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 UNITED STATES

 SECURITIES AND EXCHANGE COMMISSION

 Washington, D.C. 20549

 FORM 10-K

 (Mark One)

 x

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

 For the fiscal year ended February 28, 2023

 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

 (Exact name of registrant as specified in its charter)

 Washington

 91-0626366

 (State or other jurisdiction of incorporation or organization)

 (IRS Employer Identification No.)

 1414 S. Friendswood Drive, Suite 212, Friendswood, TX

 77546

 (Address of principal executive offices)

 (Zip code)

 Registrant's telephone number, including area
code: (281) 996-4176

 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

 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

 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 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 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

 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

 The aggregate market value of the voting and non-voting
stock held by non-affiliates of the registrant, based on the closing price of $0.05 on August 31, 2022, as reported by the OTC Pink
Open Market was $ 2,821,727.

 At January
23, 2024, the registrant had 384,734,902 outstanding shares of $0.001 par value
Common Stock.

 PAGE

 ITEM 1.

 BUSINESS

 ITEM 1A.

 RISK FACTORS

 ITEM 1B.

 UNRESOLVED STAFF COMMENTS

 ITEM 2.

 PROPERTIES

 ITEM 3.

 LEGAL PROCEEDINGS

 ITEM 4.

 MINE SAFETY DISCLOSURES

 ITEM 5.

 MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 ITEM 6.

 [ RESERVED ]

 ITEM 7.

 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 ITEM 7A.

 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 ITEM 8.

 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 Report of Independent Registered Public Accounting Firm (PCAOB ID: 206)

 Balance Sheets as of February 28, 2023 and February 28, 2022

 Statements of Operations for the Years Ended February 28, 2023 and February 28, 2022

 Statements of Changes in Stockholders' Equity (Deficit) for the Years Ended February 28, 2023 and February 28, 2022

 Statements of Cash Flows for the Years Ended February 28, 2023 and February 28, 2022

 ITEM 9.

 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 ITEM 9A.

 CONTROLS AND PROCEDURES

 ITEM 9B.

 OTHER INFORMATION

 ITEM 9C.

 DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 ITEM 10.

 DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

 ITEM 11.

 EXECUTIVE COMPENSATION

 ITEM 12.

 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 ITEM 13.

 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 ITEM 14.

 PRINCIPAL ACCOUNTING FEES AND SERVICES

 ITEM 15.

 EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 ITEM 16.

 FORM 10-K SUMMARY

 SIGNATURES

 GLOSSARY OF TERMS

 CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

 This Annual 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.

 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 OTCMarkets under the symbol DBRM in the Expert Market.

 Our corporate office is 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 in the 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 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
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 two oilfield projects 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 our 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 prices we receive for crude oil sales in California
from 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, respectively. All posted pricing is subject to adjustments that vary by
grade of crude oil, transportation costs, market differentials and other local conditions. Both the posted Midway-Sunset and Buena Vista
prices generally move in correlation to prices quoted on the New York Mercantile Exchange ("NYMEX") for spot West Texas intermediate
("WTI") crude oil, Cushing, Oklahoma delivery contracts.

 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:

 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, 2023 increased $853,153 or 125.4% to $1,533,260 in comparison to revenue of $680,107 for the twelve months ended February
28, 2022. The average sale price of a barrel of crude oil for the twelve months ended February 28, 2023 was $89.59 in comparison to $70.75
for the twelve months ended February 28, 2022. The increase of $18.84 or 26.6% per barrel in the average realized price of a barrel of
crude oil accounted for 21.2% of the increase in crude oil revenue for the twelve months ended February 28, 2023.

 Our net sales volume for the twelve months ended February
28, 2023 was 17,114 barrels of crude oil in comparison to 9,613 barrels sold for the twelve months ended February 28, 2022. The increase
in crude oil sales volume of 7,501 barrels or 78.0% was primarily due to the Reabold subsidiary acquisition in May of 2022 and this overall
increase in crude oil sales volume accounted for 78.8% of the increase in crude oil revenue for the twelve months ended February 28, 2023.

 The gravity of our produced crude oil from the East
Slopes project in Kern County ranges between 15 API and 17 API. Production for the twelve months ended February 28, 2023 and
February 28, 2022 was from 20 wells. The gravity of our produced crude oil from our Reabold subsidiary in Monterey and Contra Costs Counties
is approximately 17 API and 38 API, respectively. Production for the twelve months ended February 28, 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.

 Percentage Change

 Average twelve month Henry Hub natural gas price (Mcf)

 $
 6.35

 $
 —

 %

 Average twelve month realized natural gas sales price (Mcf)

 $
 20.94

 $
 —

 %

 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 Customers

 At both of our projects in California, we sell all
of our crude oil production to one buyer. At February 28, 2023 and February 28, 2022, this one individual customer 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.

 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:

 Project

 Customer

 Accounts
 Receivable

 Accounts
 Receivable

 California – East Slopes project (crude oil)

 Plains Marketing

 $
 55,900

 42.5
 %

 $

 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
 %

 $

 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 have 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 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.

 The California Geologic Energy
Management Division ("CalGEM") of the Department of Conservation is California's primary regulator of the crude oil and natural
gas production industry on private and state lands, with additional oversight from the State Lands Commission's administration of
state surface and mineral interests. In California, we currently operate a 20 well crude oil project in Kern County and a 10 well crude
oil and natural gas project in Monterey and Contra Costa Counties. A variety of factors outside of our control can lead to our obtaining
drilling permits from CalGEM for our operations. CalGEM has not issued any permits for new production wells to any operators since December
2022. CalGEM currently requires an operator to identify the manner in which the CEQA has been satisfied prior
to issuing various state permits, typically through either an environmental review or an exemption by a state or local agency. In Kern
County, this requirement has typically been satisfied by complying with the local crude oil and natural gas ordinance which was supported
by an Environmental Impact Report ("EIR") certified by the Kern County Board of Supervisors in 2015.

 Our operations in Kern County
have been subject to significant uncertainty over the past several years as a result of ongoing challenges to the County's ability to
rely on an existing EIR to meet the County's obligations 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 permit approvals ("Kern County EIR Litigation").
In March 2018 a trial court ("Trial Court") found that the EIR inadequately analyzed the environmental impacts to rangeland
and road paving mitigation for purposes of well work and rejected the plaintiffs' other CEQA claims. The plaintiffs appealed. In
February 2020, the California Fifth District Appellate Court ("Appellate Court") ruled that the plaintiffs' other CEQA
claims had merit and ordered Kern County to rescind the Zoning Ordinance and cease issuing permits. In March 2021, Kern County's
Board of Supervisors approved a revised Zoning Ordinance (the "Revised Ordinance") and certified a Supplemental Recirculated
Environmental Impact Report ("SREIR") for purposes of satisfying CEQA requirements with respect to the issuance of oil and
natural gas permits. A suit was subsequently filed that same month challenging the sufficiency of the SREIR. In October 2021, the Trial
Court ordered Kern County to cease using the 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 the SREIR that needed correction to conform to CEQA.
In November 2022, upon the correction of those deficiencies to the Trial Court's satisfaction, the Trial Court lifted the suspension
on Kern County's ability to rely on the existing SREIR to meet CEQA requirements in Kern County (the Discharge Order). In December 2022,
the Trial Court denied a motion to stay 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.

 On January 26, 2023, the
Appellate Court issued a preliminary order on the petition reinstating a suspension of Kern County's ability to rely on the existing SREIR
to meet CEQA requirements pending the outcome of a final order determining whether crude oil and natural gas permitting shall remain suspended
for the duration of the appeals process. That order is still pending.

 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.

 Furthermore, the California
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.

 CalGEM and other state agencies
have also significantly revised their regulations, regulatory interpretations and data collection and reporting requirements. CalGEM issued
updated regulations in April 2019 governing management of idle wells, which include specific implementation periods. The updated idle
well management regulations require operators to either submit annual idle well management plans describing how they will plug and abandon
or reactivate a specified percentage of long-term idle wells or pay additional annual fees and perform additional testing to retain greater
flexibility to return long-term idle wells to service in the future. The updated underground injection regulations address injection approvals,
project data requirements, testing of injection wells, monitoring and reporting requirements with respect to injection parameters, containment
and incident response, among other topics.

 In addition, certain local
governments have proposed or adopted ordinances that would restrict certain drilling activities in general and well stimulation, completion
or injection activities in particular, impose setback distances from certain other land uses, or ban such activities outright. For example,
a ban on prohibiting new crude oil and natural gas wells and the phasing out of existing wells over a number of years was previously proposed
in Monterey County, where we own mineral rights and have production from our Reabold acquisition. That ban however was declared to be
preempted by state and federal regulation. Other local governments have sought to ban natural gas or the transportation of natural gas
through their cities. The City of Antioch, located in Contra Costa County where we do have both crude oil and natural gas producing properties
has declined to extend the franchise agreement for a natural gas pipeline through its city. Several
companies, including our natural gas purchaser have challenged the city's inconsistent and arbitrary approach to natural gas 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, 2023, we had five full-time employees.
Additionally, we regularly use the services of 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.

 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, 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

 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.

 1414 S. Friendswood Drive,

 Suite 212

 Friendswood, TX 77546

 Attention: Corporate Secretary

 Telephone: (281) 996-4176

 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.

 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.

 Summary of 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.

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

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

 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.

 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.

 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.

 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 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 proved reserves are estimates and depend on many assumptions. Any material
inaccuracies in these assumptions could cause the quantity and value of our crude oil reserves, and our revenues, profitability and cash
flows to be materially different from our estimates.

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

 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, 2023, we determined that a non-cash impairment will not be
recognized on our California crude oil properties due to the current hydrocarbon prices.

 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 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.

 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.

 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 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 two producing projects are located in California.
As a result of this concentration, we may be disproportionately exposed to the impact of regional conditions which could negatively impact
the success and 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 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 operations may
be exposed to power outages, 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, increase operating and capital costs,
prevent development of lease inventory before expiration and limit access to markets for our products.

 Our proved reserves are estimates and depend
on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our crude oil reserves, and
our revenues, profitability, and cash flows to be materially different from our 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 order to maintain current production levels, we will be required to find and develop 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.

 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 have 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. The reduction in
our drilling plans has limited our access to capital resources. In the past, we have had to reclassify a significant amount of our proved
undeveloped reserves as probable or possible reserves because they have not been drilled within the SEC-defined time period. Any future
reclassification of proved undeveloped reserves may 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.

 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.

 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 and 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
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.

 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.

 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.

 On October 7, 2023, the California
Governor signed into law Assembly Bill 1167 ("AB 1167"), which imposes more stringent financial assurance requirements on
persons who acquire the right to operate a well or production facility in the state of California, requiring them to file either an individual
indemnity bond for single-well or production facility acquisitions, or a blanket indemnity bond for multiple wells or production facilities.
The bond imposed on the acquirer will be in an amount determined by the state to sufficiently cover plugging and abandonment costs, decommissioning,
and site restoration, and AB 1167 prohibits the closing of any acquisition of a well or production facility until a determination on the
appropriate bond amount has been completed by the state and the bond has been filed. We are still assessing the impact of AB 1167. In
addition, although AB 1167 has been signed into law, Governor Newsom has called for further legislative changes to these new requirements
to mitigate against the potential risk of the implementation of AB 1167 ultimately increasing the number of orphaned idle or low-producing
wells in California. However, we cannot predict what form these changes may ultimately take or if the legislature will act on the Governor's
request. Implementation of this law may lead to the delay or additional costs with respect to acquisitions or dispositions, which could
impact our ability to grow or explore new strategic 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

 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.

 Our operations are subject to extensive federal, state
and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish
standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes,
and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination,
as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may
arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly
owned or operated, and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate.
Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws. Under
a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than
our share of the liability

 involved, or even the entire share. Environmental
requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

 We have incurred expenses in connection with environmental
compliance, and we anticipate that we will continue to do so in the future. Failure to comply with extensive applicable environmental
laws and regulations could result in significant civil or criminal penalties and remediation costs. Some of our properties may be affected
by environmental contamination that may require investigation or remediation. In addition, claims are sometimes made or threatened against
companies engaged in crude oil and natural gas exploration and production by owners of surface estates, adjoining properties or others
alleging damage resulting from environmental contamination and other incidents of operation. Compliance with, and liabilities for remediation
under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business,
financial condition and results of 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.

 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 oil and gas within the state.

 In September 2020, Governor Gavin Newsom of California
issued an executive order (the "Order") that seeks to reduce both the demand for and supply of petroleum fuels in the state.
The Order establishes several goals and directs several state agencies to take certain actions with respect to reducing emissions of GHGs,
including, but not limited to: phasing out the sale of new emissions-producing passenger vehicles, drayage trucks and off-road vehicles
by 2035 and, to the extent feasible, medium and heavy duty trucks by 2045; developing strategies for the repurposing of crude oil and
natural gas facilities in California; and proposing legislation to end the issuance of new hydraulic fracturing permits in the state by
2024. The Order also directs the California Department of Conservation, Geologic Energy Management Division ("CalGEM") to
strictly enforce bonding requirements for oil and gas operations and to complete its ongoing public health and safety review of oil production
and propose additional regulations, which are expected to include expanded land use setbacks or buffer zones. In October 2020, the Governor
issued an executive order that establishes a state goal to conserve at least 30% of California's land and coastal waters by 2030
and directs state agencies to implement other measures to mitigate climate change and strengthen biodiversity.

 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.

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

 Climate change continues to attract considerable public
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. These efforts have included consideration by states or
groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit
GHG emissions from certain sources.

 At the federal level, no comprehensive climate change
legislation has been implemented to date. However, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present
an endangerment to public health and the environment and has adopted regulations under existing provisions of the Clean Air Act. The EPA
has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual
basis, including, among others, onshore and offshore crude oil and natural gas production facilities and onshore processing, transmission,
storage, and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of
the crude oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines,
and in January 2016, the EPA proposed additional revisions to leak detection methodology.

 The adoption and implementation of any international,
federal, or state legislation, regulations or other regulatory initiatives that require reporting of GHGs or otherwise restricts emissions
of GHGs from our equipment and operations could cause us to incur increased costs that could have an adverse effect on our business, financial
condition, and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer,
and thereby reduce demand for crude oil and natural gas, which could reduce the demand for the crude oil or natural gas we produce and
lower the value of our reserves.

 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 $ 2.4
million for the year ended February 28, 2023, and we have an accumulated deficit through February 28, 2023 of approximately $ 31.96
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.

 Our ability to satisfy our
obligations depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond
our control. Our business does not generate sufficient cash flow to meet our ongoing obligations, and future financings may not 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 business conditions. We cannot guarantee that our future performance will not be adversely affected by such economic conditions and
financial, business and other factors.

 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.

 At February 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:

 limit management's discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

 require us to dedicate a portion of our cash flows from operations to service our existing debt, thereby reducing cash available to finance our operations and other business activities;

 increase our vulnerability to downturns and adverse developments in our business and the economy generally; and,

 limit our access to capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other expenses.

 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.

 Our financial statements for the year ended February
28, 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) 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.

 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
and warrants have and may continue to dilute ownership interests which could have an adverse effect on our stock prices.

 Our authorized capital stock consists of 500,000,000
shares of Common Stock. As of February 28, 2023, there were 384,734,902 shares of Common Stock issued and outstanding. With the filing
of our Company's Second Amended and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, we no
longer have any 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.

 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.

 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.

 ITEM 1B. UNRESOLVED STAFF COMMENTS

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

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 twelve months ended February 28, 2023, we were involved in two crude oil 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, 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. We have no natural gas production associated with the East Slopes Project.

 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 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. 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
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.

 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. 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. The Ball reservoir is estimated to be 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. 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 three development wells and one
SWD well in our East Slopes project area in the 2024 – 2025 fiscal year once additional financing is put in place. When new
financing is secured, the capital investment required for the three development wells and one SWD well is approximately
$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
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, 2023.

 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.

 Reserve Category

 Crude Oil (Barrels)

 Natural Gas (Mcf)

 Total Crude Oil

 Percent of Oil

 Developed

 384,189

 100.0
 %

 Undeveloped

 —

 —

 —

 —

 Total Proved

 384,189

 100.0
 %

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

 (BOE)

 Balance as of February 28, 2022

 517,155

 Revisions

 (393,076
)

 Discoveries and extensions

 —

 Purchase of minerals

 287,582

 (17,751
)

 Balance as of February 28, 2023

 Revisions. Net upward revisions of 6,235
BOE of developed reserves in aggregate were due to the higher net crude oil and natural gas prices we received during the twelve months
ended February 28, 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, 2023, we had no discoveries or extensions of reserves.

 Purchase of minerals. For the twelve
months ended February 28, 2023, we acquired through the Reabold subsidiary acquisition 287,582 BOE of developed reserves.

 Production. Production was 17,751 BOE
in aggregate of developed reserves for the twelve months ended February 28, 2023.

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

 Proved Reserves (BOE)

 Balance as of February 28, 2022

 399,311

 Revisions

 (399,311
)

 Balance as of February 28, 2023

 —

 Revisions. A downward revision of 399,311
BOE of proved undeveloped reserves occurred for the twelve months ended February 28, 2023. 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.

 Our estimated net proved developed producing reserves
in California at February 28, 2023 are set forth in the table below.

 Proved Developed Reserves

 Natural

 Total Oil

 Percent of Oil

 Location

 Oil (Barrels)

 Gas (Mcf)

 East Slopes Project

 116,019

 —

 116,019

 29.5
 %

 Reabold Project

 268,170

 277,891

 70.5
 %

 California Total

 384,189

 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.

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

 PV-10 as a

 Total Oil

 PV-10 of

 Percentage of

 Location

 East Slopes Project

 116,019

 2,045,924

 18.5
 %

 Reabold Project

 277,891

 8,990,030

 81.5
 %

 California Total

 11,035,954

 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 $11.0 million at February 28, 2023 an increase of approximately $4.8 million or 77.4% from the PV-10 reserve valuation
of approximately $6.2 million at February 28, 2022. This increase is primarily due to the acquisition of the Reabold project in California.
The commodity prices used to estimate proved reserves and their related PV-10 at February 28, 2023 were based on the 12-month unweighted
arithmetic average of the 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 was $93.55 per barrel of crude oil in comparison to $71.69 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, 2023 reserve report of $90.43 in comparison to $68.80 in the February 28, 2022 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

 Our estimated proved developed reserves of 116,019
BOE for the East Slopes project in Kern County for the twelve months ended February 28, 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.

 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.

 PETROtech is an independent petroleum engineering
consulting firm registered in the State of California, and Bradford DeWitt, a Petroleum Engineer, is the technical person at PETROtech
primarily responsible for evaluating the proved reserves covered by their report. Mr. DeWitt has a Bachelor of Arts degree from the University
of California – Los Angeles ("U.C.L.A") and a Master of Science degree in Engineering from the University of Southern
California ("U.S.C."). He is a registered petroleum engineer in the State of California. The services provided by PETROtech
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 PETROtech, refer to the copy of their report filed as Exhibit 99.2 to this Annual Report
on Form 10-K.

 Our 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 1984 graduate of University of Southern Mississippi in Hattiesburg,
Mississippi with a Bachelor of Science Degree in Geology and is a certified Petroleum Geologist and a member, in good standing, of the
American Association of Petroleum Geologists and is a registered professional geologist in Mississippi. Mr. Greer has over 40 years of
experience in petroleum exploration, 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, 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.

 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.

