UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended February 28, 20222023

For the transition period from ______ to _______

Commission file number 000-50107

DAYBREAK OIL AND GAS, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (509)(281) 232-7674996-4176

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, $.001$0.001 par value

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

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

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

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

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262 (b)) by the registered public accounting firm that prepared or issued its audit report. ¨

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

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

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

The aggregate market value of the voting and non-voting stock held by non-affiliates of the registrant, based on the closing price of $0.035$0.05 on August 31, 2021,2022, as reported by the OTC Pink® Open Market was $1,810,5162,821,727.

At June 14, 2022,January 23, 2024, the registrant had 384,735,402384,734,902 outstanding shares of $0.001 par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE:

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

Common Stock. 

TABLE OF CONTENTS

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This annual reportAnnual 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 1934.1934, 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:

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: 

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

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

PART I

ITEM 1. BUSINESS

Historical Background

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

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

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

Market Conditions, Commodity Prices, and Interest Rates

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

Crude Oil and Natural Gas Overview

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

Our long-term success depends on, among many other factors, the acquisition and drilling of commercial grade crude oil and natural gas properties and on the prevailing sales price for crude oil and natural gas along with controlling the associated operating expenses. The volatile nature of the energy markets makes it difficult to estimate future prices of crude oil and natural gas; however, any prolonged period of depressed prices or periods of market volatility, such as we have experienced since June of 2014,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 Kern County,the Central Valley or San Francisco Bay area of California, and Michigan, although new opportunities may ultimately be secured in other areas.

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

Known Trends and Uncertainties

As we continue to pursue our two developmental drilling programprograms 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.process including other regulatory approval regulations as described below in the section titled “Regulation”. Additionally, our drilling programs are also very sensitive to drilling costs. We attempt to control these costs through drilling efficiencies by working with service providers to receive acceptable unit costs.

In order to continue our drilling programtwo 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 the Company’sour 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 priceprices we receive for crude oil sales in California isfrom our Kern County, California, “East Slopes” project and from our wholly owned Reabold subsidiary are based on prices posted for Midway-Sunset and Buena Vista crude oil delivery contracts, less deductionsrespectively. All posted pricing is subject to adjustments that vary by grade of crude oil, soldtransportation costs, market differentials and transportation costs. Theother local conditions. Both the posted Midway-Sunset priceand Buena Vista prices generally movesmove in correlation to, and at a discount to prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediateintermediate (“WTI”) crude oil, Cushing, Oklahoma delivery contracts. We do not currently have any natural gas revenues.

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

A comparison of the average WTI price and average realized crude oil sales price at our East Slope Project in California for the twelve months ended February 28, 20222023 and February 28, 20212022 is shown in the table below:

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 crude oil sale price was $70.75 representing a discount of $2.56 per barrel or 3.5% lower than the average WTI price. In comparison, for the twelve months ended February 28, 2021, the average WTI price was $39.48 and our average realized sale price was $36.91 representing a discount of $2.57 per barrel or 6.5% lower than the average WTI price. Historically, the sale price we receive for Californiaour East Slopes heavy crude oil has been less than the quoted NYMEX WTI price because of the lower API gravity of our CaliforniaEast 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, 20222023 increased $275,206$853,153 or 68.0%125.4% to $680,107$1,533,260 in comparison to revenue of $404,901$680,107 for the twelve months ended February 28, 2021.2022. The average sale price of a barrel of crude oil for the twelve months ended February 28, 20222023 was $70.75$89.59 in comparison to $36.91$70.75 for the twelve months ended February 28, 2021.2022. The increase of $33.84$18.84 or 91.7%26.6% per barrel in the average realized price of a barrel of crude oil accounted for 134.9%21.2% of the increase in crude oil revenue for the twelve months ended February 28, 2022.2023.

