EDGAR 10-K Filing

Company CIK: 1164256
Filing Year: 2024
Filename: 1164256_10-K_2024_0001515971-24-000014.json

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ITEM 1. BUSINESS
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:
Twelve Months Ended
February 28, 2023 February 28, 2022 Percentage Change
Average twelve-month WTI crude oil price $ 93.13 $ 73.31 27.0 %
Average twelve month realized crude oil sales price (Bbl) $ 89.59 $ 70.75 26.6 %
For the twelve months ended February 28, 2023, the average WTI price was $93.13, and our average realized crude oil sale price was $89.59, representing a discount of $3.54 per barrel or 3.8% lower than the average WTI price. In comparison, for the twelve months ended February 28, 2022, the average WTI price was $73.31, and our average realized sale price was $70.75 representing a discount of $2.56 per barrel or 3.5% lower than the average WTI price. Historically, the sale price we receive for our East Slopes heavy crude oil has been less than the quoted NYMEX WTI price because of the lower API gravity of our East Slopes crude oil in comparison to quoted WTI crude oil API gravity.
California Crude Oil Revenue and Production
Crude oil revenue in California for the twelve months ended February 28, 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.
Twelve Months Ended
February 28, 2023 February 28, 2022 Percentage Change
Average twelve month Henry Hub natural gas price (Mcf) $ 6.35 $ - 100 %
Average twelve month realized natural gas sales price (Mcf) $ 20.94 $ - 100 %
For the twelve months ended February 28, 2023 the average price per Mcf (1,000 cubic feet) that we received was $20.94 while the average monthly price per Mcf for spot Henry Hub prices was $6.35 for the same twelve month period. The large disparity in the two prices over the twelve-month period was largely due to the price per Mcf we received during the three months ended February 28, 2023 when the average price we received per Mcf was $29.79 and the same three month average price per Mcf for Henry Hub prices was $3.86. In January of 2023 the average price per Mcf we received in California was $58.03 while the monthly average Henry Hub price was $3.39 per Mcf.
California Natural Gas Revenue and Production
We only have natural gas production from our Reabold subsidiary wells that are located in Contra Costa County in California. For the twelve months ended February 28, 2023, natural gas revenue increased $80,026 or 100%. Prior to the Reabold acquisition in May 2022, we did not have any natural gas production. The average sales price per Mcf of our natural gas production was $20.94 and our natural gas sales volume was 3,822 Mcf for the twelve months ended February 28, 2023.
California Natural Gas BOE Net Sales Volume
For the twelve months ended February 28, 2023, our BOE net sales volume of natural gas was 637 barrels representing a 100% from the twelve months ended February 28, 2022. We did not have any natural gas sales volume for the twelve months ended February 28, 2022. We only have natural gas production from our Reabold subsidiary located in Contra Costa County in California that was acquired in May of 2022.
Competition
We compete with other independent crude oil and natural gas companies for exploration prospects, property acquisitions and for the equipment and labor required to operate and develop these properties. Many of our competitors have substantially greater financial and other resources than we have. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can.
We conduct all of our drilling, exploration and production activities onshore in the United States. All of our crude oil assets are located in the United States and all of our revenues are from sales to customers within the United States.
Marketing Arrangements - Principal 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:
February 28, 2023 February 28, 2022
Project Customer Accounts
Receivable
Percentage Accounts
Receivable
Percentage
California - East Slopes project (crude oil) Plains Marketing $ 55,900 42.5 % $ 117,727 100.0 %
California - Reabold project (crude oil) Plains Marketing 59,614 45.3 % - -
California - Reabold project (natural gas) CRC 15,996 12.2 % - -
Totals
$ 131,510 100.0 % $ 117,727 100.0 %
Joint interest participant receivables balances of $353,009 and $85,339 at February 28, 2023 and February 28, 2022, respectively, represent amounts due from working interest partners in the East Slopes and Reabold projects. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2023 and February 28, 2022.
Title to Properties
As is customary in the crude oil and natural gas industry, we make only a cursory review of title to undeveloped crude oil and natural gas leases at the time we acquire them. However, before drilling operations commence, we search the title, and remedy material defects, if any, before we actually begin drilling the well. To the extent title opinions or other investigations reflect title defects, we (rather than the seller or lessor of the undeveloped property) typically are obligated to cure any such title defects at our expense. If we are unable to remedy or cure any title defects, so that it would not be prudent for us to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. Except for encumbrances we have granted as described below under “Encumbrances,” we believe that we have good title to our crude oil and natural gas properties, some of which are subject to immaterial easements, and restrictions.
Regulation
The exploration and development of crude oil and natural gas properties are subject to various types of federal, state and local laws and regulations. These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, hydraulic fracturing operations, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and specific requirements for the operation of wells. Government actions, including the issuance of certain permits or approvals, by state and local agencies or by federal agencies may be subject to environmental reviews, respectively, under the California Environmental Quality Act (“CEQA”) or the National Environmental Policy Act (“NEPA”), which may result in delays, imposition of mitigation measures or litigation. Failure to comply with such laws and regulations can result in substantial penalties.
Laws and regulations relating to our business frequently change so we are unable to predict the future cost or impact of complying with such laws. Future laws and regulations, including changes to existing laws and regulations, could adversely affect our business. These regulatory burdens generally do not affect us any differently than they affect other companies in our industry with similar types, quantities, and locations of production.
All of the states in which we 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:
Daybreak Oil and Gas, Inc.
1414 S. Friendswood Drive,
Suite 212
Friendswood, TX 77546
Attention: Corporate Secretary
Telephone: (281) 996-4176
Information contained on or connected to our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
The following risk factors together with other information set forth in this Annual Report on Form 10-K, should be carefully considered by current and future investors in our securities. An investment in our securities involves substantial risks. There are many factors that affect our business, a number of which are beyond our control. Our business, financial condition and results of operations could be materially adversely affected by any of these factors. The nature of our business activities further subjects us to certain hazards and risks. The risks described below are a summary of the known material risks relating to our business. Additional risks and uncertainties not presently known to us or that we currently deem to be immaterial individually or in aggregate may also impair our business operations. If any of these risks actually occur, it could harm our business, financial condition or results of operations and impair our ability to implement our business plan or complete development projects as scheduled. In any such case, the trading price of our Common Stock could decline, and you could lose all, or a part, of your investment.
Summary of Risk Factors
Risks Related to Our Business
· Prices for crude oil and natural gas can fluctuate widely and an extended period of low prices could materially and adversely affect our financial condition, results of operations, cash flow and ability to invest in our assets.
· Hydrocarbon price declines may result in impairments of our asset carrying values.
· The crude oil and natural gas business is highly competitive, placing us at an operating disadvantage.
· When we make the determination to invest in crude oil or natural gas properties we rely upon geological and engineering estimates, which involve a high level of uncertainty.
· Drilling is a high-risk activity and, as a result, we may not be able to adhere to our proposed drilling schedule, or our drilling program may not result in commercially productive reserves.
· Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services, and personnel.
· To execute our business plan we will need to develop current projects and expand our operations requiring significant capital expenditures, which we may be unable to fund.
· Our ability to reach and maintain profitable operating results is dependent on our ability to find, acquire, and develop crude oil and natural gas properties.
· Our producing reserves are located in one major geographic area. Concentration of reserves in limited geographic areas may disproportionately expose us to operational, regulatory and geological risks.
· Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our crude oil reserves, and our revenues, profitability and cash flows to be materially different from our estimates.
· We may not be able to replace current production with new crude oil and natural gas reserves.
· Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
· We have reclassified proved undeveloped reserves to unproved reserves due to our inability to commit sufficient capital within the required SEC-defined time period of a five-year development window, which could adversely affect the value of our properties.
· Our financial condition will deteriorate if we are unable to retain our interests in our leased crude oil and natural gas properties.
· Title deficiencies could render our crude oil and natural gas leases worthless; thus damaging the financial condition of our business.
· If we as operator of our crude oil and natural gas projects fail to maintain adequate insurance, our business could be exposed to significant losses.
· Recent action by the State of California imposing additional financial assurance requirements related to plugging and abandonment costs, decommissioning, and site restoration on those who acquire the right to operate wells and production facilities could impact our ability to sell or acquire assets in the state of California or increase our costs in connection with the same.
· We are subject to economic downturns and the effects of public health events, such as the COVID-19 pandemic, which may materially and adversely affect the demand and the market price for our products.
Risks Related to Environmental Regulation
· Our crude oil and natural gas exploration and production and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.
· We face various risks associated with the trend toward increased anti-crude oil and natural gas development activity.
· Restricted land access could reduce our ability to explore for and develop crude oil and natural gas reserves.
· Recent and future actions by the State of California and local governments could result in restrictions to our operations and result in decreased demand for crude oil and natural gas within the state.
· Climate change legislation or regulations restricting emission of greenhouse gases (“GHG”) could result in increased operating costs and reduced demand for the crude oil and natural gas we produce.
· The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new costs on our operations.
Risks Related to Our Indebtedness
· We have experienced significant operating losses in the past and there can be no assurance that we will become profitable in the future.
· We have substantial indebtedness. The amount of our outstanding indebtedness and our current inability to meet our debt obligations will have adverse consequences on our business, financial condition and results of operations.
Risks Related to Our Common Stock
· We may be unable to continue as a going concern in which case our Common Stock will have little or no value.
· The market price of our Common Stock has been volatile, which may cause the investment value of our Common Stock to decline.
· Pursuant to SEC rules our Common Stock is classified as a “penny stock” increasing the risk of investment in our Common Stock.
· The resale of Common Stock shares offered in private placements could depress the value of other Common Stock shares.
· Privately placed issuances of our Common Stock and warrants have and may continue to dilute ownership interests which could have an adverse effect on our stock prices.
· We will need to seek to raise additional funds in the future through debt financing, which may impose operational restrictions and may further dilute existing ownership interests.
· We do not anticipate paying dividends on our Common Stock, which could devalue the market value of our Common Stock.
· We have two Common Stock shareholders that own approximately 42% and 40%, respectively of our outstanding Common Stock shares at February 28, 2023 who may be able to individually or jointly control the operations of the Company.
General Risk Factors
· Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of proposed legislation.
· We may lose key management personnel which could endanger the future success of our crude oil and natural gas operations.
· A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.
RISK FACTORS
Risks Related to Our Business
Prices for crude oil and natural gas can fluctuate widely and an extended period of low prices could materially and adversely affect our financial condition, results of operations, cash flow and ability to invest in our assets.
Our financial condition, results of operations, cash flow and ability to invest in our assets are highly dependent on crude oil and natural gas prices. A sustained period of low prices for crude oil and natural gas would reduce our cash flows from operations and could reduce our access to capital markets, and our ability to grow. Prices for crude oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:
·	 changes in the supply of and demand for crude oil and natural gas;
· market uncertainty;
· the level of consumer product demands;
· hurricanes and other weather conditions;
· domestic governmental regulations and taxes;
· the foreign supply of crude oil and natural gas;
· the price of crude oil and natural gas imports;
· political and economic conditions, including international disputes;
· national and international pandemics like the COVID-19; and
· overall domestic and foreign economic conditions.
These factors make it very difficult to predict future hydrocarbon commodity price movements with any certainty. It is beyond our control and ability to accurately predict when there will be a sustained improvement in hydrocarbon prices. All of our crude oil and natural gas sales are made pursuant to contracts based on spot market prices and are not based on long-term fixed price contracts. Crude oil and natural gas prices do not necessarily fluctuate in direct relation to each other.
Hydrocarbon price declines may result in impairments of our asset carrying values.
Commodity prices have a significant impact on the present value of our proved reserves. Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our crude oil and natural gas properties in certain situations. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required. Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred. For the twelve months ended February 28, 2023, we determined that a non-cash impairment will not be recognized on our California crude oil properties due to the current hydrocarbon prices.
The crude oil and natural gas business is highly competitive, placing us at an operating disadvantage.
We expect to be at a competitive disadvantage in (a) seeking to acquire suitable crude oil and or natural gas drilling prospects; (b) undertaking exploration and development; and (c) seeking additional financing. We base our preliminary decisions regarding the acquisition of crude oil and or natural gas prospects and undertaking of drilling ventures upon general and inferred geology and economic assumptions. This public information is also available to our competitors.
In addition, we compete with larger crude oil and natural gas companies with longer operating histories and greater financial resources than us. These larger competitors, by reason of their size and greater financial strength, can more easily:
· access capital markets;
· recruit more qualified personnel;
· absorb the burden of any changes in laws and regulation in applicable jurisdictions;
· handle longer periods of reduced prices of crude oil and natural gas;
· acquire and evaluate larger volumes of critical information; and
· compete for industry-offered business ventures.
When we make the determination to invest in crude oil or natural gas properties we rely upon geological and engineering estimates, which involve a high level of uncertainty.
Geologic and engineering data are used to determine the probability that a reservoir of crude oil or natural gas exists at a particular location. This data is also used to determine whether crude oil and natural gas are recoverable from a reservoir. Recoverability is ultimately subject to the accuracy of data including, but not limited to, geological characteristics of the reservoir, structure, reservoir fluid properties, the size and boundaries of the drainage area, reservoir pressure, and the anticipated rate of pressure depletion. Also, an increase in the costs of production operations may render some deposits uneconomic to extract.
The evaluation of these and other factors is based upon available seismic data, computer modeling, well tests and information obtained from production of crude oil and natural gas from adjacent or similar properties. There is a high degree of risk in proving the existence and recoverability of reserves. Actual recoveries of proved reserves can differ materially from original estimates. Accordingly, reserve estimates may be subject to downward adjustment. Actual production, revenue and expenditures will likely vary from estimates, and such variances may be material.
Drilling is a high risk activity and, as a result, we may not be able to adhere to our proposed drilling schedule, or our drilling program may not result in commercially productive reserves.
Our future success will partly depend on the success of our drilling programs. The future cost or timing of drilling, completing, and producing wells is inherently uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including:
· unexpected drilling conditions;
· well integrity issues and surface expressions;
· pressure or irregularities in formations;
· equipment failures or accidents;
· compliance with landowner requirements;
· current crude oil and natural gas prices and estimates of future crude oil and natural gas prices;
· availability, costs and terms of contractual arrangements with respect to pipelines and related facilities to gather, process, transport and market crude oil and natural gas; and
· shortages or delays in the availability of drilling rigs and the delivery of equipment and/or services, including experienced labor.
Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.
The demand for qualified and experienced field personnel to drill wells and conduct field operations in the crude oil and natural gas industry can fluctuate significantly, often in correlation with crude oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher crude oil and natural gas prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews, and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be.
To execute our business plan we will need to develop current projects and expand our operations requiring significant capital expenditures, which we may be unable to fund.
Our business plan contemplates the execution of our current exploration and development projects and the expansion of our business by identifying, acquiring, and developing additional crude oil and natural gas properties. We plan to rely on external sources of financing to meet the capital requirements associated with these activities. We will have to obtain any additional funding we need through debt and equity markets or the sale of producing or non-producing assets. There is no assurance that we will be able to obtain additional funding when it is required or that it will be available to us on commercially acceptable terms.
We may make offers to acquire crude oil and natural gas properties in the ordinary course of our business. If these offers are accepted, our capital needs will increase substantially. If we fail to obtain the funding that we need when it is required, we may have to forego or delay potentially valuable opportunities to acquire new crude oil and natural gas properties. In addition, without the necessary funding, we may default on existing funding commitments to third parties and forfeit or dilute our rights in existing crude oil and natural gas property interests.
Our ability to reach and maintain profitable operating results is dependent on our ability to find, acquire, and develop crude oil and natural gas properties.
Our future performance depends upon our ability to find, acquire, and develop crude oil and natural gas reserves that are economically recoverable. Without successful exploration and acquisition activities, we will not be able to develop reserves or generate production revenues to achieve and maintain profitable operating results. No assurance can be given that we will be able to find, acquire or develop these reserves on acceptable terms. We also cannot assure that commercial quantities of crude oil and natural gas deposits will be discovered that are sufficient to enable us to recover our exploration and development costs.
Our producing reserves are located in one major geographic area. Concentration of reserves in limited geographic areas may disproportionately expose us to operational, regulatory and geological risks.
Our two producing projects are located in California. As a result of this concentration, we may be disproportionately exposed to the impact of regional conditions which could negatively impact the success and profitability of our operations. Any change in supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation of state or regional regulations, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of crude oil and natural gas have the potential to negatively impact us. Our operations are also exposed to natural disasters and related events common to California, such as wildfires, mudslides, high winds, earthquakes and extreme weather events, and the potential increase to the frequency of drought and flooding. Further, our operations may be exposed to power outages, mechanical failures, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut in, delay operations and growth plans, decrease cash flows, increase operating and capital costs, prevent development of lease inventory before expiration and limit access to markets for our products.
Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our crude oil reserves, and our revenues, profitability, and cash flows to be materially different from our estimates.
The accuracy of estimated proved reserves and estimated future net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering, and economic data and is subject to various assumptions, including assumptions required by the SEC relating to crude oil prices, drilling and operating expenses and other matters. Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, crude oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of our crude oil reserves, which in turn could adversely affect our cash flows, results of operations, financial condition, and the availability of capital resources. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil prices and other factors, many of which are beyond our control. Downward adjustments to our estimated proved reserves could require us to impair the carrying value of our crude oil properties, which would reduce our earnings and increase our stockholders’ deficit.
The present value of proved reserves will not necessarily equal the current fair market value of our estimated crude oil reserves. In accordance with reserve reporting requirements of the SEC, we are required to establish economic production for reserves on an average historical price. Actual future prices and costs may be materially higher or lower than those required by the SEC. The timing of both the production and expenses with respect to the development and production of crude oil properties will affect the timing of future net cash flows from proved reserves and their present value.
The estimated proved reserve information is based upon reserve reports prepared by an independent engineer. From time to time, estimates of our reserves are also made by our company engineer for use in developing business plans and making various decisions. Such estimates may vary significantly from those of the independent engineers and may have a material effect upon our business decisions and available capital resources.
We may not be able to replace current production with new crude oil and natural gas reserves.
In general, the volume of production from a crude oil and natural gas property declines as reserves related to that property are depleted. The decline rates of production depend upon individual reservoir characteristics. In order to maintain current production levels, we will be required to find and develop additional reserves either in properties we currently own or in properties in which we may acquire in the future. Projects that we have been involved in the past have had steep rates of decline and relatively short estimated productive lives. While this is not the situation with our two current projects in California where there are fairly shallow decline curves, there is no guarantee that we will be successful in maintaining our current company-wide production levels.
Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including hydrocarbon prices, the availability and cost of
capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory and zoning approvals and other factors.
Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our business and results of operations.
Due to the volatility in crude oil prices and the lack of available drilling capital, we have not drilled any prospective development locations in California since November of 2013.
We have reclassified proved undeveloped reserves to unproved reserves due to our inability to commit sufficient capital within the required five-year development window, which could adversely affect the value of our properties.
The SEC generally requires that any undrilled location can be classified as a proved undeveloped reserve only if a development plan has been adopted indicating that the location is scheduled to be drilled within five years. The reduction of our drilling program in response to depressed crude oil and natural gas prices and a lack of drilling capital has impacted our ability to develop proved undeveloped reserves within such five-year period. The reduction in our drilling plans has limited our access to capital resources. In the past, we have had to reclassify a significant amount of our proved undeveloped reserves as probable or possible reserves because they have not been drilled within the SEC-defined time period. Any future reclassification of proved undeveloped reserves may adversely affect the value of our properties.
Our financial condition will deteriorate if we are unable to retain our interests in our leased crude oil and natural gas properties.
All of our properties are held under interests in crude oil and natural gas mineral leases. If we fail to meet the specific requirements of any lease, such lease may be terminated or otherwise expire. We cannot be assured that we will be able to meet our obligations under each lease. The termination or expiration of our “working interests” (interests created by the execution of a crude oil or natural gas lease) relating to these leases would impair our financial condition and results of operations.
We will need significant additional funds to meet capital calls, drilling, and other production costs in our effort to explore, produce, develop and sell the crude oil and natural gas produced by our leases. We may not be able to obtain any such additional funds on acceptable terms.
Title deficiencies could render our crude oil and natural gas leases worthless; thus damaging the financial condition of our business.
The existence of a material title deficiency can render a lease worthless, resulting in a large expense to our business. We rely upon the judgment of crude oil and natural gas lease brokers who perform the fieldwork and examine records in the appropriate governmental office before attempting to place a specific mineral interest under lease. This is a customary practice in the crude oil and natural gas industry.
We anticipate that we, or the person or company acting as operator on the properties that we lease, will examine title prior to any well being drilled. Even after taking these precautions, deficiencies in the marketability of the title to the leases may still arise. Such deficiencies may render some leases worthless, negatively impacting our financial condition.
If we as operator of our crude oil and natural gas projects fail to maintain adequate insurance, our business could be exposed to significant losses.
Our crude oil projects are subject to risks inherent in the crude oil and natural gas industry. These risks involve explosions, uncontrollable flows of crude oil, natural gas or well fluids, pollution, fires, earthquakes, and other environmental issues. These risks could result in substantial losses due to injury and loss of life, severe damage to and destruction of property and equipment, pollution, and other environmental damage. As protection against these operating hazards, we maintain insurance coverage to include physical
damage and comprehensive general liability. However, we are not fully insured in all aspects of our business. The occurrence of a significant event on any project against which we are not adequately covered by insurance could have a material adverse effect on our financial position.
In any project in which we are not the operator, we will require the operator to maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. The occurrence of a significant adverse event on any of these projects if they are not fully covered by insurance could result in the loss of all or part of our investment. The loss of any such project investment could have a material adverse effect on our financial condition and results of operations.
Recent action by the State of California imposing additional financial assurance requirements related to plugging and abandonment costs, decommissioning, and site restoration on those who acquire the right to operate wells and production facilities could impact our ability to sell or acquire assets in the state of California or increase our costs in connection with the same.
On October 7, 2023, the California Governor signed into law Assembly Bill 1167 (“AB 1167”), which imposes more stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in the state of California, requiring them to file either an individual indemnity bond for single-well or production facility acquisitions, or a blanket indemnity bond for multiple wells or production facilities. The bond imposed on the acquirer will be in an amount determined by the state to sufficiently cover plugging and abandonment costs, decommissioning, and site restoration, and AB 1167 prohibits the closing of any acquisition of a well or production facility until a determination on the appropriate bond amount has been completed by the state and the bond has been filed. We are still assessing the impact of AB 1167. In addition, although AB 1167 has been signed into law, Governor Newsom has called for further legislative changes to these new requirements to mitigate against the potential risk of the implementation of AB 1167 ultimately increasing the number of orphaned idle or low-producing wells in California. However, we cannot predict what form these changes may ultimately take or if the legislature will act on the Governor’s request. Implementation of this law may lead to the delay or additional costs with respect to acquisitions or dispositions, which could impact our ability to grow or explore new strategic areas - or exit others - within the state of California.
We are subject to economic downturns and the effects of public health events, such as the COVID-19 pandemic, which may materially and adversely affect the demand and the market price for our products.
The severity, magnitude and duration of COVID-19 or another pandemic, the extent of actions that have been or may be taken to contain or treat their impact, and the impacts on the economy generally and oil prices in particular, are uncertain, rapidly changing and hard to predict. This uncertainty could force us to reduce costs, including by decreasing operating expenses and lowering capital expenditures, and such actions could negatively affect future production and our reserves. We may experience labor shortages if our employees are unwilling or unable to come to work because of illness, quarantines, government actions or other restrictions in connection with the pandemic. If our suppliers cannot deliver the materials, supplies and services we need, we may need to suspend operations. In addition, we are exposed to changes in commodity prices which have been and will likely remain volatile. We cannot predict the duration and extent of the pandemic's adverse impact on our operating results.
Additionally, to the extent the COVID-19 pandemic or any resulting worsening of the global business and economic environment adversely affects our business and financial results, it may also have the effect of heightening or exacerbating many of the other risks described in the Risk Factors herein.
Risks related to Environmental Regulation
Our crude oil and natural gas exploration and production, and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.
Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated, and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate. Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability
involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.
We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs. Some of our properties may be affected by environmental contamination that may require investigation or remediation. In addition, claims are sometimes made or threatened against companies engaged in crude oil and natural gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation. Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.
We face various risks associated with the trend toward increased anti-crude oil and natural gas development activity.
In recent years, we have seen significant growth in opposition to crude oil and natural gas development in the United States. Companies in our industry can be the target of opposition to hydrocarbon development from stakeholder groups, including national, state and local governments, regulatory agencies, non-government organizations and public citizens. This opposition is focused on attempting to limit or stop hydrocarbon development. Examples of such opposition include: efforts to reduce access to public and private lands; delaying or canceling permits for drilling or pipeline construction; limiting ore banning industry techniques such as hydraulic fracturing, and/or adding restrictions on or the use of water and associated disposal; imposition of set-backs on crude oil and natural gas sites; delaying or denying air-quality permits; advocating for increased punitive taxation or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm. Recent efforts by the US Administration to modify federal crude oil and natural gas regulations could intensify the risk of anti-development efforts from grass roots opposition.
Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements from these efforts, could have a material adverse effect on our business.
Restricted land access could reduce our ability to explore for and develop crude oil and natural gas reserves.
Our ability to adequately explore for and develop crude oil and natural gas resources is affected by a number of factors related to access to land. Examples of factors which reduce our access to land include, among others:
· new municipal, state or federal land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;
· local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;
· landowner, community and/or governmental opposition to infrastructure development;
· regulation of federal and Indian land by the Bureau of Land Management;
· anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, disruption of drilling, or damage to equipment;
· the presence of threatened or endangered species or of their habitat;
· Disputes regarding leases; and
· Disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements.
Reduced ability to obtain new leases could constrain our future growth and opportunity resulting in a material adverse effect on our business, financial condition, results of operations and our cash flows.
Recent and future actions by the state of California and local governments could result in restrictions to our operations and result in decreased demand for oil and gas within the state.
In September 2020, Governor Gavin Newsom of California issued an executive order (the “Order”) that seeks to reduce both the demand for and supply of petroleum fuels in the state. The Order establishes several goals and directs several state agencies to take certain actions with respect to reducing emissions of GHGs, including, but not limited to: phasing out the sale of new emissions-producing passenger vehicles, drayage trucks and off-road vehicles by 2035 and, to the extent feasible, medium and heavy duty trucks by 2045; developing strategies for the repurposing of crude oil and natural gas facilities in California; and proposing legislation to end the issuance of new hydraulic fracturing permits in the state by 2024. The Order also directs the California Department of Conservation, Geologic Energy Management Division (“CalGEM”) to strictly enforce bonding requirements for oil and gas operations and to complete its ongoing public health and safety review of oil production and propose additional regulations, which are expected to include expanded land use setbacks or buffer zones. In October 2020, the Governor issued an executive order that establishes a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directs state agencies to implement other measures to mitigate climate change and strengthen biodiversity.
On September 16, 2022, the Governor of California signed Senate Bill No. 1137 into law, which established 3,200 feet as the minimum distance between new crude oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public effective January 1, 2023. On January 6, 2023, CalGEM's emergency regulations to support implementation of Senate Bill No. 1137 were approved by the Office of Administrative Law and final regulations were published. The regulations included applicable requirements of notice to property owners and tenants regarding the work performed and offering the sampling of test water wells or surface water before and after drilling; the contents of required notices for new production facilities; the annual submission of a sensitive receptor inventory and sensitive receptor map and the contents and format of the same; and the requirements of statements where operators have determined a location not to be within a health protection zone.