 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)

 —

 —

 Total (BOE)

 17,751

 9,613

 10,970

 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,

 2023

 2022

 2021

 Crude Oil and Gas Revenue:

 Crude oil – Kern County (East Slopes)

 $
 728,439

 $

 $
 404,901

 Crude Oil – Monterey and Contra Costa Counties (Reabold)

 804,821

 —

 —

 Natural gas – Contra Costa County (Reabold)

 80,026

 —

 —

 Total revenue

 $
 1,613,286

 $

 $
 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,

 2023

 2022

 2021

 Average Realized Price:

 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,

 2023

 2022

 2021

 Average Production Expense (BOE):

 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, 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

 Total

 Gross

 Net

 Gross

 Net

 Gross

 Net

 California – Kern County

 2,694

 1,010

 3,494

 1,302

 California – Monterey and Contra Costa Counties

 4,372

 2,186

 4,732

 2,366

 Total

 1,160

 7,066

 3,196

 8,226

 3,668

 Average working interest

 36.5
 %

 44.2
 %

 42.7
 %

 Undeveloped Acreage Expirations

 We have no gross and net undeveloped acreage in California
expiring over the next three years as all of our gross and net acreage is currently held by production.

 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 was no likely benefit to pursuing any drilling opportunities on our expiring leases, and so we have not attempted to renew
those leases when their expiration dates occurred.

 Producing Wells

 The following table sets forth our gross and net productive
crude oil wells in California as of February 28, 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 Wells

 Net Wells

 Kern County (East Slopes)

 7.3

 Monterey and Contra Costa Counties (Reabold)

 5.0

 Total

 12.3

 Weighted average - working interest

 41.0
 %

 Drilling Activity

 In the past three years, we have had no drilling activity
occur due to the volatility of crude oil prices and the lack of available drilling capital.

 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.

 ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 As of February 28, 2023, our Common Stock was 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.

 In September 2023, information on our Common Stock
became available in 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. We anticipate
that once we are current in 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.

 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.

 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

 The transfer agent for our Common Stock is ClearTrust,
LLC, 16540 Pointe Village Dr, Suite 210 Lutz, Florida 33558. Their website address is:

 On December 18, 2023, the Board of Directors of Daybreak
appointed ClearTrust LLC "ClearTrust") as its transfer agent and shareholder support provider. By December 31, 2023, all the
Company's directly held shares of Common Stock, files and information were transferred from Sedona Equity Registrar & Transfer, Incorporated
("Sedona") to ClearTrust. In this capacity, ClearTrust will now 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 required on the part of the shareholder.

 Dividend Policy

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

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 Stock. For more information on this issuance please refer to Note 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
make any cash distributions on its Common Stock in the foreseeable future.

 Preferred Stock

 With the filing of the Company's Second Amended
and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, the Company no longer has any preferred stock.
The Company has only one class of stock, which is Common Stock.

 Series A Convertible Preferred Stock

 At February 28, 2022, there were no issued or outstanding
shares of Series A Preferred stock that had not been converted into our Common Stock. With the filing of the Company's Second Amended
and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, the Company no longer has any preferred stock.
The Company has only one class of stock, which is Common Stock.

 Conversion:

 At February 28, 2022, there were no shares of Series
A Preferred stock that had not been converted into our Common Stock. The conversions of Series A Preferred that have occurred since the
Series A Preferred was first issued in July 2006 are set forth in the table below.

 Fiscal Period

 Shares of Series A

 Preferred Converted

 to Common Stock

 Shares of

 Issued from

 Conversion

 Number of

 Accredited

 Investors

 Year Ended February 29, 2008

 102,300

 306,900

 Year Ended February 28, 2009

 237,000

 711,000

 Year Ended February 28, 2010

 51,900

 155,700

 Year Ended February 28, 2011

 102,000

 306,000

 Year Ended February 29, 2012

 —

 —

 —

 Year Ended February 28, 2013

 18,000

 54,000

 Year Ended February 28, 2014

 151,000

 453,000

 Year Ended February 28, 2015

 3,000

 9,000

 Year Ended February 29, 2016

 10,000

 30,000

 Year Ended February 28, 2017

 —

 —

 —

 Year Ended February 28, 2018

 14,997

 44,991

 Year Ended February 28, 2019

 —

 —

 —

 Year Ended February 29, 2020

 —

 —

 —

 Year Ended February 28, 2021

 —

 —

 —

 Year Ended February 28, 2022

 709,568

 Totals

 1,399,765

 4,199,295

 Dividends:

all accumulated dividends of $2,449,979 were paid through the issuance of 1,100,000 shares of Common Stock. At a special meeting of shareholders
on May 20, 2022 the Company's shareholders approved the Second Amended and Restated Articles of Incorporation, which eliminated
the classification of the Series A Preferred stock. Cumulative dividends earned on our Series A Preferred stock 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

 $
 155,311

 February 29, 2008

 242,126

 February 28, 2009

 209,973

 February 28, 2010

 189,973

 February 28, 2011

 173,707

 February 29, 2012

 163,624

 February 28, 2013

 161,906

 February 28, 2014

 151,323

 February 28, 2015

 132,634

 February 29, 2016

 130,925

 February 28, 2017

 130,415

 February 28, 2018

 128,231

 February 28, 2019

 127,714

 February 29, 2020

 128,063

 February 28, 2021

 127,714

 —

 96,340

 $
 2,449,979

 The Company is authorized to issue up to 500,000,000
shares of $0.001 par value Common Stock of which 384,734,902 and 67,802,273 shares were issued and outstanding as of February 28, 2023,
and February 28, 2022, respectively.

 Balance

 Par Value

 Common Stock, Issued and Outstanding, February 28, 2021

 60,491,122

 Shares issued for Series A Preferred conversion

 $
 2,129

 Shares issued for Series A accumulated dividend

 1,100,000

 $
 1,100

 Shares issued for debt conversion of accrued salaries

 1,397,880

 $
 1,398

 Shares issued for debt conversion of accrued directors fees

 317,708

 $

 Shares issued for conversion of 12% Note principal and interest – related party

 1,144,415

 $
 1,144

 Shares issued for investment principal in production revenue program

 1,222,444

 $
 1,222

 Common Stock, Issued and Outstanding, February 28, 2022

 67,802,273

 Shares issued for conversion of 12% Note principal and interest

 78,934

 $

 Shares issued for conversion of convertible note

 $
 27,765

 Shares issued for acquisition of crude oil and natural gas properties

 $
 160,964

 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
)

 $

 Common Stock, Issued and Outstanding, February 28, 2023

 384,734,902

 During the twelve months ended February 28, 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 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. In December 2023, we were notified of a system error that had occurred in the recording of street
stock shares held by the nominee. Accordingly, the number of our issued and outstanding shares was reduced by 500 shares as of February
28, 2023. The common stock par value of this adjustment was $0.50.

 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.

 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, 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 expired on January 2, 2024.

 As of February 28, 2023, and February 28, 2022, there
were 2,100,000 and 893,333 exercisable warrants. At February 28, 2023, both the outstanding warrants and the exercisable warrants had
a weighted average exercise price of $0.01; a weighted average remaining life of 0.83 years, and an intrinsic value of $25,200. The recorded
amount of warrant expense for the twelve months ended February 28, 2023, and February 28, 2022 was $-0- and $4,913, respectively. The
warrant expense was fully amortized at February 28, 2022.

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

 Weighted Average

 Exercise Price

 Warrants outstanding, February 28, 2021

 $

 0.01

 Changes during the twelve months ended February 28, 2022:

 Issued

 —

 Expired / Cancelled / Forfeited

 —

 Warrants outstanding, February 28, 2022

 $

 0.01

 Warrants exercisable, February 28, 2022

 893,333

 Changes during the twelve months ended February 28, 2023:

 Issued

 —

 $

 Expired / Cancelled / Forfeited

 —

 Warrants outstanding, February 28, 2023

 $

 0.01

 Warrants exercisable, February 28, 2023

 $

 0.01

 Recent Sales of Unregistered Securities; Use of
Proceeds from Registered Securities

 On 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, 2023 and February 28, 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 two multi-well oilfield
projects; one in Kern County, California and the other in Monterey and Contra Costa Counties in California.

 Our management cannot provide any assurances that
Daybreak will ever operate profitably. While, in the past, we have had positive cash flow 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, 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 projects in California. Refer to our discussion in Item 2. Properties, in this Annual Report on Form 10-K for more information on
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)

 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, 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 27.6%, respectively.

 Monterey and Contra Costa Counties, California (Reabold project)

 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 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 prices we receive for crude oil sales in California
from the East Slopes project and from our Reabold subsidiary project are based on prices posted for Midway-Sunset and Buena Vista crude
oil delivery contracts, respectively. All posted pricing is subject to adjustments that vary by grade of crude oil, transportation costs,
market differentials and other local conditions. Both the posted Midway-Sunset and Buena Vista prices generally move in correlation to
prices quoted on the New York Mercantile Exchange ("NYMEX") for spot West Texas intermediate ("WTI") crude oil,
Cushing, Oklahoma delivery contracts.

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

 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, 2023 increased $853,153 or 125.4% to $1,533,260 in comparison to revenue of $680,107 for the twelve months ended February
28, 2022. The average sale price of a barrel of crude oil for the twelve months ended February 28, 2023 was $89.59 in comparison to $70.75
for the twelve months ended February 28, 2022. The increase in the average realized sales price of $18.84 or 26.6% per barrel accounted
for 21.2% of the increase in crude oil revenue for the twelve months ended February 28, 2023.

 Our net sales volume of crude oil for the twelve months
ended February 28, 2023 was 17,114 barrels of crude oil in comparison to 9,613 barrels sold for the twelve months ended February 28, 2022.
The increase in crude oil sales volume of 7,501 barrels or 78.0% was primarily due to the acquisition of our Reabold subsidiary in May
of 2022 and this overall increase in crude oil sales volume accounted for 78.8% of the increase in crude oil revenue for the twelve months
ended February 28, 2023.

 The gravity of our produced crude oil from the East
Slopes project in Kern County ranges between 15 API and 17 API. Production for the twelve months ended February 28, 2023 and
February 28, 2022 was from 20 wells. The gravity of our produced crude oil from our Reabold subsidiary in Monterey and Contra Costs Counties
is approximately 17 API and 38 API, respectively. Production for the twelve months ended February 28, 2023 was primarily from
five wells.

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

 Project

 Revenue

 Revenue

 East Slopes project – crude oil sales

 $
 728,439

 47.5
 %

 $

 100.0
 %

 Reabold project – crude oil sales

 804,821

 52.5
 %

 —

 —

 Crude oil Totals

 $
 1,533,260

 100.0
 %

 $

 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.

 Of the $853,153 or 125.4% increase in crude oil revenue
for twelve months ended February 28, 2023 approximately $672,040 or 78.8% can be attributed to the increase in sales volume mainly due
to our Reabold subsidiary acquisition.

 California Natural Gas 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.

 Percentage Change

 Average twelve month Henry Hub natural gas price (Mcf)

 $
 6.35

 $
 —

 %

 Average twelve month realized natural gas sales price (Mcf)

 $
 20.94

 $
 —

 %

 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
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

 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.

 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:

 Project

 Revenue

 Revenue

 East Slopes project – crude oil sales

 $
 728,439

 45.1
 %

 $

 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
 %

 $

 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 $2,956,413 or 314.2%
to $3,897,299 for the twelve months ended February 28, 2023 in comparison to $940,886 for the twelve months ended February 28, 2022. Our
operating expenses are set forth in the table below:

 Expenses

 BOE
 Basis

 Expenses

 BOE
 Basis

 Production expenses

 $
 1,103,825

 28.3
 %

 $
 231,275

 24.6
 %

 Exploration and drilling expenses

 —

 —
 %

 56,213

 6.0
 %

 Depreciation, depletion, amortization ("DD&A")

 504,118

 12.9
 %

 49,590

 5.3
 %

 Impairment expense

 711,873

 18.3
 %

 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 contract pumper, electricity, road maintenance, control of
well insurance, property taxes, well maintenance and workover expenses; and, relate directly to the number of wells that are on
production. For the twelve months ended February 28, 2023, these expenses increased $872,550, or 377.3% to $1,103,825 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 20
wells on production for the twelve months ended February 28, 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 replacement and upgrading of pumps in seven wells of the East Slopes project for $56,549 and the expenses
associated with salt water disposal of $426,838 from the Reabold properties. A salt water disposal well is currently being permitted
which, when put into operation is expected to significantly lower operating costs of the Reabold project. Production expenses on a
BOE basis for the twelve months ended February 28, 2023 and February 28, 2022 were $62.18 and $24.06, respectively. Production
expenses represented 28.3% and 24.6% of total operating expenses for the twelve months ended February 28, 2023 and February 28,
2022, respectively.

 Exploration and drilling expenses include geological
and geophysical ("G&G") expenses as well as leasehold maintenance, plugging and abandonment ("P&A") expenses
and dry hole expenses. These expenses decreased $56,130 to $-0- for the twelve months ended February 28, 2023 in comparison to $56,130
for the twelve months ended February 28, 2022. Exploration and drilling expenses represented -0-% and 6.0% of total operating expenses
for the twelve months ended February 28, 2023 and February 28, 2022, respectively.

 Depreciation, Depletion, Amortization
("DD&A") expense relates to equipment, proven reserves and property costs, and is another component of operating
expenses. These expenses increased $454,528 or 916.6% to $504,118 for the twelve months ended February 28, 2023 in comparison to
$49,590 for the twelve months ended February 28, 2022. The primary reason for the increase in DD&A expense was due to the
recognition of the Reabold subsidiary wells and equipment and their projected production life. On a BOE basis, DD&A expense in
California for the twelve months ended February 28, 2023, and February 28, 2022 was $28.40 and $5.16, respectively. DD&A
expenses represented 12.9% and 5.3% of total operating expenses for the twelve months ended February 28, 2023, and February 28,
2022, respectively.

 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.

 For the twelve months ended February 28, 2023,
we incurred transaction expenses of $573,472 related to the acquisition of funding and to acquire the Reabold crude oil and natural
gas properties located in central California. For the twelve months ended February 28, 2022, we did not incur any related expenses.
Transaction expenses represented 14.7% and 0.0% of total operating expenses for the twelve months ended February 28, 2023 and
February 28, 2022, respectively.

 General and administrative ("G&A")
expenses include the salaries of five employees, including 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 $400,203 or 66.3% to $1,004,011 in comparison to $603,808 for the twelve months ended February 28, 2022. The
primary reasons for the increase in G&A expense are related to the expenses of both the special shareholders and the annual shareholders
meetings, in the amount of approximately $131,394 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, 2023 and February 28, 2022, respectively.

 Interest expense, net for the twelve months ended February 28, 23 decreased
$74,861 or 34.0% to $145,224 in comparison to $220,085 for the twelve months ended February 28, 2022.

the Company recognized a gain on asset disposal of $9,614. The gain was the result of an insurance settlement on the theft of a company
vehicle that was fully depreciated. Additionally, during the twelve months ended February 28, 2022, the Company recognized a gain on debt
forgiveness in the amount of $72,800 due to notification that the SBA had approved the company's application for loan forgiveness
on the PPP 2 nd 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.

 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 volatility in our realized sale price of crude oil and natural gas does exist. One example of
this volatility is that in March 2022, our realized price per barrel of crude oil was $108.08, while in November 2022, it was $84.40 and
in February 2023 it was $71.85 per barrel. Another example of this volatility is that in June 2022 our realized price per Mcf of natural
gas in California was $11.03, while in November 2022 it was $7.59 and in January 2023 it was $58.03 per Mcf. This volatility in crude
oil and natural gas prices has continued throughout the fiscal year ended February 28, 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 three development wells and one SWD well for an approximate total of $800,000.

 Changes in our capital resources at February 28, 2023
are set forth in the table below:

 Increase
 (Decrease)

 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
 %)

 Our working capital 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 the working capital deficit was primarily due to the proceeds we received in
connection with the sale of Common Stock and the acquisition of our Reabold California, LLC subsidiary current assets. We anticipate an
increase in our cash flow will occur when we are able to return to our planned drilling program that will result in an increase in the
number of successful wells on production.

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

 Major sources of funds in the past for us have included
the debt or equity markets. 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 and natural gas prices has restricted our ability to obtain needed capital.

 The Company's financial statements for the twelve
months ended February 28, 2023 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement
of liabilities in the normal course of business. We have incurred a cumulative net loss since entering the crude oil and natural gas exploration
industry in 2005. As of February 28, 2023, we have an accumulated deficit of approximately $31.96
million and a working capital deficit of approximately $2.1 million which raises substantial doubt about our ability to continue
as a going concern.

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

 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.

 Accounts Payable – Related 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

 Twelve Months
 Ended

 Increase
 (Decrease)

 Change

 Net cash (used in) operating activities

 $
 (315,117
)

 $
 (13,356
)

 $
 301,761

 2,259.4
 %

 Net cash (used in) investing activities

 $
 (386,160
)

 $
 (16,232
)

 $
 369,928

 2,279.0
 %

 Net cash provided by financing activities

 $
 1,136,114

 $
 135,633

 $
 1,000,481

 737.6
 %

 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, 2023 was $315,117 in comparison
to cash flow used in our operating activities of $13,356 for the twelve months ended February 28, 2022. Changes in our cash flow used
for operating activities for the twelve months ended February 28, 2023 in comparison to the twelve months ended February 28, 2022 increased
$301,761 and were mainly a result of the expense of our annual shareholders meeting and the Reabold subsidiary acquisition. We had increases
in our non-cash expenses of $1,266,587, primarily from recognition of impairment of proved undeveloped locations acquired in the Reabold
acquisition of $711,873 and an increase in DD&A of $454,498, a decrease in changes in assets of $107,445 that was offset by an increase
in changes in liabilities of $569,884 and the increase in our net loss for the year of approximately $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 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, 2023
we used cash flow of $386,160 in comparison to cash flow used for investing activities of $16,232 for the twelve months ended February
28, 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 $1,136,114 for the twelve months ended February 28, 2023 in comparison to cash flow provided by our financing activities
of $135,633 for the twelve months ended February 28, 2022. For the twelve months ended February 28, 2023, we secured a capital raise of
$1,987,500 net of transaction expenses from the sale of 125,000,000 shares of our Common Stock. We also paid off the balance of $808,182
on the line of credit with UBS Bank during the twelve months ended February 28, 2023.

 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 Stock as a part of the settlement agreement.
Based on the closing price of the Company's Common Stock on the date of the settlement agreement, the value of the Common Stock
transaction was determined to be $6,000. The Common Stock shares were issued during the twelve months ended February 29, 2020. The note
had a maturity date of January 1, 2022 and bears an interest rate of 10% rate per annum. 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 1 st of each anniversary date of the note. At February 28, 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 $26,000 and $38,000 at February 28, 2023
and February 28, 2022, respectively.

 Note Payable – Related Party

 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 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, 2023, the Company made principal payments of $8,829 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 Westmoreland 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 Westmoreland 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.

 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, current portion

 $
 9,065

 $
 8,829

 Unamortized debt issuance expenses

 (728
)

 (729
)

 Note payable – related party, current portion, net

 $
 8,337

 $
 8,100

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

 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,

 2024

 9,065

 2025

 9,309

 2026

 9,558

 2027

 9,815

 2028

 10,078

 Thereafter

 88,885

 Total

 $

 136,710

 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 was 18% per annum and was payable in kind ("PIK")
solely by additional shares of the Company's Common Stock. Regardless of when the conversion occurred, a full 12 months of interest
would be payable upon conversion. On May 5, 2022, the Company received notice of conversion of the promissory note. The face amount of
the note and $36,000 in interest were converted at a rate of $0.0085 per share into 27,764,706 share of the Company's Common Stock
during the twelve months ended February 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, had a balance at February 28, 2023 and February
28, 2022 of $290,000 and $315,000, respectively. The original maturity date of January 29, 2015 had been extended to January 29, 2017
and then was extended to January 29, 2019. Interest accrues at 12% per annum, payable semi-annually on January 29th and July 29th.

 The Company has informed the remaining Note 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, 2023 and February 28, 2022 was $159,508 and $135,229, respectively. The terms of the Notes,
state that should the Board of Directors decide that the payment of the principal and any unpaid interest would impair the financial condition
or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company's
Common Stock at a conversion rate equal to 75% of the average closing price of the Company's Common Stock over the 20 consecutive
trading days preceding December 31, 2018.

