DAYBREAK OIL & GAS, INC. - Annual Report: 2016 (Form 10-K)

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 29, 2016

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)

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.  ¨

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.

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 $0.04 on August 31, 2015, as reported by the Over-the-Counter Market was $1,970,295.

At May 26, 2016, the registrant had 51,487,373 outstanding shares of $0.001 par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

TABLE OF CONTENTS

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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 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 oil and natural gas properties;

·

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

·

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

·

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

·

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

·

Technological changes and developments in the 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.

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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 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.

Oil and Natural Gas Overview

We are an independent oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing 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 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 oil and natural gas properties and on the prevailing sales price for oil and natural gas along with associated operating expenses.  The volatile nature of the energy markets makes it difficult to estimate future prices of oil and natural gas; however, any prolonged period of depressed prices, such as we are now experiencing, does have a material adverse effect on our results of operations and financial condition.

The Company’s focus is to pursue 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 oil and natural gas companies or individuals.  We identify and evaluate prospective 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 oil and natural gas reservoirs and to mitigate our risk.  Currently, our core areas of activity are located in Lawrence County, Kentucky and Kern County, California 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 operations, we strive to be the operator of our oil and 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, such as with our Kentucky properties, 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 drillings, fracturing and completing operations.

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Known Trends and Uncertainties

As we continue to pursue our exploratory and development drilling programs in our Kentucky and California properties the timing of these activities continues to be determined by current 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 programs in Kentucky and California, 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 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 oil and natural gas production 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, and demand for, 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 and price of petroleum products, foreign supply of 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.  There has been a significant amount of volatility and dramatic decline in our realized sale price for both oil and natural gas since June of 2014.  The decline in the price of crude oil as shown below has had a substantial negative impact on our cash flow from both our Kentucky and California properties.

Crude Oil and Natural Gas Prices and Revenue

Our realized crude oil and natural gas prices and revenues for the year ended February 29, 2016 have dramatically declined from the year ended February 28, 2015 as detailed in the table below:

For the year ended February 29, 2016 crude oil and natural gas revenues declined $1,830,111 in aggregate to $1,253,686.  Of the $1,830,111 decline in revenue approximately 84.0% of the decline can be directly attributed to the sharp decline in hydrocarbon prices.  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.

The decline 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 series of waivers have been granted by Maximilian for the principal and interest payments that have not been made.  Due to the waivers granted by Maximilian, the Company is currently not considered to be in default under terms of the credit facility.  Maximilian is continuing to work with the Company in modifying the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue.  Further, there can be no assurances that Maximilian will not declare the Company to be in default under the credit facility.

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Competition

We compete with other independent 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 oil and natural gas 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 Twin Bottoms Field project located in Lawrence County, Kentucky, there is only one buyer available for the purchase of our oil production and only one buyer available for the purchase of our natural gas production.  Similarly, at our East Slopes Project, located in Kern County, California, there is only one buyer available for the purchase of our oil production.  At February 29, 2016, these three individual customers in aggregate represented 100% of crude oil and natural gas sales receivable.  If these local purchasers are unable to resell their products or if they lose a significant sales contract then we may incur difficulties in selling our oil and natural gas production.

The Company’s accounts receivable from Kentucky and California for oil and natural gas sales at February 29, 2016 and February 28, 2015 are set forth in the table below.

Title to Properties

As is customary in the oil and natural gas industry, we make only a cursory review of title to undeveloped 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 oil and natural gas properties, some of which are subject to immaterial easements, and restrictions.

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement 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 a mortgage on our leases in Kern County, California encompassing the Sunday, Bear, Black, Ball and Dyer Creek Properties.  For further information on the loan agreement refer to the discussion under the caption “Non-current debt (long-term borrowings)” found in the MD&A section of this Form 10-K.

Regulation

The exploration and development of 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.

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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 oil and natural gas.  Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from 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 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 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 the event we conduct operations on federal, state or American Indian 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.

The sales prices of 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.  We commonly use hydraulic fracturing as part of our operations in Kentucky.  Hydraulic fracturing typically is regulated by state 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.

Operational Hazards and Insurance

Our operations are subject to the usual hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of 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.

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Employees and Consultants

At February 29, 2016, 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 oil and natural gas properties as well as the prevailing prices for oil and natural gas to generate future revenues and operating cash flow.  Oil and natural gas prices have been 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 oil and natural gas; however, any prolonged period of depressed prices, such as we are now experiencing, 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 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.

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:

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.

Oil and natural gas prices are volatile.  Declines in commodity prices have currently 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 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 decline 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.

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

·

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

·

the price of 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 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.  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 $4.2 million for the year ended February 29, 2016, and we have an accumulated deficit through February 29, 2016 of approximately $32.4 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.

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We have substantial indebtedness.  The amount of our outstanding indebtedness continues to increase and our current inability to make payments towards such indebtedness could have adverse consequences on future operations.

Our outstanding indebtedness at February 29, 2016 was approximately $18.9 million, which was 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 pay principal and interest and meet 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 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.  As a result of the decline in hydrocarbon prices, we are currently unable to make the interest or principal payments required under the terms of our credit facility with our lender, Maximilian.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not been made.  Due to the waivers granted by Maximilian, the Company is currently not considered to be in default under terms of the credit facility.  Maximilian is continuing to work with the Company in modifying the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue.  Further, there can be no assurances that Maximilian will not declare the Company to be in default under 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 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 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 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 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 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 year ended February 29, 2016, we recorded an impairment expense of $1.1 million on our California properties.

The 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 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 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.

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In addition, we compete with larger 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 natural gas and oil;

·

acquire and evaluate larger volumes of critical information; and

·

compete for industry-offered business ventures.

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 oil and natural gas properties.

Our future performance depends upon our ability to find, acquire, and develop 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 oil and natural gas deposits will be discovered that are sufficient to enable us to recover our exploration and development costs.

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 Kentucky and 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.

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

Legislation 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 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 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 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 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 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 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.

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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 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.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In December 2009, the Environmental Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States including petroleum refineries, as well as certain onshore oil and natural gas production facilities, on an annual basis.  More recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule.  These new sources include gathering and boosting facilities as well as completions and requirements for certain facilities.  These changes to the EPA’s greenhouse gases emissions reporting rule could result in increased compliance costs.

Moreover, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions to acquire and surrender emission allowances.  The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.  Although our current facilities are not subject to the EPA’s greenhouse gases reporting rules, the EPA has indicated that it is evaluating whether the rule should be applied to oil and natural gas production activities, perhaps on a field-wide basis.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements.  Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.  Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Recently approved final rules regulating air emissions from natural gas production operations could cause us to incur increased capital expenditures, and operating costs which could be significant.

On April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities.  The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015.  For well completion operations occurring at such well sites before January 1, 2015, the final regulation allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions.  These regulations also establish specific new requirements regarding emissions from hydrators, storage tanks and other production equipment.  This new rule and compliance with its requirements could increase our costs of

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development and productions, though we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

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.  We commonly use hydraulic fracturing as part of our operations in Kentucky.  Hydraulic fracturing typically is regulated by state oil and gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuel, and, in February 2014, issued guidance for such activities.

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.

The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.  In June 2015 the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources.  The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board.  These ongoing or any future studies could spur initiatives further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their findings, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.  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.

