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 28, 2017

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

For the transition period from ______ to _______

Commission file number 000-50107

DAYBREAK OIL AND GAS, INC.

(Exact name of registrant as specified in its charter)

Washington	91-0626366
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1101 N. Argonne Road, Suite A 211, Spokane Valley, WA	99212
(Address of principal executive offices)	(Zip code)

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

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

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

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

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

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

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

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

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company þ

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 $0.03 on August 31, 2016, as reported by the Over-the-Counter Market was $1,420,667.

At May 26, 2017, the registrant had 51,532,364 outstanding shares of $0.001 par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

TABLE OF CONTENTS

		PAGE
PART I		4
ITEM 1.	BUSINESS	4
ITEM 1A.	RISK FACTORS	10
ITEM 1B.	UNRESOLVED STAFF COMMENTS	20
ITEM 2.	PROPERTIES	21
ITEM 3.	LEGAL PROCEEDINGS	29
ITEM 4.	MINE SAFETY DISCLOSURES	29
PART II		30
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	30
ITEM 6.	SELECTED FINANCIAL DATA	37
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	38
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	53
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	54
	Balance Sheets as of February 28, 2017 and February 29, 2016	55
	Statements of Operations for the Years Ended February 28, 2017 and February 29, 2016	56
	Statements of Changes in Stockholders’ Deficit for the Years Ended February 28, 2017 and February 29, 2016	57
	Statements of Cash Flows for the Years Ended February 28, 2017 and February 29, 2016	58
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	79
ITEM 9A.	CONTROLS AND PROCEDURES	80
ITEM 9B.	OTHER INFORMATION	81
PART III		82
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE	82
ITEM 11.	EXECUTIVE COMPENSATION	87
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	92
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	94
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	96
PART IV		97
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	97
GLOSSARY OF TERMS		99
SIGNATURES		102

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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 crude oil and natural gas properties.

We have based these forward-looking statements on assumptions and analyses made in light of our experience and our perception of historical trends, current conditions, and expected future developments.  However, you should be aware that these forward-looking statements are only our predictions and we cannot guarantee any such outcomes.  Future events and actual results may differ materially from the results set forth in or implied in the forward-looking statements.  Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

·

General economic and business conditions;

·

Exposure to market risks in our financial instruments;

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

Our ability to continue as a going concern;

·

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

·

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

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

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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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 crude oil and natural gas industry.  In October of 2005, to better reflect this new direction of the Company, our shareholders approved changing our name to Daybreak Oil and Gas, Inc.  Our Common Stock is quoted on the OTC Pink marketplace under the symbol DBRM.

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

Crude Oil and Natural Gas Overview

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

Our long-term success depends on, among many other factors, the acquisition and drilling of commercial grade crude oil and natural gas properties and on the prevailing sales price for crude oil and natural gas along with associated operating expenses.  The volatile nature of the energy markets makes it difficult to estimate future prices of crude oil and natural gas; however, any prolonged period of depressed prices, such as we have experienced since June of 2014, does have a material adverse effect on our results of operations and financial condition.

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

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

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

In January 2017, Daybreak acquired a 30% working interest in 1,400 acres in the Michigan Basin where we have two shallow crude oil prospects.  The leases have been secured and multiple targets have been identified through a 2-D seismic interpretation.  A 3-D seismic survey was obtained in January and February of 2017.  An analysis of the seismic survey confirmed the prospect identified on the 2-D seismic, as well as identified several additional drilling locations.  We will obtain an additional 3-D survey to better delineate the other locations before a drilling program commences.  The wells will be drilled vertically with conventional completions and no hydraulic fracturing will be required.  The first well is expected to be drilled during the late summer of 2017.

Known Trends and Uncertainties

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

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

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

California Crude Oil Prices

The price we receive for crude oil sales in California is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) crude oil Cushing, Oklahoma delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs.  We do not have any natural gas revenues in California.

There has been a significant amount of volatility in hydrocarbon prices and dramatic decline in our realized sale price of crude oil since June of 2014 when the monthly average price of WTI oil was $105.79 per barrel.  This decline in the price of crude oil as shown below has had a substantial negative impact on our cash flow from our producing California properties.  A comparison of the average WTI price, average realized crude oil sales price for the twelve months ended February 28, 2017 with adjusted revenue from the twelve months ended February 29, 2016 sales volume is shown in the table below:

	Twelve Months Ended
	February 28, 2017		February 29, 2016		Percentage Change
Average WTI crude oil price	$	46.81	$	45.71	2.4%
Average realized crude oil sales price (Bbl)	$	37.03	$	37.43	(1.1%)
Crude oil revenue (Adjusted for FY 2015-16 volume)	$	523,772	$	529,360	(1.1%)

5

For the twelve months ended February 28, 2017, the average WTI price was $46.81 and our average realized crude oil sale price was $37.03, representing a discount of $9.78 per barrel or 20.9% lower than the average WTI price.  In comparison, for the twelve months ended February 29, 2016, the average WTI price was $45.71 and our average realized sale price was $37.43 representing a discount of $8.28 per barrel or 18.1% lower than the average WTI price.

