ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is management’s assessment
of the current and historical financial and operating results of the Company and of our financial condition. It is intended to provide
information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations
and cash flows and should be read in conjunction with our unaudited financial statements and notes thereto included elsewhere in this
Quarterly Report on Form 10-Q for the three months ended May 31, 2022 and in our Annual Report on Form 10-K for the year ended February
28, 2022. References to “Daybreak”, the “Company”, “we”, “us” or “our” mean
Daybreak Oil and Gas, Inc.
Cautionary Statement Regarding Forward-Looking
Statements
Certain statements contained in our Management’s
Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) 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
fact contained in this MD&A report are inherently uncertain and are forward-looking statements. Statements that relate to results
or developments that we anticipate will or may occur in the future are not statements of historical fact. Words such as “anticipate,”
“believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,”
“predict,” “project,” “will” and similar expressions identify forward-looking statements. Examples
of forward-looking statements include, without limitation, statements about the following:
| · | Our future operating results; |
| · | Our future capital expenditures; |
| · | Our expansion and growth of operations; and |
| · | Our future investments in and acquisitions of crude oil properties. |
We have based these forward-looking statements on
assumptions and analyses made in light of our experience and our perception of historical trends, current conditions, and expected future
developments. However, you should be aware that these forward-looking statements are only our predictions and we cannot guarantee any
such outcomes. Future events and actual results may differ materially from the results set forth in or implied in the forward-looking
statements. Important factors that could cause actual results to differ materially from our expectations include, but are not limited
to, the following risks and uncertainties:
| · | General economic and business conditions; |
| · | National and international pandemics such as the novel coronavirus COVID-19
outbreak; |
| · | Exposure to market risks in our financial instruments; |
| · | Fluctuations in worldwide prices and demand for crude oil; |
| · | Our ability to find, acquire and develop crude oil properties; |
| · | Fluctuations in the levels of our crude oil exploration and development
activities; |
| · | Risks associated with crude oil exploration and development activities; |
| · | Competition for raw materials and customers in the crude oil industry; |
| · | Technological changes and developments in the crude oil industry; |
| · | Legislative and regulatory uncertainties, including proposed changes to
federal tax law and climate change legislation, regulation of hydraulic fracturing and potential environmental liabilities; |
| · | Our ability to continue as a going concern; |
| · | Our ability to secure financing under any commitments as well as additional
capital to fund operations; and |
| · | Other factors discussed elsewhere in this Form 10-Q and in our other public
filings, press releases, and discussions with Company management. |
Our reserve estimates are determined through a subjective
process and are subject to periodic revision.
Should one or more of the risks or uncertainties described
above or elsewhere in our Form 10-K for the year ended February 28, 2022 and in this Form 10-Q for the three months ended May 31, 2022
occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed
in any forward-looking statements. We specifically undertake no obligation to publicly update or revise any information contained in any
forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or
otherwise, except as required by law.
All forward-looking statements attributable to us
are expressly qualified in their entirety by this cautionary statement.
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 acquisition and drilling of commercial grade crude oil and natural gas properties and on 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 have experienced in the last
15 months, 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 and 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. Currently, we are in the process of developing a multi-well oilfield
project in Kern County, California and an exploratory joint drilling project in Michigan.
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 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 described in Item 1A. Risk Factors of our Annual Report on Form
10-K for the fiscal year ended February 28, 2022 and in Part III, Item 1A. Risk Factors of this 10-Q Report. Throughout this Quarterly
Report on Form 10-Q, crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”)
unless otherwise specified, and hydrocarbon totals are expressed in barrels of crude oil equivalent (“BOE”).
Below is brief summary of our crude oil projects in
California. Refer to our discussion in Item 2. Properties, in our Annual Report on Form 10-K for the year ended February 28, 2022 for
more information on our multi-well oilfield project in California and our exploratory joint drilling project in Michigan.
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 at the East Slopes Project since March 2009.
The crude oil produced from our acreage in the Vedder
Sand is considered heavy oil. The crude oil ranges from 14° to 16°
API (American Petroleum Institute) gravity and must be heated to separate and remove water prior to sale. Our 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. During the three months ended May 31, 2022, we had production from 20 crude oil wells. Our average working interest and
net revenue interest (NRI) in these 20 wells is 36.6% and 28.4%, respectively.
We plan on acquiring additional acreage exhibiting
the same seismic characteristics and on trend with the Bear, Black and Dyer Creek reservoirs. 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.