Additional provisions of Senate Bill No. 1137 include, among others, the imposition of health, safety and environmental controls applicable to both current and new wells located within this distance of sensitive receptors related to noise, light, and dust pollution controls and air emission monitoring, and the immediate suspension of operations at production facilities determined to not be in compliance with certain air emission requirements.
Climate change legislation or regulations restricting emissions of greenhouse gases (“GHG”) could result in increased operating costs and reduced demand for the crude oil and natural gas we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration by states or groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the Clean Air Act. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, onshore and offshore crude oil and natural gas production facilities and onshore processing, transmission, storage, and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the crude oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines, and in January 2016, the EPA proposed additional revisions to leak detection methodology.
The adoption and implementation of any international, federal, or state legislation, regulations or other regulatory initiatives that require reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could cause us to incur increased costs that could have an adverse effect on our business, financial condition, and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for crude oil and natural gas, which could reduce the demand for the crude oil or natural gas we produce and lower the value of our reserves.
Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or
colder than their historical averages. Extreme weather conditions can interfere with our production and increase our operating expenses. Such damage or increased expenses from extreme weather may not be fully insured. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.
The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new costs on our operations.
In August 2022, President Biden signed the Act into law. The Act contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure among other provisions. In addition, the Act imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The Act amends the Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore crude oil and natural gas production categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year thereafter. Calculation of the fee is based on certain thresholds established in the Act. In addition, the multiple incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy away from fossil fuels towards lower- or zero-carbon emission alternatives. The methane charges and various incentives for clean energy industries could decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently materially and adversely affect our business and results of operations.
Risks Related to Our Indebtedness
We have experienced significant operating losses in the past and there can be no assurance that we will become profitable in the future.
We have reported net loss of approximately $2.4 million for the year ended February 28, 2023, and we have an accumulated deficit through February 28, 2023 of approximately $31.96 million. Without successful exploration and development of our properties and a significant sustained increase in hydrocarbon prices any investment in Daybreak could become devalued or worthless.
Our ability to satisfy our obligations depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. Our business does not generate sufficient cash flow to meet our ongoing obligations, and future financings may not be available to provide sufficient net proceeds, to meet these obligations or to successfully execute our business strategy. Our future performance, in turn, is dependent upon many factors that are beyond our control such as the level of hydrocarbon prices and general economic, financial and business conditions. We cannot guarantee that our future performance will not be adversely affected by such economic conditions and financial, business and other factors.
We have substantial indebtedness. The amount of our outstanding indebtedness and our current inability to meet our debt obligations will have adverse consequences on our business, financial condition, and results of operations.
At February 28, 2023, we had approximately $4.2 million of consolidated indebtedness comprised of a variety of short-term and long-term borrowings; trade payables; and 12% Subordinated Notes. The 12% Notes had a maturity date of January 29, 2019 and the principal balance of $290,000 has not been paid. Our level of indebtedness could affect our business in several ways, including the following:
· limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
· require us to dedicate a portion of our cash flows from operations to service our existing debt, thereby reducing cash available to finance our operations and other business activities;
· increase our vulnerability to downturns and adverse developments in our business and the economy generally; and,
· limit our access to capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other expenses.
Risks Related to Our Common Stock
We may be unable to continue as a going concern in which case our Common Stock will have little or no value.
Our financial statements for the year ended February 28, 2023 were prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. We have incurred net losses since inception, which raises substantial doubt about our ability to continue as a going concern. In the event we are not able to continue operations, an investor will likely suffer a complete loss of their investment in our securities.
The market price of our Common Stock has been volatile, which may cause the investment value of our stock to decline.
As of February 28, 2023, Daybreak’s Common Stock (OTC Pink: DBRM) traded on the OTC Pink® Open Market under the OTC Markets Group segment, Pink Current Information. Prior to May 1, 2016, our stock had traded on the OTCQB Venture Marketplace. Our transition to the OTC Pink® Open Market was the result of a cost-savings move for the company related to listing fees on the Venture Marketplace.
In September 2023, information on our Common Stock was transferred to the OTC Expert Market. This move to the Expert Market was triggered by a lack of current financial information being available due to delays in the filing of this 10-K filing for the year ended February 28, 2023, and subsequent 10-Q reports. These delays were caused by difficulties in completing the required two-year audit of Reabold California, LLC. following the acquisition in May 2022. The audit was subsequently completed in July 2023. We anticipate that once we are current with our public company filings, our Common Stock will again be quoted on the OTC Pink Open® Market, although we can provide no assurances as to the timing or our ultimate success in this regard.
Because of the limited liquidity of our stock, shareholders may be unable to sell their shares at or above the cost of their purchase prices. The trading price of our shares has experienced wide fluctuations and these shares may be subject to similar fluctuations in the future.
The trading price of our Common Stock may be affected by a number of factors including events described in these risk factors, as well as our operating results, financial condition, announcements of drilling activities, general conditions in the crude oil and natural gas exploration and development industry including volatility in crude oil and natural gas prices, and other events or factors. The instability and volatility in hydrocarbon prices that has occurred since June 2014, has had a corresponding material and mostly adverse impact on our revenues and a similar direct material adverse impact on the trading price of our Common Stock.
In recent years, broad stock market indices, in general, and smaller capitalization companies, in particular, have experienced substantial price fluctuations. In a volatile market, we do experience wide fluctuations in the market price of our Common Stock. These fluctuations may have a negative effect on the market price of our Common Stock.
Pursuant to SEC rules our Common Stock is classified as a “penny stock” increasing the risk of investment in these shares.
Our Common Stock is designated as a “penny stock” and thus may be more illiquid than shares traded on an exchange or on NASDAQ. Penny stocks generally are any non-NASDAQ or non-exchange listed equity securities with a price of less than $5.00, subject to certain exceptions.
The “penny stock” reporting and disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for a stock that is subject to these rules. The market liquidity for the shares could be severely and adversely affected by limiting the ability of broker-dealers to sell these shares.
The resale of shares offered in private placements could depress the value of the shares.
In the past, shares of our Common Stock have been offered and sold in private placements at significant discounts to the trading price of the Common Stock at the time of the offering. Sales of substantial amounts of Common Stock eligible for future sale in the public market, or the availability of shares for sale, including shares issued upon exercise of outstanding warrants, could adversely affect the prevailing market price of our Common Stock and our ability to raise capital by an offering of equity securities.
Privately placed issuances of our Common Stock and warrants have and may continue to dilute ownership interests which could have an adverse effect on our stock prices.
Our authorized capital stock consists of 500,000,000 shares of Common Stock. As of February 28, 2023, there were 384,734,902 shares of Common Stock issued and outstanding. With the filing of our Company’s Second Amended and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, we no longer have any preferred stock.
Historically we have issued, and likely will continue to issue, additional shares of our Common Stock in connection with the compensation of personnel, future acquisitions, private placements, possible equity swaps for debt or for other business purposes. Future issuances of substantial amounts of these equity securities could have a material adverse effect on the market price of our Common Stock and would result in further dilution of the ownership interests of our existing shareholders.
We will need to seek to raise additional funds in the future through debt financing, which may impose operational restrictions and may further dilute existing ownership interests.
We expect to seek to raise additional capital in the future to help fund our acquisition, development, and production of crude oil and natural gas reserves. In the past, we have obtained debt financing through commercial loans and credit facilities. Subsequent debt financing, if available, may require restrictive covenants, which may limit our operating flexibility. Future debt financing may also involve debt instruments that are convertible into or exercisable for Common Stock. The conversion of the debt-to-equity financing may dilute the equity position of our existing shareholders.
We do not anticipate paying dividends on our Common Stock, which could devalue the market value of these securities.
We have not paid any cash dividends on our Common Stock since the Company’s inception in 1955. We do not anticipate paying cash dividends in the foreseeable future. Any dividends paid in the future will be at the complete discretion of our Board of Directors. For the foreseeable future, we anticipate that we will retain any revenues that we may generate from our operations. These retained revenues will be used to finance and develop the growth of the Company. Prospective investors should be aware that the absence of dividend payments could negatively affect the market value of our Common Stock. Investors must rely on sales of their Common Stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our Common Stock.
We have two shareholders that own approximately 42% and 40%, respectively, of our outstanding Common Stock shares at February 28, 2023, who may be able to individually or jointly control the operations of the Company.
We face certain risks associated with having these two large shareholders. Individually or jointly they may be able to:
· control the elections of persons to the Board of Directors and may elect persons less qualified than would be elected absent the two large shareholders;
· influence the Board of Directors to enter into transactions with related or third parties that are more favorable to such parties than would be negotiated by an independent Board of Directors;
· control all matters requiring approval by the shareholders including any future issuances of a material number of securities or changes to the Company’s Articles of Incorporation and By-laws, and other major transactions; and,
· delay, defer or prevent a change in control or otherwise prevent shareholders other than these two affiliates from influencing our direction and future.
General Risk Factors
Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of proposed legislation.
From time to time, legislation has been proposed that would, if enacted into law, make significant changes to United States federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to crude oil and natural gas exploration and production companies. These changes include, but are not limited to: (1) the repeal of the percentage depletion allowance for crude oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and
development costs, (3) the elimination of the deduction for certain U.S. domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures.
However, it is unclear whether any such changes will be enacted and, if enacted, how soon any such changes could become effective. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced demand for our products. The passage of this type of legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to crude oil and natural gas exploration and development or could increase costs, and any such change could negatively impact the value of an investment in our Common Stock as well as have a negative effect on our financial condition and results of operations.
We may lose key management personnel which could endanger the future success of our crude oil and natural gas operations.
Our President and Chief Executive Officer, who is also acting as our interim principal finance and accounting officer, our Chief Operating Officer and our Director of Field Operations, along with three of our directors have substantial experience in the crude oil and natural gas business. The loss of any of these individuals could adversely affect our business. If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that a suitable or comparable substitute will be found.
A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.
A terrorist attack, anti-terrorist efforts or other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for crude oil and natural gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues. Crude oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of crude oil and natural gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
As a smaller reporting company, we are not required to provide the information otherwise required by this Item.

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ITEM 2. PROPERTIES
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.
Proved Reserves
Reserve Category Crude Oil (Barrels) Natural Gas (Mcf) Total Crude Oil
Equivalents (BOE)
Percent of Oil
Equivalents (BOE)
Developed 384,189 58,330 393,910 100.0 %
Undeveloped - - - -
Total Proved 384,189 58,330 393,910 100.0 %
Changes in our estimated total net proved reserves (BOE) for the twelve months ended February 28, 2023 are set forth in the table below.
Proved Reserves (BOE)
Balance as of February 28, 2022 517,155
Revisions (393,076 )
Discoveries and extensions -
Purchase of minerals 287,582
Production (17,751 )
Balance as of February 28, 2023 393,910
Revisions. Net upward revisions of 6,235 BOE of developed reserves in aggregate were due to the higher net crude oil and natural gas prices we received during the twelve months ended February 28, 2023 increasing the economic life of our proved reserves, offset by the removal of 399,311 BOE of proved undeveloped reserves that have remained for a period greater than five years as of February 28, 2023.
Discoveries and extensions. For the twelve months ended February 28, 2023, we had no discoveries or extensions of reserves.
Purchase of minerals. For the twelve months ended February 28, 2023, we acquired through the Reabold subsidiary acquisition 287,582 BOE of developed reserves.
Production. Production was 17,751 BOE in aggregate of developed reserves for the twelve months ended February 28, 2023.
Changes in our estimated net proved undeveloped reserves (BOE) for the twelve months ended February 28, 2023 are set forth in the table below.
Proved Reserves (BOE)
Balance as of February 28, 2022 399,311
Revisions (399,311 )
Balance as of February 28, 2023 -
Revisions. A downward revision of 399,311 BOE of proved undeveloped reserves occurred for the twelve months ended February 28, 2023. Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years.
Our estimated net proved developed producing reserves in California at February 28, 2023 are set forth in the table below.
Proved Developed Reserves
Natural Total Oil Percent of Oil
Location Oil (Barrels) Gas (Mcf) Equivalents (BOE) Equivalents (BOE)
East Slopes Project 116,019 - 116,019 29.5 %
Reabold Project 268,170 58,330 277,891 70.5 %
California Total 384,189 58,330 393,910 100.0 %
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.
Proved Reserves
PV-10 as a
Total Oil PV-10 of Percentage of
Location Equivalents (BOE) Proved Reserves Proved Reserves
East Slopes Project 116,019 2,045,924 18.5 %
Reabold Project 277,891 8,990,030 81.5 %
California Total 393,910 11,035,954 100.0 %
The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10”), was approximately $11.0 million at February 28, 2023 an increase of approximately $4.8 million or 77.4% from the PV-10 reserve valuation of approximately $6.2 million at February 28, 2022. This increase is primarily due to the acquisition of the Reabold project in California. The commodity prices used to estimate proved reserves and their related PV-10 at February 28, 2023 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the twelve month period from March 2022 through February 2023. The WTI benchmark average price for the twelve months ended February 28, 2022 was $93.55 per barrel of crude oil in comparison to $71.69 in the prior year reserve report.
These benchmark average prices were further adjusted for crude oil quality and gravity, transportation fees and other price differentials resulting in an average realized price in California for the February 28, 2023 reserve report of $90.43 in comparison to $68.80 in the February 28, 2022 reserve report. Adverse changes in any price differential would reduce our cash flow from operations and the PV-10 of our proved reserves. Operating costs were not escalated.
PV-10 is not a generally accepted accounting principal (“GAAP”) financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our financial statements. The PV-10 of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a comparable basis.
Reserve Estimation
Our estimated proved developed reserves of 116,019 BOE for the East Slopes project in Kern County for the twelve months ended February 28, 2023 were derived from engineering reports prepared by PGH Petroleum and Environmental Engineers, LLC (“PGH”) of Austin, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.
PGH is an independent petroleum engineering consulting firm registered in the State of Texas, and Frank J. Muser, a Petroleum Engineer, is the technical person at PGH primarily responsible for evaluating the proved reserves covered by their report. Mr. Muser graduated from the University of Texas at Austin with a Bachelor of Science degree in Chemical Engineering. He is a licensed Professional Engineer in the states of Texas, Alabama, Kansas, North Dakota, and West Virginia and has been employed by PGH as a staff engineer since 2012. Mr. Muser has over 20 years of extensive crude oil and natural gas experience working in both private industry and for the State of Texas. The services provided by PGH are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about the evaluations performed by PGH, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K.
Our estimated proved developed reserves of 277,891 BOE for the Reabold project in Monterey and Contra Costa Counties for the twelve months ended February 28, 2023 were derived from engineering reports prepared by PETROtech Resources Company (“PETROtech”) of Bakersfield, California in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.
PETROtech is an independent petroleum engineering consulting firm registered in the State of California, and Bradford DeWitt, a Petroleum Engineer, is the technical person at PETROtech primarily responsible for evaluating the proved reserves covered by their report. Mr. DeWitt has a Bachelor of Arts degree from the University of California - Los Angeles (“U.C.L.A”) and a Master of Science degree in Engineering from the University of Southern California (“U.S.C.”). He is a registered petroleum engineer in the State of California. The services provided by PETROtech are not audits of our reserves but instead consist of complete engineering
evaluations of the respective properties. For more information about the evaluations performed by PETROtech, refer to the copy of their report filed as Exhibit 99.2 to this Annual Report on Form 10-K.
Our internal controls over the reserve reporting process are designed to result in accurate and reliable estimates in compliance with applicable regulations and guidance. Internal reserve preparation is performed by Bobby Ray Greer, Director of Field Operations. Mr. Greer is a 1984 graduate of University of Southern Mississippi in Hattiesburg, Mississippi with a Bachelor of Science Degree in Geology and is a certified Petroleum Geologist and a member, in good standing, of the American Association of Petroleum Geologists and is a registered professional geologist in Mississippi. Mr. Greer has over 40 years of experience in petroleum exploration, reservoir analysis, drilling rig construction, oilfield operations and management.
Although we believe that the estimates of reserves prepared by Mr. Greer have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage an independent petroleum engineering consultant to prepare an annual evaluation of our estimated proved reserves. We provide to PGH and PETROtech, for their analysis, all pertinent data needed to properly evaluate our reserves. We consult regularly with PGH and PETROtech during the reserve estimation process to review properties, assumptions, and any new data available. Additionally, the Company’s senior management reviewed and approved all Daybreak reserve report information contained in this Annual Report on Form 10-K.
Under current SEC standards, proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability. The technical data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Generally, crude oil and natural gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations. Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technical data to assess the reservoir continuity. In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities. Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data. When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of crude oil derived through volumetric calculations.
The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering, and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves and future cash flows are based on various assumptions and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable crude oil reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the crude oil and natural gas industry in general are subject.
Delivery Commitments
As of February 28, 2023, we had no commitments to provide any fixed or determinable quantities of crude oil or natural gas in the near future under contracts or agreements.
Summary Operating Data
The following table sets forth our net share of annual production in each project for the periods shown. One barrel of crude oil equivalent (“BOE”) is roughly equivalent to 6,000 cubic feet or 6 Mcf of gas.
As of February 28, 2023, our total reserves were comprised of our working interest in projects located in Kern, Monterey and Contra Costa counties, all located in California. We only have natural gas production from our project in Contra Costa County. Prior to the acquisition of our Reabold subsidiary acquisition in May of 2022, we had no natural gas production.
For the Twelve Months Ended February 28,
Crude Oil and Natural Gas Production Data:
Crude oil 17,114 9,613 10,970
Natural gas (BOE) - -
Total (BOE) 17,751 9,613 10,970
The following table sets forth our net share of crude oil and natural gas revenue by project area for the periods shown.
For the Twelve Months Ended February 28,
Crude Oil and Gas Revenue:
Crude oil - Kern County (East Slopes) $ 728,439 $ 680,107 $ 404,901
Crude Oil - Monterey and Contra Costa Counties (Reabold) 804,821 - -
Natural gas - Contra Costa County (Reabold) 80,026 - -
Total revenue $ 1,613,286 $ 680,107 $ 404,901
The following table sets forth the average realized sales price from each project area for the periods shown.
For the Twelve Months Ended February 28,
Average Realized Price:
Crude oil (Bbl) - Kern County (East Slopes) $ 90.38 $ 70.75 $ 36.91
Crude oil (Bbl) - Monterey and Contra Costa Counties (Reabold) $ 88.89 $ - $ -
Natural gas (Mcf) - Contra Costa County (Reabold) $ 20.94 $ - $ -
Annual Crude oil and natural gas (BOE) realized sales price $ 90.88 $ 70.75 $ 36.91
The following table sets forth the average production expense (BOE) for the periods shown.
For the Twelve Months Ended February 28/29,
Average Production Expense (BOE):
Kern County $ 42.44 $ 24.06 $ 17.12
Monterey and Contra Costa Counties $ 85.86 $ - $ -
Annual Average production expense (BOE) $ 62.97 $ 24.06 $ 17.12
Gross and Net Acreage
The following table sets forth our interests in developed and undeveloped crude oil lease acreage in California held by us as of February 28, 2023. These ownership interests generally take the form of working interests in crude oil leases that have varying terms. Developed acreage includes leased acreage that is allocated or assignable to producing wells. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, regardless of whether or not the acreage contains proved reserves. Gross acres represents the total number of acres in which we have an interest. Net acres represents the sum of our fractional working interests owned in the gross acres.
Developed Undeveloped Total
Gross Net Gross Net Gross Net
California - Kern County 2,694 1,010 3,494 1,302
California - Monterey and Contra Costa Counties 4,372 2,186 4,732 2,366
Total 1,160 7,066 3,196 8,226 3,668
Average working interest
36.5 %
44.2 %
42.7 %
Undeveloped Acreage Expirations
We have no gross and net undeveloped acreage in California expiring over the next three years as all of our gross and net acreage is currently held by production.
In all cases the drilling of a commercial crude oil or natural gas well will hold acreage beyond the lease expiration date. In the past we have been able to, and expect in the future to be able to extend the lease terms of some of these leases. Based on our evaluation of prospective economics, we have allowed acreage to expire from time to time and we expect to allow additional acreage to expire in the future. In California, we have previously determined that there was no likely benefit to pursuing any drilling opportunities on our expiring leases, and so we have not attempted to renew those leases when their expiration dates occurred.
Producing Wells
The following table sets forth our gross and net productive crude oil wells in California as of February 28, 2023. Productive wells are producing wells and wells capable of production. Gross wells represent the total number of wells in which we have an interest. Net wells represent the sum of our fractional working interests owned in the gross wells.
Property Location
Gross Wells Net Wells
Kern County (East Slopes) 7.3
Monterey and Contra Costa Counties (Reabold) 5.0
Total 12.3
Weighted average - working interest
41.0 %
Drilling Activity
In the past three years, we have had no drilling activity occur due to the volatility of crude oil prices and the lack of available drilling capital.

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ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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.
Twelve Months Ended
February 28, 2023
Twelve Months Ended
February 28, 2022
High Low High Low
First Quarter 0.04675 0.033 0.0670 0.0200
Second Quarter 0.0522 0.037 0.0379 0.0220
Third Quarter 0.0522 0.031 0.0530 0.0230
Fourth Quarter 0.0412 0.022 0.0683 0.0225
As of January 23, 2024, the Company had 1,700 shareholders of record of its Common Stock. This number does not include an indeterminate number of shareholders whose shares are held by brokers in street name.
Transfer Agent
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.
Fiscal Period
Shares of Series A
Preferred Converted
to Common Stock
Shares of
Common Stock
Issued from
Conversion
Number of
Accredited
Investors
Year Ended February 29, 2008
102,300
306,900
Year Ended February 28, 2009
237,000
711,000
Year Ended February 28, 2010
51,900
155,700
Year Ended February 28, 2011
102,000
306,000
Year Ended February 29, 2012
-
-
-
Year Ended February 28, 2013
18,000
54,000
Year Ended February 28, 2014
151,000
453,000
Year Ended February 28, 2015
3,000
9,000
Year Ended February 29, 2016
10,000
30,000
Year Ended February 28, 2017
-
-
-
Year Ended February 28, 2018
14,997
44,991
Year Ended February 28, 2019
-
-
-
Year Ended February 29, 2020
-
-
-
Year Ended February 28, 2021
-
-
-
Year Ended February 28, 2022
709,568
2,128,704
Totals
1,399,765
4,199,295
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.
Fiscal Year Ended Shareholders at
Period End
Accumulated
Dividends
February 28, 2007 $ 155,311
February 29, 2008 242,126
February 28, 2009 209,973
February 28, 2010 189,973
February 28, 2011 173,707
February 29, 2012 163,624
February 28, 2013 161,906
February 28, 2014 151,323
February 28, 2015 132,634
February 29, 2016 130,925
February 28, 2017 130,415
February 28, 2018 128,231
February 28, 2019 127,714
February 29, 2020 128,063
February 28, 2021 127,714
February 28, 2022 - 96,340
$ 2,449,979
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.
Common Stock
Balance
Par Value
Common Stock, Issued and Outstanding, February 28, 2021 60,491,122
Shares issued for Series A Preferred conversion 2,128,704 $ 2,129
Shares issued for Series A accumulated dividend 1,100,000 $ 1,100
Shares issued for debt conversion of accrued salaries 1,397,880 $ 1,398
Shares issued for debt conversion of accrued directors fees 317,708 $ 318
Shares issued for conversion of 12% Note principal and interest - related party 1,144,415 $ 1,144
Shares issued for investment principal in production revenue program 1,222,444 $ 1,222
Common Stock, Issued and Outstanding, February 28, 2022 67,802,273
Shares issued for conversion of 12% Note principal and interest 78,934 $ 79
Shares issued for conversion of convertible note 27,764,706 $ 27,765
Shares issued for acquisition of crude oil and natural gas properties 160,964,489 $ 160,964
Shares issued for sale of stock 125,000,000 $ 125,000
Shares issued for financing fees 3,125,000 $ 3,125
Share adjustment due to recording error (500 ) $ 1
Common Stock, Issued and Outstanding, February 28, 2023 384,734,902
During the twelve months ended February 28, 2023, there were 316,933,129 shares of Common Stock issued. Common Stock shares issued for the Reabold subsidiary acquisition were 160,964,489. Share issuances in connection with fundraising were 155,889,706. Another 78,934 shares were issued through the conversion of a 12% Note and interest to our Common Stock. During the twelve months ended February 28, 2022, there were 7,311,151 shares of Common Stock issued as a part of the Company’s restructuring of its balance sheet in accordance with the conditions of the Equity Exchange Agreement between Reabold California, LLC, Gaelic Resources Ltd, and the Company. Of the total 7,311,151 shares issues, there were 4,082,447 shares issued to satisfy related party debt. Another 3,228,704 shares were issued to satisfy the Series A Preferred stock conversion and associated accumulated dividend of $2,449,979. In December 2023, we were notified of a system error that had occurred in the recording of street stock shares held by the nominee. Accordingly, the number of our issued and outstanding shares was reduced by 500 shares as of February 28, 2023. The common stock par value of this adjustment was $0.50.
All shares of Common Stock are equal to each other with respect to voting, liquidation, dividend and other rights. Owners of shares of Common Stock are entitled to one vote for each share of Common Stock owned at any shareholders’ meeting. Holders of shares of Common Stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefore; and upon liquidation, are entitled to participate pro rata in a distribution of assets available for such a distribution to shareholders.
There are no conversion, preemptive, or other subscription rights or privileges with respect to any shares of our Common Stock. Our stock does not have cumulative voting rights, which means that the holders of more than 50% of the voting power of the shares voting in an election of directors, acting together (as applicable), may elect all of the directors if they choose to do so. In such event, the holders of the remaining shares aggregating less than fifty percent (50%) would not be able to elect any directors. Each common shareholder has the right to vote in person or by proxy one vote for every share of stock standing in his or her name on the books of the Company on the record date.
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:
Warrants
Weighted Average
Exercise Price
Warrants outstanding, February 28, 2021
2,100,000
$ 0.01
Changes during the twelve months ended February 28, 2022:
Issued
-
Expired / Cancelled / Forfeited
-
Warrants outstanding, February 28, 2022
2,100,000
$ 0.01
Warrants exercisable, February 28, 2022
893,333
Changes during the twelve months ended February 28, 2023:
Issued
-
$
Expired / Cancelled / Forfeited
-
Warrants outstanding, February 28, 2023
2,100,000
$ 0.01
Warrants exercisable, February 28, 2023
2,100,000
$ 0.01
Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities
On December 15, 2021, Daybreak finalized agreements with its directors, executive officers, and other employees with respect to the forgiveness and conversion of related party debts into shares of the Company’s Common Stock (the “Related Party Debt Conversion”) at a conversion rate of $0.45 per share of Common Stock. Completing this Related Party Debt Conversion was a condition to closing the Equity Exchange Agreement dated as of October 20, 2021 entered into by and among the Company, Reabold California LLC, a California limited liability company (“Reabold”), and Gaelic Resources Ltd., a private company incorporated in the Isle of Man and the 100% owner of Reabold (“Gaelic”), pursuant to which Daybreak would acquire Reabold in exchange for issuing 160,964,489 shares of its Common Stock to Gaelic (the foregoing transaction, the “Equity Exchange”).