Our net sales volume for the twelve months ended February 28, 20222023 was 9,61317,114 barrels of crude oil in comparison to 10,9709,613 barrels sold for the twelve months ended February 28, 2021. This decrease2022. The increase in crude oil sales volume of 1,3577,501 barrels or 12.4%78.0% was primarily due to fewer well daysthe Reabold subsidiary acquisition in May of production2022 and this overall increase in crude oil sales volume accounted for 78.8% of the natural declineincrease in reservoir pressure duringcrude oil revenue for the twelve months ended February 28, 2021.2023.

The gravity of our produced crude oil from the East Slopes project in CaliforniaKern County ranges between 14°15° API and 16°17° API. Production for the twelve months ended February 28, 2023 and February 28, 2022 was from 20 wells resultingwells. The gravity of our produced crude oil from our Reabold subsidiary in 7,154 well days of production in comparison to 7,288 well days of production from 20 wellsMonterey and Contra Costs Counties is approximately 17° API and 38° API, respectively. Production for the twelve months ended February 28, 2021.2023 was primarily from five wells.

California Natural Gas Prices

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

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 CustomerCustomers

At both of our East Slopes Project, locatedprojects in Kern County, California, we sell all of our crude oil production to one buyer. At February 28, 20222023 and February 28, 2021,2022, 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, 20222023 and February 28, 20212022 are set forth in the table below.below: 

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

Title to Properties

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

Regulation

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

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

All of the states in which we operate generallyhave operated require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of crude oil and natural gas.  Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum rates of production from crude oil and natural gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring of natural gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of crude oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of crude oil and natural gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.

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

The California Department of Conservation Geologic Energy Management Division (CalGEM)(“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. Government actions, including the issuanceIn 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 certainfactors outside of our control can lead to our obtaining drilling permits or approvals, by state and local agencies or by federal agencies may be subjectfrom CalGEM for our operations. CalGEM has not issued any permits for new production wells 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.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)(“EIR”) certified by the Kern County Board of Supervisors in 2015.  A group

Our operations in Kern County have been subject to significant uncertainty over the past several years as a result of plaintiffsongoing 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 EIR and on February 25, 2020, a California Court of Appeal issued a ruling that invalidates a portionsufficiency of the EIR until thefor satisfying CEQA requirements in Kern County makes certain revisions tofor 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 recertifies it. Onroad paving mitigation for purposes of well work and rejected the plaintiffs’ other CEQA claims. The plaintiffs appealed. In February 12, 2021,2020, the California Fifth District Appellate Court (“Appellate Court”) ruled that the plaintiffs’ other CEQA claims had merit and ordered Kern County Planning Commission voted to recommend approval ofrescind the revisions in a supplementary EIR in order to reestablish the county's oilZoning Ordinance and gas permitting system, though it must be approved by the countycease issuing permits. In March 2021, Kern County’s Board of Supervisors before becoming effective.  This certificationapproved 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 expected to be completed insubsequently filed that same month challenging the first halfsufficiency of 2021; however, the supplemental EIR and certification are now inSREIR. In October 2021, the middle of litigation. A court decision is expected sometime in 2022. After the supplementary EIR is certified, it is expected that CalGEM will rely onTrial Court ordered Kern County to serve as lead agent forcease using the existing EIR to meet CEQA purposes, reducing unnecessary delays atrequirements until it determined that the state level.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.

TheFurthermore, the California Legislature hasand 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.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 eventwater we conductproduce 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 or American Indianresponded 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 leases,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, may be requiredexposure to comply with additional regulatory restrictions, including various nondiscrimination statutes, royaltyincreased liability, or other limitations as a result of future actions by these parties. Moreover, new developments resulting from the current and related valuation requirementsfuture actions of these parties could also materially and on-site security regulations,adversely affect our ability to operate, successfully execute drilling plans, or otherwise develop our reserves. Accordingly, recent and other appropriate permits issuedfuture actions by the BureauGovernor of Land Management or other relevant federal orCalifornia, the Legislature, and state agencies.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 induring our crude oil exploration and productionwell completion operations in California.