East Slopes Drilling Plans
We plan to spend approximately $435,000 drilling three development wells
in the current 2022-2023 fiscal year; however our actual expenditures may vary significantly from this estimate if our plans for exploration
and development activities change during the year.
Monterey and Contra Costa Counties, California
(Reabold California, LLC)
In May 2022, we acquired Reabold California, LLC (“Reabold”)
from its previous owner. This property includes producing wells in both Monterey and Contra Costa counties of California.
The Burnett Lease as well as the Doud Lease are located
in close proximity to one another in Monterey County. 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 oil being produced
is 19° gravity. We have future plans of drilling one horizontal well on this lease and to convert and old well bore into a salt water disposal
well (“SWDW”). The Doud Lease has four directional well bores with three of those being produced from a depth of 3,300’
from the Doud A Sand zone. The oil being produced is 22° gravity. We have future plans of drilling one additional directional well on this
lease. The SWDW for the Burnett Lease will be utilized for this lease as well.
The Brentwood Lease is located in Contra-Costa County.
This lease is part of a geological feature named the Meganos Unconformity. There are presently producing two directional wells from this
lease as well as one well bore that is shut- in waiting on a SWDW permit to be approved before putting it back in production. The wells
are producing from the Second Massive Sand from a depth of between 4,000’-4,500’. The oil being produced is 32° gravity. We
have plans to do a work over on the shut-in well to decrease water production and to increase oil production.
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. The parties
are awaiting notification from the Contra Costa County Superior Court that the transfer has been completed. If successful, the lawsuit
would prevent Reabold from injecting wastewater into an existing well until any CEQA deficiencies are addressed. 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.
Encumbrances
On October 17, 2018, a working interest partner in
the East Slopes Project in California filed a UCC financing statement in regards to payables owed to the partner by the Company.
Results of Operations – Three Months Ended May
31, 2022 compared to the Three Months Ended May 31, 2021
California Crude Oil Prices
The prices we receive for crude oil sales in California
from the East Slopes project and from Reabold California, LLC (“Reabold”) 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.
California Natural Gas Prices
The price we receive for natural gas sales from Reabold
is based on ninety-five (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.
There continues to be a significant amount of volatility
in hydrocarbon prices and a corresponding fluctuation in our realized sale price of crude oil does exist. An example of this volatility
is that in June of 2014 the monthly average price of WTI oil was $105.79 per barrel and our realized price per barrel of crude oil was
$98.78 while in April 2020, the monthly average price of WTI crude oil was $16.55 and our monthly realized price was $16.96 per barrel.
Finally, in May 2022, the monthly average price of WTI oil was $109.55 per barrel and our realized price per barrel of crude oil was $106.56.
This volatility in crude oil prices has continued throughout most of the fiscal year ended February 28, 2022. Any downward volatility
in the price of crude oil will have a prolonged and substantial negative impact on our profitability and cash flow from our producing
California properties. It is beyond our ability to accurately predict crude oil prices over any substantial length of time.
A comparison of the average WTI price and the average
realized crude oil sales price for the three months ended May 31, 2022 and 2021 is shown in the table below:
| |
Three Months Ended | |
| |
| |
May 31, 2022 | |
May 31, 2021 | |
Percentage Change | |
Average three month WTI crude oil price (Bbl) | |
$ | 106.61 | |
$ | 63.07 | |
| 69.0 | % |
Average three month realized crude oil sales price (Bbl) | |
$ | 106.12 | |
$ | 61.65 | |
| 72.1 | % |
For the three months ended May 31, 2022, the average
WTI price was $106.61 and our average realized crude oil sale price was $106.12, representing a discount of $0.49 per barrel or 0.5% lower
than the average WTI price. In comparison, for the three months ended May 31, 2021, the average WTI price was $63.07 and our average realized
sale price was $61.65 representing a discount of $1.42 per barrel or 2.3% lower than the average WTI price. Historically, the sale price
we receive for California heavy crude oil has been less than the quoted WTI price because of the lower API gravity of our California crude
oil in comparison to the API gravity of quoted WTI crude oil.
California Crude Oil Revenue and Production
Crude oil revenue in California for the three months
ended May 31, 2022 increased $100,315 or 68.1% to $247,615 in comparison to revenue of $147,300 for the three months ended May 31, 2021.
