOUNTS RECEIVABLE:

Accounts receivable consists primarily of receivables from the sale of crude oil and natural gas production by the Company and receivables from the Company’s working interest partners in crude oil and natural gas projects in which the Company acts as Operator of the project.

Crude oil and natural gas sales receivables balances of $~~117~~131,~~727~~510 and $~~108~~117,~~993~~727 at February 28, ~~2022~~2023 and February 28, ~~2021~~2022, represent crude oil and natural gas sales that occurred in February 2023 ~~2022~~ and ~~2021~~2022, respectively.

Joint interest participant receivables balances of of $85353,~~339~~009 and $7985,~~411~~339 at February 28, ~~2022~~2023, and February 28, ~~2021~~2022, 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 February 28, ~~2022~~2023, and February 28, ~~2021~~2022.

NOTE 5 — CRUDE OIL PROPERTIES:

Crude oil property balances at February 28, ~~2022 and~~2023, and February 28, ~~2021~~2022 are set forth in the table below:

	February 28, 2022			February 28, 2021
	February 28, 2023			February 28, 2022
Proved leasehold costs	$	115,119		$	115,119
Unproved leasehold costs		—			55,978
Costs of wells and development		6,915,982			2,309,628
Costs of wells and development		2,309,628			2,291,924
Capitalized exploratory well costs		1,341,494			1,341,494
Total cost of oil and gas properties		3,766,241			3,804,515
Property, plant and equipment (Reabold)		320,217			—
Accumulated depletion, depreciation amortization and impairment		(3,230,209	)		(3,192,081	)
Cost of crude oil and natural gas properties		8,692,812			3,766,241
Oil and gas properties, net	$	536,032		$	612,434
Accumulated depletion, depreciation amortization and impairment		(3,566,612	)		(3,230,209	)
Total crude oil and natural gas properties, net	$	5,126,200		$	536,032

For the twelve months ended February 28, ~~2022~~2023 and February 28, ~~2021~~2022, the Company recognized depletion expense of $38477,~~125~~089 and $5638,~~013~~125, respectively which is included in DD&A in the statement of operations. Impairment expense of proven undeveloped (PUD) well costs for the twelve months ended February 28, ~~2022~~2023 and February 28, ~~2021~~2022 was $55711,~~978~~873 and $-0-, respectively.

NOTE 6 —– ~~ASSET~~ACQUISITION: ~~RETIREMENT OBLIGATION (“ARO”)~~

~~The~~On ~~Company’s~~May ~~financial~~25, ~~statements~~2022, ~~reflect~~ the ~~provisions~~ ofCompany ~~ASC~~finalized ~~410.~~the ~~The~~acquisition of ~~ARO~~Reabold ~~primarily~~from ~~represents~~a ~~the~~third ~~estimated~~party ~~present~~for ~~value~~160,964,489 shares of the ~~amount the~~ Company’s ~~will~~Common ~~incur~~Stock tovalued ~~plug,~~at ~~abandon~~$6,599,544. ~~and~~The ~~remediate~~transaction ~~its~~balance ~~producing properties at the end~~ of ~~their productive lives~~$6,863,163 reflects inthe ~~accordance~~Common ~~with~~Stock ~~applicable~~valuation ~~state~~of ~~laws. The Company determines~~ the ~~ARO~~acquisition ontransaction ~~its crude oil~~ and ~~natural~~$263,619 in ~~gas~~reimbursements ~~properties~~to ~~by calculating~~ the ~~present~~seller, ~~value~~considered ofto ~~estimated~~be cash ~~flows~~consideration, ~~related~~relating to ~~the~~expenditures ~~liability. As~~for ofworkovers ~~February~~agreed ~~28, 2022 and February 28, 2021, ARO obligations were considered~~ to beby ~~long-term based on~~ the Company ~~estimated~~and ~~timing of~~ the ~~anticipated cash~~third ~~flows~~party. ~~For~~The ~~the~~acquisition ~~twelve~~was ~~months~~considered ~~ended~~an ~~February~~acquisition ~~28,~~of ~~2022~~a ~~and~~business ~~February~~under ~~28,~~ASC ~~2021,~~805. The ~~the~~following ~~Company~~table ~~recognized~~presents ~~accretion~~the ~~expense~~allocation of ~~$8,574~~the ~~and $4,050,~~purchase ~~respectively~~price ~~which~~of isthe ~~included~~assets inacquired ~~DD&A~~and inliabilities ~~the~~assumed ~~statements~~at offair ~~operations~~value.