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

For the twelve months ended February 28, 2017 California crude oil revenues declined $46,704 to $482,656 in comparison to revenues of $529,360 for the twelve months ended February 29, 2016.  Of the $46,704 decline in revenue approximately 12.0% of the decline can be directly attributed to the decline in realized crude oil 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, our lender is under no obligation to advance us any additional funding and, rather, there can be no assurances that out lender will not declare the Company to be in default under the credit facility.  A change of control or management of our lender, among other reasons, could also result in our loan being called due and payable.

Competition

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

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

Significant Customers

At our East Slopes Project, located in Kern County, California, there is only one buyer available for the purchase of our crude oil production.  At February 28, 2017 and February 29, 2016, this one individual customer represented 100% of crude oil sales receivable.  If this local purchaser is unable to resell their products or if they lose a significant sales contract then we may incur difficulties in selling our crude oil production.

The Company’s accounts receivable from continuing operations in California for crude oil sales at February 28, 2017 and February 29, 2016 are set forth in the table below.

		February 28, 2017			February 29, 2016
Project	Customer	Accounts Receivable Crude Oil Sales		Percentage	Accounts Receivable Crude Oil Sales		Percentage
California – East Slopes Project (Crude oil)	Plains Marketing	$	83,405	100.0%	$	39,168	100.0%

6

Title to Properties

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

Encumbrances

The Company’s debt obligations, pursuant to the credit facility loan agreement and promissory notes with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC, a Delaware limited liability company, as lender, (either party, as appropriate, is referred to in this annual report on Form 10-K as “Maximilian”), and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company and two mortgages; one covering our leases in California and the other covering our leases in Michigan.  For further information on the loan agreement refer to the discussion under the caption “Current debt (short-term borrowings)” found in the MD&A section of this Form 10-K.

Regulation

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

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

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

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

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

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

7

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  Hydraulic fracturing typically is regulated by state crude oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuel.  At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities.  If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

Operational Hazards and Insurance

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

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

Employees and Consultants

At February 28, 2017, we had six full-time employees.  Additionally, we regularly use the services of four consultants on an as-needed basis for accounting, technical, oil field, geological, investor relations and administrative services.  None of our employees are subject to a collective bargaining agreement.  In our opinion, relations with our employees are good.  We may hire more employees in the future as needed.  All other services are currently contracted for with independent contractors.  We have not obtained “key person” life insurance on any of our officers or directors.

Long-Term Success

Our long-term success depends on the successful acquisition, exploration and development of commercial grade crude oil and natural gas properties as well as the prevailing prices for crude oil and natural gas to generate future revenues and operating cash flow.  Crude oil and natural gas prices 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 crude 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 crude oil and natural gas exploration and development industry.

Availability of SEC Filings

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

8

Website / Available Information

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

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

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

Daybreak Oil and Gas, Inc.

1101 N. Argonne Road, Suite A 211

Spokane Valley, WA 99212-2699

Attention: Corporate Secretary

Telephone: (509) 232-7674

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

9

ITEM 1A.   RISK FACTORS

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

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

Our revenues, operating results, liquidity, cash flows, profitability and valuation of proved reserves depend substantially upon the market prices of crude oil and natural gas.  Product prices affect our cash flow available for capital expenditures and our ability to access funds through the capital markets.  Declines in commodity prices have historically adversely affected the estimated value of our proved reserves and our cash flows.  The 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.  Specifically, the average realized price of WTI crude oil for the twelve months ended February 28, 2017 was $37.03 in comparison to the average realized price of $37.43 for the twelve months ended February 29, 2016.

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

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

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market uncertainty;

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the level of consumer product demands;

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hurricanes and other weather conditions;

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domestic governmental regulations and taxes;

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the foreign supply of crude oil and natural gas

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the price of crude oil and natural gas imports; and

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overall domestic and foreign economic conditions.

