Attached files

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EX-99 - EXHIBIT 99.1 - DAYBREAK OIL & GAS, INC.exhibit991.htm
EX-32 - EXHIBIT 32.1 - DAYBREAK OIL & GAS, INC.exhibit321.htm
EX-31 - EXHIBIT 31.1 - DAYBREAK OIL & GAS, INC.exhibit311.htm
EX-23 - EXHIBIT 23.2 - DAYBREAK OIL & GAS, INC.exhibit232.htm
EX-23 - EXHIBIT 23.1 - DAYBREAK OIL & GAS, INC.exhibit231.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


(Mark One)


x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


For the fiscal year ended February 28, 2018


o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



For the transition period from ______ to _______


Commission file number 000-50107


DAYBREAK OIL AND GAS, INC.

(Exact name of registrant as specified in its charter)


Washington

 

91-0626366

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

 

 

1101 N. Argonne Road, Suite A 211, Spokane Valley, WA

 

99212

(Address of principal executive offices)

 

(Zip code)


Registrant’s telephone number, including area code:  (509) 232-7674


Securities registered pursuant to Section 12(b) of the Exchange Act:  None


Securities registered pursuant to Section 12(g) of the Exchange Act:  Common Stock, $.001 par value


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ¨  No þ


Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes ¨  No þ


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ  No ¨


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ  No ¨


Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company þ

 

 

 

Emerging growth company ¨


If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes ¨  No þ


The aggregate market value of the voting and non-voting stock held by non-affiliates of the registrant, based on the closing price of $0.01 on August 31, 2017, as reported by the Over-the-Counter Market was $493,024.


At May 24, 2018, the registrant had 51,532,364 outstanding shares of $0.001 par value common stock.


DOCUMENTS INCORPORATED BY REFERENCE:


None.





TABLE OF CONTENTS



 

 

PAGE

 

 

 

PART I

 

4

 

 

 

ITEM 1.

BUSINESS

4

ITEM 1A.

RISK FACTORS

10

ITEM 1B.

UNRESOLVED STAFF COMMENTS

20

ITEM 2.

PROPERTIES

21

ITEM 3.

LEGAL PROCEEDINGS

29

ITEM 4.

MINE SAFETY DISCLOSURES

29

 

 

 

PART II

 

30

 

 

 

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

30

ITEM 6.

SELECTED FINANCIAL DATA

37

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

38

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

51

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

52

 

Balance Sheets as of February 28, 2018 and February 28, 2017

53

 

Statements of Operations for the Years Ended February 28, 2018 and February 28, 2017

54

 

Statements of Changes in Stockholders’ Deficit for the Years Ended February 28, 2018 and February 28, 2017

55

 

Statements of Cash Flows for the Years Ended February 28, 2018 and February 28, 2017

56

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

75

ITEM 9A.

CONTROLS AND PROCEDURES

76

ITEM 9B.

OTHER INFORMATION

77

 

 

 

PART III

 

78

 

 

 

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

78

ITEM 11.

EXECUTIVE COMPENSATION

83

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

88

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

90

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

92

 

 

 

PART IV

 

93

 

 

 

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

93

ITEM 16.

FORM 10-K SUMMARY

96

 

 

 

SIGNATURES

97

GLOSSARY OF TERMS

98





2




CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS


This annual report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  Forward-looking statements include statements relating to future events or our future financial or operating performance, including statements regarding guidance, industry prospects or future results of operations or financial position, made in this Annual Report on Form 10-K.  These forward-looking statements are based on our current expectations, assumptions, estimates and projections for the future of our business and our industry and 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 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 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;

·

Changes to our reserve estimates or the recovery of crude oil and natural gas quantities that is less than our reserve estimates;

·

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-K; in our other public filings and press releases; and discussions with Company management.


Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  These risks and uncertainties, as well as other risks and uncertainties that could cause our actual results to differ significantly from management’s expectations, are described in greater detail in Item 1A of Part 1, “Risk Factors”.  We specifically undertake no obligation to publicly update or revise any information contained in a 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.



3




PART I


ITEM 1.   BUSINESS


Historical Background


Daybreak Oil and Gas, Inc. (referred to herein as “we,” “our,” “us,” “Daybreak” or the “Company”) was originally incorporated in the State of Washington on March 11, 1955 as Daybreak Uranium, Inc.  The Company was organized to explore for, acquire and develop mineral properties throughout the Western United States.  In August 1955, we acquired the assets of Morning Sun Uranium, Inc.  By the late 1950’s, we ceased to be a producing mining company and thereafter engaged in mineral exploration only.  In May 1964, to reflect the diversity of our mineral holdings, we changed our name to Daybreak Mines, Inc.  By February 1967, we had ceased all exploration operations.  After that time, our activities were confined to annual assessment and maintenance work on our Idaho mineral properties and other general and administrative functions.  In November 2004, we sold our last remaining mineral rights covering approximately 340 acres in Shoshone County, Idaho.


Effective March 1, 2005, we undertook a new business direction for the Company; that of an exploration, development and production company in the crude oil and natural gas industry.  In October of 2005, to better reflect this new direction of the Company, our shareholders approved changing our name to Daybreak Oil and Gas, Inc.  Our Common Stock is quoted on the OTC Pink marketplace under the symbol DBRM.


Our corporate office is located at 1101 N. Argonne Road, Suite A 211, Spokane Valley, Washington 99212-2699.  Our telephone number is (509) 232-7674.  Additionally, we have a regional operations office located at 1414 S. Friendswood Dr., Suite 212, Friendswood, Texas 77546.  The telephone number of our office in Friendswood is (281) 996-4176.


Crude Oil and Natural Gas Overview


We are an independent crude oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing crude oil and natural gas reserves through exploration and development activities and selling the production from those reserves at a profit.  To be successful, we must, over time, be able to find crude oil and natural gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.  A secondary means of generating returns can include the sale of either producing or non-producing lease properties.


Our long-term success depends on, among many other factors, the acquisition and drilling of commercial grade crude oil and natural gas properties and on the prevailing sales price 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 have experienced since June of 2014, will and does have a material adverse effect on our results of operations and financial condition.


The Company’s focus is to pursue crude oil and natural gas drilling opportunities through joint ventures with industry partners as a means of limiting our drilling risk.  Prospects are generally brought to us by other crude oil and natural gas companies or individuals.  We identify and evaluate prospective crude oil and natural gas properties to determine both the degree of risk and the commercial potential of the project.  We seek projects that offer a mix of low risk with a potential of steady reliable revenue as well as projects with a higher risk, but that may also have a larger return.  Modern technology including 3-D seismic helps us identify potential crude oil and natural gas reservoirs and to mitigate our risk.  Currently, our core areas of activity are located in Kern County, California and Michigan, although new opportunities may ultimately be secured in other areas.  We seek to maximize the value of our asset base by exploring and developing properties that have both production and reserve growth potential.


In some instances, such as with our California crude oil operations, we strive to be the operator of our crude oil and natural gas properties.  As the operator, we are more directly in control of the timing; costs of drilling and completion; and production operations on our projects.  In other instances, we may not serve as operator where we have concluded that the existing operator has existing operational knowledge, equipment and personnel in place, and operates competently and prudently and with the same operational goals that we would have if we served as operator.  However, we have our own personnel onsite during critical operations such as drilling, fracturing and completion operations.




4



On October 31, 2016, we completed the sale of our working interest in the Twin Bottoms Field located in Lawrence County, Kentucky.  As a result of this sale and the restructuring of our Balance Sheet, we recognized approximately $75,854 as a loss in discontinued operations; an approximate $1.96 million loss on the sale of crude oil and natural gas properties; a reduction of $4.5 million in debt associated with Kentucky; a loss on note receivable settlement of approximately $1.5 million; and, an additional debt settlement of approximately $3.9 million with our lender Maximilian Resources LLC., for the twelve months ended February 28, 2017.


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 wells will be drilled vertically with conventional completions and no hydraulic fracturing will be required.  The first well is expected to be drilled during the late summer of 2018.


Known Trends and Uncertainties


As we continue to pursue our exploratory and development drilling programs in our California and Michigan properties the timing of these activities continues to be determined by current crude oil and natural gas prices; the availability of funds through our lending facility; and in California, the drilling permit approval process.  Additionally, our drilling programs are also very sensitive to drilling costs.  We attempt to control these costs through drilling efficiencies by working with service providers to receive acceptable unit costs.


In order to continue our drilling program in California and undertake a new drilling program in Michigan, we must be able to realize an acceptable margin between our expected cash flows from new production and the cost to drill and complete new wells.  If any combination of a decrease in crude oil and natural gas prices; the availability of drilling funds; and/or, the rising costs of drilling, completion and other field services occurs in future periods, we may be forced to modify or discontinue a planned drilling program.


All of the Company’s crude oil production in California is sold under contracts which are market-sensitive.  Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of hydrocarbon prices and demand for crude oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  Some of these factors include the level of global demand for and price of petroleum products, foreign supply of crude oil and natural gas, the establishment of and compliance with production quotas by oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.  Because of the size of our Company, we are highly susceptible to downward changes in the price we receive for our hydrocarbon sales especially crude oil.


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”) crude oil 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 hydrocarbon prices and dramatic decline in our realized sale price of crude oil since June of 2014 when the monthly average price of WTI 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 twelve months ended February 28, 2018 in comparison to the twelve months ended February 28, 2017 there is no guarantee this trend will continue.  It is beyond our ability to accurately predict how long crude oil prices will continue to improve; when or at what level they may begin to stabilize; or when they may start to decline again 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 Slope Project in California for the twelve months ended February 28, 2018 and February 28, 2017 is shown in the table below:


 

 

Twelve Months Ended

 

 

 

 

February 28, 2018

 

February 28, 2017

 

Percentage Change

Average twelve month WTI crude oil price

 

$

52.55

 

$

46.81

 

12.3%

Average twelve month realized crude oil sales price (Bbl)

 

$

49.34

 

$

37.03

 

33.2%




5



For the twelve months ended February 28, 2018, the average WTI price was $52.55 and our average realized crude oil sale price was $49.34, representing a discount of $3.21 per barrel or 6.1% lower than the average WTI price.  In comparison, for the twelve months ended February 28, 2017, the average WTI price was $46.81 and our average realized sale price was $37.03 representing a discount of $9.78 per barrel or 20.9% lower than the average WTI price.  Effective June 1, 2017, we were able to negotiate with our crude oil purchaser the use of a more favorable crude oil pricing schedule.  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 WTI crude oil API gravity.


For the twelve months ended February 28, 2018 California crude oil revenues increased $145,996 to $628,652 in comparison to revenues of $482,656 for the twelve months ended February 28, 2017.  All of the $145,996 or 30.2% increase in revenue can be directly attributed to the increase in realized crude oil prices.  It is beyond our control and ability to accurately predict how long hydrocarbon prices will continue to improve; when or at what level they may begin to stabilize; or when they may start to decline again as there are many factors beyond our control that dictate the price we receive on our hydrocarbon sales.


The instability in hydrocarbon prices that we are currently experiencing has had a material adverse effect on our cash flows, reserves valuation and availability of funds in the financial markets.  As a result, we are currently unable to make the interest or principal payments required under the terms of our credit facility with our lender, 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 annual report on Form 10-K as “Maximilian”).  The Company is currently considered to be in default under the terms of its credit facility loan.  Maximilian is currently in receivership.  The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender to assume the Maximilian credit facility.  No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company.  During the twelve months ended February 28, 2018, the Company received an aggregate of $102,700 in advances under the terms of the credit facility.


Competition


We compete with other independent crude oil and natural gas companies for exploration prospects, property acquisitions and for the equipment and labor required to operate and develop these properties.  Many of our competitors have substantially greater financial and other resources than we have.  These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can.


We conduct all of our drilling, exploration and production activities onshore in the United States.  All of our crude oil assets are located in the United States and all of our revenues are from sales to customers within the United States.


Significant Customers


At our East Slopes Project, located in Kern County, California, we sell all of our crude oil production to one buyer.  At February 28, 2018 and 2017, this one individual customer represented 100% of crude oil sales receivable.  If this local purchaser is unable to resell their products or if they lose a significant sales contract then we may incur difficulties in selling our crude oil production.


The Company’s accounts receivable from continuing operations in California for crude oil sales at February 28, 2018 and 2017 are set forth in the table below.


 

 

 

 

February 28, 2018

 

February 28, 2017

Project

 

Customer

 

Accounts

Receivable

Crude Oil

Sales

 

Percentage

 

Accounts

Receivable

Crude Oil

Sales

 

Percentage

California – East Slopes Project (Crude oil)

 

Plains Marketing

 

$

104,840

 

100.0%

 

$

83,405

 

100.0%





6



Title to Properties


As is customary in the crude oil and natural gas industry, we make only a cursory review of title to undeveloped crude oil and natural gas leases at the time we acquire them.  However, before drilling operations commence, we search the title, and remedy material defects, if any, before we actually begin drilling the well.  To the extent title opinions or other investigations reflect title defects, we (rather than the seller or lessor of the undeveloped property) typically are obligated to cure any such title defects at our expense.  If we are unable to remedy or cure any title defects, so that it would not be prudent for us to commence drilling operations on the property, we could suffer a loss of our entire investment in the property.  Except for encumbrances we have granted as described below under “Encumbrances,” we believe that we have good title to our crude oil and natural gas properties, some of which are subject to immaterial easements, and restrictions.


Encumbrances


The Company’s debt obligations, pursuant to the credit facility loan agreement and promissory notes with 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 annual report on Form 10-K 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 agreement refer to the discussion under the caption “Current debt (short-term borrowings)” found in the MD&A section of this annual report on Form 10-K.


Regulation


The exploration and development of crude oil and natural gas properties are subject to various types of federal, state and local laws and regulations.  These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, hydraulic fracturing operations, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and specific requirements for the operation of wells.  Failure to comply with such laws and regulations can result in substantial penalties.


Laws and regulations relating to our business frequently change so we are unable to predict the future cost or impact of complying with such laws.  Future laws and regulations, including changes to existing laws and regulations, could adversely affect our business.  These regulatory burdens generally do not affect us any differently than they affect other companies in our industry with similar types, quantities and locations of production.


All of the states in which we operate generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of crude oil and natural gas.  Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum rates of production from crude oil and natural gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring of natural gas and requirements regarding the ratability of production.


These laws and regulations may limit the amount of crude oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill.  Moreover, many states impose a production or severance tax with respect to the production and sale of crude oil and natural gas within their jurisdiction.  States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.


In California, where we currently operate a 20 well oilfield project, there is substantial federal and state regulation and oversight of produced water and its disposal.  Water regulations on California are currently under review and are subject to change.  We produce a substantial amount of water while lifting oil from our reservoirs.  While the water we produce is considered to be “fresh water” under current testing standards, its handling and use are currently under review by regional authorities.  As rules change we may be required to invest in additional water management infrastructure.  There is no guarantee that we will not have to incur additional costs in the future in regards to the disposal and use of our produced water.


In the event we conduct operations on federal, state or American Indian crude oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements and on-site security regulations, and other appropriate permits issued by the Bureau of Land Management or other relevant federal or state agencies.



7




The sales price of crude oil and natural gas are not presently regulated but rather are set by the market.  We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on the operations of the underlying properties.


Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  Hydraulic fracturing typically is regulated by state crude oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuel.  At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities.  If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.  We do not use hydraulic fracturing methods in our crude oil production in California.


Operational Hazards and Insurance


Our operations are subject to the usual hazards incident to the drilling and production of crude oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires and pollution and other environmental risks.  These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation.  In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.


We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry.  We believe the coverage and types of insurance we maintain are adequate.  The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations.  We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.


Employees and Consultants


At February 28, 2018, we had six full-time employees.  Additionally, we regularly use the services of four consultants on an as-needed basis for accounting, technical, oil field, geological, investor relations and administrative services.  None of our employees are subject to a collective bargaining agreement.  In our opinion, relations with our employees are good.  We may hire more employees in the future as needed.  All other services are currently contracted for with independent contractors.  We have not obtained “key person” life insurance on any of our officers or directors.


Long-Term Success


Our long-term success depends on the successful acquisition, exploration and development of commercial grade crude oil and natural gas properties as well as the prevailing prices for crude oil and natural gas to generate future revenues and operating cash flow.  Crude oil and natural gas prices are extremely volatile and have decreased significantly since June of 2014 and are affected by many factors outside of our control.  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 have experienced since June 2014, has had and will likely continue to have a material adverse effect on our results of operations and financial condition.  Such pricing factors are beyond our control, and have resulted and will result in negative fluctuations of our earnings.  We believe; however, that even in this volatile pricing environment there are significant opportunities available to us in the crude oil and natural gas exploration and development industry.


Availability of SEC Filings


You may read and copy any materials we file with the U.S. Securities and Exchange Commission (the “SEC”) at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549, on official business days during the hours of 10:00 am to 3:00 pm.  You can obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.  The address of that site is http://www.sec.gov.




8



Website / Available Information


Our website can be found at www.daybreakoilandgas.com.  Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed with or furnished to the SEC, pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (“the Exchange Act”) can be accessed free of charge on our website at www.daybreakoilandgas.com under the “Shareholder/Financial” section of our website within the “SEC Filings” subsection as soon as is reasonably practicable after we electronically file such material with, or otherwise furnish it to, the SEC.


We have adopted an Ethical Business Conduct Policy Statement to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures.  We also have adopted a Code of Ethics for Senior Financial Officers that applies to our principal executive officer, principal financial officer, principal accounting officer and controller.  Copies of our Ethical Business Conduct Policy Statement and Code of Ethics for Senior Financial Officers are available under the “Shareholder/Financial” section of our website at www.daybreakoilandgas.com within the heading “Corporate Governance.”  We intend to promptly disclose via a Current Report on Form 8-K or via an update to our website, information on any amendment to or waiver of these codes with respect to our executive officers and directors.  Waiver information disclosed via the website will remain on the website for at least 12 months after the initial disclosure of a waiver.


Our Corporate Governance Guidelines and the charters of our Audit Committee, Nominating and Corporate Governance Committee, and Compensation Committee are also available in the “Shareholder/Financial” section of our website at www.daybreakoilandgas.com within the heading “Corporate Governance.”  In addition, copies of our Ethical Business Conduct Policy Statement, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines and the charters of the Committees referenced above are available at no cost to any shareholder who requests them by writing or telephoning us at the following address or telephone number:


 

Daybreak Oil and Gas, Inc.

 

1101 N. Argonne Road, Suite A 211

 

Spokane Valley, WA 99212-2699

 

Attention: Corporate Secretary

 

Telephone: (509) 232-7674


Information contained on or connected to our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.




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ITEM 1A.   RISK FACTORS


The following risk factors together with other information set forth in this Annual Report on Form 10-K, should be carefully considered by current and future investors in our securities.  An investment in our securities involves substantial risks.  There are many factors that affect our business, a number of which are beyond our control.  Our business, financial condition and results of operations could be materially adversely affected by any of these factors.  The nature of our business activities further subjects us to certain hazards and risks.  The risks described below are a summary of the known material risks relating to our business.  Additional risks and uncertainties not presently known to us or that we currently deem to be immaterial individually or in aggregate may also impair our business operations.  If any of these risks actually occur, it could harm our business, financial condition or results of operations and impair our ability to implement our business plan or complete development projects as scheduled.  In any such case, the trading price of our Common Stock could decline, and you could lose all, or a part, of your investment.


Crude oil and natural gas prices are volatile.  Since the second half of 2014 when the price of WTI oil was $105.79 per barrel, there has been substantial volatility and uncertainty in commodity prices, which has significantly adversely affected, and in the future may continue to adversely affect, our financial condition, liquidity, results of operations, cash flows, access to capital markets, and ability to grow.


Our revenues, operating results, liquidity, cash flows, profitability and valuation of proved reserves depend substantially upon the market prices of crude oil and natural gas.  Product prices affect our cash flow available for capital expenditures and our ability to access funds through the capital markets.  Declines in commodity prices have historically adversely affected the estimated value of our proved reserves and our cash flows.  The volatility in hydrocarbon prices from June of 2014, which we are currently experiencing has had a material adverse effect on our cash flows, reserves valuation and availability of funds in the financial markets.  Specifically, our average realized price of WTI crude oil for the twelve months ended February 28, 2018 was $49.34 in comparison to the average realized price of $37.03 for the twelve months ended February 28, 2017.