Our proved reserves are estimates and depend on many assumptions.  Any material inaccuracies in these assumptions could cause the quantity and value of our oil and natural gas 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 oil and natural gas 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, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas properties will affect the timing of future net cash flows from proved reserves and their present value.

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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 reclassify proved undeveloped reserves to unproved 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.  Our recent reduction of our drilling program in response to depressed 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 plan 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.  

When we make the determination to invest in 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 oil or natural gas exists at a particular location.  This data is also used to determine whether 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 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.

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:

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unexpected drilling conditions;

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well integrity issues and surface expressions;

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pressure or irregularities in formations;

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equipment failures or accidents;

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compliance with landowner requirements;

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

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availability, costs and terms of contractual arrangements with respect to pipelines and related facilities to gather, process, transport and market 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.

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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 oil and natural gas industry can fluctuate significantly, often in correlation with 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 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 oil and natural gas properties.

All of our properties are held under interests in 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 an oil and 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 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 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 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.

If we as operators, or the operator of our oil and natural gas projects fail to maintain adequate insurance, our business could be exposed to significant losses.

Our oil and natural gas projects are subject to risks inherent in the oil and natural gas industry.  These risks involve explosions, uncontrollable flows of 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 the projects in which we are not the operator, we 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.

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We may lose key management personnel which could endanger the future success of our 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 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 29, 2016 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, and as a part of our efforts to minimize our general and administrative costs, 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.  We plan to hold an annual shareholders’ meeting in the next year; however, if we do not, or if we otherwise fail to hold annual shareholders’ meetings in the future, our shareholders will likely not 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 marketplace.  Prior to May 1, 2016, our stock had traded on the OTCQB Venture Marketplace.  Our transition to the OTC Pink marketplace resulted in a cost-savings to the company related to listing fees.

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 oil and natural gas exploration and development industry including volatility in oil and natural gas prices, and other events or factors.  The decline 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.

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.

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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 29, 2016, there were 51,487,373 shares of Common Stock and 724,565 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:

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

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

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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.

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 may 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 oil and natural gas reserves.  We have obtained debt financing through our revolving credit facility with Maximilian, as described in the MD&A section under the caption “Non-current debt – Maximilian Loan”  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.

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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 oil and natural gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues.  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 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.

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ITEM 1B.   UNRESOLVED STAFF COMMENTS

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

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ITEM 2.   PROPERTIES

We conduct all of our drilling, exploration and production activities in the United States.  All of our oil and natural gas 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 29, 2016, we were involved in oilfield projects in Lawrence County, Kentucky and Kern County, California.  We have not filed any estimates of total, proved net oil or natural gas reserves with any federal agency other than this report to the SEC for the fiscal year ended February 29, 2016.  Throughout this Annual Report on Form 10-K, 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”).

Lawrence County, Kentucky (Twin Bottoms Field)

The Twin Bottoms Field, comprising approximately 7,220 acres in two large contiguous blocks, is located in the Appalachian Basin of eastern Kentucky.  Log data from existing vertical natural gas wells in the field indicate the existence of proved oil reserves in the Berea sandstone, located at approximately 2,000 feet.  The lateral leg of each well is between 2,000 feet and 4,500 feet in length.  We have an approximate 25% working interest and an approximate net revenue interest (“NRI”) of 21.9% in all horizontal oil wells in this project.  The oil produced from our acreage in Kentucky is light crude oil measuring between 42° and 44° API (“American Petroleum Institute”) gravity.  We are not the Operator of the Twin Bottoms Field project; instead we rely on the experience of the current Operator and its knowledge of this Field.  However, we have our own personnel onsite during critical operations such as drilling, fracturing and completing operations.

At February 29, 2016, we had 14 producing horizontal oil wells in the Twin Bottoms Field.  Our first well, the Grove H-1 was put on production in October 2013.  During the year ended February 28, 2014, three additional oil wells, the Grove #H-3, Grove #H-4 and Grove #H-5, were put on production.  Nine additional horizontal oil wells, the Dillon #H-6, Grove #H-7, Grove #H-8, Grove #H-9, Grove #H-10, Jackson #H-20, Lyons #H-23, Lyons #H-24 and the Dillon #H-22, were put on production during the year ended February 28, 2015.  The App Energy #H-33 well was drilled in October 2015 to a measured depth of 5,251 feet and encountered 3,913 feet of oil pay in the Berea Sandstone.  Our average working interest and NRI in these 14 producing horizontal oil wells is 22.6% and 19.7%, respectively.

In August 2015, we drilled the vertical leg portion of the Murray #H-34 well.  The well was logged and data was collected for use in the drilling of the App Energy #H-33 well.  The Company paid 12.5% of the drilling and completion cost for a 25% working interest in the App Energy H-33 and Murray #H-34 wells as part of the App Amendment.  The horizontal portion of the Murray #H-34 well will be drilled at a later date.

Kentucky Drilling Plans

Selected wells may be drilled from time to time to maintain production and leases, however; implementation of our full 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 $1.0 million in new capital investments in the Twin Bottoms Field Project area in the 2016 - 2017 fiscal year.

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 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 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.

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Sunday Central Processing and Storage Facility

The oil produced from our acreage in California is considered heavy oil.  The oil ranges from 14° to 16° API gravity.  All of the oil from our five producing properties is processed, stored and sold from the Sunday central processing and storage facility.  The 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 oil storage tank to handle the additional 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 an average of approximately $12 per barrel of oil for the year ended February 29, 2016.  With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

California Producing Properties

Sunday Property

In November 2008, we made our initial 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 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 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 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 all 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 all 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.

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Dyer Creek Property

The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010.  This well is producing 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 $-0- in new capital investments within the East Slopes Project area in the 2016 – 2017 fiscal year.

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement 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 a mortgage on our leases in Kern County, California encompassing the Sunday, Bear, Black, Ball and Dyer Creek properties.  For further information on the loan agreement refer to the discussion under the caption “Non-current debt (long-term borrowings)” in the MD&A portion of this Annual Report on Form 10-K.

Reserves

The following table sets forth our estimated net quantities of proved reserves as of February 29, 2016.

(1)

Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil

The following table summarizes changes in our estimated net proved reserves for the year ended February 29, 2016.

Revisions. Net downward revisions of 54,886 BOE in aggregate were due to lower realized hydrocarbons prices during the year ended February 29, 2016 decreasing the economic life of our proved reserves.

Discoveries and extensions. For the year ended February 29, 2016, extensions of 103,157 BOE were a result of our drilling activity in the Twin Bottoms Field in eastern Kentucky.  There were no extensions for the year ended February 29, 2016 in California.

Production. Production in Kentucky was 19,482 BOE and 14,145 BOE in California representing 33,627 BOE in aggregate of proved reserves for the year ended February 29, 2016.

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The following table summarizes changes in our estimated net proved undeveloped reserves for the year ended February 29, 2016.

Revisions. There were net downward revisions of 17,569 BOE in aggregate due to lower realized hydrocarbons prices during the year ended February 29, 2016 decreasing the economic life of our proved reserves.

Discoveries and extensions. For the year ended February 29, 2016, extensions of 95,020 BOE were a result of our drilling activity in the Twin Bottoms Field in eastern Kentucky.  There were no extensions for the year ended February 29, 2016 in California.