 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 – third party

 $

 $

 12% subordinated notes – related party

 —

 —

 12% Subordinated notes balance

 $

 $

 Line of Credit

 At February 28, 2022, the Company had an existing
$890,000 line of credit for working capital purposes with UBS Bank USA that was established pursuant to a Credit Line Agreement dated
October 24, 2011 and was secured by the personal guarantee of our President and Chief Executive Officer. During the twelve months ended
February 28, 2023, and February 28, 2022, the Company did not receive any advances on the line of credit.

 On May 26, 2022, the Company
paid off the outstanding balance of $809,930 on the line of credit. The payoff of the line of credit was previously approved under terms
of the Equity Exchange Agreement in which the Company acquired the Reabold property in California. The line of credit payoff was a part
of the use of proceeds from the Company's sale of Common Stock to a third party. At February 28, 2023, and February 28, 2022, the
line of credit had an outstanding balance of $-0- and $808,182, respectively. 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

 During the twelve months ended February 28, 2019,
and February 29, 2020, the Company conducted a fundraising program to raise $1.3 million to fund the drilling of future wells in California
and to settle some of its historical debt. The purchasers of a production revenue payment interest are to receive a production revenue
payment interest on future wells to be drilled in California in exchange for their purchase. The Company shall pay seventy-five percent
(75%) of its future net production revenue from the relevant wells to the purchasers until each purchaser has received two times the purchase
price (the "Production Payment Target"). Once the Company pays the purchaser group amounts equal to the Production Payment
Target, it shall thereafter pay a pro-rated eight percent (8%) of $1.3 million on its net production payments from the relevant wells
to the purchaser group. However, if the total raise amount is less than the target $1.3 million, then the payment will be a proportionate
amount of the eight percent (8%).

 The Company accounted for the amounts received from
these sales in accordance with ASC 470-10-25 and 470-10-35 which require amounts recorded as debt to be amortized under the interest method
as described in ASC 835-30, Interest Method. Consequently, the program balance of $873,281 has been recognized as a production revenue
payable. The Company determined an effective interest rate based on future expected cash flows to be paid to the holders of the production
payment interests. This rate represents the discount rate that equates estimated cash flows with the initial proceeds received from the
sales and is used to compute the amount of interest to be recognized each period. Estimating the future cash outflows under this agreement
requires the Company to make certain estimates and assumptions about future revenues and payments and such estimates are subject to significant
variability. Therefore, the estimates are likely to change which may result in future adjustments to the accretion of the interest expense
and the amortized cost based carrying value of the related payables.

 Accordingly, the Company has estimated the cash flows
associated with the production revenue payments of $913,395 and determined a discount of $78,136 as of February 28, 2023, 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, 2023, and February 28, 2022, amortization of the debt discount on these payables amounted to $56,156
and $95,974, respectively, which has been included in interest expense in the statements of operations.

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

 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

 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 formally leased approximately 988 rentable
square feet of office space from an unaffiliated third party for our corporate office located in Spokane Valley, Washington. This office
was closed in March of 2023 when the corporate office was consolidated with our Friendswood, Texas regional operations office. We currently
lease approximately 416 and 695 rentable square feet from unaffiliated third parties for our new corporate office in Friendswood, Texas
and storage and auxiliary office space in Wallace, Idaho, respectively. The lease in Friendswood is a 12-month lease that expired in October
2023 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 Wallace lease 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, 2023, and February 28, 2022 was $23,889 and $23,489, respectively.

 Crude Oil and Natural Gas Reserves

 Daybreak's total net proved developed crude
oil and natural gas reserves on a per barrel of oil equivalent ("BOE") basis increased by 276,066 BOE, or 234.3%, to 393,910
BOE at February 28, 2023 compared to 117,844 BOE at February 28, 2022. The primary reason for the increase in developed reserves was the
acquisition of our Reabold subsidiary in May of 2022. Of our proved developed reserves at February 28, 2023, the Reabold subsidiary represented
277,891 BOE or 71% of our total proved developed reserves. The East Slopes project represented 116,019 BOE or 29% of our proved developed
reserves. 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. These proved developed reserves are all located in our California East Slopes and Reabold
subsidiary projects.

 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, 2023, we received
crude oil and natural gas sales revenue from 20 wells in our East Slopes project in Kern County and eight wells in our Reabold subsidiary
in Monterey and Contra Costa Counties all located in California. For the twelve months ended February 28, 2023, and February 28, 2022,
crude oil and natural gas sales revenue from California was $1,613,286 and $680,107, respectively. Of the $933,179 increase in revenue
during the twelve months ended February 28, 2022, $193,546 or 20.7% 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, 2023, and February 28, 2022, we had an operating loss of $2,284,013 and $260,779, respectively. Our commitment
to improving corporate profitability remains unchanged.

 Our balance sheet at February 28, 2023 reflects total
assets of approximately $7.7 million, an increase of approximately $6.7 million in comparison to approximately $0.98 million at February
28, 2022. This increase of approximately $6.7 million in total assets was largely due to the acquisition of our Reabold subsidiary in
May of 2022. Our cash balance increased by approximately $160,000.

 At February 28, 2023, total liabilities were approximately
$4.5 million, an increase of approximately $0.2 million in comparison to approximately $4.3 million at February 28, 2022. This increase
was primarily due to the recognition of the ARO liability associated with the crude oil and natural gas wells acquired in the Reabold
acquisition.

 Common Stock shares issued and outstanding at February
28, 2023 and February 28, 2022 were 384,734,902 and 67,802,273, respectively. The increase in Common Stock shares of 316,932,629 is directly
related to either the acquisition of our Reabold subsidiary or the issuance of Common Stock shares for financing and a share issuance
adjustment of 500 shares.

 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.

 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, 2023, and February 28, 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.

 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.

 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 $299,410 and $139,573 at February 28, 2023 and February 28, 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 $933,179
or 137.2% to $1,613,286 for the twelve months ended February 28, 2023, in comparison to $680,107 for the twelve months ended February
28, 2022. Of the $933,179 increase in revenue during the twelve months ended February 28, 2023, $739,633 or 79.3% can be attributed to
the increase in crude oil and natural gas sales volume primarily due to the acquisition of our Reabold subsidiary.

 Operating Expenses

 Operating expenses for the twelve months ended February
28, 2023 increased approximately $3.0 million or 314.2% to approximately $3.9 million in comparison to approximately $940,886 for the
year ended February 28, 2022. This increase was primarily due to one-time expenses associated with completing the acquisition of our Reabold
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, 2023, and
February 28, 2022, we reported operating losses of approximately $2.3 million and $260,779, respectively. The increase in the operating
loss for the twelve months ended February 28, 2023, of approximately $2.0 million was primary 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.

 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, 2023 we reported a net loss of approximately
$2.4 million in comparison to net loss of $398,450 for the twelve months ended February 28, 2022.

 Management Plans to Continue as a Going Concern

 We continue to implement plans to enhance our 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 for the Company. Our average working
interest in 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%.

 On May 25, 2022, we 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. 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.

 At the same special meeting of shareholders held on
May 20, 2022, approval was granted to Amend and Restate the Company's Articles of Incorporation. This allowed 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 gave the Company enough authorized Common Stock shares to complete the transaction for the Reabold project. 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 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.

 We anticipate revenues will continue to increase as
we participate in the drilling of more wells in both the East Slopes and Reabold projects in California. Our sources of funds in the past
have included the debt or equity markets and the sale of assets. While we have experienced periodic revenue growth, which has resulted
in positive cash flow from its crude oil and natural gas properties, we have not yet established a positive cash flow on a company-wide
basis. It will be necessary for us to obtain additional funding from the private or public debt or equity markets in the future. However,
we cannot offer any assurance that our efforts will be successful in executing the aforementioned plans to continue as a going concern.
Our financial statements as of February 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.

 Off-Balance Sheet Arrangements

 As of February 28, 2023, 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.

 Commitments and Contingencies

 Various lawsuits, claims,
threatened legal actions, and other contingencies arise in the ordinary course of our business activities. In our opinion, the disposition
of any such matters is not expected, individually or in the aggregate, to have a material adverse effect on our results of operations,
financial condition or cash flows. However, the results of legal actions cannot be predicted with certainty. Therefore, it is possible
that our results of operations, financial condition or cash flows could be materially adversely affected in any particular period by the
unfavorable resolution of one or more legal actions.

 We, as an owner or lessee and operator of oil and
gas properties, are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection
of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for
the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances,
we may be directed to suspend or cease operations in the affected area. We maintain insurance coverage that is customary in the industry,
although we are not fully insured against all environmental 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.

 The Company is not aware of any environmental claims
existing as of January 23, 2 024. 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.

 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, 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.

 Revenue Recognition

 The Company recognizes revenue under ASC 606, Revenue
from Contracts with Customers ("Topic 606"). Under Topic 606, revenue is generally recognized upon delivery of our produced
crude oil and natural gas volumes to our customers. Our customer sales contracts include 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 or natural gas MMBTU) represents a separate performance obligation which is sold at variable prices,
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 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.

 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.

 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.

 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 Daybreak Oil and Gas, Inc. (the "Company") as of February 28, 2023 and February 28, 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, 2023 and February 28, 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

 January 23,
2024

 Balance Sheets

 As of February
28, 2023 and February 28, 2023

 As of February 28,

 2023

 As of February 28,
 2022

 ASSETS

 CURRENT ASSETS:

 Cash and cash equivalents

 $
 299,410

 $
 139,573

 Restricted cash

 275,000

 —

 Accounts receivable:

 Crude oil sales

 131,510

 Joint interest participants

 353,009

 85,339

 Prepaid expenses and other current assets

 95,034

 74,012

 Total current assets

 1,153,963

 416,651

 OIL AND GAS PROPERTIES, successful efforts method, net

 Proved developed properties

 5,126,200

 536,032

 Prepaid drilling costs

 16,452

 16,452

 Vehicles and Equipment, net

 3,416

 6,569

 Goodwill – crude oil and natural gas properties

 1,415,361

 —

 Total long-term assets

 6,561,429

 559,053

 Total assets

 $
 7,715,392

 $
 975,704

 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

 CURRENT LIABILITIES:

 Accounts payable and other accrued liabilities

 $
 2,129,208

 $
 1,649,119

 Accounts payable – related parties

 21,937

 49,228

 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 $ 728 and $ 729, respectively

 8,337

 8,100

 Convertible Note payable, related party

 —

 200,000

 12% Note payable

 Line of credit

 —

 808,182

 Production revenue payable, current, net of unamortized discount

 56,915

 78,877

 Total current liabilities

 3,254,246

 3,404,735

 LONG TERM LIABILITIES:

 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

 816,366

 738,248

 Asset retirement obligation

 315,509

 52,565

 Total long-term liabilities

 1,250,898

 918,173

 Total liabilities

 4,505,144

 4,322,908

 COMMITMENTS AND CONTINGENCIES

 STOCKHOLDERS' EQUITY (DEFICIT):

 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

 Additional paid-in capital

 34,785,207

 26,115,450

 Accumulated deficit

 ( 31,959,693
)

 ( 29,530,456
)

 Total stockholders' equity (deficit)

 3,210,248

 ( 3,347,204
)

 Total liabilities and stockholders'
 equity (deficit)

 $
 7,715,392

 $
 975,704

 Statements of Operations

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

 Twelve Months
 Ended

 Twelve Months
 Ended

 REVENUE:

 Crude oil sales

 $
 1,533,260

 $

 Natural gas sales

 80,026

 —

 Total crude oil and natural gas sales

 $
 1,613,286

 $

 OPERATING EXPENSES:

 1,103,825

 231,275

 Exploration and drilling

 —

 56,213

 Depreciation, depletion and amortization

 504,118

 49,590

 Impairment of crude oil and natural gas properties

 711,873

 —

 Transaction expenses

 573,472

 —

 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

 ( 145,224
)

 ( 220,085
)

 Gain on asset disposal

 —

 9,614

 Gain on debt forgiveness – SBA paycheck protection program (PPP) loan

 —

 72,800

 Total other expenses

 ( 145,224
)

 ( 137,671
)

 NET LOSS AVAILABLE TO COMMON SHAREHOLDERS

 $
 ( 2,429,237
)

 $
 ( 398,450
)

 NET LOSS PER COMMON SHARE

 Basic and diluted

 $
 ( 0.01
)

 $
 ( 0.01
)

 WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING

 Basic and diluted

 312,312,114

 61,548,414

 Crude Oil Sales

 Natural Gas Sales

 Statements of Changes
in Stockholders' Equity (Deficit)

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

 Series A Convertible

 Additional

 Preferred Stock

 Paid-In

 Accumulated

 Shares

 Amount

 Shares

 Amount

 Capital

 Deficit

 Total

 BALANCE, FEBRUARY 28, 2021

 709,568

 $

 60,491,122

 $
 60,491

 $
 24,250,556

 $
 ( 29,428,897
)

 $
 ( 5,117,140
)

 Issuance of Common Stock for:

 Conversion of accrued employee salaries

 —

 —

 1,397,880

 1,398

 627,649

 52,530

 681,577

 Conversion of accrued director fees

 —

 —

 317,708

 142,651

 —

 142,969

 Conversion of 12% Note principal and interest –
 related party

 —

 —

 1,144,415

 1,144

 513,842

 —

 514,986

 Conversion of production revenue program principal –
 related party

 —

 —

 1,222,444

 1,222

 548,878

 —

 550,100

 Conversion of Series A preferred stock

 ( 709,568
)

 ( 710
)

 2,129

 ( 1,419
)

 —

 —

 Conversion of Series A accumulated dividend

 —

 —

 1,100,000

 1,100

 28,380

 ( 29,480
)

 —

 Recognition of warrants for:

 Investor relations services

 —

 —

 —

 —

 4,913

 —

 4,913

 Debt forgiveness accrued salary - related party

 —

 —

 —

 —

 —

 53,125

 53,125

 Debt forgiveness production revenue program interest
 – related party

 —

 —

 —

 —

 —

 232,170

 232,170

 Settlement of receivables and payables – related
 party

 —

 —

 —

 —

 —

 ( 11,454
)

 ( 11,454
)

 Net Loss

 —

 —

 —

 —

 —

 ( 398,450
)

 ( 398,450
)

 BALANCE, FEBRUARY 28, 2022

 —

 $
 —

 67,802,273

 $
 67,802

 $
 26,115,450

 $
 ( 29,530,456
)

 $
 ( 3,347,204
)

 Issuance of Common Stock for:

 Conversion of 12% Note principal
 and interest

 —

 —

 78,934

 35,441

 —

 35,520

 Conversion of convertible note

 —

 —

 27,765

 208,235

 —

 236,000

 Acquisition of crude oil and natural
 gas properties

 —

 —

 160,964

 6,438,580

 —

 6,599,544

 Sale of common stock

 —

 —

 125,000,000

 125,000

 1,862,500

 —

 1,987,500

 Shares issued for financing fees

 —

 —

 3,125,000

 3,125

 125,000

 —

 128,125

 Adjustment to common stock

 —

 —

 ( 500
)

 ( 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

 Additional Paid-In Capital

 Accumulated Deficit

 Series A Convertible Preferred Stock

 Statements of Cash Flows

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

 CASH FLOWS FROM OPERATING ACTIVITIES:

 Net loss

 $
 ( 2,429,237
)

 $
 ( 398,450
)

 Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

 Common stock shares issued as an incentive

 128,125

 —

 Gain on forgiveness of PPP 2 nd draw

 —

 ( 72,800
)

 Depreciation, depletion and amortization

 504,088

 49,590

 Impairment of proved crude oil properties

 711,873

 —

 Impairment of unproved crude oil properties

 —

 55,978

 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

 235,034

 ( 8,734
)

 Accounts receivable - joint interest participants

 ( 267,670
)

 ( 5,928
)

 Prepaid expenses and other current assets

 ( 21,022
)

 68,449

 Accounts payable and other accrued liabilities

 784,819

 52,922

 Accounts payable - related parties

 ( 27,291
)

 64,153

 Accrued interest

 ( 9,279
)

 79,848

 Net cash used in operating activities

 ( 315,117
)

 ( 13,356
)

 CASH FLOWS FROM INVESTING ACTIVITIES:

 Additions to crude oil and natural gas properties

 ( 417,248
)

 ( 6,772
)

 Acquisition of crude oil and natural gas properties

 31,088

 —

 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

 ( 808,182
)

 ( 60,000
)

 Proceeds from sale of Common Stock

 1,987,500

 —

 Proceeds from convertible note payable

 —

 200,000

 Insurance financing repayments

 ( 34,375
)

 ( 68,568
)

 Payments to note payable – related party

 ( 8,829
)

 ( 8,599
)

 Proceeds from SBA PPP 2 nd draw loan and 1 st draw loans, respectively

 —

 72,800

 Net cash provided by financing activities

 1,136,114

 135,633

 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 434,837

 106,045

 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

 139,573

 33,528

 CASH AND CASH EQUIVALENTS AT END OF PERIOD

 $
 574,410

 $
 139,573

 CASH PAID FOR:

 Interest

 $
 33,431

 $
 14,446

 Income taxes

 $
 —

 $
 —

 Statements of Cash Flows (continued)

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

 SUPPLEMENTAL CASH FLOW INFORMATION:

 Common stock issued for conversion of 12% Subordinated Note

 $
 35,520

 $
 —

 Common stock issued for conversion of convertible Note

 $
 236,000

 $
 —

 Common stock issued for acquisition of crude oil and natural gas property

 $
 6,599,544

 $
 —

 Goodwill from acquisition of O&G properties

 $
 1,415,361

 $
 —

 ARO asset and liability increase due to acquisition of crude oil and natural gas properties

 $
 79,622

 $
 —

 ARO asset and liability increase due to changes in estimates

 $
 159,477

 $
 10,929

 Non-cash addition to line of credit due to monthly interest

 $
 —

 $
 27,278

 Financing of insurance premiums

 $
 —

 $
 81,154

 Forgiveness of production revenue payable interest

 $
 —

 $
 232,170

 Settlement of accrued employee salaries credited to common stock, APIC and accumulated deficit

 $
 —

 $
 681,577

 Settlement of accrued director fees credited to common stock and APIC

 $
 —

 $
 142,969

 Settlement of 12% Note – related party credited to common stock and APIC

 $
 —

 $
 514,986

 Settlement of production revenue program – related party credited to paid in capital

 $
 —

 $
 550,100

 Settlement of Series A accumulated dividend credited to additional paid in capital

 $
 —

 $
 28,380

 Common stock issued for conversion of Series A preferred stock

 $
 —

 $

 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

 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. In March 2005, management of the
Company decided to enter the crude oil and natural gas exploration, development and production industry. On October 25, 2005, the Company's
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 or international pandemics like the coronavirus outbreak.

 NOTE 2 — GOING CONCERN:

 Financial Condition

 Daybreak's financial statements for the twelve
months ended February 28, 2023, and February 28, 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. Daybreak has incurred net losses since inception and has
accumulated a deficit of approximately $ 31.96 million and a working capital deficit of approximately
 $ 2.1 million, which raises substantial doubt about the Company's ability to continue
as a going concern.

 Management Plans to Continue as a Going Concern

 The Company continues to implement plans to enhance
its ability to continue as a going concern. Daybreak currently has a net revenue interest 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 %.

 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. 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.

 At the special shareholders meeting held on May 20,
2022, approval was also granted to Amend and Restate the Company's Articles of Incorporation. This allowed 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
allowed the Company to have enough authorized Common Stock shares to complete the transaction for the Reabold project. 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 of which 3,125,000 were an incentive to the investor.

 The Company anticipates revenue will continue to increase
as the Company participates in the drilling of more wells in the East Slopes and Reabold projects 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, 2023, and February 28, 2022 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, 2023 and February 28, 2022.

 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, 2023, the
Company recognized an impairment charge of $ 711,873 for the write down of proven undeveloped reserves in both the East Slopes and the
Reabold projects. 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.

