DAYBREAK OIL & GAS, INC. [DBRM] Filings

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended February 28, 2023

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: (281) 996-4176

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No 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 $0.05 on August 31, 2022, as reported by the OTC Pink® Open Market was $2,821,727.

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

TABLE OF CONTENTS

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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 OTCMarkets under the symbol DBRM in the Expert Market.

Our corporate office is located at 1414 S. Friendswood Dr., Suite 212, Friendswood, Texas 77546. The telephone number of our office in Friendswood is (281) 996-4176.

Market Conditions, Commodity Prices, and Interest Rates

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

Crude Oil and Natural Gas Overview

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

Our long-term success depends on, among many other factors, the acquisition and drilling of commercial grade crude oil and natural gas properties and on the prevailing sales price for crude oil and natural gas along with controlling the associated operating expenses. The volatile nature of the energy markets makes it difficult to estimate future prices of crude oil and natural gas; however, any prolonged period of depressed prices or periods of market volatility, such as we have experienced in the last two years, will and does have a material adverse effect on our results of operations and financial condition.

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

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

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

Acquisition of Reabold Subsidiary in May 2022

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

Known Trends and Uncertainties

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

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

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

California Crude Oil Prices

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

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

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

 California Crude Oil Revenue and Production

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

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

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

California Natural Gas Prices

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

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

California Natural Gas Revenue and Production

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

California Natural Gas BOE Net Sales Volume

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

Competition

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

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

Marketing Arrangements – Principal Customers

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

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

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

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

Title to Properties

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

Regulation

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

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

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

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

Our operations in Kern County have been subject to significant uncertainty over the past several years as a result of ongoing challenges to the County's ability to rely on an existing EIR to meet the County's obligations under CEQA. In December 2015 several groups challenged the sufficiency of the EIR for satisfying CEQA requirements in Kern County for crude oil and natural gas permit approvals (“Kern County EIR Litigation”). In March 2018 a trial court (“Trial Court”) found that the EIR inadequately analyzed the environmental impacts to rangeland and road paving mitigation for purposes of well work and rejected the plaintiffs’ other CEQA claims. The plaintiffs appealed. In February 2020, the California Fifth District Appellate Court (“Appellate Court”) ruled that the plaintiffs’ other CEQA claims had merit and ordered Kern County to rescind the Zoning Ordinance and cease issuing permits. In March 2021, Kern County’s Board of Supervisors approved a revised Zoning Ordinance (the “Revised Ordinance”) and certified a Supplemental Recirculated Environmental Impact Report (“SREIR”) for purposes of satisfying CEQA requirements with respect to the issuance of oil and natural gas permits. A suit was subsequently filed that same month challenging the sufficiency of the SREIR. In October 2021, the Trial Court ordered Kern County to cease using the existing EIR to meet CEQA requirements until it determined that the Revised Ordinance complied with CEQA requirements. The Trial Court subsequently identified four deficiencies in the SREIR that needed correction to conform to CEQA. In November 2022, upon the correction of those deficiencies to the Trial Court’s satisfaction, the Trial Court lifted the suspension on Kern County's ability to rely on the existing SREIR to meet CEQA requirements in Kern County (the Discharge Order). In December 2022, the Trial Court denied a motion to stay the Discharge Order. The plaintiffs appealed the judgment and Discharge Order and filed a petition requesting a stay of the ordinance pending resolution of the merits of the appeal.

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

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

Furthermore, the California Legislature and Governor have significantly increased the jurisdiction, duties and enforcement authority of CalGEM, the State Lands Commission and other state agencies with respect to crude oil and natural gas activities in recent years through legislation and policy pronouncements. For example, 2019 state legislation expanded CalGEM’s duties effective on January 1, 2020 to include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs, and will require CalGEM to study and prioritize idle wells with emissions, evaluate costs of abandonment, decommissioning and restoration, and review and update associated indemnity bond amounts from operators if warranted, up to a specified cap which may be shared among operators.