The following table sets forth our estimated net proved developed reserves as of February 29, 2016 by project location.

The following table sets forth our estimated net proved undeveloped reserves as of February 29, 2016 by project location.

The Company has no proved undeveloped reserves that have remained undeveloped for a period greater than five years.  Under our current drilling plans, we intend to convert all 671,002 BOE or 100.0% of the proved undeveloped reserves disclosed as of February 29, 2016 to proved developed reserves within five years of the date they were initially first disclosed as proved undeveloped reserves.

The following table sets forth our estimated proved reserves (BOE) and PV-10 valuation by project area.

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 $4.0 million at February 29, 2016 a decline of approximately $13.5 million or 77.3% from the year ended February 28, 2015.  This decline is primarily due to the decline in hydrocarbon prices since June of 2014.  The commodity prices used to estimate proved reserves and their related PV-10 at February 29, 2016 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from March 2015 through February 2016.  The benchmark average price for the year ended February 29, 2016 was $47.45 per barrel of oil and $2.51 per Mcf for natural gas.

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These benchmark average prices were further adjusted for quality, transportation fees and other price differentials resulting in an average realized price in Kentucky for crude oil of $46.41 per barrel and $1.51 per Mcf for natural gas.  In California the average realized price was $39.10 per barrel of crude oil.  Adverse changes in any price differential could reduce our cash flow from operations and the PV-10 of our proved reserves.  Operating costs were not escalated.

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 902,780 BOE for the year ended February 29, 2016 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 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 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 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, 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

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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 oil and natural gas derived through volumetric calculations.

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 oil and natural gas 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 oil and natural gas industry in general are subject.

Delivery Commitments

As of February 29, 2016, we had no commitments to provide any fixed or determinable quantities of oil or natural gas in the near future under contracts or agreements, other than through customary marketing arrangements that require us to nominate estimated volumes of natural gas production for sale during periods of one month or less.

Summary Operating Data

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

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

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

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

The following table sets forth the developed and undeveloped oil and natural gas lease acreage held by us as of February 29, 2016.  Undeveloped acres are on lease acreage that wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas.  Gross acres are the total number of acres in which we have an interest.  Net acres are the sum of our fractional working interests owned in the gross acres.

The following table sets forth expiration dates of the leases of our gross and net undeveloped acres for the years shown.

Acres expiring are based on contractual lease maturities.  We may extend the leases prior to their expiration based upon planned activities or for other business activities.  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.  All of our proved undeveloped reserves are assigned to leases that are currently held by production (“HBP”).

The following table sets forth our productive oil and gas wells by the property and in aggregate as of February 29, 2016.  Productive wells are producing wells and wells capable of production.  Gross wells are the total number of wells in which we have an interest.  Net wells are the sum of our fractional working interests owned in the gross wells.

The following table sets forth our exploratory and development well drilling activity for the periods shown.

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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.

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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 in a cost-savings to the company related to listing fees.  The following table sets forth the high and low closing sales prices for our Common Stock for the two most recent 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.

We feel the dramatic 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 26, 2016, the Company had 1,920 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., 250 Royall Street, Canton, MA 02021.  Their website address is: www.computershare.com.

Dividend Policy

The Company has not declared or paid cash dividends or made distributions since its inception in 1955, and the Company does not anticipate that it will pay cash dividends or make 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 29, 2016, the company issued 30,000 shares of Common Stock to one accredited investor from the conversion of 10,000 shares of Series A Preferred 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.

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As of February 29, 2016, 43 accredited investors have converted 675,200 Series A Preferred shares into 2,025,600 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.

Common Stock Issuances

During the year ended February 28, 2011, the Company closed on a private placement of 12% Subordinated Notes (“Notes”) to 13 accredited investors.  In conjunction with the Notes private placement, a total of 1,190,000 Common Stock purchase warrants were issued at the rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.14 and were initially set to expire on January 29, 2015.  On January 29, 2015, the Company entered into agreements with the holders of all but one of the 12% Subordinated Notes and associated warrants to extend the maturity date of such holders’ notes and warrants to January 29, 2017.  During the years ended February 28, 2015 and 2014, two 12% Notes holders in aggregate exercised the warrants associated with the Notes, resulting in 50,000 and 100,000 Common Stock shares, respectively being issued to the Note holders.

Securities Authorized for Issuance under Equity Compensation Plan

The table below sets forth information regarding outstanding restricted stock awards for the year ended February 29, 2016.  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

⁽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 fiscal year 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 fiscal years 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 fiscal years 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.

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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.

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At February 29, 2016, 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 29, 2016 for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan issuances is set forth in the table below:

⁽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 year ended February 29, 2016, the Company recognized compensation expense related to the above restricted stock grants of $-0-.  There was no unamortized stock compensation expense remaining as of as of February 29, 2016.

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 29, 2016, one conversion of 10,000 shares of Series A Preferred occurred resulting in 30,000 shares of our Common Stock being issued.

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At February 29, 2016, there were 724,565 shares issued and outstanding that had not been converted into our Common Stock.  As of February 29, 2016, there were 43 accredited investors who had converted 675,200 Series A Preferred shares into 2,025,600 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.

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 fiscal year since issuance are set forth in the table below:

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.

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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 51,487,373 shares were issued and outstanding as of February 29, 2016.  In comparison, at February 28, 2015, a total of 51,457,373 shares were issued and outstanding.  This change of 30,000 shares was attributable as shown in the table below:

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

Maximilian Financing and Credit Facility

On October 31, 2012, the Company entered into a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment from Maximilian Investors LLC (either party, as appropriate, is referred to as “Maximilian”).  In connection with this loan, the Company also issued 2,435,517 warrants to third parties who assisted in the closing of the loan.  The warrants have an exercise price of $0.044; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on October 31, 2017.  On March 10, 2014, one of the third parties who assisted in this financing transaction exercised 2,118,900 warrants resulting in the issuance of 1,873,554 shares of Common Stock.

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 and entering into the amended loan agreement, 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 warrants have an exercise price of $0.10; contain a cash exercise provision and are exercisable for a period of three years expiring on August 28, 2016.

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The fair value of the 6.1 million warrants, as determined by the Black-Scholes option pricing model, was $898,299 and included the following assumptions: a risk free interest rate of 2.48%; stock price of $0.16, volatility of 184.53%; and a dividend yield of 0.0%.  The Company determined that the warrants were issued in connection with the increase in the Company’s borrowing limit and App’s $40 million revolving credit facility in connection with which the Company was granted a 25% working interest in App’s Kentucky properties.  Consequently, the fair value of the warrants was allocated to deferred financing costs and unproved oil and gas properties based on the amount of the increase in the revolving credit facility that is attributable to Daybreak and App.

The Company also issued 309,503 warrants to third parties who assisted in the closing of the amended and restated loan agreement with Maximilian.  The warrants have an exercise price of $0.214; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on August 28, 2018.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $47,420 and included the following assumptions: a risk free interest rate of 2.48%; stock price of $0.16, volatility of 184.53%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the revolving credit facility.

The fair value of the above warrant issuances that were recognized as a deferred financing cost are being amortized over the term of the loan.  Amortization expense was $127,513 for the years ended February 29, 2016 and February 28, 2015.  Unamortized deferred financing costs amounted to $191,270 as of February 29, 2016.