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

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

We have reported a net loss of approximately $3.5 million for the year ended February 28, 2017, and we have an accumulated deficit through February 28, 2017 of approximately $35.9 million.  Without successful exploration and development of our properties and a significant sustained increase in hydrocarbon prices any investment in Daybreak could become devalued or worthless.

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

At February 28, 2017, we had approximately $14.1 million of consolidated indebtedness comprised of a variety of short-term and long-term borrowings; related party notes and payables; a line of credit; trade payables; and 12% Subordinated Notes.  The level of indebtedness we have affects our operations in a number of ways.  We will need to use a portion of our cash flow to meet principal, interest and payables commitments; which reduces the amount of funds we will have available to finance our operations.  This lack of funds limits planning for or reacting to changes in our

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business and the industry in which we operate and could limit our ability to make funds available for other purposes, such as future exploration, development or acquisition activities.  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.  A series of waivers have been granted by our credit facility lender for the principal and interest payments that have not been made.  Due to the waivers granted by our lender, the Company is currently not considered to be in default under terms of the credit facility.  There can be no assurances that these waivers will continue to be granted in the future.  Further, our lender is under no obligation to advance us any additional funding and, rather, there can be no assurances that out lender will not declare the Company to be in default under the credit facility.  A change of control or management of our lender, among other reasons, could also result in our loan being called due and payable.  Our ability to meet our debt service obligations and reduce our total indebtedness will depend upon our future performance.  Our future performance, in turn, is dependent upon many factors that are beyond our control such as the level of hydrocarbon prices and general economic, financial and business conditions.  We cannot guarantee that our future performance will not be adversely affected by such economic conditions and financial, business and other factors.

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

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

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

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

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

Commodity prices have a significant impact on the present value of our proved reserves.  Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our crude oil and natural gas properties in certain situations.  We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets.  To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required.  Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred.  For the twelve months ended February 29, 2016, we recognized a non-cash impairment expense of $1.1 million on our California crude oil properties due to lower hydrocarbon price declines.

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

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

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

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access capital markets;

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recruit more qualified personnel;

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

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

·

acquire and evaluate larger volumes of critical information; and

·

compete for industry-offered business ventures.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The SEC generally requires that any undrilled location can be classified as a proved undeveloped reserve only if a development plan has been adopted indicating that the location is scheduled to be drilled within five years.  The recent reduction of our drilling program in response to depressed crude oil and natural gas process is likely to impact our ability to develop proved undeveloped reserves within such five-year period.  If we continue our limited drilling plans over a significant period of time our future access to capital resources is limited, we will also likely further delay our development of our proved undeveloped reserves or ultimately suspend such development which could result in the reclassification of a significant amount of our proved undeveloped reserves as probable or possible reserves.  A significant reclassification of proved undeveloped reserves could adversely affect the value of our properties.  Since June 2014, an aggregate of 33,254 barrels of crude oil reserves in California have been reclassified to unproved reserves due to the decline in hydrocarbon prices.

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

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

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

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

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

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

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

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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;

·

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

·

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

·

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

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

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

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

All of our properties are held under interests in crude oil and natural gas mineral leases.  If we fail to meet the specific requirements of any lease, such lease may be terminated or otherwise expire.  We cannot be assured that we will be able to meet our obligations under each lease.  The termination or expiration of our “working interests” (interests created by the execution of an crude 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 crude oil and natural gas leases worthless; thus damaging the financial condition of our business.

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

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

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

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

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

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

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

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

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

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

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

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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 crude oil and natural gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation.  Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.

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

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

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

Moreover, in November 2016, the EPA issued a final ICR seeking information about methane emissions from facilities and operations in the crude oil and natural gas industry.  The EPA has indicated that it intends to use the information from this request to develop Existing Source Performance Standards for the oil and natural gas industry.  Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France to prepare an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020.  This “Paris agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions.

The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that require reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could cause us to incur increased costs that could have an adverse effect on our business, financial condition and results of operations.  Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the crude oil or natural gas we produce and lower the value of our reserves.  Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, 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.  At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.

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

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

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

Our financial statements for the year ended February 28, 2017 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 tentatively 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 was a result of a cost-savings move for 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 crude oil and natural gas exploration and development industry including volatility in crude oil and natural gas prices, and other events or factors.  The decline 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.

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

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

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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 28, 2017, 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:

·

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

·

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

·

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

·

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

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

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

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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 crude oil and natural gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues.  Crude oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of crude oil and natural gas production are destroyed or damaged.  Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

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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 crude oil assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.  During the year ended February 28, 2017, we were involved in continuing operations of an oilfield project Kern County, California.