The following is a description of the debts converted, amounts of debt, and shares of Common Stock agreed to be issued in exchange:
Description of Debt Converted Dollar Amount
Converted
Shares of
Common Stock Issued
Accrued deferred salary amounts owed to employees $ 629,046.00 1,397,880
Accrued deferred director fees $ 142,968.75 317,708
12% Subordinated Note Payable, related party $ 514,986.35 1,144,415
Interest in Production Payment program, related party $ 550,100.00 1,222,444
Total $ 1,837,101.10 4,082,447
The shares of Common Stock issued pursuant to the Related Party Debt Conversion were issued in reliance upon exemptions from registration requirements pursuant to Section 4(a)(2) under the Securities Act of 1933, as amended, and Regulation D promulgated thereunder, and pursuant to applicable state securities laws and regulations, in that the sale and purchase of such securities will not involve any public offering, the recipients of the shares are each either an “accredited investor” as that term is defined under Rule 501 of Regulation D, or the Company has furnished or will, a reasonable prior to sale furnish, to each investor the information specified by paragraph (b)(2) of Rule 501 of Regulation D. All Related Party Debt Conversion shares were issued on February 22, 2022.
On January 25, 2022, Daybreak obtained the approval of a majority of the outstanding shares of the Company’s Series A Preferred shares to convert each Series A Preferred share to three (3) shares of Daybreak’s Common Stock, par value $0.001. The accrued and unpaid dividends of $2,449,979 with respect to the Series A Preferred Stock (the “Series A Conversion”) were converted into 1,100,000 shares of Common Stock. The Series A Conversion was undertaken in connection with the Equity Exchange Agreement (the “Exchange Agreement”) dated as of October 20, 2021 by and between Daybreak, Reabold, and Gaelic, pursuant to which the parties propose for (i) Gaelic to irrevocably assign and transfer all of its ownership interests in Reabold to Daybreak, and (ii) Daybreak to issue approximately 160,964,489 shares of its Common Stock to Gaelic (the “Daybreak Shares”), which, resulted in Reabold becoming a wholly-owned subsidiary of Daybreak and Gaelic becoming the owner of Daybreak Shares (the foregoing transaction, the “Equity Exchange”).
The Series A Conversion was voted on by holders of the Series A Preferred shares as of November 30, 2021, to be effective as of that date. Pursuant to the Series A Conversion, a total of 709,568 Series A Preferred shares of the Company plus accrued and unpaid dividends converted into a total of 3,228,704 shares of Daybreak Common Stock. The shares of Common Stock issued pursuant to the Series A Conversion were issued in reliance upon exemptions pursuant to Section 3(a)(9) under the Securities Act of 1933, as amended, and pursuant to applicable state securities laws and regulations, in that the shares of common were issued by the Company to its existing security holders in exchange for Series A preferred stock, and no commission or other remuneration was paid or given directly or indirectly for soliciting such exchange. All Series A Conversion shares and related dividend conversion shares were issued on February 21, 2022.
On March 22, 2022, a 12% Subordinated Note holder that was not a related party converted a $25,000 Note plus accrued interest of $10,520 to Daybreak Common Stock shares. A total of 78,934 shares were issued at a conversion rate of $0.45 per share of Common Stock. The shares of Common Stock were issued in reliance upon exemptions from registration requirements pursuant to Section 4(a)(2) under the Securities Act of 1933, as amended, and Regulation D promulgated thereunder, and pursuant to applicable state securities laws and regulations, in that the sale and purchase of such securities will not involve any public offering. The recipient of the shares is an “accredited investor” as that term is defined under Rule 501 of Regulation D.
On May 25, 2022, the Company finalized the above-mentioned acquisition of Reabold through the Equity Exchange, and there were 160,964,489 shares of the Company’s common stock valued at $6,599,544 issued for the Reabold crude oil and natural gas properties.
On May 26, 2022, Daybreak completed the sale of 125,000,000 shares of its Common Stock, par value $0.001, to Portillion for a purchase price of $0.02 per share, or $2,500,000 in the aggregate, pursuant to the Subscription Agreement dated May 5, 2022 (the “Capital Raise”). In connection with the closing of the Capital Raise, Daybreak also paid Portillion (1) an incentive fee equal to 20% of the subscription amount, payable 17.5% in cash ($437,000) and 2.5% in additional shares of Common Stock (3,125,000 shares); and (2) an equity exchange fee equal to 3% of the subscription amount. The Common Stock was issued pursuant to the exemption from registration promulgated under Regulation S of the Securities Act of 1933, as amended.
The sale and purchase of the shares did not involve any public offering, the offer and sale of the shares took place outside the United States, Daybreak reasonably believes the purchaser to be an “accredited investor” as that term is defined under Rule 501 of Regulation D, the purchaser had access to information about Daybreak and its investment, the purchaser took the securities for investment and not resale, and Daybreak took appropriate measures to restrict the transfer of the securities. The source of funds of Portillion’s purchase of shares of the Company was CitiBank. Daybreak is not aware of any arrangements, including any pledge by any person of securities of the Company or any of its parents, the operation of which may at a subsequent date result in another change in control of the Company.
On May 5, 2022, Kamran Sattar, the purchaser of a convertible promissory note in the amount of $200,000 (the “Convertible Note”) issued by the Company as of February 15, 2022 notified the Company that he had elected to convert the Convertible Note. The Convertible Note converted by its terms at a price per share of $0.0085, and the total principal balance of the note plus accrued interest, totaling $236,000, converted into 27,764,706 shares of Common Stock, par value, $0.001, of the Company. Mr. Sattar has sole voting power and sole dispositive power over these shares.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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:
Twelve Months Ended
February 28, 2023
February 28, 2022
Percentage Change
Average twelve-month WTI crude oil price
$ 93.13
$ 73.31
27.0%
Average twelve month realized crude oil sales price (Bbl)
$ 89.59
$ 70.75
26.6%
For the twelve months ended February 28, 2023, the average WTI price was $93.13 and our average realized crude oil sale price was $89.59, representing a discount of $3.54 per barrel or 3.8% lower than the average WTI price. In comparison, for the twelve months ended February 28, 2022, the average WTI price was $73.31 and our average realized sale price was $70.75 representing a discount of $2.56 per barrel or 3.5% lower than the average WTI price. Historically, the sale price we receive for our East Slopes heavy crude oil has been less than the quoted NYMEX WTI price because of the lower API gravity of our East Slopes crude oil in comparison to quoted WTI crude oil API gravity.
California Crude Oil Revenue and Production
Crude oil revenue in California for the twelve months ended February 28, 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:
Twelve Months Ended
February 28, 2023
Twelve Months Ended
February 28, 2022
Project Revenue Percentage Revenue Percentage
East Slopes project - crude oil sales $ 728,439 47.5 % $ 680,107 100.0 %
Reabold project - crude oil sales 804,821 52.5 % - -
Crude oil Totals $ 1,533,260 100.0 % $ 680,107 100.0 %
*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.
Twelve Months Ended
February 28, 2023 February 28, 2022 Percentage Change
Average twelve month Henry Hub natural gas price (Mcf) $ 6.35 $ - 100 %
Average twelve month realized natural gas sales price (Mcf) $ 20.94 $ - 100 %
For the twelve months ended February 28, 2023 the average price per Mcf (1,000 cubic feet) that we received was $20.94 while the average monthly price per Mcf for spot Henry Hub prices was $6.35 for the same twelve month period. The large disparity in the two prices over the twelve-month period was largely due to the price per Mcf we received during the three months ended February 28, 2023 when the average price we received per Mcf was $29.79 and the same three month average price per Mcf for Henry Hub prices was $3.86. In January of 2023 the average price per Mcf we received in California was $58.03 while the monthly average Henry Hub price was $3.39 per Mcf.
California Natural Gas Revenue and Production
We only have natural gas production from our Reabold subsidiary wells that are located in Contra Costa County in California. For the twelve months ended February 28, 2023, natural gas revenue 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:
Twelve Months Ended
February 28, 2023
Twelve Months Ended
February 28, 2022
Project Revenue Percentage Revenue Percentage
East Slopes project - crude oil sales $ 728,439 45.1 % $ 680,107 100.0 %
Reabold project - crude oil sales 804,821 49.9 % - -
Reabold project - natural gas sales 80,026 5.0 % - -
Total California crude oil and natural gas sales revenue $ 1,613,286 100.0 % $ 680,107 100.0 %
*Our average realized sale price on a BOE basis for the twelve months ended February 28, 2023 was $90.88 in comparison to $70.75 for the twelve months ended February 28, 2022, representing an increase of $20.13 or 28.5% per barrel. We only have natural gas production from our project in Contra Costa County. Prior to the acquisition of our Reabold subsidiary in May of 2022, we had no natural gas production.
Of the $933,179 or 137.2% increase in revenue for twelve months ended February 28, 2023 approximately $739,633 or 79.3% can be attributed to the increase in sales volume mainly due to our Reabold subsidiary acquisition.
Operating Expenses
Total operating expenses increased $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:
Twelve Months Ended
February 28, 2023
Twelve Months Ended
February 28, 2022
Expenses Percentage BOE
Basis
Expenses Percentage BOE
Basis
Production expenses $ 1,103,825 28.3 %
$ 231,275 24.6 %
Exploration and drilling expenses - - %
56,213 6.0 %
Depreciation, depletion, amortization (“DD&A”) 504,118 12.9 %
49,590 5.3 %
Impairment expense 711,873 18.3 %
Transaction (acquisition) expenses 573,472 14.7 %
- -
General and administrative (“G&A”) expenses 1,004,011 25.8 %
603,808 64.1 %
Total operating expenses $ 3,897,299 100.0 % $ 219.55 $ 940,886 100.0 % $ 97.88
Production expenses include expenses associated with the production of crude oil and natural gas. These expenses include contract pumper, electricity, road maintenance, control of well insurance, property taxes, well maintenance and workover expenses; and, relate directly to the number of wells that are on production. For the twelve months ended February 28, 2023, these expenses increased $872,550, or 377.3% to $1,103,825 in comparison to $231,275 for the twelve months ended February 28, 2022. At February 28, 2023, we had 24 wells on production in comparison to 20 wells on production for the twelve months ended February 28, 2022. The increase in producing wells was due to the acquisition of our Reabold subsidiary that occurred in May of 2022. The increase in production expenses for the twelve months ended February 28, 2023, was primarily due to the replacement and upgrading of pumps in seven wells of the East Slopes project for $56,549 and the expenses associated with salt water disposal of $426,838 from the Reabold properties. A salt water disposal well is currently being permitted which, when put into operation is expected to significantly lower operating costs of the Reabold project. Production expenses on a BOE basis for the twelve months ended February 28, 2023 and February 28, 2022 were $62.18 and $24.06, respectively. Production expenses represented 28.3% and 24.6% of total operating expenses for the twelve months ended February 28, 2023 and February 28, 2022, respectively.
Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance, plugging and abandonment (“P&A”) expenses and dry hole expenses. These expenses decreased $56,130 to $-0- for the twelve months ended February 28, 2023 in comparison to $56,130 for the twelve months ended February 28, 2022. Exploration and drilling expenses represented -0-% and 6.0% of total operating expenses for the twelve months ended February 28, 2023 and February 28, 2022, respectively.
Depreciation, Depletion, Amortization (“DD&A”) expense relates to equipment, proven reserves and property costs, and is another component of operating expenses. These expenses increased $454,528 or 916.6% to $504,118 for the twelve months ended February 28, 2023 in comparison to $49,590 for the twelve months ended February 28, 2022. The primary reason for the increase in DD&A expense was due to the recognition of the Reabold subsidiary wells and equipment and their projected production life. On a BOE basis, DD&A expense in California for the twelve months ended February 28, 2023, and February 28, 2022 was $28.40 and $5.16, respectively. DD&A expenses represented 12.9% and 5.3% of total operating expenses for the twelve months ended February 28, 2023, and February 28, 2022, respectively.
Impairment expense of $711,873 for the twelve months ended February 28, 2023 is due to the write down of proven undeveloped reserves in our Reabold subsidiary project. Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years. Impairment expense represented 18.3% and 0% of total operating expenses for the twelve months ended February 28, 2023 and February 28, 2022, respectively.
For the twelve months ended February 28, 2023, we incurred transaction expenses of $573,472 related to the acquisition of funding and to acquire the Reabold crude oil and natural gas properties located in central California. For the twelve months ended February 28, 2022, we did not incur any related expenses. Transaction expenses represented 14.7% and 0.0% of total operating expenses for the twelve months ended February 28, 2023 and February 28, 2022, respectively.
General and administrative (“G&A”) expenses include the salaries of five employees, including management. Other items included in our G&A expenses are legal and accounting expenses, investor relations fees, travel expenses, insurance expenses and other administrative expenses necessary for an operation of crude oil and natural gas properties as well as for the management of a public company. For the twelve months ended February 28, 2023, G&A expenses increased $400,203 or 66.3% to $1,004,011 in comparison to $603,808 for the twelve months ended February 28, 2022. The primary reasons for the increase in G&A expense are related to the expenses of both the special shareholders and the annual shareholders meetings, in the amount of approximately $131,394 in aggregate, approximately $120,000 in legal and accounting fees related to the acquisition and an increase in SEC reporting expense of approximately $53,800 during the twelve months ended February 28, 2023. We are continuing a program of controlling our G&A costs wherever possible. G&A expenses represented 25.8% and 64.1% of total operating expenses for the twelve months ended February 28, 2023 and February 28, 2022, respectively.
Interest expense, net for the twelve months ended February 28, 23 decreased $74,861 or 34.0% to $145,224 in comparison to $220,085 for the twelve months ended February 28, 2022.
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 2nd Draw loan.
Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially quarter-to-quarter and year-to-year. Our revenues are dependent upon both hydrocarbon production levels and the price we receive for hydrocarbon sales. Production costs will fluctuate according to the number and percentage ownership of producing wells the period of time the wells have been producing, as well as the amount of revenues being generated by each well. Exploration and drilling expenses will be dependent upon the amount of capital that we have to invest in future development projects, as well as the success or failure of such projects. Likewise, the amount of DD&A expense will depend upon the factors cited above, plus the size of our proven reserve base and the market price of energy products. G&A expenses will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company. An on-going goal of the Company is to improve cash flow to cover the current level of G&A expenses; to fund our development drilling in California; and future drilling programs in other geographic locations.
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:
February 28, 2023 February 28, 2022 Increase
(Decrease)
Percentage
Change
Cash $ 299,410 $ 139,573 $ 159,837 114.5 %
Restricted cash $ 275,000 $ - $ 275,000 100.0 %
Current assets $ 1,153,963 $ 416,651 $ 737,312 177.0 %
Total assets $ 7,715,392 $ 975,704 $ 6,739,688 690.8 %
Current liabilities $ (3,254,246 ) $ (3,404,735 ) $ (150,489 ) (4.4 %)
Total liabilities $ (4,505,143 ) $ (4,322,908 ) $ 182,235 4.2 %
Working capital deficit $ (2,100,283 ) $ (2,988,084 ) $ (887,801 ) (29.7 %)
Our working capital deficit decreased approximately $0.89 million or 29.7% from a deficit of approximately $2.99 million at February 28, 2022 to a deficit of approximately $2.1 million at February 28, 2023. The decrease in the working capital deficit was primarily due to the proceeds we received in connection with the sale of Common Stock and the acquisition of our Reabold California, LLC subsidiary current assets. We anticipate an increase in our cash flow will occur when we are able to return to our planned drilling program that will result in an increase in the number of successful wells on production.
Our business is capital intensive. Our ability to grow is dependent upon favorably obtaining outside capital and generating cash flows from operating activities necessary to fund our investment activities. There is no assurance that we will be able to achieve profitability. Since our future operations will continue to be dependent on successful exploration and development activities and our ability to seek and secure capital from external sources, should we be unable to achieve sustainable profitability this could cause any equity investment in the Company to become worthless.
Major sources of funds in the past for us have included the debt or equity markets. We will have to rely on the capital markets to fund future operations and growth. Our business model is focused on acquiring exploration or development properties as well as existing production. Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of crude oil and natural gas producing properties, which will require us to continue to raise equity or debt capital from outside sources.
Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms. Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself. These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company. The current uncertainty in the credit and capital markets, as well as the instability and volatility in crude oil and natural gas prices has restricted our ability to obtain needed capital.
The Company’s financial statements for the twelve months ended February 28, 2023 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. We have incurred a cumulative net loss since entering the crude oil and natural gas exploration industry in 2005. As of February 28, 2023, we have an accumulated deficit of approximately $31.96 million and a working capital deficit of approximately $2.1 million which raises substantial doubt about our ability to continue as a going concern.
We will need to seek additional financing for our planned exploration and development activities in California. We could obtain financing through one or more various methods, including issuing debt securities, equity securities, or bank debt, or combinations of these instruments, which could result in dilution to existing security holders and increased debt and leverage. No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all. Sales of interests in our assets may be another source of cash flow.
Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.
Accounts Payable - Related Parties
In California at the East Slopes Project, two of the vendors that the Company uses for services are partially owned by a related party, the Company’s Chief Operating Officer. The Company’s Chief Operating Officer is 50% owner in both Great Earth Power (“Great Earth”) and ABPlus Net Holdings (“ABPlus”). Great Earth began providing a portion of the solar power electrical service for production operations in July 2020. ABPlus began providing portable tank rentals to the Company as a part of its water treatment and disposal operations in September 2020. The services provided by Great Earth and ABPlus are competitive with other vendors and save the Company significant expense.
For the twelve months ended February 28, 2023, and February 28, 2022, Great Earth provided services valued at $15,663 and $20,300, respectively. For the twelve months ended February 28, 2023, and February 28, 2022, ABPlus provided services valued at $11,520, respectively. At February 28, 2023 and February 28, 2022, Great Earth was owed $613 and $1,400, respectively. At February 28, 2023 and February 28, 2022, ABPlus was owed $960, respectively. Amounts owed to Great Earth and ABPlus represent a portion of the accounts payable amount presented on the balance sheets.
Cash Flows
Changes in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below:
Twelve Months
Ended
February 28, 2023
Twelve Months
Ended
February 28, 2022
Increase
(Decrease)
Percentage
Change
Net cash (used in) operating activities $ (315,117 ) $ (13,356 ) $ 301,761 2,259.4 %
Net cash (used in) investing activities $ (386,160 ) $ (16,232 ) $ 369,928 2,279.0 %
Net cash provided by financing activities $ 1,136,114 $ 135,633 $ 1,000,481 737.6 %
Cash Flow Used in Operating Activities
Cash flow from operating activities is derived from the production of our crude oil reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. Cash flow used in our operating activities for the twelve months ended February 28, 2023 was $315,117 in comparison to cash flow used in our operating activities of $13,356 for the twelve months ended February 28, 2022. Changes in our cash flow used for operating activities for the twelve months ended February 28, 2023 in comparison to the twelve months ended February 28, 2022 increased $301,761 and were mainly a result of the expense of our annual shareholders meeting and the Reabold subsidiary acquisition. We had increases in our non-cash expenses of $1,266,587, primarily from recognition of impairment of proved undeveloped locations acquired in the Reabold acquisition of $711,873 and an increase in DD&A of $454,498, a decrease in changes in assets of $107,445 that was offset by an increase in changes in liabilities of $569,884 and the increase in our net loss for the year of approximately $2.0 million. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.
Our expenditures in operating activities consist primarily of exploration and drilling expenses, production expenses, geological, geophysical and engineering services and maintenance of existing mineral leases. Our expenses also consist of consulting and professional services, employee compensation, legal, accounting, travel and other G&A expenses that we have incurred in order to manage normal and necessary business activities of a public company in the crude oil exploration and production industry.
Cash Flow Used in Investing Activities
Cash flow from investing activities is derived from changes in oil and gas property balances, fixed asset balances and any lending activities. For the twelve months ended February 28, 2023 we used cash flow of $386,160 in comparison to cash flow used for investing activities of $16,232 for the twelve months ended February 28, 2022. The change in cash flow used in investing activities of $369,928 was primarily related to the Reabold acquisition.
Cash Flow Provided by Financing Activities
Cash flow from financing activities is derived from changes in long-term liability account balances or in equity account balances excluding retained earnings. Cash flow provided by our financing activities was $1,136,114 for the twelve months ended February 28, 2023 in comparison to cash flow provided by our financing activities of $135,633 for the twelve months ended February 28, 2022. For the twelve months ended February 28, 2023, we secured a capital raise of $1,987,500 net of transaction expenses from the sale of 125,000,000 shares of our Common Stock. We also paid off the balance of $808,182 on the line of credit with UBS Bank during the twelve months ended February 28, 2023.
Short-Term and Long-Term Borrowings
Note Payable
In December 2018, the Company was able to settle an outstanding balance owed to one of its third-party vendors. This settlement resulted in a $120,000 note payable being issued to the vendor. Additionally, the Company agreed to issue 2,000,000 shares of the Company’s Common Stock as a part of the settlement agreement. Based on the closing price of the Company’s Common Stock on the date of the settlement agreement, the value of the Common Stock transaction was determined to be $6,000. The Common Stock shares were issued during the twelve months ended February 29, 2020. The note had a maturity date of January 1, 2022 and bears an interest rate of 10% rate per annum. The note principal has not been paid and the Company is considered to be in default. There is no default interest rate associated with the note. Interest is accrued monthly and is payable on January 1st 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:
February 28, 2023 February 28, 2022
Note payable -related party, current portion $ 9,065 $ 8,829
Unamortized debt issuance expenses (728 ) (729 )
Note payable - related party, current portion, net $ 8,337 $ 8,100
Note payable -related party long-term balances at February 28, 2023 and February 28, 2022 are set forth in the table below:
February 28, 2023 February 28, 2022
Note payable - related party, non-current $ 127,645 $ 136,710
Unamortized debt issuance expenses (8,622 ) (9,350 )
Note payable - related party, non-current, net $ 119,023 $ 127,360
Future estimated payments on the outstanding note payable - related party are set forth in the table below:
Twelve month periods ending February 28/29,
9,065
9,309
9,558
9,815
10,078
Thereafter
88,885
Total
$ 136,710
Short-term Convertible Note Payable
During the twelve months ended February 28, 2022, the Company executed a convertible promissory note with a third party for $200,000. The interest rate was 18% per annum and was payable in kind (“PIK”) solely by additional shares of the Company’s Common Stock. Regardless of when the conversion occurred, a full 12 months of interest would be payable upon conversion. On May 5, 2022, the Company received notice of conversion of the promissory note. The face amount of the note and $36,000 in interest were converted at a rate of $0.0085 per share into 27,764,706 share of the Company’s Common Stock during the twelve months ended February 28, 2023.
12% Subordinated Notes
The Company’s 12% Subordinated Notes (the “Notes”) issued pursuant to a January 2010 private placement offering to accredited investors, had a balance at February 28, 2023 and February 28, 2022 of $290,000 and $315,000, respectively. The original maturity date of January 29, 2015 had been extended to January 29, 2017 and then was extended to January 29, 2019. Interest accrues at 12% per annum, payable semi-annually on January 29th and July 29th.
The Company has informed the remaining Note holders that the payment of principal and interest will be late and is subject to future financing being completed and the Company’s cash flow. The Notes principal of $290,000 has not been paid and interest continues to accrue on the unpaid principal balance. The accrued interest on the 12% Notes at February 28, 2023 and February 28, 2022 was $159,508 and $135,229, respectively. The terms of the Notes, state that should the Board of Directors decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s Common Stock at a conversion rate equal to 75% of the average closing price of the Company’s Common Stock over the 20 consecutive trading days preceding December 31, 2018.
During the twelve months ended February 28, 2023, one 12% Note holder chose to convert the principal balance and accrued interest into the Company’s Common Stock. The $25,000 Note and accrued interest of $10,520 were converted at a rate of approximately $0.45 for every dollar of principal and interest resulting in 78,934 shares of Common Stock being issued.
12% Note balances at February 28, 2023 and February 28, 2022 are set forth in the table below:
February 28, 2023 February 28, 2022
12% Subordinated notes - third party $ 290,000 $ 315,000
12% subordinated notes - related party - -
12% Subordinated notes balance $ 290,000 $ 315,000
Line of Credit
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:
February 28, 2023 February 28, 2022
Estimated payments of production revenue payable $ 913,395 $ 941,259
Less: unamortized discount (40,114 ) (124,134 )
873,281 817,125
Less: current portion (56,915 ) (78,877 )
Net production revenue payable - long term $ 816,366 $ 738,248
Encumbrances
On October 17, 2018, a working interest partner in California filed a UCC financing statement in regards to payable amounts owed to the partner by the Company.
Capital Commitments
Daybreak has ongoing capital commitments to develop certain oil and gas leases pursuant to their underlying terms. Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself. These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company. The current uncertainty in the credit and capital markets, and the economic downturn, may restrict our ability to obtain needed capital.
Leases
The Company formally leased approximately 988 rentable square feet of office space from an unaffiliated third party for our corporate office located in Spokane Valley, Washington. This office was closed in March of 2023 when the corporate office was consolidated with our Friendswood, Texas regional operations office. We currently lease approximately 416 and 695 rentable square feet from unaffiliated third parties for our new corporate office in Friendswood, Texas and storage and auxiliary office space in Wallace, Idaho, respectively. The lease in Friendswood is a 12-month lease that expired in October 2023 and was subsequently renewed until October 31, 2024, and as such is considered a short-term lease. The Company has elected to not apply the recognition requirements of ASC 842 to this short-term lease. The Wallace lease is currently on a month-to-month basis. The Company’s lease agreements do not contain any residual value guarantees, restrictive covenants or variable lease payments. The Company has not entered into any financing leases.
Rent expense for the twelve months ended February 28, 2023, and February 28, 2022 was $23,889 and $23,489, respectively.
Crude Oil and Natural Gas Reserves
Daybreak’s total net proved developed crude oil and natural gas reserves on a per barrel of oil equivalent (“BOE”) basis increased by 276,066 BOE, or 234.3%, to 393,910 BOE at February 28, 2023 compared to 117,844 BOE at February 28, 2022. The primary reason for the increase in developed reserves was the acquisition of our Reabold subsidiary in May of 2022. Of our proved developed reserves at February 28, 2023, the Reabold subsidiary represented 277,891 BOE or 71% of our total proved developed reserves. The East Slopes project represented 116,019 BOE or 29% of our proved developed reserves. Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years. These proved developed reserves are all located in our California East Slopes and Reabold subsidiary projects.
The East Slopes project reserves and the Reabold project reserves were fully engineered by PGH Petroleum and Environmental Engineers, LLC of Austin, Texas and PETROtech Resources off Bakersfield, California, respectively. Both reserve reports were prepared in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. For further information on our reserve report, refer to Exhibit 99.2 of this Annual Report on Form 10-K.
Changes in Financial Condition
During the year ended February 28, 2023, we received crude oil and natural gas sales revenue from 20 wells in our East Slopes project in Kern County and eight wells in our Reabold subsidiary in Monterey and Contra Costa Counties all located in California. For the twelve months ended February 28, 2023, and February 28, 2022, crude oil and natural gas sales revenue from California was $1,613,286 and $680,107, respectively. Of the $933,179 increase in revenue during the twelve months ended February 28, 2022, $193,546 or 20.7% can be attributed to the increase in our average realized crude oil sales price. The increase in sales volume of 8,138 Bbls BOE accounted for $739,633 or 79.3% of the increase in revenue. For the twelve months ended February 28, 2023, and February 28, 2022, we had an operating loss of $2,284,013 and $260,779, respectively. Our commitment to improving corporate profitability remains unchanged.
