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, 2020 and in our Annual Report on Form 10-K
for the year ended February 29, 2020. 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;
|
|
·
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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.
In December 2019, the 2019 novel coronavirus
(“COVID-19") surfaced in Wuhan, China. The World Health Organization declared a global emergency on January 30, 2020,
with respect to the outbreak and several countries, including the United States, Japan and Australia have initiated travel restrictions
to and from China. The full economic impact of the outbreak is unknown and rapidly evolving. This widespread health crisis and
the governmental restrictions associated with it, have adversely affected demand for crude oil and natural gas, depressed crude
oil prices, and affected our ability to access capital. These factors, in turn, have had a negative impact on our operations, and
financial condition as evidenced by the unprecedented decline in crude oil prices and our revenues during this same time period.
Should one or more of the risks or uncertainties
described above or elsewhere in our Form 10-K for the year ended February 29, 2020 and in this Form 10-Q for the nine months ended
November 30, 2020 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 exploration,
development and production company. Our basic business model is to increase shareholder value by finding and developing crude oil
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 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 properties and on the prevailing sales prices for crude
oil 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, would have a material adverse
effect on our results of operations and financial condition.
Our operations are focused on identifying and
evaluating prospective crude oil properties and funding projects that we believe have the potential to produce crude oil or natural
gas in commercial quantities. We conduct all of our drilling, exploration and production activities in the United States, and all
of our revenues are derived from sales to customers within the United States. 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 we have 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 29, 2020 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 and Michigan. Refer to our discussion in Item 2. Properties, in our Annual Report on Form 10-K for the year ended
February 29, 2020 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 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, 2020 we had production from 20 vertical crude oil wells. Our average working interest (“WI”) and net revenue interest
(“NRI”) in these 20 wells is 36.6% and 28.4%, respectively.
When funding is available, 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.
California Drilling Plans
Planned drilling activity and implementation
of our oilfield development plan will not begin until financing is put in place. We do not plan to make any capital investments
within the East Slopes Project area for the remainder of the 2020-2021 fiscal year. When additional financing is secured, we plan
to spend approximately $525,000 drilling four development wells in the 2021-2022 fiscal year.
Michigan Acreage Acquisition
In January 2017, Daybreak acquired a 30% working
interest in 1,400 acres in the Michigan Basin. The leases have been secured and multiple targets were identified through a 2-D
seismic interpretation. A 3-D seismic survey was obtained in January and February of 2017. An analysis of the 3-D seismic survey
confirmed the first prospect originally identified on the 2-D seismic, as well as several additional drilling locations. We have
plans to obtain an additional 3-D survey on the second prospect after drilling a well on the first prospect. The two prospects
are independent of each other and the success or lack of results of either prospect does not affect the potential of the other
prospect. The wells will be drilled vertically with conventional completions and no hydraulic fracturing is anticipated. With the
settlement of our debt obligations to a former lender in December 2018, we acquired an additional 40% working interest, bringing
our aggregate working interest to 70% in Michigan. The first well is expected to be drilled in the summer of 2021 if new financing
is secured.
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 November 30, 2020,
we had no encumbrances on our crude oil project in Michigan.
Results of Operations – Nine months ended
November 30, 2020 compared to the nine months ended November 30, 2019
California Crude Oil Prices
The price we receive for crude oil sales in
California is based on prices posted for Midway-Sunset crude oil delivery contracts, less deductions that vary by grade of crude
oil sold and transportation costs. The posted Midway-Sunset price generally moves in correlation to, and at a discount to, prices
quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) crude oil,
Cushing, Oklahoma delivery contracts. We do not have any natural gas revenues in California.
There has been a significant amount of volatility
in crude oil prices and a dramatic decline 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 price per barrel of crude oil was $98.78. This volatility and decline
in crude oil prices has continued as evidenced by the NYMEX daily closing price of WTI crude oil on April 20, 2020 when it closed
at a negative $36.98; the April 2020 monthly average WTI price was $16.55; and our monthly realized price for April 2020 was $16.96
per barrel. This volatility and decline in the price of crude oil has had a substantial negative impact on our cash flow from
our producing California properties. While there has been some improvement in crude oil prices since April 2020, there is no guarantee
that this trend will continue.
It is beyond our ability to accurately predict
how long crude oil prices will continue to remain at these lower price levels; when or at what level they may begin to stabilize;
or when they may rebound to 2014 levels, as there are many factors beyond our control that dictate the price we receive on our
crude oil sales.