The commodity prices we receive for our crude oil and natural gas depend upon factors beyond our control, including among others:

·

changes in the supply of and demand for crude oil and natural gas;

·

market uncertainty;

·

the level of consumer product demands;

·

hurricanes and other weather conditions;

·

domestic governmental regulations and taxes;

·

the foreign supply of crude oil and natural gas

·

the price of crude oil and natural gas imports; and

·

overall domestic and foreign economic conditions.


These factors make it very difficult to predict future hydrocarbon commodity price movements with any certainty.  It is beyond our control and ability to accurately predict when there will be a sustained improvement in hydrocarbon prices.  All of our crude oil and natural gas sales are made pursuant to contracts based on spot market prices and are not based on long-term fixed price contracts.  Crude oil and natural gas prices do not necessarily fluctuate in direct relation to each other.


We have experienced significant operating losses in the past and there can be no assurance that we will become profitable in the future.


We have reported a net loss of approximately $2.5 million for the year ended February 28, 2018, and we have an accumulated deficit through February 28, 2018 of approximately $38.3 million.  Without successful exploration and development of our properties and a significant sustained increase in hydrocarbon prices any investment in Daybreak could become devalued or worthless.


We have substantial indebtedness.  The amount of our outstanding indebtedness and our current inability to meet our debt obligations will have adverse consequences on our business, financial condition and results of operations.


At February 28, 2018, we had approximately $16.3 million of consolidated indebtedness comprised of a variety of short-term and long-term borrowings; related party notes and payables; a line of credit; trade payables; and 12% Subordinated Notes.  The level of indebtedness we have affects our operations in a number of ways.  We will need to use a portion of our cash flow to meet principal, interest and payables commitments; which reduces the amount of funds we will have available to finance our operations.  This lack of funds limits planning for or reacting to changes in our



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business and the industry in which we operate and could limit our ability to make funds available for other purposes, such as future exploration, development or acquisition activities.  The Company is currently considered to be in default under the terms of its credit facility loan.  Maximilian is currently in receivership.  The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender to assume the Maximilian credit facility.  No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company.  During the twelve months ended February 28, 2018, the Company received $102,700 in advances under the terms of the credit facility.  Our ability to meet our debt service obligations and reduce our total indebtedness will depend upon our future performance.  Our future performance, in turn, is dependent upon many factors that are beyond our control such as the level of hydrocarbon prices and general economic, financial and business conditions.  We cannot guarantee that our future performance will not be adversely affected by such economic conditions and financial, business and other factors.


To execute our business plan we will need to develop current projects and expand our operations requiring significant capital expenditures, which we may be unable to fund.


Our business plan contemplates the execution of our current exploration and development projects and the expansion of our business by identifying, acquiring, and developing additional crude oil and natural gas properties.  We plan to rely on external sources of financing to meet the capital requirements associated with these activities.  We will have to obtain any additional funding we need through debt and equity markets or the sale of producing or non-producing assets.  There is no assurance that we will be able to obtain additional funding when it is required or that it will be available to us on commercially acceptable terms.


Low hydrocarbon price environments such as the downturn in prices that we are currently experiencing, as well as operating difficulties and other factors, many of which are beyond our control, are causing our revenues and cash flows from operating activities to decrease and may limit our ability to internally fund our exploration and development activities.


We may make offers to acquire crude oil and natural gas properties in the ordinary course of our business.  If these offers are accepted, our capital needs will increase substantially.  If we fail to obtain the funding that we need when it is required, we may have to forego or delay potentially valuable opportunities to acquire new crude oil and natural gas properties.  In addition, without the necessary funding, we may default on existing funding commitments to third parties and forfeit or dilute our rights in existing crude oil and natural gas property interests.


Hydrocarbon price declines may result in impairments of our asset carrying values.


Commodity prices have a significant impact on the present value of our proved reserves.  Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our crude oil and natural gas properties in certain situations.  We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets.  To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required.  Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred.  For the twelve months ended February 28, 2018, we determined it was not necessary to recognize any additional non-cash impairment expense on our California crude oil properties due to current hydrocarbon prices.


The crude oil and natural gas business is highly competitive, placing us at an operating disadvantage.


We expect to be at a competitive disadvantage in (a) seeking to acquire suitable crude oil and or natural gas drilling prospects; (b) undertaking exploration and development; and (c) seeking additional financing.  We base our preliminary decisions regarding the acquisition of crude oil and or natural gas prospects and undertaking of drilling ventures upon general and inferred geology and economic assumptions.  This public information is also available to our competitors.

In addition, we compete with larger crude oil and natural gas companies with longer operating histories and greater financial resources than us.  These larger competitors, by reason of their size and greater financial strength, can more easily:

·

access capital markets;

·

recruit more qualified personnel;

·

absorb the burden of any changes in laws and regulation in applicable jurisdictions;

·

handle longer periods of reduced prices of crude oil and natural gas;

·

acquire and evaluate larger volumes of critical information; and

·

compete for industry-offered business ventures.




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These disadvantages could create negative results for our business plan and future operations.


Our ability to reach and maintain profitable operating results is dependent on our ability to find, acquire, and develop crude oil and natural gas properties.


Our future performance depends upon our ability to find, acquire, and develop crude oil and natural gas reserves that are economically recoverable.  Without successful exploration and acquisition activities, we will not be able to develop reserves or generate production revenues to achieve and maintain profitable operating results.  No assurance can be given that we will be able to find, acquire or develop these reserves on acceptable terms.  We also cannot assure that commercial quantities of crude oil and natural gas deposits will be discovered that are sufficient to enable us to recover our exploration and development costs.


Our limited capital expenditures and drilling program, when coupled with a sustained depression in crude oil and natural gas prices, will significantly reduce our cash flow and constrain any future drilling, which would have a material adverse effect on our business, financial condition and results of operations.


Historically, we have made substantial capital expenditures for the exploration and development of crude oil and natural gas reserves.  The combination of lower hydrocarbon prices and the reduction of our drilling operations has resulted in reduced production and operating cash flows since June of 2014.  A continued sustained volatility in these hydrocarbon prices combined with reduced production and accompanying lower cash flows will continue to adversely affect our business financial condition and results of operations.


Our proved reserves are estimates and depend on many assumptions.  Any material inaccuracies in these assumptions could cause the quantity and value of our crude oil reserves, and our revenues, profitability and cash flows to be materially different from our estimates.


The accuracy of estimated proved reserves and estimated future net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to crude oil prices, drilling and operating expenses and other matters.  Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, crude oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil reserves will most likely vary from the assumptions and estimates used to determine proved reserves.  Any significant variance could materially affect the estimated quantities and value of our crude oil reserves, which in turn could adversely affect our cash flows, results of operations, financial condition and the availability of capital resources.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil prices and other factors, many of which are beyond our control.  Downward adjustments to our estimated proved reserves could require us to impair the carrying value of our crude oil properties, which would reduce our earnings and our stockholders’ equity.


The present value of proved reserves will not necessarily equal the current fair market value of our estimated crude oil reserves.  In accordance with reserve reporting requirements of the SEC, we are required to establish economic production for reserves on an average historical price.  Actual future prices and costs may be materially higher or lower than those required by the SEC.  The timing of both the production and expenses with respect to the development and production of crude oil properties will affect the timing of future net cash flows from proved reserves and their present value.


The estimated proved reserve information is based upon reserve reports prepared by an independent engineer.  From time to time, estimates of our reserves are also made by our company engineer for use in developing business plans and making various decisions.  Such estimates may vary significantly from those of the independent engineers and may have a material effect upon our business decisions and available capital resources.


We may not be able to replace current production with new crude oil and natural gas reserves.


In general, the volume of production from a crude oil and natural gas property declines as reserves related to that property are depleted.  The decline rates depend upon reservoir characteristics.  In past years other than our East Slopes project in California, our crude oil and natural gas properties have had steep rates of decline and relatively short estimated productive lives.




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Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.


Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including hydrocarbon prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory and zoning approvals and other factors.


Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our business and results of operations.


Due to lower crude oil prices and the lack of available capital, we have not drilled any prospective development locations in California since November of 2013.


We may reclassify proved undeveloped reserves to unproved reserves due to our inability to commit sufficient capital within the required five-year development window, which could adversely affect the value of our properties.


The SEC generally requires that any undrilled location can be classified as a proved undeveloped reserve only if a development plan has been adopted indicating that the location is scheduled to be drilled within five years.  The recent reduction of our drilling program in response to depressed crude oil and natural gas process is likely to impact our ability to develop proved undeveloped reserves within such five-year period.  If we continue our limited drilling plans over a significant period of time our future access to capital resources is limited, we will also likely further delay our development of our proved undeveloped reserves or ultimately suspend such development which could result in the reclassification of a significant amount of our proved undeveloped reserves as probable or possible reserves.  A significant reclassification of proved undeveloped reserves could adversely affect the value of our properties.


Our producing reserves are located in one major geographic area.  Concentration of reserves in limited geographic areas may disproportionately expose us to operational, regulatory and geological risks.


Our one core producing property is located in Kern County, California.  As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of crude oil.


When we make the determination to invest in crude oil or natural gas properties we rely upon geological and engineering estimates, which involve a high level of uncertainty.


Geologic and engineering data are used to determine the probability that a reservoir of crude oil or natural gas exists at a particular location.  This data is also used to determine whether crude oil and natural gas are recoverable from a reservoir.  Recoverability is ultimately subject to the accuracy of data including, but not limited to, geological characteristics of the reservoir, structure, reservoir fluid properties, the size and boundaries of the drainage area, reservoir pressure, and the anticipated rate of pressure depletion.  Also, an increase in the costs of production operations may render some deposits uneconomic to extract.


The evaluation of these and other factors is based upon available seismic data, computer modeling, well tests and information obtained from production of crude oil and natural gas from adjacent or similar properties.  There is a high degree of risk in proving the existence and recoverability of reserves.  Actual recoveries of proved reserves can differ materially from original estimates.  Accordingly, reserve estimates may be subject to downward adjustment.  Actual production, revenue and expenditures will likely vary from estimates, and such variances may be material.




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Drilling is a high risk activity and, as a result, we may not be able to adhere to our proposed drilling schedule, or our drilling program may not result in commercially productive reserves.


Our future success will partly depend on the success of our drilling programs. The future cost or timing of drilling, completing, and producing wells is inherently uncertain.  Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including:

·

unexpected drilling conditions;

·

well integrity issues and surface expressions;

·

pressure or irregularities in formations;

·

equipment failures or accidents;

·

compliance with landowner requirements;

·

current crude oil and natural gas prices and estimates of future crude oil and natural gas prices;

·

availability, costs and terms of contractual arrangements with respect to pipelines and related facilities to gather, process, transport and market crude oil and natural gas; and

·

shortages or delays in the availability of drilling rigs and the delivery of equipment and/or services, including experienced labor.


Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.


The demand for qualified and experienced field personnel to drill wells and conduct field operations in the crude oil and natural gas industry can fluctuate significantly, often in correlation with crude oil and natural gas prices, causing periodic shortages.  Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled.  These factors also cause significant increases in costs for equipment, services and personnel.  Higher crude oil and natural gas prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews, and associated supplies, equipment and services.  It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be.


Our financial condition will deteriorate if we are unable to retain our interests in our leased crude oil and natural gas properties.


All of our properties are held under interests in crude oil and natural gas mineral leases.  If we fail to meet the specific requirements of any lease, such lease may be terminated or otherwise expire.  We cannot be assured that we will be able to meet our obligations under each lease.  The termination or expiration of our “working interests” (interests created by the execution of a crude oil or natural gas lease) relating to these leases would impair our financial condition and results of operations.


We will need significant additional funds to meet capital calls, drilling and other production costs in our effort to explore, produce, develop and sell the crude oil and natural gas produced by our leases.  We may not be able to obtain any such additional funds on acceptable terms.


Title deficiencies could render our crude oil and natural gas leases worthless; thus damaging the financial condition of our business.


The existence of a material title deficiency can render a lease worthless, resulting in a large expense to our business.  We rely upon the judgment of crude oil and natural gas lease brokers who perform the fieldwork and examine records in the appropriate governmental office before attempting to place a specific mineral interest under lease.  This is a customary practice in the crude oil and natural gas industry.


We anticipate that we, or the person or company acting as operator on the properties that we lease, will examine title prior to any well being drilled.  Even after taking these precautions, deficiencies in the marketability of the title to the leases may still arise.  Such deficiencies may render some leases worthless, negatively impacting our financial condition.


We face various risks associated with the trend toward increased anti-crude oil and natural gas development activity.


In recent years, we have seen significant growth in opposition to crude oil and natural gas development in the United States.  Companies in our industry can be the target of opposition to hydrocarbon development from stakeholder groups, including national, state and local governments, regulatory agencies, non-government organizations and public citizens.  This opposition is focused on attempting to limit or stop hydrocarbon development.  Examples of such opposition



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include: efforts to reduce access to public and private lands; delaying or canceling permits for drilling or pipeline construction; limiting ore banning industry techniques such as hydraulic fracturing, and/or adding restrictions on or the use of water and associated disposal; imposition of set-backs on crude oil and natural gas sites; delaying or denying air-quality permits; advocating for increased punitive taxation or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm.  Recent efforts by the US Administration to modify federal crude oil and natural gas regulations could intensify the risk of anti-development efforts from grass roots opposition.


Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements from these efforts, could have a material adverse effect on our business.


Restricted land access could reduce our ability to explore for and develop crude oil and natural gas reserves.


Our ability to adequately explore for and develop crude oil and natural gas resources is affected by a number of factors related to access to land.  Examples of factors which reduce our access to land include, among others:

·

new municipal, state or federal land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;

·

local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;

·

landowner, community and/or governmental opposition to infrastructure development;

·

regulation of federal and Indian land by the Bureau of Land Management;

·

anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, disruption of drilling, or damage to equipment;

·

 the presence of threatened or endangered species or of their habitat;

·

Disputes regarding leases; and

·

Disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements.


Reduced ability to obtain new leases could constrain our future growth and opportunity resulting in a material adverse effect on our business, financial condition, results of operations and our cash flows.


If we as operator of our crude oil project fail to maintain adequate insurance, our business could be exposed to significant losses.


Our crude oil projects are subject to risks inherent in the crude oil and natural gas industry.  These risks involve explosions, uncontrollable flows of crude oil, natural gas or well fluids, pollution, fires, earthquakes and other environmental issues.  These risks could result in substantial losses due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage.  As protection against these operating hazards we maintain insurance coverage to include physical damage and comprehensive general liability.  However, we are not fully insured in all aspects of our business.  The occurrence of a significant event on any project against which we are not adequately covered by insurance could have a material adverse effect on our financial position.


In any project in which we are not the operator, we will require the operator to maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry.  The occurrence of a significant adverse event on any of these projects if they are not fully covered by insurance could result in the loss of all or part of our investment.  The loss of any such project investment could have a material adverse effect on our financial condition and results of operations.


New technologies may cause our current exploration and drilling methods to become obsolete.


There have been rapid and significant advancements in technology in the natural gas and crude oil industry, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial increase in cost. Further, competitors may obtain patents which might prevent us from implementing new technologies. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.



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Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of proposed legislation.


Legislation previously has been proposed that would, if enacted into law, make significant changes to United States federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to crude oil and natural gas exploration and production companies.  These changes include, but are not limited to:  (1) the repeal of the percentage depletion allowance for crude oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain U.S. domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures.  It is unclear whether any such changes will be enacted and, if enacted, how soon any such changes could become effective.  The passage of this type of legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to crude oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our Common Stock as well as affect our financial condition and results of operations.


Our crude oil and natural gas exploration and production, and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.


Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances.  Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated, and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate.  Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws.  Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share.  Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.


We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future.  Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs.  Some of our properties may be affected by environmental contamination that may require investigation or remediation.  In addition, claims are sometimes made or threatened against companies engaged in crude oil and natural gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation.  Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.


Climate change legislation or regulations restricting emissions of greenhouse gases (“GHG”) could result in increased operating costs and reduced demand for the crude oil we produce.


Climate change continues to attract considerable public and scientific attention.  As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs.  These efforts have included consideration by states or groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.


At the federal level, no comprehensive climate change legislation has been implemented to date.  However, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the Clean Air Act.  The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, onshore and offshore crude oil and natural gas production facilities and onshore processing, transmission, storage and distribution facilities.  In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the crude oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines, and in January 2016, the EPA proposed additional revisions to leak detection methodology.




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The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that require reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could cause us to incur increased costs that could have an adverse effect on our business, financial condition and results of operations.  Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for crude oil and natural gas, which could reduce the demand for the crude oil or natural gas we produce and lower the value of our reserves.


Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels.  Another possible consequence of climate change is increased volatility in seasonal temperatures.  Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages.  Extreme weather conditions can interfere with our production and increase our operating expenses.  Such damage or increased expenses from extreme weather may not be fully insured.  If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.  At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.


We may lose key management personnel which could endanger the future success of our crude oil and natural gas operations.


Our President and Chief Executive Officer, who is also acting as our interim principal finance and accounting officer, our Director of Field Operations, and two of our directors each have substantial experience in the crude oil and natural gas business. The loss of any of these individuals could adversely affect our business.  If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that a suitable or comparable substitute will be found.


We may be unable to continue as a going concern in which case our securities will have little or no value.


Our financial statements for the year ended February 28, 2018 were 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 inception, which raises substantial doubt about our ability to continue as a going concern.  In the event we are not able to continue operations, an investor will likely suffer a complete loss of their investment in our securities.


We have not held an annual meeting of our shareholders since 2010; as such, our shareholders have not had the opportunity to elect directors since 2010.


Our bylaws and the Washington Business Corporation Act state that we must hold an annual meeting of our shareholders for the election of directors and other business as may be properly brought before the meeting.  However, because we have had limited financial resources, we have not held an annual meeting of our shareholders since 2010.  As such, our shareholders have not had the opportunity to vote in an election of our directors since 2010.  When we hold an annual shareholders’ meeting in the future, our shareholders will then have the opportunity to vote on the election of our directors.


The market price of our Common Stock has been volatile, which may cause the investment value of our stock to decline.


Daybreak’s Common Stock (OTC Pink: DBRM) trades on the OTC Pink® Open Market.  Prior to May 1, 2016, our stock had traded on the OTCQB Venture Marketplace.  Our transition to the OTC Pink® Open Market was a result of a cost-savings move for the company related to listing fees on the Venture Marketplace.


Because of the limited liquidity of our stock, shareholders may be unable to sell their shares at or above the cost of their purchase prices.  The trading price of our shares has experienced wide fluctuations and these shares may be subject to similar fluctuations in the future.


The trading price of our Common Stock may be affected by a number of factors including events described in these risk factors, as well as our operating results, financial condition, announcements of drilling activities, general conditions in the crude oil and natural gas exploration and development industry including volatility in crude oil and natural gas prices, and other events or factors.  The decline and instability in hydrocarbon prices, that we have been experiencing since June 2014, has had a corresponding material adverse impact on our revenues and a similar direct material adverse impact on the trading price of our Common Stock.




17



In recent years, broad stock market indices, in general, and smaller capitalization companies, in particular, have experienced substantial price fluctuations.  In a volatile market, we do experience wide fluctuations in the market price of our Common Stock.  These fluctuations may have a negative effect on the market price of our Common Stock.


Pursuant to SEC rules our Common Stock is classified as a “penny stock” increasing the risk of investment in these shares.


Our Common Stock is designated as a “penny stock” and thus may be more illiquid than shares traded on an exchange or on NASDAQ.  Penny stocks generally are any non-NASDAQ or non-exchange listed equity securities with a price of less than $5.00, subject to certain exceptions.


The “penny stock” reporting and disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for a stock that is subject to these rules.  The market liquidity for the shares could be severely and adversely affected by limiting the ability of broker-dealers to sell these shares.


We have a limited operating history on which to base an investment decision.


To date, while we have positive cash flow from our continuing operations in California, we have not yet generated sustainable positive cash flow or earnings on a company-wide basis.  We cannot provide any assurances that we will ever operate profitably especially in the current low-priced hydrocarbon environment.  As a result of our limited operating history, we are more susceptible to business risks.  These risks include unforeseen capital requirements, failure to establish business relationships, and competitive disadvantages against larger and more established companies.