On February 14, 2014, the Company at the request of Maximilian, amended the warrant agreement related to the above issuance of approximately 6.1 million warrants to include a warrant exercise blocker provision that would effectively prevent any exercise of the warrants if such exercise and related issuance of Common Stock would increase the Maximilian holdings of the Company’s Common Stock to more than 9.99% of the currently issued and outstanding shares at the time of the exercise.  All other terms of the original warrant agreement remained unchanged.

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.  This share-for-warrant exchange occurred so that Maximilian would hold no more than 9.99% of the Company’s common shares, issued and outstanding.  The Company determined that the share-for-warrant exchange did not result in any incremental fair value.

On May 20, 2015, the Company entered into a Second Amendment to Amended and Restated Loan and Security Agreement (the “Second Amendment”) with Maximilian.  The Second Amendment modified the calculation of the required monthly payment for a three-month period ending June 30, 2015.  As consideration for entering into the loan modification, the Company agreed to modify the exercise price of the warrants Maximilian currently holds 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”).  As part of the Maximilian Amendment, the Company also agreed to extend the expiration date of the warrants held by Maximilian to purchase up to 6,550,281 shares of common stock of the Company 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.

12% Subordinated Notes – Warrant Expiration Extension

On January 29, 2015, 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.  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 of the original 13 noteholders had the expiration date of their warrants extended to January 29, 2017.  The fair value of the warrant extension, as determined by the Black-Scholes option pricing model, was $56,519 using the following weighted average assumptions: a risk free interest rate of 0.51%; volatility of 153.4%; and dividend yield of 0.0%.  The fair value of the warrants was recognized as a loss on settlement of debt.

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Warrants outstanding and exercisable as of February 29, 2016 are set forth in the table below:

During the years ended February 29, 2016 and February 28, 2015, a total of 150,000 and 60,000 warrants expired, respectively.  All of the expired warrants were associated with the 12% Subordinated Note offering and had been issued to investors or were for services associated with the offering.  There were no warrants issued during the year ended February 29, 2016.  During the year ended February 28, 2015 there were 427,729 warrants issued in connection with the share-for-warrant exchange agreement with Maximilian as described in Note 11 - Short-Term and Long-Term Borrowings.  The 2,168,900 warrants exercised in the year ended February 28, 2015 were issued (a) to a third party who assisted in the Maximilian financing (2,118,900) and (b) in conjunction with the 12% Subordinated Notes (50,000).  The outstanding warrants as of February 29, 2016 and February 28, 2015 have a weighted average exercise price of $0.06 and $0.11; a weighted average remaining life of 2.28 and 1.65 years; and an intrinsic value of $-0- and $14,564, respectively.

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ITEM 6.   SELECTED FINANCIAL DATA

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

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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 29, 2016 and February 28, 2015.  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 oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing 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 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 oil and natural gas properties as well as the prevailing sales prices for oil and natural gas along with associated operating expenses. The volatile nature of the energy markets makes it difficult to estimate future prices of 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 oil and natural gas properties and funding projects that we believe have the potential to produce 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 two multi-well oilfield projects; one in Lawrence County, Kentucky and the other in Kern County, California.

Our management cannot provide any assurances that Daybreak will ever operate profitably.  While we have positive cash flow from our continuing crude oil and natural gas operations in Kentucky and 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 29, 2016.

Throughout this Annual Report on Form 10-K, 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

This was a period of time that was full of challenges, primarily managing our dwindling cash flow in the face of declining hydrocarbon prices.  During the twelve months ended February 29, 2016, we were successful in accomplishing the following objectives:

·

Kentucky development program – We drilled and put on production one development well.  We also obtained a core from our development well while it was being drilled.  The core was analyzed and the results were factored into our fracturing program for this and future wells.

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·

Increasing our proven reserves – Our total proved reserves increased 1.6% or 14,644 BOE to 902,780 BOE.  Our proved undeveloped reserves (PUD) increased by 13% or 77,451 barrels to 671,002 (BOE) primarily due to the drilling of the one development well during the twelve months ended February 29, 2016.

Below is brief summary of our oil and natural gas projects in Kentucky and California.  Refer to our discussion in Item 2. Properties, in this Annual Report on Form 10-K for more information on both the Twin Bottoms Field in Lawrence County, Kentucky and our East Slopes Project in Kern County, California.

Lawrence County, Kentucky (Twin Bottoms Field)

The Twin Bottoms Field, comprising approximately 7,220 acres in two large contiguous blocks, is located in the Appalachian Basin of eastern Kentucky.  Log data from existing vertical natural gas wells in the field indicate the existence of proved oil reserves in the Berea Oil Sand, located at approximately 2,000 feet.  Since October 2013, we have participated in the drilling of 14 horizontal oil wells in this project.  The oil produced from our acreage in Kentucky is light crude oil measuring between 42° and 44° API (American Petroleum Institute) gravity.  During the year ended February 29, 2016, we had production from 14 wells.  Our average working interest and net revenue interest (“NRI”) in these 14 wells is 22.6% and 19.7%, respectively.  We are not the Operator of the Twin Bottoms Field project, but we rely on the experience of the current Operator and their knowledge of this Field.  However, we have our own personnel onsite during critical operations such as drilling, fracturing and completing operations.

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 oil produced from our acreage in the Vedder Sand is considered heavy oil.  The 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 29, 2016 we had production from 20 vertical 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.

Results of Operations – For the years ended February 29, 2016 and February 28, 2015

Hydrocarbon Prices

The price we receive for oil sales in both Kentucky and California is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs.  The price we receive for natural gas sales in Kentucky per Mcf is based on the Columbia Gas Transmission Corp. Appalachia Index (“TCO Appalachia”) whereby we will receive 76% of the TCO Appalachia price per dekatherm (DTH) less $0.25 compression cost for each Mcf of gas delivered.  We do not have any natural gas revenues in California.

Since June 2014, there has been a significant decline in the WTI price of crude oil and correspondently in the realized price we receive from oil sales.  This decline in the price of crude oil has had a substantial negative impact on our cash flow from both our Kentucky and California properties as shown in the table below.

Crude Oil and Natural Gas Revenue, Production and Realize Prices in Aggregate

Our revenues are derived entirely from the sale of our share of crude oil production in Kentucky and California and natural gas sales in Kentucky. Crude oil and natural gas revenues for the twelve months ended February 29, 2016 in aggregate decreased $1,830,111 or 59.4%, to $1,253,686 in comparison to revenues of $3,083,797 for the twelve months ended February 28, 2015.  Oil and natural gas sales volume decreased 7,849 BOE (barrels of oil equivalent) or 18.9% to 33,626 (BOE) in comparison to 41,476 (BOE) for the twelve months ended February 28, 2015.  The decrease in volume was primarily due to the natural decline in oil producing reservoir pressure.  Our average realized sale price on a BOE basis for the twelve months ended February 29, 2016 was $37.28 in comparison to $74.35 for the twelve months ended February 28, 2015, representing a decline of $37.07 or 49.9% per barrel.  Approximately $1.5 million or 84.0% of the decline in revenue can be directly attributed to the decline in hydrocarbon prices for the twelve months ended February 29, 2016.