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

In January 2017, Daybreak acquired a 30% working interest in 1,400 acres in the Michigan Basin where we have two shallow crude oil prospects.  The leases have been secured and multiple targets have been identified through a 2-D seismic interpretation.  A 3-D seismic survey was obtained in January and February of 2017.  An analysis of the seismic survey confirmed the prospect identified on the 2-D seismic, as well as identified several drilling locations.  We will obtain an additional 3-D survey to better delineate the other locations before a drilling program commences.  The wells will be drilled vertically with conventional completions and no hydraulic fracturing will be required.  The first well is expected to be drilled during the late summer of 2017.

We have not filed any estimates of total, proved net crude oil or natural gas reserves with any federal agency other than this report to the SEC for the fiscal year ended February 28, 2017.  Throughout this Annual Report on Form 10-K, crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).

Kern County, California (East Slopes Project)

The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California.  Drilling targets are porous and permeable sandstone reservoirs that exist at depths of 1,200 feet to 4,500 feet.  Since January 2009, we have participated in the drilling of 25 wells in this project.  We have been the Operator at the East Slopes Project since March 2009.

Our 20 vertical crude oil wells in the East Slopes Project produce from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations.  The Sunday property has six producing wells, while the Bear property has nine producing wells.  The Black property is the smallest of all currently producing reservoirs, and currently has two producing wells at this property.  The Ball property also has two producing wells while the Dyer Creek property has one producing well.  Our average working interest and NRI in these 20 producing crude oil wells is 36.6% and 28.5%, respectively.

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

Sunday Central Processing and Storage Facility

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

By utilizing the Sunday centralized production facility our average operating costs have been reduced from over $40 per barrel in 2009 to under $13 per barrel of crude oil for the year ended February 28, 2017.  With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

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California Producing Properties

Sunday Property

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

Bear Property

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

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 $75,000 in new capital investments within the East Slopes Project area in the 2017-2018 fiscal year.

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Michigan Acreage Acquisition

In January 2017, Daybreak acquired a 30% working interest in 1,400 acres in the Michigan Basin where we have two shallow crude oil prospects.  The leases have been secured and multiple targets have been identified through a 2-D seismic interpretation.  A 3-D seismic survey was obtained in January and February of 2017.  An analysis of the seismic survey confirmed the prospect identified on the 2-D seismic, as well as identified several additional drilling locations.  We will obtain an additional 3-D survey to better delineate the other locations before a drilling program commences.  The wells will be drilled vertically with conventional completions and no hydraulic fracturing will be required.  The first well is expected to be drilled during the late summer of 2017.

Encumbrances

The Company’s debt obligations, pursuant to a credit facility loan agreement and promissory notes with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC, a Delaware limited liability company, as lender, (either party, as appropriate, is referred to in this Annual Report on Form 10-K as “Maximilian”), and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and two mortgages; one covering our leases in California and the other covering our leases in Michigan.  For further information on the loan agreement refer to the discussion under the caption “Current debt (short-term borrowings)” in the MD&A portion of this Annual Report on Form 10-K.

Reserves

Crude oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).  The following table sets forth our estimated net quantities of proved reserves as of February 28, 2017.

On October 31, 2016, we sold our non-operated working interest in crude oil and natural gas properties located in the Twin Bottoms Field in Lawrence County, Kentucky.  As of February 28, 2017, our total reserves were comprised of our interests in East Slopes Project located in Kern County, California.

	Proved Reserves
Reserve Category	Crude Oil (Barrels)	Natural Gas (Mcf)	Total Crude Oil Equivalents (BOE)	Percent of Oil Equivalents (BOE)
Developed	99,710	-	99,710	26.2%
Undeveloped	281,360	-	281,360	73.8%
Total Proved	381,070	-	381,070	100.0%

Changes in our estimated net proved reserves for the twelve months ended February 28, 2017 are set forth in the table below.

	Proved Reserves (BOE)
Balance as of February 29, 2016		902,780
Revisions		(13,145)
Discoveries and extensions		-
Production		(21,628)
Sales of minerals		(486,937)
Balance as of February 28, 2017		381,070

Revisions. Net downward revisions of 13,145 BOE in aggregate were due to lower realized hydrocarbons prices in California during the twelve months ended February 28, 2017 decreasing the economic life of our proved reserves.

Discoveries and extensions. For the twelve months ended February 28, 2017, there were no discoveries or extensions in California.