The resale of shares offered in private placements could depress the value of the shares.


In the past, shares of our Common Stock have been offered and sold in private placements at significant discounts to the trading price of the Common Stock at the time of the offering.  Sales of substantial amounts of Common Stock eligible for future sale in the public market, or the availability of shares for sale, including shares issued upon exercise of outstanding warrants, could adversely affect the prevailing market price of our Common Stock and our ability to raise capital by an offering of equity securities.


Privately placed issuances of our Common Stock, Preferred Stock and warrants have and may continue to dilute ownership interests which could have an adverse effect on our stock prices.


Our authorized capital stock consists of 200,000,000 shares of Common Stock and 10,000,000 shares of preferred stock.  As of February 28, 2018, there were 51,532,364 shares of Common Stock and 709,568 shares of Series A Convertible Preferred stock outstanding.


Historically we have issued, and likely will continue to issue, additional shares of our Common Stock in connection with the compensation of personnel, future acquisitions, private placements, possible equity swaps for debt or for other business purposes.  Future issuances of substantial amounts of these equity securities could have a material adverse effect on the market price of our Common Stock, and would result in further dilution of the ownership interests of our existing shareholders.


Preferred Stock has been issued with greater rights than the Common Stock issued which may dilute and depress the investment value of the Common Stock investments.


The rights of the holders of Common Stock are subject to and may be adversely affected by the rights and preferences afforded to the holders of our Series A Convertible Preferred Shares.  The rights and preferences of these issued preferred shares include:

·

conversion into Common Stock of the Company anytime the preferred shareholder may wish;

·

cumulative dividends in the amount of 6% of the original purchase price per annum, payable upon declaration by the board of directors;

·

the ability to vote together with the Common Stock with a number of votes equal to the number of shares of Common Stock to be issued upon conversion of the Preferred Stock; and

·

a preference upon any actual or “deemed” liquidation, dissolution or winding up of the Company.


The issuance of these preferred shares could make it less likely that shareholders would receive a premium for their shares of Common Stock as a result of any attempt to acquire the Company.  Further, this issuance could adversely affect the market price of, and the voting and other rights, of the holders of outstanding shares of Common Stock.




18



Further, the Board of Directors has the power to issue more shares of Preferred Stock without shareholder approval, and such shares can be issued with such rights, preferences, and limitations as may be determined by our Board of Directors.


We will need to seek to raise additional funds in the future through debt financing, which may impose operational restrictions and may further dilute existing ownership interests.


We expect to seek to raise additional capital in the future to help fund our acquisition, development, and production of crude oil and natural gas reserves.  We have obtained debt financing through our revolving credit facility with Maximilian Resources, LLC, as described in the MD&A section under the caption “Current debt (short-term borrowings) – Maximilian Credit Facility”  Subsequent debt financing, if available, may require restrictive covenants in addition to those to which we are already subject under the Maximilian loan, which may limit our operating flexibility.  Future debt financing may also involve debt instruments that are convertible into or exercisable for Common Stock.  The conversion of the debt to equity financing may dilute the equity position of our existing shareholders.


We do not anticipate paying dividends on our Common Stock, which could devalue the market value of these securities.


We have not paid any cash dividends on our Common Stock since the Company’s inception in 1955.  We do not anticipate paying cash dividends in the foreseeable future.  Any dividends paid in the future will be at the complete discretion of our Board of Directors.  For the foreseeable future, we anticipate that we will retain any revenues that we may generate from our operations.  These retained revenues will be used to finance and develop the growth of the Company.  Prospective investors should be aware that the absence of dividend payments could negatively affect the market value of our Common Stock.  Investors must rely on sales of their Common Stock after price appreciation, which may never occur, as the only way to realize a return on their investment.  Investors seeking cash dividends should not purchase our Common Stock.


A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.


A terrorist attack, anti-terrorist efforts or other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations.  If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for crude oil and natural gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues.  Crude oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of crude oil and natural gas production are destroyed or damaged.  Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.





19




ITEM 1B.   UNRESOLVED STAFF COMMENTS


As a smaller reporting company, we are not required to provide the information otherwise required by this Item.






20




ITEM 2.   PROPERTIES


We conduct all of our drilling, exploration and production activities in the United States.  All of our crude oil assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.  During the year ended February 28, 2018, we were involved in continuing operations of an oilfield project in Kern County, California.


On October 31, 2016, we completed the sale of our crude oil and natural gas interest in the Twin Bottoms Field located in Lawrence County, Kentucky.  As a result of this sale and the restructuring of its Balance Sheet, the Company recognized income of $394,623 on discontinued operations which includes; an approximate $1.96 million loss on the sale of oil and natural gas properties; a reduction of $4.5 million in debt associated with Kentucky; a loss on note receivable settlement of approximately $1.5 million; and gain on debt settlement of approximately $3.9 million with its lender Maximilian for the twelve months ended February 28, 2017.


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 on the first prospect.  An analysis of the 3-D seismic survey confirmed the first prospect identified on the 2-D seismic, as well as identified several additional drilling locations.  We will obtain 3-D survey on the second prospect after drilling a well on the first prospect however, the two prospects are independent of each other and the success or failure of either one does not effect the other.  The wells will be drilled vertically with conventional completions and no hydraulic fracturing will be required.  The first well is expected to be drilled during the late summer of 2018.


We have not filed any estimates of total, proved net crude oil or natural gas reserves with any federal agency other than this report to the SEC for the fiscal year ended February 28, 2018.  Throughout this Annual Report on Form 10-K, crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).


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.


Our 20 vertical 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.  Our average working interest and NRI in these 20 producing crude oil wells is 36.6% and 28.5%, 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.


Sunday Central Processing and Storage Facility


The crude oil produced from our acreage in California is considered heavy crude oil.  The crude oil ranges from 14° to 16° API gravity.  All of the crude oil from our five producing properties is processed, stored and sold from the Sunday central processing and storage facility.  The crude oil must be heated to separate and remove water to prepare it to be sold.  We constructed these facilities during the summer and fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines.  In 2013, we completed an upgrade to this facility including the addition of a second crude oil storage tank to handle the additional crude oil production from the wells drilled in 2013.


By utilizing the Sunday centralized production facility our average operating costs have been reduced from over $40 per barrel in 2009 to approximately $13 per barrel of crude oil for the year ended February 28, 2018.  With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.




21



California Producing Properties


Sunday Property


In November 2008, we made our initial crude oil discovery drilling the Sunday #1 well.  The well was put on production in January 2009.  Production is from the Vedder Sand at approximately 2,000 feet.  During 2009, we drilled three development wells including one horizontal well: the Sunday #2, Sunday #3 and Sunday #4H wells, respectively.  During May and June 2013, we drilled two additional development wells: the Sunday #5 and Sunday #6.  We have a 37.5% working interest with a 26.1% net revenue interest (“NRI”) in the Sunday #1 well.  For the Sunday #2 and Sunday #3 wells, we have a 33.8% working interest with a 24.3% NRI.  In the Sunday #4H well, we have a 33.8% working interest with a 27.1% NRI.  In both the Sunday #5 and Sunday #6 wells we have a 37.5% working interest and a NRI of 30.1%.  Our average working interest and NRI for the Sunday property six producing wells in aggregate is 35.6% and 27.0%, respectively.  The Sunday reservoir is estimated to be approximately 35 acres in size with the potential for at least five more development wells to be drilled in the future.


Bear Property


In February 2009, we made our second crude oil discovery drilling the Bear #1 well, which is approximately one mile northwest of our Sunday discovery.  The well was put on production in May 2009.  Production is from the Vedder Sand at approximately 2,200 feet.  In December 2009, we began a development program on this property by drilling and completing the Bear #2 well.  In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells.  In May and June 2013, we drilled three additional development wells, the Bear #5, Bear #6 and Bear #7, on this property.  In November 2013, we drilled and put on production two additional development wells: the Bear #8 and Bear #9.  We have a 37.5% working interest in all wells on the Bear property.  Our NRI in the Bear #1, Bear #2, Bear #3 and Bear #4 wells is 26.1%.  For the Bear #5, Bear #6 and Bear #7 wells our NRI is 30.1%.  Our NRI in the Bear #8 and Bear #9 wells is 31.7%.  The average working interest and NRI for the Bear property for the ten producing wells in aggregate is 37.5% and 28.7%, respectively.  The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least ten more development wells to be drilled in the future.


Black Property


The Black property was acquired through a farm-in arrangement with a local operator.  The Black property is just south of the Bear property on the same fault system.  The Black #1 well was completed and put on production in January 2010.  Production is from the Vedder Sand at approximately 2,200 feet.  In May 2013, we drilled a development well, the Black #2, on this property.  We have a 33.8% working interest with a 26.8% NRI in the two producing wells on this property.  The Black reservoir is estimated to be approximately 13 acres in size with the potential for at least three more development wells to be drilled in the future.


Ball Property


The Ball #1-11 well was put on production in late October 2010.  In June 2013 we drilled a development well, the Ball #2-11, on this property.  Production on this property is from the Vedder Sand at approximately 2,500 feet.  We have a 37.5% working interest with a 31.2% NRI in the two producing wells on this property.  Our 3-D seismic data indicates a reservoir of approximately 38 acres in size with the potential for at least three more development wells to be drilled in the future.


Dyer Creek Property


The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010.  This well produces from the Vedder Sand and is located to the north of the Bear property on the same trapping fault.  We have a 37.5% working interest with a 31.2% NRI in all wells on this property.  The Dyer Creek property has the potential for at least one development well in the future.


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 additional financing is put in place.  We plan to spend approximately $10,000 in new capital investments within the East Slopes Project area in the 2018-2019 fiscal year if no new financing is in place.  If new financing is secured, we plan to drill four development wells for a total of $525,000.




22



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 wells will be drilled vertically with conventional completions and no hydraulic fracturing will be required.  The first well is expected to be drilled during the late summer of 2018.


Encumbrances


The Company’s debt obligations, pursuant to a credit facility loan agreement and promissory notes with 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 Annual Report on Form 10-K 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.  For further information on the loan agreement refer to the discussion under the caption “Current debt (short-term borrowings)” in the MD&A portion of this Annual Report on Form 10-K.


Reserves


Crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).  The following table sets forth our estimated net quantities of proved reserves as of February 28, 2018.


On October 31, 2016, we sold our non-operated working interest in crude oil and natural gas properties located in the Twin Bottoms Field in Lawrence County, Kentucky.  As of February 28, 2018, our total reserves were comprised of our working interest in East Slopes Project located in Kern County, California.


 

 

Proved Reserves

Reserve Category

 

Crude Oil (Barrels)

 

Natural Gas

(Mcf)

 

Total Crude Oil

Equivalents (BOE)

 

Percent of Oil

Equivalents (BOE)

Developed

 

109,475

 

-

 

109,475

 

25.6%

Undeveloped

 

318,592

 

-

 

318,592

 

74.4%

Total Proved

 

428,067

 

-

 

428,067

 

100.0%


Changes in our estimated net proved reserves for the twelve months ended February 28, 2018 are set forth in the table below.


 

 

 

Proved Reserves

(BOE)

Balance as of February 28, 2017

 

 

381,070 

Revisions

 

 

35,099 

Discoveries and extensions

 

 

24,639 

Production

 

 

(12,741)

Balance as of February 28, 2018

 

 

428,067 


Revisions. Net upward revisions of 35,099 BOE in aggregate were due to higher realized hydrocarbons prices in California during the twelve months ended February 28, 2018 increasing the economic life of our proved reserves.


Discoveries and extensions. For the twelve months ended February 28, 2018, there were 24,639 BOE in extensions in California due to higher realized hydrocarbon prices.


Production. Production in California was 12,741 BOE in aggregate of proved reserves for the twelve months ended February 28, 2018.


As of February 28, 2018, our total proved undeveloped reserves were comprised of our interests in Kern County, California.




23



Changes in our estimated net proved undeveloped reserves for the twelve months ended February 28, 2018 are set forth in the table below.


 

 

Proved Undeveloped Reserves

(BOE)

Balance as of February 28, 2017

 

281,360

Revisions

 

12,593

Discoveries and extensions

 

24,639

Balance as of February 28, 2018

 

318,592


Revisions. There were net upward revisions of 12,593 BOE in aggregate due to higher realized hydrocarbons prices during the twelve months ended February 28, 2018 increasing the economic life of our proved undeveloped reserves.


Discoveries and extensions. For the twelve months ended February 28, 2018, there were there were 24,639 BOE in extensions in California due to higher realized hydrocarbon prices.


Our estimated net proved developed producing reserves of continuing operations in California at February 28, 2018 are set forth in the table below.


 

 

Proved Developed Reserves

 

 

 

 

Natural

 

Total Oil

 

Percent of Oil

Location

 

Oil (Barrels)

 

Gas (Mcf)

 

Equivalents (BOE)

 

Equivalents (BOE)

California

 

109,475

 

-

 

109,475

 

100.0%


Our estimated net proved undeveloped reserves of continuing operations in California at February 28, 2018 are set forth in the table below.


 

 

Proved Undeveloped Reserves

 

 

 

 

Natural

 

Total Oil

 

Percent of Oil

Location

 

Oil (Barrels)

 

Gas (Mcf)

 

Equivalents (BOE)

 

Equivalents (BOE)

California

 

318,592

 

-

 

318,592

 

100.0%


The Company has 29,940 Bbls of proved undeveloped reserves that have remained undeveloped for a period greater than five years.  These proved undeveloped reserves have remained undeveloped due to the period of depressed crude oil and natural gas prices that we have experienced resulting in a lack of capital available for drilling.  Under our current drilling plans, we intend to convert all 318,592 BOE or 100.0% of the proved undeveloped reserves disclosed as of February 28, 2018 to proved developed reserves within the next five years.


Our estimated proved reserves (BOE) and PV-10 valuation of continuing operations in California at February 28, 2018 are set forth in the table below.


 

 

Proved Reserves

 

 

 

 

 

 

PV-10 as a

 

 

Total Oil

 

PV-10 of

 

Percentage of

Location

 

Equivalents (BOE)

 

Proved Reserves

 

Proved Reserves

California

 

428,067

 

 

3,248,153

 

100.0%


The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10”), was approximately $3.2 million at February 28, 2018 a increase of approximately $1.5 million or 88.6% from the PV-10 reserve valuation at February 28, 2017.  This increase is due to the increase from our average realized price of crude oil sales in comparison to the average realized price from the prior twelve month period.  The commodity prices used to estimate proved reserves and their related PV-10 at February 28, 2018 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the twelve month period from March 2017 through February 2018.  The benchmark average price for the twelve months ended February 28, 2018 was $52.89 per barrel of crude oil in comparison to $45.85 in the prior year reserve report.


These benchmark average prices were further adjusted for crude oil quality and gravity, transportation fees and other price differentials resulting in an average realized price in California for the February 28, 2018 reserve report of $50.29 in comparison to $35.91 in the February 28, 2017 reserve report.  Adverse changes in any price differential would reduce our cash flow from operations and the PV-10 of our proved reserves.  Operating costs were not escalated.




24



PV-10 is not a generally accepted accounting principal (“GAAP”) financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our financial statements.  The PV-10 of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a comparable basis.


Reserve Estimation


All of our estimated proved reserves of 428,067 BOE for the twelve months ended February 28, 2018 were derived from engineering reports prepared by PGH Petroleum and Environmental Engineers, LLC (“PGH”) of Austin, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.


PGH is an independent petroleum engineering consulting firm registered in the State of Texas, and Frank J. Muser, a Petroleum Engineer, is the technical person at PGH primarily responsible for evaluating the proved reserves covered by their report.  Mr. Muser graduated from the University of Texas at Austin with a Bachelor of Science degree in Chemical Engineering.  He is a licensed Professional Engineer in the states of Texas, Alabama, Kansas, North Dakota and West Virginia and has been employed by PGH as a staff engineer since 2012.  Mr. Muser has over 20 years of extensive crude oil and natural gas experience working in both private industry and for the State of Texas.  The services provided by PGH are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties.  For more information about the evaluations performed by PGH, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K.


Our internal controls over the reserve reporting process are designed to result in accurate and reliable estimates in compliance with applicable regulations and guidance.  Internal reserve preparation is performed by Bobby Ray Greer, Director of Field Operations.  Mr. Greer is a 1984 graduate of University of Southern Mississippi in Hattiesburg, Mississippi with a Bachelor of Science Degree in Geology and is a certified Petroleum Geologist and a member, in good standing, of the American Association of Professional Geologists.  Mr. Greer has over 30 years of experience in petroleum exploration, reservoir analysis, drilling rig construction, oilfield operations and management.


Although we believe that the estimates of reserves prepared by Mr. Greer have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage an independent petroleum engineering consultant to prepare an annual evaluation of our estimated proved reserves.  We provide to PGH for their analysis all pertinent data needed to properly evaluate our reserves.  We consult regularly with PGH during the reserve estimation process to review properties, assumptions, and any new data available.  Additionally, the Company’s senior management reviewed and approved all Daybreak reserve report information contained in this Annual Report on Form 10-K.


Under current SEC standards, proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  The term “reasonable certainty” implies a high degree of confidence that the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate.  Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.  Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.


In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability.  The technical data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.  Generally, crude oil and natural gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations.  Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships.  Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technical data to assess the reservoir continuity.  In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities.  Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data.  When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of crude oil derived through volumetric calculations.




25



The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment.  The estimates of reserves and future cash flows are based on various assumptions and are inherently imprecise.  Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable crude oil reserves may vary substantially from these estimates.  Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the crude oil and natural gas industry in general are subject.


Delivery Commitments


As of February 28, 2018, we had no commitments to provide any fixed or determinable quantities of crude oil or natural gas in the near future under contracts or agreements.


Summary Operating Data


The following table sets forth our net share of annual production in each project for the periods shown.  One barrel of crude oil equivalent (“BOE”) is roughly equivalent to 6,000 cubic feet or 6 Mcf of gas.


On October 31, 2016, we sold our non-operated working interest in crude oil and natural gas properties located in the Twin Bottoms Field in Lawrence County, Kentucky.  As of February 28, 2018, our total reserves were comprised of our working interest in East Slopes Project located in Kern County, California.


 

 

For the Twelve Months Ended February 28/29,

 

 

2018

 

2017

 

2016

Crude Oil and Natural Gas Production Data:

 

 

 

 

 

 

Kentucky crude oil

 

-

 

5,842

 

14,673

Kentucky natural gas (Mcf)

 

-

 

16,678

 

28,853

Kentucky natural gas (BOE)

 

-

 

2,780

 

4,809

 

 

 

 

 

 

 

Kentucky crude oil and natural gas (BOE)

 

-

 

8,593

 

19,482

California crude oil

 

12,741

 

13,035

 

14,145

Total (BOE)

 

12,741

 

21,628

 

33,627


The following table sets forth our net share of crude oil and natural gas revenue by project area for the periods shown.


 

 

For the Twelve Months Ended February 28/29,

 

 

2018

 

2017

 

2016

Crude Oil and Gas Revenue:

 

 

 

 

 

 

 

 

 

Kentucky crude oil

 

$

-

 

$

253,539

 

$

680,869

Kentucky natural gas

 

 

-

 

 

26,491

 

 

43,457

California crude oil

 

 

628,652

 

 

482,656

 

 

529,360

Total

 

$

628,652

 

$

762,686

 

$

1,253,686


The following table sets forth the average realized sales price from each project area for the periods shown.


 

 

For the Twelve Months Ended February 28/29,

 

 

2018

 

2017

 

2016

Average Realized Price:

 

 

 

 

 

 

 

 

 

Crude oil – Kentucky (Bbl)

 

$

-

 

$

43.40

 

$

46.40

Natural gas – Kentucky (Mcf)

 

$

-

 

$

1.59

 

$

1.51

Natural gas – Kentucky (BOE)

 

$

-

 

$

9.53

 

$

9.04

 

 

 

 

 

 

 

 

 

 

Kentucky Aggregate (BOE)

 

$

-

 

$

32.48

 

$

37.18

Crude oil – California (Bbl)

 

$

49.34

 

$

37.03

 

$

37.43

Average realized price (BOE)

 

$

49.34

 

$

35.22

 

$

37.28


The following table sets forth the average production expense (BOE) for the periods shown.