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

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

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

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

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

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

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

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

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

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

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

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

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

Operational Hazards and Insurance

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

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

Human Capital

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

Long-Term Success

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

Availability of SEC Filings

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

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

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

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

·   market uncertainty;

·   the level of consumer product demands;

·   hurricanes and other weather conditions;

·   domestic governmental regulations and taxes;

·   the foreign supply of crude oil and natural gas;

·   the price of crude oil and natural gas imports;

·   political and economic conditions, including international disputes;

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

·   overall domestic and foreign economic conditions.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including hydrocarbon prices, the availability and cost of

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

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

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

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

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

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

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

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

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

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

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

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

Our crude oil projects are subject to risks inherent in the crude oil and natural gas industry. These risks involve explosions, uncontrollable flows of crude oil, natural gas or well fluids, pollution, fires, earthquakes, and other environmental issues. These risks could result in substantial losses due to injury and loss of life, severe damage to and destruction of property and equipment, pollution, and other environmental damage. As protection against these operating hazards, we maintain insurance coverage to include physical

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

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

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

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

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

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

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

Risks related to Environmental Regulation

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

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

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

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

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

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

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

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

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

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

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

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

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

Additional provisions of Senate Bill No. 1137 include, among others, the imposition of health, safety and environmental controls applicable to both current and new wells located within this distance of sensitive receptors related to noise, light, and dust pollution controls and air emission monitoring, and the immediate suspension of operations at production facilities determined to not be in compliance with certain air emission requirements.

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

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration by states or groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

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

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

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

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

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

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

Risks Related to Our Indebtedness

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

We have reported net loss of approximately $2.4 million for the year ended February 28, 2023, and we have an accumulated deficit through February 28, 2023 of approximately $31.96 million. Without successful exploration and development of our properties and a significant sustained increase in hydrocarbon prices any investment in Daybreak could become devalued or worthless.

Our ability to satisfy our obligations depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. Our business does not generate sufficient cash flow to meet our ongoing obligations, and future financings may not be available to provide sufficient net proceeds, to meet these obligations or to successfully execute our business strategy. Our future performance, in turn, is dependent upon many factors that are beyond our control such as the level of hydrocarbon prices and general economic, financial and business conditions. We cannot guarantee that our future performance will not be adversely affected by such economic conditions and financial, business and other factors.

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

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

Risks Related to Our Common Stock

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

Our financial statements for the year ended February 28, 2023 were prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. We have incurred net losses since inception, which raises substantial doubt about our ability to continue as a going concern. In the event we are not able to continue operations, an investor will likely suffer a complete loss of their investment in our securities.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

General Risk Factors

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

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

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

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

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

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

 
ITEM 2. PROPERTIES

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

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

Kern County, California (East Slopes Project)

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

Our 20 producing crude oil wells in the East Slopes Project produce from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations. The Sunday property has six producing wells, while the Bear property has nine producing wells. The Black property is the smallest of all currently producing reservoirs, and currently has two producing wells at this property. The Ball property also has two producing wells while the Dyer Creek property has one producing well. We have no natural gas production associated with the East Slopes Project.

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

Sunday Property

In November 2008, we made our initial crude oil discovery drilling the Sunday #1 well. The well was put on production in January 2009. Production is from the Vedder Sand at approximately 2,000 feet. During 2009, we drilled three development wells including one horizontal well: the Sunday #2, Sunday #3 and Sunday #4H wells, respectively. During May and June 2013, we drilled two additional development wells: the Sunday #5 and Sunday #6. The Sunday reservoir is estimated to be approximately 35 acres in size with the potential for at least five more development wells to be drilled in the future.

Bear Property

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

Black Property

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

Ball Property

The Ball #1-11 well was put on production in late October 2010. In June 2013 we drilled a development well, the Ball #2-11, on this property. Production on this property is from the Vedder Sand at approximately 2,500 feet. The Ball reservoir is estimated to be approximately 38 acres in size with the potential for at least three more development wells to be drilled in the future.

