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 nine months ended November 30, 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; in our other public
filings and press releases; and discussions with Company management. |
Our reserve estimates are determined through a subjective
process and are subject to 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 nine months ended November 30,
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 longer-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 or market volatility, such as we have experienced
in the last 18 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.
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 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 two crude oil and natural
gas 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 East Slopes project 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 at the East Slopes Project since March 2009.
The crude oil produced from our acreage in the Vedder
Sand is considered heavy oil. The gravity of 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 nine months ended November 30, 2022 we normally had production from 20 crude oil wells, however during this
same nine month time period multiple wells had workovers done to replace the downhole pumps. Our average working interest (“WI”)
and net revenue interest (“NRI”) in these 20 wells is 36.6% and 27.6%, 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, Kern County, California Drilling Plans
We are currently in the planning and permitting process
to undertake a multi-well developmental drilling program commencing in the second quarter of 2023. These plans are also dependent on a
stabilization of crude oil prices. We plan to spend approximately $825,000 drilling three development wells and one water disposal well
in this drilling program.
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.
The Burnett Lease and the Doud Lease are located in
close proximity to each 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 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”). 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 approximately 23°
API gravity. We have future plans of drilling one additional directional well on this lease. The SWD for the Burnett Lease will be utilized
for the Doud 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 two directional wells producing from this
lease. A work over was successfully completed on a third well to decrease water production and to increase oil production. This third
well will be put back on production once the Sunflower Alliance lawsuit 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 oil being produced is approximately 38°
gravity.
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 had been completed and the case filed in that court. 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. 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. Reabold will appeal
the Superior Court’s order. At this time, it is unclear when the litigation will be resolved.
The Company is not aware of any environmental claims
existing as of November 30, 2022. 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 East Slopes Project in California filed a UCC financing statement in regards to payables owed to the partner by the Company.
Results of Operations – Nine months ended November
30, 2022 compared to the nine months ended November 30, 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 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.
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. For example, in April 2020, the monthly average price of WTI crude oil was $16.55 and our monthly realized price was $16.96 per
barrel. Then 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. Finally, in November 2022, our average realized price was $84.37 per barrel. This volatility in crude oil prices has continued
throughout most of the fiscal year ended February 28, 2023. 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 crude oil price and
the average realized crude oil sales price for the nine months ended November 30, 2022 and 2021 is shown in the table below:
|
|
Nine Months Ended |
|
|
|
|
November 30, 2022 |
|
November 30, 2021 |
|
Percentage Change |
Average nine month WTI crude oil price (Bbl) |
|
$ |
98.46 |
|
$ |
70.34 |
|
40.0% |
Average nine month realized crude oil sales price (Bbl) |
|
$ |
95.69 |
|
$ |
67.97 |
|
40.8% |
For the nine months ended November 30, 2022, the average
WTI price was $98.46 and our average realized crude oil sale price was $95.69, representing a discount of $2.77 per barrel or 2.8% lower
than the average WTI price. In comparison, for the nine months ended November 30, 2021, the average WTI price was $70.34 and our average
realized sale price was $67.97 representing a discount of $2.37 per barrel or 3.4% lower than the average WTI price.
California Crude Oil Revenue and Production
Crude oil revenue in California for the nine months
ended November 30, 2022 increased $733,653 or 145.2146.6% to $1,239,063 in comparison to revenue of $505,410 for the nine months ended
November 30, 2021. The reason for the increase was the acquisition of the Reabold California, LLC wells in central California. The average
sale price of a barrel of crude oil for the nine months ended November 30, 2022 was $95.69 in comparison to $67.97 for the nine months
ended November 30, 2021. The increase of $27.72 or 40.8% per barrel in the average realized price of a barrel of crude oil accounted for
27.8% of the increase in crude oil revenue for the nine months ended November 30, 2022.
Our net crude oil sales volume for the nine months
ended November 30, 2022 was 13,027 barrels of crude oil in comparison to 7,436 barrels sold for the nine months ended November 30, 2021.
This increase in crude oil sales volume of 5,591 barrels or 75.2% was primarily due to our acquisition of the Reabold property and its
producing wells in central California. The gravity of our produced crude oil in the East Slopes project ranges between 14° API and
16° API. Historically, the sale price we receive for East Slopes crude oil has been less than the quoted WTI price because of the
lower API gravity of our East Slopes crude oil in comparison to the API gravity of quoted WTI crude oil. The gravity of our produced crude
oil in the Reabold project ranges between 17° API and 38° API.