Production. Production in Kentucky was 8,622 BOE and 13,035 BOE in California representing 21,628 BOE in aggregate of proved reserves for the twelve months ended February 28, 2017.

Sales of minerals. During the twelve months ended February 28, 2017, we sold our crude oil and natural gas interest in Kentucky consisting of 486,937 BOE in aggregate of proved reserves.

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As of February 28, 2017, our total proved undeveloped reserves were comprised of our interests in Kern County, California.

Changes in our estimated net proved undeveloped reserves for the twelve months ended February 28, 2017 are set forth in the table below.

	Proved Undeveloped Reserves (BOE)
Balance as of February 29, 2016	671,002
Revisions	(13,063)
Discoveries and extensions	-
Sales of minerals	(376,579)
Reclassified to proved developed	-
Balance as of February 28, 2017	281,360

Revisions. There were net downward revisions of 13,063 BOE in aggregate due to lower realized hydrocarbons prices during the twelve months ended February 28, 2017 decreasing the economic life of our proved undeveloped reserves.

Discoveries and extensions. For the twelve months ended February 28, 2017, there were no discoveries or extensions in California.

Sales of minerals. During the twelve months ended February 28, 2017, we sold our crude oil and natural gas interest in Kentucky consisting of 376,579 BOE in aggregate of proved undeveloped reserves.

Our estimated net proved developed producing reserves of continuing operations in California at February 28, 2017 are set forth in the table below.

	Proved Developed Reserves
		Natural	Total Oil	Percent of Oil
Location	Oil (Barrels)	Gas (Mcf)	Equivalents (BOE)	Equivalents (BOE)
California	99,710	-	99,710	100.0%

Our estimated net proved undeveloped reserves of continuing operations in California at February 28, 2017 are set forth in the table below.

	Proved Undeveloped Reserves
		Natural	Total Oil	Percent of Oil
Location	Oil (Barrels)	Gas (Mcf)	Equivalents (BOE)	Equivalents (BOE)
California	281,360	-	281,360	100.0%

The Company has 28,880 Bbls of proved undeveloped reserves that have remained undeveloped for a period greater than five years.  These proved undeveloped reserves have remained undeveloped due to the period of depressed crude oil and natural gas prices that we are currently experiencing resulting in a lack of capital available for drilling.  Under our current drilling plans, we intend to convert all 381,070 BOE or 100.0% of the proved undeveloped reserves disclosed as of February 28, 2017 to proved developed reserves within the next five years.

Our estimated proved reserves (BOE) and PV-10 valuation of continuing operations in California at February 28, 2017 are set forth in the table below.

	Proved Reserves
				PV-10 as a
	Total Oil	PV-10 of		Percentage of
Location	Equivalents (BOE)	Proved Reserves		Proved Reserves
California	381,070		1,722,340	100.0%

The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10”), was approximately $1.7 million at February 28, 2017 a decline of approximately $200,000 or 10.3% from the PV-10 reserve valuation at February 29, 2016.  This decline is primarily due to the decline in our average realized price of crude oil sales in comparison to the average realized price from the prior twelve month period.  The commodity prices used to estimate proved reserves and their related PV-10 at February 28, 2017 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the twelve month period from March 2016 through February 2017.  The benchmark average price for the twelve months ended February 28, 2017 was $45.85 per barrel of crude oil in comparison to $39.10 in the prior year reserve report.

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These benchmark average prices were further adjusted for crude oil quality and gravity, transportation fees and other price differentials resulting in an average realized price in California for the February 28, 2017 reserve report of $35.91 in comparison to $39.10 in the February 29, 2016 reserve report.  Adverse changes in any price differential would reduce our cash flow from operations and the PV-10 of our proved reserves.  Operating costs were not escalated.

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 381,070 BOE for the twelve months ended February 28, 2017 were derived from engineering reports prepared by PGH Petroleum and Environmental Engineers, LLC (“PGH”) of Austin, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.

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

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

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

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

In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability.  The technical data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.  Generally, crude oil and natural gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations.  Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships.  Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technical data to assess the reservoir continuity.  In some instances,

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particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities.  Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data.  When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of crude oil derived through volumetric calculations.

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

Delivery Commitments

As of February 28, 2017, we had no commitments to provide any fixed or determinable quantities of crude oil or natural gas in the near future under contracts or agreements.

