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4-Traders Homepage  >  Equities  >  OTC Bulletin Board - Other OTC  >  Daybreak Oil and Gas Inc    DBRM

DAYBREAK OIL AND GAS INC (DBRM)
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Daybreak Oil and Gas : & GAS, INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-Q)

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01/12/2018 | 10:31pm CEST

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, 2017 and in our Annual Report on Form 10-K for the year ended February 28, 2017. 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 future financing;

·

Our expansion and growth of operations; and

·

Our future investments in and acquisitions of crude oil and natural gas 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;

·

Exposure to market risks in our financial instruments;

·

Fluctuations in worldwide prices and demand for crude oil and natural gas;

·

Our ability to find, acquire and develop crude oil and natural gas properties;

·

Fluctuations in the levels of our crude oil and natural gas exploration and development activities;

·

Risks associated with crude oil and natural gas exploration and development activities;

·

Competition for raw materials and customers in the crude oil and natural gas industry;

·

Technological changes and developments in the crude oil and natural gas industry;

·

Legislative and regulatory uncertainties, including proposed changes to federal tax law and climate change legislation, regulation of hydraulic fracturing and potential environmental liabilities;

·

Our ability to continue as a going concern;

·

Our ability to secure financing under any commitments as well as additional capital to fund operations; and

·

Other factors discussed elsewhere in this Form 10-Q; in our other public filings and press releases; and discussions with Company management.

Our reserve estimates are determined through a subjective process and are subject to revision.

Should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended February 28, 2017 and in this Form 10-Q 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.


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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 price instability, such as we are now experiencing, 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 and natural gas properties and funding projects that we believe have the potential to produce crude oil or natural gas in commercial quantities. We conduct all of our drilling, exploration and production activities in the United States, and all of our revenues are derived from sales to customers within the United States. 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. During the twelve months ended February 28, 2017, we sold all of our working interest in the Twin Bottoms Field in Kentucky.

Our management cannot provide any assurances that Daybreak will ever operate profitably. We have not been able to generate sustained positive earnings on a Company-wide basis. As a small company, we are more susceptible to the numerous business, investment and industry risks that have been described in Item 1A. Risk Factors of our Annual Report on Form 10-K for the fiscal year ended February 28, 2017 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 28, 2017 for more information on the California project or the sale of our working interest in the Twin Bottoms Field in Lawrence County, Kentucky.

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 from the Vedder Sand is considered heavy oil. The crude oil ranges from 14° to 16° API 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, 2017 we had production from 20 vertical crude oil wells. Our average working interest and NRI in these 20 wells is 36.6% and 28.4%, respectively.

There are several other similar prospects on trend with the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic characteristics. Some of these prospects, if successful, would utilize the Company's existing production facilities. In addition to the current field development, there are several other exploratory prospects that have been identified from the seismic data, which we plan to drill in the future.



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California Drilling Plans

Planned drilling activity and implementation of our oilfield development plan will not begin until there is a sustained improvement in crude oil prices and financing is acquired. We do not plan to make any new capital investments within the East Slopes Project area for the remaining 2017 - 2018 fiscal year.

Michigan Acreage Acquisition

In January 2017, Daybreak acquired a 30% working interest in 1,400 acres in the Michigan Basin where we have two shallow crude oil prospects. The leases have been secured and multiple targets have been identified through a 2-D seismic interpretation. A 3-D seismic survey was obtained in January and February of 2017. An analysis of the seismic survey confirmed the prospect identified on the 2-D seismic, as well as identified several additional drilling locations.

We will obtain an additional 3-D survey to better delineate the other locations before a drilling program commences. The first well is expected to be drilled during the first half of 2018, once financing is secured. We do not plan to make any new capital investments within the Michigan acreage area in the 2017 - 2018 fiscal year.


Encumbrances


The Company's debt obligations, pursuant to a credit facility loan agreement and promissory notes entered into by and between Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC, a Delaware limited liability company, as lender, (either party, as appropriate, is referred to in this Quarterly Report on Form 10-Q as "Maximilian"), and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and two mortgages; one covering our leases in California and the other covering our leases in Michigan. On July 13, 2017, in connection with receiving a payment waiver from Maximilian, the California and Michigan properties were cross-collateralized for the credit facility loan and the promissory note. For further information on the credit facility loan agreements and promissory note with Maximilian refer to the discussion under the caption "Current debt (Short-term borrowings)" in the MD&A portion of this Quarterly report on Form 10-Q.