The average realized sale price of a barrel of crude oil for the three months ended May 31, 2021 was $106.12 in comparison to $61.65 for
the three months ended May 31, 2021. The increase in the average realized sale price of a barrel of crude oil of $44.47 or 72.1% accounted
for 105.9% of the increase in revenue for the three months ended May 31, 2022, offset by a decline of 5.9% in revenue due to the 2.3%
decline in production volume.
Our net sales volume for the three months ended May
31, 2022 was 2,333 barrels of crude oil in comparison to 2,389 barrels sold for the three months ended May 31, 2021. This decrease in
crude oil sales volume of 56 barrels or 2.3% was primarily due to the timing of oil sales that occurred for the three months ended May
31, 2022.
The gravity of our produced crude oil in California
ranges between 14° API and 16° API. Production for the three months ended May 31, 2022 was from 20 wells resulting in
1,822 well days of production in comparison to 1,809 well days of production for the three months ended May 31, 2021.
Our crude oil sales revenue for the three months ended
May 31, 2022 and 2021 is set forth in the following table:
| |
Three Months Ended May 31, 2022 | | |
Three Months Ended May 31, 2021 | |
Project | |
Revenue | | |
Percentage | | |
Revenue | | |
Percentage | |
California – East Slopes Project | |
$ | 247,615 | | |
| 100.0 | % | |
$ | 147,300 | | |
| 100.0 | % |
*Our average realized
sale price on a BOE basis for the three months ended May 31, 2021 was $106.12 in comparison to $61.65 for the three months ended May 31,
2021, representing an increase of $44.47 or 72.1% per barrel.
Operating Expenses
Our total operating expenses for the three months
ended May 31, 2022 were $1,350,172, an increase of $1,121,873 or 491.4% compared to $228,299 for the three months ended May 31, 2021.
Operating expenses for the three months ended May 31, 2022 and 2021 are set forth in the table below:
| |
Three Months Ended May 31, 2022 | |
Three Months Ended May 31, 2021 |
| |
Expenses | |
Percentage | | |
BOE Basis | |
Expenses | |
Percentage | | |
BOE Basis |
Production expenses | |
$ | 60,717 | |
4.5 | % | |
| | |
$ | 46,726 | |
20.5 | % | |
| |
Depreciation, depletion, amortization (“DD&A”) | |
| 11,776 | |
0.8 | % | |
| | |
| 13,948 | |
6.1 | % | |
| |
Transaction expenses | |
| 1,025,541 | |
76.0 | % | |
| | |
| — | |
— | | |
| |
General and administrative (“G&A”) expenses | |
| 252,138 | |
18.7 | % | |
| | |
| 167,625 | |
73.4 | % | |
| |
Total operating expenses | |
$ | 1,350,172 | |
100.0 | % | |
$ | 578.73 | |
$ | 228,299 | |
100.0 | % | |
$ | 95.56 |
Production expenses include expenses associated with
the production of crude oil. These expenses include pumpers, electricity, road maintenance, control of well insurance, property taxes
and well workover costs; and, relate directly to the number of wells that are in production. For the three months ended May 31, 2022,
these expenses increased by $13,991 or 29.9% to $60,717 in comparison to $46,726 for the three months ended May 31, 2021. For the three
months ended May 31, 2022 and 2021, we had 20 wells on production in California. Production expense on a barrel of oil equivalent (“BOE”)
basis for the three months ended May 31, 2022 and 2021 were $26.03 and $19.56, respectively. Production expenses represented 4.5% and
20.5% of total operating expenses for the three months ended May 31, 2022 and 2021, 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. For the three months ended May 31, 2022 and 2021, these expenses were $-0-. Exploration and drilling expenses represented
0.0% of total operating expenses for the three months ended May 31, 2022 and 2021, respectively.
Depreciation, depletion and amortization (“DD&A”)
expenses relate to equipment, proven reserves and property costs, along with impairment, and is another component of operating expenses.
For the three months ended May 31, 2022, DD&A expenses decreased $2,172 or 15.6% to $11,776 in comparison to $13,948 for the three
months ended May 31, 2021. On a BOE basis DD&A expense was $5.05 and $5.84 for the three months ended May 31, 2022 and 2021, respectively.
DD&A and impairment expenses represented 0.8% and 6.1% of total operating expenses for the three months ended May 31, 2022 and 2021,
respectively.