Cash	$	19,706
Restricted cash – O&G operator bonds		275,000
Accounts receivable		248,817
Crude oil and natural gas property and equipment		4,694,563
Property, plant and equipment, net		428,221
Goodwill		1,415,361
Accounts payable		(152,854	)
Revenue payable		(62,914	)
Other liabilities assumed		(2,737	)
Purchase price, net of closing adjustments	$	6,863,163

~~Changes in the asset retirement obligations for the twelve months ended February 28, 2022 and February 28, 2021 are set forth in the table below.~~73

Adjustments made to the Reabold assets are derived from a total value of $6,599,544, based on 160,964,489 shares of stock issued for the acquisition and the closing price that day of $0.041 per share. The total consideration given of $6,863,163, consisted of the $6,599,544 common stock valuation and cash consideration of $263,619 for approved expense reimbursement. Net assets acquired of $5,447,802 were derived by deducting the liabilities assumed of $218,505 from the assets acquired of $5,666,307. Goodwill of $1,415,361 was derived by deducting the consideration given of $6,863,163 from the net assets acquired of $5,447,802. The Company incurred approximately $445,529 in transaction costs directly related to the Acquisition.

NOTE 7 — ASSET RETIREMENT OBLIGATION (“ARO”):

The Company’s financial statements reflect the provisions of ASC 410. The ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determines the ARO on its crude oil and natural gas properties by calculating the present value of estimated cash flows related to the liability. As of February 28, 2023 and February 28, 2022, ARO obligations were considered to be long-term based on the estimated timing of the anticipated cash flows. For the twelve months ended February 28, 2023, and February 28, 2022, the Company recognized accretion expense of $23,875 and $8,574, respectively which is included in DD&A in the statements of operations.

Changes in the asset retirement obligations for the twelve months ended February 28, 2023, and February 28, 2022 are set forth in the table below.

	February 28, 2022		February 28, 2021
	February 28, 2023		February 28, 2022
Asset retirement obligation, beginning of period	$	3352,~~062~~565	$	2733,~~149~~062
Accretion expense		823,~~574~~875		48,~~050~~574
Revisions to asset retirement obligation		10239,~~929~~069		110,~~863~~929
Asset retirement obligation, end of period	$	52315,~~565~~509	$	3352,~~062~~565

NOTE 78 — ACCOUNTS PAYABLE:

On March 1, 2009, the Company became the ~~operator~~ operator for the East Slopes Project located in Kern County, 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 wells program. The Company subsequently sold the 25% working interest on June 11, 2009. Approximately $244,849 of the $1.5 million default remains unpaid and is included in the February 28, ~~2022~~2023 and February 28, ~~2021~~2022 accounts payable balance. 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 February 28, ~~2022~~2023 and February 28, ~~2021~~2022, the balance owed this working interest partner was $7663,~~268~~367 and $8876,~~905~~268, respectively and is included in the accounts payable ~~balances. During the twelve months ended February 28, 2022, the Company worked~~ ~~to restructure its balance sheet. Employer payroll tax estimates of $52,530 and employee payroll tax estimates of $135,687 that had been recognized as a part of the accounts payable~~ balances ~~were eliminated either through debt forgiveness or conversion to 301,527 shares of the Company’s common stock~~.

NOTE 9 8 — ACCOUNTS PAYABLE - RELATED PARTIES:

The February 28, ~~2022~~2023, and February 28, ~~2021~~2022 accounts payable – related ~~parties~~party balances of $4921,~~228~~ 937 and $~~988~~49,~~966~~228, 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~~employees.