Summary Operating Data

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

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

	For the Twelve Months Ended February 28/29,
	2017	2016	2015
Crude Oil and Natural Gas Production Data:
Kentucky crude oil	5,842	14,673	21,460
Kentucky natural gas (Mcf)	16,678	28,853	22,134
Kentucky natural gas (BOE)	2,780	4,809	3,689
Kentucky crude oil and natural gas (BOE)	8,593	19,482	25,149
California crude oil	13,035	14,145	16,402
Total (BOE)	21,628	33,627	41,551

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

	For the Twelve Months Ended February 28/29,
	2017		2016		2015
Crude Oil and Gas Revenue:
Kentucky crude oil	$	253,539	$	680,869	$	1,734,400
Kentucky natural gas		26,491		43,457		64,486
California crude oil		482,656		529,360		1,284,911
Total	$	762,686	$	1,253,686	$	3,083,797

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

	For the Twelve Months Ended February 28/29,
	2017		2016		2015
Average Realized Price:
Crude oil – Kentucky (Bbl)	$	43.40	$	46.40	$	80.82
Natural gas – Kentucky (Mcf)	$	1.59	$	1.51	$	2.93
Natural gas – Kentucky (BOE)	$	9.53	$	9.04	$	17.59
Kentucky Aggregate (BOE)	$	32.48	$	37.18	$	71.74
Crude oil – California (Bbl)	$	37.03	$	37.43	$	78.34
Average realized price (BOE)	$	35.22	$	37.28	$	74.35

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

	For the Twelve Months Ended February 28/29,
	2017		2016		2015
Average Production Expense (BOE):
Kentucky (BOE)	$	6.71	$	5.52	$	5.96
California	$	12.55	$	11.37	$	10.99
Average production cost (BOE)	$	10.23	$	7.98	$	7.94

Gross and Net Acreage

The following table sets forth our interests in developed and undeveloped crude oil lease acreage in California and our undeveloped crude oil lease acreage in Michigan held by us as of February 28, 2017.  These ownership interests generally take the form of working interests in crude oil leases that have varying terms.  Developed acreage includes leased acreage that is allocated or assignable to producing wells.  Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, regardless of whether or not the acreage contains proved reserves.  Gross acres represents the total number of acres in which we have an interest.  Net acres represents the sum of our fractional working interests owned in the gross acres.

	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
California	800	292	4,261	1,575	5,061	1,867
Michigan	-	-	1,400	420	1,400	420
Total Acreage	800	292	5,661	1,995	6,461	2,287
Average working interest		36.5%		35.2%		35.4%

Undeveloped Acreage Expirations

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

	Twelve Months Ended February 28, 2018		Twelve Months Ended February 28, 2019		Twelve Months Ended February 29, 2020
	Gross	Net	Gross	Net	Gross	Net
California	200	75	-	-	-	-
Michigan	109	33	366	110	117	35
Total Acreage	309	108	366	110	117	35
Average working interest		35.0%		30.1%		30.0%

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

Producing Wells

The following table sets forth our gross and net productive crude oil wells from continuing operations in California as of February 28, 2017.  Productive wells are producing wells and wells capable of production.  Gross wells represent the total number of wells in which we have an interest.  Net wells represent the sum of our fractional working interests owned in the gross wells.

Property Location	Gross	Net
California	20	7.3
Average working interest		36.5%

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Drilling Activity

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

	Twelve Months Ended		Twelve Months Ended		Twelve Months Ended
	February 28, 2017		February 29, 2016		February 28, 2015
Property Location	Productive	Dry	Productive	Dry	Productive	Dry
California
Exploratory	-	-	-	-	-	-
Developmental	-	-	-	-	-	-
Total	-	-	-	-	-	-

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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 from a cost-savings program for the company and 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 twelve month periods shown.  The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.  The information is derived from information received from online stock quotation services.

	Twelve Months Ended February 28, 2017		Twelve Months Ended February 29, 2016
	High	Low	High	Low
First Quarter	0.03	0.01	0.10	0.06
Second Quarter	0.03	0.01	0.07	0.04
Third Quarter	0.03	0.01	0.05	0.03
Fourth Quarter	0.04	0.02	0.04	0.01

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, 2017, the Company had 1,917 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 28, 2017, there were no conversions of Series A Preferred stock to Common Stock.  The terms of the Series A Preferred are disclosed in the Company’s Amended and Restated Articles of Incorporation.  The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s Common Stock.  Conversion of Series A Preferred to the Company’s Common Stock by the accredited investors relies upon an exemption from registration provided by Section 3(a)(9) of the Securities Act of 1933 relating to securities exchanged by the issuer with its existing security holders exclusively where no commission or other remuneration is paid or given directly or indirectly for soliciting such exchange.