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

Operational Hazards and Insurance

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

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

Human Capital

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

Long-Term Success

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

Availability of SEC Filings

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

Website / Available Information

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

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

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

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 Volatile Energy Our Business

Risks Related to Environmental Regulation

Risks Related to Our Indebtedness

Risks Related to Our Common Stock

General Risk Factors

RISK FACTORS

Risks Related to Our Business

CrudePrices for crude oil and natural gas prices are volatile. From January 2020 through February 2021, there was a significantcan fluctuate widely and an extended period of depressed commoditylow prices that significantly adversely affected,could materially and in the future may continue to adversely affect our financial condition, liquidity, 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 ability to grow.

Our revenues, operating results, liquidity, cash flows, profitability and valuation of proved reserves depend substantially upon the market prices of crude oil and natural gas. Product prices affect our cash flow available for capital expenditures and our ability to access funds through the capital markets. Declines in commodity prices have historically adversely affected the estimated value of our proved reserves and our cash flows. The volatile nature of the energy markets makes it difficult to estimate future prices of crude oil and natural gas; however, any prolonged period of price instability, such as was experienced from February 2020 through January 2021, has had a material adverse effect on our cash flows, reserves valuation and availability of funds in the financial markets. Specifically, our average annual realized price of crude oil salesgrow. Prices for the twelve months periods ended February 28, 2022, 2021 and February 29, 2020 was $70.75, $36.91 and $60.25, respectively.

The commodity prices we receive for our crude oil and natural gas depend uponmay 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, including among others: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 importsimports;

—·  political and economic conditions, including international disputes;

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

—·   overall domestic and foreign economic conditions.

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

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

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

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

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

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

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

Risks RelatedThe 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:

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 Businessfuture 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:

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.

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

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

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

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

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

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 capital expendituresgeographic areas may disproportionately expose us to operational, regulatory and drilling program, when coupled with a sustained depression in crude oil and natural gas prices, will significantly reduce our cash flow and constrain any future drilling, which would have a material adverse effect on our business, financial condition and results of operations.geological risks.

Historically,Our two producing projects are located in California. As a result of this concentration, we have made substantial capital expenditures formay be disproportionately exposed to the explorationimpact of regional conditions which could negatively impact the success and developmentprofitability 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 reserves. The combination of lower hydrocarbon priceshave 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 reductionpotential increase to the frequency of drought and flooding. Further, our drilling operations may be exposed to power outages, mechanical failures, industrial accidents or labor difficulties. Any one of these events has resultedthe potential to cause producing wells to be shut in, reduced productiondelay operations and operatinggrowth plans, decrease cash flows, since Juneincrease operating and capital costs, prevent development of 2014. A continued sustained volatility in these hydrocarbon prices combined with reduced productionlease inventory before expiration and accompanying lower cash flows will continuelimit access to adversely affectmarkets for our business financial condition and results of operations.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 past years other than our East Slopes projectorder to maintain current production levels, we will be required to find and develop additional reserves either in California, our crude oil and natural gas 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 may reclassifyhave reclassified proved undeveloped reserves to unproved reserves due to our inability to commit sufficient capital within the required five-year development window, which could adversely affect the value of our properties.

The SEC generally requires that any undrilled location can be classified as a proved undeveloped reserve only if a development plan has been adopted indicating that the location is scheduled to be drilled within five years. The reduction of our drilling program in response to depressed crude oil and natural gas prices and a lack of drilling capital has impacted our ability to develop proved undeveloped reserves within such five-year period. IfThe reduction in our reduced drilling plans continue over a significant period of timehas limited our future access to capital resources will be limited, andresources. In the past, we will also likely further delay the development of our proved undeveloped reserves or ultimately suspend such development which could result in the reclassification ofhave had to reclassify a significant amount of our proved undeveloped reserves as probable or possible reserves. A significantreserves because they have not been drilled within the SEC-defined time period. Any future reclassification of proved undeveloped reserves couldmay adversely affect the value of our properties.

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

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

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

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.

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.

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:

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 projectand 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.

New technologies may causeRecent 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 current exploration and drilling methodsability to become obsoletesell or acquire assets in the state of California or increase our costs in connection with the same..