Our balance sheet at February 28, 2023 reflects total assets of approximately $7.7 million, an increase of approximately $6.7 million in comparison to approximately $0.98 million at February 28, 2022. This increase of approximately $6.7 million in total assets was largely due to the acquisition of our Reabold subsidiary in May of 2022. Our cash balance increased by approximately $160,000.
At February 28, 2023, total liabilities were approximately $4.5 million, an increase of approximately $0.2 million in comparison to approximately $4.3 million at February 28, 2022. This increase was primarily due to the recognition of the ARO liability associated with the crude oil and natural gas wells acquired in the Reabold acquisition.
Common Stock shares issued and outstanding at February 28, 2023 and February 28, 2022 were 384,734,902 and 67,802,273, respectively. The increase in Common Stock shares of 316,932,629 is directly related to either the acquisition of our Reabold subsidiary or the issuance of Common Stock shares for financing and a share issuance adjustment of 500 shares.
With the filing of our Second Amended and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, the Company no longer has any preferred stock shares. We only have one class of stock and that is Common Stock.
As of February 28, 2023, and February 28, 2022, there were 2,100,000 and 893,333 outstanding and exercisable Common Stock warrants. At February 28, 2023, both the outstanding warrants and the exercisable warrants had a weighted average exercise price of $0.01. All outstanding and exercisable warrants expired on January 2, 2024.
Accumulated Deficit
Our financial statements for the twelve months ended February 28, 2023, and February 28, 2022 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. Our financial statements show that the Company has incurred significant operating losses that raise substantial doubt about our ability to continue as a going concern. The accompanying financial statements do not include any adjustments that might result from this uncertainty.
The increase of approximately $2.9 million in the accumulated deficit from approximately $29.5 million at February 28, 2022 to $31.96 million at February 28, 2023 was primarily due to one-time expenses associated with completing the acquisition of our Reabold subsidiary including holding both an annual meeting and a special shareholders meeting; associated public company filing expenses; impairment of certain crude oil and natural gas assets; along with an increase in the lease operating expenses related to disposal of the produced water from the Reabold wells.
Cash Balance
We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations, investments and capital resource funding. Our cash balances were $299,410 and $139,573 at February 28, 2023 and February 28, 2022, respectively. The Company has restricted cash in the amount of $275,000 relating to cash used to secure operator bonds for our crude oil and natural gas wells.
Crude oil and natural gas revenues
Crude oil and natural gas revenues increased $933,179 or 137.2% to $1,613,286 for the twelve months ended February 28, 2023, in comparison to $680,107 for the twelve months ended February 28, 2022. Of the $933,179 increase in revenue during the twelve months ended February 28, 2023, $739,633 or 79.3% can be attributed to the increase in crude oil and natural gas sales volume primarily due to the acquisition of our Reabold subsidiary.
Operating Expenses
Operating expenses for the twelve months ended February 28, 2023 increased approximately $3.0 million or 314.2% to approximately $3.9 million in comparison to approximately $940,886 for the year ended February 28, 2022. This increase was primarily due to one-time expenses associated with completing the acquisition of our Reabold subsidiary including holding both an annual meeting and a special shareholders meeting; associated public company filing expenses; impairment of certain crude oil and natural gas assets; along with an increase in the lease operating expenses related to disposal of the produced water from the Reabold wells.
Operating Loss
For the twelve months ended February 28, 2023, and February 28, 2022, we reported operating losses of approximately $2.3 million and $260,779, respectively. The increase in the operating loss for the twelve months ended February 28, 2023, of approximately $2.0 million was primary due to one-time expenses associated with completing the acquisition of our Reabold subsidiary including holding both an annual meeting and a special shareholders meeting; associated public company filing expenses; impairment of certain crude oil and natural gas assets; along with an increase in the lease operating expenses related to disposal of the produced water from the Reabold wells.
Net Loss
Since entering the crude oil and natural gas exploration industry, we have incurred net losses with periodic negative cash flow and have depended on external financing and the sale of crude oil and natural gas assets to sustain our operations. For the twelve months ended February 28, 2023 we reported a net loss of approximately $2.4 million in comparison to net loss of $398,450 for the twelve months ended February 28, 2022.
Management Plans to Continue as a Going Concern
We continue to implement plans to enhance our ability to continue as a going concern. Daybreak currently has a net revenue interest in 20 producing crude oil wells in Kern County, California (the “East Slopes” project) and a 10 well crude oil and natural gas project in Monterey and Contra Costa Counties, California (the “Reabold”) project). At the Reabold project, five of these wells are currently shut-in awaiting our receiving water disposal permit approvals. The revenue from these wells has created a steady and reliable source of revenue for the Company. Our average working interest in the East Slopes wells is 36.6% and the average net revenue interest is 28.4%. Our average working interest in the Reabold wells is 50.0% and the average net revenue interest is 40.0%.
On May 25, 2022, we finalized the acquisition of Reabold California, LLC (“Reabold”) from a third party for 160,964,489 shares of the Company’s Common Stock valued at $6,599,544 and cash consideration of $263,619. The acquisition of Reabold was approved at a Special Meeting of Shareholders held on May 20, 2022. Approximately 82% or 51,054,229 shares of the Company’s 62,510,204 issued and outstanding shares of the Company’s Common Stock were present or represented by proxy at the meeting. The proposal for the Reabold acquisition was passed with over a 99.6% approval vote.
At the same special meeting of shareholders held on May 20, 2022, approval was granted to Amend and Restate the Company’s Articles of Incorporation. This allowed for the increase in the number of authorized Common Stock shares of the Company from 200,000,000 shares to 500,000,000 shares. The increase in Common Stock shares gave the Company enough authorized Common Stock shares to complete the transaction for the Reabold project. Also, all the preferred stock classification was eliminated.
In conjunction with the Company’s efforts to acquire Reabold, and as a condition of closing the acquisition, the Company was able to secure a capital raise of $2,500,000 through the issuance of shares of the Company’s Common Stock. The commitment for that capital raise was executed on May 5, 2022, and subsequently 128,125,000 shares were issued of which 3,125,000 were an incentive to the investor.
We anticipate revenues will continue to increase as we participate in the drilling of more wells in both the East Slopes and Reabold projects in California. Our sources of funds in the past have included the debt or equity markets and the sale of assets. While we have experienced periodic revenue growth, which has resulted in positive cash flow from its crude oil and natural gas properties, we have not yet established a positive cash flow on a company-wide basis. It will be necessary for us to obtain additional funding from the private or public debt or equity markets in the future. However, we cannot offer any assurance that our efforts will be successful in executing the aforementioned plans to continue as a going concern. Our financial statements as of February 28, 2023, and February 28, 2022 do not include any adjustments that might result from the inability to implement or execute our plans to improve our ability to continue as a going concern.
Off-Balance Sheet Arrangements
As of February 28, 2023, we did not have any relationships with unconsolidated entities or financial partners, such as entities often referred to as structured finance or special purpose entities, which have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.
Commitments and Contingencies
Various lawsuits, claims, threatened legal actions, and other contingencies arise in the ordinary course of our business activities. In our opinion, the disposition of any such matters is not expected, individually or in the aggregate, to have a material adverse effect on our results of operations, financial condition or cash flows. However, the results of legal actions cannot be predicted with certainty. Therefore, it is possible that our results of operations, financial condition or cash flows could be materially adversely affected in any particular period by the unfavorable resolution of one or more legal actions.
We, as an owner or lessee and operator of oil and gas properties, are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, we may be directed to suspend or cease operations in the affected area. We maintain insurance coverage that is customary in the industry, although we are not fully insured against all environmental risks.
Sunflower Alliance v. California Department of Conservation, Geologic Energy Management Division. This case challenges the state agency’s compliance with the California Environmental Quality Act (CEQA) with respect to the PAL Reabold 072-00-0001 Project, for wastewater injection into an existing well. The Petition was filed on December 29, 2021 in the Alameda County Superior Court. The Petitioner seeks an order setting aside the state agency’s approval of a wastewater injection permit; damages are not sought in the lawsuit. On February 22, 2022, Real Party in Interest Reabold California, LLC filed a motion to transfer the case to the Contra Costa County Superior Court. On March 22, 2022, the Alameda County Superior Court ordered the case transferred to the Contra Costa County Superior Court. On August 15, 2022, the Contra Costa County Superior Court provided notice that the transfer has been completed and the case filed in that court. On December 22, 2022, the Superior Court issued an order finding CEQA deficiencies, and directing the state agency to rescind its approval of the project. On September 7, 2023, an appeal of the Superior Court order was filed in the California Court of Appeal, First Appellate District, Division 5. The California Attorney General is defending the state agency, which disputes Petitioner’s claims. At this time, it is unclear when the litigation will be resolved. If successful, the lawsuit would prevent Reabold from injecting wastewater into an existing well until any CEQA deficiencies are addressed.
The Company is not aware of any environmental claims existing as of January 23, 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.
Summary of Significant Accounting Policies and Estimates
Significant accounting policies are policies that are both most important to the portrayal of the Company’s financial condition and results, and that require management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain. Management’s discussion and analysis of our financial condition and results of operations are based on our financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Accounting
estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.
On an ongoing basis, we evaluate our estimates, including those related to revenue recognition, bad debts, cancellation costs associated with long term commitments, investments, intangible assets, assets subject to disposal, income taxes, service contracts, contingencies and litigation. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making estimates and judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Estimates, by their nature, are based on judgment and available information. These judgments and uncertainties do affect the application of these significant accounting policies. There is a strong likelihood that materially different amounts could be reported under different conditions or using different assumptions. Therefore, actual results could differ from those estimates and could have a material impact on our financial statements, and it is possible that such changes could occur in the near term.
Proved Crude Oil and Natural Gas Reserves
Our estimates of proved and proved developed reserves are a major component of our depletion calculation. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. Proved reserves are defined by the SEC as those quantities of crude oil and natural gas which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserve estimates if the extraction is by means not involving a well.
Although our external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in crude oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.
While the estimates of our proved reserves at February 28, 2023 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could differ materially from our actual results.
Successful Efforts Accounting Method
We use the successful efforts method of accounting for natural gas and oil producing activities as opposed to the alternate acceptable full cost method. We believe that net assets and net income are more conservatively measured under the successful efforts method of accounting than under the full cost method, particularly during periods of active exploration. Costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred. All exploratory dry holes and geological and geophysical costs are charged against earnings during the periods they occur. Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred. The geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. Costs to operate and maintain wells and field equipment are expensed as incurred.
Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on proved reserves. Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their proved developed reserves. Support equipment and other property and equipment are depreciated over their estimated useful lives.
Pursuant to Financial Accounting Standards Board Codification (“ASC”) Topic 360, “Property, Plant and Equipment,” we review proved oil and natural gas properties and other long-lived assets for impairment. These reviews are predicated by events and circumstances, such as downward revision of the reserve estimates or commodity prices that indicate a decline in the recoverability of the carrying value of such properties. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amounts of the properties are reduced to their estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production, future capital expenditures and a risk-adjusted discount rate. The charge is included in DD&A.
Unproved crude oil and natural gas properties that are individually significant are also periodically assessed for impairment of value. For the twelve months ended February 28, 2022, our unproved properties in Michigan and the balance of $55,978 was written off to exploration expense. An impairment loss for unproved crude oil and natural gas properties is recognized at the time of impairment by providing an impairment allowance.
On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income. Deposits and advances for services expected to be provided for exploration and development or for the acquisition of crude oil and natural gas properties are classified as long-term other assets.
Revenue Recognition
The Company recognizes revenue under ASC 606, Revenue from Contracts with Customers (“Topic 606”). Under Topic 606, revenue is generally recognized upon delivery of our produced crude oil and natural gas volumes to our customers. Our customer sales contracts include crude oil sales from both the East Slopes and Reabold projects and natural gas sales from some of the Reabold project. Both of these projects are located in California. Each unit of commodity product (crude oil barrel or natural gas MMBTU) represents a separate performance obligation which is sold at variable prices, determinable on a monthly basis. The pricing provisions of our crude oil and natural gas contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, product quality and prevailing supply and demand conditions in the geographic areas in which we operate. We allocate the transaction price to each performance obligation and recognize revenue upon delivery of the commodity product when the customer obtains control. Control of our produced crude oil volumes passes to our customers when the oil is measured by a trucking oil ticket. The Company has no control over the crude oil after this point and the measurement at this point dictates the amount on which the customer's payment is based. Control of our produced natural gas volumes passes to our customers when the natural gas is measured at the purchaser’s gas line meter. The Company has no control over the natural gas after this point and the measurement at this point dictates the amount on which the customer’s payment is based. Our crude oil and natural gas revenue streams include volumes burdened by royalty and other joint owner working interests. Our revenues are recorded and presented on our financial statements net of the royalty and other joint owner working interests. Our revenue stream does not include any payments for services or ancillary items other than for the sale of crude oil and natural gas. We record revenue in the month our crude oil and natural gas production is delivered to the purchaser.
Suspended Well Costs
We account for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities - Oil and Gas” (“ASC 932”). ASC 932 states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the economic and operating feasibility of the well. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management's evaluation of capitalized exploratory well costs.
In addition, ASC 932 requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year, designating the number of wells the aging is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation.
Share Based Payments
Share based awards are accounted for under FASB Topic ASC 718, “Compensation-Stock Compensation” (“ASC 718”). ASC 718 requires compensation costs for all share-based payments granted to be based on the grant date fair value. The value of the portion of the award that is ultimately expected to vest is recognized as expense ratably over the requisite service periods.
See Note 3 - Summary of Significant Accounting Policies in the Company's financial statements for a full discussion of our significant accounting policies.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As a smaller reporting company, we are not required to provide the information otherwise required by this Item.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of
Daybreak Oil and Gas, Inc.
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Daybreak Oil and Gas, Inc. (the “Company”) as of February 28, 2023 and February 28, 2022, and the related statements of operations, changes in stockholders’ equity (deficit), and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of February 28, 2023 and February 28, 2022, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Going Concern Matter
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency that raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
Critical audit matters, are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.
/s/ MaloneBailey, LLP
www.malonebailey.com
We have served as the Company's auditor since 2006.
Houston, Texas
January 23,
DAYBREAK OIL AND GAS, INC.
Balance Sheets
As of February 28, 2023 and February 28, 2023
As of February 28,
As of February 28,
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 299,410 $ 139,573
Restricted cash 275,000 -
Accounts receivable:
Crude oil sales 131,510 117,727
Joint interest participants 353,009 85,339
Prepaid expenses and other current assets 95,034 74,012
Total current assets 1,153,963 416,651
OIL AND GAS PROPERTIES, successful efforts method, net
Proved developed properties 5,126,200 536,032
Prepaid drilling costs 16,452 16,452
Vehicles and Equipment, net 3,416 6,569
Goodwill - crude oil and natural gas properties 1,415,361 -
Total long-term assets 6,561,429 559,053
Total assets $ 7,715,392 $ 975,704
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities $ 2,129,208 $ 1,649,119
Accounts payable - related parties 21,937 49,228
Revenue payable 192,341 -
Accrued interest 185,508 176,229
Accrued expenses 250,000 -
Note payable 120,000 120,000
Note payable - related party, current, net of unamortized discount of $728 and $729, respectively 8,337 8,100
Convertible Note payable, related party - 200,000
12% Note payable 290,000 315,000
Line of credit - 808,182
Production revenue payable, current, net of unamortized discount 56,915 78,877
Total current liabilities 3,254,246 3,404,735
LONG TERM LIABILITIES:
Note payable - related party, net of current portion and net of unamortized discount of $8,620 and $9,350, respectively 119,023 127,360
Production revenue payable, net of current portion and net of unamortized discount 816,366 738,248
Asset retirement obligation 315,509 52,565
Total long-term liabilities 1,250,898 918,173
Total liabilities 4,505,144 4,322,908
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY (DEFICIT):
Common Stock- 500,000,000 shares authorized; $0.001 par value, 384,734,902 and 67,802,273 shares issued and outstanding, respectively 384,734 67,802
Additional paid-in capital 34,785,207 26,115,450
Accumulated deficit (31,959,693 ) (29,530,456 )
Total stockholders’ equity (deficit) 3,210,248 (3,347,204 )
Total liabilities and stockholders’ equity (deficit) $ 7,715,392 $ 975,704
The accompanying notes are an integral part of these financial statements.
DAYBREAK OIL AND GAS, INC.
Statements of Operations
For the Twelve Months Ended February 28, 2023 and February 28, 2022
Twelve Months
Ended
February 28, 2023
Twelve Months
Ended
February 28, 2022
REVENUE:
Crude oil sales $ 1,533,260 $ 680,107
Natural gas sales 80,026 -
Total crude oil and natural gas sales $ 1,613,286 $ 680,107
OPERATING EXPENSES:
Production 1,103,825 231,275
Exploration and drilling - 56,213
Depreciation, depletion and amortization 504,118 49,590
Impairment of crude oil and natural gas properties 711,873 -
Transaction expenses 573,472 -
General and administrative 1,004,011 603,808
Total operating expenses 3,897,299 940,886
OPERATING LOSS (2,284,013 ) (260,779 )
OTHER INCOME (EXPENSE):
Interest expense, net (145,224 ) (220,085 )
Gain on asset disposal - 9,614
Gain on debt forgiveness - SBA paycheck protection program (PPP) loan - 72,800
Total other expenses (145,224 ) (137,671 )
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS $ (2,429,237 ) $ (398,450 )
NET LOSS PER COMMON SHARE
Basic and diluted $ (0.01 ) $ (0.01 )
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic and diluted 312,312,114 61,548,414
Crude Oil Sales
Natural Gas Sales
The accompanying notes are an integral part of these financial statements.
DAYBREAK OIL AND GAS, INC.
Statements of Changes in Stockholders' Equity (Deficit)
For the Twelve Months Ended February 28, 2023 and February 28, 2022
Series A Convertible
Additional
Preferred Stock Common Stock Paid-In Accumulated
Shares Amount Shares Amount Capital Deficit Total
BALANCE, FEBRUARY 28, 2021 709,568 $ 710 60,491,122 $ 60,491 $ 24,250,556 $ (29,428,897 ) $ (5,117,140 )
Issuance of Common Stock for:
Conversion of accrued employee salaries - - 1,397,880 1,398 627,649 52,530 681,577
Conversion of accrued director fees - - 317,708 142,651 - 142,969
Conversion of 12% Note principal and interest - related party - - 1,144,415 1,144 513,842 - 514,986
Conversion of production revenue program principal - related party - - 1,222,444 1,222 548,878 - 550,100
Conversion of Series A preferred stock (709,568 ) (710 ) 2,128,704 2,129 (1,419 ) - -
Conversion of Series A accumulated dividend - - 1,100,000 1,100 28,380 (29,480 ) -
Recognition of warrants for:
Investor relations services - - - - 4,913 - 4,913
Debt forgiveness accrued salary - related party - - - - - 53,125 53,125
Debt forgiveness production revenue program interest - related party - - - - - 232,170 232,170
Settlement of receivables and payables - related party - - - - - (11,454 ) (11,454 )
Net Loss - - - - - (398,450 ) (398,450 )
BALANCE, FEBRUARY 28, 2022 - $ - 67,802,273 $ 67,802 $ 26,115,450 $ (29,530,456 ) $ (3,347,204 )
Issuance of Common Stock for:
Conversion of 12% Note principal and interest - - 78,934 35,441 - 35,520
Conversion of convertible note - - 27,764,706 27,765 208,235 - 236,000
Acquisition of crude oil and natural gas properties - - 160,964,489 160,964 6,438,580 - 6,599,544
Sale of common stock - - 125,000,000 125,000 1,862,500 - 1,987,500
Shares issued for financing fees - - 3,125,000 3,125 125,000 - 128,125
Adjustment to common stock - - (500 ) (1 ) - -
-
Net Loss - - - - - (2,429,237 ) (2,429,237 )
BALANCE, FEBRUARY 28, 2023 - $ - 384,734,902 $ 384,734 $ 34,785,207 $ (31,959,693 ) $ 3,210,248
Common Stock
Additional Paid-In Capital
Accumulated Deficit
Series A Convertible Preferred Stock
The accompanying notes are an integral part of these financial statements.
DAYBREAK OIL AND GAS, INC.
Statements of Cash Flows
For the Twelve Months Ended February 28, 2023 and February 28, 2022
Twelve Months Ended
February 28, 2023 February 28, 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $ (2,429,237 ) $ (398,450 )
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Common stock shares issued as an incentive 128,125 -
Gain on forgiveness of PPP 2nd draw - (72,800 )
Depreciation, depletion and amortization 504,088 49,590
Impairment of proved crude oil properties 711,873 -
Impairment of unproved crude oil properties - 55,978
Amortization of debt discount 56,885 96,703
Warrants issued for investor relations services - 4,913
Changes in assets and liabilities:
Accounts receivable - crude oil and natural gas sales 235,034 (8,734 )
Accounts receivable - joint interest participants (267,670 ) (5,928 )
Prepaid expenses and other current assets (21,022 ) 68,449
Accounts payable and other accrued liabilities 784,819 52,922
Accounts payable - related parties (27,291 ) 64,153
Accrued interest (9,279 ) 79,848
Net cash used in operating activities (315,117 ) (13,356 )
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to crude oil and natural gas properties (417,248 ) (6,772 )
Acquisition of crude oil and natural gas properties 31,088 -
Purchase of fixed asset (used pickup truck) - (9,460 )
Net cash used in investing activities (386,160 ) (16,232 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments to line of credit (808,182 ) (60,000 )
Proceeds from sale of Common Stock 1,987,500 -
Proceeds from convertible note payable - 200,000
Insurance financing repayments (34,375 ) (68,568 )
Payments to note payable - related party (8,829 ) (8,599 )
Proceeds from SBA PPP 2nd draw loan and 1st draw loans, respectively - 72,800
Net cash provided by financing activities 1,136,114 135,633
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 434,837 106,045
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 139,573 33,528
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 574,410 $ 139,573
CASH PAID FOR:
Interest $ 33,431 $ 14,446
Income taxes $ - $ -
The accompanying notes are an integral part of these financial statements.
DAYBREAK OIL AND GAS, INC.
Statements of Cash Flows (continued)
For the Twelve Months Ended February 28, 2023 and February 28, 2022
Twelve Months Ended
February 28, 2023 February 28, 2022
SUPPLEMENTAL CASH FLOW INFORMATION:
Common stock issued for conversion of 12% Subordinated Note $ 35,520 $ -
Common stock issued for conversion of convertible Note $ 236,000 $ -
Common stock issued for acquisition of crude oil and natural gas property $ 6,599,544 $ -
Goodwill from acquisition of O&G properties $ 1,415,361 $ -
ARO asset and liability increase due to acquisition of crude oil and natural gas properties $ 79,622 $ -
ARO asset and liability increase due to changes in estimates $ 159,477 $ 10,929
Non-cash addition to line of credit due to monthly interest $ - $ 27,278
Financing of insurance premiums $ - $ 81,154
Forgiveness of production revenue payable interest $ - $ 232,170
Settlement of accrued employee salaries credited to common stock, APIC and accumulated deficit $ - $ 681,577
Settlement of accrued director fees credited to common stock and APIC $ - $ 142,969
Settlement of 12% Note - related party credited to common stock and APIC $ - $ 514,986
Settlement of production revenue program - related party credited to paid in capital $ - $ 550,100
Settlement of Series A accumulated dividend credited to additional paid in capital $ - $ 28,380
Common stock issued for conversion of Series A preferred stock $ - $ 710
Common stock issued for Series A preferred accumulated dividend $ - $ 1,100
Debt forgiveness of related party accrued gross salary and employer payroll taxes $ - $ 53,125
Settlement of related party receivables and payables $ - $ 11,454
Reclassification of related party accounts payable to accounts payable $ - $ 66,719
The accompanying notes are an integral part of these financial statements.
DAYBREAK OIL AND GAS, INC.
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - ORGANIZATION AND BASIS OF PRESENTATION:
Originally incorporated as Daybreak Uranium, Inc., (“Daybreak Uranium”) on March 11, 1955, under the laws of the State of Washington, Daybreak Uranium was organized to explore for, acquire, and develop mineral properties in the Western United States. In August 1955, the assets of Morning Sun Uranium, Inc. were acquired by Daybreak Uranium. In May 1964, Daybreak Uranium changed its name to Daybreak Mines, Inc. In March 2005, management of the Company decided to enter the crude oil and natural gas exploration, development and production industry. On October 25, 2005, the Company’s shareholders approved a name change from Daybreak Mines, Inc. to Daybreak Oil and Gas, Inc. (referred to herein as “Daybreak” or the “Company”) to better reflect the business of the Company.
All of the Company’s crude oil and natural gas production is sold under contracts that are market-sensitive. Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, crude oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. These factors include the level of global demand for petroleum products, foreign supply of crude oil and natural gas, the establishment of and compliance with production quotas by crude oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic, crude oil disputes between OPEC members; and national or international pandemics like the coronavirus outbreak.
NOTE 2 - GOING CONCERN:
Financial Condition
Daybreak’s financial statements for the twelve months ended February 28, 2023, and February 28, 2022 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. Daybreak has incurred net losses since inception and has accumulated a deficit of approximately $31.96 million and a working capital deficit of approximately $2.1 million, which raises substantial doubt about the Company’s ability to continue as a going concern.
Management Plans to Continue as a Going Concern
The Company continues to implement plans to enhance its ability to continue as a going concern. Daybreak currently has a net revenue interest in 20 producing crude oil wells in Kern County, California (the “East Slopes” project) and a 10 well crude oil and natural gas project in Monterey and Contra Costa Counties, California (the “Reabold” project). At the Reabold project, five of these wells are currently shut-in awaiting our receiving water disposal permit approvals. The revenue from these wells has created a steady and reliable source of revenue. The Company’s average working interest in the East Slopes project is 36.6% and the average net revenue interest is 28.4%. In the Reabold project, the Company has a 50.0% working interest and a net revenue interest of 40%.
On May 25, 2022, the Company finalized the acquisition of Reabold California, LLC (“Reabold”) from a third party for 160,964,489 shares of the Company’s Common Stock valued at $6,599,544 and cash consideration of $263,619. The acquisition of Reabold was approved at a Special Meeting of Shareholders held on May 20, 2022. Approximately 82% or 51,054,229 shares of the Company’s 62,510,204 issued and outstanding shares of the Company’s Common Stock were present or represented by proxy at the meeting. The proposal for the Reabold acquisition was passed with over a 99.6% approval vote.
At the special shareholders meeting held on May 20, 2022, approval was also granted to Amend and Restate the Company’s Articles of Incorporation. This allowed for the increase in the number of authorized Common Stock shares of the Company from 200,000,000 shares to 500,000,000 shares. The increase in Common Stock shares allowed the Company to have enough authorized Common Stock shares to complete the transaction for the Reabold project. Also, all the Preferred stock classification was eliminated.
In conjunction with the Company’s efforts to acquire Reabold, and as a condition of closing the acquisition, the Company was to secure a capital raise of $2,500,000 through the issuance of shares of the Company’s Common Stock. The commitment for that capital raise was executed on May 5, 2022, and subsequently 128,125,000 shares were issued of which 3,125,000 were an incentive to the investor.