 

 

For the Twelve Months Ended February 28/29,

 

 

2018

 

2017

 

2016

Average Production Expense (BOE):

 

 

 

 

 

 

 

 

 

Kentucky (BOE)

 

$

-

 

$

6.71

 

$

5.52

California

 

$

13.35

 

$

12.55

 

$

11.37

Average production cost (BOE)

 

$

13.35

 

$

10.23

 

$

7.98




26



Gross and Net Acreage


The following table sets forth our interests in developed and undeveloped crude oil lease acreage in California and our undeveloped crude oil lease acreage in Michigan held by us as of February 28, 2018.  These ownership interests generally take the form of working interests in crude oil leases that have varying terms.  Developed acreage includes leased acreage that is allocated or assignable to producing wells.  Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, regardless of whether or not the acreage contains proved reserves.  Gross acres represents the total number of acres in which we have an interest.  Net acres represents the sum of our fractional working interests owned in the gross acres.


 

 

Developed

 

Undeveloped

 

Total

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

California

 

800

 

292

 

4,261

 

1,575

 

5,061

 

1,867

Michigan

 

-

 

-

 

1,400

 

420

 

1,400

 

420

Total Acreage

 

800

 

292

 

5,661

 

1,995

 

6,461

 

2,287

Average working interest

 

 

 

36.5%

 

 

 

35.2%

 

 

 

35.4%


Undeveloped Acreage Expirations


The following table sets forth expiration dates of our gross and net undeveloped acres from continuing operations in California for the years shown.


 

 

Twelve Months Ended

February 28, 2019

 

Twelve Months Ended

February 29, 2020

 

Twelve Months Ended

February 28, 2021

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

California

 

-

 

-

 

-

 

-

 

-

 

-

Michigan

 

366

 

110

 

-

 

-

 

248

 

74

Total Acreage

 

366

 

110

 

-

 

-

 

248

 

74

Average working interest

 

 

 

30.0%

 

 

 

-

 

 

 

30.0%


In all cases the drilling of a commercial crude oil or natural gas well will hold acreage beyond the lease expiration date.  In the past we have been able to, and expect in the future to be able to extend the lease terms of some of these leases.  The expirations included in the table above do not take into account the fact that we may be able to extend the lease terms.  We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel.  However, based on our evaluation of prospective economics, we have allowed acreage to expire from time to time and we expect to allow additional acreage to expire in the future.  In California, we have previously determined that there is no likely benefit to pursuing any drilling opportunities on the majority of the expiring leases, so the expiration of these leases is expected to be immaterial to our operations.  Further, none of our proved undeveloped reserves have been assigned to locations that are scheduled to be drilled after the expiration of the current leases.  In California, all of our proved undeveloped reserves are assigned to leases that are currently held by production (“HBP”).


Producing Wells


The following table sets forth our gross and net productive crude oil wells from continuing operations in California as of February 28, 2018.  Productive wells are producing wells and wells capable of production.  Gross wells represent the total number of wells in which we have an interest.  Net wells represent the sum of our fractional working interests owned in the gross wells.


Property Location

 

Gross

 

Net

California

 

20

 

7.3

Average working interest

 

 

 

36.5%




27



Drilling Activity


The following table sets forth our exploratory and development well drilling activity from continuing operations in California for the periods shown.



 

 

Twelve Months Ended

 

Twelve Months Ended

 

Twelve Months Ended

 

 

February 28, 2018

 

February 28, 2017

 

February 29, 2016

Property Location

 

Productive

 

Dry

 

Productive

 

Dry

 

Productive

 

Dry

California

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory

 

-

 

-

 

-

 

-

 

-

 

-

Developmental

 

-

 

-

 

-

 

-

 

-

 

-

Total

 

-

 

-

 

-

 

-

 

-

 

-





28




ITEM 3.   LEGAL PROCEEDINGS


Neither the Company, nor any of our officers or directors is a party to any material legal proceeding or litigation, and such persons know of no material legal proceeding or contemplated or threatened litigation.  There are no judgments against us or our officers or directors.  None of our officers or directors has been convicted of a felony or misdemeanor relating to securities or performance in corporate office.



ITEM 4.   MINE SAFETY DISCLOSURES


Not applicable.






29



PART II


ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES


Our Common Stock is quoted on the OTC Pink marketplace under the symbol “DBRM”.  Prior to May 1, 2016, our stock had traded on the OTCQB Venture Marketplace.  Our transition to the OTC Pink marketplace resulted from a cost-savings program for the company and related to listing fees on the Venture Marketplace.


The following table sets forth the high and low closing sales prices for our Common Stock for the two most recent twelve month periods shown.  The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.  The information is derived from information received from online stock quotation services.


 

 

Twelve Months Ended

February 28, 2018

 

Twelve Months Ended

February 28, 2017

 

 

High

 

Low

 

High

 

Low

First Quarter

 

0.04

 

0.01

 

0.03

 

0.01

Second Quarter

 

0.04

 

0.02

 

0.03

 

0.01

Third Quarter

 

0.03

 

0.01

 

0.03

 

0.01

Fourth Quarter

 

0.02

 

0.01

 

0.04

 

0.02


We feel the decline in the trading price of our stock can be directly linked to the similar dramatic decline in crude oil and natural gas prices since June of 2014.


As of May 24, 2018, the Company had 1,847 shareholders of record of its Common Stock.  This number does not include an indeterminate number of shareholders whose shares are held by brokers in street name.


Transfer Agent


The transfer agent for our Common Stock is Computershare Trust Company, N.A., P.O. Box 30170 College Station, TX  77842-3170.  Their website address is: www.computershare.com.


Dividend Policy


The Company has not declared or paid cash dividends or made any distributions since its inception in 1955.  Furthermore, the Company does not anticipate that it will pay cash dividends or make any cash distributions in the foreseeable future.


Sales of Unregistered Securities


Series A Convertible Preferred Stock Conversions


Daybreak Series A Convertible Preferred Stock (“Series A Preferred”) was issued to 100 accredited investors pursuant to the terms of a Daybreak private placement offering held in July 2006.  For the year ended February 28, 2018, there was one conversion of Series A Preferred stock to Common Stock.  In this conversion, 14,997 shares of Series A Preferred were converted to 44,991 shares of the Company’s Common Stock.  The terms of the Series A Preferred are disclosed in the Company’s Amended and Restated Articles of Incorporation.  The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s Common Stock.  Conversion of Series A Preferred to the Company’s Common Stock by the accredited investors relies upon an exemption from registration provided by Section 3(a)(9) of the Securities Act of 1933 relating to securities exchanged by the issuer with its existing security holders exclusively where no commission or other remuneration is paid or given directly or indirectly for soliciting such exchange.




30



As of February 28, 2018, 44 accredited investors have converted 690,197 Series A Preferred shares into 2,070,591 shares of Daybreak Common Stock.  Conversions of the Series A Preferred that have occurred since being issued in July 2006 are set forth in the table below.


Fiscal Period

 

Shares of Series A

Preferred Converted

to Common Stock

 

Shares of

Common Stock

Issued from

Conversion

 

Number of

Accredited

Investors

Year Ended February 29, 2008

 

102,300

 

306,900

 

10

Year Ended February 28, 2009

 

237,000

 

711,000

 

12

Year Ended February 28, 2010

 

51,900

 

155,700

 

4

Year Ended February 28, 2011

 

102,000

 

306,000

 

4

Year Ended February 29, 2012

 

-

 

-

 

-

Year Ended February 28, 2013

 

18,000

 

54,000

 

2

Year Ended February 28, 2014

 

151,000

 

453,000

 

9

Year Ended February 28, 2015

 

3,000

 

9,000

 

1

Year Ended February 29, 2016

 

10,000

 

30,000

 

1

Year Ended February 28, 2017

 

-

 

-

 

-

Year Ended February 28, 2018

 

14,997

 

44,991

 

1

Totals

 

690,197

 

2,070,591

 

44


Common Stock Issuances


During the twelve months ended February 28, 2018, there were 44,991 shares of the Company’s Common Stock issued as a result of the conversion of 14,997 of the Company’s Series A Preferred Convertible Stock.  For the twelve months ended February 28, 2017, there were no issuances of the Company’s Common Stock.


Securities Authorized for Issuance under Equity Compensation Plan


The table below sets forth information regarding outstanding restricted stock awards for the twelve months ended February 28, 2017.  All shares awarded under the 2009 Restricted Stock and Restricted Stock Plan (“2009 Plan”) have either fully vested or been returned to the 2009 Plan for future awards.  The Company has not awarded any restricted stock units.  The Company has no qualified or nonqualified stock option plans and has no outstanding stock options.


Equity Compensation Plan Information


Plan Category

 

Number of securities to

be issued upon exercise

of outstanding options,

warrants and rights

 

Weighted-average

exercise price of

outstanding

options, warrants

and rights

 

Number of securities

remaining available for

future issuance under equity

compensation plans

Equity compensation plans approved by security holders

 

-

 

-

 

- 

Equity compensation plans not approved by security holders(1)

 

-

 

-

 

1,013,780(2)

Total

 

-

 

-

 

1,013,780(2)


(1)

On April 6, 2009, the Board of Directors approved the 2009 Restricted Stock and Restricted Stock Unit Plan, as described in detail under Item 11. Executive Compensation – Equity Compensation Plan Information.

(2)

Reflects the initial 4,000,000 shares in the 2009 Plan, reduced by (i) 900,000 shares of restricted stock awarded to the Company’s non-employee directors in recognition of their leadership and contribution during the restructuring and transformation of the Company during the twelve months ended February 28, 2009, (ii) 1,000,000 shares of restricted stock awarded to our current President and Chief Executive Officer and our former interim President and Chief Executive Officer in recognition of past service as executive officers (iii) 425,000 and 625,000 shares of restricted stock awarded to employees during the twelve months ended February 28, 2011 and 2010 respectively; and (iv) 25,000 shares of restricted stock awarded to non-employee directors in accordance with the director compensation policy for the twelve months ended February 28, 2011 and 2010 respectively, as described in detail under Item 11 – Executive Compensation, subheading “Director Compensation”.  Also reflects 2,040 shares that were returned to the 2009 Plan during the year ended February 28, 2015, 4,080 shares that were returned to the 2009 Plan during the year ended February 28, 2014, and 3,830 shares that were returned to the 2009 Plan during each year ended February 28, 2013 and February 29, 2012, respectively.




31



2009 Restricted Stock and Restricted Stock Unit Plan


On April 6, 2009, the Board of Directors approved the 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”), allowing the executive officers, directors, consultants and employees of the Company and its affiliates (“Plan Participants”) to be eligible to receive restricted stock and restricted stock units awards, as a means of providing Plan Participants with a continuing proprietary interest in the Company.  There are no predeterminations established for restricted stock or restricted stock units to be awarded to our named executive officers or employees.


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.


Under the 2009 Plan, we may grant up to 4,000,000 shares.  The Board delegated the administration of the 2009 Plan to the Compensation Committee.  The Compensation Committee has the power and authority to select Plan Participants and grant awards of restricted stock and restricted stock units (“Awards”) to such Plan Participants pursuant to the terms of the 2009 Plan.  Awards may be in the form of actual shares of restricted Common Stock or hypothetical restricted Common Stock Units having a value equal to the fair market value of an identical number of shares of Common Stock.  Unless otherwise provided by the Compensation Committee in an individual Award agreement, Awards under the 2009 Plan vest 25% on each of the first four anniversaries of the date of grant and the unvested portion of any Award will terminate and be forfeited upon termination of the Plan Participant’s employment or service.  To date, the Compensation Committee has approved a vesting period of three years (vesting 331/3% per year), as opposed to a four-year vesting period, for Awards granted to non-employee directors.


Subject to the terms of the 2009 Plan and the applicable Award agreement, the recipients of restricted stock generally will have the rights and privileges of a shareholder with respect to the restricted stock, including the right to vote the shares and to receive dividends, if applicable.  The recipients of restricted stock units will not have the rights and privileges of a shareholder with respect to the shares underlying the restricted stock unit award until the award vests and the shares are received.  The Compensation Committee may, at its discretion, withhold dividends attributed to any particular share of restricted stock, and any dividends so withheld will be distributed to the Plan Participant upon the release of restrictions on such shares in cash, or at the sole discretion of the Compensation Committee, in shares of Common Stock having a fair market value equal to the amount of such dividends.  Awards under the 2009 Plan may not be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by a Plan Participant other than by will or by the laws of descent and distribution.


Change in Control


Unless otherwise provided in an Award agreement, in the event of a Change in Control (as defined in the 2009 Plan) of the Company, the Compensation Committee may provide that the restrictions pertaining to all or any portion of a particular outstanding Award will expire at a time prior to the change in control.  To the extent practicable, any actions taken by the Compensation Committee to accelerate vesting will occur in a manner and at a time that will allow affected Plan Participants to participate in the change in control transaction with respect to the Common Stock subject to their Awards.


Amendment and Termination


The Board at any time, and from time to time, may amend or terminate the 2009 Plan; provided, however, that such amendment or termination shall not be effective unless approved by the Company’s shareholders to the extent shareholder approval is necessary to comply with any applicable tax or regulatory requirements.  In addition, any such amendment or termination that would materially and adversely affect the rights of any Plan Participant shall not to that extent be effective without the consent of the affected Plan Participant.  The Compensation Committee at any time, and from time to time, may amend the terms of any one or more Awards; provided, however, that the Compensation Committee may not effect any amendment that would materially and adversely affect the rights of any Plan Participant under any Award without the consent of such Plan Participant.




32



At February 28, 2018, a total of 3,000,000 shares of restricted stock had been awarded and 2,986,220 of those were fully vested and remained outstanding under the 2009 Plan.  A total of 1,013,780 common stock shares remained available at February 28, 2018 for issuance pursuant to the 2009 Plan.  For the twelve months ended February 28, 2018 and 2017, there were no shares that vested since all issued shares were fully vested as of August 31, 2014.  A summary of the 2009 Plan issuances is set forth in the table below:


Grant

Date

 

Shares

Awarded

 

Vesting

Period

 

Shares

Vested(1)

 

Shares

Returned(2)

 

Shares

Outstanding

(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(3)

 

5,870

 

-

7/22/2010

 

25,000

 

3 Years

 

25,000(4)

 

-

 

-

7/22/2010

 

425,000

 

4 Years

 

417,090(5)

 

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.

(3)

In accordance with the award, on July 16, 2013, 156,250 shares were vested with 2,040 shares being returned to the 2009 Plan.

(4)

In accordance with the award, on July 22, 2013, 8,335 shares were vested.

(5)

In accordance with the award, on of July 22, 2014, 106,250 shares were vested, with 2,040 shares being returned to the 2009 Plan.


For the twelve months ended February 28, 2018 and 2017, the Company did not recognize any stock compensation expense related to the above restricted stock grants since the stock awards were fully amortized as of August 31, 2014.


Preferred Stock


The Company is authorized to issue up to 10,000,000 shares of Preferred Stock with a par value of $0.001.  Our Preferred Stock may be entitled to preference over the Common Stock with respect to the distribution of assets of the Company in the event of liquidation, dissolution, or winding-up of the Company, whether voluntarily or involuntarily, or in the event of any other distribution of assets of the Company among its shareholders for the purpose of winding-up its affairs.  The authorized but unissued shares of Preferred Stock may be divided into and issued in designated series from time to time by one or more resolutions adopted by the Board of Directors.  The directors in their sole discretion shall have the power to determine the relative powers, preferences, and rights of each series of Preferred Stock.


Series A Convertible Preferred Stock


The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as Series A Convertible Preferred Stock (“Series A Preferred”), with a $0.001 par value.  In July 2006, we completed a private placement of the Series A Preferred that resulted in the issuance of 1,399,765 Series A Preferred shares to 100 accredited investors.


The following is a summary of the rights and preferences of the Series A Preferred.


Voluntary Conversion:


The Series A Preferred that is currently issued and outstanding is eligible to be converted by the shareholder at any time into three shares of the Company’s Common Stock.  During the year ended February 28, 2018, one conversion of 14,997 shares of Series A Preferred occurred resulting in 44,991 shares of our Common Stock being issued.  There were no conversions of Series A Preferred during the twelve months ended February 28, 2017.




33



At February 28, 2018, there were 709,568 shares issued and outstanding that had not been converted into our Common Stock.  As of February 28, 2018, there were 44 accredited investors who had converted 690,197 Series A Preferred shares into 2,070,591 shares of Daybreak Common Stock.  The conversions of Series A Preferred that have occurred since the Series A Preferred was first issued in July 2006 are set forth in the table below.


Fiscal Period

 

Shares of Series A

Preferred Converted

to Common Stock

 

Shares of

Common Stock

Issued from

Conversion

 

Number of

Accredited

Investors

Year Ended February 29, 2008

 

102,300

 

306,900

 

10

Year Ended February 28, 2009

 

237,000

 

711,000

 

12

Year Ended February 28, 2010

 

51,900

 

155,700

 

4

Year Ended February 28, 2011

 

102,000

 

306,000

 

4

Year Ended February 29, 2012

 

-

 

-

 

-

Year Ended February 28, 2013

 

18,000

 

54,000

 

2

Year Ended February 28, 2014

 

151,000

 

453,000

 

9

Year Ended February 28, 2015

 

3,000

 

9,000

 

1

Year Ended February 29, 2016

 

10,000

 

30,000

 

1

Year Ended February 28, 2017

 

-

 

-

 

-

Year Ended February 28, 2018

 

14,997

 

44,991

 

1

Totals

 

690,197

 

2,070,591

 

44


Automatic Conversion:


The Series A Preferred shall be automatically converted into Common Stock if the Common Stock into which the Series A Preferred are convertible is registered with the SEC and at any time after the effective date of the registration statement the Company’s Common Stock closes at or above $3.00 per share for 20 out of 30 trading days.


Dividend:


Holders of Series A Preferred shall be paid dividends, in the amount of 6% of the original purchase price per annum. Dividends may be paid in cash or Common Stock at the discretion of the Company.  Dividends are cumulative from the date of the final closing of the private placement, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.  Accumulations of dividends on shares of Series A Preferred do not bear interest.  Dividends are payable upon declaration by the Board of Directors.  There have been no cash or common stock dividends declared by the Board of Directors to date.


Cumulative dividends earned for each twelve month period since issuance are set forth in the table below:


Fiscal Year Ended

 

Shareholders at

Period End

 

Accumulated

Dividends

February 28, 2007

 

100

 

$

155,311

February 29, 2008

 

90

 

 

242,126

February 28, 2009

 

78

 

 

209,973

February 28, 2010

 

74

 

 

189,973

February 28, 2011

 

70

 

 

173,707

February 29, 2012

 

70

 

 

163,624

February 28, 2013

 

68

 

 

161,906

February 28, 2014

 

59

 

 

151,323

February 28, 2015

 

58

 

 

132,634

February 29, 2016

 

57

 

 

130,925

February 28, 2017

 

57

 

 

130,415

February 28, 2018

 

56

 

 

128,231

 

 

 

 

$

1,970,148


Liquidation Preference:


In the event of any liquidation, dissolution or winding up of the Company, either voluntary or involuntary, the holders of the Series A Preferred shall be entitled to receive, prior and in preference to any distribution of any of the assets or surplus funds of the Company to the holders of Common Stock by reason of their ownership thereof, and subject to the rights of any series of preferred stock that may rank on liquidation prior to the Series A Preferred, an amount equal to all accrued or declared but unpaid dividends on such shares, for each share of Series A Preferred then held by them.  The remaining assets shall be distributed ratably to the holders of Common Stock and Series A Preferred on a common equivalent basis.  Certain other events, as described in our Amended and Restated Articles of Incorporation, including a



34



consolidation or merger of the Company or the disposition of the Company’s assets, may trigger the payment of the liquidation preference to the holders of Series A Preferred.


Voting Rights:


The holders of the Series A Preferred will vote together with the Common Stock and not as a separate class except as specifically provided or as otherwise required by law.  Each share of the Series A Preferred shall have a number of votes equal to the number of shares of Common Stock then issuable upon conversion of such shares of Series A Preferred.


Common Stock


The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock of which 51,532,365 and 51,487,373 shares were issued and outstanding as of February 28, 2018 and February 28, 2017, respectively.