 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 including cash, restricted cash, receivables, prepaid expenses, accounts payable, and other accrued liabilities, short-term
liabilities and 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.

 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 ("EPS") calculations are determined
by dividing net earnings (loss) available to Common Stockholders by the weighted average number of common shares issued and outstanding
during the year. Diluted earnings per common share are determined by dividing net income (loss) by the weighted average number of common
shares outstanding and, dilutive common share equivalents outstanding. During periods when common share equivalents, if any, are anti-dilutive
they are not considered in the 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

 Accounts Receivable

 At both the Company's projects in California
there is only one buyer for the purchase of all crude oil production. At February 28, 2023 and February 28, 2022, this one individual
customer represented 100 % 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.

 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:

 Summary of Significant Accounting Policies -
Schedule of Concentration of Risk, by Risk Factor

 Project

 Customer

 Accounts
 Receivable

 Accounts
 Receivable

 California – East Slopes project (crude oil)

 Plains Marketing

 $
 55,900

 42.5
 %

 $

 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
 %

 $

 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.

 Revenue Recognition

 The Company recognizes revenue under ASC 606, Revenue
from Contracts with Customers ("Topic 606"). Under Topic 606, revenue is generally recognized upon delivery of the Company's
produced crude oil and natural gas volumes to its customers. Customer sales contracts include 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 or natural gas MMBTU) represents a separate performance obligation which is sold at variable prices,
determinable on a monthly basis. The pricing provisions of 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 the Company operates. The Company allocates the transaction price to each performance obligation and recognize revenue
upon delivery of the commodity product when the customer obtains control. Control of the produced crude oil volumes passes to 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. Control of the Company's produced natural gas volumes
passes to its 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. The
crude oil and natural gas revenue streams include volumes burdened by royalty and other joint owner working interests. The Company's
revenues are recorded and presented on its financial statements net of the royalty and other joint owner working interests. The revenue
stream

 does not include 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.

 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.

 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.

 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.

 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

 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 $ 131,510 and $ 117,727 at February 28, 2023 and February 28, 2022, represent crude oil and natural gas sales that occurred in February
2023 and 2022, respectively.

 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
California, where the Company is the Operator.

 There were no allowances for doubtful accounts for
the Company's trade accounts receivable at February 28, 2023, and February 28, 2022.

 NOTE 5 — CRUDE OIL PROPERTIES:

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

 Crude
Oil Properties - Schedule of Crude Oil Activities

 Proved leasehold costs

 $
 115,119

 $
 115,119

 Costs of wells and development

 6,915,982

 2,309,628

 Capitalized exploratory well costs

 1,341,494

 1,341,494

 Property, plant and equipment (Reabold)

 320,217

 —

 Cost of crude oil and natural gas properties

 8,692,812

 3,766,241

 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, 2023 and
February 28, 2022, the Company recognized depletion expense of $ 477,089 and $ 38,125, 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, 2023 and February
28, 2022 was $ 711,873 and $- 0 -, respectively.

 NOTE 6 – ACQUISITION:

 On May 25, 2022, the Company finalized the acquisition
of Reabold from a third party for 160,964,489
 shares of the Company's Common Stock valued at $ 6,599,544.
The transaction balance of $ 6,863,163
 reflects the Common Stock valuation of the acquisition transaction and $ 263,619
 in reimbursements to the seller, considered to be cash consideration, relating to expenditures for workovers agreed to by the
Company and the third party. The acquisition was considered an acquisition of a business under ASC 805.
The following table presents the allocation of the purchase price of the assets acquired and liabilities assumed at fair 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

 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.

 Asset Retirement Obligation ("ARO") -
Schedule of Changes in the Asset Retirement Obligations

 Asset retirement obligation, beginning of period

 $
 52,565

 $
 33,062

 Accretion expense

 23,875

 8,574

 Revisions to asset retirement obligation

 239,069

 10,929

 Asset retirement obligation, end of period

 $
 315,509

 $
 52,565

 NOTE 8 — ACCOUNTS PAYABLE:

 On March 1, 2009, the Company became the 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, 2023 and February 28, 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, 2023 and February
28, 2022, the balance owed this working interest partner was $ 63,367 and $ 76,268, respectively and is included in the accounts payable
balances.

 NOTE
9 — ACCOUNTS PAYABLE - RELATED PARTIES:

 The February 28, 2023, and February 28, 2022 accounts
payable – related party balances of $ 21,937 and $ 49,228, respectively, were comprised of deferred expense reimbursements to employees.

 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.

 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 Stock as a part of the settlement agreement.
Based on the closing price of the Company's Common Stock on the date of the settlement agreement, the value of the Common Stock
transaction was determined to be $ 6,000. The Common 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. 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 1 st of each anniversary date. At February 28, 2023, the principal and a portion of the accrued interest
had not been paid and was outstanding. The accrued interest on the Note was $ 26,000 and $ 38,000 at February 28, 2023 and February 28,
2022, respectively.

 Note Payable – Related Party

 Secured Debt

 Chief Executive Officer

 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.

 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.

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

 Short-Term and Long-Term Borrowings - Schedule
of Related Party Notes Payable

 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

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

 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:

 Short-Term and Long-Term Borrowings - Schedule of Future Estimated Payments

 Twelve month periods ending February 28/29,

 2024

 9,065

 2025

 9,309

 2026

 9,558

 2027

 9,815

 2028

 10,078

 Thereafter

 88,885

 Total

 $
 136,710

 Short-term Convertible Note Payable

 Convertible Debt

the Company executed a convertible promissory note with a third party for $ 200,000.
The interest rate was 18 %
per annum and is payable in kind ("PIK") solely by additional shares of the Company's Common Stock. Regardless of when
the conversion occurred, a full 12 months of interest would be payable upon conversion. On May 5, 2022, the Company received notice of
conversion of the promissory note. The face amount of the note and $ 36,000
 in interest were converted at a rate of $ 0.0085
 per share into 27,764,706
 shares of the Company's Common Stock during the twelve months ended February 28, 2023.

 12% Subordinated Notes

 Private Placement

 Subordinated Debt

 The Company's 12% Subordinated Notes (the "Notes")
issued pursuant to a January 2010 private placement offering to accredited investors, had a balance at February 28, 2023 and February
28, 2022 of $ 290,000 and $ 315,000, respectively. The original maturity date of January 29, 2015 had been extended to January 29, 2017
and then was extended to January 29, 2019. Interest accrues at 12 % per annum, payable semi-annually on January 29th and July 29th.

 The Company has informed the Note 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, 2023 and February 28, 2022 was $ 159,508 and $ 135,229, 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 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:

 Short-Term and Long-Term Borrowings - Schedule
of Subordinated Notes

 12% Subordinated Notes

 Related Party Notes

 12% Subordinated notes – third party

 $

 $

 12% subordinated notes – related
 party

 —

 —

 12% Subordinated notes balance

 $

 $

 Line of Credit

 Line of Credit

 At February 28, 2022, the Company 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 and was secured
by the personal guarantee of our President and Chief Executive Officer. During the twelve months ended February 28, 2023, and
February 28, 2022, the Company did not receive any advances on the line of credit.

 On May 26, 2022, the Company paid off the outstanding
balance of $ 809,930 on the line of credit. The payoff of the line of credit was previously approved under terms of the Equity Exchange
Agreement in which the Company acquired the Reabold property in California. The line of credit payoff was a part of the use of proceeds
from the Company's sale of Common Stock to a third party. At February 28, 2023 and February 28, 2022, the line of credit had an
outstanding balance of $- 0 - and $ 808,182, respectively

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

 During the twelve months ended February 28, 2019,
and February 29, 2020, the Company conducted 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 interest are to receive a production revenue
payment interest on future wells to be drilled in California in exchange for their purchase. The Company shall pay seventy-five percent
(75%) of its future net production revenue from the relevant wells to the purchasers until each purchaser has received two times the purchase
price (the "Production Payment Target"). Once the Company pays the purchaser group amounts equal to the Production Payment
Target, it shall thereafter pay a pro-rated eight percent (8%) of $1.3 million on its net production payments from the relevant wells
to the purchaser group. However, if the total raise amount is less than the target $1.3 million, then the payment will be a proportionate
amount of the eight percent (8%).

 The Company accounted for the amounts received from
these sales in accordance with ASC 470-10-25 and 470-10-35 which require amounts recorded as debt to be amortized under the interest method
as described in ASC 835-30, Interest Method. Consequently, the program balance of $ 873,281 has been recognized as a production revenue
payable. The Company determined an effective interest rate based on future expected cash flows to be paid to the holders of the production
payment interests. This rate represents the discount rate that equates estimated cash flows with the initial proceeds received from the
sales and is used to compute the amount of interest to be recognized each period. Estimating the future cash outflows under this agreement
requires the Company to make certain estimates and assumptions about future revenues and payments and such estimates are subject to significant
variability. Therefore, the estimates are likely to change which may result in future adjustments to the accretion of the interest expense
and the amortized cost based carrying value of the related payables.

 Accordingly, the Company has estimated the cash flows
associated with the production revenue payments and determined a discount of $ 78,136 as of February 28, 2023, 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, 2023, and February 28, 2022, amortization of the debt discount on these payables amounted to $ 56,156 and $ 95,974,
respectively, which has been included in interest expense in the statements of operations.

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

 Short-Term and Long-Term Borrowings - Schedule
of Production Revenue Payable Balances

 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

 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.

 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.

 NOTE 11 — LEASES:

 Daybreak formally leased approximately 988 rentable
square feet of office space from an unaffiliated third party for our corporate office located in Spokane Valley, Washington. This office
was closed in March of 2023 when the corporate office was consolidated with our Friendswood, Texas regional operations office. The Company
leases approximately 416 rentable square feet of office space from an unaffiliated third party for our new corporate office located in
in Friendswood, Texas. Additionally, we lease approximately 695 rentable square feet from an unaffiliated third party for storage and
auxiliary office space in Wallace, Idaho. The lease in Friendswood is a 12-month lease that expired in October 2023, and 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 Wallace lease 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, 2023 and February 28, 2022 was $ 23,889 and $ 23,489, respectively.

 NOTE 12 — RELATED PARTY TRANSACTIONS:

 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, Bennett
Anderson. Mr. Anderson is a 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.

 NOTE 13 — STOCKHOLDERS' EQUITY (DEFICIT):

 Preferred Stock

 With the filing of the Company's Second Amended
and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, the Company no longer has any preferred stock.
The Company has only one class of stock, which is Common Stock.

 Series A Convertible Preferred Stock

 At February 28, 2022, there were no issued or outstanding
shares of Series A Preferred stock that had not been converted into our Common Stock. With the filing of the Company's Second Amended
and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, the Company no longer had any preferred stock.
The Company has only one class of stock, which is Common Stock.

 Conversion:

 At February 28, 2022, there were no shares issued
and outstanding that had not been converted into our Common Stock.

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

 Stockholders' Deficit - Schedule of
Conversions of Series A Preferred Stock

 Series A Preferred Stock

 Fiscal Period

 Shares of Series A
 Preferred Converted
 to Common Stock

 Shares of
 Issued from
 Conversion

 Number of
 Accredited
 Investors

 Year Ended February 29, 2008

 102,300

 306,900

 Year Ended February 28, 2009

 237,000

 711,000

 Year Ended February 28, 2010

 51,900

 155,700

 Year Ended February 28, 2011

 102,000

 306,000

 Year Ended February 29, 2012

 —

 —

 —

 Year Ended February 28, 2013

 18,000

 54,000

 Year Ended February 28, 2014

 151,000

 453,000

 Year Ended February 28, 2015

 3,000

 9,000

 Year Ended February 29, 2016

 10,000

 30,000

 Year Ended February 28, 2017

 —

 —

 —

 Year Ended February 28, 2018

 14,997

 44,991

 Year Ended February 28, 2019

 —

 —

 —

 Year Ended February 29, 2020

 —

 —

 —

 Year Ended February 28, 2021

 —

 —

 —

 Year Ended February 28, 2022

 709,568

 Totals

 1,399,765

 4,199,295

 Dividends:

all accumulated dividends of $ 2,449,979 were paid through the issuance of 1,100,000 shares of Common Stock. At a special meeting of shareholders
on May 20, 2022 the Company's shareholders approved the Second Amended and Restated Articles of Incorporation, which eliminated
the classification of the Series A Preferred stock.

 Cumulative dividends earned on the Series A Preferred stock for each twelve month
period since issuance are set forth in the table below:

 Stockholders' Deficit - Schedule of
Preferred Stock Dividends Earned

 Fiscal Year Ended

 Shareholders at

 Period End

 Accumulated

 Dividends

 February 28, 2007

 $

 155,311

 February 29, 2008

 242,126

 February 28, 2009

 209,973

 February 28, 2010

 189,973

 February 28, 2011

 173,707

 February 29, 2012

 163,624

 February 28, 2013

 161,906

 February 28, 2014

 151,323

 February 28, 2015

 132,634

 February 29, 2016

 130,925

 February 28, 2017

 130,415

 February 28, 2018

 128,231

 February 28, 2019

 127,714

 February 29, 2020

 128,063

 February 28, 2021

 127,714

 —

 96,340

 $

 2,449,979

 The Company is authorized to issue up to 500,000,000
shares of $ 0.001 par value Common Stock of which 384,734,902 and 67,802,273 shares were issued and outstanding as of February 28, 2023
and February 28, 2022, respectively.

 Balance

 Par Value

 Common stock, Issued and Outstanding, February 28, 2021

 60,491,122

 Shares issued for Series A Preferred conversion

 $
 2,129

 Shares issued for Series A accumulated dividend

 1,100,000

 $
 1,100

 Shares issued for debt conversion of accrued salaries

 1,397,880

 $
 1,398

 Shares issued for debt conversion of accrued directors fees

 317,708

 $

 Shares issued for conversion of 12% Note principal and interest –
 related party

 1,144,415

 $
 1,144

 Shares issued for investment principal in production
 revenue program

 1,222,444

 $
 1,222

 Common stock, Issued and Outstanding, February 28, 2022

 67,802,273

 Shares issued for conversion of 12% Note principal and interest

 78,934

 $

 Shares issued for conversion of convertible note

 $
 27,765

 Shares issued for acquisition of crude oil and natural gas properties

 $
 160,964

 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
)

 $

 Common stock, Issued and Outstanding, February 28,
 2023

 384,734,902

 During the twelve months ended February 28, 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 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.
In December 2023, we were notified of a system error that had occurred in the recording of street stock shares held by the nominee. Accordingly,
the number of our issued and outstanding shares was reduced by 500 shares as of February 28, 2023. The common stock par value of this
adjustment was $0.50.

 Subsequent
Event

 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 shares voting in an election of directors may elect all of the directors if they choose to do so.
In such event, the holders of the remaining shares aggregating less than 50% would not be able to elect any directors.

 At a special meeting of shareholders on May 20, 2022
the Company's shareholders approved an increase in the number of authorized Common Stock shares to 500,000,000 rather than the previous
 200,000,000 Common Stock authorization.

 NOTE 14 — WARRANTS:

 Share Based Payment Arrangement -
Non-Employee

 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 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
vested in equal parts over a three-year period beginning on January 2, 2020 and all warrants expired on January 2, 2024.

 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;
a weighted average remaining life of 0.83
years, and an intrinsic value of $ 25,200.
The recorded amount of warrant expense for the twelve months ended February 28, 2023, and February 28, 2022 was $- 0 -
and $ 4,913,
respectively. The warrants were fully amortized at December 31, 2021. All outstanding and exercisable warrants expired on January 2, 2024.

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

 Warrants - Schedule of Warrant Activity

 Weighted Average

 Exercise Price

 Warrants outstanding, February 28, 2021

 $

 0.01

 Changes during the twelve months ended February 28, 2022:

 Issued

 —

 Expired / Cancelled / Forfeited

 —

 Warrants outstanding, February 28. 2022

 $

 0.01

 Warrants exercisable, February 28, 2022

 893,333

 Changes during the twelve months ended February 28, 2023:

 Issued

 —

 $

 Expired / Cancelled / Forfeited

 —

 Warrants outstanding, February 28, 2023

 $

 0.01

 Warrants exercisable, February 28, 2023

 $

 0.01

 NOTE 15 — INCOME TAXES:

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

 Reconciliation between actual tax expense (benefit)
and income taxes computed by applying the U.S. federal income tax rate and state income tax rate to income from continuing operations
before income taxes is as follows:

 Income Taxes - Schedule of Reconciliation Between Actual Tax Expense Benefit and Income Taxes Computed by Applying Income Tax Rate

 Computed at U.S. and state statutory rates

 $
 ( 724,883
)

 $
 ( 118,897
)

 Permanent differences

 19,156

 11,157

 Changes in valuation allowance

 705,727

 107,740

 Total

 $
 —

 $
 —

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

 Income Taxes - Schedule of Deferred Tax
Assets and Liabilities

 Deferred tax assets:

 Net operating loss carryforwards

 $
 6,108,775

 $
 5,670,900

 Oil and gas properties

 355,546

 87,694

 Stock based compensation

 66,187

 66,187

 Other

 27,838

 27,838

 Less valuation allowance

 ( 6,558,346
)

 ( 5,852,619
)

 Total

 $
 —

 $
 —

 At February 28, 2023, the Company had a net
operating loss ("NOL") carryforwards for federal and state income tax purposes of approximately $ 20,471,769,
which will begin to expire, if unused, beginning in 2024. Under the Tax Cuts and Jobs Act, the NOL portion of the loss incurred in
the 2018, 2020, 2021 and 2022 periods of $ 340,749,
$ 339,299,
$ 416,898
and $ 279,773,
respectively, and the loss incurred for the year ended February 28, 2023 in the amount of $ 107,740
will not expire and will carry over indefinitely. The valuation allowance increased approximately $ 705,727
for the year ended February 28, 2023 and increased approximately $ 107,740
for the year ended February 28, 2022. Section 382 Rule of the Internal Revenue Code will place annual limitations on the
Company's NOL carryforward.

 The above estimates are based upon management's
decisions concerning certain elections that could change the relationship between net income and taxable income. Management decisions
are made annually and could cause the estimates to vary significantly. The Company's files federal income tax returns with the United
States Internal Revenue Service and state income tax returns in various state tax jurisdictions. As a general rule, the Company's
tax returns for the fiscal years after 2016 currently remain subject to examinations by appropriate tax authorities. None of our tax returns
are under examination at this time.

 NOTE 16 — COMMITMENTS AND CONTINGENCIES:

 Various lawsuits, claims, threatened legal actions,
and other contingencies arise in the ordinary course of the Company's business activities. In the opinion of management, the disposition
of any such matters is not expected, individually or in the aggregate, to have a material adverse effect on the Company's results
of operations, financial condition, or cash flows. However, the results of legal actions cannot be predicted with certainty. Therefore,
it is possible that the Company's results of operations, financial condition or cash flows could be materially adversely affected
in any particular period by the unfavorable resolution of one or more legal actions.

 The Company, as an owner or lessee and operator of
oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and
protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas
lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances,
the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary
in the industry, although the Company is not fully insured against all environmental risks.

 The Company is not aware of any environmental claims
existing as of February 28, 2023. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance
with environmental issues will not be discovered on the Company's crude oil and natural gas properties.

 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.

 NOTE 17 — SUBSEQUENT EVENTS:

 Related Party Note Payable

 Unsecured

 On July 27, 2023, the Company executed an Unsecured
Promissory Note (the "Note") with James F. Westmoreland, the Company's President and CEO, in the amount of $ 60,000.
The Note has a maturity date of July 27, 2024 and carries no interest, fees or penalties. The Company may prepay the Note at any time.
Proceeds of the Note will be used for working capital purposes.