A comparison of the average WTI price and average
realized crude oil sales price for the nine months ended November 30, 2020 and 2019 is shown in the table below:
|
|
Nine Months Ended
|
|
|
|
|
|
November 30, 2020
|
|
November 30, 2019
|
|
Percentage Change
|
|
Average nine month WTI crude oil price (Bbl)
|
|
$
|
35.07
|
|
$
|
57.51
|
|
(39.0
|
%)
|
Average nine month realized crude oil sales price (Bbl)
|
|
$
|
32.52
|
|
$
|
60.77
|
|
(46.5
|
%)
|
For the nine months ended November 30, 2020,
the average WTI price was $35.07 and our average realized crude oil sale price was $32.52, representing a discount of $2.55 per
barrel or 7.3% lower than the average WTI price. In comparison, for the nine months ended November 30, 2019, the average WTI price
was $57.51 and our average realized sale price was $60.77 representing a premium of $3.26 per barrel or 5.7% higher 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 nine
months ended November 30, 2020 decreased $227,292 or 45.3% to $274,085 in comparison to revenue of $501,377 for the nine months
ended November 30, 2019. The average sale price of a barrel of crude oil for the nine months ended November 30, 2020 was $32.52
in comparison to $60.77 for the nine months ended November 30, 2019. The decrease of $28.25 or 46.5% per barrel in the average
realized price of a barrel of crude oil accounted for over 100.0% of the decrease in crude oil revenue for the nine months ended
November 30, 2020. The 2019 novel coronavirus (“COVID-19") that has spread to countries throughout the world including
the United States has had a substantial negative impact on the demand for crude oil and is largely responsible for the decline
in crude oil prices.
Our net sales volume for the nine months ended
November 30, 2020 was 8,427 barrels of crude oil in comparison to 8,250 barrels sold for the nine months ended November 30, 2019.
This increase in crude oil sales volume of 177 barrels or 2.1% was not sufficient enough to offset the decrease in revenue due
to lower crude oil prices during the nine months ended November 30, 2020.
The gravity of our produced crude oil in California
ranges between 14° API and 16° API. Production for the nine months ended November 30, 2020 was from 20 wells resulting
in 5,495 well days of production in comparison to 5,379 well days of production for the nine months ended November 30, 2019.
Our crude oil sales revenue for the nine months
ended November 30, 2020 and 2019 is set forth in the following table:
|
|
Nine Months Ended
November 30, 2020
|
|
|
Nine Months Ended
November 30, 2019
|
|
Project
|
|
Revenue
|
|
|
Percentage
|
|
|
Revenue
|
|
|
Percentage
|
|
California – East Slopes Project
|
|
$
|
274,085
|
|
|
|
100.0
|
%
|
|
$
|
501,377
|
|
|
|
100.0
|
%
|
*Our average
realized sale price on a BOE basis for the nine months ended November 30, 2020 was $32.52 in comparison to $60.77 for the nine
months ended November 30, 2019, representing a decrease of $28.25 or 46.5% per barrel.
Operating Expenses
Total operating expenses for the nine months
ended November 30, 2020 were $605,954, a decrease of $117,710 or 16.3% compared to $723,664 for the nine months ended November
30, 2019. Operating expenses for the nine months ended November 30, 2020 and 2019 are set forth in the table below:
|
|
Nine Months Ended
November 30, 2020
|
|
|
Nine Months Ended
November 30, 2019
|
|
|
Expenses
|
|
|
Percentage
|
|
|
BOE
Basis
|
|
|
Expenses
|
|
|
Percentage
|
|
|
BOE
Basis
|
Production expenses
|
|
$
|
136,218
|
|
|
|
22.5
|
%
|
|
|
|
|
|
$
|
134,276
|
|
|
|
18.6
|
%
|
|
|
|
Exploration and drilling expenses
|
|
|
73
|
|
|
|
0.0
|
%
|
|
|
|
|
|
|
123
|
|
|
|
0.0
|
%
|
|
|
|
Depreciation, depletion, amortization (“DD&A”)
|
|
|
42,318
|
|
|
|
7.0
|
%
|
|
|
|
|
|
|
44,210
|
|
|
|
6.1
|
%
|
|
|
|
General and administrative (“G&A”) expenses
|
|
|
427,345
|
|
|
|
70.5
|
%
|
|
|
|
|
|
|
545,055
|
|
|
|
75.3
|
%
|
|
|
|
Total operating expenses
|
|
$
|
605,954
|
|
|
|
100.0
|
%
|
|
$
|
71.91
|
|
|
$
|
723,664
|
|
|
|
100.0
|
%
|
|
$
|
87.72
|
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, 2020, these expenses increased by $1,942 or 1.4% to $136,218 in comparison to $134,276 for the nine months ended
November 30, 2019. For the nine months ended November 30, 2020 and 2019, we had 20 wells on production in California. Production
expense on a barrel of oil equivalent (“BOE”) basis for the nine months ended November 30, 2020 and 2019 was $16.16