Results of Operations - Nine months ended November 30, 2017 compared to the nine months ended November 30, 2016 (Continuing Operations)

California Crude Oil Prices

The price we receive for crude oil sales in California is based on prices quoted on the New York Mercantile Exchange ("NYMEX") for spot West Texas Intermediate ("WTI") Cushing, Oklahoma delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs. Effective June 1, 2017, we were able to negotiate with our crude oil purchaser the use of a more favorable crude oil pricing schedule. We do not have any natural gas revenues in California.

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. This 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 an improvement in crude oil prices for the nine months ended November 30, 2017 in comparison to the nine months ended November 30, 2016 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 start to rebound 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 at our East Slopes Project in California for the nine months ended November 30, 2017 and 2016 is shown in the table below:

                                      Nine Months Ended
                           November 30, 2017      November 30, 2016    Percentage Change
Average nine month WTI
crude oil price           $             49.64    $             44.87               10.6%
Average nine month
realized crude oil
sales price (Bbl)         $             45.38    $             34.66               30.9%


For the nine months ended November 30, 2017, the average WTI price was $49.64 and our average realized crude oil sale price was $45.38, representing a discount of $4.26 per barrel or 8.6% lower than the average WTI price. In comparison, for the nine months ended November 30, 2016, the average WTI price was $44.87 and our average realized sale price was $34.66 representing a discount of $10.21 per barrel or 22.7% lower than the average WTI price.

Historically, the sale price we receive for California heavy crude oil has been less than the quoted WTI price because of the lower API gravity of our California crude oil in comparison to the API gravity of quoted WTI crude oil.


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California Crude Oil Revenue and Production

Crude oil revenue in California for the nine months ended November 30, 2017 increased $106,254 or 32.0% to $438,295 in comparison to revenue of $332,041 for the nine months ended November 30, 2016. The average sale price of a barrel of crude oil for the nine months ended November 30, 2017 was $45.38 in comparison to $34.66 for the nine months ended November 30, 2016. The increase of $10.72 or 30.9% per barrel in the average realized price of a barrel of crude oil accounted for 96.6% of the increase in crude oil revenue for the nine months ended November 30, 2017.

Our net sales volume for the nine months ended November 30, 2017 was 9,659 barrels of crude oil in comparison to 9,579 barrels sold for the nine months ended November 30, 2016. This increase in crude oil sales volume of 80 barrels or 0.8% was primarily due to more well days of production during the nine months ended November 30, 2017. Approximately 3.4% of the increase in revenue during the nine months ended November 30, 2017 was due to the increase in sales volume over the same period.

The gravity of our produced crude oil in California ranges between 14° API and 16° API. Production for the nine months ended November 30, 2017 was from 20 wells resulting in 5,481 well days of production in comparison to 5,406 well days of production for the nine months ended November 30, 2016.

Our crude oil sales revenue for the nine months ended November 30, 2017 and 2016 are set forth in the following table:


                                     Nine Months Ended        Nine Months Ended
                                     November 30, 2017        November 30, 2016
            Project                 Revenue    Percentage    Revenue    Percentage

California - East Slopes Project$ 438,295 100.0% $ 332,041 100.0%

*Our average realized sale price on a BOE basis for the nine months ended November 30, 2017 was $45.38 in comparison to $34.66 for the nine months ended November 30, 2016, representing an increase of $8.36 or 24.8% per barrel.

Operating Expenses

Total operating expenses for the nine months ended November 30, 2017 were $1,043,776, an increase of $12,277 or 1.2% compared to $1,031,499 for the nine months ended November 30, 2016. The increase was due to the exploration work associated with our new Michigan exploratory joint drilling project in the amount of $88,543. Operating expenses for the nine months ended November 30, 2017 and 2016 are set forth in the table below:

                                Nine Months Ended                     Nine Months Ended
                                November 30, 2017                     November 30, 2016
                                                    BOE                                   BOE
                        Expenses     Percentage    Basis      Expenses     Percentage    Basis
Production expenses    $   130,454        12.5%              $   122,337        11.9%
Exploration and
drilling expenses          103,041         9.9%                    2,342         0.2%
Depreciation,
depletion,
amortization
("DD&A")                    77,526         7.4%                   78,911         7.6%
General and
administrative
("G&A") expenses           732,755        70.2%                  827,909        80.3%
Total operating
expenses               $ 1,043,776       100.0%   $ 108.06$ 1,031,499       100.0%   $ 107.69

Production expenses include expenses associated with the production of crude oil and natural gas. 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, 2017, these expenses increased by $8,117 or 6.6% to $130,454 in comparison to $122,337 for the nine months ended November 30, 2016. The increase of $8,117 was primarily due to higher utility expenses than in the comparative period ended November 30, 2016. For the nine months ended November 30, 2017 and 2016, 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, 2017 and 2016 was $13.51 and $12.77, respectively.