 NOTE
18 — SUPPLEMENTARY INFORMATION FOR CRUDE OIL PRODUCING ACTIVITIES (UNAUDITED):

 Capitalized Costs Relating to Crude Oil and Natural
Gas Producing Activities

Producing Activities - Capitalized Costs Relating to Crude Oil and Natural Gas Producing Activities

 As of

 As of

 Proved leasehold costs

 Mineral Interests

 $
 115,119

 $
 115,119

 Wells, equipment and facilities

 8,577,693

 3,651,122

 Total Proved Properties

 8,692,812

 3,766,241

 Unproved properties

 Mineral Interests

 —

 —

 Uncompleted wells, equipment and facilities

 —

 —

 Total unproved properties

 —

 —

 Less accumulated depreciation, depletion amortization and impairment

 ( 3,566,612
)

 ( 3,230,209
)

 Net capitalized costs

 $
 5,126,200

 $
 536,032

 Costs Incurred in Oil and Gas Producing Activities

Producing Activities - Costs Incurred in Oil and Gas Producing Activities

 Acquisition of proved properties

 $
 4,694,563

 $
 —

 Acquisition of unproved properties

 —

 —

 Development costs

 —

 6,773

 Exploration costs

 —

 —

 Total costs incurred

 $
 4,694,563

 $
 6,773

 Results of Operations from Oil and Gas Producing
Activities

Producing Activities - Results of Operations from Oil and Gas Producing Activities

 Crude oil and natural gas revenues

 $
 1,613,286

 $

 Production costs

 ( 1,103,825
)

 ( 231,275
)

 Exploration expenses

 —

 ( 56,213
)

 Depletion, depreciation and amortization

 ( 504,118
)

 ( 49,590
)

 Impairment of crude oil and natural gas properties

 ( 711,873
)

 —

 Result of crude oil and natural gas producing operations before income taxes

 ( 706,530
)

 343,029

 Provision for income taxes

 —

 —

 Results of crude oil and natural gas producing activities

 $
 ( 706,530
)

 $
 343,029

 The Company's proved oil and natural gas reserves
have been estimated by two certified independent engineering firms, PGH Petroleum and Environmental Engineers, LLC, of Austin, Texas and
PETROtech Resources Company of Bakersfield, California. Proved reserves are the estimated quantities that geologic and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods
when the estimates were made. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to
change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may
be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling
and production history; acquisitions of oil and natural gas properties; and changes in economic factors.

 As of February 28, 2023, our total reserves were comprised
of our working interest in the East Slopes Project located in Kern County and our working interest in the Reabold subsidiary located in
Monterey and Contra Costs Counties, all 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.

 Our proved reserves are summarized in the table below:

Producing Activities - Schedule of Proved Oil and Gas Reserves

 Oil (Barrels)

 Natural Gas (Mcf)

 Oil (Barrels)

 Natural Gas (Mcf)

 BOE (Barrels)

 Proved reserves:

 February 28, 2021

 434,223

 —

 434,223

 Revisions (1)

 92,545

 —

 92,545

 Discoveries and extensions

 —

 —

 —

 ( 9,613

)

 —

 ( 9,613

)

 517,155

 —

 517,155

 Purchases of minerals

 277,224

 62,152

 287,582

 Revisions (2)

 ( 393,076

)

 —

 ( 393,076

)

 Discoveries and extensions

 —

 —

 —

 ( 17,114

)

 ( 3,822

)

 ( 17,751

)

 384,188

 (1)

 The upward revision of 92,545 BOE of proved reserves in aggregate were due to an increase in the economic life of existing reserves due to an improvement in crude oil prices in the energy markets.

 (2)

 A decrease in aggregate of 393,076 BOE resulted from upward revisions of 6,235 BOE of developed reserves due to an increase in the economic life of existing reserves due to an improvement in crude oil prices in the energy markets, offset by the removal of 399,311 BOE of proved undeveloped reserves that have remained undeveloped for a period greater than five years as of February 28, 2023.

 The Company's proved reserves are set forth
in the table below.

Producing Activities - Schedule of Proved Developed and Undeveloped Reserves

 Developed

 Undeveloped

 Total Reserves

 Oil (Bbls)

 BOE (Bbls)

 Oil (Bbls)

 BOE (Bbls)

 Oil (Bbls)

 BOE (Bbls)

 February 28, 2021

 95,120

 95,120

 339.103

 339,103

 495,977

 495,977

 117,844

 117,844

 47,323

 47,323

 165,167

 165,167

 384,188

 —

 —

 384,188

 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.

 Standardized Measure of Discounted Future Net Cash
Flows Relating to Proved Oil and Gas Reserves

 The following information is based on the Company's
best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of February 28, 2023, and February
28, 2022 in accordance with ASC 932, "Extractive Activities – Oil and Gas" which requires the use of a 10% discount
rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company's
proved oil and gas reserves.

 Future cash inflows for the years ended February 28,
2023, and February 28, 2022 were estimated as specified by the SEC through calculation of an average price based on the twelve-month unweighted
arithmetic average of the first-day-of-the-month price for the period from March through February during each respective fiscal year.
The resulting net cash flow are reduced to present value by applying a 10% discount factor.

 Standardized Measure of Discounted Future
Net Cash Flows Relating to Proved Oil and Gas Reserves

 Supplementary
Information for Crude Oil Producing Activities - Standardized Measure of Discounted Future Cash Flows Relating to Proved Oil and Gas
Reserves

 Future cash inflows

 $
 35,775,832

 $
 35,580,251

 Future production costs (1)

 ( 17,162,238
)

 ( 16,217,379
)

 Future development costs

 ( 725,938
)

 ( 3,603,561
)

 Future income tax expenses (2)

 —

 —

 Future net cash flows

 17,887,656

 15,759,311

 10% annual discount for estimated timing of cash flows

 ( 6,851,692
)

 ( 9,567,367
)

 Standardized measure of discounted future net cash flows at the end of the fiscal year

 $
 11,035,964

 $
 6,191,944

 (1)

 Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation expense, workover costs and G&A expense supporting the Company's crude oil and natural gas operations.

 (2)

 The Company has sufficient tax deductions and allowances related to proved crude oil and natural gas reserves to offset future net revenues.

 Average hydrocarbon prices are set forth in the table
below.

 Supplementary
Information for Crude Oil Producing Activities - Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure

 Crude Oil
 Average Price

 Natural

 Natural Gas

 Crude Oil (Bbl)

 Gas (Mcf)

 Year ended February 28, 2021 (1)

 $

 36.91

 $

 —

 Year ended February 28, 2022 (1)

 $

 70.75

 $

 —

 Year ended February 28, 2023 (1)

 $

 93.67

 $

 5.76

 (1)

 Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year.

 Future production and development costs, which include
dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company's
proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic
conditions.

 Sources of Changes in Discounted Future Net Cash
Flows

 Principal changes in the aggregate standardized measure
of discounted future net cash flows attributable to the Company's proved crude oil and natural gas reserves, as required by ASC
932, at fiscal year-end are set forth in the table below.

 Supplementary Information
for Crude Oil Producing Activities - Schedule of Sources of Changes in Discounted Future Net Cash Flows

 Standardized measure of discounted future net cash flows at the beginning of the year

 $
 6,191,944

 $
 1,648,418

 Extensions, discoveries and improved recovery, less related costs

 —

 906,390

 Revisions of previous quantity estimates

 ( 11,442,092
)

 44,898

 Purchase of minerals in place

 8,990,030

 —

 Net changes in prices and production costs

 4,695,284

 3,320,241

 Accretion of discount

 619,194

 164,842

 Sales of crude oil and natural gas produced, net of production costs

 ( 509,461
)

 ( 448,832
)

 Changes in future development costs

 2,022,097

 ( 267,335
)

 Changes in timing of future production

 468,968

 823,322

 Net changes in income taxes

 —

 —

 Standardized measure of discounted future net cash flows at the end of the year

 $
 11,035,964

 $
 6,191,944

 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

 During the Company's fiscal years ended February
28, 2022 and 2023, and since then, no independent accountant who was previously engaged as the principal accountant to audit the Company's
financial statements, and no independent accountant who was previously engaged to audit a significant subsidiary on whom the principal
accountant expressed reliance in its report, has resigned (or indicated it has declined to stand for re-election after the completion
of the current audit) or was dismissed.

 ITEM 9A. CONTROLS AND PROCEDURES

 Management's Evaluation of Disclosure
Controls and Procedures

 As of the end of the reporting period, February 28,
2023, an evaluation was conducted by Daybreak's management, including our President and Chief Executive Officer, also serving as
our interim principal finance and accounting officer, as to the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-15(e) of the Exchange Act. Such disclosure controls and procedures are designed to ensure that information
required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported
within required time periods specified by the SEC rules and forms. Additionally, it is vital that such information is accumulated and
communicated to our management including our President and Chief Executive Officer, in a manner to allow timely decisions regarding required
disclosures.

 Based on that evaluation, our management concluded
that we did not maintain disclosure controls and procedures that were effective in providing reasonable assurances that information required
to be disclosed in our reports filed under the Securities Exchange Act of 1934 was recorded, processed, summarized and reported within
the time periods prescribed by SEC rules and regulations, and that such information was accumulated and communicated to our management
to allow decisions regarding the disclosure.

 Internal Control Over Financial Reporting

 The Company's internal control over financial
reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles.

 Our internal controls over financial reporting include
those policies and procedures that:

 1)

 pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

 2)

 provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made in accordance with authorizations of management and our Board of Directors; and

 3)

 provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.

 Because of the inherent limitations due to, for example,
the potential for human error or circumvention of controls, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

 Management's
Report on Internal Control Over Financial Reporting

 Daybreak's management, including our President
and Chief Executive Officer, also serving as our interim principal finance and accounting officer is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our
management assessed the effectiveness of our internal control over financial reporting as of February 28, 2023.

 In making this assessment, management used certain
criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control-Integrated
Framework (2013). Based on such assessment and those criteria, management believes that the Company's internal control over
financial reporting is not effective as of February 28, 2023. Material weaknesses noted by our management include:

 Inadequate segregation of duties consistent with control objectives and
affecting the functions of authorization, recordkeeping, custody of assets, and reconciliation;

 Management dominated by a single individual/small group without compensating
controls;

 Limited knowledge and experience of the accounting and financial reporting
staff in the field of mergers and acquisitions accounting for a public company;

 The Company does not have adequate procedures and controls in place to ensure
the proper timing of financial statements and the financial reporting process.

 This annual report does not include an attestation
report of the Company's registered public accounting firm regarding internal control over financial reporting. Management's
report was not subject to attestation by the Company's registered public accounting firm pursuant to SEC rules that permit the company
to provide only management's report in this annual report.

 Changes in Internal Control over Financial Reporting

 There have not been any changes in the Company's
internal control over financial reporting during the quarter ended February 28, 2023 that have materially affected, or are reasonably
likely to materially affect, the Company's internal control over financial reporting.

 Limitations

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

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

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

 ITEM 9B. OTHER INFORMATION

 None.

 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS
THAT PREVENT INSPECTIONS

 Not applicable.

 ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE
GOVERNANCE

 Directors of Daybreak Oil and Gas, Inc.

 The following information reflects the business experience
of each individual serving on the Board of Directors (the "Board") of Daybreak Oil and Gas, Inc.

 Director

 Name

 Age

 Since

 Timothy R. Lindsey

 2007

 James F. Meara

 2008

 James F. Westmoreland

 2008

 Darren Williams

 2022

 Timothy R. Lindsey has served as a member of
the Board of Directors since January 2007. He served as the Company's Interim President and Chief Executive Officer from December
2007 until his resignation in October 2008. Mr. Lindsey has over 40 years of energy and mineral exploration, technical and executive leadership
in global exploration, production, technology, and business development. From March 2005 to the present, Mr. Lindsey has been the Principal
of Lindsey Energy and Natural Resources, an independent consulting firm specializing in energy and mining industry issues. From September
2003 to March 2005, Mr. Lindsey held executive positions including Senior Vice-President, Exploration with The Houston Exploration Company,
a Houston-based independent natural gas and oil company formerly engaged in the exploration, development, exploitation and acquisition
of domestic natural gas and oil properties. From October 1975 to February 2003, Mr. Lindsey was employed with Marathon Oil Corporation,
a Houston-based company engaged in the worldwide exploration and production of crude oil and natural gas, as well as the domestic refining,
marketing and transportation of petroleum products. During his 27-year tenure with Marathon, Mr. Lindsey held a number of positions including
senior management roles in both domestic and international exploration and business development. Mr. Lindsey served as a director and
Chairman of the Board of Directors of Revett Mining Company., a publicly listed company with mining activities in Montana from April 2009
until the merger of Revett Mining Company into Helca Mining in June 2015. Mr. Lindsey obtained his Bachelor of Science degree in geology
at Eastern Washington University in 1973 and completed graduate studies in economic geology from the University of Montana in 1975. In
addition, he completed the Advanced Executive Program from the Kellogg School of Management, Northwestern University, in 1990. Mr. Lindsey
is a member of the American Association of Petroleum Geologists, the Rocky Mountain Association of Geologists, the Montana Mining Association,
and the American Exploration and Mining Association.

 James F. Meara has served as a member of the
Board of Directors since March 2008. From 1980 through December 2007, Mr. Meara was employed with Marathon Oil Corporation, a Houston-based
company engaged in the worldwide exploration and production of crude oil and natural gas, as well as the domestic refining, marketing
and transportation of petroleum products. During his 27-year tenure with Marathon, Mr. Meara moved through a series of posts in the tax
department, becoming manager of Tax Audit Systems and Planning in 1988, and in 1995 he was named Commercial Director of Sakhalin Energy
in Moscow, Russia. In 2000, Mr. Meara served as Controller and was appointed to Vice President of Tax in January 2002, serving until his
retirement in December 2007. Mr. Meara holds a bachelor's degree in accounting from the University of Kentucky and a master's
degree in business administration from Bowling Green State University, and is a member of the American Institute of Certified Public Accountants.

 James F. Westmoreland was elected Chairman
of the Board of Directors in 2014, and appointed President and Chief Executive Officer and director in October 2008. He also serves as
interim principal finance and accounting officer. Prior to that, he had been our Executive Vice President and Chief Financial Officer
since April 2008. He also served as the Company's interim Chief Financial Officer from December 2007 to April 2008. From August
2007 to December 2007, he consulted with the Company on various accounting and finance matters. Prior to that time, Mr. Westmoreland was
employed in various financial and accounting capacities for The Houston Exploration Company for 21 years, including Vice President, Controller
and Corporate Secretary, serving as its Vice President and Chief Accounting Officer from October 1995 until its acquisition by Forest
Oil Corporation in June 2007. Mr. Westmoreland has almost 40 years of experience in oil and gas accounting, finance, corporate compliance
and governance, both in the public and private sector. He earned his Bachelor of Business Administration in accounting from the University
of Houston.

 Darren Williams was elected to the Board in
May 2022, being nominated by the Board of Directors as agreed pursuant to the terms of the Exchange Agreement. Mr. Williams brings over
28 years of experience in various areas in the Oil and Gas industry. In 2021 he was appointed Chief Operating Officer of Black Knight
Energy, LLC, a California-based, private energy company focused on the acquisition and development of large, cash flowing oil and natural
gas assets across the Lower 48. Prior to that, from 2014 to 2021, Mr. Williams served as Executive Vice President - Operations/Exploration
& Development for California Resources Corp (NYSE: CRC), California's largest independent oil and gas producer. From 1997 to
2014, Mr. Williams held many positions within Marathon Oil Corporation (MRO), domestically as well as internationally. His titles included
Africa Exploration Manager President Marathon Upstream Gabon, Vice-President Marathon Oil Investments Limited; Oklahoma Exploration &
Production Manager; Gulf of Mexico Exploration & Appraisal Manager; and Geophysicist/Technical Supervisor. Before joining Marathon,
Mr. Williams was Geophysicist/Technical Supervisor in London and Houston, TX from 1997 to 2008. From 1994 to 1997 he was Special Projects
Geophysicist with Ikon Science. Mr. Williams holds a MSc Basin Evolutions & Dynamics (Petroleum Geology) from Royal Holloway, University
of London, UK; and a BSc Geophysics, University of Leicester, UK.

 Consideration of Director Nominees.

 When analyzing whether directors and nominees have
the experience, qualifications, attributes and skills, taken as a whole, to enable the Board of Directors to satisfy its oversight responsibilities
effectively in light of the Company's business and structure, the Governance Committee and the Board focus on the information as
summarized in each of the Directors' individual biographies set forth above.

 In particular, the Governance Committee and the Board
considered:

 Mr. Lindsey's over 40-year career as a successful senior executive in the energy industry, his extensive knowledge of the industry and his active participation in energy-related professional organizations are also valuable assets to the Board. His knowledge and expertise in the energy business and management leadership regarding the issues affecting our business have been invaluable to the Board of Directors in overseeing the business affairs of our Company. Further, the Committee believes that his extensive background and service with other public companies in the energy and mining sectors and his technical expertise provide the Board with superior leadership and decision-making skills.

 Mr. Meara's education, executive leadership roles and 27-year work experience in finance, tax and accounting in the crude oil and natural gas industry provide the knowledge and financial expertise needed to serve on the Board and the Company's audit committee.

 Mr. Westmoreland's over 40-year career in various operational, financial, and accounting capacities, including Vice President, Chief Accounting Officer, Controller and Corporate Secretary at a public crude oil and natural gas company along with his recent experience as President, Chief Executive Officer, Executive Vice President, and Chief Financial Officer of the Company. The Board also considered his role in reorganizing the Company and his day-to-day management of the Company.

 •

 Mr. William's over 28 years' experience in ever increasing roles in various operational and management positions in the oil and gas industry, especially in the California market. With his background and expertise, he will be able to assist the Company in evaluating various opportunities that may be afforded to the Company in the future.

 Information About Our Executive Officers

 Executive officers are elected annually by
our Board and serve at the discretion of the Board. There are no arrangements or understandings between any of the directors, officers,
and other persons pursuant to which such person was selected as an executive officer.

 The following information concerns our executive
officers, including the business experience of each during the past five years:

 Executive

 Name

 Age

 Since

 Office

 James F. Westmoreland

 2007

 Chairman of the Board, President and Chief Executive Officer

 Bennett W. Anderson

 2006

 Chief Operating Officer

 James F. Westmoreland was elected Chairman
of the Board of Directors in 2014, and appointed President and Chief Executive Officer and director in October 2008. He also serves as
interim principal finance and accounting officer. Prior to that, he had been our Executive Vice President and Chief Financial Officer
since April 2008. He also served as the Company's interim Chief Financial Officer from December 2007 to April 2008. From August
2007 to December 2007, he consulted with the Company on various accounting and finance matters. Prior to that time, Mr. Westmoreland was
employed in various financial and accounting capacities for The Houston Exploration Company for 21 years, including Vice President, Controller
and Corporate Secretary, serving as its Vice President and Chief Accounting Officer from October 1995 until its acquisition by Forest
Oil Corporation in June 2007. Mr. Westmoreland has almost 40 years of experience in oil and gas accounting, finance, corporate compliance
and governance, both in the public and private sector. He earned his Bachelor of Business Administration in accounting from the University
of Houston.

 Bennett W. Anderson was appointed Chief
Operating Officer in 2006. Prior to that time, he was a private investor from 2002 - 2006. He served as a Senior Vice President with Novell,
Inc. from 1998-2002. Mr. Anderson's duties included product direction, strategy and market direction, and training and support for
the field sales staff. From 1978 to 1982, Mr. Anderson worked as a rig hand and was involved in drilling over a dozen wells in North Dakota.
He holds a Bachelor of Science from Brigham Young University in Computer Science and graduated with University Honors of Distinction.

 Family Relationships

 There are no family relationships between any
director, executive officer, or person nominated or chosen by the Company to become a director or executive officer.

 Involvement in Certain Legal Proceedings

 With respect to Darren Williams, current director,
in July 2020 California Resources Corporation, where Mr. Williams served as Executive Vice President, filed for voluntary Chapter 11 bankruptcy
protection as part of a debt restructuring undertaken in agreement with a majority of its creditors. California Resources Corporation
cited an unsustainable debt burden given the prevailing commodity markets at the time as the reason for the filing and restructuring.