and $16.28, respectively. Production expenses represented 22.5% and 18.6% of total operating expenses for the nine months ended
November 30, 2020 and 2019, 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, 2020, these expenses decreased $50 to $73 in comparison
to $123 the nine months ended November 30, 2019. Exploration and drilling expenses represented 0.0% and 0.0% of total operating
expenses for the nine months ended November 30, 2020 and 2019, 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, 2020, DD&A expenses decreased $1,892 or 4.3% to $42,318 in comparison to $44,210
for the nine months ended November 30, 2019. On a BOE basis, DD&A expense was $5.02 and $5.36 for the nine months ended November
30, 2020 and 2019, respectively. DD&A expenses represented 7.0% and 6.1% of total operating expenses for the nine months ended
November 30, 2020 and 2019, respectively.
General and administrative (“G&A”)
expenses include the salaries of our six full-time employees, including management. During the first three months of the prior
fiscal year ended February 29, 2020, fifty percent (50%) of certain management salaries were being deferred by the Company. However,
effective June 1, 2019, the salary deferral program ended and those base salaries were temporarily reduced by half. Additionally,
director fees are being suspended temporarily. Both of these compensation changes were reviewed by the Board of Directors during
June 2020 and based on the financial status of the Company it was decided to continue these temporary changes. 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. For the nine
months ended November 30, 2020, G&A expenses decreased $117,710 or 21.6% to $427,345 in comparison to $545,055 for the nine
months ended November 30, 2019. We received, as Operator, administrative overhead reimbursement of $39,965 during the nine months
ended November 30, 2020 for the East Slopes Project which was used to directly offset certain employee salaries. We are continuing
a program of controlling our G&A costs wherever possible. G&A expenses represented 70.5% and 75.3% of total operating expenses
for the nine months ended November 30, 2020 and 2019, respectively.
Interest expense, net for the nine months ended
November 30, 2020 decreased $242,824 or 57.1% to $182,246 in comparison to $425,070 for the nine months ended November 30, 2019.
Results of Operations – Three months
ended November 30, 2020 compared to the three months ended November 30, 2019
A comparison of the average WTI price and average
realized crude oil sales price at our East Slopes Project in California for the three months ended November 30, 2020 and 2019 is
shown in the table below:
|
|
Three Months Ended
|
|
|
|
|
|
November 30, 2020
|
|
November 30, 2019
|
|
Percentage Change
|
|
Average three month WTI crude oil price (Bbl)
|
|
$
|
39.99
|
|
$
|
55.98
|
|
(28.6
|
%)
|
Average three month realized crude oil sales price (Bbl)
|
|
$
|
36.58
|
|
$
|
57.92
|
|
(36.8
|
%)
|
For the three months ended November 30, 2020,
the average WTI price was $39.99 and our average realized crude oil sale price was $36.58, representing a discount of $3.41 per
barrel or 8.5% lower than the average WTI price. In comparison, for the three months ended November 30, 2019, the average WTI price
was $55.98 and our average realized sale price was $57.92 representing a premium of $1.94 per barrel or 3.5% higher 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 November 30, 2020, decreased $45,642 or 32.2% to $96,322 in comparison to revenue of $141,964 for the three months
ended November 30, 2019. The average sale price of a barrel of crude oil for the three months ended November 30, 2020 was $36.58
in comparison to $57.92 for the three months ended November 30, 2019. The decrease of $21.34 or 36.8% per barrel in the average
realized price of a barrel of crude oil accounted for over 100.0% of the decrease in crude oil revenue for the three months ended
November 30, 2020.
Our net sales volume for the three months ended
November 30, 2020 was 2,633 barrels of crude oil in comparison to 2,451 barrels sold for the three months ended November 30, 2019.
This increase in crude oil sales volume of 182 barrels or 7.4% was not sufficient enough to offset the decrease in revenue due
to lower crude oil prices during the three months ended November 30, 2020.