Production expenses represented 12.5% and 11.9% of total operating expenses for the nine months ended November 30, 2017 and 2016, respectively.

Exploration and drilling expenses include geological and geophysical ("G&G") expenses as well as leasehold maintenance, plugging and abandonment ("P&A") expenses and dry hole expenses. These expenses increased $100,699 to $103,041 for the nine months ended November 30, 2017 in comparison to $2,342 the nine months ended November 30, 2016. The two primary reasons for the year-to-year increase was the G&G work on the new Michigan exploratory joint drilling project in the amount of $88,543 and the P&A operations on two non-producing well bores in California for $14,492 representing $103,035 in aggregate. Exploration and drilling expenses represented 9.9% and 0.2% of total operating expenses for the nine months ended November 30, 2017 and 2016, respectively.


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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, 2017, DD&A expenses decreased $1,385 or 1.8% to $77,526 in comparison to $78,911 for the nine months ended November 30, 2016.

DD&A on a BOE basis was $8.03 and $8.24 for the nine months ended November 30, 2017 and 2016, respectively. The decrease in DD&A is directly related to the level of our crude oil production volume in California. DD&A expenses represented 7.4% and 7.6% of total operating expenses for the nine months ended November 30, 2017 and 2016, respectively.

General and Administrative ("G&A") expenses include the salaries of our six full-time employees, including management. Fifty percent (50%) of certain employee's salaries are currently being deferred until the Company's cash flow improves, however the entire salary expense is recognized under G&A on the statements of operations. Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley ("SOX") compliance expenses and other administrative expenses necessary for an operator of oil and natural gas properties as well as for running a public company. For the nine months ended November 30, 2017, G&A expenses decreased $95,154 or 11.5% to $732,755 in comparison to $827,909 for the nine months ended November 30, 2016. We received, as Operator in California, administrative overhead reimbursement of $39,965 during the nine months ended November 30, 2017 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 70.2% and 80.3% of total operating expenses for the nine months ended November 30, 2017 and 2016, respectively.

Interest expense for the nine months ended November 30, 2017 decreased $1,133,152 or 45.3% to $1,366,972 in comparison to $2,500,124 for the nine months ended November 30, 2016. The decrease in interest expense was due to a lower loan balance on our credit facility with Maximilian since the proceeds from the Kentucky project sale were used to pay-down a portion of the loan balance. Refer to the discussion below under the caption Current debt (Short-term borrowings) in this MD&A for more information on the Maximilian loans.

Results of Operations - Three months ended November 30, 2017 compared to the three months ended November 30, 2016 (Continuing Operations)

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, 2017 and 2016 is shown in the table below:


                                     Three Months Ended
                          November 30, 2017      November 30, 2016    Percentage Change
Average three month WTI
crude oil price          $             52.68    $             46.89               12.3%
Average three month
realized crude oil sales
price (Bbl)              $             52.02    $             37.20               39.8%


For the three months ended November 30, 2017, the average WTI price was $52.68 and our average realized crude oil sale price was $52.02, representing a discount of $0.66 per barrel or 1.3% lower than the average WTI price. In comparison, for the three months ended November 30, 2016, the average WTI price was $46.89 and our average realized sale price was $37.20 representing a discount of $9.67 per barrel or 20.6% lower than the average WTI price.

Historically, the sale price we receive for California heavy crude oil has been less than the quoted WTI price because of the lower API gravity of our California crude oil in comparison to the API gravity of quoted WTI crude oil.

California Crude Oil Revenue and Production

Crude oil revenue in California for the three months ended November 30, 2017 increased $66,780 or 65.0% to $169,532 in comparison to revenue of $102,751 for the three months ended November 30, 2016. The average sale price of a barrel of crude oil for the three months ended November 30, 2017 was $52.02 in comparison to $37.20 for the three months ended November 30, 2016. The increase of $14.82 or 39.8% per barrel in the average realized price of a barrel of crude oil accounted for 61.3% of the increase in crude oil revenue for the three months ended November 30, 2017.