 As required by Item 401(f) of Regulation S-K,
none of Daybreak's other current directors or Executive Officers has, during the past ten years, had:

 (f) Involvement in certain legal proceedings.
Describe any of the following events that occurred during the past ten years and that are material to an evaluation of the ability or
integrity of any director, person nominated to become a director or executive officer of the registrant:

 (1) A petition under the Federal bankruptcy
laws or any state insolvency law was filed by or against, or a receiver, fiscal agent or similar officer was appointed by a court for
the business or property of such person, or any partnership in which he was a general partner at or within two years before the time of
such filing, or any corporation or business association of which he was an executive officer at or within two years before the time of
such filing;

 (2) Such person was convicted in a criminal
proceeding or is a named subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);

 (3) Such person was the subject of any
order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily
enjoining him from, or otherwise limiting, the following activities:

 (i) Acting as a futures commission merchant,
introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant, any other person
regulated by the Commodity Futures Trading Commission, or an associated person of any of the foregoing, or as an investment adviser, underwriter,
broker or dealer in securities, or as an affiliated person, director or employee of any investment company, bank, savings and loan association
or insurance company, or engaging in or continuing any conduct or practice in connection with such activity;

 (ii) Engaging in any type of business
practice; or

 (iii) Engaging in any activity in connection
with the purchase or sale of any security or commodity or in connection with any violation of Federal or State securities laws or Federal
commodities laws;

 (4) Such person was the subject of any
order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise
limiting for more than 60 days the right of such person to engage in any activity described in paragraph (f)(3)(i) of this section, or
to be associated with persons engaged in any such activity;

 (5) Such person was found by a court
of competent jurisdiction in a civil action or by the Commission to have violated any Federal or State securities law, and the judgment
in such civil action or finding by the Commission has not been subsequently reversed, suspended, or vacated;

 (6) Such person was found by a court
of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law,
and the judgment in such civil action or finding by the Commodity Futures Trading Commission has not been subsequently reversed, suspended
or vacated;

 (7) Such person was the subject of,
or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended
or vacated, relating to an alleged violation of:

 (i) Any Federal or State securities
or commodities law or regulation; or

 (ii) Any law or regulation respecting
financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement
or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or

 (iii) Any law or regulation prohibiting
mail or wire fraud or fraud in connection with any business entity; or

 (8) Such person was the subject of, or
a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in
Section 3(a)(26) of the Exchange Act (15 U.S.C. 78c(a)(26))), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange
Act (7 U.S.C. 1(a)(29))), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members
or persons associated with a member.

 Consideration of Nominees and Qualifications for
Nominations to the Board of Directors

 Our Corporate Governance Guidelines, which can be
found under the "Shareholder/Financial - Corporate Governance" section of our website at www.daybreakoilandgas.com, contain
Board membership criteria that apply to nominees recommended by the Nominating and Corporate Governance Committee (the "Governance
Committee") for a position on the Board. The Corporate Governance Guidelines state that the Board's Governance Committee is
responsible for making recommendations to the Board concerning the appropriate size and composition of the Board, as well as for recommending
to the Board nominees for election or re-election to the Board. In formulating its recommendations for Board nominees, the Governance
Committee will assess each proffered candidate's independence and weigh his or her qualifications in accordance with the Governance
Committee's stated Qualifications for Nominations to the Board of Directors, which can be
found under the "Shareholder/Financial - Corporate Governance" section of our website at www.daybreakoilandgas.com.

 Ethical Business Conduct Policy Statement and Code
of Ethics for Senior Financial Officers

 All of our employees, officers and directors are required
to comply with our Ethical Business Conduct Policy Statement to help ensure that our business is conducted in accordance with the highest
standards of moral and ethical behavior. Our Ethical Business Conduct Policy covers all areas of professional conduct including:

 Conflicts of interest;

 Customer
relationships;

 Insider trading of our securities;

 Financial disclosure;

 Protection of confidential information; and

 Strict legal and regulatory compliance.

 Our employees, officers and directors are required
to certify their compliance with our Ethical Business Conduct Policy Statement once each year.

 In addition to the Ethical Business Conduct Policy
Statement, all members of our senior financial management, including our President and Chief Executive Officer, have agreed in writing
to our Code of Ethics for Senior Financial Officers, which prescribes additional ethical obligations pertinent to the integrity of our
internal controls and financial reporting process, as well as the overall fairness of all financial disclosures.

 The full text of our Ethical Business Conduct Policy
Statement, and the Code of Ethics for Senior Financial Officers, are available under the "Shareholder/Financial - Corporate Governance"
section of our website at www.daybreakoilandgas.com and are also available upon request, without charge, by contacting the Corporate Secretary
at Daybreak Oil and Gas, Inc., 1414 S. Friendswood Dr., Suite 212, Friendswood, TX 77546.

 We intend to promptly disclose via a Current Report
on Form 8-K or an update to our website information about any amendment to, or waiver of, these codes with respect to our executive officers
and directors.

 Audit Committee

 The Audit Committee is responsible for monitoring
the integrity of the Company's financial reporting standards and practices and its financial statements, overseeing the Company's
compliance with ethics and legal and regulatory requirements, and selecting, compensating, overseeing, and evaluating the Company's
independent registered public accountants.

 During the fiscal year ended February 28, 2023, the
Audit Committee met seven times. The Audit Committee operates under a charter that is available under the "Shareholder/Financial
- Corporate Governance" section of our website at www.daybreakoilandgas.com and also upon request, without charge, by contacting
the Corporate Secretary at Daybreak Oil and Gas, Inc., 1414 S. Friendswood Dr., Suite 212, Friendswood, TX 77546

 The Audit Committee's purpose is to assist the
Board in fulfilling its responsibility to oversee management activities related to accounting and financial reporting policies, internal
controls, auditing practices and related legal and regulatory compliance. In that connection, the Audit Committee is directly responsible
for the appointment, compensation, retention, and oversight of the work of our independent registered public accountants for the purposes
of preparing or issuing an audit report or performing other audit, review or attest services. The Audit Committee determines the independence
of our independent registered public accountants, and our independent registered public accountants report directly to the Audit Committee,
which also must review and pre-approve the current year's audit and non-audit fees. The Audit Committee has the authority to select,
retain and/or replace consultants to provide independent advice to the Committee. The Audit Committee discusses quarterly with the independent
auditor the applicable requirements of the Public Company Accounting Oversight Board ("PCAOB") and the Commission.

 The Audit Committee charter prescribes the Committee's
functions, which include the following:

 Maintaining our compliance with legal and regulatory requirements relating to financial reporting accounting and controls;

 Overseeing our whistleblower procedures;

 Overseeing the pre-approval of audit fees;

 Appointing and overseeing our independent registered public accountants;

 Overseeing our internal audit function;

 Overseeing the integrity of our financial reporting processes, including the Company's internal controls;

 Assessing the effect of regulatory and accounting initiatives, as well as any off-balance sheet structures, on our financial statements;

 Reviewing our earnings press releases, guidance and SEC filings;

 Overseeing our risk analysis and risk management procedures;

 Resolving any disagreements between management and the independent registered public accountants regarding financial reporting;

 Overseeing our business practices and ethical standards;

 Preparing an audit committee report to be included in our public filings pursuant to applicable rules and regulations of the SEC.

 Timothy R. Lindsey, James F. Meara, and Darren Williams
serve on the Audit Committee. All members of the Audit Committee satisfy all SEC criteria for independence and meet all financial literacy
and other SEC and NYSE American requirements for Audit Committee service. The Board has determined that James F. Meara is an "audit
committee financial expert" as defined by the rules of the SEC.

 Delinquent
Section 16(a) Reports

 Section 16(a) of the Securities Exchange Act of 1934
requires our directors, officers and beneficial owners of more than 10% of our Common Stock, to file initial reports of ownership and
reports of changes in ownership of Common Stock on Forms 3, 4 and 5 with the SEC. Directors, officers and beneficial owners of more than
10% of our Common Stock are required by SEC regulations to furnish us with copies of any forms that they file. We assist our directors
and executive officers in complying with these requirements and are required to disclose in this Annual Report the failure to file these
reports on behalf of any reporting person when due.

 With respect to our officers and directors, based on our review of related
information, we believe that no such Section 16(a) reports needed to be filed during the fiscal year ended February 28, 2023.

 ITEM 11. EXECUTIVE COMPENSATION

 Executive Officers

 Named Executive Officers

 Named executive officers consist of any individual
who served as our Chief Executive Officer during the fiscal year ended February 28, 2023, and up to two of our most highly compensated
executive officers other than the Chief Executive Officer during the fiscal year ended February 28, 2023. For the fiscal year ended February
28, 2023, under the smaller reporting company rules, our named executive officers are James F. Westmoreland, President and Chief Executive
Officer; and Bennett W. Anderson, our Chief Operating Officer (collectively, the "Named Executive Officers"). Executive officers
are elected annually by our Board and serve at the discretion of the Board. There are no arrangements or understandings between any of
the directors, officers, and other persons pursuant to which any such person was selected as an executive officer.

 The following information concerns our Named Executive
Officers for the fiscal year ended February 28, 2023.

 Executive

 Name

 Age

 Since

 Office

 James F. Westmoreland

 2007

 President and Chief Executive Officer

 Bennett W. Anderson

 2006

 Chief Operating Officer

 EXECUTIVE COMPENSATION

 We currently qualify as a "smaller reporting
company" as such term is defined in Rule 405 of the Securities Act and Item 10 of Regulation S-K. Accordingly, and in accordance
with relevant SEC rules and guidance, we have elected, with respect to the disclosures required by Item 402 (Executive Compensation) of
Regulation S-K, to comply with the disclosure requirements applicable to smaller reporting companies. The following Compensation Overview
is not comparable to the "Compensation Discussion and Analysis" that is required of SEC reporting companies that are not smaller
reporting companies.

 Compensation Overview

 This Compensation Overview discusses the material
elements of the compensation awarded to, earned by or paid to our executive officers, and the Compensation Committee's role in the
design and administration of these programs and policies in making specific compensation decisions for our executive officers, including
officers who are considered to be "Named Executive Officers" during the fiscal year ended February 28, 2023.

 General Discussion of Executive Compensation

 The Compensation Committee is responsible for establishing,
implementing, and continually monitoring adherence to our compensation philosophy. In doing so, the Compensation Committee reviews and
approves, on at least, an annual basis the evaluation process and compensation structure for the Company's Named Executive Officers.
The Committee reviews and recommends to the Board the annual compensation, including salary, and any incentive and/or equity-based compensation
for such officers. The Committee also provides oversight of management's decisions concerning the performance and compensation of
other employees.

 The current and future objectives of Daybreak's
compensation program are to keep compensation aligned with Daybreak's cost structure, financial position, and strategic business
and financial objectives. Daybreak's financial position and its plans going forward are integral to the design and implementation
of officer and employee compensation. Therefore, the Compensation Committee reviews the Company's cash flow with the Chief Executive
Officer at a minimum, on an annual basis, in order to evaluate the current compensation program and its effects on the financial position
of the Company. In short, we pay what we can afford and adjust accordingly as conditions warrant. In deciding on the type and amount of
compensation for each Named Executive Officer, the Compensation Committee focuses on the market value of the role and pay of the individual,
along with the Company's cost structure and financial position.

 For the fiscal years ended February 28, 2023, February
28, 2022, and February 28, 2021, compensation to our Named Executive Officers consisted solely of base salaries. The Board, with the assistance
of the Compensation Committee, has reviewed the compensation structure of the Company's Named Executive Officers. After taking into
consideration the Company's current cost

 structure, financial position, and current compensation
structure (discussed under the heading "Narrative Disclosure to Summary Compensation Table, Base Salaries"), the Board approved
continuation of the compensation structure. In addition, the full Board reviewed and discussed, with the assistance of the CEO, the performance
and compensation of all of Daybreak's employees.

 With the increase in cash flow during the fiscal year
ended February 28, 2023, the Board, with the assistance of the Compensation Committee and the CEO, increased all employee salaries, with
the exception of our President and CEO, who agreed to keep his salary at its current level until an increase in shareholder value is achieved.

 We do not provide any perquisites or other personal
benefits to our named executive officers, or any of our employees.

 For the fiscal years ended February 28, 2023, February
28, 2022, and February 28, 2021, compensation to our Named Executive Officers consisted solely of base salaries. The Board, with the assistance
of the Compensation Committee, has reviewed the compensation structure of the Company's Named Executive Officers. After taking into
consideration the Company's current cost structure, financial position, and current compensation structure (discussed under the
heading "Narrative Disclosure to Summary Compensation Table, Base Salaries"), the Board approved continuation of the current
compensation structure. In addition, the full Board reviewed and discussed the performance and compensation of all of Daybreak's
employees.

 The elements of compensation are described in more
detail under "Narrative Disclosure to Summary Compensation Table", below, beginning on page
97 of this Form 10-K.

 Summary Compensation
Table

 The following table sets forth summary information
concerning the compensation paid to or earned by our Named Executive Officers during the fiscal years ended February 28, 2023, and February
28, 2022.

 Name and Principal Position

 Fiscal Year

 Ended

 Salary

 ($)

 Bonus

 ($)

 All Other

 Compensation

 ($)

 Total

 ($)

 James F. Westmoreland (1)

 75,000 (2)

 —

 —

 75,000 (2)

 President and Chief Executive Officer

 75,000 (3)

 —

 —

 75,000 (3)

 Bennett W. Anderson0

 72,350 (4)

 —

 —

 72,350 (4)

 Chief Operating Officer

 44,700 (5)

 —

 —

 44,700 (5)

 (1)

 Mr. Westmoreland commenced his employment on December 14, 2007 as the Company's interim Chief Financial Officer and was appointed Executive Vice President and Chief Financial Officer in April 2008. He was appointed to the position of President and Chief Executive Officer of the Company in October 2008 and continues to serve as the interim principal finance and accounting officer of the Company.

 (2)

 On August 22, 2019, due to the cost structure and financial position of the Company, Mr. Westmoreland's annual base salary was reduced by 50% to $75,000. This annual base salary remains at this amount until an increase in shareholder value is achieved. During the fiscal year ended February 28, 2023, Mr. Westmoreland was paid $75,000.

 (3)

 As a result of the effect of low oil prices on the Company's
cash flow; and the lack of outside financing, Mr. Westmoreland deferred partial salary payments during the fiscal year ended February
28, 2022. During the fiscal year ended February 28, 2022, Mr. Westmoreland was paid $59,375; and $15,625 was accrued, but
not paid. The accrued liability was recorded on our balance sheet under accrued liabilities. During the fiscal year ended February 28, 2022, Mr. Westmoreland agreed to forgive
the remaining $53,125 of accrued but unpaid salary.

 (4)

 As a result of the increase in cash flow from the Reabold California, LLC transactions as well as higher oil prices and increasing responsibilities, Mr. Anderson's salary was increased to $100,000 per year, effective in September 2022. During the fiscal year ended February 28, 2022, Mr. Anderson was paid $72,350.

 (5)

 As a result of the effect of low oil prices on the Company's cash flow; and the lack of outside financing, Mr. Anderson deferred partial salary payments during the fiscal year ended February 28, 2022, Mr. Anderson was paid $35,388; and $9,312 was accrued, but not paid. During the fiscal year ended February 28, 2021, Mr. Anderson was paid $22,350; and $22,350 was accrued, but not paid. On December 15, 2021, Mr. Anderson agreed to convert his total of $189,546 in accrued but unpaid salary into 421,214 shares of Common Stock. These shares were issued on February 22, 2022.

 Narrative Disclosure to Summary Compensation Table

 Base Salaries

 The Board, with the assistance of the Compensation
Committee, has reviewed the compensation structure of the Company's Named Executive Officers. After taking into consideration the
Company's cost structure and financial position, on August 22, 2019, the Compensation Committee, along with the Board of Directors
entered into a series of arrangements with its Named Executive Officers, as well as its Board of Directors and other key employees. As
part of these efforts, Mr. Westmoreland agreed to forgive deferred salary owed him by the Company, totaling $943,750, and to reduce his
annual base salary by 50%, to $75,000. The Company also ended its policy of deferring base salary amounts of its other Named Executive
Officer and other employees, and temporarily reduced such executive and employee's base salaries by 50% but continued to owe previously
deferred amounts to these individuals. These changes were agreed to by each affected person and were deemed to take effect as of June
1, 2019.

 On November 22, 2021, the Compensation Committee,
along with the Nominating and Corporate Governance Committee, and Board of Directors agreed to a debt-to-equity exchange for Daybreak
Common Stock with its directors, executive officers, and other employees with respect to the forgiveness and conversion of related party
debts. The agreements include conversion of all deferred salary owed to its executive officers and key employees, into shares of the Company's
Common Stock at a conversion rate of $0.45 per share of Common Stock (the "Related Party Debt Conversion"). All the members
of the Compensation Committee and all the members of the Nominating and Corporate Governance Committee, reviewed the Related Party Debt
Conversion under the Company's Related Party Transactions Policy, and was satisfied that it has been fully informed as to the material
facts of the debt exchange, and that the exchange was fair to the Company and its shareholders. On December 15, 2021, the Company finalized
these agreements, and Mr. Westmoreland agreed to forgive the remaining $53,125 of accrued but unpaid salary, and Mr. Anderson exchanged
$189,546 of accrued but unpaid salary owed to him into 421,214 shares of Common Stock.

 The Board, with the assistance of the
Compensation Committee, has continued to review the compensation structure of the Company's Named Executive Officers in
alignment with the Company's financial position. After taking into consideration the Company's cost structure and
financial position, in August 2022, the Compensation Committee, along with the Board of Directors agreed that, as a result of the
increase in cash flow from the Reabold California, LLC transactions as well as higher oil prices and increasing responsibilities,
Mr. Anderson's salary was increased to $100,000 per year, effective September 1, 2022. Subsequently, beginning Ju1y 1, 2023,
all employees and Named Executive Officers salaries were temporarily cut back by 75% due to a change in the Company's
financial position, with the unpaid salaries being accrued.

 Other: Securities Trading

 We have a policy that executive officers and directors
may not purchase or sell exchange traded options to sell or buy Daybreak stock ("puts" and "calls"), engage in
short sales with respect to Daybreak stock or otherwise hedge equity positions in Daybreak (e.g., by buying or selling straddles, swaps
or other derivatives).

 Outstanding Equity Awards at Fiscal Year-End

 The Company has no unvested outstanding restricted
stock awards held by our Named Executive Officers for the fiscal year ended February 28, 2023. The Company has no qualified or nonqualified
stock option plans and has no outstanding stock options.

 Executive Employment Agreements

 Our employees, including our named executive officers,
are employed at-will and do not have employment agreements. Our Compensation Committee believes that employment agreements encourage a
short-term rather than long-term focus, provide inappropriate security to the executives or employees and undermine the team spirit of
the organization.

 Payments Upon Termination or Change in Control

 We do not have any agreements with any of our named
executive officers that affect the amount paid or benefits provided following termination or a change in control.

 Pension Plan Benefits

 The Company does not have any pension plans that oblige
the Company to make payments or provide benefits at, following or in connection with retirement of its Directors, Officers, or employees.

 Deductibility of Compensation

 Section 162(m) of the Internal Revenue Code (the "Code")
places a $1 million per executive cap on the compensation paid to executives that can be deducted for tax purposes by publicly traded
corporations each year. Amounts that qualify as "performance based" compensation under Section 162(m)(4)(c) of the Code are
exempt from the cap and do not count toward the $1 million limit if certain requirements are satisfied. At our current named executive
officer compensation levels, we do not presently anticipate that Section 162(m) of the Code will be applicable, and accordingly, our Compensation
Committee did not consider its impact in determining compensation levels for our Named Executive Officers for the fiscal year ended February
28, 2023.