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As of February 28, 2017, 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.

Fiscal Period	Shares of Series A Preferred Converted to Common Stock	Shares of Common Stock Issued from Conversion	Number of Accredited Investors
Year Ended February 29, 2008	102,300	306,900	10
Year Ended February 28, 2009	237,000	711,000	12
Year Ended February 28, 2010	51,900	155,700	4
Year Ended February 28, 2011	102,000	306,000	4
Year Ended February 29, 2012	-	-	-
Year Ended February 28, 2013	18,000	54,000	2
Year Ended February 28, 2014	151,000	453,000	9
Year Ended February 28, 2015	3,000	9,000	1
Year Ended February 29, 2016	10,000	30,000	1
Year Ended February 28, 2017	-	-	-
Totals	675,200	2,025,600	43

Common Stock Issuances

During the twelve months ended February 28, 2010, 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 had 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 twelve months ended February 28, 2015 and February 28, 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.  Effective January 29, 2017, the Company entered into agreements with the remaining holders of the 12% Subordinated Notes and associated warrants to extend the maturity date of such holders’ notes and warrants to January 29, 2019.  The exercise price of the remaining unexercised warrants was lowered from $0.14 to $0.07 as a part of the warrant modification.

Securities Authorized for Issuance under Equity Compensation Plan

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

Equity Compensation Plan Information

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders	-	-	-
Equity compensation plans not approved by security holders(1)	-	-	1,013,780(2)
Total	-	-	1,013,780(2)

⁽¹⁾

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

⁽²⁾

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

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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.

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 28, 2017, a total of 3,000,000 shares of restricted stock had been awarded and 2,986,220 of those were fully vested and remained outstanding under the 2009 Plan.  A total of 1,013,780 common stock shares remained available at February 28, 2017 for issuance pursuant to the 2009 Plan.  For the twelve months ended February 28, 2017 and February 29, 2016, there were no shares that vested since all issued shares were fully vested as of August 31, 2014.  A summary of the 2009 Plan issuances is set forth in the table below:

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

⁽¹⁾

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

⁽²⁾

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

⁽³⁾

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

⁽⁴⁾

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

⁽⁵⁾

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

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

Preferred Stock

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

Series A Convertible Preferred Stock

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

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

Voluntary Conversion:

The Series A Preferred that is currently issued and outstanding is eligible to be converted by the shareholder at any time into three shares of the Company’s Common Stock.  During the year ended February 29, 2016, one conversion of 10,000 shares of Series A Preferred occurred resulting in 30,000 shares of our Common Stock being issued.  There were no conversions of Seris A Preferred during the twelve months ended February 28, 2017.

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At February 28, 2017, there were 724,565 shares issued and outstanding that had not been converted into our Common Stock.  As of February 28, 2017, 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.

Fiscal Period	Shares of Series A Preferred Converted to Common Stock	Shares of Common Stock Issued from Conversion		Number of Accredited Investors
Year Ended February 29, 2008	102,300		306,900		10
Year Ended February 28, 2009	237,000		711,000		12
Year Ended February 28, 2010	51,900		155,700		4
Year Ended February 28, 2011	102,000		306,000		4
Year Ended February 29, 2012	-		-		-
Year Ended February 28, 2013	18,000		54,000		2
Year Ended February 28, 2014	151,000		453,000		9
Year Ended February 28, 2015	3,000		9,000		1
Year Ended February 29, 2016	10,000		30,000		1
Year Ended February 28, 2017	-		-		-
Totals	675,200		2,025,600		43

Automatic Conversion:

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

Dividend:

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

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

Fiscal Year Ended	Shareholders at Period End	Accumulated Dividends
February 28, 2007	100	$	155,311
February 29, 2008	90		242,126
February 28, 2009	78		209,973
February 28, 2010	74		189,973
February 28, 2011	70		173,707
February 29, 2012	70		163,624
February 28, 2013	68		161,906
February 28, 2014	59		151,323
February 28, 2015	58		132,634
February 29, 2016	57		130,925
February 28, 2017	57		130,415
		$	1,841,917

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 28, 2017 and February 29, 2016.  There were no shares of the Company’s Common Stock issued during the twelve months ended February 28, 2017.