For the three months ended May 31, 2022, we incurred
transaction expenses of $1,025,541 related to the acquisition of funding for future drilling and to eliminate our line of credit balance.
For the three months ended May 31, 2021, we did not incur any related expenses. Transaction expenses represented 76.0% and 0.0% of total
operating expenses for the three months ended May 31, 2022 and 2021, respectively.
General and administrative (“G&A”)
expenses include the salaries of our six employees, including management. Other items included in our G&A expenses are legal and accounting
expenses, director fees, stock compensation, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other
administrative expenses necessary for an operator of crude oil properties as well as for running a public company. For the three months
ended May 31, 2022, these expenses increased $84,513 or 50.49% to $252,138 in comparison to $167,625 for the three months ended May 31,
2021. Approximately $68,086 or 80.5% of the increase was directly related to the expense of holding the special shareholders meeting to
approve the acquisition of the Reabold property in California. We are continuing a program of reducing all of our G&A costs wherever
possible. G&A expenses represented 18.7% and 73.4% of total operating expenses for the three months ended May 31, 2022 and 2021, respectively.
Interest expense, net for the three months ended May
31, 2022 increased $9,664 or 15.8% to $70,930 in comparison to $61,266 for the three months ended May 31, 2021.
Due to the nature of our business, we expect that
revenues, as well as all categories of expenses, will continue to fluctuate substantially on a quarter-to-quarter and year-to-year basis.
Revenues are highly dependent on the volatility of hydrocarbon prices as seen during the last 18 months and production volumes. Production
expenses will fluctuate according to the number and percentage ownership of producing wells as well as the amount of revenues we receive
based on the price of crude oil. 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 including the size of our proven reserves 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 ongoing goal of the Company is to improve cash flow to cover the current level of G&A expenses and to fund our drilling
programs in California and Michigan.
Capital Resources and Liquidity
Our primary financial resource is our proven crude
oil reserve base. Our ability to fund any future capital expenditure programs is dependent upon the prices we receive from crude oil sales,
the success of our drilling programs in California and Michigan and the availability of capital resource financing. There continues to
be a significant amount of volatility in hydrocarbon prices and a corresponding fluctuation in our realized sale price of crude oil does
exist. An example of this volatility is that in June of 2014 the monthly average price of WTI oil was $105.79 per barrel and our realized
price per barrel of crude oil was $98.78 while in April 2020, the monthly average price of WTI crude oil was $16.55 and our monthly realized
price was $16.96 per barrel. Finally, in May 2022, the monthly average price of WTI oil was $109.55 per barrel and our realized price
per barrel of crude oil was $106.56. This volatility in crude oil prices has continued throughout most of the fiscal year ended February
28, 2022. Any downward volatility in the price of crude oil will have a prolonged and substantial negative impact on our profitability
and cash flow from our producing California properties. It is beyond our ability to accurately predict crude oil prices over any substantial
length of time.
We plan to spend approximately $435,000 drilling three
development wells in the current 2022-2023 fiscal year; however our actual expenditures may vary significantly from this estimate if our
plans for exploration and development activities change during the year. Factors such as changes in operating margins and the availability
of capital resources could increase or decrease our ultimate level of expenditures during the current fiscal year.
Changes in our capital resources at May 31, 2022 in
comparison with February 28, 2022 are set forth in the table below:
| |
May 31, 2022 | | |
February 28, 2022 | | |
Increase (Decrease) | | |
Percentage Change | |
Cash | |
$ | 1,159,469 | | |
$ | 139,573 | | |
$ | 1,019,896 | | |
730.7 | % |
Current assets | |
$ | 1,380,571 | | |
$ | 416,651 | | |
$ | 963,920 | | |
231.3 | % |
Total assets | |
$ | 8,792,745 | | |
$ | 975,704 | | |
$ | 7,817,041 | | |
801.2 | % |
Current liabilities | |
$ | (3,013,189 | ) | |
$ | (3,404,735 | ) | |
$ | (391,546 | ) | |
(11.5 | %) |
Total liabilities | |
$ | (3,814,247 | ) | |
$ | (4,322,908 | ) | |
$ | (508,661 | ) | |
(11.8 | %) |
Working capital | |
$ | (1,632,618 | ) | |
$ | (2,988,084 | ) | |
$ | 1,355,466 | | |
45.4 | % |
Our working capital deficit decreased approximately
$1.36 million or 45.4% to $1.63 million at May 31, 2022 in comparison to $2.99 million at February 28, 2022. The decrease in our working
capital deficit was primarily due to the funding we received in conjunction with the Reabold property in California. 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
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 and we anticipate that we will have to rely on these 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 producing properties, which
may very likely 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 will cause us to seek additional
forms of financing through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these
instruments which could result in dilution to existing security holders and increased debt and leverage. The current uncertainty in the
credit and capital markets as well as the instability and volatility in crude oil prices since June of 2014, has restricted our ability
to obtain needed capital. The 2019 novel coronavirus (“COVID-19") that spread to countries throughout the world including the
United States had a substantial negative impact on the demand for crude oil and is largely responsible for the decline in crude oil prices.