 Stock Compensation Expense

 Stock awards are accounted for under FASB ASC 718,
"Stock Compensation". 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.

 CEO PAY RATIO

 As a "smaller reporting company", we are
not required to disclose the ratio of its CEO's annual total compensation to the Company's median employee's annual
total compensation. However, in comparing the current annual total compensation of our CEO of $75,000, and the fiscal year ending February
28, 2024 annual total compensation of our median compensated employees of $100,000, the result of this calculation was a CEO Pay Ratio
of 0.75 to 1.

 Employee, Officer and Director Insider Trading

 The Company has adopted a policy regarding insider
trading both to satisfy the Company's obligation to prevent insider trading and to help Company personnel avoid the severe consequences
associated with violations of insider trading laws. The Company considers it improper and inappropriate for any director, officer, or
other employee of the Company to engage in short-term or speculative transactions in the Company's securities. It therefore is the
Company's policy that directors, officers and other employees may not engage in short sales, publicly traded options, margins accounts
and pledges, and hedging transactions. The full text of our Securities Law Compliance Policy is available under the "Shareholder/Financial
- Corporate Governance" section of our website at www.daybreakoilandgas.com and is also available upon request, without charge,
by contacting the Corporate Secretary at Daybreak Oil and Gas, Inc., 1414 S. Friendswood Dr., Suite 212, Friendswood, TX 77546.

 DIRECTOR COMPENSATION

 The Board has adopted a Non-Employee Director Compensation
Policy (the "Director Compensation Policy") under which it compensates directors that are not employees of the Company. The
Compensation Committee re-evaluates the policy at least annually, taking into consideration the Company's financial status.

 As a result of the Company's limited
available cash, the Board of Directors, beginning in June 2010 postponed receiving payments of meeting fees and quarterly retainer
fees until cash flow would allow. On August 22, 2019, the Board of Directors agreed to forgive 50% of accrued, deferred board fees
owed to them, and to temporarily discontinue future board fees, deemed to take effect as of June 1, 2019. On February 22, 2022, the
members of the Board of Directors converted the remaining 50% of their accrued but unpaid fees into Common Stock. The Compensation
Committee, along with the Board of Directors continues to evaluate the metrics under the Director Compensation Policy, whereas each
director who is not an employee or officer of the Company ("non-employee director") is entitled to receive an annual
cash retainer of $9,000. Each non-employee director also receives $500 per Board meeting attended and $500 per committee meeting
attended. Additionally, under this Policy, the chairman of the Audit Committee would receive an additional annual retainer of $1,500
and all other committee chairmen would receive an additional $750 annual retainer. Additionally, directors are reimbursed for any
out-of-pocket expenses incurred in attending board and committee meetings. For the fiscal year ended February 28, 2023, the
directors received no cash compensation for their services. This policy will stay in place; however the discontinuance of all board
fees is ongoing during the 2024 fiscal year and will continue to be monitored for any changes in the Company's cash
position.

 On November 22, 2021, the Compensation Committee,
along with the Nominating and Corporate Governance Committee, and Board of Directors agreed to a debt-to-equity exchange with its directors,
executive officers, and other employees with respect to the forgiveness and conversion of related party debts. These agreements include
conversion of all accrued, deferred board fees owed to the non-employee directors, into shares of the Company's Common Stock at
a conversion rate of $0.45 per share of Common Stock (the "Related Party Debt Conversion").

 All the members of the Compensation Committee and
all the members of the Nominating and Corporate Governance Committee, reviewed the Related Party Debt Conversion under the Company's
Related Party Transactions Policy, and were satisfied that it had been fully informed as to the material facts of the Related Party Debt
Conversion, and that the Related Party Debt Conversion was fair to the Company and its shareholders. On December 15, 2021, the Company
finalized the 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. On February 22, 2022, the members of the Board of Directors converted
the above mentioned remaining 50% of their accrued but unpaid fees into Common Stock.

 As a result of the debt-for-equity exchange, the directors
received shares of Common Stock of the Company in full payment and satisfaction of their deferred fees, as follows:

 Name

 Shares Issued in Debt-for-Equity Exchange

 Timothy R. Lindsey

 148,819

 James F. Meara

 168,889

 James F. Westmoreland (1)

 -

 Darren Williams (2)

 -

 (1)
 As an employee director, Mr. James F. Westmoreland did not receive any compensation
for serving on the Board of Directors during the fiscal year ended February 28, 2023. Only non-employee directors receive compensation
for serving on the Board of Directors.

 (2)
 Mr. Williams was elected to the Board on May 20, 2022, effective as of May
25, 2022.

 The Board of Directors continue to forgo the payment
of any fees or retainers until a more positive cash flow is seen by the Company and positive effects are seen by the shareholders.

 The Compensation Committee will re-evaluate its director
compensation policies periodically, and at least annually, taking into consideration the Company's financial status. All details
can be seen in the Director Summary Compensation Table below.

 DIRECTOR SUMMARY COMPENSATION TABLE

 The table below provides information concerning compensation
paid to, or earned by, directors for the fiscal year ended February 28, 2023 (1).

 Name

 Fees Earned

 Or

 Paid in Cash 2)

 ($)

 Stock Awards

 ($)

 All other

 compensation

 ($)

 Total (2)

 ($)

 Timothy R. Lindsey

 —

 —

 —

 James F. Meara

 —

 —

 —

 James F. Westmoreland (1)

 —

 —

 —

 Darren Williams (3)

 —

 —

 —

 (1)

 As an employee director, Mr. James F. Westmoreland did not receive any compensation for serving on the Board of Directors during the fiscal year ended February 28, 2023. Only non-employee directors receive compensation for serving on the Board of Directors.

 (2)

 As a result of the Company's limited
 available cash, the Board of Directors, beginning in June 2010 postponed receiving payments of meeting fees and quarterly retainer
 fees until cash flow would allow. On August 22, 2019, the Board of Directors agreed to forgive 50% of accrued, deferred
 board fees owed to them, and to temporarily discontinue future board fees, deemed to take effect as of June 1, 2019. The
 Compensation Committee re-evaluates the policy at least annually, taking into consideration the Company's financial
 status. On February 22, 2022, the members of the Board of Directors converted the remaining 50% of their accrued but
 unpaid fees into Common Stock as part of the Related Party Debt Conversion described above.

 (3)

 Mr. Williams was elected to the Board on May 20, 2022, effective as of May 25, 2022.

 REPORT OF THE COMPENSATION COMMITTEE

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

 COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

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

 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 Securities Authorized for Issuance Under Equity
Compensation Plans

 None.

 Security Ownership of Certain Beneficial Owners,
Executive Management and Directors

 Our four directors and officers of the Company together
own and control about 3% percent of our outstanding Common Stock.

 Our shareholders do not have the right to cumulative
voting in the election of our directors. Cumulative voting could allow a minority group to elect at least one director to our Board. Because
there is no provision for cumulative voting, a minority group will not be able to elect any directors. Conversely, if our principal beneficial
shareholders and directors wish to act in concert, they would be able to vote to appoint directors of their choice, and otherwise directly
or indirectly control the direction and operation of the Company.

 As of January
22, 2024, based on information available to the Company, the following tables shows the beneficial ownership of the Company's
voting securities (Common Stock) by: (i) any persons or entities known by management to beneficially own more than 5% of the outstanding
shares of the Company's Common Stock; (ii) each current director and director nominee of the Company; (iii) each current executive
officer of the Company named in the Summary Compensation Table appearing on page 96; and
(iv) all of the current directors and executive officers of Daybreak as a group. The address of each of the beneficial owners, except
where otherwise indicated, is the Company's address. Unless otherwise indicated, each person shown below has the sole power to vote
and the sole power to dispose of the shares of voting stock listed as beneficially owned.

 Security Ownership of Certain Beneficial Owners

 The following table shows the beneficial owners of
five percent or more of the Company's Common Stock, based on information available as of January
22, 2024.

 Class of Stock

 Name and Address of Beneficial of Beneficial Owner

 Amount and

 Nature of

 Beneficial

 Ownership (1,2)

 Currently

 Exercisable or

 Exercisable

 Within 60 Days

 Total

 Beneficial

 Holdings

 Percent of

 Class *

 Common

 Gaelic Resources Ltd. (1)

 -

 8th Floor, 20 Primrose Street, London, EC2A 2EW

 Portillion Capital Ltd (2)

 128,125,000

 128,125,000

 Level 33, 25A Canadian SQ., Canary Wharf London E14 5LQ

 Kamran Sattar (3)

 Red Roofs Traps Ln,

 London KT3 4RY United Kingdom

 To reflect "beneficial ownership" as defined
in Rule 13d-3 promulgated under the Securities Exchange Act

 *Percent of class is shown only for holdings of 1%
or more. Based upon 384,734,902 shares of Common Stock outstanding as of January
22, 2024.

 (1)
 Based on its Form 3 filed on May 27, 2023, and its Schedule 13D filed with the SEC on May 31, 2022, and
subsequently amended on June 24, 2022 Gaelic Resources Ltd. ("Gaelic") owns 160,964,489 shares. Gaelic has sole voting power
and sole dispositive power over these shares. On May 25, 2022, 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")
closed the transactions contemplated by the Equity Exchange Agreement (the "Exchange Agreement") dated as of October 20, 2021,
amended on February 22, 2022 and May 24, 2022 by and between Daybreak, Reabold, and Gaelic. At the

 closing, (i) Gaelic irrevocably assigned
and transferred all of its ownership interests in Reabold to Daybreak, and (ii) Daybreak authorized the issuance of 160,964,489 shares
of its Common Stock to Gaelic, as a result of which Reabold became a wholly-owned subsidiary of Daybreak and Gaelic. The closing of the
Equity Exchange and the transactions contemplated thereby was approved by the Daybreak shareholders at the Special Meeting of Shareholders
held on May 20, 2022.

 (2)
 On May 26, 2022, Daybreak completed the sale of 125,000,000 shares of its Common Stock, par value $0.001,
to Portillion Capital Ltd. ("Portillion") for a purchase price of $0.02 per share, or $2,500,000 in the aggregate, pursuant
to the previously disclosed Subscription Agreement dated May 5, 2022 (the "Capital Raise"). In connection with the closing
of the Capital Raise, Daybreak also paid Portillion certain fees in additional shares of Common Stock. This resulted in Portillion owning
a total of 128,125,000 shares of Daybreak Common Stock. According to Portillion, they do not sole voting or dispositive control over these
shares. The closing of the Equity Exchange and the transactions contemplated thereby was approved by the shareholders of the Company at
the Special Meeting of Shareholders held on May 20, 2022.

 (3)
 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 it 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.

 Security Ownership of Executive Management and
Directors

 The following table shows the number of shares of
Daybreak Common Stock beneficially owned as of January 22, 2024, by each director, by each
executive officer named in the Summary Compensation Table and by all directors and executive officers as a group. Unless otherwise indicated
by footnote, we believe, based on the information furnished to us, that the persons named in the table have sole voting and investment
power with respect to all shares shown as beneficially owned by them. Unless otherwise provided, the address of each individual listed
below is c/o the Company at 1414 S. Friendswood Dr., Suite 212, Friendswood, TX 77546.

 Class of Stock

 Name of Beneficial Owner

 Amount and

 Nature of

 Beneficial

 Ownership (1,)

 Currently

 Exercisable or

 Exercisable

 Within 60 Days (2)

 Total

 Beneficial

 Holdings

 Percent of

 Class (X)

 Common

 Timothy R. Lindsey, Director

 1,058,819 (3)(4)

 -

 1,058,819 (3)(4)

 *

 James F. Meara, Director

 328,889 (3)(5)

 -

 328,889 (3)(5)

 *

 James F. Westmoreland, President and Chief Executive Officer and Director

 9,925,617 (3)(6)

 -

 9,925,617 (3)(6)

 2.6

 Bennett W. Anderson, Chief Operating Officer

 821,214 (3)(7)

 -

 821,214 (3)(7)

 *

 Darren Williams, Director

 -0-

 -0-

 *

 All (5) directors and executive officers as a group

 12,134,539 (3)(8)

 -

 12,134,539 (3)(8)

 3.2

 To reflect "beneficial ownership"
as defined in Rule 13d-3 promulgated under the Securities Exchange Act

 *
 Percent of class is shown only for holdings of 1% or more. Based upon 384,734,902
shares of Common Stock outstanding as of January 22, 2024. Includes shares believed to be
held directly or indirectly by directors and executive officers that have voting power and/or the power to dispose of such shares. Unless
otherwise noted, each individual or member of the group has the sole power to vote and the sole power to dispose of the shares listed
as beneficially owned.

 (1)

 To reflect "beneficial ownership"
 as defined in Rule 13d-3 promulgated under the Securities Exchange Act of 1934, this column includes shares as to which each individual
 has (A) sole voting power, (B) shared voting power, (C) sole investment power, or (D) shared investment power, and (E) the right
 to acquire within sixty days (from January 22, 2024).

 (2)

 Based upon 384,734,902 shares of Common Stock outstanding as of January 22, 2024, and right to acquire and within 60 days of January 22, 2024

 (3)

 On December 15, 2021, the Company 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 "Debt Conversion") at a conversion rate of $0.45 per share of Common Stock. There was a total of 3,105,851 shares issued to the current directors and executive officers of Daybreak as a group in exchange for $1,397,601. Completing this Debt Conversion was a condition to closing the Equity Exchange.

 (4)

 This includes 148,819 shares acquired under the terms of the Debt Conversion, as detailed above, for conversion of $66,969 of owed but unpaid director fees.

 (5)

 This includes 168,889 shares acquired under the terms of the Debt Conversion, as detailed above, for conversion of $76,000 of owed but unpaid director fees.

 (6)

 This includes 6,958,758 shares acquired under the terms of a Convertible Note Purchase Agreement with Mr. Westmoreland, the Company's Chairman, President and Chief Executive Officer. He loaned the Company $27,835 for general operating expenses under a Convertible Note Purchase Agreement. The Note had a maturity date of 180 days, or July 12, 2020 and carried no interest, fees or penalties. On July 13, 2020, the note payable was converted to 6,958,758 shares of the Company's Common Stock. The note payable had a conversion formula of $0.004 per share. This total also includes shares acquired under the terms of the Debt Conversion, as detailed above, for conversion of $514,986.35 in an outstanding 12% subordinated note and accrued interest into 1,144,414 shares of Common Stock.; and conversion of a production payment of $550,100 he bought from the Company into 1,222,444 shares of Common Stock.

 (7)

 This includes 421,214 shares acquired under the terms of the Debt Conversion, as detailed above, for conversion of $189,546 of owed but unpaid salary compensation.

 (8)

 There was a total of 3,105,781 shares issued to the current directors and executive officers of Daybreak as a group in exchange for $1,397,601.

 c hanges
in Control

 None.

 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
AND DIRECTOR INDEPENDENCE

 Transactions with Related Persons, Promoters and
Certain Control Persons

 The Board adopted a policy prescribing procedures
for review, approval and monitoring of transactions involving Daybreak and "related persons" (directors and executive officers
or their immediate family members, or shareholders owning 5% (five percent) or greater of our outstanding stock). The Policy Statement
Regarding Related Party Transactions of Daybreak Oil and Gas, Inc. ("Related Party Transactions Policy") supplements the conflict
of interest provisions in our Ethical Business Policy Conduct Statement and Corporate Governance Guidelines. The Board has determined
that the Governance Committee is best suited to review and consider for approval related party transactions, although the Board may instead
determine that a particular related party transaction be reviewed and considered for approval by a majority of disinterested directors.

 The Related Party Transactions Policy covers any related
person transaction that involves amounts exceeding $50,000 in which a related person has a direct or indirect material interest. In addition,
the Related Party Transactions Policy applies specifically to transactions involving Daybreak and any of the following:

 (1)

 all officers;

 (2)

 directors and director nominees;

 (3)

 5% shareholders;

 (4)

 immediate family members of the foregoing individuals (broadly defined to include any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law);

 (5)

 any entity controlled by any of the individuals in (1), (2), (3) or (4) above (whether through ownership, management authority or otherwise); and

 (6)

 certain entities at which any of the individuals in (1), (2), (3) or (4) above is employed (generally, if the individual employed is directly involved in the negotiation of the transaction, has or shares responsibility at such entity for such transaction, or might receive compensation tied to such transaction).

 On July 27, 2023, the Company entered into an unsecured Promissory Note
(the "Agreement") in which James F. Westmoreland, the Company's Chairman, President and Chief Executive Officer, loaned
the Company the aggregate principal amount of $60,000.00 (the "Westmoreland Note").

 The Westmoreland Note has a maturity date of July
27, 2024, and carries no interest, fees or penalties. The Company may prepay the Note at any time.

 The Company's Chief Operating Officer, Bennett
Anderson is fifty percent (50%) owner in Great Earth Power, a company that provides a portion of the solar power electrical service to
Daybreak for its production operations at the East Slopes Project in Bakersfield, California. Great Earth Power began providing a portion
of the solar powered electrical service for production operations in California in July 2020. For the twelve months ended February 28,
2023 and February 28, 2022, Mr. Anderson received approximately $7,831 and $10,150, respectively from Great Earth Power.

 Mr. Anderson is also a fifty percent (50%) owner in
ABPlus Net Holdings, a company that provides tank rentals to Daybreak for its production operations in Kern County, California. ABPlus
began providing portable tank rentals to the Company as a part of its water treatment and disposal operations in September 2020. For the
twelve months ended February 28, 2023, and February 28, 2022, Mr. Anderson received approximately $ 5,760
and $ 6,720, respectively from ABPlus Net Holdings.

 Great Earth Power provides solar electricity and ABPlus
Net Holdings provides tank rentals to Daybreak at very reasonable rates, saving the Company significant money.

 On December 15, 2021, the Company 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 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 will acquire Reabold in exchange for issuing 160,964,489 shares of its Common Stock to Gaelic (the foregoing transaction, the
"Equity Exchange").

 As part of
this agreement, Mr. Westmoreland converted $514,986 in an outstanding debt under a 12% subordinated note and accrued interest into 1,144,414
shares of Common Stock; and agreed to convert a production payment of $550,100 that he purchased from the Company, into 1,222,444 shares
of Common Stock. Also on December 15, 2022, Mr. Westmoreland agreed to forgive the Company of $43,192 in accrued but not paid past salary,
related taxes and expense reimbursements.

 Also, under
the same Related Party Debt Conversions, Mr. Anderson converted $189,546 in accrued but unpaid salary into 421,214 shares of Common Stock.

 Mr. Timothy
R. Lindsey and Mr. James F. Mears agreed to convert their accrued, deferred director fees owed to them in the amounts of $66,969; and
$76,000; into 148,819, and 168,889 shares of Common Stock, respectively.

 All Related
Party Debt Conversion shares were issued on February 22, 2022.

 All transactions were reviewed and approved by the
Company's Board of Directors, including all disinterested directors, all the members of the Compensation Committee and all the members
of the Nominating and Corporate Governance Committee, and were approved pursuant to the Company's Related Party Transactions policy.

 Director Independence

 We seek individuals who are able to guide our operations
based on their business experience, both past and present, or their education. Our business model is not complex and our accounting issues
are straightforward.

 The Governance Committee is delegated with the responsibility
to review the independence and qualifications of each member of the Board and its various Committees. Directors are deemed independent
only if the Board affirmatively determines that they have no material relationship with Daybreak, directly, or as an officer, shareowner
or partner of an organization that has a relationship with us.

 The Company has adopted the standards of NYSE American
for determining the independence of its directors. The Company is not listed on NYSE American and is not subject to the rules of NYSE
American but applies the rules established by NYSE American to establish director independence.