The Company anticipates revenue will continue to increase as the Company participates in the drilling of more wells in the East Slopes and Reabold projects in California. Daybreak’s sources of funds in the past have included the debt or equity markets and the sale of assets. While the Company has experienced periodic revenue growth, which has resulted in positive cash flow from its crude oil and natural gas properties, it has not yet established a positive cash flow on a company-wide basis. It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future. However, the Company cannot offer any assurance that it will be successful in executing the aforementioned plans to continue as a going concern.
Daybreak’s financial statements as of February 28, 2023, and February 28, 2022 do not include any adjustments that might result from the inability to implement or execute Daybreak’s plans to improve our ability to continue as a going concern.
NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Use of Estimates and Assumptions
In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions. These estimates and assumptions may affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows:
· The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any impairment of proved properties;
· The valuation of unproved acreage and proved crude oil and natural gas properties to determine the amount of any impairment of crude oil and natural gas properties;
· Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment; and
· Estimates regarding the timing and cost of future abandonment obligations; and,
· Estimates regarding projected cash flows used in determining the production payable discount.
Cash and Cash Equivalents
Cash equivalents include demand deposits with banks and all highly liquid investments with original maturities of three months or less. The Company has in the past maintained balances in financial institutions where deposits may exceed the federally insured deposit limit of $250,000. The Company has not experienced any losses from such accounts and does not believe it is exposed to any significant credit risk on cash.
Restricted Cash
Restricted cash balances include amounts posted with regulatory authorities for reclamation bonds related to the Company’s crude oil and natural gas operations in California.
Accounts Receivable
The Company routinely assesses the recoverability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Actual write-offs may exceed the recorded allowance. Substantially all of the Company’s trade accounts receivable result from crude oil and natural gas sales in California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors. Trade accounts receivable are generally not collateralized. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2023 and February 28, 2022.
Crude Oil and Natural Gas Properties
The Company uses the successful efforts method of accounting for crude oil and natural gas property acquisition, exploration, development, and production activities. Costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred. Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred. In addition, the geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. Costs to operate and maintain wells and field equipment are expensed as incurred.
Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on estimated proved reserves. Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their estimated proved developed reserves. Support equipment and other property and equipment are depreciated over their estimated useful lives.
Pursuant to the provisions of Financial Accounting Standards Codification (“ASC”) Topic 360, “Property, Plant and Equipment” the Company reviews proved crude oil and natural gas properties and other long-lived assets for impairment. These reviews are predicated by events and circumstances, such as downward revision of the reserve estimates or commodity prices that indicate a decline in the recoverability of the carrying value of such properties. The Company estimates the future cash flows expected in connection with the properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amounts of the properties are reduced to their estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production, future capital expenditures and a risk-adjusted discount rate. These estimates of future product prices may differ from current market prices of crude oil and natural gas. Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s crude oil and natural gas properties in subsequent periods. Unproved crude oil and natural gas properties that are individually significant are also periodically assessed for impairment of value. An impairment loss for unproved crude oil and natural gas properties is recognized at the time of impairment by providing an impairment allowance.
For the twelve months ended February 28, 2023, the Company recognized an impairment charge of $711,873 for the write down of proven undeveloped reserves in both the East Slopes and the Reabold projects. Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years.
For the twelve months ended February 28, 2022, the Company recognized an impairment of unproved properties in Michigan and wrote down the entire $55,978 balance in Michigan.
On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income.
Property and Equipment
Vehicles
Machinery and Equipment
Fixed assets are stated at cost. Depreciation on vehicles is provided using the straight-line method over expected useful lives of three years. Depreciation on machinery and equipment is provided using the straight-line method over expected useful life of three years. Depreciation of production facilities and natural gas pipelines are recorded using the unit-of-production method based on estimated reserves.
Long Lived Assets
The Company reviews the carrying value of long-lived assets and identifiable intangibles whenever events or circumstances indicate that the carrying amounts of such assets may not be fully recoverable. The Company evaluates the recoverability of long-lived assets by measuring the carrying amounts of the assets against the estimated undiscounted cash flows associated with these assets. If this evaluation indicates that the future undiscounted cash flows of certain long-lived assets are not sufficient to recover the assets' carrying value, the assets are adjusted to their fair values (based upon discounted cash flows) through recognition of impairment.
Fair Value Measurements
ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. To increase consistency and comparability in fair value measurements and related disclosures, ASC Topic 820 also established a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. We are required to maximize the use of observable inputs and minimize the use of observable inputs when measuring fair value. The hierarchy describes three levels of inputs that may be used to measure fair value:
Level 1 - Quoted prices in active markets for identical assets and liabilities.
Level 2 - Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are financial instruments whose are determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant judgment or estimation.
ASC Topic 820 requires that an entity give consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value. Asset acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying market and income approached using level 3 inputs.
Fair Value of Financial Instruments
The Company’s carrying value of short-term financial instruments including cash, restricted cash, receivables, prepaid expenses, accounts payable, and other accrued liabilities, short-term liabilities and credit lines approximated their fair values due to the relatively short period to maturity for these instruments. The long-term notes payable approximates fair value since the related rates of interest approximate current market rates.
The Company’s financial instruments consist of cash, restricted cash, accounts receivable, accounts payable, notes payable and loans. The carrying amount of these financial instruments approximates their fair value due either to length of maturity or interest rates that approximate prevailing market rates unless otherwise disclosed in these financial statements. The Company has no financial assets or liabilities that are measured at fair value on a recurring basis as of February 28, 2023.
Share Based Payments
Stock awards are accounted for under FASB ASC Topic 718, “Compensation-Stock Compensation” (“ASC 718”). Under ASC 718, compensation for all share-based payment awards is based on estimated fair value at the grant date. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.
The Company estimates the fair value of stock purchase warrants on the grant date using the Black-Scholes option pricing model (“Black-Scholes Model”) as its method of valuation for warrant awards granted during the year. The Company’s determination of fair value of warrant awards on the date of grant using an option-pricing model is affected by the Company’s stock price, as well as assumptions regarding a number of subjective variables. These variables include, but are not limited to, the Company’s expected price volatility over the term of the awards and discount rates assumed.
Earnings (Loss) per Share of Common Stock
The Company follows ASC Topic 260, Earnings per Share, to account for the earnings per share. Basic earnings (loss) per common share (“EPS”) calculations are determined by dividing net earnings (loss) available to Common Stockholders by the weighted average number of common shares issued and outstanding during the year. Diluted earnings per common share are determined by dividing net income (loss) by the weighted average number of common shares outstanding and, dilutive common share equivalents outstanding. During periods when common share equivalents, if any, are anti-dilutive they are not considered in the computation.
Concentration of Credit Risk
Substantially all of the Company’s trade accounts receivable result from crude oil and natural gas sales in California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions including crude oil and natural gas prices as well as other related factors. Trade accounts receivable are generally not collateralized.
Customer Concentration
Accounts Receivable
At both the Company’s projects in California there is only one buyer for the purchase of all crude oil production. At February 28, 2023 and February 28, 2022, this one individual customer represented 100% of crude oil sales receivable from operations. If this buyer is unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its crude oil production.
At the Reabold project wells in Contra Costs County, California there is also natural gas production that the Company sells to a single buyer. At February 28, 2023, this one individual customer per project represented 100% of natural gas sales receivable. The Company had no natural gas sales before the Reabold acquisition in May of 2022. If this local purchaser is unable to resell their products or if they lose a significant sales contract then we may incur difficulties in selling our natural gas production.
The Company’s accounts receivable for California crude oil and natural gas sales at February 28, 2023 and February 28, 2022 are set forth in the table below:
Summary of Significant Accounting Policies - Schedule of Concentration of Risk, by Risk Factor
February 28, 2023 February 28, 2022
Project Customer Accounts
Receivable
Percentage Accounts
Receivable
Percentage
California - East Slopes project (crude oil) Plains Marketing $ 55,900 42.5 % $ 117,727 100.0 %
California - Reabold project (crude oil) Plains Marketing 59,614 45.3 % - -
California - Reabold project (natural gas) CRC 15,996 12.2 % - -
Totals
$ 131,510 100.0 % $ 117,727 100.0 %
Joint interest participant receivables balances of $353,009 and $85,339 at February 28, 2023 and February 28, 2022, respectively, represent amounts due from working interest partners in the East Slopes and Reabold projects. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2023 and February 28, 2022.
Revenue Recognition
The Company recognizes revenue under ASC 606, Revenue from Contracts with Customers (“Topic 606”). Under Topic 606, revenue is generally recognized upon delivery of the Company’s produced crude oil and natural gas volumes to its customers. Customer sales contracts include crude oil sales from both the East Slopes and Reabold projects and natural gas sales from some of the Reabold project. Both of these projects are located in California. Each unit of commodity product (crude oil barrel or natural gas MMBTU) represents a separate performance obligation which is sold at variable prices, determinable on a monthly basis. The pricing provisions of the crude oil and natural gas contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, product quality and prevailing supply and demand conditions in the geographic areas in which the Company operates. The Company allocates the transaction price to each performance obligation and recognize revenue upon delivery of the commodity product when the customer obtains control. Control of the produced crude oil volumes passes to the Company’s customers when the oil is measured by a trucking oil ticket. The Company has no control over the crude oil after this point and the measurement at this point dictates the amount on which the customer's payment is based. Control of the Company’s produced natural gas volumes passes to its customers when the natural gas is measured at the purchaser’s gas line meter. The Company has no control over the natural gas after this point and the measurement at this point dictates the amount on which the customer’s payment is based. The crude oil and natural gas revenue streams include volumes burdened by royalty and other joint owner working interests. The Company’s revenues are recorded and presented on its financial statements net of the royalty and other joint owner working interests. The revenue stream
does not include any payments for services or ancillary items other than for the sale of crude oil and natural gas. Revenue is recorded in the month crude oil and natural gas production is delivered to the purchaser.
Suspended Well Costs
The Company accounts for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities - Oil and Gas” (“ASC 932”). ASC 932 states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the economic and operating feasibility of the well. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs.
In addition, ASC 932 requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year, designating the number of wells the aging is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation.
Income Taxes
The Company follows the provisions of FASB ASC Topic 740, “Income Taxes” (“ASC 740”). As required under ASC 740, the Company accounts for income taxes using an asset and liability approach, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial statements and tax bases of assets and liabilities at the applicable tax rates. A valuation allowance is utilized when it is more likely than not, that some portion of, or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
ASC 740 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under ASC 740, the Company recognizes tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% (percent) likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards.
Recent Accounting Pronouncements
Accounting Standards Issued and Adopted
The Company does not believe that any recently issued effective pronouncements, or pronouncements issued but not yet effective, if adopted, would have a material effect on the Company’s financial statements.
NOTE 4 - ACCOUNTS RECEIVABLE:
Accounts receivable consists primarily of receivables from the sale of crude oil and natural gas production by the Company and receivables from the Company’s working interest partners in crude oil and natural gas projects in which the Company acts as Operator of the project.
Crude oil and natural gas sales receivables balances of $131,510 and $117,727 at February 28, 2023 and February 28, 2022, represent crude oil and natural gas sales that occurred in February 2023 and 2022, respectively.
Joint interest participant receivables balances of $353,009 and $85,339 at February 28, 2023, and February 28, 2022, respectively, represent amounts due from working interest partners in California, where the Company is the Operator.
There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2023, and February 28, 2022.
NOTE 5 - CRUDE OIL PROPERTIES:
Crude oil property balances at February 28, 2023, and February 28, 2022 are set forth in the table below:
Crude Oil Properties - Schedule of Crude Oil Activities
February 28, 2023 February 28, 2022
Proved leasehold costs $ 115,119 $ 115,119
Costs of wells and development 6,915,982 2,309,628
Capitalized exploratory well costs 1,341,494 1,341,494
Property, plant and equipment (Reabold) 320,217 -
Cost of crude oil and natural gas properties 8,692,812 3,766,241
Accumulated depletion, depreciation amortization and impairment (3,566,612 ) (3,230,209 )
Total crude oil and natural gas properties, net $ 5,126,200 $ 536,032
For the twelve months ended February 28, 2023 and February 28, 2022, the Company recognized depletion expense of $477,089 and $38,125, respectively which is included in DD&A in the statement of operations. Impairment expense of proven undeveloped (PUD) well costs for the twelve months ended February 28, 2023 and February 28, 2022 was $711,873 and $-0-, respectively.
NOTE 6 - ACQUISITION:
On May 25, 2022, the Company finalized the acquisition of Reabold from a third party for 160,964,489 shares of the Company’s Common Stock valued at $6,599,544. The transaction balance of $6,863,163 reflects the Common Stock valuation of the acquisition transaction and $263,619 in reimbursements to the seller, considered to be cash consideration, relating to expenditures for workovers agreed to by the Company and the third party. The acquisition was considered an acquisition of a business under ASC 805. The following table presents the allocation of the purchase price of the assets acquired and liabilities assumed at fair value.
Cash $ 19,706
Restricted cash - O&G operator bonds 275,000
Accounts receivable 248,817
Crude oil and natural gas property and equipment 4,694,563
Property, plant and equipment, net 428,221
Goodwill 1,415,361
Accounts payable (152,854 )
Revenue payable (62,914 )
Other liabilities assumed (2,737 )
Purchase price, net of closing adjustments $ 6,863,163
Adjustments made to the Reabold assets are derived from a total value of $6,599,544, based on 160,964,489 shares of stock issued for the acquisition and the closing price that day of $0.041 per share. The total consideration given of $6,863,163, consisted of the $6,599,544 common stock valuation and cash consideration of $263,619 for approved expense reimbursement. Net assets acquired of $5,447,802 were derived by deducting the liabilities assumed of $218,505 from the assets acquired of $5,666,307. Goodwill of $1,415,361 was derived by deducting the consideration given of $6,863,163 from the net assets acquired of $5,447,802. The Company incurred approximately $445,529 in transaction costs directly related to the Acquisition.
NOTE 7 - ASSET RETIREMENT OBLIGATION (“ARO”):
The Company’s financial statements reflect the provisions of ASC 410. The ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determines the ARO on its crude oil and natural gas properties by calculating the present value of estimated cash flows related to the liability. As of February 28, 2023 and February 28, 2022, ARO obligations were considered to be long-term based on the estimated timing of the anticipated cash flows. For the twelve months ended February 28, 2023, and February 28, 2022, the Company recognized accretion expense of $23,875 and $8,574, respectively which is included in DD&A in the statements of operations.
Changes in the asset retirement obligations for the twelve months ended February 28, 2023, and February 28, 2022 are set forth in the table below.
Asset Retirement Obligation (“ARO”) - Schedule of Changes in the Asset Retirement Obligations
February 28, 2023 February 28, 2022
Asset retirement obligation, beginning of period $ 52,565 $ 33,062
Accretion expense 23,875 8,574
Revisions to asset retirement obligation 239,069 10,929
Asset retirement obligation, end of period $ 315,509 $ 52,565
NOTE 8 - ACCOUNTS PAYABLE:
On March 1, 2009, the Company became the operator for the East Slopes Project located in Kern County, California. Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning wells program. The Company subsequently sold the 25% working interest on June 11, 2009. Approximately $244,849 of the $1.5 million default remains unpaid and is included in the February 28, 2023 and February 28, 2022 accounts payable balance. Payment of this liability has been delayed until the Company’s cash flow situation improves. On October 17, 2018, a working interest partner in California filed a UCC financing statement in regards to payables owed to the partner by the Company. At February 28, 2023 and February 28, 2022, the balance owed this working interest partner was $63,367 and $76,268, respectively and is included in the accounts payable balances.
NOTE 9 - ACCOUNTS PAYABLE - RELATED PARTIES:
The February 28, 2023, and February 28, 2022 accounts payable - related party balances of $21,937 and $49,228, respectively, were comprised of deferred expense reimbursements to employees.
In California at the East Slopes Project, two of the vendors that the Company uses for services are partially owned by a related party, the Company’s Chief Operating Officer. The Company’s Chief Operating Officer is 50% owner in both Great Earth Power (“Great Earth”) and ABPlus Net Holdings (“ABPlus”). Great Earth began providing a portion of the solar power electrical service for production operations in July 2020. ABPlus began providing portable tank rentals to the Company as a part of its water treatment and disposal operations in September 2020. The services provided by Great Earth and ABPlus are competitive with other vendors and save the Company significant expense.
For the twelve months ended February 28, 2023, and February 28, 2022, Great Earth provided services valued at $15,663 and $20,300, respectively. For the twelve months ended February 28, 2023, and February 28, 2022, ABPlus provided services valued at $11,520, respectively. At February 28, 2023 and February 28, 2022, Great Earth was owed $613 and $1,400, respectively. At February 28, 2023 and February 28, 2022, ABPlus was owed $960, respectively. Amounts owed to Great Earth and ABPlus represent a portion of the accounts payable amount presented on the balance sheets.
NOTE 10 - SHORT-TERM AND LONG-TERM BORROWINGS:
Note Payable
In December 2018, the Company was able to settle an outstanding balance owed to one of its third-party vendors. This settlement resulted in a $120,000 note payable being issued to the vendor. Additionally, the Company agreed to issue 2,000,000 shares of the Company’s Common Stock as a part of the settlement agreement. Based on the closing price of the Company’s Common Stock on the date of the settlement agreement, the value of the Common Stock transaction was determined to be $6,000. The Common Stock shares were issued during the twelve months ended February 29, 2020. The note has a maturity date of January 1, 2022, and bears an interest rate of 10% rate per annum. The note principal has not been paid and the Company is considered to be in default. There is no default interest rate associated with the note. Interest is accrued monthly and is payable on January 1st of each anniversary date. At February 28, 2023, the principal and a portion of the accrued interest had not been paid and was outstanding. The accrued interest on the Note was $26,000 and $38,000 at February 28, 2023 and February 28, 2022, respectively.
Note Payable - Related Party
Secured Debt
Chief Executive Officer
On December 22, 2020, the Company entered into a Secured Promissory Note (the “Note”), as borrower, with James Forrest Westmoreland and Angela Marie Westmoreland, Co-Trustees of the James and Angela Westmoreland Revocable Trust, or its assigns (the “Noteholder”), as the lender. James F. Westmoreland is the Company’s Chairman, President and Chief Executive Officer. Pursuant to the Note, the Noteholder loaned the Company an aggregate principal amount of $155,548. After the deduction of loan fees of $10,929 the net proceeds from the loan were $144,619. The loan fees are being amortized as original issue discount (OID) over the term of the loan. The interest rate of the loan is 2.25%. The Note requires monthly payments on the Note balance until repaid in full. The maturity date of the Note is December 21, 2035. For the twelve months ended February 28, 2023, the Company made principal payments of $8,829 and amortized debt discount of $729. The obligations under the Note are secured by a lien on and security interest in the Company’s oil and gas assets located in Kern County, California, as described in a Deed of Trust entered into by the Company in favor of the Noteholder to secure the obligations under the Note. Such lien shall be a first priority lien, subject only to a pre-existing lien filed by a working interest partner of the Company.
The Company may prepay the Note at any time. Upon the occurrence of any Event of Default and expiration of any applicable cure period, and at any time thereafter during the continuance of such Event of Default, the Noteholder may at its option, by written notice to the Company: (a) declare the entire principal amount of the Note, together with all accrued interest thereon and all other amounts payable hereunder, immediately due and payable; (b) exercise any of its remedies with respect to the collateral set forth in the Deed of Trust; and/or (c) exercise any or all of its other rights, powers or remedies under applicable law.
Current portion of note payable -related party balances at February 28, 2023, and February 28, 2022 are set forth in the table below:
Short-Term and Long-Term Borrowings - Schedule of Related Party Notes Payable
February 28, 2023 February 28, 2022
Note payable - related party, current portion $ 9,065 $ 8,829
Unamortized debt issuance expenses (728 ) (729 )
Note payable - related party, current portion, net $ 8,337 $ 8,100
Note payable -related party long-term balances at February 28, 2023 and February 28, 2022 are set forth in the table below:
February 28, 2023 February 28, 2022
Note payable - related party, non-current $ 127,645 $ 136,710
Unamortized debt issuance expenses (8,622 ) (9,350 )
Note payable - related party, non-current, net $ 119,023 $ 127,360
Future estimated payments on the outstanding note payable - related party are set forth in the table below:
Short-Term and Long-Term Borrowings - Schedule of Future Estimated Payments
Twelve month periods ending February 28/29,
9,065
9,309
9,558
9,815
10,078
Thereafter 88,885
Total $ 136,710
Short-term Convertible Note Payable
Convertible Debt
During the twelve months ended February 28, 2022, the Company executed a convertible promissory note with a third party for $200,000. The interest rate was 18% per annum and is payable in kind (“PIK”) solely by additional shares of the Company’s Common Stock. Regardless of when the conversion occurred, a full 12 months of interest would be payable upon conversion. On May 5, 2022, the Company received notice of conversion of the promissory note. The face amount of the note and $36,000 in interest were converted at a rate of $0.0085 per share into 27,764,706 shares of the Company’s Common Stock during the twelve months ended February 28, 2023.
12% Subordinated Notes
Private Placement
Subordinated Debt
The Company’s 12% Subordinated Notes (the “Notes”) issued pursuant to a January 2010 private placement offering to accredited investors, had a balance at February 28, 2023 and February 28, 2022 of $290,000 and $315,000, respectively. The original maturity date of January 29, 2015 had been extended to January 29, 2017 and then was extended to January 29, 2019. Interest accrues at 12% per annum, payable semi-annually on January 29th and July 29th.
The Company has informed the Note holders that the payment of principal and interest will be late and is subject to future financing being completed and the Company’s cash flow. The Notes principal of $290,000 has not been paid and interest continues to accrue on the unpaid principal balance. The accrued interest on the 12% Notes at February 28, 2023 and February 28, 2022 was $159,508 and $135,229, respectively. The terms of the Notes, state that should the Board of Directors, on any future maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s Common Stock at a conversion rate equal to 75% of the average closing price of the Company’s Common Stock over the 20 consecutive trading days preceding December 31, 2018.
During the twelve months ended February 28, 2023, one 12% Note holder chose to convert the principal balance and accrued interest into the Company’s Common Stock. The $25,000 Note and accrued interest of $10,520 were converted at a rate of approximately $0.45 for every dollar of principal and interest resulting in 78,934 shares of Common Stock being issued.
12% Note balances at February 28, 2023 and February 28, 2022 are set forth in the table below:
Short-Term and Long-Term Borrowings - Schedule of Subordinated Notes
12% Subordinated Notes
Related Party Notes
February 28, 2023 February 28, 2022
12% Subordinated notes - third party $ 290,000 $ 315,000
12% subordinated notes - related party - -
12% Subordinated notes balance $ 290,000 $ 315,000
Line of Credit
Line of Credit
At February 28, 2022, the Company had an existing $890,000 line of credit for working capital purposes with UBS Bank USA (“UBS”) that was established pursuant to a Credit Line Agreement dated October 24, 2011 and was secured by the personal guarantee of our President and Chief Executive Officer. During the twelve months ended February 28, 2023, and February 28, 2022, the Company did not receive any advances on the line of credit.
On May 26, 2022, the Company paid off the outstanding balance of $809,930 on the line of credit. The payoff of the line of credit was previously approved under terms of the Equity Exchange Agreement in which the Company acquired the Reabold property in California. The line of credit payoff was a part of the use of proceeds from the Company’s sale of Common Stock to a third party. At February 28, 2023 and February 28, 2022, the line of credit had an outstanding balance of $-0- and $808,182, respectively
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 existing historical debt. The purchasers of a production payment interest are to receive a production revenue payment interest on future wells to be drilled in California in exchange for their purchase. The Company shall pay seventy-five percent (75%) of its future net production revenue from the relevant wells to the purchasers until each purchaser has received two times the purchase price (the “Production Payment Target”). Once the Company pays the purchaser group amounts equal to the Production Payment Target, it shall thereafter pay a pro-rated eight percent (8%) of $1.3 million on its net production payments from the relevant wells to the purchaser group. However, if the total raise amount is less than the target $1.3 million, then the payment will be a proportionate amount of the eight percent (8%).
The Company accounted for the amounts received from these sales in accordance with ASC 470-10-25 and 470-10-35 which require amounts recorded as debt to be amortized under the interest method as described in ASC 835-30, Interest Method. Consequently, the program balance of $873,281 has been recognized as a production revenue payable. The Company determined an effective interest rate based on future expected cash flows to be paid to the holders of the production payment interests. This rate represents the discount rate that equates estimated cash flows with the initial proceeds received from the sales and is used to compute the amount of interest to be recognized each period. Estimating the future cash outflows under this agreement requires the Company to make certain estimates and assumptions about future revenues and payments and such estimates are subject to significant variability. Therefore, the estimates are likely to change which may result in future adjustments to the accretion of the interest expense and the amortized cost based carrying value of the related payables.
Accordingly, the Company has estimated the cash flows associated with the production revenue payments and determined a discount of $78,136 as of February 28, 2023, which is being accounted as interest expense over the estimated period over which payments will be made based on expected future revenue streams. For the twelve months ended February 28, 2023, and February 28, 2022, amortization of the debt discount on these payables amounted to $56,156 and $95,974, respectively, which has been included in interest expense in the statements of operations.
Production revenue payable balances at February 28, 2023 and February 28, 2022 are set forth in the table below:
Short-Term and Long-Term Borrowings - Schedule of Production Revenue Payable Balances
February 28, 2023 February 28, 2022
Estimated payments of production revenue payable $ 913,395 $ 941,259
Less: unamortized discount (40,114 ) (124,134 )
873,281 817,125
Less: current portion (56,915 ) (78,877 )
Net production revenue payable - long term $ 816,366 $ 738,248
Encumbrances
On October 17, 2018, a working interest partner in California filed a UCC financing statement in regards to payable amounts owed to the partner by the Company.
On December 22, 2020, the Company entered into a Secured Promissory Note (the “Westmoreland Note”), as borrower, with James Forrest Westmoreland and Angela Marie Westmoreland, Co-Trustees of the James and Angela Westmoreland Revocable Trust, or its assigns (the “Noteholder”), as the lender. James F. Westmoreland is the Company’s Chairman, President and Chief Executive Officer. Pursuant to the Westmoreland Note, the Noteholder loaned the Company an aggregate principal amount of $155,548. The obligations under the Westmoreland Note are secured by a lien on and security interest in the Company’s oil and gas assets located in Kern County, California, as described in a Deed of Trust entered into by the Company in favor of the Noteholder to secure the obligations under the Westmoreland Note. Such lien shall be a first priority lien, subject only to a pre-existing lien filed by a working interest partner of the Company.
NOTE 11 - LEASES:
Daybreak formally leased approximately 988 rentable square feet of office space from an unaffiliated third party for our corporate office located in Spokane Valley, Washington. This office was closed in March of 2023 when the corporate office was consolidated with our Friendswood, Texas regional operations office. The Company leases approximately 416 rentable square feet of office space from an unaffiliated third party for our new corporate office located in in Friendswood, Texas. Additionally, we lease approximately 695 rentable square feet from an unaffiliated third party for storage and auxiliary office space in Wallace, Idaho. The lease in Friendswood is a 12-month lease that expired in October 2023, and subsequently renewed until October 31, 2024 and as such is considered a short-term lease. The Company has elected to not apply the recognition requirements of ASC 842 to this short-term lease. The Wallace lease is currently on a month-to-month basis. The Company’s lease agreements do not contain any residual value guarantees, restrictive covenants or variable lease payments. The Company has not entered into any financing leases.