Our crude oil sales revenue for the nine months ended
November 30, 2022 and 2021 are set forth in the following table:
| |
Nine Months Ended November 30, 2022 | | |
Nine Months Ended November 30, 2021 | |
Project | |
Revenue | |
Percentage | | |
Revenue | |
Percentage | |
East Slopes Project – crude oil sales | |
$ | 609,924 | |
| 49.2 | % | |
$ | 505,410 | |
| 100.0 | % |
Reabold Project – crude oil sales | |
| 629,139 | |
| 50.8 | % | |
| — | |
| — | |
California Totals | |
$ | 1,239,063 | |
| 100.0 | % | |
$ | 505,410 | |
| 100.0 | % |
Our natural gas sales revenue for the nine months
ended November 30, 2022 and 2021 is set forth in the following table:
| |
Nine Months Ended November 30, 2022 | | |
Nine Months Ended November 30, 2021 | |
Project | |
Revenue | |
Percentage | | |
Revenue | |
Percentage | |
Reabold Project – natural gas sales | |
$ | 15,594 | |
| 100.0 | % | |
$ | — | |
| — | |
Our average realized
sale price on a barrel of oil equivalent (BOE) basis of crude oil and natural gas for the nine months ended November 30, 2022 was $94.87
in comparison to $67.97 for the nine months ended November 30, 2021, representing an increase of $26.90 or 39.6% per barrel.
Operating Expenses
Total operating expenses for the nine months ended
November 30, 2022 were $2,819,269, an increase of $2,161,721 or 328.8% compared to $657,548 for the nine months ended November 30, 2021.
Operating expenses for the nine months ended November 30, 2022 and 2021 are set forth in the table below:
| |
Nine Months Ended November 30, 2022 | | |
Nine Months Ended November 30, 2021 | |
| |
Expenses | | |
Percentage | | |
BOE Basis | | |
Expenses | | |
Percentage | | |
BOE Basis | |
Production expenses | |
$ | 742,450 | | |
| 26.3 | % | |
| | | |
$ | 165,357 | | |
| 25.1 | % | |
| | |
Exploration and drilling expenses | |
| 1,170 | | |
| 0.1 | % | |
| | | |
| 235 | | |
| 0.0 | % | |
| | |
Depreciation, depletion, amortization (“DD&A”) | |
| 214,046 | | |
| 7.6 | % | |
| | | |
| 44,004 | | |
| 6.7 | % | |
| | |
Transaction (acquisition) expenses | |
| 1,086,154 | | |
| 38.5 | % | |
| | | |
| — | | |
| — | | |
| | |
General and administrative (“G&A”) expenses | |
| 775,449 | | |
| 27.5 | % | |
| | | |
| 447,952 | | |
| 68.2 | % | |
| | |
Total operating expenses | |
$ | 2,819,269 | | |
| 100.0 | % | |
$ | 211.93 | | |
$ | 657,548 | | |
| 100.0 | % | |
$ | 88.43 | |
Production expenses include expenses associated with
the production of crude oil. These expenses include contract pumpers, electricity, road maintenance, control of well insurance, property
taxes and well workover expenses; and, relate directly to the number of wells that are in production. For the nine months ended November
30, 2022, these expenses increased by $577,093 or 349.0% to $742,450 in comparison to $165,357 for the nine months ended November 30,
2021. For the nine months ended November 30, 2022, we had 25 wells on production from the East Slopes and Reabold projects in comparison
to 20 wells on production in the East Slopes project for the nine months ended November 30, 2021. The increase of four wells was from
the Reabold acquisition that occurred in late May 2022. The increase in production expenses for the nine months ended November 30, 2022,
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 $318,052 from the Reabold project. 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 expense on a barrel of oil equivalent
(“BOE”) basis for the nine months ended November 30, 2022 and 2021 were $55.81 and $22.24, respectively. Production expenses
represented 27.5% and 25.1% of total operating expenses for the nine months ended November 30, 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 nine months ended November 30, 2022 and 2021, these expenses were $1,170 and $235, respectively. Exploration
and drilling expenses represented 0.1% and 0.0% of total operating expenses for the nine months ended November 30, 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 nine months ended November 30, 2022, DD&A expenses increased $170,042 or 386.4% to $214,046 in comparison to $44,004 for the
nine months ended November 30, 2021. On a BOE basis, DD&A expense was $16.09 and $5.92 for the nine months ended November 30, 2022
and 2021, respectively. DD&A expenses represented 7.6% and 6.7% of total operating expenses for the nine months ended November 30,
2022 and 2021, respectively.