 These independence standards specify the relationships
deemed sufficiently material to create the presumption that a director is not independent. No director qualifies as independent unless
the Company's Board affirmatively determines that the director does not have a relationship that would interfere with the exercise
of independent judgment in carrying out the responsibilities of a director. In addition, Section 803A of the NYSE American Company Guide
(and related commentary) sets forth the following non-exclusive list of persons who shall not be considered independent:

 (a)

 a director who is, or during the past three years was, employed by the Company, other than prior employment as an interim executive officer (provided the interim employment did not last longer than one year);

 (b)

 a director who accepted or has an immediate family member who accepted any compensation from the Company in excess of $120,000 during any period of twelve consecutive months within the three years preceding the determination of independence, other than the following:

 (i)

 compensation for Board or Board committee service,

 (ii)

 compensation paid to an immediate family member who is an employee (other than an executive officer) of the Company,

 (iii)

 compensation received for former service as an interim executive officer (provided the interim employment did not last longer than one year), or

 (iv)

 benefits under a tax-qualified retirement plan, or non-discretionary compensation;

 (c)

 a director who is an immediate family member of an individual who is, or at any time during the past three years was, employed by the Company as an executive officer;

 (d)

 a director who is, or has an immediate family member who is, a partner in, or a controlling shareholder or an executive officer of, any organization to which the Company made, or from which the Company received, payments (other than those arising solely from investments in the Company's securities or payments under non-discretionary charitable contribution matching programs) that exceed 5% of the organization's consolidated gross revenues for that year, or $200,000, whichever is more, in any of the most recent three fiscal years;

 (e)

 a director who is, or has an immediate family member who is, employed as an executive officer of another entity where at any time during the most recent three fiscal years any of the issuer's executive officers serve on the compensation committee of such other entity; or

 (f)

 a director who is, or has an immediate family member who is, a current partner of the Company's outside auditor, or was a partner or employee of the Company's outside auditor who worked on the Company's audit at any time during any of the past three years.

 Directors serving on the Company's audit committee
must also comply with the additional, more stringent requirements set forth in Section 803B of the NYSE American Company Guide and Rule
10A-3 of the Securities Exchange Act of 1934, as amended.

 Consistent with these considerations, after review
of all relevant transactions and/or relationships between each director and any of his family members and Daybreak, its senior management
and its independent registered public accountants, the Board affirmatively determined that two of the current directors, Messrs. Timothy
R. Lindsey, and James F. Meara are independent. Mr. James F. Westmoreland, our President and Chief Executive Officer, is not independent.
Directors serving on the Company's compensation committee must also comply with the additional, more stringent requirements as set
forth in Section 805(c) of the NYSE American Company Guide.

 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

 Fees Billed by Independent Registered Public Accountants

 A summary of fees for professional services performed
by MaloneBailey, LLP ("MaloneBailey") for the audit of our financial statements for the fiscal years ended February 28, 2023
and February 28, 2022 is set forth in the table below:

 Services Rendered

 Fees Billed for the

 Fiscal Year Ended

 February 28 2023

 Fees Billed for the

 Fiscal Year Ended

 February 28 2022

 Audit fees

 $

 100,000

 $

 70,000

 Audit-related fees

 100,000

 —

 Tax fees

 —

 —

 All other fees

 —

 —

 Total

 $

 200,000

 $

 70,000

 The Audit Committee has reviewed the nature and scope
of the services provided by MaloneBailey and considers the services provided to have been compatible with the maintenance of MaloneBailey's
independence.

 The Audit Committee has determined that the scope
of services to be provided by MaloneBailey for the year ending February 29, 2024, will generally be limited to audit and audit-related
services. The Audit Committee must expressly approve the provision of any service by MaloneBailey outside the scope of the foregoing services.

 Pre-Approval Policies and Procedures

 The Audit Committee has adopted guidelines for the
pre-approval of audit and permitted non-audit services by our independent registered public accountants. The Audit Committee considers
annually and approves the provision of audit services by our independent registered public accountants and considers and pre-approves
the provision of certain defined audit and non-audit services. The Audit Committee also considers on a case-by-case basis and approves
specific engagements that are not otherwise pre-approved. Any proposed engagement that does not fit within the definition of a pre-approved
service may be presented to the Chairman of the Audit Committee. The Chairman of the Audit Committee reports any specific approval of
services at the next regular Audit Committee meeting. The Audit Committee reviews a summary report detailing all services being provided
to Daybreak by its independent registered public accountants. All of the fees and services described above under "audit fees,"
"audit-related fees," "tax fees" and "all other fees" were pre-approved in accordance with the Audit
Fee Pre-Approval Policy and pursuant to Section 202 of the Sarbanes-Oxley Act of 2002.

 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 The following Exhibits are filed as part of the report:

 2.1

 Equity
 Exchange Agreement dated October 20, 2021 by and between Daybreak Oil and Gas, Inc., Reabold California LLC, and Gaelic Resources
 Ltd. (incorporated by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K dated October
 26, 2021, and filed on October 27, 2021).

 2.2

 Letter
 Agreement by and between Daybreak Oil and Gas, Inc., and Gaelic Resources Ltd., effective as of February 14, 2022 (incorporated
 by reference to Exhibit 2.2 of the Company's Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15,
 2022) to amend the Equity Exchange Agreement dated October 20, 2021 by and between Daybreak Oil and Gas, Inc., Reabold California
 LLC, and Gaelic Resources Ltd.

 2.3

 Letter
 Agreement by and between Daybreak Oil and Gas, Inc., and Gaelic Resources Ltd., effective as of May 24, 2022 (incorporated
 by reference to Exhibit 2.3 of the Company's Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15,
 2022) to amend the Equity Exchange Agreement dated October 20, 2021 and amended on February 22, 2022 by and between Daybreak Oil
 and Gas, Inc., Reabold California LLC, and Gaelic Resources Ltd.

 3.01

 Second
 Amended and Restated Articles of Incorporation of Daybreak Oil and Gas, Inc. dated May 20, 2022 (incorporated
 by reference to Exhibit 3.02 of the Company's Quarterly Report on Form 10-Q for the period ended August 31, 2022, dated October
 27, 2022, and filed on 28, 2022.)

 3.02

 Amended
 and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company's Current Report on Form 8-K filed
 on April 9, 2008).

 4.01+

 Specimen Stock Certificate

 4.02

 Description
 of Securities (incorporated by reference to Exhibit 4.02 of the Company's Quarterly Report on Form 10-Q for the
 period ended August 31, 2022, dated October 27, 2022, and filed on October 28, 2022.)

 4.03

 Designations
 of Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 of the Company's Form SB-2 on
 July 18, 2006, and incorporated by reference herein. (filed as part of the Articles of Amendment to the Articles of Incorporation
 of Daybreak Oil and Gas, Inc. dated June 30, 2006.))

 4.04

 Form
 of 12% Subordinated Note due 2015 (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form
 8-K, filed on February 3, 2010).

 4.05

 Form
 of Warrant in connection with 12% Subordinated Notes (incorporated by reference to Exhibit 4.2 of the Company's
 Current Report on Form 8-K, filed on February 3, 2010).

 4.06

 Form
 of Amendment to 12% Subordinated Note due 2015 and Warrant to Purchase Shares of Common Stock (incorporated by reference
 to Exhibit 4.13 of the Company's Annual Report on Form 10-K for year ended February 28, 2015).

 4.07

 Form
 of Second Amendment to 12% Subordinated Note due 2017 and Warrant to Purchase Shares of Common Stock (incorporated by
 reference to Exhibit 4.14 of the Company's Annual Report on Form 10-K filed on May 30, 2017).

 4.08

 Warrant
 Agreement by and between Daybreak Oil and Gas, Inc., and Bear to Bull Investor Relations, LLC, dated November 27, 2019.
 (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the period ended November 30,
 2019).

 10.01

 Prospect
 review and non-competition agreement for California project (incorporated by reference to Exhibit 10vi of the Company's
 SB-2/A filed on December 28, 2006).

 10.02

 Prospect
 review agreement for California project (incorporated by reference to Exhibit 10x of the Company's SB-2/A filed
 on December 28, 2006).

 10.03

 Form
 of Subscription Agreement for 12% Subordinated Note due 2015 (incorporated by reference to Exhibit 10.1 of the Company's
 Current Report on Form 8-K, filed on February 3, 2010).

 10.04

 Promissory
 Note, dated June 20, 2011, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland (incorporated by reference
 to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the period ended August 31, 2011).

 10.05

 Promissory
 Note, dated January 31, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland (incorporated by reference
 to Exhibit 10.6 of the Company's Quarterly Report on Form 10-Q for the period ended November 30, 2012).

 10.06

 Credit
 Line Agreement, dated October 24, 2011, by and between Daybreak Oil and Gas, Inc. and UBS Bank USA (incorporated by reference
 to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the quarter ended November 30, 2011).

 10.07

 Mortgage,
 Deed of Trust, Assignment of Production, Security Agreement and Financing Statement (incorporated by reference to Exhibit
 10.2 of the Company's Quarterly Report on Form 10-Q for the period ended November 30, 2020).

 10.08

 Promissory
 Note, dated August 21, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland (incorporated by reference
 to Exhibit 10.7 of the Company's Quarterly Report on Form 10-Q for the period ended November 30, 2012).

 10.09

 Promissory
 Note, dated December 22, 2020, by and between Daybreak Oil and Gas, Inc. and James Forrest Westmoreland and Angela Marie Westmoreland,
 Co-Trustees of the James and Angela Westmoreland Revocable Trust (incorporated by reference to Exhibit 10.1 of the Company's
 Quarterly Report on Form 10-Q for the period ended November 30, 2020).

 10.10

 Securities
 Purchase Agreement dated December 27, 2018 by and between Daybreak Oil and Gas, Inc. and Maximilian Resources, LLC. (incorporated
 by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed on January 3, 2019).

 10.11

 Payment Interest Purchase Agreement dated December 27, 2018 by and among Daybreak Oil and Gas, Inc. and the purchasers named therein.
 (incorporated by reference to Exhibit 10.2 of the Company's Current Report on Form 8-K, filed on January 3, 2019).

 10.12

 Consulting
 Agreement by and between Daybreak Oil and Gas, Inc., and Bear to Bull Investor Relations, LLC, dated October 8, 2019.
 (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the period ended August 31, 2019).

 10.13

 Form
 of Convertible Note Purchase Agreement and Note, issued by the Company by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland
 dated as of January 14, 2020. (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form
 8-K, filed on January 17, 2020).

 10.14

 Form
 of letter agreement regarding conversion of accrued director fees (incorporated by reference to Exhibit 10.1 of the Company's
 Quarterly Report on Form 10-Q for the period ended November 30, 2021, filed on January 18, 2022).

 10.15

 Form
 of letter agreement regarding conversion of accrued salary (incorporated by reference to Exhibit 10.2 of the Company's
 Quarterly Report on Form 10-Q for the period ended November 30, 2021, filed on January 18, 2022).

 10.16

 Form
 of letter agreement dated December 3, 2021 by and between Daybreak Oil and Gas, Inc., and James F. Westmoreland regarding conversion
 of 12% subordinated note (incorporated by reference to Exhibit 10.2 of the Company's Quarterly Report
 on Form 10-Q for the period ended November 30, 2021, filed on January 18, 2022).

 10.17

 Letter
 agreement by and between Daybreak Oil and Gas, Inc., and James F. Westmoreland regarding conversion of Production Payment Interests
 (incorporated by reference to Exhibit 10.37 of the Company's Annual Report on Form 10-K for year ended February 28, 2022, filed
 on June 15, 2022.)

 10.18

 Form
 of letter agreement regarding conversion of the Company's Series A Preferred shares to convert each Series A Preferred share
 to three (3) shares of Daybreak's Common Stock (incorporated by reference to Exhibit 10.38 of the Company's
 Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15, 2022).

 10.19

 Form
 of letter agreement regarding conversion of accrued and unpaid dividends with respect to the Series A Preferred Stock (the "Series
 A Conversion") (incorporated by reference to Exhibit 10.39 of the Company's Annual Report on Form 10-K for
 year ended February 28, 2022, filed on June 15, 2022.).

 10.20

 Form
 of Promissory Note Agreement, issued by the Company dated as of July 27, 2023. (incorporated by reference to Exhibit 10.1
 of the Company's Current Report on Form 8-K, filed on January 17, 2020).

 10.21

 Convertible
 Note Purchase Agreement by and between Daybreak Oil and Gas, Inc. and the purchaser dated as of February 15, 2022 (incorporated
 by reference to Exhibit 10.40 of the Company's Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15,
 2022.)

 21.1+

 Subsidiaries
 of the Registrant

 23.1+

 Consent of PGH Petroleum
 and Environmental Engineers, LLC

 23.2+

 Consent
 of PETROTech Resources Company

 31.1+

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

 32.1+

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

 99.1+

 Reserve Report of
 PGH Petroleum and Environmental Engineers, LLC, independent petroleum engineering consulting firm, as of February 28, 2023

 99.2+

 Reserve Report of
 PETROTech Resources Company, independent petroleum engineering consulting firm, as of February 28, 2023

 101.INS

 101.XSD

 101.CAL

 101.DEF

 101.LAB

 101.PRE

 + Filed herewith.

 * Furnished herewith.

 ITEM 16. FORM 10–K SUMMARY

 The Company has elected not to include the optional
summary information hyperlink.

 SIGNATURES

 Pursuant to the requirements of Section 13 or 15(d)
of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.

 By:

 /s/ JAMES F. WESTMORELAND

 James F. Westmoreland, its

 President, Chief Executive Officer and

 interim principal finance and

 accounting officer

 Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated.

 By:

 /s/ JAMES F. WESTMORELAND

 By:

 /s/ TIMOTHY R. LINDSEY

 James F. Westmoreland

 Timothy R. Lindsey

 Director / President and Chief Executive Officer

 Director

 By:

 /s/ JAMES F. MEARA

 By:

 /s/ DARREN WILLIAMS

 James F. Meara

 Darren Williams

 Director

 Director

 GLOSSARY OF TERMS

 The following are abbreviations and definitions of
certain terms commonly used in the crude oil and natural gas industry and within this Annual Report on Form 10-K.

 Measurements.

 Bbl One barrel, or 42 U.S. gallons of liquid
volume of oil.

 Boe One stock tank barrel of crude
oil, calculated by converting natural gas volumes to equivalent oil barrels at a ratio of six thousand (6,000) cubic feet of natural gas
to one (1) barrel of crude oil. BOE is the standard convention used to express crude oil and natural gas volumes on a comparable crude
oil equivalent basis.

 Boe/d One stock tank barrel equivalent of oil
per day.

 Btu British thermal unit. One British thermal
unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

 MBbl One thousand (1,000) barrels of oil or
other liquid hydrocarbons.

 MBoe One thousand (1,000) Boe.

 Mcf One thousand (1,000) cubic feet of natural
gas.

 MMBtu One million (1,000,000) British thermal
units.

 MMcf One million (1,000,000) cubic feet of
natural gas.

 Abbreviations.

 API American Petroleum Institute

 ARO Asset retirement obligation

 BLM Bureau of Land Management

 DD&A Depreciation, depletion and amortization

 EPA Environmental Protection Agency

 FERC Federal Energy Regulatory Commission

 Gas Natural Gas

 GHG Greenhouse Gas

 IRS Internal Revenue Service

 NRI Net Revenue Interest

 NYMEX New York Mercantile Exchange

 Oil Crude Oil and Condensate

 PDP Proved Developed Producing Reserves

 PDNP Proved Developed Non-Producing Reserves

 PUD Proved Undeveloped Reserves

 SEC Securities and Exchange Commission

 SWD Saltwater disposal well

 U.S. GAAP Accounting principles generally accepted
in the United States of America

 WI Working Interest

 WTI West Texas Intermediate Crude Oil

 Terms and Definitions.

 3-D seismic. An advanced technology
method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves
transmitted into the earth as they reflect back to the surface.

 American Petroleum Institute. A petroleum induction
association that sets standards for oil field equipment and operations. Also see Oil Gravity.

 Completion. The installation of
permanent equipment for the production of crude oil or natural gas.

 DD&A. Refers to depreciation,
depletion and amortization of the Company's property and equipment.

 Development well. A well drilled
within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 Dry hole. A well found to be incapable
of producing hydrocarbons in sufficient quantities to justify completion as a crude oil or natural gas well.

 Exploratory well. A well drilled
to find a new field or to find a new reservoir in a field previously found to be productive of crude oil and natural gas in another reservoir.
Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

 Fracturing. A procedure undertaken to attempt
to increase the flow of crude oil or natural gas from a well. A fluid (usually crude oil, diesel oil or water) is pumped into the reservoir
with such great force that the reservoir rock is physically broken and split open. Usually the "frac fluid" carries small
pellets or beads mixed in with it; the idea is for them to get caught in the fractures and prop them open (the beads or pellets are called
the "propping agent" or "proppant"). As the pumping pressures are gradually released at the surface, the natural
reservoir pressures will force the "frac fluid" out of the reservoir, and back into the well as the well begins to flow. The
proppant remains behind, holding the fractures open, thereby increasing the flow of crude oil or natural gas from the reservoir into the
well. This procedure is also called hydraulic fracturing. To "frac a well" means to hydraulically fracture a reservoir in
a well.

 Gas. Refers to natural gas. A mixture
of gaseous hydrocarbons formed naturally in the earth.

 Gross acres or wells. Refers to
the total acres or wells in which the Company has a working interest.

 Horizontal drilling. A drilling
technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling
techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

 Hydrocarbons. A large class of organic compounds
composed of hydrogen and carbon. Crude oil, natural gas and natural gas condensate are all mixtures of various hydrocarbons, among which
methane is the simplest.

 Hydraulic fracturing. Refer to the definition
of fracturing.

 Net acres or wells. Refers to the
gross sum of fractional working interest ownership in gross acres or wells.

 Net production. Crude oil and natural
gas production that is owned by the Company, less royalties and production due others.

 New York Mercantile Exchange. The exchange
on which commodities, including crude oil and natural gas futures contracts, are traded.

 Oil. Refers to crude oil or condensate.
A naturally occurring mixture of liquid hydrocarbons as it comes out of the ground.

 Oil Gravity. The density of liquid hydrocarbons
generally measured in degrees API. The lighter the crude oil, the higher the API gravity. Heavy oil has an API gravity of 20
API or less. For example, motor lubricating oil is around 26 API; while gasoline is approximately
55 API.

 Operator. The individual or company
responsible for the exploration, development and production of a crude oil or natural gas well or lease.

 Play. A geographic area with hydrocarbon
potential.

 Productive wells. Producing wells and wells
mechanically capable of production.

 Proved Developed Reserves. Proved
reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the
cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment
and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 Proved reserves. Proved crude oil
and natural gas 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 – prior to the time at which contracts providing the right to
operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods
are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that
it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A)
The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can,
with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or natural gas on the basis
of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir
are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and
reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations
has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved crude oil reserves may be assigned
in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish
the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved
recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful
testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation
of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable
certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development
by all necessary parties and entities, including government entities.

 Proved undeveloped reserves (PUD). Undeveloped
crude oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage
shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless
evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii)
Undrilled locations can be classified as having

 undeveloped reserves only if a development plan has been adopted indicating that they
are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances
shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous
reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 PV-10. The present value of
estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and
future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to
change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and
administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of ten percent (10%). While this measure does not include the effect of income taxes as it would in
the use of the standard measure calculation, it does provide an indicative representation of the relative value of the applicable
company on a comparable basis to other companies and from period to period.

 Royalty. An interest in a crude
oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage
(or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating
the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the
leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection
with a transfer to a subsequent owner.

 Standardized measure of discounted future net cash
flows. Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net
of the estimated salvage value of related equipment, and (ii) estimated future income taxes.

 Undeveloped acreage. Leased acreage on which
wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil or natural gas,
regardless of whether such acreage contains proved reserves.

 Working interest. An interest in
a crude oil and natural gas lease that gives the owner of the interest the right to drill for and produce crude oil and natural gas on
the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production
to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to
the extent of any royalty burden.

 Workover. Operations on a producing
well to restore or increase production.