Rent expense for the twelve months ended February 28, 2023 and February 28, 2022 was $23,889 and $23,489, respectively.
NOTE 12 - RELATED PARTY TRANSACTIONS:
In California at the East Slopes Project, two of the vendors that the Company uses for services are partially owned by a related party, the Company’s Chief Operating Officer, Bennett Anderson. Mr. Anderson is a 50% owner in both Great Earth Power (“Great Earth”) and ABPlus Net Holdings (“ABPlus”). Great Earth began providing a portion of the solar power electrical service for production operations in July 2020. ABPlus began providing portable tank rentals to the Company as a part of its water treatment and disposal operations in September 2020. The services provided by Great Earth and ABPlus are competitive with other vendors and save the Company significant expense.
For the twelve months ended February 28, 2023, and February 28, 2022, Great Earth provided services valued at $15,663 and $20,300, respectively. For the twelve months ended February 28, 2023, and February 28, 2022, ABPlus provided services valued at $11,520, respectively. At February 28, 2023 and February 28, 2022, Great Earth was owed $613 and $1,400, respectively. At February 28, 2023 and February 28, 2022, ABPlus was owed $960, respectively. Amounts owed to Great Earth and ABPlus represent a portion of the accounts payable amount presented on the balance sheets.
NOTE 13 - STOCKHOLDERS’ EQUITY (DEFICIT):
Preferred Stock
With the filing of the Company’s Second Amended and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, the Company no longer has any preferred stock. The Company has only one class of stock, which is Common Stock.
Series A Convertible Preferred Stock
At February 28, 2022, there were no issued or outstanding shares of Series A Preferred stock that had not been converted into our Common Stock. With the filing of the Company’s Second Amended and Restated Articles of Incorporation with the Washington Secretary of State in May 2022, the Company no longer had any preferred stock. The Company has only one class of stock, which is Common Stock.
Conversion:
At February 28, 2022, there were no shares issued and outstanding that had not been converted into our Common Stock.
The conversions of Series A Preferred that have occurred since the Series A Preferred was first issued in July 2006 are set forth in the table below.
Stockholders’ Deficit - Schedule of Conversions of Series A Preferred Stock
Series A Preferred Stock
Fiscal Period Shares of Series A
Preferred Converted
to Common Stock
Shares of
Common Stock
Issued from
Conversion
Number of
Accredited
Investors
Year Ended February 29, 2008 102,300 306,900
Year Ended February 28, 2009 237,000 711,000
Year Ended February 28, 2010 51,900 155,700
Year Ended February 28, 2011 102,000 306,000
Year Ended February 29, 2012 - - -
Year Ended February 28, 2013 18,000 54,000
Year Ended February 28, 2014 151,000 453,000
Year Ended February 28, 2015 3,000 9,000
Year Ended February 29, 2016 10,000 30,000
Year Ended February 28, 2017 - - -
Year Ended February 28, 2018 14,997 44,991
Year Ended February 28, 2019 - - -
Year Ended February 29, 2020 - - -
Year Ended February 28, 2021 - - -
Year Ended February 28, 2022 709,568 2,128,704
Totals 1,399,765 4,199,295
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 the Series A Preferred stock for each twelve month period since issuance are set forth in the table below:
Stockholders’ Deficit - Schedule of Preferred Stock Dividends Earned
Fiscal Year Ended
Shareholders at
Period End
Accumulated
Dividends
February 28, 2007
$ 155,311
February 29, 2008
242,126
February 28, 2009
209,973
February 28, 2010
189,973
February 28, 2011
173,707
February 29, 2012
163,624
February 28, 2013
161,906
February 28, 2014
151,323
February 28, 2015
132,634
February 29, 2016
130,925
February 28, 2017
130,415
February 28, 2018
128,231
February 28, 2019
127,714
February 29, 2020
128,063
February 28, 2021
127,714
February 28, 2022
-
96,340
$ 2,449,979
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.
Common Stock
Balance
Par Value
Common stock, Issued and Outstanding, February 28, 2021 60,491,122
Shares issued for Series A Preferred conversion 2,128,704 $ 2,129
Shares issued for Series A accumulated dividend 1,100,000 $ 1,100
Shares issued for debt conversion of accrued salaries 1,397,880 $ 1,398
Shares issued for debt conversion of accrued directors fees 317,708 $ 318
Shares issued for conversion of 12% Note principal and interest - related party 1,144,415 $ 1,144
Shares issued for investment principal in production revenue program 1,222,444 $ 1,222
Common stock, Issued and Outstanding, February 28, 2022 67,802,273
Shares issued for conversion of 12% Note principal and interest 78,934 $ 79
Shares issued for conversion of convertible note 27,764,706 $ 27,765
Shares issued for acquisition of crude oil and natural gas properties 160,964,489 $ 160,964
Shares issued for sale of stock 125,000,000 $ 125,000
Shares issued for financing fees 3,125,000 $ 3,125
Share adjustment due to recording error (500 ) $ 1
Common stock, Issued and Outstanding, February 28, 384,734,902
During the twelve months ended February 28, 2023, there were 316,933,129 shares of Common Stock issued. Common Stock shares issued for the Reabold subsidiary acquisition were 160,964,489. Share issuances in connection with fundraising were 155,889,706. Another 78,934 shares were issued through the conversion of a 12% Note and interest to our Common Stock. During the twelve months ended February 28, 2022, there were 7,311,151 shares of Common Stock issued as a part of the Company’s restructuring of its balance sheet in accordance with the conditions of the Equity Exchange Agreement between Reabold California, LLC, Gaelic Resources Ltd, and the Company. Of the total 7,311,151 shares issues, there were 4,082,447 shares issued to satisfy related party debt. Another 3,228,704 shares were issued to satisfy the Series A Preferred stock conversion and associated accumulated dividend of $2,449,979. In December 2023, we were notified of a system error that had occurred in the recording of street stock shares held by the nominee. Accordingly, the number of our issued and outstanding shares was reduced by 500 shares as of February 28, 2023. The common stock par value of this adjustment was $0.50.
Subsequent Event
All shares of Common Stock are equal to each other with respect to voting, liquidation, dividend and other rights. Owners of shares of Common Stock are entitled to one vote for each share of Common Stock owned at any shareholders’ meeting. Holders of shares of Common Stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefore; and upon liquidation, are entitled to participate pro rata in a distribution of assets available for such a distribution to shareholders.
There are no conversion, preemptive, or other subscription rights or privileges with respect to any shares of our Common Stock. Our stock does not have cumulative voting rights, which means that the holders of more than 50% of the shares voting in an election of directors may elect all of the directors if they choose to do so. In such event, the holders of the remaining shares aggregating less than 50% would not be able to elect any directors.
At a special meeting of shareholders on May 20, 2022 the Company’s shareholders approved an increase in the number of authorized Common Stock shares to 500,000,000 rather than the previous 200,000,000 Common Stock authorization.
NOTE 14 - WARRANTS:
Share Based Payment Arrangement - Non-Employee
During the twelve months ended February 29, 2020 there were 2.1 million warrants issued to a third party for investor relations services. The fair value of the warrants was determined by the Black-Scholes pricing model, was $17,689, and is being amortized over the three-year vesting period of the warrants. The Black-Scholes valuation encompassed the following assumptions: a risk-free interest rate of 1.68%; volatility rate of 260.23%; and a dividend yield of 0.0%.
The warrant contains a vesting blocking provision that prevents the vesting of any warrants that such vesting would cause the warrant holder’s beneficial ownership (as such term is defined in Section 13d-3 of the Securities Exchange Act of 1934, as amended) to exceed more than four and ninety-nine one-hundredths percent (4.99%) of the Company’s outstanding Common Stock. The foregoing restriction may not be waived by either party. The warrants vested in equal parts over a three-year period beginning on January 2, 2020 and all warrants expired on January 2, 2024.
As of February 28, 2023, and February 28, 2022, there were 2,100,000 and 893,333 outstanding and exercisable Common Stock warrants. At February 28, 2023, both the outstanding warrants and the exercisable warrants had a weighted average exercise price of $0.01; a weighted average remaining life of 0.83 years, and an intrinsic value of $25,200. The recorded amount of warrant expense for the twelve months ended February 28, 2023, and February 28, 2022 was $-0- and $4,913, respectively. The warrants were fully amortized at December 31, 2021. All outstanding and exercisable warrants expired on January 2, 2024.
Warrant activity for the twelve months ended February 28, 2023 and February 28, 2022 is set forth in the table below:
Warrants - Schedule of Warrant Activity
Warrants
Weighted Average
Exercise Price
Warrants outstanding, February 28, 2021
2,100,000
$ 0.01
Changes during the twelve months ended February 28, 2022:
Issued
-
Expired / Cancelled / Forfeited
-
Warrants outstanding, February 28. 2022
2,100,000
$ 0.01
Warrants exercisable, February 28, 2022
893,333
Changes during the twelve months ended February 28, 2023:
Issued
-
$
Expired / Cancelled / Forfeited
-
Warrants outstanding, February 28, 2023
2,100,000
$ 0.01
Warrants exercisable, February 28, 2023
2,100,000
$ 0.01
NOTE 15 - INCOME TAXES:
On December 22, 2017, the federal government enacted a tax bill H.R.1, an act to provide for reconciliation pursuant to Titles II and V of the concurrent resolution on the budget for fiscal year 2018, commonly referred to as the Tax Cuts and Jobs Act. The Tax Cuts and Jobs Act contains significant changes to corporate taxation, including, but not limited to, reducing the U.S. federal corporate income tax rate from 35% to 21% and modifying or limiting many business deductions. The Company has re-measured its deferred tax liabilities based on rates at which they are expected to be utilized in the future, which is generally 21%.
Reconciliation between actual tax expense (benefit) and income taxes computed by applying the U.S. federal income tax rate and state income tax rate to income from continuing operations before income taxes is as follows:
Income Taxes - Schedule of Reconciliation Between Actual Tax Expense Benefit and Income Taxes Computed by Applying Income Tax Rate
February 28, 2023 February 28, 2022
Computed at U.S. and state statutory rates $ (724,883 ) $ (118,897 )
Permanent differences 19,156 11,157
Changes in valuation allowance 705,727 107,740
Total $ - $ -
Tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred liabilities are presented below:
Income Taxes - Schedule of Deferred Tax Assets and Liabilities
February 28, 2023 February 28, 2022
Deferred tax assets:
Net operating loss carryforwards $ 6,108,775 $ 5,670,900
Oil and gas properties 355,546 87,694
Stock based compensation 66,187 66,187
Other 27,838 27,838
Less valuation allowance (6,558,346 ) (5,852,619 )
Total $ - $ -
At February 28, 2023, the Company had a net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $20,471,769, which will begin to expire, if unused, beginning in 2024. Under the Tax Cuts and Jobs Act, the NOL portion of the loss incurred in the 2018, 2020, 2021 and 2022 periods of $340,749, $339,299, $416,898 and $279,773, respectively, and the loss incurred for the year ended February 28, 2023 in the amount of $107,740 will not expire and will carry over indefinitely. The valuation allowance increased approximately $705,727 for the year ended February 28, 2023 and increased approximately $107,740 for the year ended February 28, 2022. Section 382 Rule of the Internal Revenue Code will place annual limitations on the Company’s NOL carryforward.
The above estimates are based upon management’s decisions concerning certain elections that could change the relationship between net income and taxable income. Management decisions are made annually and could cause the estimates to vary significantly. The Company’s files federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for the fiscal years after 2016 currently remain subject to examinations by appropriate tax authorities. None of our tax returns are under examination at this time.
NOTE 16 - COMMITMENTS AND CONTINGENCIES:
Various lawsuits, claims, threatened legal actions, and other contingencies arise in the ordinary course of the Company’s business activities. In the opinion of management, the disposition of any such matters is not expected, individually or in the aggregate, to have a material adverse effect on the Company’s results of operations, financial condition, or cash flows. However, the results of legal actions cannot be predicted with certainty. Therefore, it is possible that the Company’s results of operations, financial condition or cash flows could be materially adversely affected in any particular period by the unfavorable resolution of one or more legal actions.
The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.
The Company is not aware of any environmental claims existing as of February 28, 2023. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s crude oil and natural gas properties.
Sunflower Lawsuit
Sunflower Alliance v. California Department of Conservation, Geologic Energy Management Division. This case challenges the state agency’s compliance with the California Environmental Quality Act (CEQA) with respect to the PAL Reabold 072-00-0001 Project, for wastewater injection into an existing well. The Petition was filed on December 29, 2021 in the Alameda County Superior Court. The Petitioner seeks an order setting aside the state agency’s approval of a wastewater injection permit; damages are not sought in the lawsuit. On February 22, 2022, Real Party in Interest Reabold California, LLC filed a motion to transfer the case to the Contra Costa County Superior Court. On March 22, 2022, the Alameda County Superior Court ordered the case transferred to the Contra Costa County Superior Court. On August 15, 2022, the Contra Costa County Superior Court provided notice that the transfer has been completed and the case filed in that court. On December 22, 2022, the Superior Court issued an order finding CEQA deficiencies, and
directing the state agency to rescind its approval of the project. On September 7, 2023, an appeal of the Superior Court order was filed in the California Court of Appeal, First appellate District, Division 5. The California Attorney General is defending the state agency, which disputes Petitioner’s claims. At this time, it is unclear when the litigation will be resolved. If successful, the lawsuit would prevent Reabold from injecting wastewater into an existing well until any CEQA deficiencies are addressed.
The Company is not aware of any environmental claims existing as of January 23, 2024. There can be no assurance, however, that current regulatory requirements will not change or that past non-compliance with environmental issues will not be discovered on the Company’s crude oil properties.
NOTE 17 - SUBSEQUENT EVENTS:
Related Party Note Payable
Unsecured
On July 27, 2023, the Company executed an Unsecured Promissory Note (the “Note”) with James F. Westmoreland, the Company’s President and CEO, in the amount of $60,000. The Note has a maturity date of July 27, 2024 and carries no interest, fees or penalties. The Company may prepay the Note at any time. Proceeds of the Note will be used for working capital purposes.
NOTE 18 - SUPPLEMENTARY INFORMATION FOR CRUDE OIL PRODUCING ACTIVITIES (UNAUDITED):
Capitalized Costs Relating to Crude Oil and Natural Gas Producing Activities
Supplementary Information for Crude Oil Producing Activities - Capitalized Costs Relating to Crude Oil and Natural Gas Producing Activities
As of
February 28, 2023
As of
February 28, 2022
Proved leasehold costs
Mineral Interests $ 115,119 $ 115,119
Wells, equipment and facilities 8,577,693 3,651,122
Total Proved Properties 8,692,812 3,766,241
Unproved properties
Mineral Interests - -
Uncompleted wells, equipment and facilities - -
Total unproved properties - -
Less accumulated depreciation, depletion amortization and impairment (3,566,612 ) (3,230,209 )
Net capitalized costs $ 5,126,200 $ 536,032
Costs Incurred in Oil and Gas Producing Activities
Supplementary Information for Crude Oil Producing Activities - Costs Incurred in Oil and Gas Producing Activities
12 Months Ended 12 Months Ended
February 28, 2023 February 28, 2022
Acquisition of proved properties $ 4,694,563 $ -
Acquisition of unproved properties - -
Development costs - 6,773
Exploration costs - -
Total costs incurred $ 4,694,563 $ 6,773
Results of Operations from Oil and Gas Producing Activities
Supplementary Information for Crude Oil Producing Activities - Results of Operations from Oil and Gas Producing Activities
12 Months Ended 12 Months Ended
February 28, 2023 February 28, 2022
Crude oil and natural gas revenues $ 1,613,286 $ 680,107
Production costs (1,103,825 ) (231,275 )
Exploration expenses - (56,213 )
Depletion, depreciation and amortization (504,118 ) (49,590 )
Impairment of crude oil and natural gas properties (711,873 ) -
Result of crude oil and natural gas producing operations before income taxes (706,530 ) 343,029
Provision for income taxes - -
Results of crude oil and natural gas producing activities $ (706,530 ) $ 343,029
Proved Reserves
The Company’s proved oil and natural gas reserves have been estimated by two certified independent engineering firms, PGH Petroleum and Environmental Engineers, LLC, of Austin, Texas and PETROtech Resources Company of Bakersfield, California. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods when the estimates were made. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors.
As of February 28, 2023, our total reserves were comprised of our working interest in the East Slopes Project located in Kern County and our working interest in the Reabold subsidiary located in Monterey and Contra Costs Counties, all in California. Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years.
Our proved reserves are summarized in the table below:
Supplementary Information for Crude Oil Producing Activities - Schedule of Proved Oil and Gas Reserves
Oil (Barrels)
Natural Gas (Mcf)
Oil (Barrels)
Natural Gas (Mcf)
BOE (Barrels)
Proved reserves:
February 28, 2021
434,223
-
434,223
Revisions(1)
92,545
-
92,545
Discoveries and extensions
-
-
-
Production
(9,613 )
-
(9,613 )
February 28, 2022
517,155
-
517,155
Purchases of minerals
277,224
62,152
287,582
Revisions(2)
(393,076 )
-
(393,076 )
Discoveries and extensions
-
-
-
Production
(17,114 )
(3,822 )
(17,751 )
February 28, 2023
384,188
58,330
393,910
(1) The upward revision of 92,545 BOE of proved reserves in aggregate were due to an increase in the economic life of existing reserves due to an improvement in crude oil prices in the energy markets.
(2) A decrease in aggregate of 393,076 BOE resulted from upward revisions of 6,235 BOE of developed reserves due to an increase in the economic life of existing reserves due to an improvement in crude oil prices in the energy markets, offset by the removal of 399,311 BOE of proved undeveloped reserves that have remained undeveloped for a period greater than five years as of February 28, 2023.
The Company’s proved reserves are set forth in the table below.
Supplementary Information for Crude Oil Producing Activities - Schedule of Proved Developed and Undeveloped Reserves
Developed
Undeveloped
Total Reserves
Oil (Bbls)
BOE (Bbls)
Oil (Bbls)
BOE (Bbls)
Oil (Bbls)
BOE (Bbls)
February 28, 2021
95,120
95,120
339.103
339,103
495,977
495,977
February 28, 2022
117,844
117,844
47,323
47,323
165,167
165,167
February 28, 2023
384,188
393,910
-
-
384,188
393,910
Under the guidance provided by Rule 4-10(a)(31)(ii) of Regulation S-X, we have no reserves that qualify to be considered proved undeveloped reserves since any proved undeveloped reserves that were previously considered to be proved undeveloped reserves have remained undeveloped for a period greater than five years.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of February 28, 2023, and February 28, 2022 in accordance with ASC 932, “Extractive Activities - Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.
Future cash inflows for the years ended February 28, 2023, and February 28, 2022 were estimated as specified by the SEC through calculation of an average price based on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the period from March through February during each respective fiscal year. The resulting net cash flow are reduced to present value by applying a 10% discount factor.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Supplementary Information for Crude Oil Producing Activities - Standardized Measure of Discounted Future Cash Flows Relating to Proved Oil and Gas Reserves
12 Months Ended
February 28, 2023 February 28, 2022
Future cash inflows $ 35,775,832 $ 35,580,251
Future production costs(1) (17,162,238 ) (16,217,379 )
Future development costs (725,938 ) (3,603,561 )
Future income tax expenses(2) - -
Future net cash flows 17,887,656 15,759,311
10% annual discount for estimated timing of cash flows (6,851,692 ) (9,567,367 )
Standardized measure of discounted future net cash flows at the end of the fiscal year $ 11,035,964 $ 6,191,944
(1) Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation expense, workover costs and G&A expense supporting the Company’s crude oil and natural gas operations.
(2) The Company has sufficient tax deductions and allowances related to proved crude oil and natural gas reserves to offset future net revenues.
Average hydrocarbon prices are set forth in the table below.
Supplementary Information for Crude Oil Producing Activities - Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure
Crude Oil Average Price
Natural
Natural Gas Crude Oil (Bbl)
Gas (Mcf)
Year ended February 28, 2021(1) $ 36.91
$ -
Year ended February 28, 2022(1) $ 70.75
$ -
Year ended February 28, 2023(1) $ 93.67
$ 5.76
(1) Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year.
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
Sources of Changes in Discounted Future Net Cash Flows
Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by ASC 932, at fiscal year-end are set forth in the table below.
Supplementary Information for Crude Oil Producing Activities - Schedule of Sources of Changes in Discounted Future Net Cash Flows
12 Months Ended
February 28, 2023 February 28, 2022
Standardized measure of discounted future net cash flows at the beginning of the year $ 6,191,944 $ 1,648,418
Extensions, discoveries and improved recovery, less related costs - 906,390
Revisions of previous quantity estimates (11,442,092 ) 44,898
Purchase of minerals in place 8,990,030 -
Net changes in prices and production costs 4,695,284 3,320,241
Accretion of discount 619,194 164,842
Sales of crude oil and natural gas produced, net of production costs (509,461 ) (448,832 )
Changes in future development costs 2,022,097 (267,335 )
Changes in timing of future production 468,968 823,322
Net changes in income taxes - -
Standardized measure of discounted future net cash flows at the end of the year $ 11,035,964 $ 6,191,944

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
During the Company’s fiscal years ended February 28, 2022 and 2023, and since then, no independent accountant who was previously engaged as the principal accountant to audit the Company’s financial statements, and no independent accountant who was previously engaged to audit a significant subsidiary on whom the principal accountant expressed reliance in its report, has resigned (or indicated it has declined to stand for re-election after the completion of the current audit) or was dismissed.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Management’s Evaluation of Disclosure Controls and Procedures
As of the end of the reporting period, February 28, 2023, an evaluation was conducted by Daybreak’s management, including our President and Chief Executive Officer, also serving as our interim principal finance and accounting officer, as to the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Exchange Act. Such disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods specified by the SEC rules and forms. Additionally, it is vital that such information is accumulated and communicated to our management including our President and Chief Executive Officer, in a manner to allow timely decisions regarding required disclosures.
Based on that evaluation, our management concluded that we did not maintain disclosure controls and procedures that were effective in providing reasonable assurances that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 was recorded, processed, summarized and reported within the time periods prescribed by SEC rules and regulations, and that such information was accumulated and communicated to our management to allow decisions regarding the disclosure.
Internal Control Over Financial Reporting
The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Our internal controls over financial reporting include those policies and procedures that:
1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made in accordance with authorizations of management and our Board of Directors; and
3) provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.
Because of the inherent limitations due to, for example, the potential for human error or circumvention of controls, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
Management’s Report on Internal Control Over Financial Reporting
Daybreak’s management, including our President and Chief Executive Officer, also serving as our interim principal finance and accounting officer is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our management assessed the effectiveness of our internal control over financial reporting as of February 28, 2023.
In making this assessment, management used certain criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013). Based on such assessment and those criteria, management believes that the Company’s internal control over financial reporting is not effective as of February 28, 2023. Material weaknesses noted by our management include:
· Inadequate segregation of duties consistent with control objectives and affecting the functions of authorization, recordkeeping, custody of assets, and reconciliation;
· Management dominated by a single individual/small group without compensating controls;
· Limited knowledge and experience of the accounting and financial reporting staff in the field of mergers and acquisitions accounting for a public company;
· The Company does not have adequate procedures and controls in place to ensure the proper timing of financial statements and the financial reporting process.
This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to SEC rules that permit the company to provide only management’s report in this annual report.
Changes in Internal Control over Financial Reporting
There have not been any changes in the Company’s internal control over financial reporting during the quarter ended February 28, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Limitations
Our management does not expect that our disclosure controls or internal controls over financial reporting will prevent all errors or all instances of fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.
Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and any design may not succeed in achieving its stated goals under all potential future conditions.
Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures. Because of the inherent limitation of a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Directors of Daybreak Oil and Gas, Inc.
The following information reflects the business experience of each individual serving on the Board of Directors (the “Board”) of Daybreak Oil and Gas, Inc.
Director
Name
Age
Since
Timothy R. Lindsey
James F. Meara
James F. Westmoreland
Darren Williams
Timothy R. Lindsey has served as a member of the Board of Directors since January 2007. He served as the Company’s Interim President and Chief Executive Officer from December 2007 until his resignation in October 2008. Mr. Lindsey has over 40 years of energy and mineral exploration, technical and executive leadership in global exploration, production, technology, and business development. From March 2005 to the present, Mr. Lindsey has been the Principal of Lindsey Energy and Natural Resources, an independent consulting firm specializing in energy and mining industry issues. From September 2003 to March 2005, Mr. Lindsey held executive positions including Senior Vice-President, Exploration with The Houston Exploration Company, a Houston-based independent natural gas and oil company formerly engaged in the exploration, development, exploitation and acquisition of domestic natural gas and oil properties. From October 1975 to February 2003, Mr. Lindsey was employed with Marathon Oil Corporation, a Houston-based company engaged in the worldwide exploration and production of crude oil and natural gas, as well as the domestic refining, marketing and transportation of petroleum products. During his 27-year tenure with Marathon, Mr. Lindsey held a number of positions including senior management roles in both domestic and international exploration and business development. Mr. Lindsey served as a director and Chairman of the Board of Directors of Revett Mining Company., a publicly listed company with mining activities in Montana from April 2009 until the merger of Revett Mining Company into Helca Mining in June 2015. Mr. Lindsey obtained his Bachelor of Science degree in geology at Eastern Washington University in 1973 and completed graduate studies in economic geology from the University of Montana in 1975. In addition, he completed the Advanced Executive Program from the Kellogg School of Management, Northwestern University, in 1990. Mr. Lindsey is a member of the American Association of Petroleum Geologists, the Rocky Mountain Association of Geologists, the Montana Mining Association, and the American Exploration and Mining Association.
James F. Meara has served as a member of the Board of Directors since March 2008. From 1980 through December 2007, Mr. Meara was employed with Marathon Oil Corporation, a Houston-based company engaged in the worldwide exploration and production of crude oil and natural gas, as well as the domestic refining, marketing and transportation of petroleum products. During his 27-year tenure with Marathon, Mr. Meara moved through a series of posts in the tax department, becoming manager of Tax Audit Systems and Planning in 1988, and in 1995 he was named Commercial Director of Sakhalin Energy in Moscow, Russia. In 2000, Mr. Meara served as Controller and was appointed to Vice President of Tax in January 2002, serving until his retirement in December 2007. Mr. Meara holds a bachelor’s degree in accounting from the University of Kentucky and a master’s degree in business administration from Bowling Green State University, and is a member of the American Institute of Certified Public Accountants.
James F. Westmoreland was elected Chairman of the Board of Directors in 2014, and appointed President and Chief Executive Officer and director in October 2008. He also serves as interim principal finance and accounting officer. Prior to that, he had been our Executive Vice President and Chief Financial Officer since April 2008. He also served as the Company’s interim Chief Financial Officer from December 2007 to April 2008. From August 2007 to December 2007, he consulted with the Company on various accounting and finance matters. Prior to that time, Mr. Westmoreland was employed in various financial and accounting capacities for The Houston Exploration Company for 21 years, including Vice President, Controller and Corporate Secretary, serving as its Vice President and Chief Accounting Officer from October 1995 until its acquisition by Forest Oil Corporation in June 2007. Mr. Westmoreland has almost 40 years of experience in oil and gas accounting, finance, corporate compliance and governance, both in the public and private sector. He earned his Bachelor of Business Administration in accounting from the University of Houston.