Dyer Creek Property

The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010. This well produces from the Vedder Sand and is located to the north of the Bear property on the same trapping fault. The Dyer Creek property has the potential for at least one development well in the future.

Sunday Central Processing and Storage Facility

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

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

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

Monterey County Properties

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

Contra Costa County Property

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

California Drilling Plans

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

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

Sunflower Lawsuit

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

The Company is not aware of any environmental claims existing as of January 23, 2024. There can be no assurance, however, that current regulatory requirements will not change or that past non-compliance with environmental issues will not be discovered on the Company’s crude oil properties.

Encumbrances

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

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

Reserves

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

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

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

Revisions. Net upward revisions of 6,235 BOE of developed reserves in aggregate were due to the higher net crude oil and natural gas prices we received during the twelve months ended February 28, 2023 increasing the economic life of our proved reserves, offset by the removal of 399,311 BOE of proved undeveloped reserves that have remained for a period greater than five years as of February 28, 2023.

Discoveries and extensions. For the twelve months ended February 28, 2023, we had no discoveries or extensions of reserves.

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

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

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

Revisions. A downward revision of 399,311 BOE of proved undeveloped reserves occurred for the twelve months ended February 28, 2023. Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years.

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

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

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

The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10”), was approximately $11.0 million at February 28, 2023 an increase of approximately $4.8 million or 77.4% from the PV-10 reserve valuation of approximately $6.2 million at February 28, 2022. This increase is primarily due to the acquisition of the Reabold project in California. The commodity prices used to estimate proved reserves and their related PV-10 at February 28, 2023 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the twelve month period from March 2022 through February 2023. The WTI benchmark average price for the twelve months ended February 28, 2022 was $93.55 per barrel of crude oil in comparison to $71.69 in the prior year reserve report.

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

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

Reserve Estimation

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

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

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

PETROtech is an independent petroleum engineering consulting firm registered in the State of California, and Bradford DeWitt, a Petroleum Engineer, is the technical person at PETROtech primarily responsible for evaluating the proved reserves covered by their report. Mr. DeWitt has a Bachelor of Arts degree from the University of California – Los Angeles (“U.C.L.A”) and a Master of Science degree in Engineering from the University of Southern California (“U.S.C.”). He is a registered petroleum engineer in the State of California. The services provided by PETROtech are not audits of our reserves but instead consist of complete engineering

evaluations of the respective properties. For more information about the evaluations performed by PETROtech, refer to the copy of their report filed as Exhibit 99.2 to this Annual Report on Form 10-K.

Our internal controls over the reserve reporting process are designed to result in accurate and reliable estimates in compliance with applicable regulations and guidance. Internal reserve preparation is performed by Bobby Ray Greer, Director of Field Operations. Mr. Greer is a 1984 graduate of University of Southern Mississippi in Hattiesburg, Mississippi with a Bachelor of Science Degree in Geology and is a certified Petroleum Geologist and a member, in good standing, of the American Association of Petroleum Geologists and is a registered professional geologist in Mississippi. Mr. Greer has over 40 years of experience in petroleum exploration, reservoir analysis, drilling rig construction, oilfield operations and management.

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

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

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

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

Delivery Commitments

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

Summary Operating Data

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

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

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, 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

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

In all cases the drilling of a commercial crude oil or natural gas well will hold acreage beyond the lease expiration date. In the past we have been able to, and expect in the future to be able to extend the lease terms of some of these leases. Based on our evaluation of prospective economics, we have allowed acreage to expire from time to time and we expect to allow additional acreage to expire in the future. In California, we have previously determined that there was no likely benefit to pursuing any drilling opportunities on our expiring leases, and so we have not attempted to renew those leases when their expiration dates occurred.