~~During~~In ~~the~~California ~~twelve~~at ~~months~~the ~~ended~~East ~~February~~Slopes 28Project, two of the ~~2022,~~vendors that the Company ~~worked~~uses tofor ~~restructure~~services ~~its~~are ~~balance~~partially ~~sheet~~owned ~~through~~by ~~the~~a ~~conversion of~~ related party, ~~debt to~~ the Company’s ~~common~~Chief Operating Officer. The Company’s ~~stock~~Chief Operating Officer is 50% owner in both Great Earth Power (“Great Earth”) and ABPlus Net Holdings (“ABPlus”). Great ~~Accrued~~Earth ~~employee~~began ~~net~~providing ~~salaries~~a portion of ~~approximately~~the ~~$493,359~~solar ~~were~~power ~~converted~~electrical ~~into~~service ~~1,096,353~~for ~~shares~~production ofoperations ~~common~~in ~~stock~~July 2020. ~~Accrued~~ABPlus began providing ~~director~~portable ~~fees~~tank ofrentals ~~$142,969~~to ~~were~~the ~~converted~~Company ~~into~~as ~~317,708~~a ~~shares~~part of ~~common~~its ~~stock.~~water ~~Additionally,~~treatment ~~$264,986~~and ofdisposal ~~12%~~operations ~~Note~~in ~~related~~September ~~party~~2020. The services provided ~~interest~~by ~~was~~Great ~~converted~~Earth ~~into~~and ~~588,859~~ABPlus ~~shares~~are ofcompetitive ~~common~~with ~~stock~~other vendors and save the Company significant expense.

~~NOTE 9 — SHORT-TERM AND LONG-TERM BORROWINGS:~~74

NOTE 10 — SHORT-TERM AND LONG-TERM BORROWINGS:

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 being issued to the vendor. Additionally, the Company agreed to issue 2,000,000 shares of the Company’s ~~common~~Common ~~stock~~Stock as a part of the settlement agreement. Based on the closing price of the Company’s ~~common~~Common ~~stock~~Stock on the date of the settlement agreement, the value of the ~~common~~Common ~~stock~~Stock transaction was determined to be $6,000. The ~~common~~Common ~~stock~~Stock shares were issued during the twelve months ended February 29, 2020. The note has a maturity date of January 1, 2022, and bears an interest rate of 10% rate per annum. ~~Monthly~~The note principal has not been paid and the Company is considered to be in default. There is no default interest rate associated with the note. Interest is accrued monthly and is payable on January 1st of each anniversary date ~~until maturity of the note~~. At February 28, ~~2022~~2023, the principal and a portion of the accrued interest had not been paid and was outstanding. The accrued interest on the Note was $3826,000 and $2638,000 at February 28, ~~2022~~2023 and February 28, ~~2021~~ 2022, respectively.

Note Payable – Related Party

Chief Executive Officer

Secured Debt

On December 22, 2020, the Company entered into a Secured Promissory Note (the “Note”), as borrower, with James Forrest Westmoreland and Angela Marie Westmoreland, Co-Trustees of the James and Angela Westmoreland Revocable Trust, or its assigns (the “Noteholder”), as the lender. James F. Westmoreland is the Company’s Chairman, President and Chief Executive Officer.

63 On December 22, 2020, the Company entered into a Secured Promissory Note (the “Note”), as borrower, with James Forrest Westmoreland and Angela Marie Westmoreland, Co-Trustees of the James and Angela Westmoreland Revocable Trust, or its assigns (the “Noteholder”), as the lender. James F. Westmoreland is the Company’s Chairman, President and Chief Executive Officer. Pursuant to the Note, the Noteholder loaned the Company an aggregate principal amount of $155,548. After the deduction of loan fees of $10,929 the net proceeds from the loan were $144,619. The loan fees are being amortized as original issue discount (OID) over the term of the loan. The interest rate of the loan is 2.25%. The Note requires monthly payments on the Note balance until repaid in full. The maturity date of the Note is December 21, 2035. For the twelve months ended February 28, 2023, the Company made principal payments of $8,829 and amortized debt discount of $729. The obligations under the Note are secured by a lien on and security interest in the Company’s oil and gas assets located in Kern County, California, as described in a Deed of Trust entered into by the Company in favor of the Noteholder to secure the obligations under the Note. Such lien shall be a first priority lien, subject only to a pre-existing lien filed by a working interest partner of the Company.

Pursuant to the Note, the Noteholder loaned the Company an aggregate principal amount of $155,548. After the deduction of loan fees of $10,929 the net proceeds from the loan were $144,619. The loan fees are being amortized as original issue discount (OID) over the term of the loan. The interest rate of the loan is 2.25%. The Note requires monthly payments on the Note balance until repaid in full. The maturity date of the Note is December 21, 2035. For the twelve months ended February 28, 2022, the Company made principal payments of $8,599 and amortized debt discount of $729. The obligations under the Note are secured by a lien on and security interest in the Company’s oil and gas assets located in Kern County, California, as described in a Deed of Trust entered into by the Company in favor of the Noteholder to secure the obligations under the Note. Such lien shall be a first priority lien, subject only to a pre-existing lien filed by a working interest partner of the Company.