Darren Williams was elected to the Board in May 2022, being nominated by the Board of Directors as agreed pursuant to the terms of the Exchange Agreement. Mr. Williams brings over 28 years of experience in various areas in the Oil and Gas industry. In 2021 he was appointed Chief Operating Officer of Black Knight Energy, LLC, a California-based, private energy company focused on the acquisition and development of large, cash flowing oil and natural gas assets across the Lower 48. Prior to that, from 2014 to 2021, Mr. Williams served as Executive Vice President - Operations/Exploration & Development for California Resources Corp (NYSE: CRC), California’s largest independent oil and gas producer. From 1997 to 2014, Mr. Williams held many positions within Marathon Oil Corporation (MRO), domestically as well as internationally. His titles included Africa Exploration Manager President Marathon Upstream Gabon, Vice-President Marathon Oil Investments Limited; Oklahoma Exploration & Production Manager; Gulf of Mexico Exploration & Appraisal Manager; and Geophysicist/Technical Supervisor. Before joining Marathon, Mr. Williams was Geophysicist/Technical Supervisor in London and Houston, TX from 1997 to 2008. From 1994 to 1997 he was Special Projects Geophysicist with Ikon Science. Mr. Williams holds a MSc Basin Evolutions & Dynamics (Petroleum Geology) from Royal Holloway, University of London, UK; and a BSc Geophysics, University of Leicester, UK.
Consideration of Director Nominees.
When analyzing whether directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board of Directors to satisfy its oversight responsibilities effectively in light of the Company’s business and structure, the Governance Committee and the Board focus on the information as summarized in each of the Directors’ individual biographies set forth above.
In particular, the Governance Committee and the Board considered:
· Mr. Lindsey’s over 40-year career as a successful senior executive in the energy industry, his extensive knowledge of the industry and his active participation in energy-related professional organizations are also valuable assets to the Board. His knowledge and expertise in the energy business and management leadership regarding the issues affecting our business have been invaluable to the Board of Directors in overseeing the business affairs of our Company. Further, the Committee believes that his extensive background and service with other public companies in the energy and mining sectors and his technical expertise provide the Board with superior leadership and decision-making skills.
· Mr. Meara’s education, executive leadership roles and 27-year work experience in finance, tax and accounting in the crude oil and natural gas industry provide the knowledge and financial expertise needed to serve on the Board and the Company’s audit committee.
· Mr. Westmoreland’s over 40-year career in various operational, financial, and accounting capacities, including Vice President, Chief Accounting Officer, Controller and Corporate Secretary at a public crude oil and natural gas company along with his recent experience as President, Chief Executive Officer, Executive Vice President, and Chief Financial Officer of the Company. The Board also considered his role in reorganizing the Company and his day-to-day management of the Company.
• Mr. William’s over 28 years’ experience in ever increasing roles in various operational and management positions in the oil and gas industry, especially in the California market. With his background and expertise, he will be able to assist the Company in evaluating various opportunities that may be afforded to the Company in the future.
Information About Our Executive Officers
Executive officers are elected annually by our Board and serve at the discretion of the Board. There are no arrangements or understandings between any of the directors, officers, and other persons pursuant to which such person was selected as an executive officer.
The following information concerns our executive officers, including the business experience of each during the past five years:
Executive
Name
Age
Since
Office
James F. Westmoreland
Chairman of the Board, President and Chief Executive Officer
Bennett W. Anderson
Chief Operating Officer
James F. Westmoreland was elected Chairman of the Board of Directors in 2014, and appointed President and Chief Executive Officer and director in October 2008. He also serves as interim principal finance and accounting officer. Prior to that, he had been our Executive Vice President and Chief Financial Officer since April 2008. He also served as the Company’s interim Chief Financial Officer from December 2007 to April 2008. From August 2007 to December 2007, he consulted with the Company on various accounting and finance matters. Prior to that time, Mr. Westmoreland was employed in various financial and accounting capacities for The Houston Exploration Company for 21 years, including Vice President, Controller and Corporate Secretary, serving as its Vice President and Chief Accounting Officer from October 1995 until its acquisition by Forest Oil Corporation in June 2007. Mr. Westmoreland has almost 40 years of experience in oil and gas accounting, finance, corporate compliance and governance, both in the public and private sector. He earned his Bachelor of Business Administration in accounting from the University of Houston.
Bennett W. Anderson was appointed Chief Operating Officer in 2006. Prior to that time, he was a private investor from 2002 - 2006. He served as a Senior Vice President with Novell, Inc. from 1998-2002. Mr. Anderson’s duties included product direction, strategy and market direction, and training and support for the field sales staff. From 1978 to 1982, Mr. Anderson worked as a rig hand and was involved in drilling over a dozen wells in North Dakota. He holds a Bachelor of Science from Brigham Young University in Computer Science and graduated with University Honors of Distinction.
Family Relationships
There are no family relationships between any director, executive officer, or person nominated or chosen by the Company to become a director or executive officer.
Involvement in Certain Legal Proceedings
With respect to Darren Williams, current director, in July 2020 California Resources Corporation, where Mr. Williams served as Executive Vice President, filed for voluntary Chapter 11 bankruptcy protection as part of a debt restructuring undertaken in agreement with a majority of its creditors. California Resources Corporation cited an unsustainable debt burden given the prevailing commodity markets at the time as the reason for the filing and restructuring.
As required by Item 401(f) of Regulation S-K, none of Daybreak’s other current directors or Executive Officers has, during the past ten years, had:
(f) Involvement in certain legal proceedings. Describe any of the following events that occurred during the past ten years and that are material to an evaluation of the ability or integrity of any director, person nominated to become a director or executive officer of the registrant:
(1) A petition under the Federal bankruptcy laws or any state insolvency law was filed by or against, or a receiver, fiscal agent or similar officer was appointed by a court for the business or property of such person, or any partnership in which he was a general partner at or within two years before the time of such filing, or any corporation or business association of which he was an executive officer at or within two years before the time of such filing;
(2) Such person was convicted in a criminal proceeding or is a named subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);
(3) Such person was the subject of any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from, or otherwise limiting, the following activities:
(i) Acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant, any other person regulated by the Commodity Futures Trading Commission, or an associated person of any of the foregoing, or as an investment adviser, underwriter, broker or dealer in securities, or as an affiliated person, director or employee of any investment company, bank, savings and loan association or insurance company, or engaging in or continuing any conduct or practice in connection with such activity;
(ii) Engaging in any type of business practice; or
(iii) Engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of Federal or State securities laws or Federal commodities laws;
(4) Such person was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting for more than 60 days the right of such person to engage in any activity described in paragraph (f)(3)(i) of this section, or to be associated with persons engaged in any such activity;
(5) Such person was found by a court of competent jurisdiction in a civil action or by the Commission to have violated any Federal or State securities law, and the judgment in such civil action or finding by the Commission has not been subsequently reversed, suspended, or vacated;
(6) Such person was found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law, and the judgment in such civil action or finding by the Commodity Futures Trading Commission has not been subsequently reversed, suspended or vacated;
(7) Such person was the subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of:
(i) Any Federal or State securities or commodities law or regulation; or
(ii) Any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or
(iii) Any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or
(8) Such person was the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act (15 U.S.C. 78c(a)(26))), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act (7 U.S.C. 1(a)(29))), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.
Consideration of Nominees and Qualifications for Nominations to the Board of Directors
Our Corporate Governance Guidelines, which can be found under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com, contain Board membership criteria that apply to nominees recommended by the Nominating and Corporate Governance Committee (the “Governance Committee”) for a position on the Board. The Corporate Governance Guidelines state that the Board’s Governance Committee is responsible for making recommendations to the Board concerning the appropriate size and composition of the Board, as well as for recommending to the Board nominees for election or re-election to the Board. In formulating its recommendations for Board nominees, the Governance Committee will assess each proffered candidate’s independence and weigh his or her qualifications in accordance with the Governance Committee’s stated Qualifications for Nominations to the Board of Directors, which can be found under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com.
Ethical Business Conduct Policy Statement and Code of Ethics for Senior Financial Officers
All of our employees, officers and directors are required to comply with our Ethical Business Conduct Policy Statement to help ensure that our business is conducted in accordance with the highest standards of moral and ethical behavior. Our Ethical Business Conduct Policy covers all areas of professional conduct including:
· 	 Conflicts of interest;
· 	 Customer relationships;
· 	 Insider trading of our securities;
· 	 Financial disclosure;
· 	 Protection of confidential information; and
· 	 Strict legal and regulatory compliance.
Our employees, officers and directors are required to certify their compliance with our Ethical Business Conduct Policy Statement once each year.
In addition to the Ethical Business Conduct Policy Statement, all members of our senior financial management, including our President and Chief Executive Officer, have agreed in writing to our Code of Ethics for Senior Financial Officers, which prescribes additional ethical obligations pertinent to the integrity of our internal controls and financial reporting process, as well as the overall fairness of all financial disclosures.
The full text of our Ethical Business Conduct Policy Statement, and the Code of Ethics for Senior Financial Officers, are available under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com and are also available upon request, without charge, by contacting the Corporate Secretary at Daybreak Oil and Gas, Inc., 1414 S. Friendswood Dr., Suite 212, Friendswood, TX 77546.
We intend to promptly disclose via a Current Report on Form 8-K or an update to our website information about any amendment to, or waiver of, these codes with respect to our executive officers and directors.
Audit Committee
The Audit Committee is responsible for monitoring the integrity of the Company’s financial reporting standards and practices and its financial statements, overseeing the Company’s compliance with ethics and legal and regulatory requirements, and selecting, compensating, overseeing, and evaluating the Company’s independent registered public accountants.
During the fiscal year ended February 28, 2023, the Audit Committee met seven times. The Audit Committee operates under a charter that is available under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com and also upon request, without charge, by contacting the Corporate Secretary at Daybreak Oil and Gas, Inc., 1414 S. Friendswood Dr., Suite 212, Friendswood, TX 77546
The Audit Committee’s purpose is to assist the Board in fulfilling its responsibility to oversee management activities related to accounting and financial reporting policies, internal controls, auditing practices and related legal and regulatory compliance. In that connection, the Audit Committee is directly responsible for the appointment, compensation, retention, and oversight of the work of our independent registered public accountants for the purposes of preparing or issuing an audit report or performing other audit, review or attest services. The Audit Committee determines the independence of our independent registered public accountants, and our independent registered public accountants report directly to the Audit Committee, which also must review and pre-approve the current year’s audit and non-audit fees. The Audit Committee has the authority to select, retain and/or replace consultants to provide independent advice to the Committee. The Audit Committee discusses quarterly with the independent auditor the applicable requirements of the Public Company Accounting Oversight Board (“PCAOB”) and the Commission.
The Audit Committee charter prescribes the Committee’s functions, which include the following:
· Maintaining our compliance with legal and regulatory requirements relating to financial reporting accounting and controls;
· Overseeing our whistleblower procedures;
· Overseeing the pre-approval of audit fees;
· Appointing and overseeing our independent registered public accountants;
· Overseeing our internal audit function;
· Overseeing the integrity of our financial reporting processes, including the Company’s internal controls;
· Assessing the effect of regulatory and accounting initiatives, as well as any off-balance sheet structures, on our financial statements;
· Reviewing our earnings press releases, guidance and SEC filings;
· Overseeing our risk analysis and risk management procedures;
· Resolving any disagreements between management and the independent registered public accountants regarding financial reporting;
· Overseeing our business practices and ethical standards;
· Preparing an audit committee report to be included in our public filings pursuant to applicable rules and regulations of the SEC.
Timothy R. Lindsey, James F. Meara, and Darren Williams serve on the Audit Committee. All members of the Audit Committee satisfy all SEC criteria for independence and meet all financial literacy and other SEC and NYSE American requirements for Audit Committee service. The Board has determined that James F. Meara is an “audit committee financial expert” as defined by the rules of the SEC.
Delinquent Section 16(a) Reports
Section 16(a) of the Securities Exchange Act of 1934 requires our directors, officers and beneficial owners of more than 10% of our Common Stock, to file initial reports of ownership and reports of changes in ownership of Common Stock on Forms 3, 4 and 5 with the SEC. Directors, officers and beneficial owners of more than 10% of our Common Stock are required by SEC regulations to furnish us with copies of any forms that they file. We assist our directors and executive officers in complying with these requirements and are required to disclose in this Annual Report the failure to file these reports on behalf of any reporting person when due.
With respect to our officers and directors, based on our review of related information, we believe that no such Section 16(a) reports needed to be filed during the fiscal year ended February 28, 2023.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Executive Officers
Named Executive Officers
Named executive officers consist of any individual who served as our Chief Executive Officer during the fiscal year ended February 28, 2023, and up to two of our most highly compensated executive officers other than the Chief Executive Officer during the fiscal year ended February 28, 2023. For the fiscal year ended February 28, 2023, under the smaller reporting company rules, our named executive officers are James F. Westmoreland, President and Chief Executive Officer; and Bennett W. Anderson, our Chief Operating Officer (collectively, the “Named Executive Officers”). Executive officers are elected annually by our Board and serve at the discretion of the Board. There are no arrangements or understandings between any of the directors, officers, and other persons pursuant to which any such person was selected as an executive officer.
The following information concerns our Named Executive Officers for the fiscal year ended February 28, 2023.
Executive
Name
Age
Since
Office
James F. Westmoreland
President and Chief Executive Officer
Bennett W. Anderson
Chief Operating Officer
EXECUTIVE COMPENSATION
We currently qualify as a “smaller reporting company” as such term is defined in Rule 405 of the Securities Act and Item 10 of Regulation S-K. Accordingly, and in accordance with relevant SEC rules and guidance, we have elected, with respect to the disclosures required by Item 402 (Executive Compensation) of Regulation S-K, to comply with the disclosure requirements applicable to smaller reporting companies. The following Compensation Overview is not comparable to the “Compensation Discussion and Analysis” that is required of SEC reporting companies that are not smaller reporting companies.
Compensation Overview
This Compensation Overview discusses the material elements of the compensation awarded to, earned by or paid to our executive officers, and the Compensation Committee’s role in the design and administration of these programs and policies in making specific compensation decisions for our executive officers, including officers who are considered to be “Named Executive Officers” during the fiscal year ended February 28, 2023.
General Discussion of Executive Compensation
The Compensation Committee is responsible for establishing, implementing, and continually monitoring adherence to our compensation philosophy. In doing so, the Compensation Committee reviews and approves, on at least, an annual basis the evaluation process and compensation structure for the Company’s Named Executive Officers. The Committee reviews and recommends to the Board the annual compensation, including salary, and any incentive and/or equity-based compensation for such officers. The Committee also provides oversight of management’s decisions concerning the performance and compensation of other employees.
The current and future objectives of Daybreak’s compensation program are to keep compensation aligned with Daybreak’s cost structure, financial position, and strategic business and financial objectives. Daybreak’s financial position and its plans going forward are integral to the design and implementation of officer and employee compensation. Therefore, the Compensation Committee reviews the Company’s cash flow with the Chief Executive Officer at a minimum, on an annual basis, in order to evaluate the current compensation program and its effects on the financial position of the Company. In short, we pay what we can afford and adjust accordingly as conditions warrant. In deciding on the type and amount of compensation for each Named Executive Officer, the Compensation Committee focuses on the market value of the role and pay of the individual, along with the Company’s cost structure and financial position.
For the fiscal years ended February 28, 2023, February 28, 2022, and February 28, 2021, compensation to our Named Executive Officers consisted solely of base salaries. The Board, with the assistance of the Compensation Committee, has reviewed the compensation structure of the Company’s Named Executive Officers. After taking into consideration the Company’s current cost
structure, financial position, and current compensation structure (discussed under the heading “Narrative Disclosure to Summary Compensation Table, Base Salaries”), the Board approved continuation of the compensation structure. In addition, the full Board reviewed and discussed, with the assistance of the CEO, the performance and compensation of all of Daybreak’s employees.
With the increase in cash flow during the fiscal year ended February 28, 2023, the Board, with the assistance of the Compensation Committee and the CEO, increased all employee salaries, with the exception of our President and CEO, who agreed to keep his salary at its current level until an increase in shareholder value is achieved.
We do not provide any perquisites or other personal benefits to our named executive officers, or any of our employees.
For the fiscal years ended February 28, 2023, February 28, 2022, and February 28, 2021, compensation to our Named Executive Officers consisted solely of base salaries. The Board, with the assistance of the Compensation Committee, has reviewed the compensation structure of the Company’s Named Executive Officers. After taking into consideration the Company’s current cost structure, financial position, and current compensation structure (discussed under the heading “Narrative Disclosure to Summary Compensation Table, Base Salaries”), the Board approved continuation of the current compensation structure. In addition, the full Board reviewed and discussed the performance and compensation of all of Daybreak’s employees.
The elements of compensation are described in more detail under “Narrative Disclosure to Summary Compensation Table”, below, beginning on page 97 of this Form 10-K.
Summary Compensation Table
The following table sets forth summary information concerning the compensation paid to or earned by our Named Executive Officers during the fiscal years ended February 28, 2023, and February 28, 2022.
Name and Principal Position
Fiscal Year
Ended
Salary
($)
Bonus
($)
All Other
Compensation
($)
Total
($)
James F. Westmoreland(1)
February 28, 2023
75,000(2)
-
-
75,000(2)
President and Chief Executive Officer
February 28, 2022
75,000(3)
-
-
75,000(3)
Bennett W. Anderson0
February 28, 2023
72,350(4)
-
-
72,350(4)
Chief Operating Officer
February 28, 2022
44,700(5)
-
-
44,700(5)
(1) Mr. Westmoreland commenced his employment on December 14, 2007 as the Company’s interim Chief Financial Officer and was appointed Executive Vice President and Chief Financial Officer in April 2008. He was appointed to the position of President and Chief Executive Officer of the Company in October 2008 and continues to serve as the interim principal finance and accounting officer of the Company.
(2) On August 22, 2019, due to the cost structure and financial position of the Company, Mr. Westmoreland’s annual base salary was reduced by 50% to $75,000. This annual base salary remains at this amount until an increase in shareholder value is achieved. During the fiscal year ended February 28, 2023, Mr. Westmoreland was paid $75,000.
(3) As a result of the effect of low oil prices on the Company’s cash flow; and the lack of outside financing, Mr. Westmoreland deferred partial salary payments during the fiscal year ended February 28, 2022 . During the fiscal year ended February 28, 2022, Mr. Westmoreland was paid $59,375; and $15,625 was accrued, but not paid. The accrued liability was recorded on our balance sheet under accrued liabilities. During the fiscal year ended February 28, 2022, Mr. Westmoreland agreed to forgive the remaining $53,125 of accrued but unpaid salary.
(4) As a result of the increase in cash flow from the Reabold California, LLC transactions as well as higher oil prices and increasing responsibilities, Mr. Anderson’s salary was increased to $100,000 per year, effective in September 2022. During the fiscal year ended February 28, 2022, Mr. Anderson was paid $72,350.
(5) As a result of the effect of low oil prices on the Company’s cash flow; and the lack of outside financing, Mr. Anderson deferred partial salary payments during the fiscal year ended February 28, 2022, Mr. Anderson was paid $35,388; and $9,312 was accrued, but not paid. During the fiscal year ended February 28, 2021, Mr. Anderson was paid $22,350; and $22,350 was accrued, but not paid. On December 15, 2021, Mr. Anderson agreed to convert his total of $189,546 in accrued but unpaid salary into 421,214 shares of Common Stock. These shares were issued on February 22, 2022.
Narrative Disclosure to Summary Compensation Table
Base Salaries
The Board, with the assistance of the Compensation Committee, has reviewed the compensation structure of the Company’s Named Executive Officers. After taking into consideration the Company’s cost structure and financial position, on August 22, 2019, the Compensation Committee, along with the Board of Directors entered into a series of arrangements with its Named Executive Officers, as well as its Board of Directors and other key employees. As part of these efforts, Mr. Westmoreland agreed to forgive deferred salary owed him by the Company, totaling $943,750, and to reduce his annual base salary by 50%, to $75,000. The Company also ended its policy of deferring base salary amounts of its other Named Executive Officer and other employees, and temporarily reduced such executive and employee’s base salaries by 50% but continued to owe previously deferred amounts to these individuals. These changes were agreed to by each affected person and were deemed to take effect as of June 1, 2019.
On November 22, 2021, the Compensation Committee, along with the Nominating and Corporate Governance Committee, and Board of Directors agreed to a debt-to-equity exchange for Daybreak Common Stock with its directors, executive officers, and other employees with respect to the forgiveness and conversion of related party debts. The agreements include conversion of all deferred salary owed to its executive officers and key employees, into shares of the Company’s Common Stock at a conversion rate of $0.45 per share of Common Stock (the “Related Party Debt Conversion”). All the members of the Compensation Committee and all the members of the Nominating and Corporate Governance Committee, reviewed the Related Party Debt Conversion under the Company’s Related Party Transactions Policy, and was satisfied that it has been fully informed as to the material facts of the debt exchange, and that the exchange was fair to the Company and its shareholders. On December 15, 2021, the Company finalized these agreements, and Mr. Westmoreland agreed to forgive the remaining $53,125 of accrued but unpaid salary, and Mr. Anderson exchanged $189,546 of accrued but unpaid salary owed to him into 421,214 shares of Common Stock.
The Board, with the assistance of the Compensation Committee, has continued to review the compensation structure of the Company’s Named Executive Officers in alignment with the Company’s financial position. After taking into consideration the Company’s cost structure and financial position, in August 2022, the Compensation Committee, along with the Board of Directors agreed that, as a result of the increase in cash flow from the Reabold California, LLC transactions as well as higher oil prices and increasing responsibilities, Mr. Anderson’s salary was increased to $100,000 per year, effective September 1, 2022. Subsequently, beginning Ju1y 1, 2023, all employees and Named Executive Officers salaries were temporarily cut back by 75% due to a change in the Company’s financial position, with the unpaid salaries being accrued.
Other: Securities Trading
We have a policy that executive officers and directors may not purchase or sell exchange traded options to sell or buy Daybreak stock (“puts” and “calls”), engage in short sales with respect to Daybreak stock or otherwise hedge equity positions in Daybreak (e.g., by buying or selling straddles, swaps or other derivatives).
Outstanding Equity Awards at Fiscal Year-End
The Company has no unvested outstanding restricted stock awards held by our Named Executive Officers for the fiscal year ended February 28, 2023. The Company has no qualified or nonqualified stock option plans and has no outstanding stock options.
Executive Employment Agreements
Our employees, including our named executive officers, are employed at-will and do not have employment agreements. Our Compensation Committee believes that employment agreements encourage a short-term rather than long-term focus, provide inappropriate security to the executives or employees and undermine the team spirit of the organization.
Payments Upon Termination or Change in Control
We do not have any agreements with any of our named executive officers that affect the amount paid or benefits provided following termination or a change in control.
Pension Plan Benefits
The Company does not have any pension plans that oblige the Company to make payments or provide benefits at, following or in connection with retirement of its Directors, Officers, or employees.
Deductibility of Compensation
Section 162(m) of the Internal Revenue Code (the “Code”) places a $1 million per executive cap on the compensation paid to executives that can be deducted for tax purposes by publicly traded corporations each year. Amounts that qualify as “performance based” compensation under Section 162(m)(4)(c) of the Code are exempt from the cap and do not count toward the $1 million limit if certain requirements are satisfied. At our current named executive officer compensation levels, we do not presently anticipate that Section 162(m) of the Code will be applicable, and accordingly, our Compensation Committee did not consider its impact in determining compensation levels for our Named Executive Officers for the fiscal year ended February 28, 2023.
Stock Compensation Expense
Stock awards are accounted for under FASB ASC 718, “Stock Compensation”. Under ASC 718, compensation for all share-based payment awards is based on estimated fair value at the grant date. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.
CEO PAY RATIO
As a “smaller reporting company”, we are not required to disclose the ratio of its CEO’s annual total compensation to the Company’s median employee’s annual total compensation. However, in comparing the current annual total compensation of our CEO of $75,000, and the fiscal year ending February 28, 2024 annual total compensation of our median compensated employees of $100,000, the result of this calculation was a CEO Pay Ratio of 0.75 to 1.
Employee, Officer and Director Insider Trading
The Company has adopted a policy regarding insider trading both to satisfy the Company’s obligation to prevent insider trading and to help Company personnel avoid the severe consequences associated with violations of insider trading laws. The Company considers it improper and inappropriate for any director, officer, or other employee of the Company to engage in short-term or speculative transactions in the Company’s securities. It therefore is the Company’s policy that directors, officers and other employees may not engage in short sales, publicly traded options, margins accounts and pledges, and hedging transactions. The full text of our Securities Law Compliance Policy is available under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com and is also available upon request, without charge, by contacting the Corporate Secretary at Daybreak Oil and Gas, Inc., 1414 S. Friendswood Dr., Suite 212, Friendswood, TX 77546.
DIRECTOR COMPENSATION
The Board has adopted a Non-Employee Director Compensation Policy (the “Director Compensation Policy”) under which it compensates directors that are not employees of the Company. The Compensation Committee re-evaluates the policy at least annually, taking into consideration the Company’s financial status.
As a result of the Company’s limited available cash, the Board of Directors, beginning in June 2010 postponed receiving payments of meeting fees and quarterly retainer fees until cash flow would allow. On August 22, 2019, the Board of Directors agreed to forgive 50% of accrued, deferred board fees owed to them, and to temporarily discontinue future board fees, deemed to take effect as of June 1, 2019. On February 22, 2022, the members of the Board of Directors converted the remaining 50% of their accrued but unpaid fees into Common Stock. The Compensation Committee, along with the Board of Directors continues to evaluate the metrics under the Director Compensation Policy, whereas each director who is not an employee or officer of the Company (“non-employee director”) is entitled to receive an annual cash retainer of $9,000. Each non-employee director also receives $500 per Board meeting attended and $500 per committee meeting attended. Additionally, under this Policy, the chairman of the Audit Committee would receive an additional annual retainer of $1,500 and all other committee chairmen would receive an additional $750 annual retainer. Additionally, directors are reimbursed for any out-of-pocket expenses incurred in attending board and committee meetings. For the fiscal year ended February 28, 2023, the directors received no cash compensation for their services. This policy will stay in place; however the discontinuance of all board fees is ongoing during the 2024 fiscal year and will continue to be monitored for any changes in the Company’s cash position.
On November 22, 2021, the Compensation Committee, along with the Nominating and Corporate Governance Committee, and Board of Directors agreed to a debt-to-equity exchange with its directors, executive officers, and other employees with respect to the forgiveness and conversion of related party debts. These agreements include conversion of all accrued, deferred board fees owed to the non-employee directors, into shares of the Company’s Common Stock at a conversion rate of $0.45 per share of Common Stock (the “Related Party Debt Conversion”).
All the members of the Compensation Committee and all the members of the Nominating and Corporate Governance Committee, reviewed the Related Party Debt Conversion under the Company’s Related Party Transactions Policy, and were satisfied that it had been fully informed as to the material facts of the Related Party Debt Conversion, and that the Related Party Debt Conversion was fair to the Company and its shareholders. On December 15, 2021, the Company finalized the agreements with its directors, executive officers, and other employees with respect to the forgiveness and conversion of related party debts into shares of the Company’s Common Stock. On February 22, 2022, the members of the Board of Directors converted the above mentioned remaining 50% of their accrued but unpaid fees into Common Stock.