ThereOn 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 rapid and significant advancements in technology in the natural gas and crude oil industry, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage,taken to contain or treat their impact, and competitive pressures maythe impacts on the economy generally and oil prices in particular, are uncertain, rapidly changing and hard to predict. This uncertainty could force us to implement new technologies at a substantial increasereduce 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 cost. Further, competitorsconnection with the pandemic. If our suppliers cannot deliver the materials, supplies and services we need, we may obtain patents which might prevent us from implementing new technologies.need to suspend operations. In addition, competitorswe 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 greater financial, technical and personnel resources that allow them to enjoy technological advantages and maythe effect of heightening or exacerbating many of the other risks described in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.Risk Factors herein.

Risks related to Environmental Regulation

RecentOur crude oil and future actions bynatural 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 statedischarge of Californiapollutants 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 restrictions tosignificant civil or criminal penalties and remediation costs. Some of our operations and resultproperties may be affected by environmental contamination that may require investigation or remediation. In addition, claims are sometimes made or threatened against companies engaged in decreased demand forcrude oil and natural gas within the state.

In September 2020, Governor Gavin Newsomexploration and production by owners of California issued an executive order (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 closure and repurposing of oil and 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 setbackssurface estates, adjoining properties 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. In February 2021, SB 467 was introduced in the state senate. If passed, the bill would ban new permits for hydraulic fracturing, acid well stimulation treatments, cyclic steaming, water flooding and steam flooding – beginning in 2022 and would ban these activities in total beginning in 2027. The bill would also allow local governments to prohibit such practices prior to 2027. After the bill was introduced one of the authors announced that it would also be amended to also add a 2,500 feet setback for new wellsothers alleging damage resulting from sensitive receptors. We cannot predict the outcome of this most recent legislative effort. Previous high profile efforts to pass mandatory setbacks have failed; however, any of the foregoing developmentsenvironmental contamination and other future actions taken by the stateincidents of operation. Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may materially and adversely affect our operationsbusiness, financial condition and properties and the demand for our products.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:

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.

OurIn 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 explorationfacilities 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 related activitiespropose additional regulations, which are subjectexpected to extensive environmental regulations,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 laws that can give riseimplement other measures to substantial liabilities from environmental contamination.mitigate climate change and strengthen biodiversity.

Our operations are subject to extensive federal, state and local environmental laws and regulations,On September 16, 2022, the Governor of California signed Senate Bill No. 1137 into law, which impose limitations onestablished 3,200 feet as 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 inminimum distance between new crude oil and natural gas explorationproduction 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 by ownersfacilities; the annual submission of surface estates, adjoining properties ora 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, alleging damage resulting fromthe imposition of health, safety and environmental contaminationcontrols applicable to both current and other incidentsnew wells located within this distance of operation. Compliancesensitive 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 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.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.

Risks Related to Our Indebtedness

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

We have reported net loss of approximately $398,450$2.4 million for the year ended February 28, 2022,2023, and we have an accumulated deficit through February 28, 20222023 of approximately $29.5$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.

We have substantial indebtedness. The amount ofOur ability to satisfy our outstanding indebtedness and our current inability to meet our debt obligations will have adverse consequencesdepends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. Our business financial condition and results of operations.

At February 28, 2022, we had approximately $4.3 million of consolidated indebtedness comprised of a variety of short-term and long-term borrowings; a line of credit; trade payables; and 12% Subordinated Notes. The 12% Notes had a maturity date of January 29, 2019 and the principal balance of $315,000 hasdoes not been paid. The level of indebtedness we have affects our operations in a number of ways. We will need to use a portion of ourgenerate sufficient cash flow to meet principal, interestour ongoing obligations, and payables commitments; which reduces the amount of funds we will havefuture financings may not be available to finance our operations. This lack of funds limits planning forprovide sufficient net proceeds, to meet these obligations or reacting to changes insuccessfully execute our business and the industry in which we operate and could limit our ability to make funds available for other purposes, such as future exploration, development or acquisition activities. Our ability to meet our debt service obligations and reduce our total indebtedness will depend upon our future performance.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.