 

Common Stock

Balance

 

Par Value

Common stock, Issued and Outstanding, February 29, 2016

51,487,373 

 

 

 

Conversion of Series A Convertible Preferred Stock to common stock

 

$

Common stock, Issued and Outstanding, February 28, 2017

51,487,373 

 

 

 

Share issuances during the current year

44,991 

 

$

45

Common stock, Issued and Outstanding, February 28, 2018

51,532,364 

 

 

 


During the year ended February 28, 2018, one conversion of 14,997 shares of Series A Preferred occurred resulting in 44,991 shares of our Common Stock being issued.


All shares of Common Stock are equal to each other with respect to voting, liquidation, dividend and other rights.  Owners of shares of Common Stock are entitled to one vote for each share of Common Stock owned at any shareholders’ meeting.  Holders of shares of Common Stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefore; and upon liquidation, are entitled to participate pro rata in a distribution of assets available for such a distribution to shareholders.


There are no conversion, preemptive, or other subscription rights or privileges with respect to any shares of our Common Stock.  Our stock does not have cumulative voting rights, which means that the holders of more than 50% of the shares voting in an election of directors may elect all of the directors if they choose to do so.  In such event, the holders of the remaining shares aggregating less than 50% would not be able to elect any directors.


Warrants


12% Subordinated Notes – Warrant Expiration Extension


Effective January 29, 2017, the expiration date of the warrants that were issued in conjunction with the 12% Subordinated Notes from a January 2010 private placement offering to accredited investors was extended for an additional two years to January 29, 2019.  The exercise price of the warrants was lowered from $0.14 to $0.07 as a part of the warrant modification.  The warrant expiration extension applied to noteholders who chose to extend the maturity date of the 12% Subordinated Notes for an additional two years to January 29, 2019, and had not already exercised the associated warrants.  Ten noteholders had the expiration date of their warrants extended to January 29, 2019.  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%.


Maximilian Credit Facility and Loan Agreement


On October 31, 2012, the Company entered into a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment from Maximilian Investors LLC (either party, as appropriate, is referred to as “Maximilian”).  In connection with this loan, the Company also issued approximately 2.4 million warrants to third parties who assisted in the closing of the loan.  There were 316,617 of these warrants that remained unexercised at February 28, 2018.




35



In connection with the Company’s acquisition of a working interest from App Energy, LLC, a Kentucky limited liability company (“App”), in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013.  As consideration for Maximilian facilitating the Company’s transactions with App, the Company issued to Maximilian approximately 6.1 million warrants to purchase shares of the Company’s common stock representing the right to purchase up to an additional 9.99% of the Company’s outstanding common stock on a fully-diluted basis, calculated as of the date of grant.


The Company also issued 309,503 warrants to third parties who assisted in the closing of the amended and restated loan agreement with Maximilian.


On May 28, 2014, at Maximilian’s request, the Company finalized a share-for-warrant exchange agreement in which Maximilian returned to the Company 427,729 common shares and was in turn issued the same number of warrants containing the same provisions as the originally issued warrants.


On May 20, 2015, the Company entered into a Second Amendment to Amended and Restated Loan and Security Agreement (the “Second Amendment”) with Maximilian.  As consideration for entering into the Second Amendment, the Company agreed to modify the exercise price of the warrants Maximilian currently held from $0.10 to $0.04.  No other terms of the warrant agreement were changed.  The modification did not result to any accounting since these warrants were deemed to be investor warrants.


On October 14, 2015, the Company entered into a Third Amendment to the Amended and Restated Loan and Security Agreement and Second Warrant Amendment with Maximilian, (the “Third Amendment”).  Pursuant to the Third Amendment, Maximilian agreed to a reduction in the Company’s monthly payments under the loan agreement to $50,000 per month for a period of six months ending on February 29, 2016.  As part of the Third Amendment, the Company agreed to extend the expiration date of the approximately 6.6 million warrants held by Maximilian to August 28, 2018.  The Company determined that the accounting of the loan modification was not substantial.  Likewise, the Company determined that the modification of the warrant term did not result in any accounting since these warrants were deemed to be investor warrants.


Warrants outstanding and exercisable as of February 28, 2018 are set forth in the table below:


 

 

Warrants

 

Exercise

Price

 

Remaining

Life

(Years)

 

Exercisable

Warrants

Remaining

12% Subordinated Notes

 

980,000

 

$0.07

 

0.92

 

980,000

Warrants issued for Kentucky crude oil project

 

3,498,601

 

$0.04

 

0.50

 

3,498,601

Warrants issued for Kentucky debt financing

 

2,623,951

 

$0.04

 

0.50

 

2,623,951

Warrants issued for Kentucky debt financing

 

309,503

 

$0.214

 

0.50

 

309,503

Warrants issued in share-for-warrant exchange

 

427,729

 

$0.04

 

0.50

 

427,729

 

 

7,839,784

 

 

 

 

 

7,839,784


Warrant activity for the twelve months ended February 28, 2017 and February 28, 2018 is set forth in the table below:


 

 

Warrants

 

Weighted Average

Exercise Price

Warrants outstanding, February 29, 2016

 

8,156,401 

 

$0.06

 

 

 

 


Changes during the twelve months ended February 28, 2017:

 

 

 


Expired / Cancelled / Forfeited

 

 


Warrants outstanding, February 28, 2017

 

8,156,401 

 

$0.05

 

 

 

 


Changes during the twelve months ended February 28, 2018:

 

 

 


Expired / Cancelled / Forfeited

 

(316,617)

 


Warrants outstanding, February 28, 2018

 

7,839,784 

 

$0.05

 

 

 

 


Warrants exercisable, February 28, 2018

 

7,839,784 

 

$0.05


On January 29, 2017, the 980,000 warrants associated with the 12% Subordinated Notes were modified to extend the expiration date of the warrants to January 29, 2019.  As a part of this modification the exercise price of the 12% Note warrants was changed from $0.14 to $0.07.  No other terms of the warrants were affected by the modification.  The outstanding warrants as of February 28, 2018 and February 28, 2017 have a weighted average exercise price of $0.05; a weighted average remaining life of 0.55 and 1.52; and an intrinsic value of $-0-, respectively.




36



ITEM 6.   SELECTED FINANCIAL DATA


As a smaller reporting company, we are not required to provide the information otherwise required by this Item.





37



ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The following management’s discussion and analysis (“MD&A”) is management’s assessment of the financial condition, changes in our financial condition and our results of operations and cash flows for the twelve months ended February 28, 2018 and February 28, 2017.  This MD&A should be read in conjunction with the audited financial statements and the related notes and other information included elsewhere in this Annual Report on Form 10-K.


Safe Harbor Provision


Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations 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 facts contained in this MD&A report, including statements regarding our current expectations and projections about future results, intentions, plans and beliefs, business strategy, performance, prospects and opportunities, are inherently uncertain and are forward-looking statements.  For more information about forward-looking statements, please refer to the section labeled “Cautionary Statement About Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.


Introduction and Overview


We are an independent crude oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing crude oil and natural gas reserves through exploration and development activities, and selling the production from those reserves at a profit.  To be successful, we must, over time, be able to find crude oil and natural gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.  A secondary means of generating returns can include the sale of either producing or non-producing lease properties.


Our long-term success depends on, among many other factors, the successful acquisition and drilling of commercial grade crude oil and natural gas properties as well as the prevailing sales prices for crude oil and natural gas along with associated operating expenses.  The volatile nature of the energy markets makes it difficult to estimate future prices of crude oil and natural gas; however, any prolonged period of depressed prices, such as we are now experiencing, 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 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.  We are currently in the process of developing a multi-well oilfield projects in Kern County, California and an exploratory project in Michigan.


Our management cannot provide any assurances that Daybreak will ever operate profitably.  While we have positive cash flow from our continuing crude oil operations in California, we have not yet generated sustainable positive cash flow or earnings on a company-wide basis.  As a small company, we are more susceptible to the numerous business, investment and industry risks that have been more fully described in Item 1A. Risk Factors of this Annual Report on Form 10-K for the fiscal year ended February 28, 2018.


Throughout this Annual Report on Form 10-K, crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).


Year-to-Date Results


Below is brief summary of our crude oil and natural gas projects in California and Michigan.  On October 31, 2016, we sold our non-operated working interest in crude oil and natural gas properties located in the Twin Bottoms Field in Lawrence County, Kentucky.  Refer to our discussion in Item 2. Properties, in this Annual Report on Form 10-K for more information on our East Slopes Project in Kern County, California.





38



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.  The crude oil produced from our acreage in the Vedder Sand is considered heavy crude oil.  The produced crude oil ranges from 14° to 16° API gravity and must be heated to separate and remove water prior to sale.  During the twelve months ended February 28, 2018 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.  We have been the Operator at the East Slopes Project since March 2009.


Michigan Acreage Acquisition


Daybreak has 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 wells will be drilled vertically with conventional completions and no hydraulic fracturing will be required.  The first well is expected to be drilled during the late summer of 2018.


Results of Operations – For the years ended February 28, 2018 and February 28, 2017 – 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”) crude oil Cushing, Oklahoma delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs.  We do not have any natural gas revenues in California.


There has been a significant amount of volatility in hydrocarbon prices and dramatic decline in our realized sale price of crude oil since June of 2014, when the monthly average price of WTI oil was $105.79 per barrel.  This decline in the price of crude oil as shown below 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 twelve months ended February 28, 2018 in comparison to the twelve months ended February 28, 2017 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 if they will continue 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 twelve months ended February 28, 2018 and 2017 is shown in the table below:


 

 

Twelve Months Ended

 

 

 

 

February 28, 2018

 

February 28, 2017

 

Percentage Change

Average twelve month WTI crude oil price

 

$

52.55

 

$

46.81

 

12.3%

Average twelve month realized crude oil sales price (Bbl)

 

$

49.34

 

$

37.03

 

33.2%


For the twelve months ended February 28, 2018, the average WTI price was $52.55 and our average realized crude oil sale price was $49.34, representing a discount of $3.21 per barrel or 6.1% lower than the average WTI price.  In comparison, for the twelve months ended February 28, 2017, the average WTI price was $46.81 and our average realized sale price was $37.03 representing a discount of $9.78 per barrel or 20.9% lower than the average WTI price.  Effective June 1, 2017, we were able to negotiate with our oil purchaser the use of a more favorable oil pricing schedule that has contributed to lowering the difference between WTI price and our average realized price on oil sales.


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 WTI crude oil.  It is beyond our control and ability to accurately predict how long hydrocarbon prices will continue to decline; 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 hydrocarbon sales.







39



California Crude Oil Revenue and Production


Crude oil sales revenue in California for the twelve months ended February 28, 2018 increased $145,996 or 30.2% to $628,652 in comparison to revenue of $482,656 for the twelve months ended February 28, 2017.  The average sale price of a barrel of crude oil for the twelve months ended February 28, 2018 was $49.34 in comparison to $37.03 for the twelve months ended February 28, 2017.  The increase of $12.31 or 33.2% in the average realized price of a barrel of crude oil accounted for $100% of the increase in crude oil revenue.  Effective June 1, 2017, we were able to negotiate with our oil purchaser the use of a more favorable oil pricing schedule that has contributed significantly to increasing the average realized price we receive on oil sales.


Our net sales volume for the twelve months ended February 28, 2018 was 12,741 barrels of crude oil in comparison to 13,035 barrels sold for the twelve months ended February 28, 2017.  This decrease in oil sales volume of 294 barrels or 2.3% was primarily due to the natural decline in reservoir pressure during the twelve months ended February 28, 2018.


The gravity of our produced oil in California ranges between 14° API and 16° API.  Production for the twelve months ended February 28, 2018 was from 20 wells resulting in 7,566 well days of production in comparison to 7,187 well days of production for the twelve months ended February 28, 2017.


Our crude oil sales revenue from California is set forth in the table below:


 

 

Twelve Months Ended

February 28, 2018

 

Twelve Months Ended

February 28, 2017

Project

 

Revenue

 

Percentage

 

Revenue

 

Percentage

California – East Slopes Project

 

$

628,652

 

100.0%

 

$

482,656

 

100.0%

Total crude oil revenues*

 

$

628,652

 

100.0%

 

$

482,656

 

100.0%


*Our average realized sale price on a BOE basis for the twelve months ended February 28, 2018 was $49.34 in comparison to $37.03 for the twelve months ended February 28, 2017, representing an increase of $12.31 or 33.2% per barrel.


Of the $145,996 or 30.2% increase in revenue for twelve months ended February 28, 2018, all of the increase can be directly attributed to the increase in the realized price of crude oil.


Operating Expenses


Total operating expenses decreased approximately $8,601 or 0.6% to $1,342,847 for the twelve months ended February 28, 2018 in comparison to $1,351,448 for the twelve months ended February 28, 2017.  Our operating expenses are set forth in the table below:


 

 

Twelve Months Ended

February 28, 2018

 

Twelve Months Ended

February 28, 2017

 

 

Expenses

 

Percentage

 

BOE

Basis

 

Expenses

 

Percentage

 

BOE

Basis

Production expenses

 

$

170,966

 

12.7%

 

 

 

 

$

163,654

 

12.1%

 

 

 

Exploration and drilling expenses

 

 

107,884

 

8.0%

 

 

 

 

 

9,297

 

0.7%

 

 

 

Depreciation, Depletion, Amortization (“DD&A”)

 

 

82,707

 

6.2%

 

 

 

 

 

110,285

 

8.2%

 

 

 

General and Administrative (“G&A”) expenses

 

 

981,290

 

73.1%

 

 

 

 

 

1,068,212

 

79.0%

 

 

 

Total operating expenses

 

$

1,342,847

 

100.0%

 

$

105.39

 

$

1,351,448

 

100.0%

 

$

103.68


Production expenses include expenses associated with the production of crude oil and natural gas.  These expenses include pumper salaries, electricity, road maintenance, control of well insurance, property taxes and well maintenance and workover expenses; and, relate directly to the number of wells that are on production.  For the twelve months ended February 28, 2018, these expenses increased $7,312, or 4.5% to $170,966 in comparison to $163,654 for the twelve months ended February 28, 2017.  We had 20 wells on production in California for the twelve months ended February 28, 2018 and 2017.  Production expenses on a BOE basis in California for the twelve months ended February 28, 2018 and 2017 were $13.42 and $12.56, respectively.  Production expenses represented 12.7% and 12.1% of total operating expenses for the twelve months ended February 28, 2018 and 2017, respectively.




40



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 $98,587 to $107,884 for the twelve months ended February 28, 2018 in comparison to $9,297 for the twelve months ended February 28, 2017.  The two primary reasons for the increase was the G&G work on the new Michigan exploratory joint drilling project in the amount of $100,251 and the P&A operations on two non-producing well bores in California for $7,617, representing $107,884 in aggregate.  Exploration and drilling expenses represented 8.0% and 0.7% of total operating expenses for the twelve months ended February 28, 2018 and 2017, respectively.


Depreciation, Depletion, Amortization (“DD&A”) expense relates to equipment, proven reserves and property costs, and is another component of operating expenses.  These expenses decreased $27,578 or 25.0% to $82,707 for the twelve months ended February 28, 2018 in comparison to $110,285 for the twelve months ended February 28, 2017.  The primary reason for the decrease in DD&A was due to improved future hydrocarbon prices in our reserve report in comparison to our reserve report from the prior year.  The improved pricing increased the estimated life of our wells.  On a BOE basis, DD&A expense in California for the twelve months ended February 28, 2018 and 2017 was $6.49 and $8.46, respectively.  DD&A expenses represented 6.2% and 8.2% of total operating expenses for the twelve months ended February 28, 2018 and 2017, 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, 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 gas properties as well as for running a public company.  These expenses decreased $86,922 or 8.1% to $981,290 for the twelve months ended February 28, 2018 in comparison to $1,068,212 for the twelve months ended February 28, 2017.  The decline in G&A expenses for the current year in comparison to the prior year was due to recognition of more fundraising expense in the prior year.  For the year ended February 28, 2018, we received, as Operator of the East Slopes project in California, administrative overhead reimbursement of $53,287, 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 73.1% and 79.0% of total operating expenses for the twelve months ended February 28, 2018 and 2017, respectively.


Interest expense decreased approximately $1.3 million or 41.9% to 1,740,773 for the twelve months ended February 28, 2018 in comparison to $2,994,466 for the twelve months ended February 28, 2017.  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 credit facility balance.  Refer to the discussion below under the caption Current Debt (Short-term borrowings) in this MD&A section for more information on the Maximilian loans.


Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially quarter-to-quarter and year-to-year.  Our revenues are dependent upon both hydrocarbon production levels and the price we receive for hydrocarbon sales.  This revenue is subject to the volatility of hydrocarbon prices and the material adverse impact of lower crude oil prices on our revenues cannot be overstated.  For the twelve months ended February 28, 2018 our sales volume decreased 294 Bbls or 2.3% while our revenues increased $145,996 or 30.3% during the same time period.  Production costs will fluctuate according to the number and percentage ownership of producing wells, as well as the amount of revenues being contributed by such wells.  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, plus the size of our proven reserve 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; to fund our development drilling in California; and, future drilling programs in Michigan and other geographic locations.


Capital Resources and Liquidity


Our primary financial resource is our base of crude oil reserves.  Our ability to fund our capital expenditure program is dependent upon the prices we receive from our crude oil and natural gas sales; the success of our exploration program in Michigan; and the availability of capital resource financing.  We plan to spend approximately $10,000 in new capital investments within the East Slopes Project area in the 2018-2019 fiscal year if no new financing is in place.  If new financing is secured, we plan to drill four development wells for a total of $525,000.


Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.





41



Changes in our capital resources at February 28, 2018 are set forth in the table below:


 

February 28, 2018

 

February 28, 2017

 

Increase

(Decrease)

 

Percentage

Change

Cash

$

48,535 

 

$

42,003 

 

$

6,532 

 

15.6%

Current Assets

$

333,652 

 

$

309,308 

 

$

24,344 

 

7.9%

Total Assets

$

1,095,900 

 

$

1,263,313 

 

$

(167,413)

 

(13.3%)

Current Liabilities

$

(16,343,108)

 

$

(13,462,236)

 

$

(2,880,872)

 

21.4%

Total Liabilities

$

(16,380,282)

 

$

(14,092,781)

 

$

(2,287,501)

 

16.2%

Working Capital Deficit

$

(16,009,456)

 

$

(13,152,928)

 

$

(2,856,528)

 

21.7%


Our working capital deficit increased by approximately $2.9 million or 21.7% from a deficit of $13.1 million at February 28, 2017 to a deficit of $16.0 million at February 28, 2018.  The increase in the working capital deficit was a result of an increase in our current liabilities slightly offset by an increase in our current assets.  The approximate $2.9 million increase in current liabilities was comprised of approximately $1.3 million in accrued interest relating to the Maximilian credit facility loan as well as increase in payables and loan balances along with the reclassification of the 12% subordinated notes to current liabilities from non-current liabilities in the prior year.  The Company is currently considered to be in default under the terms of its credit facility loan.  Maximilian is currently in receivership.  The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender to assume the Maximilian credit facility.  No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company.  During the twelve months ended February 28, 2018, the Company received an aggregate of $102,700 in advances under the terms of the credit facility.  While we continue to have ongoing positive cash flow from our crude oil operations in California, we are unable to generate sufficient cash flow to cover all of our general and administrative (“G&A”) and interest expense requirements.


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.  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 will 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 may also cause us to seek additional capital from sources outside of the Company.  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 Company’s financial statements for the twelve months ended February 28, 2018 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.  As of the twelve months ended February 28, 2018, we have an accumulated deficit of $38,334,383 and a working capital deficit of $16,009,456 which raises substantial doubt about our ability to continue as a going concern.


In this 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, 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.






42



Cash Flows


Changes in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below:


 

Twelve Months

Ended

February 28, 2018

 

Twelve Months

Ended

February 28, 2017

 

Increase

(Decrease)

 

Percentage

Change

Net cash provided by (used in) operating activities

$

(120,168)

 

$

165,967 

 

$

(286,135)

 

(172.4%)

Net cash used in investing activities

$

 

$

(95,959)

 

$

95,959 

 

100.0% 

Net cash provided by (used in) financing activities

$

126,700 

 

$

(35,000)

 

$

161,700 

 

462.0% 


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 year ended February 28, 2018, cash used in our operating activities was $120,168 in comparison to cash flow provided by operating activities of $165,967 for the twelve months ended February 28, 2017.  Cash flow used in operating activities of $120,168 consisted of changes in non-cash expenses of $387,360; changes in assets of $16,515; changes in liabilities of $1,963,901 and our net loss of approximately $2.5 million.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.