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Kentucky Oil Prices

For the twelve months ended February 29, 2016, our average realized oil sale price was $46.40 in comparison to the average WTI price of $45.72 representing a premium of $0.68 per barrel or 1.5% higher than the average WTI price.  In comparison, for the twelve months ended February 28, 2015, the average WTI price was $85.12 and our average realized sale price was $80.82 representing a discount of $4.30 per barrel or 5.1% lower than the average WTI price.

Kentucky Oil Revenue and Production

Oil revenue in Kentucky for the twelve months ended February 29, 2016 decreased $1,053,531 or 60.7% to $680,869 in comparison to revenue of $1,734,400 for the twelve months ended February 28, 2015.  The average sale price of a barrel of oil for the twelve months ended February 29, 2016 was $46.40 in comparison to $80.82 for the twelve months ended February 28, 2015.  The decrease of $34.42 or 42.6% in the average realized price of a barrel of oil accounted for $738,600 or 70.1% of the decline in oil revenue while a decrease of $314,930 or 29.9% can be attributed to a decline in production for the twelve months ended February 29, 2016.

Our net sales volume for the twelve months ended February 29, 2016 was 14,673 barrels of oil in comparison to 21,460 barrels sold for the twelve months ended February 28, 2015.  This decrease in oil sales volume of 6,787 barrels or 31.6% was due to the natural decline in reservoir pressure partially offset by the addition of one new development well being put on production during the twelve months ended February 29, 2016.

The gravity of our produced oil in Kentucky ranges between 42° API and 44° API.  Production for the twelve months ended February 29, 2016 was from 14 wells resulting in 4,241 well days of production in comparison to 2,634 well days of production from 13 wells for the twelve months ended February 28, 2015.  The increase of 1,607 well days or 61.0% of production was due to gas pipeline infrastructure improvements within the Twin Bottoms Field and a full year of production time for 13 horizontal oil wells.

Kentucky Natural Gas Prices

For the twelve months ended February 29, 2016, our average realized natural gas sale price was $1.51 per Mcf (thousand cubic feet) in comparison to the average Henry Hub price of $2.64 per million BTU representing a discount of $1.13 per Mcf or 43.0% lower than the average Henry Hub price.  In comparison, for the twelve months ended February 28, 2015, the average realized sale price was $2.97 per Mcf in comparison to the average Henry Hub price of $3.99 per million BTU representing a discount of $1.02 or 25.5% lower than the average Henry Hub price.

Kentucky Natural Gas Revenue and Production

Natural gas revenue for the twelve months ended February 29, 2016 decreased $21,029 or 32.6% to $43,457 in comparison to revenue of $64,486 for the twelve months ended February 28, 2015.  The average sale price per Mcf for the twelve months ended February 29, 2016 was $1.51 in comparison to $2.97 for the twelve months ended February 28, 2015.

Our net sales volume for the twelve months ended February 29, 2016 was 28,853 Mcf or 4,809 BOE in comparison to 21,687 Mcf or 3,614 BOE for the twelve months ended February 28, 2015.  The increase in natural gas volume was due to having 13 horizontal wells on production during the twelve months ended February 29, 2016 and the resolution of infrastructure issues that had previously inhibited natural gas production from existing wells.

California Oil Prices

For the twelve months ended February 29, 2016, the average WTI price was $45.72 and our average realized oil sale price was $37.43, representing a discount of $8.29 per barrel or 18.1% lower than the average WTI price.  In comparison, for the twelve months ended February 28, 2015, the average WTI price was $85.12 and our average realized sale price was $78.34 representing a discount of $6.78 per barrel or 8.0% lower than the average WTI price.  Historically, the sale price we receive for California heavy oil has been less than the quoted WTI price because of the lower API gravity of our California oil in comparison to the API gravity of WTI oil.

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California Oil Revenue and Production

Oil revenue in California for the twelve months ended February 29, 2016 decreased $755,551 or 58.8% to $529,360 in comparison to revenue of $1,284,912 for the twelve months ended February 28, 2015.  The average sale price of a barrel of crude oil for the twelve months ended February 29, 2016 was $37.43 in comparison to $78.34 for the twelve months ended February 28, 2015.  The decrease of $40.92 or 52.2% in the average realized price of a barrel of oil accounted for $671,083 or 88.8% of the decline in oil revenue while a decrease of $84,469 or 11.2% can be attributed to a decline in production for the twelve months ended February 29, 2016.

Our net sales volume for the twelve months ended February 29, 2016 was 14,144 barrels of oil in comparison to 16,402 barrels sold for the twelve months ended February 28, 2015.  This decrease in oil sales volume of 2,258 barrels or 13.8% was primarily due to the natural decline in reservoir pressure during the twelve months ended February 29, 2016.

The gravity of our produced oil in California ranges between 14° API and 16° API.  Production for the twelve months ended February 29, 2016 was from 20 wells resulting in 7,210 well days of production in comparison to 7,225 well days of production for the twelve months ended February 28, 2015.

Our oil and natural gas revenues from Kentucky and California are set forth in the table below:

*Our average realized sale price on a BOE basis for the twelve months ended February 29, 2016 was $37.28 in comparison to $74.35 for the twelve months ended February 28, 2015, representing a decrease of $37.07 or 49.9% per barrel.

Of the $1,830,111 or 59.4% decline in revenue for twelve months ended February 29, 2016, approximately $1.5 million or 84.0% can be directly attributed to the decline in the price of crude oil and natural gas.

Operating Expenses

Total operating expenses increased $933,985 or 45.6% to $2,980,051 for the twelve months ended February 29, 2016 in comparison to $2,046,066 for the twelve months ended February 28, 2015.  As shown below, this increase in expenses was due to impairment recognition of oil and gas properties for $1,108,683.  Our operating expenses are set forth in the table below:

Production expenses include expenses associated with the production of 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 29, 2016, these expenses decreased $61,469, or 18.6% to $268,448 in comparison to $329,917 for the twelve months ended February 28, 2015.  For the twelve months ended February 29, 2016, we had 14 wells on production in Kentucky and 20 wells on production in California in comparison to 13 wells on production in Kentucky and 20 wells on production in California for the twelve months ended February 28, 2015.  Production expenses represented 8.5% of total operating expenses in comparison to 16.1% for the year ended February 28, 2015.

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Production expenses in Kentucky and California for the twelve months ended February 29, 2016 and February 28, 2015 are set forth in the table below:

Production expenses on a BOE basis in Kentucky and California for the twelve months ended February 29, 2016 and February 28, 2015 are set forth in the table below:

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses increased $33,056 or 76.9% to $76,053 for the twelve months ended February 29, 2016 in comparison to $42,297 for the twelve months ended February 28, 2015.  Exploration and drilling expenses represented 2.4% of total operating expenses in comparison to 2.1% for the twelve months ended February 28, 2015.

Depreciation, Depletion, Amortization (“DD&A”) expense relates to equipment, proven reserves and property costs, along with impairment and is another component of operating expenses.  These expenses decreased $52,240 or 9.2% to $517,870 for the twelve months ended February 29, 2016 in comparison to $570,110 for the year ended February 28, 2015.  This decrease is directly related to lower hydrocarbon prices and reduced production during the twelve months ended February 29, 2016.  On a BOE basis, DD&A in Kentucky was 14.21 and $17.04 in California.  In aggregate, DD&A for the twelve months ended February 29, 2016 was $15.40.  DD&A expenses represented 16.5% of total operating expenses in comparison to 27.9% for the twelve months ended February 28, 2015.