As a result of the debt-for-equity exchange, the directors received shares of Common Stock of the Company in full payment and satisfaction of their deferred fees, as follows:
Name Shares Issued in Debt-for-Equity Exchange
Timothy R. Lindsey 148,819
James F. Meara 168,889
James F. Westmoreland(1) -
Darren Williams(2) -
(1) As an employee director, Mr. James F. Westmoreland did not receive any compensation for serving on the Board of Directors during the fiscal year ended February 28, 2023. Only non-employee directors receive compensation for serving on the Board of Directors.
(2) Mr. Williams was elected to the Board on May 20, 2022, effective as of May 25, 2022.
The Board of Directors continue to forgo the payment of any fees or retainers until a more positive cash flow is seen by the Company and positive effects are seen by the shareholders.
The Compensation Committee will re-evaluate its director compensation policies periodically, and at least annually, taking into consideration the Company’s financial status. All details can be seen in the Director Summary Compensation Table below.
DIRECTOR SUMMARY COMPENSATION TABLE
The table below provides information concerning compensation paid to, or earned by, directors for the fiscal year ended February 28, 2023(1).
Name
Fees Earned
Or
Paid in Cash2)
($)
Stock Awards
($)
All other
compensation
($)
Total(2)
($)
Timothy R. Lindsey
-
-
-
James F. Meara
-
-
-
James F. Westmoreland(1)
-
-
-
Darren Williams(3)
-
-
-
(1) As an employee director, Mr. James F. Westmoreland did not receive any compensation for serving on the Board of Directors during the fiscal year ended February 28, 2023. Only non-employee directors receive compensation for serving on the Board of Directors.
(2) As a result of the Company’s limited available cash, the Board of Directors, beginning in June 2010 postponed receiving payments of meeting fees and quarterly retainer fees until cash flow would allow. On August 22, 2019, the Board of Directors agreed to forgive 50% of accrued, deferred board fees owed to them, and to temporarily discontinue future board fees, deemed to take effect as of June 1, 2019. The Compensation Committee re-evaluates the policy at least annually, taking into consideration the Company’s financial status. On February 22, 2022, the members of the Board of Directors converted the remaining 50% of their accrued but unpaid fees into Common Stock as part of the Related Party Debt Conversion described above.
(3) Mr. Williams was elected to the Board on May 20, 2022, effective as of May 25, 2022.
REPORT OF THE COMPENSATION COMMITTEE
As a smaller reporting company, we are not required to provide the information otherwise required by this Item.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
As a smaller reporting company, we are not required to provide the information otherwise required by this Item.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Securities Authorized for Issuance Under Equity Compensation Plans
None.
Security Ownership of Certain Beneficial Owners, Executive Management and Directors
Our four directors and officers of the Company together own and control about 3% percent of our outstanding Common Stock.
Our shareholders do not have the right to cumulative voting in the election of our directors. Cumulative voting could allow a minority group to elect at least one director to our Board. Because there is no provision for cumulative voting, a minority group will not be able to elect any directors. Conversely, if our principal beneficial shareholders and directors wish to act in concert, they would be able to vote to appoint directors of their choice, and otherwise directly or indirectly control the direction and operation of the Company.
As of January 22, 2024, based on information available to the Company, the following tables shows the beneficial ownership of the Company’s voting securities (Common Stock) by: (i) any persons or entities known by management to beneficially own more than 5% of the outstanding shares of the Company’s Common Stock; (ii) each current director and director nominee of the Company; (iii) each current executive officer of the Company named in the Summary Compensation Table appearing on page 96; and (iv) all of the current directors and executive officers of Daybreak as a group. The address of each of the beneficial owners, except where otherwise indicated, is the Company’s address. Unless otherwise indicated, each person shown below has the sole power to vote and the sole power to dispose of the shares of voting stock listed as beneficially owned.
Security Ownership of Certain Beneficial Owners
The following table shows the beneficial owners of five percent or more of the Company’s Common Stock, based on information available as of January 22, 2024.
Class of Stock Name and Address of Beneficial of Beneficial Owner
Amount and
Nature of
Beneficial
Ownership(1,2)
Warrants
Currently
Exercisable or
Exercisable
Within 60 Days
Total
Beneficial
Holdings
Percent of
Class*
Common
Gaelic Resources Ltd.(1) 160,964,489 - 160,964,489
8th Floor, 20 Primrose Street, London, EC2A 2EW
Portillion Capital Ltd(2) 128,125,000
128,125,000
Level 33, 25A Canadian SQ., Canary Wharf London E14 5LQ
Kamran Sattar(3) 27,764,706
27,764,706
Red Roofs Traps Ln,
London KT3 4RY United Kingdom
To reflect “beneficial ownership” as defined in Rule 13d-3 promulgated under the Securities Exchange Act
*Percent of class is shown only for holdings of 1% or more. Based upon 384,734,902 shares of Common Stock outstanding as of January 22, 2024.
(1) Based on its Form 3 filed on May 27, 2023, and its Schedule 13D filed with the SEC on May 31, 2022, and subsequently amended on June 24, 2022 Gaelic Resources Ltd. (“Gaelic”) owns 160,964,489 shares. Gaelic has sole voting power and sole dispositive power over these shares. On May 25, 2022, Daybreak, Reabold California, LLC, a California limited liability company (“Reabold”), and Gaelic Resources Ltd., a private company incorporated in the Isle of Man and the 100% owner of Reabold (“Gaelic”) closed the transactions contemplated by the Equity Exchange Agreement (the “Exchange Agreement”) dated as of October 20, 2021, amended on February 22, 2022 and May 24, 2022 by and between Daybreak, Reabold, and Gaelic. At the
closing, (i) Gaelic irrevocably assigned and transferred all of its ownership interests in Reabold to Daybreak, and (ii) Daybreak authorized the issuance of 160,964,489 shares of its Common Stock to Gaelic, as a result of which Reabold became a wholly-owned subsidiary of Daybreak and Gaelic. The closing of the Equity Exchange and the transactions contemplated thereby was approved by the Daybreak shareholders at the Special Meeting of Shareholders held on May 20, 2022.
(2) On May 26, 2022, Daybreak completed the sale of 125,000,000 shares of its Common Stock, par value $0.001, to Portillion Capital Ltd. (“Portillion”) for a purchase price of $0.02 per share, or $2,500,000 in the aggregate, pursuant to the previously disclosed Subscription Agreement dated May 5, 2022 (the “Capital Raise”). In connection with the closing of the Capital Raise, Daybreak also paid Portillion certain fees in additional shares of Common Stock. This resulted in Portillion owning a total of 128,125,000 shares of Daybreak Common Stock. According to Portillion, they do not sole voting or dispositive control over these shares. The closing of the Equity Exchange and the transactions contemplated thereby was approved by the shareholders of the Company at the Special Meeting of Shareholders held on May 20, 2022.
(3) On May 5, 2022, Kamran Sattar, the purchaser of a convertible promissory note in the amount of $200,000 (the “Convertible Note”) issued by the Company as of February 15, 2022 notified the Company that it had elected to convert the Convertible Note. The Convertible Note converted by its terms at a price per share of $0.0085, and the total principal balance of the note plus accrued interest, totaling $236,000, converted into 27,764,706 shares of Common Stock, par value, $0.001, of the Company. Mr. Sattar has sole voting power and sole dispositive power over these shares.
Security Ownership of Executive Management and Directors
The following table shows the number of shares of Daybreak Common Stock beneficially owned as of January 22, 2024, by each director, by each executive officer named in the Summary Compensation Table and by all directors and executive officers as a group. Unless otherwise indicated by footnote, we believe, based on the information furnished to us, that the persons named in the table have sole voting and investment power with respect to all shares shown as beneficially owned by them. Unless otherwise provided, the address of each individual listed below is c/o the Company at 1414 S. Friendswood Dr., Suite 212, Friendswood, TX 77546.
Class of Stock Name of Beneficial Owner
Amount and
Nature of
Beneficial
Ownership(1,)
Warrants
Currently
Exercisable or
Exercisable
Within 60 Days(2)
Total
Beneficial
Holdings
Percent of
Class(X)
Common
Timothy R. Lindsey, Director 1,058,819(3)(4) - 1,058,819(3)(4) *
James F. Meara, Director 328,889(3)(5) - 328,889(3)(5) *
James F. Westmoreland, President and Chief Executive Officer and Director 9,925,617(3)(6) - 9,925,617(3)(6) 2.6
Bennett W. Anderson, Chief Operating Officer 821,214(3)(7) - 821,214(3)(7) *
Darren Williams, Director
*
All (5) directors and executive officers as a group 12,134,539(3)(8) - 12,134,539(3)(8) 3.2
To reflect “beneficial ownership” as defined in Rule 13d-3 promulgated under the Securities Exchange Act
* Percent of class is shown only for holdings of 1% or more. Based upon 384,734,902 shares of Common Stock outstanding as of January 22, 2024. Includes shares believed to be held directly or indirectly by directors and executive officers that have voting power and/or the power to dispose of such shares. Unless otherwise noted, each individual or member of the group has the sole power to vote and the sole power to dispose of the shares listed as beneficially owned.
(1) To reflect “beneficial ownership” as defined in Rule 13d-3 promulgated under the Securities Exchange Act of 1934, this column includes shares as to which each individual has (A) sole voting power, (B) shared voting power, (C) sole investment power, or (D) shared investment power, and (E) the right to acquire within sixty days (from January 22, 2024).
(2) Based upon 384,734,902 shares of Common Stock outstanding as of January 22, 2024, and right to acquire and within 60 days of January 22, 2024
(3) On December 15, 2021, the Company finalized agreements with its directors, executive officers, and other employees with respect to the forgiveness and conversion of related party debts into shares of the Company’s Common Stock (the “Debt Conversion”) at a conversion rate of $0.45 per share of Common Stock. There was a total of 3,105,851 shares issued to the current directors and executive officers of Daybreak as a group in exchange for $1,397,601. Completing this Debt Conversion was a condition to closing the Equity Exchange.
(4) This includes 148,819 shares acquired under the terms of the Debt Conversion, as detailed above, for conversion of $66,969 of owed but unpaid director fees.
(5) This includes 168,889 shares acquired under the terms of the Debt Conversion, as detailed above, for conversion of $76,000 of owed but unpaid director fees.
(6) This includes 6,958,758 shares acquired under the terms of a Convertible Note Purchase Agreement with Mr. Westmoreland, the Company’s Chairman, President and Chief Executive Officer. He loaned the Company $27,835 for general operating expenses under a Convertible Note Purchase Agreement. The Note had a maturity date of 180 days, or July 12, 2020 and carried no interest, fees or penalties. On July 13, 2020, the note payable was converted to 6,958,758 shares of the Company’s Common Stock. The note payable had a conversion formula of $0.004 per share. This total also includes shares acquired under the terms of the Debt Conversion, as detailed above, for conversion of $514,986.35 in an outstanding 12% subordinated note and accrued interest into 1,144,414 shares of Common Stock.; and conversion of a production payment of $550,100 he bought from the Company into 1,222,444 shares of Common Stock.
(7) This includes 421,214 shares acquired under the terms of the Debt Conversion, as detailed above, for conversion of $189,546 of owed but unpaid salary compensation.
(8) There was a total of 3,105,781 shares issued to the current directors and executive officers of Daybreak as a group in exchange for $1,397,601.
changes in Control
None.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Transactions with Related Persons, Promoters and Certain Control Persons
The Board adopted a policy prescribing procedures for review, approval and monitoring of transactions involving Daybreak and “related persons” (directors and executive officers or their immediate family members, or shareholders owning 5% (five percent) or greater of our outstanding stock). The Policy Statement Regarding Related Party Transactions of Daybreak Oil and Gas, Inc. (“Related Party Transactions Policy”) supplements the conflict of interest provisions in our Ethical Business Policy Conduct Statement and Corporate Governance Guidelines. The Board has determined that the Governance Committee is best suited to review and consider for approval related party transactions, although the Board may instead determine that a particular related party transaction be reviewed and considered for approval by a majority of disinterested directors.
The Related Party Transactions Policy covers any related person transaction that involves amounts exceeding $50,000 in which a related person has a direct or indirect material interest. In addition, the Related Party Transactions Policy applies specifically to transactions involving Daybreak and any of the following:
(1) all officers;
(2) directors and director nominees;
(3) 5% shareholders;
(4) immediate family members of the foregoing individuals (broadly defined to include any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law);
(5) any entity controlled by any of the individuals in (1), (2), (3) or (4) above (whether through ownership, management authority or otherwise); and
(6) certain entities at which any of the individuals in (1), (2), (3) or (4) above is employed (generally, if the individual employed is directly involved in the negotiation of the transaction, has or shares responsibility at such entity for such transaction, or might receive compensation tied to such transaction).
On July 27, 2023, the Company entered into an unsecured Promissory Note (the “Agreement”) in which James F. Westmoreland, the Company’s Chairman, President and Chief Executive Officer, loaned the Company the aggregate principal amount of $60,000.00 (the “Westmoreland Note”).
The Westmoreland Note has a maturity date of July 27, 2024, and carries no interest, fees or penalties. The Company may prepay the Note at any time.
The Company’s Chief Operating Officer, Bennett Anderson is fifty percent (50%) owner in Great Earth Power, a company that provides a portion of the solar power electrical service to Daybreak for its production operations at the East Slopes Project in Bakersfield, California. Great Earth Power began providing a portion of the solar powered electrical service for production operations in California in July 2020. For the twelve months ended February 28, 2023 and February 28, 2022, Mr. Anderson received approximately $7,831 and $10,150, respectively from Great Earth Power.
Mr. Anderson is also a fifty percent (50%) owner in ABPlus Net Holdings, a company that provides tank rentals to Daybreak for its production operations in Kern County, California. ABPlus began providing portable tank rentals to the Company as a part of its water treatment and disposal operations in September 2020. For the twelve months ended February 28, 2023, and February 28, 2022, Mr. Anderson received approximately $5,760 and $6,720, respectively from ABPlus Net Holdings.
Great Earth Power provides solar electricity and ABPlus Net Holdings provides tank rentals to Daybreak at very reasonable rates, saving the Company significant money.
On December 15, 2021, the Company finalized agreements with its directors, executive officers, and other employees with respect to the forgiveness and conversion of related party debts into shares of the Company’s Common Stock (the “Related Party Debt Conversion”) at a conversion rate of $0.45 per share of Common Stock. Completing this Debt Conversion was a condition to closing the Equity Exchange Agreement dated as of October 20, 2021 entered into by and among the Company, Reabold California LLC, a California limited liability company (“Reabold”), and Gaelic Resources Ltd., a private company incorporated in the Isle of Man and the 100% owner of Reabold (“Gaelic”), pursuant to which Daybreak will acquire Reabold in exchange for issuing 160,964,489 shares of its Common Stock to Gaelic (the foregoing transaction, the “Equity Exchange”).
As part of this agreement, Mr. Westmoreland converted $514,986 in an outstanding debt under a 12% subordinated note and accrued interest into 1,144,414 shares of Common Stock; and agreed to convert a production payment of $550,100 that he purchased from the Company, into 1,222,444 shares of Common Stock. Also on December 15, 2022, Mr. Westmoreland agreed to forgive the Company of $43,192 in accrued but not paid past salary, related taxes and expense reimbursements.
Also, under the same Related Party Debt Conversions, Mr. Anderson converted $189,546 in accrued but unpaid salary into 421,214 shares of Common Stock.
Mr. Timothy R. Lindsey and Mr. James F. Mears agreed to convert their accrued, deferred director fees owed to them in the amounts of $66,969; and $76,000; into 148,819, and 168,889 shares of Common Stock, respectively.
All Related Party Debt Conversion shares were issued on February 22, 2022.
All transactions were reviewed and approved by the Company’s Board of Directors, including all disinterested directors, all the members of the Compensation Committee and all the members of the Nominating and Corporate Governance Committee, and were approved pursuant to the Company’s Related Party Transactions policy.
Director Independence
We seek individuals who are able to guide our operations based on their business experience, both past and present, or their education. Our business model is not complex and our accounting issues are straightforward.
The Governance Committee is delegated with the responsibility to review the independence and qualifications of each member of the Board and its various Committees. Directors are deemed independent only if the Board affirmatively determines that they have no material relationship with Daybreak, directly, or as an officer, shareowner or partner of an organization that has a relationship with us.
The Company has adopted the standards of NYSE American for determining the independence of its directors. The Company is not listed on NYSE American and is not subject to the rules of NYSE American but applies the rules established by NYSE American to establish director independence.
These independence standards specify the relationships deemed sufficiently material to create the presumption that a director is not independent. No director qualifies as independent unless the Company’s Board affirmatively determines that the director does not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In addition, Section 803A of the NYSE American Company Guide (and related commentary) sets forth the following non-exclusive list of persons who shall not be considered independent:
(a) a director who is, or during the past three years was, employed by the Company, other than prior employment as an interim executive officer (provided the interim employment did not last longer than one year);
(b) a director who accepted or has an immediate family member who accepted any compensation from the Company in excess of $120,000 during any period of twelve consecutive months within the three years preceding the determination of independence, other than the following:
(i) compensation for Board or Board committee service,
(ii) compensation paid to an immediate family member who is an employee (other than an executive officer) of the Company,
(iii) compensation received for former service as an interim executive officer (provided the interim employment did not last longer than one year), or
(iv) benefits under a tax-qualified retirement plan, or non-discretionary compensation;
(c) a director who is an immediate family member of an individual who is, or at any time during the past three years was, employed by the Company as an executive officer;
(d) a director who is, or has an immediate family member who is, a partner in, or a controlling shareholder or an executive officer of, any organization to which the Company made, or from which the Company received, payments (other than those arising solely from investments in the Company’s securities or payments under non-discretionary charitable contribution matching programs) that exceed 5% of the organization’s consolidated gross revenues for that year, or $200,000, whichever is more, in any of the most recent three fiscal years;
(e) a director who is, or has an immediate family member who is, employed as an executive officer of another entity where at any time during the most recent three fiscal years any of the issuer’s executive officers serve on the compensation committee of such other entity; or
(f) a director who is, or has an immediate family member who is, a current partner of the Company’s outside auditor, or was a partner or employee of the Company’s outside auditor who worked on the Company’s audit at any time during any of the past three years.
Directors serving on the Company’s audit committee must also comply with the additional, more stringent requirements set forth in Section 803B of the NYSE American Company Guide and Rule 10A-3 of the Securities Exchange Act of 1934, as amended.
Consistent with these considerations, after review of all relevant transactions and/or relationships between each director and any of his family members and Daybreak, its senior management and its independent registered public accountants, the Board affirmatively determined that two of the current directors, Messrs. Timothy R. Lindsey, and James F. Meara are independent. Mr. James F. Westmoreland, our President and Chief Executive Officer, is not independent. Directors serving on the Company’s compensation committee must also comply with the additional, more stringent requirements as set forth in Section 805(c) of the NYSE American Company Guide.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Fees Billed by Independent Registered Public Accountants
A summary of fees for professional services performed by MaloneBailey, LLP (“MaloneBailey”) for the audit of our financial statements for the fiscal years ended February 28, 2023 and February 28, 2022 is set forth in the table below:
Services Rendered
Fees Billed for the
Fiscal Year Ended
February 28 2023
Fees Billed for the
Fiscal Year Ended
February 28 2022
Audit fees
$ 100,000
$ 70,000
Audit-related fees
100,000
-
Tax fees
-
-
All other fees
-
-
Total
$ 200,000
$ 70,000
The Audit Committee has reviewed the nature and scope of the services provided by MaloneBailey and considers the services provided to have been compatible with the maintenance of MaloneBailey’s independence.
The Audit Committee has determined that the scope of services to be provided by MaloneBailey for the year ending February 29, 2024, will generally be limited to audit and audit-related services. The Audit Committee must expressly approve the provision of any service by MaloneBailey outside the scope of the foregoing services.
Pre-Approval Policies and Procedures
The Audit Committee has adopted guidelines for the pre-approval of audit and permitted non-audit services by our independent registered public accountants. The Audit Committee considers annually and approves the provision of audit services by our independent registered public accountants and considers and pre-approves the provision of certain defined audit and non-audit services. The Audit Committee also considers on a case-by-case basis and approves specific engagements that are not otherwise pre-approved. Any proposed engagement that does not fit within the definition of a pre-approved service may be presented to the Chairman of the Audit Committee. The Chairman of the Audit Committee reports any specific approval of services at the next regular Audit Committee meeting. The Audit Committee reviews a summary report detailing all services being provided to Daybreak by its independent registered public accountants. All of the fees and services described above under “audit fees,” “audit-related fees,” “tax fees” and “all other fees” were pre-approved in accordance with the Audit Fee Pre-Approval Policy and pursuant to Section 202 of the Sarbanes-Oxley Act of 2002.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
The following Exhibits are filed as part of the report:
2.1 Equity Exchange Agreement dated October 20, 2021 by and between Daybreak Oil and Gas, Inc., Reabold California LLC, and Gaelic Resources Ltd. (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated October 26, 2021, and filed on October 27, 2021).
2.2 Letter Agreement by and between Daybreak Oil and Gas, Inc., and Gaelic Resources Ltd., effective as of February 14, 2022 (incorporated by reference to Exhibit 2.2 of the Company’s Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15, 2022) to amend the Equity Exchange Agreement dated October 20, 2021 by and between Daybreak Oil and Gas, Inc., Reabold California LLC, and Gaelic Resources Ltd.
2.3 Letter Agreement by and between Daybreak Oil and Gas, Inc., and Gaelic Resources Ltd., effective as of May 24, 2022 (incorporated by reference to Exhibit 2.3 of the Company’s Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15, 2022) to amend the Equity Exchange Agreement dated October 20, 2021 and amended on February 22, 2022 by and between Daybreak Oil and Gas, Inc., Reabold California LLC, and Gaelic Resources Ltd.
3.01 Second Amended and Restated Articles of Incorporation of Daybreak Oil and Gas, Inc. dated May 20, 2022 (incorporated by reference to Exhibit 3.02 of the Company’s Quarterly Report on Form 10-Q for the period ended August 31, 2022, dated October 27, 2022, and filed on 28, 2022.)
3.02 Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on April 9, 2008).
4.01+ Specimen Stock Certificate
4.02 Description of Securities (incorporated by reference to Exhibit 4.02 of the Company’s Quarterly Report on Form 10-Q for the period ended August 31, 2022, dated October 27, 2022, and filed on October 28, 2022.)
4.03 Designations of Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 of the Company’s Form SB-2 on July 18, 2006, and incorporated by reference herein. (filed as part of the Articles of Amendment to the Articles of Incorporation of Daybreak Oil and Gas, Inc. dated June 30, 2006.))
4.04 Form of 12% Subordinated Note due 2015 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on February 3, 2010).
4.05 Form of Warrant in connection with 12% Subordinated Notes (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K, filed on February 3, 2010).
4.06 Form of Amendment to 12% Subordinated Note due 2015 and Warrant to Purchase Shares of Common Stock (incorporated by reference to Exhibit 4.13 of the Company’s Annual Report on Form 10-K for year ended February 28, 2015).
4.07 Form of Second Amendment to 12% Subordinated Note due 2017 and Warrant to Purchase Shares of Common Stock (incorporated by reference to Exhibit 4.14 of the Company’s Annual Report on Form 10-K filed on May 30, 2017).
4.08 Warrant Agreement by and between Daybreak Oil and Gas, Inc., and Bear to Bull Investor Relations, LLC, dated November 27, 2019. (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended November 30, 2019).
10.01 Prospect review and non-competition agreement for California project (incorporated by reference to Exhibit 10vi of the Company’s SB-2/A filed on December 28, 2006).
10.02 Prospect review agreement for California project (incorporated by reference to Exhibit 10x of the Company’s SB-2/A filed on December 28, 2006).
10.03 Form of Subscription Agreement for 12% Subordinated Note due 2015 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on February 3, 2010).
10.04 Promissory Note, dated June 20, 2011, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended August 31, 2011).
10.05 Promissory Note, dated January 31, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland (incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q for the period ended November 30, 2012).
10.06 Credit Line Agreement, dated October 24, 2011, by and between Daybreak Oil and Gas, Inc. and UBS Bank USA (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended November 30, 2011).
10.07 Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended November 30, 2020).
10.08 Promissory Note, dated August 21, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland (incorporated by reference to Exhibit 10.7 of the Company’s Quarterly Report on Form 10-Q for the period ended November 30, 2012).
10.09 Promissory Note, dated December 22, 2020, by and between Daybreak Oil and Gas, Inc. and James Forrest Westmoreland and Angela Marie Westmoreland, Co-Trustees of the James and Angela Westmoreland Revocable Trust (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended November 30, 2020).
10.10 Securities Purchase Agreement dated December 27, 2018 by and between Daybreak Oil and Gas, Inc. and Maximilian Resources, LLC. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on January 3, 2019).
10.11 Production Payment Interest Purchase Agreement dated December 27, 2018 by and among Daybreak Oil and Gas, Inc. and the purchasers named therein. (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed on January 3, 2019).
10.12 Consulting Agreement by and between Daybreak Oil and Gas, Inc., and Bear to Bull Investor Relations, LLC, dated October 8, 2019. (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended August 31, 2019).
10.13 Form of Convertible Note Purchase Agreement and Note, issued by the Company by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland dated as of January 14, 2020. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on January 17, 2020).
10.14 Form of letter agreement regarding conversion of accrued director fees (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended November 30, 2021, filed on January 18, 2022).
10.15 Form of letter agreement regarding conversion of accrued salary (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended November 30, 2021, filed on January 18, 2022).
10.16 Form of letter agreement dated December 3, 2021 by and between Daybreak Oil and Gas, Inc., and James F. Westmoreland regarding conversion of 12% subordinated note (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended November 30, 2021, filed on January 18, 2022).
10.17 Letter agreement by and between Daybreak Oil and Gas, Inc., and James F. Westmoreland regarding conversion of Production Payment Interests (incorporated by reference to Exhibit 10.37 of the Company’s Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15, 2022.)
10.18 Form of letter agreement regarding conversion of the Company’s Series A Preferred shares to convert each Series A Preferred share to three (3) shares of Daybreak’s Common Stock (incorporated by reference to Exhibit 10.38 of the Company’s Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15, 2022).
10.19 Form of letter agreement regarding conversion of accrued and unpaid dividends with respect to the Series A Preferred Stock (the “Series A Conversion”) (incorporated by reference to Exhibit 10.39 of the Company’s Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15, 2022.).
10.20 Form of Promissory Note Agreement, issued by the Company dated as of July 27, 2023. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on January 17, 2020).
10.21 Convertible Note Purchase Agreement by and between Daybreak Oil and Gas, Inc. and the purchaser dated as of February 15, 2022 (incorporated by reference to Exhibit 10.40 of the Company’s Annual Report on Form 10-K for year ended February 28, 2022, filed on June 15, 2022.)
21.1+ Subsidiaries of the Registrant
23.1+ Consent of PGH Petroleum and Environmental Engineers, LLC
23.2+ Consent of PETROTech Resources Company
31.1+ Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1+ Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1+ Reserve Report of PGH Petroleum and Environmental Engineers, LLC, independent petroleum engineering consulting firm, as of February 28, 2023
99.2+ Reserve Report of PETROTech Resources Company, independent petroleum engineering consulting firm, as of February 28, 2023
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Cover Page Interactive Data File - formatted in Inline XBRL and contained in Exhibit 101
+ Filed herewith.
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