Our expenditures in operating activities consist primarily of exploration and drilling expenses, production expenses, geological, geophysical and engineering services and acquisition of mineral leases.  Our expenses also consist of consulting and professional services, employee compensation, legal, accounting, travel and other G&A expenses that we have incurred in order to address normal and necessary business activities.


Cash Flow Used in Investing Activities


Cash flow from investing activities is derived from changes in oil and gas property balances and any lending activities.  We had no cash flow provided by investing activities for the twelve months ended February 28, 2018 in comparison to cash flow used in investing activities of $95,959 for the twelve months ended February 28, 2017.


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 $126,700 for the twelve months ended February 28, 2018 in comparison to cash flow used in our financing activities of $35,000 for the year ended February 28, 2017.  For the twelve months ended February 28, 2018, we received advances on our credit facility from Maximilian of $102,700 and advances from our line of credit with UBS Bank for $84,000.  These additions were offset by interest payments of $60,000 to the line of credit.  The following is a summary of the Company’s financing activities for the twelve months ended February 28, 2018.


Current debt (short-term borrowings)


Related Party


The Company has a note payable-related party loan balance of $250,100 as of February 28, 2018 and 2017.  The Company’s Chairman, President and Chief Executive Officer has loaned the Company an aggregate $250,100 that was 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.


12% Subordinated Notes


The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a January 2010 private placement, 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 12% Subordinated Notes from the January 2010 private placement offering to accredited investors were extended for an additional two years to January 29, 2019.  The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes.  Should the Board of Directors, on the maturity date, decide that the payment of the



43



principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2018.  The exercise price of the associated warrants was lowered from $0.14 to $0.07 as a part of the warrant modification.  The warrant expiration extension applied to noteholders who chose to extend the maturity date of the 12% Subordinated Notes for an additional two years and had not already exercised the associated warrants.  Ten noteholders had the expiration date of their warrants extended to January 29, 2019.


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%.  At February 28, 2018 and 2017, amortization expense was $14,538 and $1,211, respectively.  The unamortized debt discount at February 28, 2018 and 2017 was $13,326 and $27,864, respectively.


12% Note balances at February 28, 2018 and 2017 are set forth in the table below:


 

February 28, 2018

 

February 29, 2017

12% Subordinated Notes

$

315,000 

 

$

315,000 

Debt discount

 

(7,429)

 

 

(15,535)

Net 12% Subordinated Note balance

$

307,571 

 

$

299,465 


12% Note balances – related parties at February 28, 2018 and 2017 and February 29, 2016 are set forth in the table below:


 

February 28, 2018

 

February 28, 2017

12% Subordinated Notes – related party

$

250,000 

 

$

250,000 

Debt discount

 

(5,897)

 

 

(12,329)

Net 12% Subordinated Note – related party balance

$

244,103 

 

$

237,671 


In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.07 and an amended expiration date of January 29, 2019.  The 12% Note warrants that have been exercised are set forth in the table below.  At February 28, 2018, there were 980,000 warrants that were not exercised and had not expired.


Fiscal Period

 

Warrants

Exercised

 

Shares of

Common Stock

Issued

 

Number of

Accredited

Investors

Year Ended February 28, 2014

 

100,000

 

100,000

 

1

Year Ended February 28, 2015

 

50,000

 

50,000

 

1

Year Ended February 29, 2016

 

-

 

-

 

-

Year Ended February 29, 2017

 

-

 

-

 

-

Year Ended February 28, 2018

 

-

 

-

 

-

Totals

 

150,000

 

150,000

 

2


Maximilian Credit Facility and Loan Agreement


On October 31, 2012, the Company entered into a loan agreement with Maximilian which provided for a revolving credit facility of up to $20 million, maturing on October 31, 2016, with a minimum commitment of $2.5 million.  The Company also granted Maximilian a 10% working interest in its share of the oil and gas leases in Kern County, California which was recognized as a discount to debt.  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.  The debt discount associated with the Maximilian credit facility was fully amortized at February 28, 2017.


Maximilian Loan - Amended and Restated Loan Agreement


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%.  Effective October 31, 2016, we sold our non-operated working interest in crude oil and natural gas properties located in the Twin Bottoms Field in Lawrence County, Kentucky.




44



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: (1) the deemed payment in full and/or forgiveness of approximately $8.3 million in outstanding indebtedness under the Daybreak Loan Agreement (which includes approximately $5.4 million in indebtedness that was loaned by the Company to App Energy pursuant to the Loan and Security Agreement between the parties dated as of August 28, 2013, as amended from time to time); (2) a commitment by Maximilian to forgive an additional amount of indebtedness under the Daybreak Loan Agreement, currently estimated to be $3.2 million, in the event of the future issuance of senior preferred stock by the Company to it; (3) the deemed payment in full and termination of the App Loan Agreement; (4) the termination and release of all liens, security interests and other interests held by Maximilian or its affiliates in any of the Company’s or App Energy’s Kentucky oil and natural gas assets, including the termination of the overriding royalty interests and net profits interests held by Maximilian and/or its affiliates; (5) amendments to the Daybreak Loan Agreement to suspend principal and interest payments for up to six months and extend the maturity date to February 28, 2020; (6) a commitment by Maximilian to advance up to $250,000 in financing to the Company over the next six months; (7) the pursuit of the Michigan Joint Venture 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.


As a result of the decline in hydrocarbon prices, we have been unable to make the interest or principal payments required under the terms of our credit facility with our lender, 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 February 28, 2018 and 2017 was $1,812,128 and $440,389, respectively.  The Company is currently considered to be in default under the terms of its credit facility loan.  Maximilian is currently in receivership.  The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender to assume the Maximilian credit facility.  No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company.  During the twelve months ended February 28, 2018, the Company received an aggregate of $102,700 in advances under the terms of the credit facility.  In accordance with guidance from ASC 470-10-45, since we have been unable to make the above referenced payments the entire balance of the Maximilian credit facility is presented under the current liabilities section of the financial statements.


During the twelve months ended February 28, 2018 and 2017, the Company received an aggregate of $102,700 and $25,000 in advances under the terms of the credit facility, respectively.


Maximilian Loan Agreement – Michigan Project


As of February 28, 2018, 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 oilfield project in Michigan.  Advances under this agreement are subject to a 5% (five percent) per annum interest rate.  If a well that the Company elects to participate in is scheduled to be spudded at the Michigan oilfield 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 oilfield project or (b) December 31, 2017.  If there is not a well scheduled to be spudded at the Michigan oilfield project on or before December 31, 2017 that the Company elects to participate in, then the Company will assign to Maximilian its working interest in the Michigan oilfield project, in full payment and satisfaction of the advances under the promissory note.  Advances under the promissory note may be prepaid at any time without penalty, and are secured by a mortgage on the Company’s working interest in the Michigan oilfield project.  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.  Due to a lack of funding from Maximilian, we were unable to spud a well on the Michigan project by December 31, 2017.  The Company is currently considered to be in default under the terms of its loan agreement.  Maximilian is currently in receivership.  The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender.  No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company.  Accrued interest on the Michigan promissory note at February 28, 2018 and 2017 was $5,158 and $456, respectively.  During the twelve months ended February 28, 2018, an aggregate amount of $10,650 was paid directly to the Operator of the Michigan project by Maximilian on the Company’s behalf.





45



Current debt balances at February 28, 2018 and 2017 are set forth in the table below:


 

February 28, 2018

 

February 28, 2017

Principal 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 project debt

 

94,650

 

 

84,000 

Net debt

$

9,157,794

 

$

8,805,846 


In accordance with the guidance found in ASC-470-10-45, the entire balance of the Maximilian credit facility and Michigan 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 twelve months ended February 28, 2018.


Deferred financing costs at February 28, 2018 and 2017 relating to the original and the amended credit facility with Maximilian, are set forth in the table below:


 

February 28, 2018

 

February 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 

Subtotal – deferred financing costs

 

1,762,630 

 

 

1,762,630 

Accumulated amortization

 

(1,762,630)

 

 

(1,524,032)

Remaining balance – deferred financing costs

$

 

$

238,598 


Deferred financing cost balances were $-0- and $238,598 at February 28, 2018 and 2017, respectively; and, include 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 $423,331 for the twelve months ended February 28, 2018 and 2017, respectively.  Accrued interest on both the Maximilian credit facility loan and the Michigan loan at February 28, 2018 and 2017, respectively was $1,817,286 and $440,845, respectively.


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.  On July 10, 2017 a $700,000 portion of the outstanding credit line balance 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.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.  Interest was $31,728 and $33,815 for the twelve months ended February 28, 2018 and 2017, respectively.  At February 28, 2018 and 2017, the line of credit had an outstanding balance of $873, 350 and $817,622, respectively.


Capital Commitments


Daybreak has ongoing capital commitments to develop certain oil and gas leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company.  The current uncertainty in the credit and capital markets, and the economic downturn, may restrict our ability to obtain needed capital.


Encumbrances


The Company’s debt obligations, pursuant to the loan agreement and promissory notes entered into by and among 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 lease in Michigan.  For further information on the loan agreement with Maximilian refer to the discussion above under the caption above “Current debt (short-term borrowings)” in this MD&A.




46



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 stock and restricted stock unit awards.  Subject to adjustment, the total number of shares of Daybreak’s 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 February 28, 2018, a total of 3,000,000 shares of restricted common stock had been awarded and 2,986,220 shares of the 2009 Plan had fully vested.  A total of 1,013,780 common stock shares remained available for issuance pursuant to the 2009 Plan at February 28, 2017.  For the twelve months ended February 28, 2017 and February 29, 2016, there were no shares that vested since all issued shares were fully vested.  A summary of the 2009 Plan issuances is set forth in the table below:


Grant

Date

 

Shares

Awarded

 

Vesting

Period

 

Shares

Vested(1)

 

Shares

Returned(2)

 

Shares

Outstanding

(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 the number of common 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 twelve months ended February 28, 2018 and 2017, the Company did not recognize any stock compensation expense related to the above restricted stock grants since the stock awards were fully amortized as of August 31, 2014.


Crude Oil and Natural Gas Reserves


Daybreak’s total net proved developed and undeveloped crude oil and natural gas reserves on a per barrel of oil equivalent (“BOE”) basis increased by 46,997 BOE, or 12.3%, to 428,067 BOE at February 28, 2018 compared to 381,070 BOE at February 28, 2017.  These reserves are all located in our California East Slopes project.  The primary reason for the increase of both our proven developed (“PDP”) and proven undeveloped reserves (“PUD”) was an improvement in the price of crude oil, thereby extending the life of our potential reserves.  The year-to-year reserve increase consisted of a 22,488 barrel or 9.8% increase in our PDP reserves and a 37,258 barrel or 13.2% increase in our PUD reserves.  Included in the PUD reserve increase was 35,099 barrels of revisions and 24,639 barrels of reserve extensions.  Our production for the year ended February 28, 2018 was 12,741 BOE.  Our reserves were fully engineered by PGH Petroleum and Environmental Engineers, LLC of Austin, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.  For further information on our reserve report, refer to exhibit 99.1 of this Annual Report on Form 10-K.


Changes in Financial Condition


During the year ended February 28, 2018, we received crude oil sales revenue from 20 wells in our East Slopes Project in Kern County, California.  Our commitment to improving corporate profitability remains unchanged.  Since June 2014, there has been significant volatility and uncertainty in the WTI price of crude oil and correspondently in the realized price we receive from oil sales.  This volatility in the price of crude oil has had a substantial impact on the cash flow of our producing crude oil properties in California.  During the twelve months ended February 28, 2018 and 2017, crude oil revenue from California were $628,652 and $482,656, respectively.  All of the current year increase in revenue can be attributed to an improvement in our realized crude oil sales revenue.  For the twelve months ended February 28, 2018 and 2017, we had an operating loss of $714,195 and $868,792, respectively.




47



Our balance sheet at February 28, 2018 reflects total assets of approximately $1.1 million, a decrease of approximately $167,000 in comparison to approximately $1.3 million at February 28, 2017.  This decrease of approximately in total assets was primarily due to a decline in valuation of our proved and unproved crude oil properties in California and Michigan.


At February 28, 2017, total liabilities were approximately $16.4 million, an increase of approximately $2.3 million in comparison to approximately $14.1 million at February 28, 2017.  This increase was primarily due to accrued interest and advances related to the Maximilian credit facility and increases in our payables balances.


There was an increase in our Common Stock of 44,991 shares, bringing our February 28, 2018 balance to 51,532,364 shares issued and outstanding.  The increase was due to a conversion of 14,997 shares of Series A preferred into 44,991 shares of Common Stock.


Accumulated Deficit


Our financial statements for the year ended February 28, 2018 and 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.  Our financial statements show that the Company has incurred significant operating losses that raise substantial doubt about our ability to continue as a going concern.  The accompanying financial statements do not include any adjustments that might result from this uncertainty.


The increase in the accumulated deficit from approximately $35.9 million as of February 28, 2017 to $38.3 million as of February 28, 2018 was due to the approximate $2.5 million net loss for the year.  This compares to an approximate net loss of $3.5 million for the twelve months ended February 28, 2017.  


Cash Balance


We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations, investments and capital resource funding.  Our cash balances were $48,535 and $42,003 at February 28, 2018 and 2017, respectively.


Crude oil and natural gas revenues


Crude oil revenues increased 145,996 or 30.2% to $628,652 for the twelve months ended February 28, 2018 in comparison to $482,656 for the twelve months ended February 28, 2017.  All of the increase in revenue can be attributed to an increase in our realized crude oil price for the twelve months ended February 28, 2018.


Operating Expenses


Operating expenses for the twelve months ended February 28, 2018 decreased by approximately $8,600 or 0.6% to approximately $1.3 million.  


Operating Loss


For the year ended February 28, 2018, we reported an operating loss of $714,195 in comparison to an operating loss of $868,792 for the twelve months ended February 28, 2017.  This decrease in operating loss of $154,597 was primarily due to the increase in revenue in G&A expenses for the twelve months ended February 28, 2018.


Net Loss


Since entering the crude oil and natural gas exploration industry, we have incurred net losses with periodic negative cash flow and have depended on external financing and the sale of crude oil and natural gas assets to sustain our operations.  A net loss of approximately $2.5 million was reported for the twelve months ended February 28, 2018 in comparison to a net loss of $3.5 million for the twelve months ended February 28, 2017.


Management Plans to Continue as a Going Concern


We continue to implement plans to enhance Daybreak’s ability to continue as a going concern.  The Company currently has a net revenue interest in 20 producing crude oil wells in our East Slopes Project located in Kern County, California.  The revenue from these wells has created a steady and reliable source of revenue for the Company.  Our average working interest in these wells is 36.6% and the average net revenue interest is 28.5%.




48



We anticipate revenues will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project in California and our project in Michigan.  However given the current decline and instability in hydrocarbon prices, the timing of any drilling activity in California will be dependent on a sustained improvement in hydrocarbon prices and a successful refinancing or restructuring of our current credit facility.


We believe that our liquidity will improve when there is a sustained improvement in hydrocarbon prices.  Our sources of funds in the past have included the debt or equity markets and the sale of assets.  While the Company does have positive cash flow from its crude oil 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, we cannot offer any assurance that we will be successful in executing the aforementioned plans to continue as a going concern.


Critical Accounting Policies


Critical accounting policies are policies that are both most important to the portrayal of the Company’s financial condition and results, and that require management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.  Management’s discussion and analysis of our financial condition and results of operations are based on our financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America.  The preparation of these financial statements requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.


On an ongoing basis, we evaluate our estimates, including those related to revenue recognition, bad debts, cancellation costs associated with long term commitments, investments, intangible assets, assets subject to disposal, income taxes, service contracts, contingencies and litigation.  We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making estimates and judgments about the carrying value of assets and liabilities that are not readily apparent from other sources.  Estimates, by their nature, are based on judgment and available information.  These judgments and uncertainties do affect the application of these critical accounting policies.  There is a strong likelihood that materially different amounts could be reported under different conditions or using different assumptions.  Therefore, actual results could differ from those estimates and could have a material impact on our financial statements, and it is possible that such changes could occur in the near term.


Crude Oil and Natural Gas Properties


We use the successful efforts method of accounting for crude oil and natural gas property acquisition, exploration, development, and production activities.  Costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred.  Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred.  In addition, the geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred.  Costs to operate and maintain wells and field equipment are expensed as incurred.


Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on proved reserves.  Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their proved developed reserves.  Support equipment and other property and equipment are depreciated over their estimated useful lives.


Pursuant to Financial Accounting Standards Board Codification (“ASC”) Topic 360, “Property, Plant and Equipment,” we review proved oil and natural gas properties and other long-lived assets for impairment.  These reviews are predicated by events and circumstances, such as downward revision of the reserve estimates or commodity prices that indicate a decline in the recoverability of the carrying value of such properties.  We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable.  When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amounts of the properties are reduced to their estimated fair value.  The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production, future capital expenditures and a risk-adjusted discount rate.  The charge is included in DD&A.




49



Unproved crude oil and natural gas properties that are individually significant are also periodically assessed for impairment of value.  An impairment loss for unproved crude oil and natural gas properties is recognized at the time of impairment by providing an impairment allowance.


On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income.


Deposits and advances for services expected to be provided for exploration and development or for the acquisition of crude oil and natural gas properties are classified as long term other assets.


Revenue Recognition


Revenues from the sale of crude oil and natural gas are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.  The Company follows the sales method of accounting for recording crude oil and natural gas revenues.  Under this method, the Company records revenue based on actual sales volumes to purchasers.


Suspended Well Costs


We account for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities – Oil and Gas” (“ASC 932”).  ASC 932 states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the economic and operating feasibility of the well.  If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value.  Additional annual disclosures are required to provide information about management's evaluation of capitalized exploratory well costs.


In addition, ASC 932 requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year, designating the number of wells the aging is related to.  Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation.


Share Based Payments


Share based awards are accounted for under FASB Topic ASC 718, “Compensation-Stock Compensation” (“ASC 718”).  ASC 718 requires compensation costs for all share-based payments granted to be based on the grant date fair value.  The value of the portion of the award that is ultimately expected to vest is recognized as expense ratably over the requisite service periods.


Off-Balance Sheet Arrangements


As of February 28, 2018, we did not have any relationships with unconsolidated entities or financial partners, such as entities often referred to as structured finance or special purpose entities, which have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.  As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.




50



ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


As a smaller reporting company, we are not required to provide the information otherwise required by this Item.





51



ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




To the Board of Directors and Shareholders of

Daybreak Oil and Gas, Inc.

Spokane Valley, Washington


Opinion on the Financial Statements


We have audited the accompanying balance sheets of Daybreak Oil and Gas, Inc. (the “Company”) as of February 28, 2018 and 2017, and the related statements of operations, changes in stockholders’ deficit, and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of February 28, 2018 and 2017, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.


Going Concern Matter


The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency that raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.


Basis for Opinion


These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.


We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.


Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


/s/ MaloneBailey, LLP

www.malonebailey.com

We have served as the Company's auditor since 2006.

Houston, Texas

May 24, 2018






52



DAYBREAK OIL AND GAS, INC.