Impairment of proved and unproved oil properties in California for the twelve months ended February 29, 2016 was $1,108,683 for the twelve months ended February 29, 2016 in comparison to $-0- for the twelve months ended February 28, 2015.  On a BOE basis in aggregate, impairment of oil properties in California represented $32.97.  This impairment was caused by lower hydrocarbon prices resulting in lower economic reserve valuation and a reduction in our cash flows in California.  Impairment of oil properties represented 35.3% of total operating expenses.

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 increased $69,163 or 6.3% to $1,172,206 for the twelve months ended February 29, 2016 in comparison to $1,103,042 for the twelve months ended February 28, 2015.  Accounting, reserve reporting and legal expenses decreased by $57,255 in aggregate during the twelve months ended February 29, 2016.  Director fees decreased $12,125 due to fewer Board of Directors meetings.  Advertising, marketing and press release expense decreased by $8,590.  Rent, office supplies and postage decreased by $5,675.  These decreases were offset by the recognition of $169,340 in expenses associated with our refinancing efforts.  For the year ended February 29, 2016, we received, as Operator of the East Slopes project in California, administrative overhead reimbursement of $66,487, 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 approximately 37.3% of total operating expenses in comparison to 53.9% for the twelve months ended February 28, 2015.

Interest income decreased $41,352 or 3.8% to $1,039,862 for the twelve months ended February 29, 2016 in comparison to $1,081,214 for the twelve months ended February 28, 2015 primarily due to a lower loan balance and interest rate on the Note Receivable from App Energy, LLC.  For further discussion on this Note refer to the App Loan Agreement under the caption “Non-current Borrowings” in this MD&A.

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Interest expense increased $560,407 or 20.0% to 3,355,776 for the twelve months ended February 29, 2016 in comparison to $2,795,369 for the twelve months ended February 28, 2015 due to higher balances on our credit facility with Maximilian.  This financing transaction is discussed further in the MD&A section of this 10-K report under the caption “Non-current debt – Maximilian Loan.”

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.  The material adverse impact of lower crude oil prices on our revenues cannot be understated.  For the twelve months ended February 29, 2016 our sales volume on a BOE basis decreased by 18.9% while our revenues decreased 59.4% 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 reserve base and the market price of energy products.  G&A costs will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.  An ongoing goal throughout the Company is to improve cash flow to cover the current level of G&A expenses and to fund our development drilling in California and Kentucky.

Capital Resources and Liquidity

Our primary financial resource is our base of oil reserves. Our ability to fund our capital expenditure program is dependent upon the prices we receive from our oil and natural gas sales; the success of our development program in Kentucky; and the availability of capital resource financing.  In the next fiscal year, we plan on investing approximately $1.0 million in new capital expenditures; however our actual expenditures may vary significantly from this estimate if our plans for exploration and development activities change during the year.  Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.

Changes in our capital resources at February 29, 2016 are set forth in the table below:

Our working capital deficit increased by $11,678,512 or 202.9% from a deficit of $5,757,022 at February 28, 2015 to a deficit of $17,435,534 at February 29, 2016.  The increase in the working capital deficit is primarily related to the classification of the entire Maximilian credit facility balance of $14,309,180 as a current liability in accordance with guidance from ASC 470-10-45 as compared to $4,691,211 in current liabilities at February 28, 2015.  Partially offsetting this balance sheet presentation was the classification of $641,075 in net deferred financing costs being presented as a current asset.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not been made by us since December 2015.  Due to the waivers granted by Maximilian, we are currently not considered to be in default under terms of the credit facility.  Maximilian is continuing to work with us in modifying the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue.  Further, there can be no assurances that in the future Maximilian will not declare us to be in default under the credit facility.  While we continue to have ongoing positive cash flow from our oil and gas operations in Kentucky and California during this period of low hydrocarbon prices, we are unable to generate sufficient cash flow to cover all of our general and administrative (“G&A”) and interest expense requirements.  We cannot forecast when there will be a sustained improvement in crude oil and natural gas prices allowing us to implement a more aggressive drilling program in the Twin Bottoms Field in Lawrence County, Kentucky and our East Slope operations in Kern County, California.

Our business is capital intensive.  Our ability to grow is dependent upon favorably obtaining outside capital and generating cash flows from operating activities necessary to fund our investment activities.  There is no assurance that we will be able to achieve profitability.  Since our future operations will continue to be dependent on successful exploration and development activities and our ability to seek and secure capital from external sources, should we be unable to achieve sustainable profitability this could cause any equity investment in the Company to become worthless.

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Major sources of funds in the past for us have included the debt or equity markets.  While we have achieved positive cash flow from our operations in Kentucky and California, we will have to rely on these capital markets to fund future operations and growth.  Our business model is focused on acquiring exploration or development properties as well as existing production.  Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of oil and gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources.

Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments 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.

For the current fiscal year, we may seek additional forms of financing through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these instruments which could result in dilution to existing security holders and increased debt and leverage.  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.

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:

Cash Flow Provided by (Used in) Operating Activities

Cash flow from operating activities is derived from the production of our 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 29, 2016, cash used in our operating activities was $496,667 in comparison to cash flow provided by operating activities of $312,700 for the twelve months ended February 28, 2015.  This decrease in cash provided by operating activities of $809,367 was due to a decline in operating revenue of $1.8 million; a decrease in receivables and prepaids and the net loss offset by an increases in accounts payable.  Non-cash expenses increased by $965,726 in comparison to the twelve months ended February 28, 2015.  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 costs; production costs; 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 (Provided By) Investing Activities

Cash flow from investing activities is derived from changes in oil and gas property balances and our lending activities associated with the App Energy, LLC (“App”) loan.  Cash flow provided by investing activities for the twelve months ended February 29, 2016 was $636,034 in comparison to $2,717,083 used in investing activities for the twelve months ended February 28, 2015.  We invested approximately $171,000 million in our multi-well drilling program in Kentucky and collected $775,500 from App in payments on their advances in Kentucky.  Refer to the caption “Non-current debt – App Loan Agreement” for further discussion of the App loan.

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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 used in our financing activities was $629,144 for the twelve months ended February 29, 2016 in comparison to $2,400,724 provided by our financing activities for the year ended February 28, 2015.  For the twelve months ended February 29, 2016 we received advances of $25,000 on our credit facility and we made principal payments of $618,431 against the outstanding balance.  We anticipate it will continue to be necessary to rely on additional funding from the capital markets in the current fiscal year to maintain our current drilling program.  The following is a summary of cash flows provided by, and used in, the Company’s financing activities for the twelve months ended February 29, 2016.

Current debt (short-term borrowings)

Related Party

During the years ended February 29, 2012 and February 28, 2013, the Company’s President and Chief Executive Officer loaned the Company $250,100 in aggregate that has been used for a variety of corporate purposes including an escrow requirement on a loan commitment; extension fees on third party loans; and a reduction of principal on the Company’s credit line with UBS Bank.  These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.