Current portion of note payable – related party balances at February 28, ~~2022~~2023, and February 28, ~~2021~~2022 are set forth in the table below:

	February 28, 2022			February 28, 2021
	February 28, 2023			February 28, 2022
Note payable – related party, current portion	$	89,~~829~~065		$	8,~~598~~829
Unamortized debt issuance expenses		(~~729~~728	)		(~~728~~729	)
Note payable – related party, current portion, net	$	8,~~100~~337		$	78,~~870~~100

~~Note payable – related party long-term balances at February 28, 2022 and February 28, 2021 are set forth in the table below:~~75

	February 28, 2022			February 28, 2021
Note payable – related party, non-current	$	136,710		$	145,540
Unamortized debt issuance expenses		(9,350	)		(10,080	)
Note payable – related party, non-current, net	$	127,360		$	135,460

Note payable –related party long-term balances at February 28, 2023 and February 28, 2022 are set forth in the table below:

	February 28, 2023			February 28, 2022
Note payable – related party, non-current	$	127,645		$	136,710
Unamortized debt issuance expenses		(8,622	)		(9,350	)
Note payable – related party, non-current, net	$	119,023		$	127,360

Future estimated payments on the outstanding note payable – related party are set forth in the table below:

Twelve month periods ending February 28/29,
2023		8,829
2024		9,065
2025		9,309
2026		9,558
2027		9,815
Thereafter		98,963
2028		10,078
Total	$	145,539
Thereafter		88,885
Total	$	136,710

Short-term Convertible Note Payable

Convertible Debt

During the twelve months ended February 28, 2022, the Company executed a convertible promissory note with a third party for $200,000. The interest rate iswas 18% per annum and is payable in kind (“PIK”) solely by additional shares of the Company’s ~~common~~Common ~~stock~~Stock. Regardless of when the conversion ~~occurs~~occurred, a full 12 months of interest ~~will~~would be payable upon conversion. ~~The~~On ~~maturity~~May ~~date of the note is the date of the closing of the transactions contemplated by the Equity Exchange Agreement with Reabold California~~5, ~~LLC and Gaelic Resources~~2022, ~~Ltd. as described above under~~ the ~~Capital~~Company ~~Resources and~~received ~~Liquidity~~notice ~~caption found in this Item 7, Management’s Discussion and Analysis (MD&A). The conversion price was to be determined by one~~ of ~~two cases. In Case 1, the conversion price would be $0.017 and in Case 2, the conversion price would be $0.0085. The Case 1~~ conversion ~~price scenario would apply if the terms~~ of the ~~Equity~~promissory ~~Exchange Agreement were met by a Long Stop Date of April 29, 2022~~note. The ~~Case~~ 2face ~~conversion~~amount ~~price scenario would apply if the terms~~ of the ~~Equity~~note ~~Exchange~~and ~~Agreement were not met by a Long Stop Date of April 29~~$36,000 ~~2022.~~in ~~The~~interest ~~terms of the Equity Exchange Agreement~~ were ~~not~~converted ~~met~~at bya ~~the~~rate ~~Long Stop Date~~ of ~~April 29, 2022 and the conversion price was determined to be the~~ $0.0085 per ~~rate.~~share ~~Under~~into ~~ASC 855-10-55-1~~27,764,706 shares ~~the~~of ~~Company determined that a derivate issue did not exist since~~ the Company’s ~~was~~Common ~~able~~Stock ~~to determine~~during the ~~impact~~twelve ofmonths ~~the~~ended ~~subsequent~~February ~~event~~28, 2023.

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 was extended for an additional two years to January 29, 2019. The 980,000 warrants held by ten noteholders expired on January 29, 2019.

Private Placement

~~The~~Subordinated 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, on any future maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2018.Debt