Balance Sheets

As of February 28, 2018 and 2017

 

 

 

 

 

As of February 28, 2018

 

As of February 28, 2017

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

$

48,535 

 

$

42,003 

Accounts receivable:

 

 

 

 

 

Crude oil sales

 

104,840 

 

 

83,405 

Joint interest participants

 

58,452 

 

 

55,154 

Other receivables, net

 

 

 

4,489 

Prepaid expenses and other current assets

 

21,796 

 

 

24,197 

Restricted short-term time deposit

 

100,029 

 

 

100,060 

Total current assets

 

333,652 

 

 

309,308 

OIL AND GAS PROPERTIES, successful efforts method, net

 

 

 

 

 

Proved properties

 

714,609 

 

 

853,552 

Unproved properties

 

31,187 

 

 

59,375 

PREPAID DRILLING COSTS

 

16,452 

 

 

41,078 

Total assets

$

1,095,900 

 

$

1,263,313 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ DEFICIT

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable and other accrued liabilities

$

2,022,672 

 

$

1,727,955 

Accounts payable - related parties

 

1,664,845 

 

 

1,414,481 

Accrued interest

 

1,822,673 

 

 

446,232 

Notes payable, related party

 

250,100 

 

 

250,100 

12% Notes payable, net of discount of $7,429

 

307,571 

 

 

12% Note payable - related party, net of discount of $5,897

 

244,103 

 

 

Debt - current portion, net of deferred financing costs of $-0- and $238,598, respectively

 

9,157,794 

 

 

8,805,846 

Line of credit

 

873,350 

 

 

817,622 

Total current liabilities

 

16,343,108 

 

 

13,462,236 

LONG TERM LIABILITIES:

 

 

 

 

 

12% Notes payable, net of discount $15,535

 

 

 

299,465 

12% Note payable - related party, net of discount $12,329

 

 

 

237,671 

Asset retirement obligation

 

37,174 

 

 

93,409 

Total liabilities

 

16,380,282 

 

 

14,092,781 

COMMITMENTS AND CONTINGENCIES

 

 

 

 

 

STOCKHOLDERS’ DEFICIT:

 

 

 

 

 

Preferred stock - 10,000,000 shares authorized, $0.001 par value;

 

 

 

Series A Convertible Preferred stock - 2,400,000 shares authorized, $0.001 par value, 6% cumulative dividends; 709,568 and 724,565 shares issued and outstanding, respectively

 

710 

 

 

725 

Common stock- 200,000,000 shares authorized; $0.001 par value, 51,532,364 and 51,487,373 shares issued and outstanding, respectively

 

51,532 

 

 

51,487 

Additional paid-in capital

 

22,997,759 

 

 

22,997,789 

Accumulated deficit

 

(38,334,383)

 

 

(35,879,469)

Total stockholders’ deficit

 

(15,284,382)

 

 

(12,829,468)

Total liabilities and stockholders' deficit

$

1,095,900 

 

$

1,263,313 


The accompanying notes are an integral part of these financial statements




53



DAYBREAK OIL AND GAS, INC.

Statements of Operations

For the Twelve Months Ended February 28, 2018 and 2017

 

 

 

 

 

Twelve Months Ended

February 28, 2018

 

Twelve Months Ended

February 28, 2017

REVENUE:

 

 

 

 

 

Crude oil sales

$

628,652 

 

$

482,656 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

Production

 

170,966 

 

 

163,654 

Exploration and drilling

 

107,884 

 

 

9,297 

Depreciation, depletion and amortization

 

82,707 

 

 

110,285 

General and administrative

 

981,290 

 

 

1,068,212 

Total operating expenses

 

1,342,847 

 

 

1,351,448 

OPERATING LOSS

 

(714,195)

 

 

(868,792)

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

Interest income

 

54 

 

 

81 

Interest expense

 

(1,740,773)

 

 

(2,994,466)

Total other expenses

 

(1,740,719)

 

 

(2,994,385)

 

 

 

 

 

 

LOSS FROM CONTINUING OPERATIONS

 

(2,454,914)

 

 

(3,863,177)

 

 

 

 

 

 

DISCONTINUED OPERATIONS: (Note 7)

 

 

 

 

 

Income from discontinued operations

 

 

 

394,623 

 

 

 

 

 

 

NET LOSS

 

(2,454,914)

 

 

(3,468,554)

 

 

 

 

 

 

Cumulative convertible preferred stock dividend requirement

 

(128,231)

 

 

(130,415)

 

 

 

 

 

 

NET LOSS AVAILABLE TO COMMON SHAREHOLDERS

$

(2,583,145)

 

$

(3,598,969)

 

 

 

 

 

 

NET INCOME (LOSS) PER COMMON SHARE

 

 

 

 

 

Loss on continuing operations

$

(0.05)

 

$

(0.08)

Income from discontinued operations

 

-  

 

 

0.01  

 

 

 

 

 

 

NET LOSS PER COMMON SHARE – Basic and diluted

$

(0.05)

 

$

(0.07)

 

 

 

 

 

 

WEIGHTED AVERAGE NUMBER OF

COMMON SHARES OUTSTANDING – Basic and diluted

 

51,523,816 

 

 

51,487,373 


The accompanying notes are an integral part of these financial statements





54





DAYBREAK OIL AND GAS, INC.

Statements of Changes in Stockholders' Deficit

For the Twelve Months Ended February 28, 2018 and 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Series A Convertible

 

 

 

 

 

 

Additional

 

 

 

 

 

 

 

Preferred Stock

 

Common Stock

 

Paid-In

 

Accumulated

 

 

 

 

Shares

 

Amount

 

Shares

 

Amount

 

Capital

 

Deficit

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, FEBRUARY 29, 2016

724,565 

 

$

725 

 

51,487,373

 

$

51,487

 

$

22,968,714 

 

$

(32,410,915)

 

$

(9,389,989)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Extension of 12% Note warrants

 

 

 

 

 

 

 

 

 

 

 

29,075 

 

 

 

 

29,075 

Net loss

 

 

 

-

 

 

-

 

 

 

 

(3,468,554)

 

 

(3,468,554)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, FEBRUARY 28, 2017

724,565 

 

$

725 

 

51,487,373

 

$

51,487

 

$

22,997,789 

 

$

(35,879,469)

 

$

(12,829,468)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of common stock for:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conversion of preferred stock

(14,997)

 

 

(15)

 

44,991

 

 

45

 

 

(30)

 

 

 

 

 

Net loss

 

 

 

-

 

 

-

 

 

 

 

(2,454,914)

 

 

(2,454,914)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, FEBRUARY 28, 2018

709,568 

 

$

710 

 

51,532,364

 

$

51,532

 

$

22,997,759 

 

$

(38,334,383)

 

$

(15,284,382)


The accompanying notes are an integral part of these financial statements










55





DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows

For the Twelve Months Ended February 28, 2018 and 2017

 

 

 

Twelve Months Ended

 

February 28, 2018

 

February 28, 2017

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net loss

$

(2,454,914)

 

$

(3,468,554)

Adjustments to reconcile net loss to net cash (used in) provided by operating activities:

 

 

 

 

 

Loss on sale of crude oil and natural gas properties

 

 

 

1,955,315 

Loss on settlement of Note Receivable

 

 

 

1,500,676 

Gain on debt settlement

 

 

 

(3,926,468)

Depreciation, depletion and amortization

 

82,707 

 

 

234,454 

Amortization of debt discount

 

14,538 

 

 

73,162 

Amortization of deferred financing costs

 

238,598 

 

 

423,331 

Reclass of unproved crude oil and natural gas properties to exploration expense

 

51,486 

 

 

Debt modification fees

 

 

 

1,057,042 

Interest income

 

31 

 

 

81 

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable – crude oil and natural gas sales

 

(21,435)

 

 

(21,332)

Accounts receivable - joint interest participants

 

(3,298)

 

 

51,540 

Accounts receivable - other

 

4,489 

 

 

(711,987)

Prepaid expenses and other current assets

 

3,729 

 

 

86,819 

Accounts payable and other accrued liabilities

 

305,368 

 

 

395,814 

Accounts payable - related parties

 

250,364 

 

 

423,998 

Accrued interest

 

1,408,169 

 

 

2,092,076 

Net cash provided by (used in) operating activities

 

(120,168)

 

 

165,967 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Additions to crude oil and natural gas properties

 

 

 

(73,683)

Prepaid drilling costs

 

 

 

(22,276)

Net cash used in investing activities

 

 

 

(95,959)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Proceeds from debt

 

102,700 

 

 

25,000 

Additions to line of credit

 

84,000 

 

 

 

Payments to line of credit

 

(60,000)

 

 

(60,000)

Net cash provided by (used in) financing activities

 

126,700 

 

 

(35,000)

 

 

 

 

 

 

NET INCREASE IN CASH AND CASH EQUIVALENTS

 

6,532 

 

 

35,008 

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

 

42,003 

 

 

6,995 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

$

48,535 

 

$

42,003 

 

 

 

 

 

 

CASH PAID FOR:

 

 

 

 

 

Interest

$

111,195 

 

$

98,659 

Income taxes

$

 

$





56





DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows (continued)

For the Twelve Months Ended February 28, 2018 and 2017

 

 

 

Twelve Months Ended

 

February 28, 2018

 

February 28, 2017

SUPPLEMENTAL CASH FLOW INFORMATION:

 

 

 

 

 

Interest and fees converted to principal on debt

$

 

$

1,567,795 

Increase in note receivable for interest and fees added to principal

$

 

$

745,163 

Satisfaction of note receivable through debt reduction

$

 

$

3,900,000 

ARO revision

$

64,206 

 

$

11,806 

Proceeds from sale of crude oil and natural gas properties paid directly to reduce debt

$

 

$

600,000 

Proceeds from debt paid directly to accounts payable vendor

$

10,650 

 

$

Unpaid deferred financing costs

$

 

$

20,854 

Non-cash addition to debt for unproved O&G properties and prepaid drilling costs

$

 

$

84,000 

Non-cash addition to debt for expenses paid directly by lender

$

 

$

215,000 

Non-cash addition to line of credit due to monthly interest

$

31,728 

 

$

33,815 

Debt discount addition due to debt modification

$

 

$

29,075 

Conversion of preferred stock to common stock

$

45 

 

$




The accompanying notes are an integral part of these financial statements









57






DAYBREAK OIL AND GAS, INC.

NOTES TO AUDITED FINANCIAL STATEMENTS


NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION:


Originally incorporated as Daybreak Uranium, Inc., (“Daybreak Uranium”) under the laws of the State of Washington on March 11, 1955, Daybreak Uranium was organized to explore for, acquire, and develop mineral properties in the Western United States.  During 2005, management of the Company decided to enter the crude oil and natural gas exploration and production industry.  On October 25, 2005, the Company’s shareholders approved a name change from Daybreak Mines, Inc. to Daybreak Oil and Gas, Inc. (referred to herein as “Daybreak” or the “Company”) to better reflect the business of the Company.


All of the Company’s crude oil and natural gas production is sold under contracts that are market-sensitive.  Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, crude oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  These factors include the level of global demand for petroleum products, foreign supply of crude oil and natural gas, the establishment of and compliance with production quotas by crude oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.



NOTE 2 — GOING CONCERN:


Financial Condition


Daybreak’s financial statements for the twelve months ended February 28, 2018 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.  Daybreak has incurred net losses since inception and has accumulated a deficit of $38,334,383 and a working capital deficit of $16,009,456, which raises substantial doubt about the Company’s ability to continue as a going concern.


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 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 in these wells is 36.6% and the average net revenue interest is 28.4% for these same wells.


The Company anticipates revenue will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project in California and our project in Michigan.  However given the current decline and instability in hydrocarbon prices, the timing of any drilling activity in California will be dependent on a sustained improvement in hydrocarbon prices and a successful refinancing or restructuring of our 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 February 28, 2018 do not include any adjustments that might result from the inability to implement or execute Daybreak’s plans to improve our ability to continue as a going concern.




58





NOTE 3 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:


Cash and Cash Equivalents


Cash equivalents include demand deposits with banks and all highly liquid investments with original maturities of three months or less.  The Company has in the past maintained balances in financial institutions where deposits may exceed the federally insured deposit limit of $250,000.  The Company has not experienced any losses from such accounts and does not believe it is exposed to any significant credit risk on cash.


Accounts Receivable


The Company routinely assesses the recoverability of all material trade and other receivables.  The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated.  Actual write-offs may exceed the recorded allowance.  Substantially all of the Company’s trade accounts receivable result from crude oil in California or joint interest billings to its working interest partners in California.  This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors.  Trade accounts receivable are generally not collateralized.  There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2018 and 2017.


Crude Oil and Natural Gas Properties


The Company uses the successful efforts method of accounting for crude oil and natural gas property acquisition, exploration, development, and production activities.  Costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred.  Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred.  In addition, the geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred.  Costs to operate and maintain wells and field equipment are expensed as incurred.


Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on estimated proved reserves.  Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their estimated proved developed reserves.  Support equipment and other property and equipment are depreciated over their estimated useful lives.


Pursuant to the provisions of Financial Accounting Standards Codification (“ASC”) Topic 360, “Property, Plant and Equipment” the Company reviews proved crude oil and natural gas properties and other long-lived assets for impairment.  These reviews are predicated by events and circumstances, such as downward revision of the reserve estimates or commodity prices that indicate a decline in the recoverability of the carrying value of such properties.  The Company estimates the future cash flows expected in connection with the properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable.  When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amounts of the properties are reduced to their estimated fair value.  The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production, future capital expenditures and a risk-adjusted discount rate.  These estimates of future product prices may differ from current market prices of crude oil and natural gas.  Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s crude oil and natural gas properties in subsequent periods.  Unproved crude oil and natural gas properties that are individually significant are also periodically assessed for impairment of value.  An impairment loss for unproved crude oil and natural gas properties is recognized at the time of impairment by providing an impairment allowance.


The Company did not recognize any asset impairment for the twelve months ended February 28, 2018 and 2017, respectively.


On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income.



59





Property and Equipment


Fixed assets are stated at cost.  Depreciation on vehicles is provided using the straight-line method over expected useful lives of three years.  Depreciation on machinery and equipment is provided using the straight-line method over expected useful life of three years.  Depreciation of production facilities and natural gas pipelines are recorded using the unit-of-production method based on estimated reserves.


Long Lived Assets


The Company reviews long-lived assets and identifiable intangibles whenever events or circumstances indicate that the carrying amounts of such assets may not be fully recoverable.  The Company evaluates the recoverability of long-lived assets by measuring the carrying amounts of the assets against the estimated undiscounted cash flows associated with these assets.  If this evaluation indicates that the future undiscounted cash flows of certain long-lived assets are not sufficient to recover the assets' carrying value, the assets are adjusted to their fair values (based upon discounted cash flows).


Fair Value of Financial Instruments


The carrying value of short-term financial instruments including cash, receivables, prepaid expenses, accounts payable, and other accrued liabilities, short-term liabilities and the line of credit approximated their fair values due to the relatively short period to maturity for these instruments.  The long-term notes payable approximates fair value since the related rates of interest approximate current market rates.


Share Based Payments


Stock awards are accounted for under FASB ASC Topic 718, “Compensation-Stock Compensation” (“ASC 718”).  Under ASC 718, compensation for all share-based payment awards is based on estimated fair value at the grant date.  The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.


The Company estimates the fair value of stock purchase warrants on the grant date using the Black-Scholes option pricing model (“Black-Scholes Model”) as its method of valuation for warrant awards granted during the year.  The Company’s determination of fair value of warrant awards on the date of grant using an option-pricing model is affected by the Company’s stock price, as well as assumptions regarding a number of subjective variables.  These variables include, but are not limited to, the Company’s expected price volatility over the term of the awards and discount rates assumed.


Loss per Share of Common Stock


Basic loss per share of Common Stock is calculated by dividing net loss available to common stockholders by the weighted average number of common shares issued and outstanding during the year.  Diluted net loss per share is computed based on the weighted average number of common shares outstanding, increased by dilutive Common Stock equivalents.  Common Stock equivalents are excluded from the calculations when their effect is anti-dilutive.


Concentration of Credit Risk


Substantially all of the Company’s accounts receivable result from crude oil California or joint interest billings to its working interest partners in California.  This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors.


At the Company’s East Slopes project in California we deal with only one buyer for the purchase of all crude oil production.  The Company has no natural gas production in California.  At February 28, 2018 and 2017, this one individual customer represented 100.0% of crude oil sales receivable from continuing operations.  If this buyer is unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its crude oil production.



60





The Company’s accounts receivable from continuing operations in California for crude oil sales at February 28, 2018 and 2017, respectively are set forth in the table below.


 

 

 

 

February 28, 2018

 

February 28, 2017

Project

 

Customer

 

Accounts

Receivable

Crude Oil

Sales

 

Percentage

 

Accounts

Receivable

Crude Oil

Sales

 

Percentage

California – East Slopes Project (Crude oil)

 

Plains Marketing

 

$

104,840

 

100.0%

 

$

83,405

 

100.0%


Revenue Recognition


Revenues from the sale of crude oil and natural gas are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.  The Company follows the sales method of accounting for recording crude oil and natural gas revenues.  Under this method, the Company records revenue based on actual sales volumes to purchasers.


Reclamation Bonds


Included in current assets as of February 28, 2018 and 2017, are funds that have been pledged as collateral in connection with any future obligations for plugging, abandonment and site remediation.  The amount pledged for an operator bond in California is approximately $100,000 plus accrued interest.  The pledging of these funds is required by any state in which the Company operates as the project Operator.  On March 29, 2018, the restriction on these funds was released by the State of California.  


Asset Retirement Obligation (“ARO”)


The Company follows the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“ASC 410”), which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  This standard requires that the Company recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred.  The ARO is capitalized as part of the carrying value of the assets to which it is associated, and depreciated over the useful life of the asset.  The ARO and the related asset retirement cost are recorded when an asset is first drilled, constructed or purchased.  The asset retirement cost is determined and discounted to present value using a credit-adjusted risk-free rate.  After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in the statements of operations.  Subsequent adjustments in the cost estimate are reflected in the ARO liability and the amounts continue to be amortized over the useful life of the related long-lived assets.


Suspended Well Costs


The Company accounts for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities – Oil and Gas” (“ASC 932”).  ASC 932 states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the economic and operating feasibility of the well.  If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value.  Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs.


In addition, ASC 932 requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year, designating the number of wells the aging is related to.  Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation.




61





Income Taxes


The Company follows the provisions of FASB ASC Topic 740, “Income Taxes” (“ASC 740”).  As required under ASC 740, the Company accounts for income taxes using an asset and liability approach, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial statements and tax bases of assets and liabilities at the applicable tax rates.  A valuation allowance is utilized when it is more likely than not, that some portion of, or all of the deferred tax assets will not be realized.  Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.


ASC 740 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  Under ASC 740, the Company recognizes tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities.  The amount recognized is measured as the largest amount of benefit that is greater than 50% (percent) likely to be realized upon settlement.  A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards.


Use of Estimates and Assumptions


In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions.  These estimates and assumptions may affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting periods.  Actual results could differ materially from those estimates.  The accounting policies most affected by management’s estimates and assumptions are as follows:

·

The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any impairment of proved properties;

·

The valuation of unproved acreage and proved crude oil and natural gas properties to determine the amount of any impairment of crude oil and natural gas properties;

·

Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment; and

·

Estimates regarding the timing and cost of future abandonment obligations.


Recent Accounting Pronouncements


Accounting Standards Issued and Adopted


In May 2014, the FASB issued ASC updated No. 2014-09, Revenue from Contracts with Customers (Topic 606 (ASU 2014-09).  Under the amendments in this update, recognition of revenue occurs when a customer obtains control of promised goods or services in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  In addition, the new standard requires that reporting companies disclose the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.  The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2017.  The new standard is required to be applied either retrospectively to each prior reporting period presented, or retrospectively with the cumulative effect of applying the update recognized at the date of initial application.  The Company has determined that implementation of this amendment will not result in any change to its financial statements.


In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (“ASU 2016-18”).  The update is effective for years beginning December 15, 2017, including interim reporting periods within those fiscal years.  Early adoption is permitted.  The purpose of Update 216-18 is to clarify guidance and presentation related to restricted cash in the Statements of Cash Flows.  The amendment requires beginning-of-period and end-of-period total amounts shown on the Statements of Cash Flows to include cash and cash equivalents as well as restricted cash and restricted cash equivalents.  The Company has evaluated the impact and timing of the adoption of ASU 2016-18 and has concluded it will not have a material impact on its financial statements.


Reclassifications


Certain reclassifications have been made to conform the prior period’s financial information to the current period’s presentation.  These reclassifications had no effect on previously reported net loss or accumulated deficit.




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NOTE 4 — ACCOUNTS RECEIVABLE:


Accounts receivable consists primarily of receivables from the sale of crude oil production from continuing operations by the Company and receivables from the Company’s working interest partners in crude oil projects in which the Company acts as Operator of the project.


Crude oil sales receivables balances from continuing operations of $104,840 and $83,405 at February 28, 2018 and 2017, represent crude oil sales that occurred in February 2018 and 2017, respectively.


Joint interest participant receivables balances of $58,452 and $55,154 at February 28, 2018 and 2017, respectively, represent amounts due from working interest partners in California, where the Company is the Operator.  There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2018 and 2017.