Producing Wells

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

Drilling Activity

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

ITEM 3. LEGAL PROCEEDINGS

Sunflower Lawsuit

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

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

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

In September 2023, information on our Common Stock became available in the OTC Expert Market. This move to the Expert Market was triggered by a lack of current financial information being available due to delays in the filing of this 10-K filing for the year ended February 28, 2023 and subsequent 10-Q reports. We anticipate that once we are current in our public company filings our Common Stock will again be quoted on the OTC Pink Open Market, although we can provide no assurances as to the timing or our ultimate success in this regard.

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

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

Transfer Agent

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

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

Dividend Policy

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

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. For more information on this issuance please refer to Note 13 of the financial statements that are included in this 10-K filing. The Company does not anticipate that it will pay cash dividends or make any cash distributions on its Common Stock in the foreseeable future.

Preferred Stock

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

Series A Convertible Preferred Stock

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

Conversion:

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

 Dividends:

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. At a special meeting of shareholders on May 20, 2022 the Company’s shareholders approved the Second Amended and Restated Articles of Incorporation, which eliminated the classification of the Series A Preferred stock. Cumulative dividends earned on our Series A Preferred stock for each twelve month period since issuance are set forth in the table below.

Common Stock

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

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

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

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

Warrants

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

ITEM 6. [RESERVED]

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

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

Safe Harbor Provision

Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations are intended to be covered by the safe harbor provided for under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. All statements other than statements of historical facts contained in this MD&A report, including statements regarding our current expectations and projections about future results, intentions, plans and beliefs, business strategy, performance, prospects and opportunities, are inherently uncertain and are forward-looking statements. For more information about forward-looking statements, please refer to the section labeled “Cautionary Statement About Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.

Introduction and Overview

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

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

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

Our management cannot provide any assurances that Daybreak will ever operate profitably. While, in the past, we have had positive cash flow from our crude oil operations in the East Slopes project in California, we have not yet generated sustainable positive cash flow or earnings on a company-wide basis. As a small company, we are more susceptible to the numerous business, investment and industry risks that have been more fully described in Item 1A. Risk Factors of this Annual Report on Form 10-K for the fiscal year ended February 28, 2023.

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

Year-to-Date Results

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

Kern County, California (East Slopes project)

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

The crude oil produced from our acreage in the Vedder Sand is considered heavy crude oil. The produced crude oil ranges from 14° to 16° API (American Petroleum Institute) gravity and must be heated to separate and remove water prior to sale. During the twelve months ended February 28, 2023 we had production from 20 vertical or horizontal crude oil wells. Our average working interest and NRI in these 20 wells is 36.6% and 27.6%, respectively.

Monterey and Contra Costa Counties, California (Reabold project)

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

Monterey County Properties

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

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

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

California Crude Oil Prices

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

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

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

California Crude Oil Revenue and Production

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

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

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

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

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

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

California Natural Gas Prices

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

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

California Natural Gas Revenue and Production

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

California Natural Gas BOE Net Sales Volume

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

Total California Crude Oil and Natural Gas Revenue and Production

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

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

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

Operating Expenses

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

Production expenses include expenses associated with the production of crude oil and natural gas. These expenses include contract pumper, electricity, road maintenance, control of well insurance, property taxes, well maintenance and workover expenses; and, relate directly to the number of wells that are on production. For the twelve months ended February 28, 2023, these expenses increased $872,550, or 377.3% to $1,103,825 in comparison to $231,275 for the twelve months ended February 28, 2022. At February 28, 2023, we had 24 wells on production in comparison to 20 wells on production for the twelve months ended February 28, 2022. The increase in producing wells was due to the acquisition of our Reabold subsidiary that occurred in May of 2022. The increase in production expenses for the twelve months ended February 28, 2023, was primarily due to the replacement and upgrading of pumps in seven wells of the East Slopes project for $56,549 and the expenses associated with salt water disposal of $426,838 from the Reabold properties. A salt water disposal well is currently being permitted which, when put into operation is expected to significantly lower operating costs of the Reabold project. Production expenses on a BOE basis for the twelve months ended February 28, 2023 and February 28, 2022 were $62.18 and $24.06, respectively. Production expenses represented 28.3% and 24.6% of total operating expenses for the twelve months ended February 28, 2023 and February 28, 2022, respectively.