Our net sales volume for the three months ended November 30, 2017 was 3,259 barrels of crude oil in comparison to 2,762 barrels sold for the three months ended November 30, 2016. This increase in crude oil sales volume of 497 barrels or 18.0% was primarily due to more well days of production during the three months ended November 30, 2017. Approximately 38.7% of the increase in revenue during the three months ended November 30, 2017 was due to the increase in sales volume over the same period.



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The gravity of our produced crude oil in California ranges between 14° API and 16° API. Production for the three months ended November 30, 2017 was from 20 wells resulting in 1,820 well days of production in comparison to 1,750 well days of production for the three months ended November 30, 2016.

Our crude oil sales revenue for the three months ended November 30, 2017 and 2016 are set forth in the following table:


                                     Three Months Ended       Three Months Ended
                                     November 30, 2017        November 30, 2016
            Project                 Revenue    Percentage    Revenue    Percentage

California - East Slopes Project$ 169,532 100.0% $ 102,751 100.0%

*Our average realized sale price on a BOE basis for the three months ended November 31, 2017 was $52.02 in comparison to $37.20 for the three months ended November 30, 2016, representing an increase of $14.82 or 39.8% per barrel.

Operating Expenses

Total operating expenses for the three months ended November 30, 2017 were $294,173, a decrease of $86,046 or 22.6% compared to $380,219 for the three months ended November 30, 2016. Operating expenses for the three months ended November 30, 2017 and 2016 are set forth in the table below:

                                   Three Months Ended                 Three Months Ended
                                   November 30, 2017                   November 30, 2016
                                                       BOE                                BOE
                            Expenses    Percentage    Basis    Expenses    Percentage    Basis
Production expenses         $  38,229        13.0%             $  42,277        11.1%
Exploration and drilling
expenses                        8,048         2.7%                 1,759         0.5%
Depreciation, depletion,
amortization ("DD&A")          26,190         8.9%                23,017         6.0%
General and
administrative ("G&A")
expenses                      221,706        75.4%               313,166        82.4%
Total operating expenses    $ 294,173       100.0%   $ 90.27$ 380,219       100.0%   $ 137.66

For the three months ended November 30, 2017, production expenses decreased by $4,048 or 9.6% to $38,229 in comparison to $42,277 for the three months ended November 30, 2016. For the three months ended November 30, 2017 and 2016 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, 2017 and 2016 were $11.73 and $15.31, respectively. Production expenses represented 13.0% and 11.1% of total operating expenses for the three months ended November 30, 2017 and 2016, respectively.

For the three months ended November 30, 2017, exploration and drilling expenses increased $6,289 to $8,048 in comparison to $1,759 for the three months ended November 30, 2016. All of the G&G expense for the three months ended November 30, 2017 was directly related to the new Michigan exploratory joint drilling project. Exploration and drilling expenses represented 2.7% and 0.5% of total operating expenses for the three months ended November 30, 2017 and 2016, respectively.

For the three months ended November 30, 2017, DD&A expenses increased $3,173 or 13.8% to $26,190 in comparison to $23,017 for the three months ended November 30, 2016. DD&A on a BOE basis was $8.04 and $8.33 for the three months ended November 30, 2017 and 2016, respectively. The increase in DD&A is directly related to the level of our crude oil production volume in California. DD&A expenses represented 8.9% and 6.0% of total operating expenses for the three months ended November 30, 2017 and 2016, respectively.

For the three months ended November 30, 2017, G&A expenses decreased $91,460 or 29.2% to $221,706 in comparison to $313,166 for the three months ended November 30, 2016. Fifty percent (50%) of certain employee's salaries are currently being deferred until the Company's cash flow improves, however the entire salary expense is recognized under G&A on the statements of operations. We received, as Operator in California, administrative overhead reimbursement of $13,322 during the three months ended November 30, 2017 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 75.4% and 82.4% of total operating expenses for the three months ended November 30, 2017 and 2016, respectively.



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Interest expense for the three months ended November 30, 2017 decreased $320,816 or 43.8% to $411,427 in comparison to $732,243 for the three months ended November 30, 2016. The decrease in interest expense was due to a lower loan balance on our credit facility with Maximilian since the proceeds from the Kentucky project sale were used to pay-down a portion of the loan balance. The credit facility activity is discussed further in the discussion of the Maximilian Loan Agreement (Credit Facility) under the Current Debt (Short-Term Borrowings) section of this MD&A.

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.

Since June 2014, there has been a significant decline in the WTI price of crude oil and consequently in the realized price we receive from crude oil sales in California. This instability in the price of crude oil has had a substantial negative impact on our cash flow, financial statements and our ability to implement an aggressive drilling program in both California and Michigan.

In the current fiscal year we are not planning any additional capital investments in California and Michigan. 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, 2017 in comparison to February 28, 2017 are set forth in the table below:


                                                                   Increase     Percentage
                      November 30, 2017     February 28, 2017     (Decrease)      Change
Cash                 $           12,487    $           42,003    $   (29,516)   (70.3%)
Current Assets       $          319,782    $          309,308    $    10,474    3.4%
Total Assets         $        1,109,236$        1,263,313$  (154,077)   (12.2%)
Current Liabilities  $      (15,303,879)$      (13,462,236)$ 1,841,643    13.7%
Total Liabilities    $      (15,911,116)$      (14,092,781)$ 1,818,335    12.9%
Working Capital
Deficit              $      (14,984,097)$      (13,152,928)$ 1,831,169    13.9%


Our working capital deficit increased approximately $1.8 million or 13.7% to $14,984,097 at November 30, 2017 in comparison to $13,152,928 at February 28, 2017. The increase in our working capital deficit was primarily due to our loss on continuing operations of $1,972,412.

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.



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Major sources of funds in the past for us have included the debt or equity markets and the sale of assets. We will have to rely on the capital markets to fund future operations and growth. Our business model is focused on acquiring exploration or development properties as well as existing production. Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of crude oil and natural gas producing properties, which 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 in crude oil prices since June of 2014 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, 2017 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 and natural gas exploration industry in 2005, and as of the nine months ended November 30, 2017, we have an accumulated deficit of $37,851,881 and a working capital deficit of $14,984,097 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.

Changes in Financial Condition

During the nine months ended November 30, 2017, we received crude oil sales revenue from 20 wells in California. Our commitment to improving corporate profitability remains unchanged. During the nine months ended November 30, 2017, we had an operating loss of $605,481. We experienced an increase in revenues of $106,254 or 32.0% to $438,295 for the nine months ended November 30, 2017 in comparison to revenues of $332,041 for the nine months ended November 30, 2016. Of the $10.72 per barrel increase in the realized sale price we received on a BOE basis from $34.66 to $45.38 approximately $10.34 or 96.6% was due to an improvement in the realized sales price of oil.

Our balance sheet at November 30, 2017 reflects total assets of approximately $1.1 million in comparison to approximately $1.3 million at February 28, 2017.

This decrease of approximately $0.2 million is due to DD&A expense, a decline in our cash available balances and exploratory work done in Michigan.

At November 30, 2017, total liabilities were approximately $15.9 million in comparison to approximately $14.1 million at February 28, 2017. The increase in liabilities of approximately $1.8 million was due to increases in payables and our credit facility balance with Maximilian.

The change in our common stock issued and outstanding balance of 51,532,364 shares at November 30, 2017 in comparison to the 51,487,373 shares at February 28, 2017 was due to the conversion of 14,997 shares of Series A Preferred to 44,991 shares of our common stock.

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           Nine Months
                             Ended                 Ended           Increase     Percentage
                       November 30, 2017     November 30, 2016    (Decrease)      Change
Net cash provided by
(used in) operating
activities            $         (152,216)   $           45,123      (197,339)     (437.3%)
Net cash provided by
investing activities  $                -    $          (11,958)       11,958       100.0%
Net cash provided by
(used in) financing
activities            $          122,700    $          (19,666)      142,366       723.9%





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Cash Flow Provided by (Used In) Operating Activities

Cash flow from operating activities is derived from the production of our crude oil and natural gas 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, 2017, cash flow used in operating activities was $152,216 in comparison to cash flow provided by operating activities of $45,123 for the nine months ended November 30, 2016. This decrease in operating cash flow of $197,339 or 437.3% is directly related to an increase in our receivables balances; an increase in our payables balances; and, an increase in accrued interest offset by our net loss for the nine months ended November 30, 2017. Changes in non-cash account balances primarily relating to DD&A; amortization of debt discount; deferred financing costs; a reclass of O&G properties, interest on the line of credit and debt modification fees amounted to $402,648 in aggregate for the nine months ended November 30, 2017.

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 and natural gas property balances and any lending activities. Cash flow provided by investing activities for the nine months ended November 30, 2017 was -$0- a change of $11,958 from the cash flow provided by investing activities for the nine months ended November 30, 2016. This change was due to a lack of drilling activity due to delays in funding for drilling activities.

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 $122,700 for the nine months ended November 30, 2017 in comparison to cash flow used in our financing activities of $19,666 for the nine months ended November 30, 2016.

This increase of $142,366 in cash flow was due to advances of $102,700 in aggregate we received from our Maximilian Credit Facility and advances of $65,000 from the UBS Line of Credit offset by payments of $45,000 to the same UBS Line of Credit. The Maximilian Credit Facility is discussed further under the caption "Current Debt (Short-Term Borrowings) - Maximilian Loan Agreement (Credit Facility)" in this MD&A.

The following discussion is a summary of cash flows provided by, and used in, the Company's financing activities at November 30, 2017.

Current debt (Short-term borrowings)

Related Party

At November 30, 2017 and February 28, 2017, the Company had a loan balance of $250,100 with the Company's Chairman, President and Chief Executive Officer.

These advances which were obtained during the years ended February 29, 2012 and February 28, 2013, and were used for a variety of corporate purposes including an escrow requirement on a loan commitment; maturity extension fees on third party loans; and a reduction of principal on the Company's credit line with UBS Bank. These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.

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 our President and Chief Executive Officer. At November 30, 2017 and February 28, 2017, the Line of Credit had an outstanding balance of $861,715 and $817,622, respectively. On July 10, 2017, a portion of the outstanding credit line balance, $700,000, was converted to a 24 month fixed term annual interest rate of 3.244% with interest payable monthly. The remaining balance of the credit line has a stated reference rate of 0.249% + 337.5 basis points with interest payable monthly.

Interest was $24,093 and $25,335 for the nine months ended November 30, 2017 and 2016, respectively. 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, 2017, the Company received advances of $65,000 in aggregate through the line of credit.



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Maximilian Loan Agreement (Credit Facility)

On October 31, 2012, the Company entered into a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in this Quarterly Report on Form 10-Q as "Maximilian"), which provided for a revolving credit facility of up to $20 million, that matured on October 31, 2016, with a minimum commitment of $2.5 million. On October 31, 2016 through the Fourth Amendment to the Amended and Restated Loan and Security Agreement, the maturity date of the loan was changed to February 28, 2020.

In connection with the Company's acquisition of a working interest from App Energy, LLC, a Kentucky limited liability company ("App Energy") in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013. The amendment increased the amount of the credit facility to $90 million and reduced the annual interest rate to 12%. The Company evaluated the amendment of the revolving credit facility under ASC 470-50-40 and determined that the Company's borrowing capacity under the amended loan agreement exceeded its borrowing capacity under the old loan agreement. Due to the Company's default on the Maximilian loan, all unamortized discount and deferred financing costs were fully amortized during the nine months ended November 30, 2017.

On October 31, 2016, the Company entered into a Fourth Amendment to the Amended and Restated Loan and Security Agreement with Maximilian, which amended the Company's loan agreement with Maximilian (the "Restructuring Agreement").

Pursuant to the Restructuring Agreement, in exchange for the proceeds it received from the Kentucky Sale, Maximilian and the Company have agreed to a commitment by Maximilian to advance up to $250,000 in financing to the Company over the next six months and the pursuit of the Michigan exploratory joint drilling project using the $250,000 set aside from the Kentucky Sale. The Company recognized a gain on debt settlement in aggregate of approximately $3.9 million through the sale of the Kentucky property and reduction in the outstanding credit facility balance.

During the nine months ended November 30, 2016, approximately $1.5 million of interest was converted to principal. Additionally, as a consequence of the Company selling its' Kentucky project and the settlement of the account receivable owed by App Energy to the Company $745,163 of interest was added to the note receivable principal; $341,049 in deferred financing costs were reclassified; $600,000 of the sale proceeds were paid directly to Maximilian; and, a $3.9 million in reduction in debt owed to Maximilian occurred.

As a result of the decline in hydrocarbon prices that started in June of 2014, the Company has been unable to make any type of interest or principal payments required under the amended terms of its credit facility with Maximilian since December of 2015. Under the terms of the Restructuring Amendment all unpaid interest is currently being accrued. Accrued interest on the credit facility loan at November 30, 2017 and February 28, 2017 was $1,472,260 and $440,389, respectively. The Company is currently considered to be in default on its credit facility. Maximilian is continuing to work with the Company in restructuring the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue.

Furthermore, our lender is under no obligation to advance us any additional funding. A change of control or management of our lender, among other reasons, could also result in our loan being called due and payable.

During the nine months ended November 30, 2017, we received $102,700 in advances under the terms of the credit facility.

Maximilian Promissory Note - Michigan Exploratory Joint Drilling Project

As of November 30, 2017, the Company had received $94,650 in aggregate from multiple advances starting in the year ended February 28, 2017 from Maximilian under a separate promissory note agreement dated January 17, 2017 and amended on February 10, 2017 regarding the development of an exploratory joint drilling project in Michigan. In the event of a default of any of the Company's obligations under the promissory note, the amounts due may be called immediately due and payable at Maximilian's option. Advances under this agreement are subject to a 5% (five percent) per annum interest rate and may be prepaid at any time without penalty. Pursuant to the agreement, if a well that the Company elects to participate in is scheduled to be spudded at the Michigan exploratory joint drilling project on or before December 31, 2017, then the advances under the promissory note must be repaid in full upon the earlier of (a) the time that is ten days prior to the first well being spudded on the Michigan exploratory joint drilling project or (b) December 31, 2017. The agreement also provided that, if there was not a well scheduled to be spudded at the Michigan exploratory joint drilling project on or before December 31, 2017 that the Company elected to participate in, then the Company would assign to Maximilian its working interest in the Michigan exploratory joint drilling project, in full payment and satisfaction of the advances under the promissory note. Due to a lack of funding from Maximilian, we were unable to spud a well on the Michigan project by December 31, 2017. However, Maximilian has not issued any demands or notice of default with respect to the promissory note or our working interest in Michigan, and we continue to work with Maximilian to try to achieve a mutually agreeable restructuring of our debt with them. Accrued interest on the Michigan promissory note at November 30, 2017 and February 28, 2017 was $3,975 and $456, respectively. During the nine months ended November 30, 2017, an aggregate amount of $10,650 was paid directly to the Operator of the Michigan project by Maximilian on the Company's behalf.



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In accordance with the guidance found in ASC-470-10-45, the entire balance of the Maximilian loan is presented under the current liabilities section of the balance sheets. In accordance with the guidance found in ASC 835-30 the net amount of the deferred finance costs associated with the credit facility are included with the debt discount as a reduction of the loan balance shown on the Balance Sheet as of February 28, 2017. Due to the Company's default on the Maximilian loan, all unamortized discount and deferred financing costs were fully amortized during the nine months ended November 30, 2017.


Current debt balances at November 30, 2017 and February 28, 2017 are set forth
in the table below:


                                                                        February 28,
                                                   November 30, 2017        2017
Credit facility balance                           $        9,063,144$  8,960,444
Less unamortized discount and debt issuance costs                  -        (238,598)
Subtotal - O&G operating debt                              9,063,144       8,721,846
Michigan exploratory joint drilling project debt              94,650          84,000
Net debt                                          $        9,157,794$  8,805,846

Deferred financing costs at November 30, 2017 and February 28, 2017 relating to the original and the amended credit facility with Maximilian, are set forth in the table below:


                                             November 30, 2017February 28, 2017

Deferred financing costs - loan fees $ 181,648 $ 181,648 Deferred financing costs - loan commissions

            630,662               630,662
Deferred financing costs - fair value of
warrants                                               530,488               530,488
Deferred financing costs - fair value of
common stock                                           419,832               419,832
                                                     1,762,630             1,762,630
Accumulated amortization                            (1,762,630)           (1,524,032)
                                            $                -    $          238,598


Deferred financing costs of $-0- and $238,598 at November 30, 2017 and February 28, 2017, respectively includes the fair value of common shares and warrants issued to Maximilian and to a third party that assisted in both the original and the amended financing transactions. The unamortized deferred financing costs are netted against debt in the balance sheets. Amortization expense of deferred financing costs was $238,598 and $300,026 for the nine months ended November 30, 2017 and 2016, respectively. Accrued interest on both of the Maximilian loans at November 30, 2017 and February 28, 2017 was $1,476,236 and $440,845, respectively.


Encumbrances


The Company's debt obligations, pursuant to the above mentioned credit facility loan agreement and promissory notes entered into by and between Maximilian and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and two mortgages; one covering its leases in California and the other covering its leases in Michigan. On July 13, 2017, in connection with receiving the latest payment waiver from Maximilian, the California and Michigan properties were cross-collateralized for the credit facility loan and the promissory note.