For the nine months ended November 30, 2022, we incurred
transaction expenses of $1,086,154 related to the acquisition of funding and to acquire the Reabold crude oil and natural gas properties
located in central California. For the nine months ended November 30, 2021, we did not incur any related expenses. Transaction expenses
represented 38.5% and 0.0% of total operating expenses for the nine months ended November 30, 2022 and 2021, respectively.
General and administrative (“G&A”)
expenses include the salaries of nine 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 running a public company. For the nine months ended November 30, 2022, G&A
expenses increased $327,497 or 73.1% to $775,449 in comparison to $447,952 for the nine months ended November 30, 2021. 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 $122,200 in aggregate, that were held during the nine months ended November 30, 2022 and professional legal
and accounting fees of approximately $70,000 related to the Reabold acquisition. We are continuing a program of controlling our G&A
costs wherever possible. G&A expenses represented 27.5% and 68.2% of total operating expenses for the nine months ended November 30,
2022 and 2021, respectively.
During the nine months ended
November 30, 2021, 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 nine months ended November 30, 2021, 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 a Paycheck Protection Program (PPP) 2nd Draw loan.
Interest expense, net for the nine months ended November
30, 2022 decreased $54,363 or 30.5% to $123,857 in comparison to $178,220 for the nine months ended November 30, 2021.
Results of Operations – Three months ended November
30, 2022 compared to the three months ended November 30, 2021
A comparison of the average WTI crude oil price and
the average realized crude oil sales price for the three months ended November 30, 2022 and 2021 is shown in the table below:
| |
Three Months Ended | |
| |
| |
November 30, 2022 | |
November 30, 2021 | |
Percentage Change | |
Average three month WTI crude oil price (Bbl) | |
$ | 85.39 | |
$ | 77.43 | |
| 10.3 | % |
Average three month realized crude oil sales price (Bbl) | |
$ | 85.39 | |
$ | 74.12 | |
| 15.2 | % |
For the three months ended November 30, 2022, the
average WTI price was $85.39 and our average realized crude oil sale price was also $85.39. In comparison, for the three months ended
November 30, 2021, the average WTI price was $77.43 and our average realized sale price was $74.12 representing a discount of $3.31 per
barrel or 4.3% lower than the average WTI price.
California Crude Oil Revenue and Production
Crude oil revenue in California for the three months
ended November 30, 2022, increased $271,373 or 143.7% to $460,165 in comparison to revenue of $188,792 for the three months ended November
30, 2021. The primary reason for the increase was the acquisition of the Reabold California, LLC wells in central California. The average
sale price of a barrel of crude oil for the three months ended November 30, 2022 was $85.39 in comparison to $74.12 for the three months
ended November 30, 2021. The increase of $11.27 or 15.2% per barrel in the average realized price of a barrel of crude oil accounted for
120.6% of the increase in crude oil revenue for the three months ended November 30, 2022.
Our net sales volume for the three months ended November
30, 2022 was 5,389 barrels of crude oil in comparison to 2,547 barrels sold for the three months ended November 30, 2021. This increase
in crude oil sales volume of 2,842 barrels or 111.6% was due to our acquisition of the Reabold property and its producing wells in central
California. The gravity of our produced crude oil in the East Slopes project ranges between 14° API and 16° API. Historically,
the sale price we receive for East Slopes 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. The gravity of our produced crude oil in the Reabold
project ranges between 17° API and 38° API.
Our crude oil sales revenue for the three months ended
November 30, 2022 and 2021 are set forth in the following table:
| |
Three Months Ended November 30, 2022 | | |
Three Months Ended November 30, 2021 | |
Project | |
Revenue | |
Percentage | | |
Revenue | |
Percentage | |
East Slopes Project – crude oil sales | |
$ | 169,885 | |
| 36.9 | % | |
$ | 188,792 | |
| 100.0 | % |
Reabold Project – crude oil sales | |
| 290,280 | |
| 63.1 | % | |
| — | |
| — | |
California Totals | |
$ | 460,165 | |
| 100.0 | % | |
$ | 188,792 | |
| 100.0 | % |
Our natural gas sales revenue for the three months
ended November 30, 2022 and 2021 is set forth in the following table:
| |
Three Months Ended November 30, 2022 | | |
Three Months Ended November 30, 2021 | |
Project | |
Revenue | |
Percentage | | |
Revenue | |
Percentage | |
Reabold Project – natural gas sales | |
$ | 5,846 | |
| 100.0 | % | |
$ | — | |
| — | |
Our average realized
sale price on a barrel of oil equivalent (BOE) basis of crude oil and natural gas for the three months ended November 30, 2022 was $84.72
in comparison to $74.12 for the three months ended November 30, 2021, representing an increase of $10.60 or 14.3% per barrel.
Operating Expenses
Total operating expenses for the three months ended
November 30, 2022 were $745,236, an increase of $442,304 or 207.7% compared to $242,182 for the three months ended November 30, 2021.
Operating expenses for the three months ended November 30, 2022 and 2021 are set forth in the table below:
| |
Three Months Ended November 30, 2022 | |
Three Months Ended November 30, 2021 | |
| |
Expenses | |
Percentage | | |
BOE Basis | |
Expenses | |
Percentage | | |
BOE Basis | |
Production expenses | |
$ | 383,251 | |
| 51.4 | % | |
| | |
$ | 65,788 | |
| 27.2 | % | |
| | |
Exploration and drilling expenses | |
| — | |
| 0.0 | % | |
| | |
| 34 | |
| 0.0 | % | |
| | |
Depreciation, depletion, amortization (“DD&A”) | |
| 64,382 | |
| 8.6 | % | |
| | |
| 15,196 | |
| 6.3 | % | |
| | |
Transaction (acquisition) expenses | |
| 60,613 | |
| 8.2 | % | |
| | |
| — | |
| — | | |
| | |
General and administrative (“G&A”) expenses | |
| 236,989 | |
| 31.8 | % | |
| | |
| 161,164 | |
| 66.5 | % | |
| | |
Total operating expenses | |
$ | 745,235 | |
| 100.0 | % | |
$ | 135.47 | |
$ | 242,182 | |
| 100.0 | % | |
$ | 95.09 | |
Production expenses for the three months ended November
30, 2022, increased by $317,463 or 482.6% to $383,251 in comparison to $65,788 for the three months ended November 30, 2021. For the three
months ended November 30, 2022 and 2021, we had 20 and 20 wells, respectively, on production in our East Slopes project. For the three
months ended November 30, 2022, we had five wells on production in the Reabold project that we acquired in May 2022. The increase in production
expenses for the three months ended November 30, 2022, was primarily due to the replacement and upgrading of pumps in seven wells of the
East Slopes project for $42,920 and the expenses associated with salt water disposal of $158,100 from the Reabold project. A salt water
disposal well is currently being permitted which, when put into operation will significantly lower operating costs of the Reabold project.
Production expense on a barrel of oil equivalent (“BOE”) basis for the three months ended November 30, 2022 and 2021 were
$69.67 and $25.83, respectively. Production expenses represented 51.4% and 27.2% of total operating expenses for the three months ended
November 30, 2022 and 2021, respectively.
Exploration and drilling expenses for the three months
ended November 30, 2022 were $-0- in comparison to $34 for the three months ended November 30, 2021. Exploration and drilling expenses
represented 0.0% and 0.0% of total operating expenses for the three months ended November 30, 2022 and 2021, respectively.
DD&A expenses for the three months ended November
30, 2022, increased $49,186 or 323.7% to $64,382 in comparison to $15,196 for the three months ended November 30, 2021. DD&A on a
BOE basis was $11.70 and $5.97 for the three months ended November 30, 2022 and 2021, respectively. DD&A expenses represented 8.6%
and 6.3% of total operating expenses for the three months ended November 30, 2022 and 2021, 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 operator of
crude oil properties as well as for running a public company. G&A expenses for the three months ended November 30, 2022, increased
$75,825 or 47.0% to $236,989 in comparison to $161,164 for the three months ended November 30, 2021. We are continuing a program of controlling
our G&A costs wherever possible. G&A expenses represented 31.8% and 66.5% of total operating expenses for the three months ended
November 30, 2022 and 2021, respectively.
Interest expense, net for the three months ended November
30, 2022 decreased $77,342 to $14,719 due to an adjustment from prior periods in comparison to ($62,623) for the three months ended November
30, 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 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 on-going 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 the availability of capital resource financing. There continues to be a significant
amount of volatility in crude oil prices and dramatic fluctuation in our realized sale price of crude oil since June of 2014, when the
monthly average price of WTI crude oil was $105.79 per barrel, and our realized sale price per barrel of crude oil was $98.78. For example,
in the month of April 2020 the monthly average closing price of WTI crude oil was $16.55 and our monthly realized oil price was $16.96
per barrel. Then in 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. In November, 2022, our average realized price was $84.37 per barrel. This volatility in crude oil prices continued into
the current fiscal year. 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.
East Slopes, Kern County, California Drilling Plans
We are currently in the planning and permitting process
to undertake a multi-well developmental drilling program commencing in the second quarter of 2023. These plans are also dependent on a
stabilization of crude oil prices. We plan to spend approximately $825,000 drilling three development wells and one water disposal well
in this drilling program.
Changes in our capital resources at November 30, 2022
in comparison to February 28, 2022 are set forth in the table below:
| |
November 30, 2022 | | |
February 28, 2022 | | |
Increase (Decrease) | | |
Percentage Change | |
Cash | |
$ | 403,498 | | |
$ | 139,573 | | |
$ | 263,925 | | |
| 189.1 | % |
Restricted Cash | |
$ | 275,000 | | |
$ | — | | |
$ | 275,000 | | |
| 100.0 | % |
Current assets | |
$ | 1,399,584 | | |
$ | 416,651 | | |
$ | 982,933 | | |
| 235.9 | % |
Total assets | |
$ | 8,764,828 | | |
$ | 975,704 | | |
$ | 7,789,124 | | |
| 798.3 | % |
Current liabilities | |
$ | (3,254,450 | ) | |
$ | (3,404,735 | ) | |
$ | (150,285 | ) | |
| (4.4 | %) |
Total liabilities | |
$ | (4,301,312 | ) | |
$ | (4,322,908 | ) | |
$ | (21,596 | ) | |
| (0.5 | %) |
Working capital deficit | |
$ | (1,854,866 | ) | |
$ | (2,988,084 | ) | |
$ | (1,133,218 | ) | |
| (37.9 | %) |
Our working capital deficit decreased approximately
$1.13 million or 37.9% to approximately $1.85 million at November 30, 2022 in comparison to approximately $2.99 million at February 28,
2022. The decrease in our working capital deficit was primarily due to the proceeds we received in connection with the sale of common
stock and the acquisition of the Reabold California, LLC 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 and the sale of assets. 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") and its subsequent variants that spread to countries throughout
the world including the United States continue to have an uncertain negative impact on the financial and energy markets. 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 nine
months ended November 30, 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 net losses since entering the crude oil exploration industry in 2005,
and as of the nine months ended November 30, 2022, we have an accumulated deficit of $31.2 million and a working capital deficit of $1.85
million which raises substantial doubt about our ability to continue as a going concern.
In the current fiscal year, 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.
Changes in Financial Condition
During the nine months ended November 30, 2022, we
received crude oil sales revenue from our 20 producing wells in the East slopes project as well as crude oil and natural gas sales revenue
from five producing wells in the recently acquired Reabold project. Both of these projects are located in California. Our commitment to
improving corporate profitability remains unchanged. We experienced an increase in revenues of $749,247 or 148.2% to $1,254,657 for the
nine months ended November 30, 2022 in comparison to revenues of $505,410 for the nine months ended November 30, 2021. The increase of
$26.90 or 39.5% in the average realized price BOE accounted for 26.4% of the increase in crude oil revenue for the nine months ended November
30, 2022. The increase in sales volume BOE accounted for the remaining 73.6% of the revenue increase. The increase in volume was primarily
due to the producing wells that we acquired in the recently completed acquisition of Reabold California, LLC. For the nine months ended
November 30, 2022, we had an operating loss of $1,564,612 in comparison to an operating loss of $152,138 for the nine months ended November
30, 2021. The increase in the operating loss was due to transaction expenses related to the acquisition of the Reabold property, fundraising,
and the expenses of holding both a special shareholders’ meeting to approve the acquisition and a regular annual shareholders meeting.
Our balance sheet at November 30, 2022 reflects total
assets of approximately $8.8 million in comparison to approximately $0.98 million at February 28, 2022. The increase of approximately
$7.8 million is directly related to the acquisition of crude oil and natural gas assets in California.
At November 30, 2022, total liabilities decreased
by approximately $21,600 to approximately $4.3 million in comparison to approximately $4.3 million at February 28, 2022.
At November 30, 2022, there were 384,735,402 issued
and outstanding shares of common stock in comparison to 67,802,273 shares at February 28, 2022. The increase in shares issued and outstanding
of 316,933,129 shares was directly related to the acquisition of producing crude oil and natural gas assets, associated fundraising and
the restructuring of our balance sheet eliminating debt in exchange for equity.
Additional paid in capital (APIC) increased approximately
$9.2 million at November 30, 2022 to $35,297,706 from $26,115,450 at February 28, 2022, as a result of the same acquisition of producing
crude oil and natural gas assets, associated fundraising and the restructuring of our balance sheet eliminating debt in exchange for equity.
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:
| |
Nine Months Ended November 30, 2022 | | |
Nine Months Ended November 30, 2021 | | |
Increase (Decrease) | | |
Percentage Change | |
Net cash (used in) provided by operating activities | |
$ | (599,420 | ) | |
$ | 31,984 | | |
| (631,404 | ) | |
| (1,974.1 | %) |
Net cash (used in) investing activities | |
$ | — | | |
$ | (14,673 | ) | |
| 14,673 | | |
| 100.0 | % |
Net cash provided by (used in) financing activities | |
$ | 1,138,345 | | |
$ | (33,447 | ) | |
| 1,171,792 | | |
| 3,503.4 | % |
Cash Flow Provided By (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. For the nine months ended November 30, 2022, cash flow used in operating activities was $599,420 in comparison
to cash flow provided by operating activities of $31,984 for the nine months ended November 30, 2021. The increase in our cash flow used
in operating activities of $631,404 for the nine months ended November 30, 2022 was primarily due to increases in our accounts receivable
crude oil and natural gas sales and receivables from our working interest partners. Both of these increases were directly related to our
acquisition of producing crude oil and natural gas assets in California from a third party. Changes in non-cash account balances primarily
relating to financing fees, DD&A and amortization of debt discount increased by approximately $644,000 in comparison to the nine month
ended November 30, 2021. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.
Cash Flow Used In Investing Activities
Cash flow from investing activities is derived from
changes in crude oil property balances and any lending activities. Cash flow used in our investing activities for the nine months ended
November 30, 2022 was $-0- in comparison to cash flow used in our investing activities of $14,673 for the nine months ended November 30,
2021.
Cash Flow Provided By (Used In) 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 $1,138,345 for the nine months ended November 30, 2022 in comparison to cash flow used in our financing activities
of $33,447 for the nine months ended November 30, 2021. During the nine months ended November 30, 2022 we secured a capital raise of $1,987,500
net of transaction expenses from the sale of 128,125,000 shares of our common stock. Additionally, during the nine months ended November
30, 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, and used in, the Company’s financing activities at November 30, 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
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 November 30, 2022, the note principal and a portion of the
accrued interest had not been paid and was outstanding. The accrued interest on the Note was $23,000 and $38,000 at November 30, 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 nine months ended
November 30, 2022, the Company made principal payments of $6,598 and amortized debt discount of $546. The obligations under the Note are
secured by a lien on and security interest in the Company’s crude oil 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 November 30, 2022 and February 28, 2022 are set forth in the table below:
| |
November 30, 2022 | | |
February 28, 2022 | |
Note payable – related party, current portion | |
$ | 9,006 | | |
$ | 8,829 | |
Unamortized debt issuance expenses | |
| (729 | ) | |
| (729 | ) |
Note payable – related party, current portion, net | |
$ | 8,277 | | |
$ | 8,100 | |
Note payable – related party long-term balances
at November 30, 2022 and February 28, 2022 are set forth in the table below:
| |
November 30, 2022 | | |
February 28, 2022 | |
Note payable – related party, non-current | |
$ | 129,934 | | |
$ | 136,710 | |
Unamortized debt issuance expenses | |
| (8,804 | ) | |
| (9,350 | ) |
Note payable – related party, non-current, net | |
$ | 121,130 | | |
$ | 127,360 | |
Future estimated payments on the outstanding note
payable – related party are set forth in the table below:
Twelve month periods ending November 30 | | |
| |
2023 | | |
$ | 9,006 | |
2024 | | |
| 9,247 | |
2025 | | |
| 9,495 | |
2026 | | |
| 9,750 | |
2027 | | |
| 10,011 | |
Thereafter | | |
| 91,431 | |
Total | | |
$ | 138,940 | |
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 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 nine months ended November 30, 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, James F. Westmoreland, the Company’s
President and Chief Executive Officer, 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 nine months ended November 30, 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 Note holders that the
payment of principal and final 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. 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 November 30, 2022 and February 28, 2022 was $150,927 and $135,229, respectively.