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

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

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

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

General and administrative (“G&A”) expenses include the salaries of five employees, including management. Other items included in our G&A expenses are legal and accounting expenses, investor relations fees, travel expenses, insurance expenses and other administrative expenses necessary for an operation of crude oil and natural gas properties as well as for the management of a public company. For the twelve months ended February 28, 2023, G&A expenses increased $400,203 or 66.3% to $1,004,011 in comparison to $603,808 for the twelve months ended February 28, 2022. The primary reasons for the increase in G&A expense are related to the expenses of both the special shareholders and the annual shareholders meetings, in the amount of approximately $131,394 in aggregate, approximately $120,000 in legal and accounting fees related to the acquisition and an increase in SEC reporting expense of approximately $53,800 during the twelve months ended February 28, 2023. We are continuing a program of controlling our G&A costs wherever possible. G&A expenses represented 25.8% and 64.1% of total operating expenses for the twelve months ended February 28, 2023 and February 28, 2022, respectively.

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

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

Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially quarter-to-quarter and year-to-year. Our revenues are dependent upon both hydrocarbon production levels and the price we receive for hydrocarbon sales. Production costs will fluctuate according to the number and percentage ownership of producing wells the period of time the wells have been producing, as well as the amount of revenues being generated by each well. Exploration and drilling expenses will be dependent upon the amount of capital that we have to invest in future development projects, as well as the success or failure of such projects. Likewise, the amount of DD&A expense will depend upon the factors cited above, plus the size of our proven reserve base and the market price of energy products. G&A expenses will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company. An on-going goal of the Company is to improve cash flow to cover the current level of G&A expenses; to fund our development drilling in California; and future drilling programs in other geographic locations.

Capital Resources and Liquidity

Our primary financial resource is our base of crude oil and natural gas reserves. Our ability to fund our capital expenditure program is dependent upon the prices we receive from our crude oil and natural gas sales and the availability of capital resource financing. There continues to be a significant amount of volatility in hydrocarbon prices and a corresponding volatility in our realized sale price of crude oil and natural gas does exist. One example of this volatility is that in March 2022, our realized price per barrel of crude oil was $108.08, while in November 2022, it was $84.40 and in February 2023 it was $71.85 per barrel. Another example of this volatility is that in June 2022 our realized price per Mcf of natural gas in California was $11.03, while in November 2022 it was $7.59 and in January 2023 it was $58.03 per Mcf. This volatility in crude oil and natural gas prices has continued throughout the fiscal year ended February 28, 2023. Any downward volatility in the price of crude oil and natural gas will have a prolonged and substantial negative impact on our profitability and cash flow from our producing California properties. It is beyond our ability to accurately predict crude oil prices over any substantial length of time. When new financing is secured, we plan to drill three development wells and one SWD well for an approximate total of $800,000.

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

Our working capital deficit decreased approximately $0.89 million or 29.7% from a deficit of approximately $2.99 million at February 28, 2022 to a deficit of approximately $2.1 million at February 28, 2023. The decrease in the working capital deficit was primarily due to the proceeds we received in connection with the sale of Common Stock and the acquisition of our Reabold California, LLC subsidiary current assets. We anticipate an increase in our cash flow will occur when we are able to return to our planned drilling program that will result in an increase in the number of successful wells on production.

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

Major sources of funds in the past for us have included the debt or equity markets. We will have to rely on the capital markets to fund future operations and growth. Our business model is focused on acquiring exploration or development properties as well as existing production. Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of crude oil and natural gas producing properties, which will require us to continue to raise equity or debt capital from outside sources.