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 available to us.
The Company’s financial statements for the three
months ended May 31, 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. We have incurred a cumulative net loss since entering the crude oil exploration industry
and as of three months ended May 31, 2022 have an accumulated deficit of $30.7 million and
a working capital deficit of $1.6 million which raises substantial doubt about our ability
to continue as a going concern.
In the current fiscal year, we may continue 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.
Changes in Financial Condition
During the three months ended May 31, 2022, we received
crude oil sales revenue from 20 wells in our East slopes Project in Kern County, California. In May 2022, we acquired Reabold California,
LLC from its previous owner. This property includes four producing wells in both Monterey and Contra Costa counties of California. Our
commitment to improving corporate profitability remains unchanged. During the three months ended May 31, 2022 and 2021, crude oil revenue
from the East Slopes Project was $247,615 and $147,300, respectively. For the three months ended May 31, 2022 and 2021, we had an operating
loss of $1,102,557 and $80,999, respectively.
Our balance sheet at May 31, 2022 reflects total assets
of approximately $8.792 million in comparison to approximately $0.976 million at February 28, 2022. At May 31, 2022, total liabilities
were approximately $3.814 million in comparison to approximately $4.322 million at February 28, 2022.
Common stock shares issued and outstanding were 384,735,402
and 67,802,273 at May 31, 2022 and February 28, 2022, respectively.
Cash Flows
Changes in the net funds provided by and (used in)
our operating, investing and financing activities are set forth in the table below:
| |
Three Months Ended May 31, 2022 | | |
Three Months Ended May 31, 2021 | | |
Increase (Decrease) | | |
Percentage Change | |
Net cash (used in) provided by operating activities | |
$ | (132,636 | ) | |
$ | 63,339 | | |
| (195,975 | ) | |
| (309.4 | %) |
Net cash used in investing activities | |
$ | — | | |
$ | (10,584 | ) | |
| (10,584 | ) | |
| 100 | % |
Net cash provided by financing activities | |
$ | 1,152,532 | | |
$ | 26,440 | | |
| 1,126,092 | | |
| 4,259.0 | % |
Cash Flow (Used In) Provided By 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. For the three months ended May 31, 2022, cash flow used in operating activities was $132,636 in comparison to
cash flow provided by operating activities of $63,339 for the three months ended May 31, 2021. This increase of $195,975 in our cash flow
used for operating activities included approximately $68,086 in one-time expenses associated with the special shareholders meeting that
was held to approve the acquisition of another crude oil and natural gas property, Reabold California, LLC. Additionally, we experienced
transaction expenses of $1,025,541 associated with the acquisition and the sale of our common stock. Variations in cash flow from operating
activities may impact our level of exploration and development expenditures.
Our expenditures
in operating activities consist primarily of exploration and drilling expenses, production expenses, geological, geophysical and engineering
services and maintenance of existing mineral leases. Our expenses also consist of consulting and professional services, employee compensation,
legal, accounting, travel and other G&A expenses that we have incurred in order to address normal and necessary business activities.
Cash Flow Used In Investing Activities
Cash flow from investing activities is derived from
changes in oil and gas property balances and other investment activities. Cash flow used in investing activities for the three months
ended May 31, 2022 was $-0-. For the three months ended May 31, 2021 cash flow used in investing activities was $10,584.
Cash Flow
Provided By Financing Activities
Cash flow from financing activities is derived from
changes in long-term liability account balances, our borrowing activities or in equity account balances, excluding retained earnings.
Cash flow provided by financing activities for the three months ended May 31, 2022 was $1,152,532 in comparison to $26,440 provided by
financing activities in the three months ended May 31, 2021. During the three months ended May 31, 2022 we received $1,987,500 net of
transaction expenses from the sale of 128,125,000 shares of our common stock. Additionally, during the three months ended May 31, 2022,
we paid off the balance of $808,182 on the line of credit with UBS Bank.
The following discussion is a summary of cash flows
provided by or used in our financing activities at May 31, 2022.
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. Monthly interest is accrued and payable on January
1st of each anniversary date until maturity of the note. At May 31, 2022, the principal and accrued interest had not been paid
and was outstanding. The accrued interest on the Note was $41,000 and $38,000 at May 31, 2022 and February 28, 2022, respectively.
Note Payable – Related Party
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 three months ended
May 31, 2022, the Company made principal payments of $2,128 and amortized debt discount of $182. 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 May 31, 2022 and February 28, 2022 are set forth in the table below:
| |
May 31, 2022 | | |
February 28, 2022 | |
Note payable –related party, current portion | |
$ | 8,888 | | |
$ | 8,829 | |
Unamortized debt issuance expenses | |
| (729 | ) | |
| (729 | ) |
Note payable – related party, current portion, net | |
$ | 8,159 | | |
$ | 8,100 | |
Note payable –related party long-term balances
at May 31, 2022 and February 28, 2022 are set forth in the table below:
| |
May 31, 2022 | | |
February 28, 2022 | |
Note payable – related party, non-current | |
$ | 134,466 | | |
$ | 136,710 | |
Unamortized debt issuance expenses | |
| (9,168 | ) | |
| (9,350 | ) |
Note payable– related party, non-current, net | |
$ | 125,298 | | |
$ | 127,360 | |
Future estimated payments on the outstanding note
payable – related party are set forth in the table below:
Twelve month periods ending May 31, | | |
| |
2023 | | |
$ | 8,887 | |
2024 | | |
| 9,126 | |
2025 | | |
| 9,370 | |
2026 | | |
| 9,622 | |
2027 | | |
| 10,715 | |
Thereafter | | |
| 94,797 | |
Total | | |
$ | 142,517 | |
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 is payable
in kind (PIK) solely by additional shares of the Company’s common stock. Regardless of when 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 three months ended May 31, 2022.
12% Subordinated Notes
The Company’s 12% Subordinated Notes (“the
Notes”) issued pursuant to a January 2010 private placement offering to accredited investors, resulted in $595,000 in gross proceeds
(of which $250,000 was from a related party) to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th
and July 29th. On January 29, 2015, the Company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes
for an additional two years to January 29, 2017. Effective January 29, 2017, the maturity date of the Notes and the expiration date of
the warrants that were issued in conjunction with the Notes were extended for an additional two years to January 29, 2019.
As a result of the Company restructuring its balance
sheet through conversions of related party debt to common stock, the related party 12% Noteholder chose to convert the principal and accrued
interest of their Notes to the Company’s common stock. The related party Note for $250,000 and accrued interest of $264,986 were
converted to common stock at a rate of approximately $0.45 for every dollar of principal and interest resulting in 1,144,415 shares of
common stock being issued.
During the three months ended May 31, 2022, one 12%
Note holder chose to convert the principal balance and accrued interest in to 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.
The Company has informed the remaining Note holders
that the payment of principal and final interest will be late and is subject to future financing being completed. The Notes principal
of $290,000 has not been paid. 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. The accrued interest on the 12%
Notes at May 31, 2022 and February 28, 2022 was $133,480 and $135,229, respectively.
12% Note balances at May 31, 2022 and February 28,
2022 are set forth in the table below:
|
|
May 31, 2022 |
|
|
February 28, 2022 |
|
12% Subordinated notes – third party |
|
$ |
290,000 |
|
|
$ |
315,000 |
|
12% subordinated notes – related party |
|
|
— |
|
|
|
— |
|
12% Subordinated notes balance |
|
$ |
290,000 |
|
|
$ |
315,000 |
|
Line of Credit
The Company had an $890,000 line of credit
for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24,
2011 that was secured by the personal guarantee of its Chairman, President and Chief Executive Officer. 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 payoff was a part of the use of proceeds
from the Company’s sale of common stock to a third party.
Production Revenue Payable
Beginning in December 2018, the Company conducted
a fundraising program to fund the drilling of future wells in California and Michigan and to settle some of its historical debt. The purchaser(s)
of a production revenue payment interest received a production revenue payment on future wells to be drilled in California and Michigan
in exchange for their purchase. As of May 31, 2022, the production revenue payment program balance was $950,100 of which $550,100 was
owed to a related party - the Company’s Chairman, President and Chief Executive Officer.
The production payment interest entitles the purchasers
to receive production payments equal to twice their original amount paid, payable from a percentage of the Company’s future net
production payments from wells drilled after the date of the purchase and until the Production Payment Target (as described below) is
met. The Company shall pay fifty percent of its net production payments 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 purchasers 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 each of the purchasers. However, if the total raised is less than the target $1.3 million, then the payment
will be a proportionate amount of the eight percent (8%). Additionally, if the Production Payment Target is not met within the first three
years, the Company shall pay seventy-five percent of its production payments from the relevant wells to the purchasers until the Production
Payment Target is met.
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 $950,100 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 $1,077,642 as of May 31, 2022, which is being accounted as
interest expense over the estimated period over which payments will be made based on expected future revenue streams. For the three months
ended May 31, 2022 and 2021, amortization of the debt discount on these payables amounted to $30,525 and $31,970, respectively, which
has been included in interest expense in the statements of operations.
Production revenue payable balances at May 31, 2022
and February 28, 2022 are set forth in the table below:
| |
May 31, 2022 | | |
February 28, 2022 | |
Estimated payments of production revenue payable | |
$ | 991,638 | | |
$ | 941,259 | |
Less: unamortized discount | |
| (112,476 | ) | |
| (124,134 | ) |
| |
| 879,162 | | |
| 817,125 | |
Less: current portion | |
| (210,215 | ) | |
| (78,877 | ) |
Net production revenue payable – long term | |
$ | 621,461 | | |
$ | 738,248 | |
Encumbrances
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. As of May 31, 2021 we had no encumbrances
on our crude oil project in Michigan.
Operating Leases
We lease approximately 988 rentable square feet of
office space from an unaffiliated third party for our corporate office located in Spokane Valley, Washington. Additionally, we lease approximately
416 and 695 rentable square feet from unaffiliated third parties for our regional operations office in Friendswood, Texas and storage
and auxiliary office space in Wallace, Idaho, respectively. The lease in Friendswood is a 12 month lease that expires in October 2021
and as such is considered a short-term lease. The Company has elected to not apply the recognition requirements of ASC 842 to this short-term
lease. The Spokane Valley and Wallace leases are currently on a month-to-month basis. Our lease agreements do not contain any residual
value guarantees, restrictive covenants or variable lease payments. We have not entered into any financing leases.
We determine if an arrangement is a lease at inception.
Operating leases are recorded in operating lease right of use assets, net, operating lease liability – current, and operating lease
liability, long-term on its balance sheet.
Rent expense for the three months ended May 31, 2022
and 2021 was $5,947 and $5,947, respectively.
Capital Commitments
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, and the economic downturn, may
restrict our ability to obtain needed capital.
Management Plans to Continue as a Going Concern
We continue to implement plans to enhance Daybreak’s
ability to continue as a going concern. The Company currently has a net revenue interest in 20 producing crude oil wells in our East Slopes
Project located in Kern County, California. The revenue from these wells has created a steady and reliable source of revenue for the Company.
Our average working interest in these wells is 36.6% and the average net revenue interest is 28.5%.
In May 2022, the Company acquired Reabold California,
LLC (“Reabold”) from a third party. This property includes producing wells in both the Monterey and Contra Costa counties
of California. This project includes four producing wells. We have a 50% working interest with a 40% net revenue interest in this project.
In conjunction with our acquisition of Reabold, the Company was able to secure a capital raise of $2,500,000 through the issuances of
the Company’s common stock.
The Company anticipates its 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. 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.
We believe that our liquidity will improve when there
is a sustained improvement in hydrocarbon prices. Our sources of funds in the past have included the debt or equity markets and the sale
of assets. While the Company does have positive cash flow from its crude oil 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, we cannot offer any assurance that we will be successful in executing the aforementioned plans to continue as
a going concern.
Our financial statements as of May 31, 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.
Critical Accounting Policies
Refer to Daybreak’s Annual Report on Form 10-K
for the fiscal year ended February 28, 2022.
Off-Balance Sheet Arrangements
As of May 31, 2022, we did not have any off-balance
sheet arrangements or relationships with unconsolidated entities or financial partners that have been, or are reasonably likely to have,
a material effect on our financial position or results of operations.