Non-current debt (Long-term borrowings)

12% Subordinated Notes

The Company's 12% Subordinated Notes ("the Notes") issued pursuant to a January 2010 private placement offering to accredited investors, resulted in $595,000 in gross proceeds (of which $250,000 was from a related party) to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th. On January 29, 2015, the Company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes for an additional two years to January 29, 2017. Effective January 29, 2017, the maturity date of the Notes and the expiration date of the warrants that were issued in conjunction with the Notes were extended for an additional two years to January 29, 2019. There are ten noteholders, holding 980,000 warrants, who have not yet exercised their warrants. The exercise price of the associated warrants was lowered from $0.14 to $0.07 as a part of the Note maturity extension. The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes. The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes. The Black-Scholes valuation encompassed the following weighted average assumptions: a risk free interest rate of 1.22%; volatility of 378.73%; and dividend yield of 0.0%.

Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company's common stock at a conversion rate equal to 75% of the average closing price of the Company's common stock over the 20


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consecutive trading days preceding December 31, 2018. Amortization expense was $10,904 and $-0- at November 30, 2017 and 2016, respectively. The unamortized debt discount at November 30, 2017 and February 28, 2017 was $16,960 and $27,864, respectively.


12% Note balances at November 30, 2017 and February 28, 2017 are set forth in
the table below:


                                   November 30, 2017     February 28, 2017
12% Subordinated Notes            $          315,000    $          315,000
Debt discount                                 (9,456)              (15,535)

Net 12% Subordinated Note balance $ 305,544 $ 299,465

12% Note balances - related parties at November 30, 2017 and February 28, 2017 are set forth in the table below:


                                                                        February 28,
                                                   November 30, 2017        2017
12% Subordinated Notes - related party            $          250,000    $    250,000
Debt discount                                                 (7,504)        (12,329)

Net 12% Subordinated Note - related party balance $ 242,496 $ 237,671


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.

Restricted Stock and Restricted Stock Unit Plan

On April 6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the "2009 Plan") allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted common stock and restricted common stock unit awards.

Subject to adjustment, the total number of shares of Daybreak common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan. We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance. Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.

At November 30, 2017, a total of 3,000,000 shares of restricted stock had been awarded under the 2009 Plan, with 2,986,220 shares outstanding and fully vested.

A total of 1,013,780 common stock shares remained available at November 30, 2017 for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is set forth in the table below:

                                                                         Shares
          Grant      Shares     Vesting      Shares        Shares      Outstanding
          Date       Awarded    Period     Vested(1)     Returned(2)   (Unvested)
         4/7/2009   1,900,000   3 Years      1,900,000             -             -
        7/16/2009      25,000   3 Years         25,000             -             -
        7/16/2009     625,000   4 Years        619,130         5,870             -
        7/22/2010      25,000   3 Years         25,000             -             -
        7/22/2010     425,000   4 Years        417,090         7,910             -
                    3,000,000             2,986,220(1)    13,780(2)              -



(1)

Does not include shares that were withheld to satisfy such tax liability upon vesting of a restricted award by a Plan Participant, and subsequently returned to the 2009 Plan.

(2)

Reflects the number of common shares that were withheld pursuant to the settlement of the number of shares with a fair market value equal to such tax withholding liability, to satisfy such tax liability upon vesting of a restricted award by a Plan Participant.

For the nine months ended November 30, 2017 and 2016, the Company did not recognize any stock compensation expense related to the above restricted stock grants since all issuances have been fully amortized.



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Management Plans to Continue as a Going Concern

The Company continues to implement plans to enhance its ability to continue as a going concern. Daybreak currently has a net revenue interest ("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 revenue. The Company's average working interest ("WI") in these wells is 36.6% and the NRI is 28.4% for these same wells.

The Company anticipates its revenue will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project in California and as our exploratory drilling project begins in Michigan. However, given the current 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 the Company's credit facility.

The Company believes that our liquidity will improve when there is a sustained improvement in hydrocarbon prices. Daybreak's sources of funds in the past have included the debt or equity markets and the sale of assets. While the Company has experienced revenue growth, which has resulted in positive cash flow from its crude oil and natural gas properties, it has not yet established a positive cash flow on a company-wide basis. It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future. However, the Company cannot offer any assurance that it will be successful in executing the aforementioned plans to continue as a going concern.

Daybreak's financial statements as of November 30, 2017 do not include any adjustments that might result from the inability to implement or execute the Company's plans to improve its ability to continue as a going concern.

Critical Accounting Policies

Refer to Daybreak's Annual Report on Form 10-K for the fiscal year ended February 28, 2017.

Off-Balance Sheet Arrangements

As of November 30, 2017, 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.



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© Edgar Online, source Glimpses

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