General Risk Factors

Certain U.S. federal income tax deductions currently available with respectWe have substantial indebtedness. The amount of our outstanding indebtedness and our current inability to crude oil and natural gas exploration and development may be eliminated as a result of proposed legislation.

Legislation previously 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. It is unclear whether any such changesmeet our debt obligations will be enacted and, if enacted, how soon any such changes could become effective. The passage of this type of legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to crude oil and natural gas exploration and development, and any such change could negatively impact the value of an investment inhave adverse consequences on our Common Stock as well as affect ourbusiness, 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.

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 President and Chief Executive Officer, who is also acting as our interim principal finance and accounting officer, our Directorlevel of Field Operations, and two of our directors each have substantial experience in the crude oil and natural gas business. The loss of any of these individualsindebtedness 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.in several ways, including the following:

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

Risks Related to Our Common Stock

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

Our financial statements for the year ended February 28, 20222023 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) tradestraded on the OTC Pink® Open Market under the OTC Markets Group segment, Pink Current Information. Prior to May 1, 2016, our stock had traded on the OTCQB Venture Marketplace. Our transition to the OTC Pink® Open Market was the result of a cost-savings move for the company related to listing fees on the Venture Marketplace.

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

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

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

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

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

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

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

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

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

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

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

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

Our authorized capital stock consists of 200,000,000500,000,000 shares of Common Stock and 10,000,000 shares of preferred stock.Stock. As of February 28, 2022,2023, there were 67,802,273384,734,902 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 equitydebt-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:

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 yeartwelve months ended February 28, 2022,2023, we were involved in the operation oftwo 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, 2022.2023. Throughout this Annual Report on Form 10-K, crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).

Kern County, California (East Slopes Project)

The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California. Drilling targets are porous and permeable sandstone reservoirs that exist at depths of 1,200 feet to 4,500 feet. Since January 2009, we have participated in the drilling of 25 wells in this project.project, of which 20 wells were successful. We have been the Operator at the East Slopes Project since March 2009.

Our 20 producing crude oil wells in the East Slopes Project produce from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations. The Sunday property has six producing wells, while the Bear property has nine producing wells. The Black property is the smallest of all currently producing reservoirs, and currently has two producing wells at this property. The Ball property also has two producing wells while the Dyer Creek property has one producing well. Our average working interest and NRI in these 20 producing crude oil wells is 36.6% and 28.4%, respectively.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 Central Processing and Storage Facility

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

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

California Producing Properties

Sunday Property

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

Bear Property

In February 2009, we made our second crude oil discovery 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. We have a 37.5% working interest in all wells on the Bear property. Our NRI in the Bear #1, Bear #2, Bear #3 and Bear #4 wells is 26.1%. For the Bear #5, Bear #6 and Bear #7 wells our NRI is 30.1%. Our NRI in the Bear #8 and Bear #9 wells is 31.7%. The average working interest and NRI for the Bear property for the ten producing wells in aggregate is 37.5% and 28.7%, respectively. The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least eleven more development wells to be drilled in the future.

Black Property

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

Ball Property

The Ball #1-11 well was put on production in late October 2010. In June 2013 we drilled a development well, the Ball #2-11, on this property. Production on this property is from the Vedder Sand at approximately 2,500 feet. We have a 37.5% working interest with a 31.7% NRI in the two producing wells on this property. Our 3-D seismic data indicates aThe Ball reservoir ofis 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. We have a 37.5% working interest with a 31.7% NRI in all wells on this property. The Dyer Creek property has the potential for at least one development well in the future.

Sunday Central Processing and Storage Facility

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

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

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

Monterey County Properties

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

Contra Costa County Property

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

California Drilling Plans

We plan to drill fourthree development wells and one SWD well in our East Slopes project area in the 20222024 – 20232025 fiscal year once additional financing is put in place. When new financing is secured, the capital investment required for the fourthree development wells and one SWD well is $525,000.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 Californiathe Kern County project filed a UCC financing statement in regards to payables owed to the partner by the Company.

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

Reserves

Crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”). The following table sets forth our estimated net quantities of proved reserves as of February 28, 2022.2023.

As of February 28, 2022,2023, 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.

Changes in our estimated total net proved reserves (BOE) for the twelve months ended February 28, 20222023 are set forth in the table below.

Revisions. Net upward revisions of 3,0526,235 BOE of developed reserves in aggregate were due to the higher net crude oil and natural gas prices in Californiawe received during the twelve months ended February 28, 20222023 increasing the economic life of our proved reserves.reserves, offset by the removal of 399,311 BOE of proved undeveloped reserves that have remained for a period greater than five years as of February 28, 2023.

Discoveries and extensions. For the twelve months ended February 28, 2022, net2023, we had no discoveries or extensions of 89,493reserves.

Purchase of minerals. For the twelve months ended February 28, 2023, we acquired through the Reabold subsidiary acquisition 287,582 BOE reserves were added in California due to an increase in economic PUD locations.of developed reserves.

Production. Production in California was 9,61317,751 BOE in aggregate of proveddeveloped reserves for the twelve months ended February 28, 2022.

As of February 28, 2022, our total proved undeveloped reserves were comprised of our interests in Kern County, California.2023.

Changes in our estimated net proved undeveloped reserves (BOE) for the twelve months ended February 28, 20222023 are set forth in the table below.

Revisions. There were netA downward revisionsrevision of 29,285399,311 BOE in aggregate due to lower estimated reservoir production of our proved undeveloped reserves.

Discoveries and extensions. Forreserves occurred for the twelve months ended February 28, 2022, there2023. 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 89,493 BOE in extensions duepreviously considered to an increase in economic PUD locations in California.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, 20222023 are set forth in the table below.

Our estimated netUnder 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 in California at February 28, 2021 are set forth in the table below.

The Company has 273,265 Bbls ofsince 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 undeveloped reserves have remained undeveloped due to depressed crude oil and natural gas prices and a lack of capital available for drilling. Under our current drilling plans, we intend to convert all 273,265 BOE or 100.0% of the proved undeveloped reserves disclosed as of February 28, 2022 into proved developed reserves within the next five years.

Our estimated proved reserves (BOE) and PV-10 valuation in California at February 28, 20222023 are set forth in the table below.

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 an increase of approximately $4.5 million or 287.5% from the PV-10 reserve valuation at February 28, 2021.2022. This increase is primarily due to the increaseacquisition of the Reabold project in the base price of crude oil in the current report in comparison to the base price of crude oil in the February 28, 2021 report; and an increase in both PDP and PUD reserve totals. .California. The commodity prices used to estimate proved reserves and their related PV-10 at February 28, 20222023 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the twelve month period from March 20212022 through February 2022.2023. The WTI benchmark average price for the twelve months ended February 28, 2022 was $71.69$93.55 per barrel of crude oil in comparison to $38.64$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, 20222023 reserve report of $68.80$90.43 in comparison to $36.14$68.80 in the February 28, 20212022 reserve report. Adverse changes in any price differential would reduce our cash flow from operations and the PV-10 of our proved reserves. Operating costs were not escalated.

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

Reserve Estimation

All of ourOur estimated proved developed reserves of 517,155116,019 BOE for the East Slopes project in Kern County for the twelve months ended February 28, 20222023 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 3540 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, 2022,2023, we had no commitments to provide any fixed or determinable quantities of crude oil or natural gas in the near future under contracts or agreements.

Summary Operating Data

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

As of February 28, 2022,2023, our total reserves were comprised of our working interest in East Slopes Projectprojects located in Kern, County,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.

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

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

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

Gross and Net Acreage

The following table sets forth our interests in developed and undeveloped crude oil lease acreage in California held by us as of February 28, 2022.2023. These ownership interests generally take the form of working interests in crude oil leases that have varying terms. Developed acreage includes leased acreage that is allocated or assignable to producing wells. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, regardless of whether or not the acreage contains proved reserves. Gross acres represents the total number of acres in which we have an interest. Net acres represents the sum of our fractional working interests owned in the gross acres.

Undeveloped Acreage Expirations

The following table sets forth expiration datesWe have no gross and net undeveloped acreage in California expiring over the next three years as all of our gross and net undeveloped acres in California for the years shown.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 iswas no likely benefit to pursuing any drilling opportunities on the majority of theour expiring leases, and so thewe have not attempted to renew those leases when their expiration of these leases is expected to be immaterial to our operations. Further, none of our proved undeveloped reserves have been assigned to locations that are scheduled to be drilled after the expiration of the current leases. In California, all of our proved undeveloped reserves are assigned to leases that are currently held by production (“HBP”).dates occurred.

Producing Wells

The following table sets forth our gross and net productive crude oil wells in California as of February 28, 2022.2023. Productive wells are producing wells and wells capable of production. Gross wells represent the total number of wells in which we have an interest. Net wells represent the sum of our fractional working interests owned in the gross wells.

Drilling Activity

The following table sets forth our exploratory and development well drilling activity in California forIn the periods shown. Wepast three years, we have had no drilling activity in the past three yearsoccur 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.

PART II

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

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

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.

As of June 14, 2022,January 23, 2024, the Company had 1,7031,700 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

EffectiveThe transfer agent for our Common Stock is ClearTrust, LLC, 16540 Pointe Village Dr, Suite 210 Lutz, Florida 33558. Their website address is: https://www.cleartrustonline.com.

On December 22, 2020,18, 2023, the CompanyBoard of Directors of Daybreak appointed Sedona Equity Registrar & Transfer, Incorporated (“Sedona”ClearTrust LLC “ClearTrust”) as its transfer agent and shareholder support provider. By December 28, 2020,31, 2023, all of the Company's directly held shares of common stock,Common Stock, files and information has beenwere transferred from ComputershareSedona Equity Registrar & Transfer, Incorporated (“Sedona”) to Sedona.ClearTrust. In this capacity, SedonaClearTrust will now manage all stock registry requests for shareholders, including change of address, certificate replacement and transfer of shares. All stock and investment information willhas automatically transfertransferred to SedonaClearTrust from our former Transfer Agent and Registrar, Computershare,Sedona, and no action is required on the part of the shareholder.

The transfer agent for our Common Stock is Sedona Equity Registrar & Transfer, 143 W. Helena Drive Phoenix, AZ 85023. Their website address is: www.sedonaequity.com.

Dividend Policy

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

During the twelve months ended February 28, 2022, the Company paid the shareholders of its Series A Convertible Preferred stock all accrued and accumulated dividends that were associated with the Series A Convertible Preferred stock with common stock.Common Stock. For more information on this issuance please refer to Note 1213 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 stockCommon Stock in the foreseeable future.

Preferred Stock

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

With the filing of ourthe 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 shares. Westock. The Company has only have one class of stock, and thatwhich is common stock.Common Stock.

Series A Convertible Preferred Stock

The Company designated 2,400,000 shares of the 10,000,000 preferred shares as Series A Convertible Preferred Stock (“Series A Preferred”), with a $0.001 par value. In July 2006, we completed a private placement of the Series A Preferred that resulted in the issuance of 1,399,765 Series A Preferred shares to 100 accredited investors.

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

The following is a summarythat had not been converted into our Common Stock. With the filing of the rightsCompany’s Second Amended and preferencesRestated Articles of Incorporation with the Series A Preferred.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 issued and outstandingof Series A Preferred stock that had not been converted into our Common Stock. As of February 28, 2021, there were 44 accredited investors who had converted 690,197 Series A Preferred shares into 2,070,591 shares of Daybreak Common Stock.

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

Dividends:

Holders of Series A Preferred shall be paid dividends, in the amount of 6% of the original purchase price per annum. Dividends may be paid in cash or Common Stock at the discretion of the Company. Dividends are cumulative from the date of the final closing of the private placement, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends. Accumulations of dividends on shares of Series A Preferred do not bear interest. Dividends are payable upon declaration by the Board of Directors. During the twelve months ended February 28, 2022, all accumulated dividends of $2,449,979 were paid through the issuance of 1,100,000 shares of common stock.

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