AsThe aCompany’s ~~result~~12% ofSubordinated Notes (the ~~Company restructuring its~~“Notes”) ~~balance~~issued ~~sheet~~pursuant ~~through~~to ~~conversions~~a ofJanuary ~~related~~2010 ~~party~~private ~~debt~~placement offering to ~~common~~accredited ~~stock~~investors, ~~the~~had ~~related~~a ~~party~~balance ~~12%~~at ~~Noteholder~~February ~~chose~~28, to2023 ~~convert~~and ~~the~~February ~~principal~~28, ~~and~~2022 ~~accrued interest~~ of ~~their Notes to the Company’s common stock. The related party Note for~~ $~~250~~290,000 and ~~accrued~~ ~~interest of~~ $~~264~~315,~~986~~000, ~~were converted~~respectively. toThe ~~common~~original ~~stock~~maturity atdate ~~a rate~~ of ~~approximately~~January ~~$0.45~~29, ~~for every~~2015 ~~dollar~~had ofbeen ~~principal~~extended ~~and~~to ~~interest~~January ~~resulting in 1~~29,~~144,415~~ ~~shares~~2017 ofand ~~common~~then ~~stock~~was ~~being~~extended ~~issued.~~to ~~The~~January ~~accrued~~29, ~~interest~~2019. onInterest ~~the~~accrues at 12% ~~Notes~~per ~~at February 28~~annum, ~~2022~~payable ~~and~~semi-annually ~~February~~on ~~28,~~January ~~2021~~29th ~~was~~and ~~$135,229~~July ~~and $340,042, respectively~~29th.

~~12%~~The Company has informed the Note ~~balances~~holders that the payment of principal and interest will be late and is subject to future financing being completed and the Company’s cash flow. The Notes principal of $290,000 has not been paid and interest continues to accrue on the unpaid principal balance. The accrued interest on the 12% Notes at February 28, ~~2022~~2023 and February 28, ~~2021~~2022 ~~are~~was ~~set~~$159,508 ~~forth~~and in$135,229, respectively. The terms of the ~~table~~Notes, ~~below:~~state that should the Board of Directors, on any future maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s Common Stock at a conversion rate equal to 75% of the average closing price of the Company’s Common Stock over the 20 consecutive trading days preceding December 31, 2018.

During the twelve months ended February 28, 2023, one 12% Note holder chose to convert the principal balance and accrued interest into the Company’s Common Stock. The $25,000 Note and accrued interest of $10,520 were converted at a rate of approximately $0.45 for every dollar of principal and interest resulting in 78,934 shares of Common Stock being issued.

12% Note balances at February 28, 2023 and February 28, 2022 are set forth in the table below:

12% Subordinated Notes

	February 28, 2022		February 28, 2021
12% Subordinated notes – third party	$	315,000	$	315,000
12% subordinated notes – related party		—		250,000
12% Subordinated notes balance	$	315,000	$	565,000

Related Party Notes

	February 28, 2023		February 28, 2022
12% Subordinated notes – third party	$	290,000	$	315,000
12% subordinated notes – related party		—		—
12% Subordinated notes balance	$	290,000	$	315,000

Line of Credit

Line of Credit

~~The~~At February 28, 2022, the Company ~~has~~had an existing $890,000 line of credit for working capital purposes with UBS Bank USA (“UBS”), that was established pursuant to a Credit Line Agreement dated October 24, 2011 ~~that~~and iswas secured by the personal guarantee of our President and Chief Executive Officer. OnDuring ~~November 10, 2021,~~ the ~~Company~~twelve ~~was~~months ~~notified that~~ended ~~effective~~February ~~January 1~~28, ~~2022~~2023, ~~a new interest rate benchmark the UBS Variable Rate (UBSVR) would replace the existing 30-day LIBOR (“London~~and ~~Interbank~~February ~~Offered~~28, ~~Rate”)~~2022, ~~benchmark. The UBSVR is comprised of~~ the ~~compounded~~Company ~~30-day~~did ~~average~~not ofreceive ~~the~~any ~~Secured~~advances ~~Overnight Financing Rate (SOFR) plus a fixed spread adjustment of 0.110%. The Company’s new all-~~on ~~rate~~the ~~will~~line ~~consist~~ of ~~the UBSVR plus its current spread over LIBOR~~credit.

~~During~~On ~~the~~May ~~twelve~~26, ~~months~~2022, ~~ended~~the ~~February~~Company ~~28,~~paid ~~2022~~off ~~and~~the outstanding ~~February~~balance ~~28,~~of ~~2021~~$809,930 weon ~~did~~the ~~not~~line ~~receive~~of ~~any~~credit. ~~advances~~The onpayoff of the line of credit, ~~respectively.~~was ~~During~~previously ~~the~~approved ~~twelve~~under ~~months~~terms ~~ended~~of ~~February~~the ~~28,~~Equity ~~2022~~Exchange ~~and~~Agreement ~~February~~in ~~28,~~which ~~2021,~~the weCompany ~~made~~acquired ~~payments~~the toReabold ~~the~~property in California. The line of credit ofpayoff ~~$60,000,~~was ~~respectively.~~a ~~Interest~~part ~~converted~~of tothe ~~principal~~use ~~for~~of ~~the twelve~~proceeds ~~months~~from ~~ended~~the ~~February~~Company’s ~~28,~~sale ~~2022~~of ~~and~~Common ~~February~~Stock ~~28,~~to ~~2021~~a ~~was~~third ~~$27,278 and $28,503, respectively~~party. At February 28, ~~2022~~2023 and February 28, ~~2021~~2022, the line of credit had an outstanding balance of $~~808,182~~-0- and $~~840~~808,~~904~~182, respectively.