Line of Credit

The Company has an existing $890,000 line of credit for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer.  At February 29, 2016 and February 28, 2015, the Line of Credit had an outstanding balance of $843,807 and $869,865, respectively.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $31,442 and  $31,498 for the years ended February 29, 2016 and February 28, 2015, respectively.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

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.  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, 2016.  The 12% Notes balances at February 29, 2016 and February 28, 2015 are set forth in the table below.

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 $0.14 and an amended expiration date of January 29, 2017.  The 12% Note warrants that have been exercised are set forth in the table below.

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Maximilian Loan

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 loan had annual interest of 18% and a monthly commitment fee of 0.5%.  The Company also granted Maximilian a 10% working interest in its share of the oil and gas leases in Kern County, California. The relative fair value of this 10% working interest amounting to $515,638 was recognized as a debt discount and is being amortized over the term of the loan. Amortization expense for the year ended February 29, 2016 amounted to $132,114.  Unamortized debt discount amounted to $71,951 as of February 29, 2016.

In 2012, the Company also issued 2,435,517 warrants to third parties who assisted in the closing of the loan.  The warrants have an exercise price of $0.044; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on October 31, 2017.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $98,084 and included the following assumptions: a risk free interest rate of 0.72%; stock price of $0.04, volatility of 153.44%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the loan.  Amortization expense for the year ended February 29, 2016 amounted to $127,513.  Unamortized deferred financing cost of these warrants was $191,270 as of February 29, 2016.  There were 316,617 of these warrants that remained unexercised as of February 29, 2016.

Maximilian Loan - Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App Energy, LLC (“App”) in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013.  The amended loan agreement provided for an increase in the revolving credit facility from $20 million to $90 million and a reduction in the annual interest rate from 18% to 12%.  The monthly commitment fee of 0.5% per month on the outstanding principal balance remained unchanged.  Advances under the amended loan agreement will mature on August 28, 2017.  The obligations under the amended loan agreement continue to be secured by a perfected first priority security interest in substantially all of the personal property of the Company, and a mortgage on the Company’s leases in Kern County, California.  The amended loan agreement also provided for the revolving credit facility to be divided into two borrowing sublimits.  The first borrowing sublimit is $50 million and is for borrowing by the Company, primarily for its ongoing oil and gas exploration and development activities.  The second borrowing sublimit, of $40 million, is for loans to be extended by the Company, as lender, to App, as borrower pursuant to a Loan and Security Agreement entered into between the Company and App on August 28, 2013 (See the caption “App Loan Agreement” in the discussion below for further information).

The amended loan agreement contains customary covenants for loan of such type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The amended loan agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of the Company’s obligations under the amended loan agreement could be accelerated by Maximilian, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

As consideration for Maximilian facilitating the Company’s transactions with App and entering into the amended loan agreement, the Company (a) issued to Maximilian, approximately 6.1 million common shares representing 9.99% of the Company’s outstanding common stock on a fully-diluted basis at the time of grant, and (b) issued 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 warrants had an exercise price of $0.10; contain a cash exercise provision; were exercisable for a period of three years expiring on August 28, 2016; and contain an exercise provision blocker provision that prevents any exercise of the warrants if such exercise and related issuance of Common Stock would increase the Maximilian holdings of the Company’s Common Stock to more than 9.99% of the Company’s currently issued and outstanding shares at the time of the exercise.  The Company also granted to Maximilian a 50% net profits interest in the Company’s 25% working interest, after the Company recovers its investment, in the Company’s working interest in its Kentucky properties, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.

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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 deferred financing costs as of the date of amendment of approximately $400,349 and the new deferred financing costs, as mentioned above, are being amortized over the term of the amended loan agreement.

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.  This share-for-warrant exchange occurred so that Maximilian would hold no more than 9.99% of the Company’s common shares issued and outstanding.  The Company determined that the share-for-warrant exchange did not result in any incremental fair value.

On August 21, 2014, the Company entered into a First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement (the “Amendment”) with Maximilian under its Amended and Restated Loan and Security Agreement dated as of August 28, 2013.  The Amendment secured for the Company an additional advance of $2,200,000 under its credit facility with Maximilian since the advances made by Maximilian had already exceeded its minimum funding commitment. Additionally, Maximilian agreed to temporarily decrease the required monthly payment made by the Company until it had paid $1,000,000 less than the principal payments required by the previous agreement.  Furthermore, Maximilian agreed to reduce the regular interest rate applicable to the loan from 12% per annum to 9% per annum and the default interest rate by 3%.

The additional advance, the reduction in the required monthly payment and the reduction in the interest rate were facilitated through our acquisition of 5,694,823 shares of our common stock held by Maximilian.  The repurchased shares were cancelled and restored to the status of authorized but unissued stock.  We paid for the share repurchase transaction through an advance of $1,708,447 under the existing loan agreement with Maximilian.

On May 20, 2015, the Company entered into a Second Amendment to Amended and Restated Loan and Security Agreement (the “Second Amendment”) with Maximilian.  The Second Amendment modified the calculation of the required monthly payment for a three-month period ending June 30, 2015.  As consideration for entering into the loan modification, the Company agreed to modify the exercise price of the warrants Maximilian currently holds 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.  The reduction in monthly payments allows for additional funds to be used by the Company in drilling and completing additional wells in Kentucky.  As consideration for the reduction in the monthly payment amount, the Company agreed that twenty percent (20%) of the amount by which the monthly payment was reduced would be added to the loan balance, and the portion of the monthly payment savings that constitutes savings in interest or commitment fees would be treated as an additional advance of principal under the loan agreement (the “Deemed Advances”).  The 20% fee is being recognized as additional interest expense.  The Company also agreed to grant to Maximilian an overriding royalty interest of 1.5% of its working interest in four wells in Kentucky.  As part of the Maximilian Amendment, the Company also agreed to extend the expiration date of the warrants held by Maximilian to purchase up to 6,550,281 shares of common stock of the Company 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.

As a result of the decline in hydrocarbon prices, we are currently unable to make the interest or principal payments required under the terms of our credit facility with our lender, Maximilian.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not been made.  Due to the waivers granted by Maximilian, the Company is currently not considered to be in default under terms of the credit facility.  Maximilian is continuing to work with the Company in modifying the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue.  Further, there can be no assurances that Maximilian will not declare the Company to be in default under 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.

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Current debt balances at February 29, 2016 and February 28, 2015 are set forth in the table below:

Non-current debt balances at February 29, 2016 and February 28, 2015 are set forth in the table below:

App Loan Agreement

In connection with amending and restating its loan agreement with Maximilian, on August 28, 2013 the Company extended to App Energy, LLC, a Kentucky limited liability company (“App”) a credit facility for the development of a shallow oil project in an existing gas field in Lawrence County, Kentucky pursuant to a Loan and Security Agreement between the Company as lender and App as borrower (the “App Loan Agreement”).