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

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

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

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

Accounts Payable – Related Parties

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

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

Cash Flows

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

Cash Flow Used in Operating Activities

Cash flow from operating activities is derived from the production of our crude oil reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. Cash flow used in our operating activities for the twelve months ended February 28, 2023 was $315,117 in comparison to cash flow used in our operating activities of $13,356 for the twelve months ended February 28, 2022. Changes in our cash flow used for operating activities for the twelve months ended February 28, 2023 in comparison to the twelve months ended February 28, 2022 increased $301,761 and were mainly a result of the expense of our annual shareholders meeting and the Reabold subsidiary acquisition. We had increases in our non-cash expenses of $1,266,587, primarily from recognition of impairment of proved undeveloped locations acquired in the Reabold acquisition of $711,873 and an increase in DD&A of $454,498, a decrease in changes in assets of $107,445 that was offset by an increase in changes in liabilities of $569,884 and the increase in our net loss for the year of approximately $2.0 million. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

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

Cash Flow Used in Investing Activities

Cash flow from investing activities is derived from changes in oil and gas property balances, fixed asset balances and any lending activities. For the twelve months ended February 28, 2023 we used cash flow of $386,160 in comparison to cash flow used for investing activities of $16,232 for the twelve months ended February 28, 2022. The change in cash flow used in investing activities of $369,928 was primarily related to the Reabold acquisition.

Cash Flow Provided by Financing Activities

Cash flow from financing activities is derived from changes in long-term liability account balances or in equity account balances excluding retained earnings. Cash flow provided by our financing activities was $1,136,114 for the twelve months ended February 28, 2023 in comparison to cash flow provided by our financing activities of $135,633 for the twelve months ended February 28, 2022. For the twelve months ended February 28, 2023, we secured a capital raise of $1,987,500 net of transaction expenses from the sale of 125,000,000 shares of our Common Stock. We also paid off the balance of $808,182 on the line of credit with UBS Bank during the twelve months ended February 28, 2023.

Short-Term and Long-Term Borrowings

Note Payable

In December 2018, the Company was able to settle an outstanding balance owed to one of its third-party vendors. This settlement resulted in a $120,000 note payable being issued to the vendor. Additionally, the Company agreed to issue 2,000,000 shares of the Company’s Common Stock as a part of the settlement agreement. Based on the closing price of the Company’s Common Stock on the date of the settlement agreement, the value of the Common Stock transaction was determined to be $6,000. The Common Stock shares were issued during the twelve months ended February 29, 2020. The note had a maturity date of January 1, 2022 and bears an interest rate of 10% rate per annum. The note principal has not been paid and the Company is considered to be in default. There is no default interest rate associated with the note. Interest is accrued monthly and is payable on January 1^st of each anniversary date of the note. At February 28, 2023, the note principal and a portion of the accrued interest had not been paid and was outstanding. The accrued interest on the Note was $26,000 and $38,000 at February 28, 2023 and February 28, 2022, respectively.

Note Payable – Related Party

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

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

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

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

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

Short-term Convertible Note Payable

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

12% Subordinated Notes

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

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

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

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

Line of Credit

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

On May 26, 2022, the Company paid off the outstanding balance of $809,930 on the line of credit. The payoff of the line of credit was previously approved under terms of the Equity Exchange Agreement in which the Company acquired the Reabold property in California. The line of credit payoff was a part of the use of proceeds from the Company’s sale of Common Stock to a third party. At February 28, 2023, and February 28, 2022, the line of credit had an outstanding balance of $-0- and $808,182, respectively. During the twelve months ended February 28, 2022, the Company made payments to the line of credit of $60,000. Interest converted to principal for the twelve months ended February 28, 2022 was $27,278.

Production Revenue Payable

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

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

Accordingly, the Company has estimated the cash flows associated with the production revenue payments of $913,395 and determined a discount of $78,136 as of February 28, 2023, which is being accounted as interest expense over the estimated period over which payments will be made based on expected future revenue streams. For the twelve months ended February 28, 2023, and February 28, 2022, amortization of the debt discount on these payables amounted to $56,156 and $95,974, respectively, which has been included in interest expense in the statements of operations.

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