65 During the twelve months ended February 28, 2022, the Company made payments to the line of credit of $60,000. Interest converted to principal for the twelve months ended February 28, 2022 was $27,278.

Production Revenue Payable

~~Since~~During ~~December~~the ~~2018~~twelve months ended February 28, 2019, and February 29, 2020, the Company ~~has~~conducted ~~been conducting~~ a fundraising program to raise $1.3 million to fund the drilling of future wells in California and to settle some of its existing historical debt. The purchasers of a production payment ~~interests~~interest are to receive a production revenue payment interest on future wells to be drilled in California in exchange for their purchase. OnThe ~~August~~Company ~~22,~~shall ~~2019,~~pay ~~the~~seventy-five ~~Company~~percent (75%) ~~entered~~of ~~into~~its afuture ~~Note~~net ~~Payoff~~production ~~Agreement~~revenue ~~with~~from the ~~Company’s~~relevant ~~Chairman,~~wells ~~President~~to ~~and~~the ~~Chief Executive~~purchasers ~~Officer~~until aseach ~~payment~~purchaser inhas ~~full~~received oftwo times the ~~$250,100~~purchase price ~~that~~(the ~~had~~“Production ~~been~~Payment ~~loaned~~Target”). toOnce the Company ~~during~~pays the ~~years~~purchaser ~~ended~~group ~~February~~amounts ~~29,~~equal ~~2012 and February 28, 2013. Pursuant~~ to the ~~Note~~Production ~~Payoff Agreement~~Payment Target, ~~the~~it ~~Company~~shall ~~issued~~thereafter pay a ~~production~~pro-rated ~~payment~~eight ~~interest~~percent in(8%) ~~certain~~ of ~~the~~$1.3 ~~Company’s production~~million ~~revenue~~on ~~from~~its ~~the~~net ~~drilling of future wells in California. The~~ production ~~payment~~payments ~~interest~~from ~~was~~the ~~granted~~relevant ~~for a deemed consideration~~wells ~~amount~~to of the ~~balance~~purchaser ~~of the Notes~~group. ~~The~~However, ~~grant~~if ~~was~~the ~~made~~total onraise ~~the~~amount ~~same~~is ~~terms~~less asthan the ~~Company~~target ~~has~~$1.3 ~~sold~~million, ~~production~~then the payment ~~interests~~will tobe ~~other~~a proportionate ~~third~~amount ~~parties~~of in the ~~2018-2019~~eight ~~fiscal~~percent ~~year pursuant to its previously disclosed program~~(8%).

The ~~production~~Company ~~payment~~accounted ~~interest~~for ~~entitles~~ the ~~purchasers~~amounts received from tothese ~~receive~~sales ~~production~~in ~~payments~~accordance ~~equal~~with toASC ~~twice~~470-10-25 ~~their~~and ~~original~~470-10-35 ~~amount~~which ~~paid,~~require ~~payable~~amounts ~~from~~recorded aas ~~percentage~~debt ofto ~~the~~be ~~Company’s~~amortized ~~future~~under ~~net production~~the ~~payments~~interest ~~from~~method as ~~wells~~described ~~drilled~~in ~~after~~ASC ~~the~~835-30, ~~date~~Interest ofMethod. Consequently, the ~~purchase~~program ~~and~~balance ~~until~~of ~~the~~$873,281 ~~Production~~has ~~Payment~~been ~~Target~~recognized (as ~~described~~a ~~below)~~production isrevenue ~~met~~payable. The Company ~~shall~~determined ~~pay~~an ~~seventy-five~~effective ~~percent~~interest ~~(75%)~~rate ofbased ~~its~~on ~~net~~future ~~production~~expected

Filing Compare · DAYBREAK OIL & GAS, INC.