The App Loan Agreement provides for a revolving credit facility of up to $40 million, maturing on August 28, 2017, with a minimum commitment of $2.65 million (the “Initial Advance”).  All funds advanced to App, as borrower, by Daybreak, as lender, are to be borrowed by Daybreak under its Amended Loan Agreement with Maximilian.  The Initial Advance bears interest at a rate per annum equal to 16.8%, and subsequent loans under the Loan Agreement bear interest at a rate per annum equal to 12%.  The App Loan Agreement also provides for a monthly commitment fee of 0.6% per month of the outstanding principal balance of the loans.  The obligations under the App Loan Agreement are secured by a perfected first priority security interest in substantially all of the assets of App, including the Company’s leases in Lawrence County, Kentucky.

The proceeds of the initial borrowing by App of $2.65 million under the App facility were primarily used to (a) pay loan fees and closing costs, (b) repay indebtedness and (c) finance the drilling of three wells by App in the Twin Bottoms Field in Lawrence County, Kentucky in which the Company has a 25% working interest.  Future advances under the facility will primarily be used for oil and gas exploration and development activities.

The App Loan Agreement contains customary covenants for loan of such type, including, among other things, covenants that restrict App’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The App Loan Agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of App’s obligations under the App Loan Agreement could be accelerated by the Company, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

In connection with the App Loan Agreement, App also granted to the Company the 25% working interest in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky and entered into a corresponding promissory note and a Mortgage, Leasehold Mortgage, Assignment of Production, Security Agreement and Financing Statement, both dated as of August 28, 2013.  App’s manager, John A. Piedmonte, Jr., also entered into a limited Indemnity Agreement in connection with the loan.  The loans under the App Loan Agreement are also guaranteed by certain of App’s affiliates.

On August 21, 2014, a First Amendment to the Loan and Security Agreement by and between the Company and App was executed whereby Section 1.5 (f) of the original Loan and Security Agreement was deleted and intentionally left blank. The affected section removed App’s ability to have the Required Monthly Payment be equal to zero for a maximum of three payments.  All other terms of the original agreement remained unchanged.

On May 20, 2015, a Second Amendment to the Loan and Security Agreement by and between Daybreak and App was executed whereby the Required Monthly Payment definition was modified for the months of March, April, May and June of 2015.  All other terms of the original agreement remained unchanged.

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In connection with entering into the Third Amendment with Maximilian, the Company concurrently entered into a Third Amendment to Loan and Security Agreement with App Energy (the “App Amendment”), which amended the Company’s loan agreement with App Energy in which the Company, as lender, lends to App Energy, as borrower, a portion of the advances it receives pursuant to its loan agreement with Maximilian.  The App Amendment provides for a reduction in interest rate and a reduction in monthly payments to be made by App Energy to the Company for the same payment cycles as the reduced payment to be made by the Company under the Maximilian Amendment.  The reduction in monthly payments by App Energy will allow App Energy to fund its share of drilling and completing additional wells in Kentucky with the Company.  As consideration for the reduction in the monthly payment amount, App Energy agreed that certain amounts will be treated as additional advances under the App Energy loan agreement, and that it would fund a portion of the Company’s drilling and development expenses with respect to two wells.  App Energy also agreed to grant to Maximilian an overriding royalty interest on the same terms as the overriding royalty interest agreed to by the Company.

For the twelve months ended February 29, 2016, we received principal payments of $777,500 from App Energy.  Since November 2015, App Energy has been unable to make any required interest or principal payments under terms of the amended loan agreements, but is not considered to be in default under the terms of the amended agreements because Daybreak has granted a series of waivers for the required payments as App Energy seeks to refinance their loan with alternative lenders.  The Company retains all of its rights under the loan agreements to declare App Energy in default on the loan in the future.  The App Energy loan is secured by a perfected first priority security interest in substantially all of the assets of App Energy, including its leases in Lawrence County, Kentucky.

Note receivable balances at February 29, 2016 and February 28, 2015 are set forth in the table below:

Capital Commitments

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

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement 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 a mortgage on our leases in Kern County, California.  This includes mortgages on the Sunday, Bear, Black, Ball and Dyer Creek Properties in California.  For further information on the loan agreement with Maximilian refer to the discussion above under the caption “Current debt (short-term borrowings)” in this MD&A.

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.

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At February 29, 2016, 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 29, 2016.  For the years ended February 29, 2016 and February 28, 2015, an aggregate of -0- and 106,250 shares vested, respectively.  A summary of the 2009 Plan issuances is set forth in the table below:

⁽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 years ended February 29, 2016 and February 28, 2015, the Company recognized compensation expense related to the above-restricted stock grants of $-0- and $2,515, respectively.  There was no unamortized stock compensation expense remaining as of as of February 29, 2016.

Oil and Natural Gas Reserves

Daybreak’s total net proved developed and undeveloped oil and natural gas reserves on a barrel of oil equivalent (“BOE”) basis increased by 14,644 barrels, or 1.6%, to 902,780 barrels at February 29, 2016 compared to 888,136 BOE at February 28, 2015.  Our Kentucky, Twin Bottoms Field, project added 43,186 net barrels of oil and 523,160 net Mcf of natural gas or an additional 130,379 net BOE in aggregate to our proved reserve base after adjusting for extensions, revisions and production.  The proved reserve base in California declined by 115,735 barrels of oil due to reserve revisions and production.  Net proved developed reserves in aggregate decreased by 62,807 BOE or 21.3%, to 231,778 BOE at February 29, 2016 compared to 294,585 BOE at February 28, 2015.  This net decrease was caused by 33,627 BOE of production and 37,317 BOE of downward revisions from lower hydrocarbon prices offset by 8,137 BOE of extensions in Kentucky.  Net proved undeveloped reserves increased by 77,451 BOE or 13.0% to 671,002 BOE at February 29, 2016 in comparison to 593,551 at February 28, 2015. This net increase in proved undeveloped reserves was from 95,020 BOE in extensions in Kentucky offset by downward revisions of 17,569 in aggregate.  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 29, 2016, we received crude oil and natural gas sales revenue from 14 wells in Lawrence County, Kentucky and 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 a significant decline in the WTI price of crude oil and correspondently in the realized price we receive from oil sales.  This decline in the price of crude oil has had a substantial negative impact on our cash flow from both our Kentucky and California properties.  During the year ended February 29, 2016, oil and natural gas revenues in aggregate decreased $1,830,111 or 59.4%, to $1,253,686.  Approximately $1.5 million or 84.0% of the decline in revenue can be directly attributed to the decline in hydrocarbon prices for the twelve months ended February 29, 2016.  An additional consequence of lower hydrocarbon prices was the recognition of $1,108,683 in impairment of proved and unproved oil properties in California.  These two factors were the primary reasons why we incurred an operating loss of $1,889,574 for the twelve months ended February 29, 2016 in comparison to an operating profit of $1,037,731 for the twelve months ended February 28, 2015.

Our balance sheet at February 29, 2016 reflects total assets of $9,601,079 a decrease of $2,711,982 or 22.0% in comparison to $12,313,061 at February 28, 2015.  This decrease in total assets is comprised primarily of a $1.3 million decrease in oil and gas properties due to DD&A and impairment; a $0.5 million decrease in cash and an approximate $318,000 decrease in accounts receivable and prepaid expenses in aggregate.

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At February 29, 2016, total liabilities were $18,991,068, an increase of approximately $1.5 million or 8.5% in comparison to $17,497,651 at February 28, 2015.  This increase was primarily comprised of a $1.0 million increase in our credit line facility balance and approximate $420,000 increase in our accounts payable.