The gravity of our produced crude oil in California
ranges between 14° API and 16° API. Production for the three months ended November 30, 2020 was from 20 wells resulting
in 1,820 well days of production in comparison to 1,749 well days of production for the three months ended November 30, 2019.
Our crude oil sales revenue for the three months
ended November 30, 2020 and 2019 is set forth in the following table:
|
|
Three Months Ended
November 30, 2020
|
|
|
Three Months Ended
November 30, 2019
|
|
Project
|
|
Revenue
|
|
|
Percentage
|
|
|
Revenue
|
|
|
Percentage
|
|
California – East Slopes Project
|
|
$
|
96,322
|
|
|
|
100.0
|
%
|
|
$
|
141,964
|
|
|
|
100.0
|
%
|
*Our average
realized sale price on a BOE basis for the three months ended November 30, 2020 was $36.58 in comparison to $57.92 for the three
months ended November 30, 2019, representing a decrease of $21.34 or 36.8% per barrel.
Operating Expenses
Total operating expenses for the three months
ended November 30, 2020 were $191,937, a decrease of $22,715 or 10.6% compared to $214,652 for the three months ended November
30, 2019. Operating expenses for the three months ended November 30, 2020 and 2019 are set forth in the table below:
|
|
Three Months Ended
November 30, 2020
|
|
|
Three Months Ended
November 30, 2019
|
|
|
|
Expenses
|
|
|
Percentage
|
|
|
BOE
Basis
|
|
|
Expenses
|
|
|
Percentage
|
|
|
BOE
Basis
|
|
Production expenses
|
|
$
|
53,581
|
|
|
|
28.0
|
%
|
|
|
|
|
|
$
|
44,733
|
|
|
|
20.8
|
%
|
|
|
|
|
Exploration and drilling expenses
|
|
|
73
|
|
|
|
0.0
|
%
|
|
|
|
|
|
|
9
|
|
|
|
0.0
|
%
|
|
|
|
|
Depreciation, depletion, amortization (“DD&A”)
|
|
|
13,491
|
|
|
|
7.0
|
%
|
|
|
|
|
|
|
13,288
|
|
|
|
6.2
|
%
|
|
|
|
|
General and administrative (“G&A”) expenses
|
|
|
124,792
|
|
|
|
65.0
|
%
|
|
|
|
|
|
|
156,622
|
|
|
|
73.0
|
%
|
|
|
|
|
Total operating expenses
|
|
$
|
191,937
|
|
|
|
100.0
|
%
|
|
$
|
72.90
|
|
|
$
|
214,652
|
|
|
|
100.0
|
%
|
|
$
|
87.58
|
|
Production expenses for the three months ended
November 30, 2020, increased by $8,848 or 19.8% to $53,581 in comparison to $44,733 for the three months ended November 30, 2019.
The increase was primarily due to increases in property taxes and regulatory expenses. For the three months ended November 30,
2020 and 2019 we had 20 wells on production in California. Production expense on a barrel of oil equivalent (“BOE”)
basis for the three months ended November 30, 2020 and 2019 were $20.35 and $18.25, respectively. Production expenses represented
28.0% and 20.8% of total operating expenses for the three months ended November 30, 2020 and 2019, respectively.
Exploration and drilling expenses for the three
months ended November 30, 2020, increased $64 to $73 in comparison to $9 for the three months ended November 30, 2019. Exploration
and drilling expenses represented 0.0% and 0.0% of total operating expenses for the three months ended November 30, 2020 and 2019,
respectively.
DD&A expenses for the three months ended
November 30, 2020, increased $203 or 1.5% to $13,491 in comparison to $13,288 for the three months ended November 30, 2019. DD&A
on a BOE basis was $5.12 and $5.42 for the three months ended November 30, 2020 and 2019, respectively. DD&A expenses represented
7.0% and 6.2% of total operating expenses for the three months ended November 30, 2020 and 2019, respectively.
G&A expenses for the three months ended
November 30, 2020, decreased $31,830 or 20.3% to $124,792 in comparison to $156,622 for the three months ended November 30, 2019.
Effective June 1, 2019, the salary deferral program that was in place ended and those base salaries were reduced by half. Additionally,
director fees are being suspended temporarily. Both of these compensation changes were reviewed by the Board of Directors during
June 2020 and based on the financial status of the Company it was decided to continue these temporary changes. Other items included
in our G&A expenses are legal and accounting expenses, director fees, 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. We
received, as Operator in California, administrative overhead reimbursement of $13,321 during the three months ended November 30,
2020 for the East Slopes Project which was used to directly offset certain employee salaries. We are continuing a program of reducing
all of our G&A costs wherever possible. G&A expenses represented 65.0% and 73.0% of total operating expenses for the three
months ended November 30, 2020 and 2019, respectively.
Interest expense, net for the three months
ended November 30, 2020 decreased $95,833 or 63.0% to $56,302 in comparison to $152,135 for the three months ended November 30,
2019.
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 Michigan and the availability of capital resource financing.
There has been a significant amount of volatility in crude oil prices and dramatic decline 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. This volatility and decline in crude oil prices has continued as evidenced by the NYMEX daily
closing price of WTI crude oil on April 20, 2020 when it closed at a negative $36.98; the April 2020 monthly average WTI price
was $16.55; and our monthly realized price for April 2020 was $16.96 per barrel. This volatility and decline in the price of crude
oil has had a substantial negative impact on our cash flow from our producing California properties. While there has been some
improvement in crude oil prices since April 2020, there is no guarantee that this trend will continue. Most recently our average
realized price declined from $60.77 for the nine months ended November 30, 2019 to $32.52 for the nine months ended November 30,
2020, demonstrating the continued volatility in crude oil prices. It is beyond our ability to accurately predict how long crude
oil prices will continue to remain at these lower price levels; when or at what level they may begin to stabilize; or when they
may continue to rebound as there are many factors beyond our control that dictate the price we receive for our crude oil sales.
In the 2021-2022 fiscal year we plan to spend
approximately $525,000 in capital investments in California when new financing is secured. However, our actual expenditures may
vary significantly from this estimate if our plans for exploration and development activities change during the year or if we are
unable to obtain financing to fund these capital investments. 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 November
30, 2020 in comparison to February 29, 2020 are set forth in the table below:
|
|
|
|
|
|
|
|
Increase
|
|
|
Percentage
|
|
|
|
November 30, 2020
|
|
|
February 29, 2020
|
|
|
(Decrease)
|
|
|
Change
|
|
Cash
|
|
$
|
61,717
|
|
|
$
|
94,043
|
|
|
$
|
(32,326
|
)
|
|
|
(34.4
|
%)
|
Current Assets
|
|
$
|
246,027
|
|
|
$
|
240,434
|
|
|
$
|
5,593
|
|
|
|
2.3
|
%
|
Total Assets
|
|
$
|
888,683
|
|
|
$
|
917,456
|
|
|
$
|
(28,773
|
)
|
|
|
(3.1
|
%)
|
Current Liabilities
|
|
$
|
(4,432,228
|
)
|
|
$
|
(4,063,712
|
)
|
|
$
|
368,516
|
|
|
|
9.1
|
%
|
Total Liabilities
|
|
$
|
(6,009,148
|
)
|
|
$
|
(5,556,063
|
)
|
|
$
|
453,085
|
|
|
|
8.2
|
%
|
Working Capital Deficit
|
|
$
|
(4,186,201
|
)
|
|
$
|
(3,823,278
|
)
|
|
$
|
362,923
|
|
|
|
9.5
|
%
|
Our working capital deficit increased
approximately $0.36 million or 9.5% to approximately $4.2 million at November 30, 2020 in comparison to
approximately $3.8 million at February 29, 2020. The increase in our working capital deficit was due to an increase in
accounts payable, accrued interest, the paycheck protection program (PPP) loan we received and a decline in our cash balance
offset by a decline in our line of credit balance, elimination of related party debt, and an increase in our prepaid assets.
While we have ongoing positive cash flow from
our crude oil operations in California, we have not yet been able to generate sufficient cash flow to cover all of our G&A
and interest expense requirements. 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 the sale of assets. While we have positive cash flow from our operations in California,
we will have to rely on the capital markets to fund future operations and growth. Our business model is focused on acquiring exploration
or development properties as well as existing production. Our ability to generate future revenues and operating cash flow will
depend on successful exploration, and/or acquisition of crude oil 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 volatility in the credit and capital markets as well as the decline in crude oil prices from June of 2014 price levels
has restricted our ability to obtain needed capital. 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. The sale of all or part 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, 2020 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, 2020, we have an accumulated deficit of
$29.4 million and a working capital deficit of $4.2 million which raises substantial
doubt about our ability to continue as a going concern.
In the current fiscal year, we will continue
to seek additional financing for our planned exploration and development activities in California and Michigan. 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, 2020,
we received crude oil sales revenue from 20 wells in California. Our commitment to improving corporate profitability remains unchanged.
We experienced a decrease in revenues of $227,292 or 45.3% to $274,085 for the nine months ended November 30, 2020 in comparison
to revenues of $501,377 for the nine months ended November 30, 2019. The decrease of $28.25 or 46.5% per barrel in the average
realized price of a barrel of crude oil accounted for over 100.0% of the decrease in crude oil revenue for the nine months ended
November 30, 2020. For the nine months ended November 30, 2020, we had an operating loss of $331,869 in comparison to an operating
loss of $222,287 for the nine months ended November 30, 2019.
Our balance sheet at November 30, 2020 reflects
total assets of approximately $0.89 million in comparison to approximately $0.92 million at February 29, 2020. The decrease of
$28,773 is primarily due to cash outflow from operations and depletion of our crude oil properties.
At November 30, 2020, total liabilities were
approximately $6.0 million in comparison to approximately $5.6 million at February 29, 2020. The increase in liabilities of $453,085
was primarily due to an increase in accounts payable and the paycheck protection program (PPP) loan.
The issued and outstanding shares of common
stock at November 30, 2020 increased by 6,958,758 shares to 60,491,122 in comparison to the February 29, 2020 balance of 53,532,364
shares as a result of the conversion of a related party note payable. The common stock issuance was valued at $27,835.
Additional paid in capital (APIC) increased
$25,298 to $24,249,081 at November 30, 2020 from $24,223,783 as a result of the conversion of a related party note payable.
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, 2020
|
|
|
Nine Months
Ended
November 30, 2019
|
|
|
Increase
(Decrease)
|
|
|
Percentage
Change
|
|
Net cash used in operating activities
|
|
$
|
(17,019
|
)
|
|
$
|
(48,094
|
)
|
|
|
31,075
|
|
|
|
64.6
|
%
|
Net cash provided by (used in) investing activities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Net cash (used in) provided by financing activities
|
|
$
|
(15,307
|
)
|
|
$
|
29,000
|
|
|
|
(44,307
|
)
|
|
|
(152.8
|
%)
|
Cash Flow Used In Operating
Activities
Cash flow from operating activities is
derived from the production of our crude oil reserves and changes in the balances of non-cash accounts, receivables, payables
or other non-energy property asset account balances. For the nine months ended November 30, 2020, cash flow used in operating
activities was $17,019 in comparison to cash flow used in operating activities of $48,094 for the nine months ended November
30, 2019. The change in our cash flow used in operating activities of $31,075 for the nine months ended November 30, 2020 was
due to a reduction in our non-cash operating expenses, an increase in our prepaid assets, liability balances and our net
loss. Changes in non-cash account balances primarily relating to DD&A and amortization of debt discount. Variations in
cash flow from operating activities may impact our level of exploration and development expenditures.
Cash Flow Provided By (Used In) Investing
Activities
Cash flow from investing activities is
derived from changes in crude oil property balances and any lending activities. Cash flow provided by (used in) our investing
activities for the nine months ended November 30, 2020 was $-0- in comparison to cash flow provided by (used in) our investing
activities of $-0- for the nine months ended November 30, 2019.
Cash Flow (Used In) Provided By Financing Activities
Cash flow from financing activities is derived
from changes in long-term liability account balances or in equity account balances, excluding retained earnings. Cash flow used
in our financing activities was $15,307 for the nine months ended November 30, 2020 in comparison to cash flow provided by our
financing activities of $29,000 for the nine months ended November 30, 2019. This change in our cash flow provided by (used in)
activities was primarily due to the recognition of annual insurance premium financing activities. For the nine months ended November
30, 2020, we made total payments of $45,000 to our 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, 2020.
Current debt (Short-term
borrowings)
Convertible Promissory Note Payable –
Related Party
During the twelve months ended February 29,
2020, the Company’s Chairman, President and Chief Executive Officer loaned the Company $27,835 for general operating expenses
under a Convertible Note Purchase Agreement. The Note had a maturity date of July 12, 2020 and carried no interest, fees or penalties.
By the terms of the Convertible Note Purchase Agreement, Mr. Westmoreland had also agreed to loan up to an additional $22,165 in
funding for the Company, if and when agreed upon, but this additional amount was not ever loaned pursuant to the Note.
On July 12, 2020, the Convertible Promissory
Note issued on January 14, 2020 matured. The Note was not repaid in full on or prior to the maturity date, so, pursuant to the
terms of the conversion feature of the Convertible Promissory Note, the $27,835 balance of the Convertible Note was converted into
the Company’s common stock shares on July 13, 2020. The conversion price was $0.004 per share resulting in 6,958,758 shares
being issued. The balance of the Note was $-0- and $27,835 at November 30, 2020 and February 29, 2020, respectively.
12% Subordinated Notes
Our 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 us and accrue interest at 12% per annum, payable semi-annually on January 29th and
July 29th. On January 29, 2015, we 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. The
980,000 warrants held by ten noteholders expired on January 29, 2019.
We have informed the 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
$565,000 was payable in full at the amended maturity date of the Notes, and has not been paid. Interest continues to accrue on
the unpaid $565,000 principal balance. 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, we may then elect a
mandatory conversion of the unpaid principal and interest into our common stock at a conversion rate equal to 75% of the average
closing price of our common stock over the 20 consecutive trading days preceding December 31, 2018. As of November 30, 2020, no
conversion of the unpaid principal and interest into the Company’s common stock has occurred. The accrued interest on the
12% Notes at November 30, 2020 and February 29, 2020 was $323,324 and $272,428, respectively. There was no unamortized debt discount
remaining at November 30, 2019 and February 28, 2019.
12% Note balances at November 30, 2020 and
February 29, 2020 are set forth in the table below:
|
|
November 30, 2020
|
|
|
February 29, 2020
|
|
12% Subordinated Notes
|
|
$
|
315,000
|
|
|
$
|
315,000
|
|
12% Subordinated Notes – related party
|
|
|
250,000
|
|
|
|
250,000
|
|
Total 12% Subordinated Notes balance
|
|
$
|
565,000
|
|
|
$
|
565,000
|
|
12% Note balances – accrued interest
at November 30, 2020 and February 29, 2020 are set forth in the table below:
|
|
November 30, 2020
|
|
|
February 29, 2020
|
|
Accrued interest 12% Subordinated Notes
|
|
$
|
88,338
|
|
|
$
|
59,962
|
|
Accrued interest 12% Subordinated Notes – related party
|
|
|
234,986
|
|
|
|
212,466
|
|
Total accrued interest 12% Subordinated Notes
|
|
$
|
323,324
|
|
|
$
|
272,428
|
|
The accrued interest owed on the 12% Subordinated
Note to the related party is presented on our Balance Sheets under the caption Accounts payable – related party rather
than under the caption Accrued interest.
Production Revenue Payable
Since December 2018, the Company has been conducting
a fundraising program to fund the drilling of future wells in California and Michigan and to settle some of its historical debt.
The purchasers of production payment interests will receive a production revenue payment on future wells to be drilled in California
and Michigan in exchange for their purchase. As of November 30, 2020, 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 $998,879 as of November 30, 2020, 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, 2020 and 2019, amortization of the debt discount on these payables amounted to
$88,786 and $336,658, respectively, which has been included in interest expense in the statements of operations.
Production revenue payable balances at November
30, 2020 and February 29, 2020 are set forth in the table below:
|
|
November 30, 2020
|
|
|
February 29, 2020
|
|
Estimated payments of production revenue payable
|
|
$
|
1,948,979
|
|
|
$
|
2,054,766
|
|
Less: unamortized discount
|
|
|
(471,922
|
)
|
|
|
(666,495
|
)
|
|
|
|
1,477,057
|
|
|
|
1,388,271
|
|
Less: current portion
|
|
|
(50,269
|
)
|
|
|
(43,069
|
)
|
Net production revenue payable – long-term
|
|
$
|
1,426,788
|
|
|
$
|
1,345,202
|
|
Paycheck Protection Program (PPP) Loan
On March 27, 2020, President Trump signed into
law the Coronavirus Aid, Relief, and Economic Security Act commonly referred to as the CARES Act. One component of the CARES Act
was the paycheck protection program (“PPP”) which provides small business with the resources needed to maintain their
payroll and cover applicable overhead. The PPP is implemented by the Small Business Administration (“SBA”) with support
from the Department of the Treasury. The PPP provides funds to pay up to eight weeks of payroll costs including benefits. Funds
can also be used to pay interest on mortgages, rent, and utilities. The Company applied for, and was accepted to participate in
this program. On May 11, 2020, the Company received funding for approximately $74,355.
The loan is a two-year loan with a maturity
date of May 5, 2022. The loan bears an annual interest rate of 1%. The loan shall be payable monthly with the first six monthly
payments deferred. It is the Company’s intent to apply for loan forgiveness under the provisions of Section 1106 of the CARES
Act. Loan forgiveness is subject to the sole approval of the SBA. The Company is eligible for loan forgiveness in an amount equal
to payments made during the 8-week period beginning on the Loan date, with the exception that no more than 25.0% of the amount
of loan forgiveness may be for expenses other than payroll expenses. The Company used all loan proceeds to partially subsidize
direct payroll expenses. The Company expects the loan to be fully forgiven.
Line of Credit
The Company has 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 is secured by the personal guarantee of its Chairman, President and Chief Executive Officer. On July 10,
2017 a $700,000 portion of the outstanding line of credit balance was converted to a 24 month fixed term annual percentage interest
rate of 3.244% with interest payable monthly. On July 10, 2019, the 24 month fixed term loan amount of $700,000 was renewed at
the same annual percentage interest rate of 3.244% for an additional 24 months. The remaining principal balance of the line of
credit has a stated reference rate of 0.249% + 337.5 basis points with interest payable monthly. The reference rate is based on
the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.
During the nine months ended November 30, 2020
and 2019, the Company received advances on the line of credit of $-0- and $74,000, respectively. During the nine months ended November
30, 2020 and 2019, the Company made payments to the line of credit of $45,000 and $45,000, respectively. Interest converted to
principal for the nine months ended November 30, 2020 and 2019 was $21,744 and $23,624, respectively. At November 30, 2020 and
February 29, 2020, the line of credit had an outstanding balance of $849,145 and $872,401, respectively.
Note Payable
In December 2018, we were able to settle an
outstanding balance owed to one of our third-party vendors. This settlement resulted in a $120,000 note payable issued to the vendor.
Additionally, we agreed to issue 2,000,000 shares of the Company’s common stock to the vendor as a part of the settlement.
Based on the closing price of the Company’s common stock on the date of the settlement, 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 through maturity of the note. At November 30, 2020, the note principal balance
of $120,000 and the accrued interest had not been paid and were outstanding. At November 30, 2020 and February 29, 2020, the accrued
interest on the Note was $23,000 and $14,000, respectively.
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. As of November
30, 2020, we had no encumbrances on our crude oil project in Michigan.
Operating Leases
The Company leases 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 was a 24 month lease that
expired in October 2020. The new lease in Friendswood is a 12 month lease 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 also short-term leases 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 Balance Sheet classification of lease assets
and liabilities is as follows:
|
|
November 30, 2020
|
|
|
February 29, 2020
|
|
Assets
|
|
|
|
|
|
|
|
|
Operating lease right-of use assets, beginning balance
|
|
$
|
5,857
|
|
|
$
|
13,787
|
|
Current period amortization
|
|
|
(5,857
|
)
|
|
|
(7,930
|
)
|
Total operating lease right-of-use asset
|
|
|
—
|
|
|
|
5,857
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Operating lease liability – current
|
|
|
—
|
|
|
|
5,857
|
|
Operating lease liability – long-term
|
|
|
—
|
|
|
|
—
|
|
Total lease liabilities
|
|
$
|
—
|
|
|
$
|
5,857
|
|
Rent expense for the nine months ended November
30, 2020 and 2019 was $17,642 and $17,842, 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.
Subsequent Event - Change in Transfer Agent
Effective December 22, 2020, the Company appointed
Sedona Equity Registrar & Transfer, Incorporated (“Sedona”) as its transfer agent and shareholder support provider.
On December 28, 2020, all of the Company's directly held shares of common stock, files and information have been transferred from
Computershare to Sedona. In this capacity, Sedona will manage all stock registry requests for shareholders, including change of
address, certificate replacement and transfer of shares. All stock and investment information will automatically transfer to Sedona
from our former Transfer Agent and Registrar, Computershare, and no action is required on the part of the shareholder.
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 28.4%.
We anticipate revenues will continue to increase
as the Company participates in the drilling of more wells in the East Slopes Project in California and as our drilling operations
begin in Michigan. However given the current volatility and instability in hydrocarbon prices, the timing of any drilling activity
in California and Michigan will be dependent on a sustained improvement in hydrocarbon prices and a successful refinancing or restructuring
of our credit facility.
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 November 30,
2020 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 29, 2020.
Off-Balance Sheet Arrangements
As of November 30, 2020, 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.