NOTE 5 — CRUDE OIL PROPERTIES:


Crude oil property balances from continuing operations at February 28, 2018 and 2017 are set forth in the table below:


 

February 28, 2018 (1)

 

February 28, 2017

Proved leasehold costs

$

115,119 

 

$

115,119 

Unproved leasehold costs

 

31,187 

 

 

59,375 

Costs of wells and development

 

2,293,668 

 

 

2,293,668 

Capitalized exploratory well costs

 

1,333,785 

 

 

1,341,494 

Capitalized asset retirement costs

 

 

 

56,497 

Total cost of oil and gas properties

 

3,773,759 

 

 

3,866,153 

Accumulated depletion, depreciation amortization and impairment

 

(3,027,963)

 

 

(2,953,226)

Oil and gas properties, net

$

745,796 

 

$

912,927 


(1) During the twelve months ended February 28, 2018, a $51,486 reduction in unproved crude oil and natural gas properties was recorded to properly recognize geologic and geophysical lease expenses associated with our Michigan exploratory joint drilling project development.



NOTE 6 — Asset Retirement Obligation (“ARO”)


The Company’s financial statements reflect the provisions of ASC 410.  The ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws.  The Company determines the ARO on its crude oil and natural gas properties by calculating the present value of estimated cash flows related to the liability.  As of February 28, 2018 and 2017, ARO obligations were considered to be long-term based on the estimated timing of the anticipated cash flows.  For the twelve months ended February 28, 2018 and 2017, the Company recognized accretion expense of $7,971 and $8,390, respectively which is included in DD&A in the statement of operations.


Changes in the asset retirement obligations for the twelve months ended February 28, 2018 and 2017 are set forth in the table below.


 

February 28, 2018

 

February 28, 2017

Asset retirement obligation, beginning of period

$

93,409 

 

$

73,213

Accretion expense

 

7,971 

 

 

8,390

Revisions to asset retirement obligation

 

(64,206)

 

 

11,806

Asset retirement obligation, end of period

$

37,174 

 

$

93,409



NOTE 7 — DISCONTINUED OPERATIONS:


Effective October 31, 2016, the Company finalized the sale of its interest in the Twin Bottoms Field in Kentucky.  The sale included Daybreak’s working interest in 14 producing horizontal crude oil wells, its mineral rights, its lease acreage and infrastructure.  In accordance with the guidance provided in ASC 205-20, the Company concluded that this sale qualified for presentation as discontinued operations.  The Company has no ongoing or future plans to be involved in this segment of its crude oil and natural gas projects.  Prior period income statement balances applicable to the Twin Bottoms Field in Kentucky have been reclassified and are included under the Discontinued Operations caption in the statements of operations for February 28, 2017.




63





Operating income, interest income, operating expenses and interest expense related to Kentucky for the twelve months ended February 28, 2018 and 2017 are set forth in the tables below.


 

For the Twelve Months Ended

 

February 28, 2018

 

February 28, 2017

Crude oil and natural gas sales revenue

$

 

$

280,030 

Interest income

 

 

 

760,704 

Production, exploration and drilling expenses

 

 

 

(65,157)

Depreciation, Depletion and Amortization (“DD&A”) expenses

 

 

 

(124,169)

General and Administrative (G&A)

 

 

 

(204,056)

Interest expense

 

 

 

(723,206)

Loss on note receivable settlement

 

 

 

(1,500,676)

Loss on sale of O&G properties

 

 

 

(1,955,315)

Gain on debt settlement

 

 

 

3,926,468 

Loss from discontinued operations

$

 

$

(394,623)


The statements of cash flows include certain significant non-cash operating items for discontinued operations in Kentucky during the twelve months ended February 28, 2017, comprised of loss on sale of crude oil and natural gas properties of $1.96 million; loss on note receivable settlement of $1.5 million; gain on debt settlement of $3.9 million; satisfaction of note receivable through debt reduction of $3.9 million; proceeds from sale of crude oil and natural gas properties paid directly to reduce debt of $600 thousand; addition to debt for expenses directly by lender of $215 thousand; increase in note receivable for interest added to principal of $745 thousand; DD&A expense of $124 thousand; and additions to crude oil and natural gas properties of $13 thousand.  



NOTE 8ACCOUNTS PAYABLE:


On March 1, 2009, the Company became the operator for the East Slopes Project located in Kern County, California.  Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning wells program.  The Company subsequently sold the 25% working interest on June 11, 2009.  Approximately $244,849 of the $1.5 million default remains unpaid and is included in the February 28, 2018 accounts payable balance.



NOTE 9ACCOUNTS PAYABLE- RELATED PARTIES:


The February 28, 2018 and 2017 accounts payable – related parties balances of $1,664,845 and $1,414,481, respectively, were comprised primarily of deferred salaries of the Company’s Executive Officers and certain employees; deferred directors’ fees; expense reimbursements; related party consulting fees; and deferred interest payments on the 12% Subordinated Note to the Company’s Chairman, President and Chief Executive Officer.  Payment of these deferred items has been delayed until the Company’s cash flow situation improves.



NOTE 10 — SHORT-TERM AND LONG-TERM BORROWINGS:


Note Payable – Related Party


The Company has a note payable-related party loan balance of $250,100 as of February 28, 2018 and 2017.  The Company’s Chairman, President and Chief Executive Officer has loaned the Company an aggregate $250,100 that was 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.




64





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 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%.  


The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes.  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 consecutive trading days preceding December 31, 2018.  Amortization expense was $14,538 and $1,211 at February 28, 2018 and 2017, respectively.  The unamortized debt discount at February 28, 2018 and 2017 was $13,326 and $27,864, respectively.


12% Note balances at February 28, 2018 and 2017 are set forth in the table below:


 

February 28, 2018

 

February 28, 2017

12% Subordinated Notes

$

315,000 

 

$

315,000 

Debt discount

 

(7,429)

 

 

(15,535)

Net 12% Subordinated Note balance

$

307,571 

 

$

299,465 


12% Note balances – related parties at February 28, 2018 and 2017 are set forth in the table below:


 

February 28, 2018

 

February 28, 2017

12% Subordinated Notes – related party

$

250,000 

 

$

250,000 

Debt discount

 

(5,897)

 

 

(12,329)

Net 12% Subordinated Note – related party balance

$

244,103 

 

$

237,671 


In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.07 and an amended expiration date of January 29, 2019.  The 12% Note warrants that have been exercised are set forth in the table below.  At February 28, 2018, there were 980,000 warrants that were not exercised and had not expired.


Fiscal Period

 

Warrants

Exercised

 

Shares of

Common Stock

Issued

 

Number of

Accredited

Investors

Year Ended February 28, 2014

 

100,000

 

100,000

 

1

Year Ended February 28, 2015

 

50,000

 

50,000

 

1

Year Ended February 29, 2016

 

-

 

-

 

-

Year Ended February 28, 2017

 

-

 

-

 

-

Year Ended February 28, 2018

 

-

 

-

 

-

Totals

 

150,000

 

150,000

 

2


Maximilian Credit Facility and Loan Agreement


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 these notes to the financial statements 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.




65





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.  Consequently, the unamortized discount and the deferred financing costs as of the date of amendment were amortized over the term of the loan agreement.  Due to the Company’s default on the Maximilian loan, all unamortized discount and deferred financing costs were fully amortized during the twelve months ended February 28, 2018.


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 had agreed to a commitment by Maximilian to advance up to $250,000 in financing to the Company over the following six month period and the pursuit of the Michigan exploratory joint drilling project using the $250,000 set aside from the Kentucky Sale.


During the twelve months ended February 28, 2017, 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; $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 February 28, 2018 and 2017 was $1,812,128 and $440,389, respectively The Company is currently considered to be in default under the terms of its credit facility loan.  Maximilian is currently in receivership.  The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender to assume the Maximilian credit facility.  No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company.


During the twelve months ended February 28, 2018 and 2017, the Company received advances of $102,700 and $25,000, respectively, under the terms of the credit facility.


Maximilian Promissory Note – Michigan Exploratory Joint Drilling Project


As of February 28, 2018, 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 available funding from Maximilian, we were unable to spud a well on the Michigan project by December 31, 2017.  The Company is currently considered to be in default under the terms of its loan agreement.  Maximilian is currently in receivership.  The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender.  No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company.  Accrued interest on the Michigan promissory note at February 28, 2018 and 2017 was $5,158 and $456, respectively.  During the twelve months ended February 28, 2018, an aggregate amount of $10,650 was paid directly to the Operator of the Michigan project by Maximilian on the Company’s behalf.




66





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, 2018 and 2017.  Due to the Company’s default on the Maximilian loan, all unamortized discount and deferred financing costs were fully amortized during the twelve months ended February 28, 2018.


Current debt balances at February 28, 2018 and 2017 are set forth in the table below:


 

February 28, 2018

 

February 28, 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 debt

 

94,650

 

 

84,000 

Net debt

$

9,157,794

 

$

8,805,846 


Deferred financing costs at February 28, 2018 and 2017 relating to the original and the amended credit facility with Maximilian, are set forth in the table below:


 

February 28, 2018

 

February 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 

Subtotal – deferred financing costs

 

1,762,630 

 

 

1,762,630 

Accumulated amortization

 

(1,762,630)

 

 

(1,524,032)

Remaining balance – deferred financing costs

$

 

$

238,598 


Deferred financing cost balances of $-0- and $238,598 at February 28, 2018 and 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 $423,331 for the twelve months ended February 28, 2018 and 2017, respectively.  Accrued interest on both the Maximilian credit facility loan and the Michigan loan at February 28, 2018 and 2017 was $1,817,286 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 a payment waiver from Maximilian, the California and Michigan properties were cross-collateralized for the credit facility loan and the promissory note.


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 Line of Credit Agreement dated October 24, 2011 that is secured by the personal guarantee of the Company’s Chairman, President and Chief Executive Officer.  On July 10, 2017 a $700,000 portion of the outstanding line of credit balance was converted to a 24 month fixed term annual interest rate of 3.244% with interest payable monthly.  The remaining principal balance of the line of credit has a stated reference rate of 0.249% + 337.5 basis points with interest payable monthly.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.  During the twelve months ended February 28, 2018 and 2017, we received advances on the line of credit of $84,000 and $-0-, respectively.  During the twelve months ended February 28, 2018 and 2017 the Company made payments to the line of credit of $60,000 and $60,000, respectively.  Interest paid for the twelve months ended February 28, 2018 and 2017 was $31,727 and $33,815, respectively.  At February 28, 2018 and 2017, the line of credit had an outstanding balance of $873,350 and $817,622, respectively.




67





NOTE 11 — STOCKHOLDERS’ DEFICIT:


Preferred Stock


The Company is authorized to issue up to 10,000,000 shares of preferred stock with a par value of $0.001.  The Company’s preferred stock may be entitled to preference over the common stock with respect to the distribution of assets of the Company in the event of liquidation, dissolution, or winding-up of the Company, whether voluntarily or involuntarily, or in the event of any other distribution of assets of the Company among its shareholders for the purpose of winding-up its affairs.  The authorized but unissued shares of preferred stock may be divided into and issued in designated series from time to time by one or more resolutions adopted by the Board of Directors.  The directors in their sole discretion shall have the power to determine the relative powers, preferences, and rights of each series of preferred stock.


Series A Convertible Preferred Stock


The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as Series A Convertible Preferred Stock (“Series A Preferred”), with a $0.001 par value.  In July 2006, we completed a private placement of the Series A Preferred that resulted in the issuance of 1,399,765 shares to 100 accredited investors.  For the year ended February 28, 2018, there was one conversion of Series A Preferred stock to Common Stock.  In this conversion, 14,997 shares of Series A Preferred were converted to 44,991 shares of the Company’s Common Stock.


The following is a summary of the rights and preferences of the Series A Preferred.


Voluntary Conversion:


The Series A Preferred that is currently issued and outstanding is eligible to be converted by the shareholder at any time into three shares of the Company’s common stock.  During the twelve months ended February 28, 2018, there was one conversion of 14,997 shares of Series A Preferred to 44,991 shares of the Company’s Common Stock.  For the twelve months ended February 28, 2017, there were no conversions of Series A Preferred.


At February 28, 2018 there were 709,568 shares issued and outstanding that had not been converted into our common stock.  As of February 28, 2018, 44 accredited investors have converted 690,197 Series A Preferred shares into 2,070,591 shares of Daybreak Common Stock.  The conversions of Series A Preferred that have occurred since the Series A Preferred was first issued in July 2006 is set forth in the table below.


Fiscal Period

 

Shares of Series A

Preferred Converted

to Common Stock

 

Shares of

Common Stock

Issued from

Conversion

 

Number of

Accredited

Investors

Year Ended February 29, 2008

 

102,300

 

306,900

 

10

Year Ended February 28, 2009

 

237,000

 

711,000

 

12

Year Ended February 28, 2010

 

51,900

 

155,700

 

4

Year Ended February 28, 2011

 

102,000

 

306,000

 

4

Year Ended February 29, 2012

 

-

 

-

 

-

Year Ended February 28, 2013

 

18,000

 

54,000

 

2

Year Ended February 28, 2014

 

151,000

 

453,000

 

9

Year Ended February 28, 2015

 

3,000

 

9,000

 

1

Year Ended February 29, 2016

 

10,000

 

30,000

 

1

Year Ended February 28, 2017

 

-

 

-

 

-

Year Ended February 28, 2018

 

14,997

 

44,991

 

1

Totals

 

690,197

 

2,070,591

 

44


Automatic Conversion:


The Series A Preferred shall be automatically converted into the Company’s common stock if the common stock into which the Series A Preferred are convertible the Company’s common stock closes at or above $3.00 per share for 20 out of 30 trading days.




68






Dividend:


Holders of Series A Preferred shall be paid dividends, in the amount of 6% of the original purchase price per annum.  Dividends may be paid in cash or common stock at the discretion of the Company.  Dividends are cumulative from the date of the final closing of the private placement, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.  Accumulations of dividends on shares of Series A Preferred do not bear interest.  Dividends are payable upon declaration by the Board of Directors.


Cumulative dividends earned for each twelve month period since issuance are set forth in the table below:


Fiscal Year Ended

 

Shareholders at

Period End

 

Accumulated

Dividends

February 28, 2007

 

100

 

$

155,311

February 29, 2008

 

90

 

 

242,126

February 28, 2009

 

78

 

 

209,973

February 28, 2010

 

74

 

 

189,973

February 28, 2011

 

70

 

 

173,707

February 29, 2012

 

70

 

 

163,624

February 28, 2013

 

68

 

 

161,906

February 28, 2014

 

59

 

 

151,323

February 28, 2015

 

58

 

 

132,634

February 29, 2016

 

57

 

 

130,925

February 28, 2017

 

57

 

 

130,415

February 28, 2018

 

56

 

 

128,231

 

 

 

 

$

1,970,148


Liquidation Preference:


In the event of any liquidation, dissolution or winding up of the Company, either voluntary or involuntary, the holders of the Series A Preferred shall be entitled to receive, prior and in preference to any distribution of any of the assets or surplus funds of the Company to the holders of common stock by reason of their ownership thereof, and subject to the rights of any series of preferred stock that may rank on liquidation prior to the Series A Preferred, an amount equal to all accrued or declared but unpaid dividends on such shares, for each share of Series A Preferred then held by them.  The remaining assets shall be distributed ratably to the holders of common stock and Series A Preferred on a common equivalent basis.  Certain other events, as described in our Amended and Restated Articles of Incorporation, including a consolidation or merger of the Company or the disposition of the Company’s assets, may trigger the payment of the liquidation preference to the holders of Series A Preferred.


Voting Rights:


The holders of the Series A Preferred will vote together with the common stock and not as a separate class except as specifically provided or as otherwise required by law.  Each share of the Series A Preferred shall have a number of votes equal to the number of shares of common stock then issuable upon conversion of such shares of Series A Preferred.


Common Stock


The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock of which 51,532,364 and 51,487,373 shares were issued and outstanding as of February 28, 2018 and 2017, respectively.


 

Common Stock

Balance

 

Par Value

Common stock, Issued and Outstanding, February 29, 2016

51,487,373 

 

 

 

Conversion of Series A Convertible Preferred Stock to common stock

 

$

Common stock, Issued and Outstanding, February 28, 2017

51,487,373 

 

 

 

Conversion of Series A Convertible Preferred Stock to common stock

44,991 

 

$

45

Common stock, Issued and Outstanding, February 28, 2018

51,532,364 

 

 

 




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All shares of common stock are equal to each other with respect to voting, liquidation, dividend and other rights.  Owners of shares of common stock are entitled to one vote for each share of common stock owned at any shareholders’ meeting.  Holders of shares of common stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefore; and upon liquidation, are entitled to participate pro rata in a distribution of assets available for such a distribution to shareholders.


There are no conversion, preemptive, or other subscription rights or privileges with respect to any shares of our common stock.  Our stock does not have cumulative voting rights, which means that the holders of more than 50% of the shares voting in an election of directors may elect all of the directors if they choose to do so.  In such event, the holders of the remaining shares aggregating less than 50% would not be able to elect any directors.



NOTE 12 — WARRANTS:


Warrants outstanding and exercisable as of February 28, 2018 are set forth in the table below:


 

 

Warrants

 

Exercise

Price

 

Remaining

Life

(Years)

 

Exercisable

Warrants

Remaining

12% Subordinated Notes

 

980,000

 

$0.07

 

0.92

 

980,000

Warrants issued for Kentucky crude oil project

 

3,498,601

 

$0.04

 

0.50

 

3,498,601

Warrants issued for Kentucky debt financing

 

2,623,951

 

$0.04

 

0.50

 

2,623,951

Warrants issued for Kentucky debt financing

 

309,503

 

$0.214

 

0.50

 

309,503

Warrants issued in share-for-warrant exchange

 

427,729

 

$0.04

 

0.50

 

427,729

 

 

7,839,784

 

 

 

 

 

7,839,784


Warrant activity for the twelve months ended February 28, 2018 and 2017 is set forth in the table below:


 

 

Warrants

 

Weighted Average

Exercise Price

Warrants outstanding, February 29, 2016

 

8,156,401 

 

$0.06

 

 

 

 


Changes during the twelve months ended February 28, 2017:

 

 

 


Expired / Cancelled / Forfeited

 

 


Warrants outstanding, February 28, 2017

 

8,156,401 

 

$0.05

 

 

 

 


Changes during the twelve months ended February 28, 2018:

 

 

 


Expired / Cancelled / Forfeited

 

(316,617)

 


Warrants outstanding, February 28, 2018

 

7,839,784 

 

$0.05

 

 

 

 


Warrants exercisable, February 28, 2018

 

7,839,784 

 

$0.05


On January 29, 2017, the 980,000 warrants associated with the 12% Subordinated Notes were modified to extend the expiration date of the warrants to January 29, 2019.  As a part of this modification the exercise price of the 12% Note warrants was changed from $0.14 to $0.07.  No other terms of the warrants were affected by the modification.  The outstanding warrants as of February 28, 2018 and 2017 have a weighted average exercise price of $0.05; a weighted average remaining life of 0.55 and 1.52, respectively; and an intrinsic value of $-0-.



NOTE 13 INCOME TAXES:


On December 22, 2017, the federal government enacted a tax bill H.R.1, an act to provide for reconciliation pursuant to Titles II and V of the concurrent resolution on the budget for fiscal year 2018, commonly referred to as the Tax Cuts and Jobs Act.  The Tax Cuts and Jobs Act contains significant changes to corporate taxation, including, but not limited to, reducing the U.S. federal corporate income tax rate from 35% to 21% and modifying or limiting many business deductions.  At Febraury 28, 2018, we had not completed our accounting for the tax effects resulting from the enactment of the Tax Cuts and Jobs Act; however we have made a reasonable estimate of the effects on our existing deferred tax balances.  We remeasured deferred tax liabilities based on rates at which they are expected tobe utilized in the future, which is generally 21%.  However, we are still analyzing certain aspecs of the Tax Cuts and Jobs Act and refining our calculations, which could potentially affect the measurement of those balances or give rise to new deferred tax amounts.




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Reconciliation between actual tax expense (benefit) and income taxes computed by applying the U.S. federal income tax rate and state income tax rate to income from continuing operations before income taxes is as follows: