DAYBREAK OIL AND GAS, INC. 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 six months endedAugust 31, 2022 and in our Annual Report on Form 10-K for the year endedFebruary 28, 2022 . References to "Daybreak", the "Company", "we", "us" or "our" meanDaybreak 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 future financing;
· 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 endedFebruary 28, 2022 and in this Form 10-Q for the six months endedAugust 31, 2022 occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically undertake no obligation to publicly update or revise any information contained in any forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except
as required by law.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
16 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 inthe United States , and all of our revenues are derived from sales to customers withinthe United States . Currently, we are in the process of developing a multi-well oilfield project inKern 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 inCalifornia , 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 endedFebruary 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 inCalifornia . Refer to our discussion in Item 2. Properties, in our Annual Report on Form 10-K for the year endedFebruary 28, 2022 for more information on our multi-well oilfield East Slopes project inCalifornia .
The East Slopes Project is located in the southeastern part of theSan Joaquin Basin nearBakersfield, California . Drilling targets are porous and permeable sandstone reservoirs that exist at depths of 1,200 feet to 4,500 feet. SinceJanuary 2009 , we have participated in the drilling of 25 wells in this project. We have been the Operator at theEast Slopes Project sinceMarch 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 theEast Slopes Project produce from five reservoirs at our Sunday, Bear, Black, Ball andDyer 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 theDyer Creek property has one producing well. During the six months endedAugust 31, 2021 we had production from 20 crude oil wells. 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 andDyer 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 We are currently in the planning and permitting process to undertake a multi-well developmental drilling program commencing in the late fall of 2022 or first quarter of 2023. These plans are dependent on a stabilization of crude oil prices. We plan to spend approximately$435,000 drilling three development wells in the current 2022-2023 fiscal year. 17
In
The Burnett Lease and the Doud Lease are located in close proximity to each another inMonterey County . They are part of a geological feature named the Monroe Swell. The Burnett Lease presently has two directional wells that are being produced from a depth of 2,900' from the Beedy Sand zone. The oil being produced is 19° gravity. We have future plans of drilling one horizontal well on this lease and to convert and old well bore into a salt water disposal well ("SWDW"). The Doud Lease has four directional well bores with three of those being produced from a depth of 3,300' from the Doud A Sand zone. The oil being produced is 22° gravity. We have future plans of drilling one additional directional well on this lease. The SWDW for the Burnett Lease will be utilized for the Doud lease as well. The Brentwood Lease is located inContra-Costa County . This lease is part of a geological feature named the Meganos Unconformity. There are presently two directional wells producing from this lease. Additionally, another well bore will be worked over after a SWDW permit has been approved before putting it back in production. The wells are producing from the Second Massive Sand from a depth of between 4,000'- 4,500'. The oil being produced is 32°gravity. A work over was successfully completed on one well to decrease water production and to increase oil production. It will be brought back into production when the SWDW is completed. Sunflower LawsuitSunflower 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 onDecember 29, 2021 in theAlameda 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. OnFebruary 22, 2022 ,Real Party inInterest Reabold California, LLC filed a motion to transfer the case to theContra Costa County Superior Court . OnMarch 22, 2022 , theAlameda County Superior Court ordered the case transferred to theContra Costa County Superior Court . OnAugust 15, 2022 , theContra Costa County Superior Court provided notice that the transfer has 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. TheCalifornia Attorney General is defending the state agency,
which disputes Petitioner's claims. At this time, it is unclear when the litigation will be resolved.
The Company is not aware of any environmental claims existing as ofAugust 31, 2021 . 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
OnOctober 17, 2018 , a working interest partner in theEast Slopes Project inCalifornia filed a UCC financing statement in regards to payables owed to the partner by the Company.
Results of Operations - Six months ended
California Crude Oil Prices The prices we receive for crude oil sales inCalifornia from the East Slopes project and fromReabold California, LLC ("Reabold") are based on prices posted for Midway-Sunset andBuena 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 andBuena Vista prices generally move in correlation to prices quoted on theNew York Mercantile Exchange (NYMEX") for spotWest Texas intermediate ("WTI") crude oil,Cushing, Oklahoma delivery contracts. California Natural Gas Prices The price we receive for natural gas sales from Reabold is based on ninety-five (95%) of the price published in Natural Gas Intelligence ("NGI") Gas Price Index under the column "Bidweek Averages" for "California", "PG&E Citygate" less an amount per MMBtu equal to the Silverado Path On System As-Available transport date, less the Silverado Path On System transmission shrinkage 18
rate for
There continues to be a significant amount of volatility in hydrocarbon prices and a corresponding fluctuation in our realized sale price of crude oil does exist. An example of this volatility is that in June of 2014 the monthly average price of WTI oil was$105.79 per barrel and our realized price per barrel of crude oil was$98.78 while inApril 2020 , the monthly average price of WTI crude oil was$16.55 and our monthly realized price was$16.96 per barrel. Finally, inAugust 2022 , the monthly average price of WTI oil was$93.67 per barrel and our realized price per barrel of crude oil was$92.43 . This volatility in crude oil prices has continued throughout most of the fiscal year endedFebruary 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 producingCalifornia 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 six months endedAugust 31, 2022 and 2021 is shown
in
the table below:
Six Months Ended
August 31, 2022 August 31, 2021 Percentage Change
Average six month WTI crude oil
price (Bbl) $ 104.99 $ 66.80 57.2 %
Average six month realized crude
oil sales price (Bbl) $ 102.97 $ 64.77 59.0 %
For the six months endedAugust 31, 2022 , the average WTI price was$104.99 and our average realized crude oil sale price was$102.97 , representing a discount of$2.02 per barrel or 1.9% lower than the average WTI price. In comparison, for the six months endedAugust 31, 2021 , the average WTI price was$66.80 and our average realized sale price was$64.77 representing a discount of$2.03 per barrel or 3.0% lower than the average WTI price. 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.
California Crude Oil Revenue and Production
Crude oil revenue inCalifornia for the six months endedAugust 31, 2022 increased$462,579 or 146.1% to$779,197 in comparison to revenue of$316,618 for the six months endedAugust 31, 2021 . The reason for the increase was the acquisition of the Reabold wells in centralCalifornia . The average sale price of a barrel of crude oil for the six months endedAugust 31, 2022 was$102.97 in comparison to$64.77 for the six months endedAugust 31, 2021 . The 2019 novel coronavirus ("COVID-19") that has spread throughout the world includingthe United States had a substantial negative impact on the demand for crude oil and was largely responsible for the volatility in crude oil prices for the last 18 months. The increase of$38.20 or 59.0% per barrel in the average realized price of a barrel of crude oil accounted for 40.4% of the increase in crude oil revenue for the six months endedAugust 31, 2022 . Our net crude oil sales volume for the six months endedAugust 31, 2022 was 7,567 barrels of crude oil in comparison to 4,888 barrels sold for the six months endedAugust 31, 2021 . This increase in crude oil sales volume of 2,679 barrels or 54.8% was primarily due to our acquisition of the Reabold property and its producing wells in centralCalifornia . The gravity of our produced crude oil in the East Slopes project ranges between 14° API and 16° API. The gravity of our produced crude oil in the Reabold project ranges between 17° API and 38° API.
Our crude oil sales revenue for the six months ended
Six Months Ended Six Months Ended
August 31, 2022 August 31, 2021
Project Revenue Percentage Revenue PercentageEast Slopes Project - crude oil sales$ 440,039 56.5 %$ 316,618 100.0 % Reabold Project - crude oil sales 338,859 43.5 %
- -
California Totals $ 778,898 100.0 % $ 316,618 100.0 %
Our natural gas sales revenue for the six months ended
Six Months Ended Six Months Ended
August 31, 2022 August 31, 2021
Project Revenue Percentage Revenue Percentage
Reabold Project - natural gas sales $ 9,748 100.0 % $
- -
Our average realized sale price on a BOE basis of crude oil and natural gas for the six months endedAugust 31, 2022 was$102.00 in comparison to$64.77 for the six months endedAugust 31, 2021 , representing an increase of$37.23 or 57.5% per barrel. 19 Operating Expenses Total operating expenses for the six months endedAugust 31, 2022 were$2,074,034 , an increase of$1,658,668 or 399.3%compared to$415,366 for the six months endedAugust 31, 2021 . Operating expenses for the six months endedAugust 31, 2022 and 2021 are set forth in the table below: Six Months Ended Six Months Ended August 31, 2022 August 31, 2021 BOE BOE Expenses Percentage Basis Expenses Percentage Basis Production expenses$ 359,199 17.3 %$ 99,569 24.0 % Exploration and drilling expenses 1,170 0.1 % 201 0.0 % Depreciation, depletion, amortization ("DD&A") 149,664 7.2 % 28,808 6.9 % Transaction (acquisition) expenses 1,025,541 49.4 % - - General and administrative ("G&A") expenses 538,460 26.0 % 286,788 69.1 % Total operating expenses$ 2,074,034 100.0 %$ 268.24 $ 415,366 100.0 %$ 84.98 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 six months endedAugust 31, 2022 , these expenses increased by$259,630 or 260.8% to$359,199 in comparison to$99,569 for the six months endedAugust 31, 2021 . For the six months endedAugust 31, 2022 , we had 24 wells on production from the East Slopes and Reabold projects in comparison to 20 wells on production in the East Slopes project for the six months endedAugust 31, 2021 . The increase of four wells was from the Reabold acquisition that occurred in lateMay 2022 . The increase in production expenses for the six months endedAugust 31, 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 six months endedAugust 31, 2022 and 2021 were$46.46 and$20.37 , respectively. Production expenses represented 17.3% and 24.0% of total operating expenses for the six months endedAugust 31, 2022
and
2021, respectively.
Exploration and drilling expenses include geological and geophysical ("G&G")
expenses as well as leasehold maintenance, plugging and abandonment ("P&A")
expenses and dry hole expenses. For the six months ended August 31, 2022 and
2021, these expenses were $1,170 and $201 , respectively. Exploration and
drilling expenses represented 0.1% and 0.0% of total operating expenses for the
six months ended August 31, 2022 and 2021, respectively.
Depreciation, depletion and amortization ("DD&A") expenses relate to equipment,
proven reserves and property costs, along with impairment, and is another
component of operating expenses. For the six months ended August 31, 2022 , DD&A
expenses increased $120,856 or 419.5% to $149,664 in comparison to $28,808 for
the six months ended August 31, 2021 . On a BOE basis, DD&A expense was $19.36
and$5.89 for the six months ended August 31, 2022 and 2021, respectively. DD&A
expenses represented 7.2% and 6.9% of total operating expenses for the six
months ended August 31, 2022 and 2021, respectively.
For the six months ended August 31, 2022 , we incurred transaction expenses of
$1,025,541 related to the acquisition of funding and to acquire the Reabold
crude oil and natural gas properties located in central California and to
eliminate our line of credit balance. For the six months ended August 31, 2021 ,
we did not incur any related expenses. Transaction expenses represented 49.4%
and 0.0% of total operating expenses for the six months ended August 31, 2022
and 2021, respectively.
General and administrative ("G&A") expenses include the salaries of six
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 six months ended August 31, 2022 , G&A expenses increased
$251,672 or 87.8% to $538,460 in comparison to $286,788 for the six months ended
August 31, 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 six months ended August 31, 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 26.0% and 69.1% of total operating expenses for the six
months ended August 31, 2022 and 2021, respectively.
During the six months ended August 31, 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.
Interest expense, net for the six months ended August 31, 2022 increased $22,979
or 19.9% to $138,576 in comparison to $115,597 for the six months ended August
31, 2021 .
20
Results of Operations - Three months ended
A comparison of the average WTI crude oil price and the average realized crude oil sales price for the three months endedAugust 31, 2022 and 2021 is shown in the table below: Three Months Ended August 31, 2022 August 31, 2021 Percentage Change Average three month WTI crude oil price (Bbl) $ 103.38 $ 70.52 46.4 % Average three month realized crude oil sales price (Bbl) $ 101.56 $ 67.75 49.9 % For the three months endedAugust 31, 2022 , the average WTI price was$103.38 and our average realized crude oil sale price was$101.56 , representing a discount of$1.82 per barrel or 1.8% lower than the average WTI price. In comparison, for the three months endedAugust 31, 2021 , the average WTI price was$70.52 and our average realized sale price was$67.75 representing a discount of$2.77 per barrel or 3.9% lower than the average WTI price. 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 ourCalifornia crude oil in comparison to the API gravity of quoted WTI crude oil.
California Crude Oil Revenue and Production
Crude oil revenue inCalifornia for the three months endedAugust 31, 2022 , increased$362,264 or 214.0% to$531,582 in comparison to revenue of$169,318 for the three months endedAugust 31, 2021 . The primary reason for the increase was the acquisition of the Reabold wells in centralCalifornia . The average sale price of a barrel of crude oil for the three months endedAugust 31, 2022 was$101.56 in comparison to$67.75 for the three months endedAugust 31, 2021 . The increase of$33.81 or 49.9% per barrel in the average realized price of a barrel of crude oil accounted for 23.3% of the increase in crude oil revenue for the three months endedAugust 31, 2022 . Our net sales volume for the three months endedAugust 31, 2022 was 5,234 barrels of crude oil in comparison to 2,499 barrels sold for the three months endedAugust 31, 2021 . This increase in crude oil sales volume of 2,735 barrels or 109.4% was due to our acquisition of the Reabold property and its producing wells in centralCalifornia . The gravity of our produced crude oil in the East Slopes project ranges between 14° API and 16° API. The gravity of our produced crude oil in the Reabold project ranges between 17° API and 38° API.
Our crude oil sales revenue for the three months ended
Three Months Ended Three Months Ended
August 31, 2022 August 31, 2021
Project Revenue Percentage Revenue PercentageEast Slopes Project - crude oil sales$ 192,424 36.2 %$ 169,318 100.0 % Reabold Project - crude oil sales 338,859 63.8 %
- -
California Totals $ 531,283 100.0 % $ 169,318 100.0 %
Our natural gas sales revenue for the three months ended
Three Months Ended Three Months Ended
August 31, 2022 August 31, 2021
Project Revenue Percentage Revenue Percentage
Reabold Project - natural gas sales $ 9,748 100.0 % $ - -
Our average realized sale price on a BOE basis of crude oil and natural gas for the three months endedAugust 31, 2022 was$100.21 in comparison to$67.75 for the three months endedAugust 31, 2021 , representing an increase of$32.46
or 47.9% per barrel. 21 Operating Expenses
Total operating expenses for the three months ended
Three Months Ended Three Months Ended
August 31, 2022 August 31, 2021
BOE BOE
Expenses Percentage Basis Expenses Percentage Basis
Production expenses $ 298,482 41.2 % $ 52,843 28.3 %
Exploration and drilling expenses 1,170 0.2 % 201 0.1 %
Depreciation, depletion,
amortization ("DD&A") 137,888 19.0 % 14,860 7.9 %
General and administrative ("G&A")
expenses 286,322 39.6 % 119,163 63.7 %
Total operating expenses $ 723,862 100.0 % $ 134.07 $ 187,067 100.0 % $ 74.86
Production expenses for the three months ended August 31, 2022 , increased by
$245,639 or 464.8% to $298,482 in comparison to $52,843 for the three months
ended August 31, 2021 . For the three months ended August 31, 2022 and 2021, we
had 19 and 20 wells, respectively, on production in our East Slopes project. For
the three months ended August 31, 2022 , we had four wells on production in the
Reabold project that we acquired in May 2022 . The increase in production
expenses for the three months ended August 31, 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 August 31, 2022 and 2021 were $55.28 and $21.15 ,
respectively. Production expenses represented 41.2% and 28.3% of total operating
expenses for the three months ended August 31, 2022 and 2021, respectively.
Exploration and drilling expenses for the three months ended August 31, 2022
were $1,170 in comparison to $201 for the three months ended August 31, 2021 .
Exploration and drilling expenses represented 0.1% and 0.1% of total operating
expenses for the three months ended August 31, 2022 and 2021, respectively.
DD&A expenses for the three months ended August 31, 2022 , increased $123,028 or
827.9% to $137,888 in comparison to $14,860 for the three months ended August
31, 2021 . DD&A on a BOE basis was $25.54 and $5.95 for the three months ended
August 31, 2022 and 2021, respectively. DD&A expenses represented 19.0% and 7.9%
of total operating expenses for the three months ended August 31, 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 August 31, 2022 , increased $167,159 or 140.3% to
$286,322 in comparison to $119,163 for the three months ended August 31, 2021 .
The primary reasons for the increase in G&A expense are related to the special
shareholders meeting held during the three months ended May 31, 2022 and the
annual shareholders meeting held during the three months ended August 31, 2022
in the amount of approximately $54,200 in aggregate and professional legal and
accounting services of approximately $61,000 related to the Reabold acquisition
on May 2022 . We are continuing a program of controlling our G&A costs wherever
possible. G&A expenses represented 39.6% and 63.7% of total operating expenses
for the three months ended August 31, 2022 and 2021, respectively.
Interest expense, net for the three months ended
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 inCalifornia andMichigan . 22
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 inCalifornia 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 . As an example, for the month ofApril 2020 the monthly average closing price of WTI crude oil was$16.55 and our monthly realized oil price was$16.96 per barrel. Finally, inMay 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 . Again in August, 2022, our average realized price was$92.36 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 producingCalifornia properties. It is beyond our ability to accurately predict crude oil prices over any substantial length of time. We plan to spend approximately$435,000 drilling three development wells in the current 2022-2023 fiscal year; however our actual expenditures may vary significantly from this estimate if our plans for exploration and development activities change during the year. Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the current fiscal year.
Changes in our capital resources at
Increase Percentage
August 31, 2022 February 28, 2022 (Decrease) Change
Cash $ 412,949 $ 139,573 $ 273,376 195.9 %
Restricted Cash $ 275,000 $ - $ 275,000 100.0 %
Current assets $ 1,240,430 $ 416,651 $ 823,779 197.7 %
Total assets $ 8,562,095 $ 975,704 $ 7,586,391 777.5 %
Current liabilities $ (2,861,272 ) $ (3,404,735 ) $ (543,463 ) (16.0 %)
Total liabilities $ (3,834,074 ) $ (4,322,908 ) $ (488,834 ) (11.3 %)
Working capital $ (1,620,842 ) $ (2,988,084 ) $ (1,367,242 ) (45.8 %)
Our working capital deficit decreased approximately$1.37 million or 45.8% to approximately$1.6 million atAugust 31, 2022 in comparison to approximately$2.99 million atFebruary 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. 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. We anticipate that we will have to rely on these capital markets to fund future operations and growth. Our business model is focused on acquiring exploration or development properties as well as existing production. Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of crude oil producing properties, which may very likely require us to continue to raise equity or
debt capital from outside sources.
Daybreak has ongoing capital commitments to develop certain leases pursuant to
their underlying terms. Failure to meet such ongoing commitments may result in
the loss of the right to participate in future drilling on certain leases or the
loss of the lease itself. These ongoing capital commitments will cause us to
seek additional forms of financing through various methods, including issuing
debt securities, equity securities, bank debt, or combinations of these
instruments which could result in dilution to existing security holders and
increased debt and leverage. The current uncertainty in the credit and capital
markets as well as the instability and volatility in crude oil prices since June
of 2014, has restricted our ability to obtain needed capital. The 2019 novel
coronavirus ("COVID-19") that spread to countries throughout the world including
the United States had a substantial negative impact on the demand for crude oil
and is largely responsible for the decline in crude oil prices. No assurance can
be given that we will be able to obtain funding under any loan commitments or
any additional financing on favorable terms, if at all. Sales of interests in
our assets may be another source of cash flow available to us.