12% Note balances at November 30, 2022 and February
28, 2022 are set forth in the table below:
| |
November 30, 2022 | | |
February 28, 2022 | |
12% Subordinated Notes | |
$ | 290,000 | | |
$ | 315,000 | |
12% Subordinated Notes – related party | |
| — | | |
| — | |
Total 12% Subordinated Note balance | |
$ | 290,000 | | |
$ | 315,000 | |
Line of Credit
The Company had an existing $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. 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 net program balance of $865,480 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 $951,417 and determined a discount of $85,937 as of November 30, 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 nine months ended November 30, 2022 and 2021, amortization of the debt discount on these payables amounted to $50,063 and $87,008,
respectively, which has been included in interest expense in the statements of operations.
Production revenue payable balances at November 30,
2022 and February 28, 2022 are set forth in the table below:
| |
November 30, 2022 | | |
February 28, 2022 | |
Estimated payments of production revenue payable | |
$ | 981,417 | | |
$ | 941,259 | |
Less: unamortized discount | |
| (85,937 | ) | |
| (124,134 | ) |
| |
| 865,480 | | |
| 817,125 | |
Less: current portion | |
| (162,991 | ) | |
| (78,877 | ) |
Net production revenue payable – long-term | |
$ | 702,489 | | |
$ | 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.
Operating Leases
The Company leases approximately 988 rentable square
feet of office space from an unaffiliated third party for our former 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 2022. The Spokane Valley and Wallace leases are 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.
The Company determines 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 nine months ended November 30,
2022 and 2021 was $17,867 and $17,542, respectively.
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. The Company’s
Chief Operating Officer is a 50% owner in both Great Earth Power and ABPlus Net Holdings. Great Earth Power began providing a portion
of the solar power electrical service for production operations in July 2020. ABPlus Net Holdings 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 Power
and ABPlus Net Holdings are competitive with other vendors and save the Company significant expense. For the nine months ended November
30, 2022 and 2021, Great Earth Power was paid $13,300 and $20,038, respectively. For the nine months ended November 30, 2022 and 2021,
ABPlus Net holdings was paid $8,640 and $10,560, 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 current economic downturn
in the energy sector, may restrict our ability to obtain needed capital.
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 (“NRI”) in 20 producing crude oil wells in its
East Slopes Project located in Kern County, California (the “East Slopes Project”). The revenue from these wells has created
a steady and reliable source of income for the Company. The Company’s average working interest (“WI”) in these wells
is 36.6% and the average net revenue interest (“NRI”) is 27.6% for these same wells.
In May 2022, we acquired Reabold California, LLC (“Reabold”)
from a third party. This property currently includes four producing wells, five shut-in wells, and two potential disposal wells in the
Monterey and Contra Costa counties of California. We have a 50% working interest with a 40% net revenue interest in this project.
In conjunction with our acquisition of Reabold, we
were able to secure a capital raise of $2,500,000 through the issuances of the Company’s common stock.
We anticipate our revenue will continue to increase
as the Company participates in the drilling of more wells in the East Slopes and the 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 us to obtain additional
funding from the private or public debt or equity markets in the future. However, we cannot offer any assurance that it will be successful
in executing the aforementioned plans to continue as a going concern.
Our financial statements as of November 30, 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.
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 November 30, 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.