23
The Company's financial statements for the six months endedAugust 31, 2022 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. We have incurred net losses since entering the crude oil exploration industry in 2005, and as of the six months endedAugust 31, 2022 , we have an accumulated deficit of$30.95 million and a working capital deficit of$1.6 million which raises substantial doubt about our ability to continue as a going concern. In the current fiscal year, we will need to seek additional financing for our planned exploration and development activities inCalifornia . 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 six months endedAugust 31, 2021 , 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 four producing wells in the recently acquired Reabold project. Both of these projects are located inCalifornia . Our commitment to improving corporate profitability remains unchanged. We experienced an increase in revenues of$472,028 or 149.1% to$788,646 for the six months endedAugust 31, 2022 in comparison to revenues of$316,618 for the six months endedAugust 31, 2021 . The increase of$37.23 or 57.5% in the average realized price BOE accounted for 38.6% of the increase in crude oil revenue for the six months endedAugust 31, 2022 . The increase in sales volume BOE accounted for the remaining 61.5% of the revenue increase. The increase in volume was primarily due to the four producing wells that we acquired in the recently completed acquisition ofReabold California, LLC . For the six months endedAugust 31, 2022 , we had an operating loss of$1,285,388 in comparison to an operating loss of$98,748 for the six months endedAugust 31, 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
AtAugust 31, 2022 , total liabilities were approximately$3.8 million in comparison to approximately$4.3 million atFebruary 28, 2022 . The decrease in liabilities of approximately$488,000 was primarily due elimination of the line of credit withUBS Bank in conjunction with the completion of the sale of common stock through a private sale. AtAugust 31, 2022 , there were 384,735,402 issued and outstanding shares of common stock in comparison to 67,802,273 shares atFebruary 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 atAugust 31, 2022 to$35,297,706 from$26,115,450 atFebruary 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:
Six Months Six Months
Ended Ended Increase Percentage
August 31, 2022 August 31, 2021 (Decrease) Change
Net cash (used in) provided by
operating activities $ (592,183 ) $ 41,329 (633,512 ) (1,532.9 %)
Net cash (used in) investing
activities $ - $ (13,107 ) 13,107 N/A
Net cash provided by (used in)
financing activities $ 1,140,559 $ (4,611 )
1,145,170 24,835.6 %
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 six months endedAugust 31, 2022 , cash flow used in operating activities was$592,183 in comparison to cash flow provided by operating activities of$41,329 for the six months endedAugust 31, 2021 . The increase in our cash flow used in operating activities of 24 633,512 for the six months endedAugust 31, 2022 was primarily due to increases in our accounts receivable crude oil and natural gas sales and receivables form our working interest partners. Both of these increases were directly related to our acquisition of producing crude oil and natural gas assets inCalifornia 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$644,000 in comparison to the six month endedAugust 31, 2021 . Variations in cash flow from operating activities may impact our level of exploration and development expenditures.
Cash Flow Used In Investing Activities
Cash flow from investing activities is derived from changes in crude oil property balances and any lending activities. Cash flow used in our investing activities for the six months endedAugust 31, 2022 was$-0 - in comparison to cash flow used in our investing activities of$13,107 for the six months endedAugust 31, 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$1,140,559 for the six months endedAugust 31, 2022 in comparison to cash flow used in our financing activities of$4,611 for the six months endedAugust 31, 2021 . During the six months endedAugust 31, 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 six months endedAugust 31, 2022 , we paid off the balance of$808,182 on the line of credit withUBS Bank .
The following discussion is a summary of cash flows provided by, and used in,
the Company's financing activities at
SHORT-TERM AND LONG-TERM BORROWINGS:
Note Payable InDecember 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 endedFebruary 29, 2020 . The note has a maturity date ofJanuary 1, 2022 and bears an interest rate of 10% rate per annum. Monthly interest is accrued and payable onJanuary 1st of each anniversary date until maturity of the note. AtAugust 31, 2022 , the accrued interest had not been paid and was outstanding. The accrued interest on the Note was$44,000 and$38,000 atAugust 31, 2022 andFebruary 28, 2022 , respectively. Note Payable -Related Party OnDecember 22, 2020 , the Company entered into a Secured Promissory Note (the "Note"), as borrower, withJames Forrest Westmoreland andAngela Marie Westmoreland , Co-Trustees of theJames 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 isDecember 21, 2035 . For the six months endedAugust 31, 2022 , the Company made principal payments of$4,384 and amortized debt discount of$364 . The obligations under the Note are secured by a lien on and security interest in the Company's crude oil assets located inKern 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 theCompany: (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. 25
Current portion of note payable - related party balances at
August 31, 2022 February 28, 2022
Note payable - related party, current portion $ 8,947 $ 8,829
Unamortized debt issuance expenses (729 ) (729 )
Note payable - related party, current portion, net $ 8,218 $ 8,100
Note payable - related party long-term balances at
August 31, 2022 February 28, 2022
Note payable - related party, non-current $ 132,207 $136,710
Unamortized debt issuance expenses (8,985 ) (9,350 )
Note payable - related party, non-current, net $ 123,222 $
127,360
Future estimated payments on the outstanding note payable - related party are set forth in the table below:
Twelve month periods ending August 31 2023$ 8,946 2024 9,186 2025 9,433 2026 9,686 2027 9,945 Thereafter 93,957 Total$ 141,153
Short-term Convertible Note Payable
During the twelve months endedFebruary 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. OnMay 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 six months endedAugust 31, 2022 . 12% Subordinated Notes The Company's 12% Subordinated Notes ("the Notes") issued pursuant to aJanuary 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 onJanuary 29th andJuly 29th . OnJanuary 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 toJanuary 29, 2017 . EffectiveJanuary 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 toJanuary 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 six months endedAugust 31, 2022 , one 12% Note holder chose to convert the principal balance and accrued interest in to the Company's common stock. The$25,000 Note and accrued interest of$10,520 were converted at a rate of approximately$0.45 for every dollar of principal and interest resulting in 78,934 shares of common stock being issued. The Company has informed the 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 precedingDecember 31, 2018 . The accrued interest on the 12% Notes atAugust 31, 2022 andFebruary 28, 2022 was$142,251 and$135,229 , respectively. 26 12% Note balances atAugust 31, 2022 andFebruary 28, 2022 are set forth in the table below: August 31, 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 withUBS Bank USA ("UBS"), established pursuant to a Credit Line Agreement datedOctober 24, 2011 that was secured by the personal guarantee of its Chairman, President and Chief Executive Officer. OnMay 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 inCalifornia . 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 inDecember 2018 , the Company conducted a fundraising program to fund the drilling of future wells inCalifornia andMichigan 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 inCalifornia andMichigan 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 program balance of$885,606 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$984,601 and determined a discount of$98,995 as ofAugust 31, 2022 , which is being accounted as interest expense over the estimated period over which payments will be made based on expected future revenue streams. For the six months endedAugust 31, 2022 and 2021, amortization of the debt discount on these payables amounted to$68,482 and$54,304 , respectively, which has been included in interest expense in the statements
of operations. Production revenue payable balances atAugust 31, 2022 andFebruary 28, 2022 are set forth in the table below:August 31, 2022 February 28, 2022
Estimated payments of production revenue payable $ 984,601 $
941,259
Less: unamortized discount (98,994 ) (124,134 )
885,607 817,125
Less: current portion (251,734 ) (78,877 )Net production revenue payable - long-term $ 633,873 $
738,248
Encumbrances
On
27
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 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 six months ended
Related Party Transactions InCalifornia at theEast 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 bothGreat Earth Power andABPlus Net Holdings .Great Earth Power began providing a portion of the solar power electrical service for production operations inJuly 2020 .ABPlus Net Holdings began providing portable tank rentals to the Company as a part of its water treatment and disposal operations inSeptember 2020 . The services provided byGreat Earth Power andABPlus Net Holdings are competitive with other vendors and save the Company significant expense. For the six months endedAugust 31, 2022 and 2021,Great Earth Power was paid$9,716 and$10,675 , respectively. For the six months endedAugust 31, 2022 and 2021, ABPlus Net holdings was paid$5,760 and$5,760 , 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 . This project includes four producing wells. We have a 50% working
interest with a 40% net revenue interest in this project.
In conjunction with our acquisition of Reabold, we were able to secure a capital
raise of
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 inCalifornia . 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
Critical Accounting Policies
Refer to Daybreak's Annual Report on Form 10-K for the fiscal year ended
28
Off-Balance Sheet Arrangements
As ofAugust 31, 2022 , we did not have any off-balance sheet arrangements or relationships with unconsolidated entities or financial partners that have been, or are reasonably likely to have, a material effect on our financial position or results of operations. 29
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