	Common Stock Balance	Par Value
Common stock, Issued and Outstanding, February 28, 2015	51,457,373
Conversion of Series A Convertible Preferred Stock to common stock	30,000	$	30
Common stock, Issued and Outstanding, February 29, 2016	51,487,373
Share issuances during the current year	-
Common stock, Issued and Outstanding, February 28, 2017	51,487,373

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

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

Warrants

12% Subordinated Notes – Warrant Expiration Extension

Effective January 29, 2017, the expiration date of the warrants that were issued in conjunction with the 12% Subordinated Notes from a January 2010 private placement offering to accredited investors was extended for an additional two years to January 29, 2019.  The exercise price of the warrants was lowered from $0.14 to $0.07 as a part of the warrant modification.  The warrant expiration extension applied to noteholders who chose to extend the maturity date of the 12% Subordinated Notes for an additional two years to January 29, 2019, and had not already exercised the associated warrants.  Ten noteholders had the expiration date of their warrants extended to January 29, 2019.  The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes.  The Black-Scholes valuation encompassed the following weighted average assumptions: a risk free interest rate of 1.22%; volatility of 378.73%; and dividend yield of 0.0%.

Maximilian Credit Facility Agreement

On October 31, 2012, the Company entered into a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment from Maximilian Investors LLC (either party, as appropriate, is referred to as “Maximilian”).  In connection with this loan, the Company also issued approximately 2.4 million warrants to third parties who assisted in the closing of the loan.  There were 316,617 of these warrants that remained unexercised at February 28, 2017.

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

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

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

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

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

Warrants outstanding and exercisable as of February 28, 2017 are set forth in the table below:

	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining
12% Subordinated Notes	1,190,000	$0.07	1.92	980,000
Warrants issued in 2012 for debt financing	2,435,517	$0.044	0.67	316,617
Warrants issued for Kentucky crude oil project	3,498,601	$0.04	1.50	3,498,601
Warrants issued for Kentucky debt financing	2,623,951	$0.04	1.50	2,623,951
Warrants issued for Kentucky debt financing	309,503	$0.214	1.50	309,503
Warrants issued in share-for-warrant exchange	427,729	$0.04	1.50	427,729
	10,485,301			8,156,401

Warrant activity for the twelve months ended February 29, 2016 and February 28, 2017 is set forth in the table below:

	Warrants	Weighted Average Exercise Price
Warrants outstanding, February 28, 2015	8,306,401	$0.11
Changes during the twelve months ended February 29, 2016:
Expired / Cancelled / Forfeited	150,000	$0.14
Warrants outstanding, February 29, 2016	8,156,401	$0.06
Changes during the twelve months ended February 28, 2017:
Expired / Cancelled / Forfeited	-
Warrants outstanding, February 28, 2017	8,156,401	$0.05
Warrants exercisable, February 28, 2017	8,156,401	$0.05

On January 29, 2017, the 980,000 warrants associated with the 12% Subordinated Notes were modified to extend the expiration date of the warrants to January 29, 2019.  As a part of this modification the exercise price of the 12% Note warrants was changed from $0.14 to $0.07.  No other terms of the warrants were affected by the modification.  The outstanding warrants as of February 28, 2017 and February 29, 2016 have a weighted average exercise price of $0.05 and $0.06; a weighted average remaining life of 1.52 and 2.28 years; and an intrinsic value of $-0-, 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 28, 2017 and February 29, 2016.  This MD&A should be read in conjunction with the audited financial statements and the related notes and other information included elsewhere in this Annual Report on Form 10-K.

Safe Harbor Provision

Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations are intended to be covered by the safe harbor provided for under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.  All statements other than statements of historical facts contained in this MD&A report, including statements regarding our current expectations and projections about future results, intentions, plans and beliefs, business strategy, performance, prospects and opportunities, are inherently uncertain and are forward-looking statements.  For more information about forward-looking statements, please refer to the section labeled “Cautionary Statement About Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.

Introduction and Overview

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

Our long-term success depends on, among many other factors, the successful acquisition and drilling of commercial grade crude oil and natural gas properties as well as the prevailing sales prices for crude oil and natural gas along with associated operating expenses.  The volatile nature of the energy markets makes it difficult to estimate future prices of crude oil and natural gas; however, any prolonged period of depressed prices, such as we are now experiencing, will have a material adverse effect on our results of operations and financial condition.

Our operations are focused on identifying and evaluating prospective crude oil and natural gas properties and funding projects that we believe have the potential to produce crude oil or natural gas in commercial quantities.  We conduct all of our drilling, exploration and production activities in the United States, and all of our revenues are derived from sales to customers within the United States.  We are currently in the process of developing a multi-well oilfield projects in Kern County, California and an exploratory project in Michigan.

Our management cannot provide any assurances that Daybreak will ever operate profitably.  While we have positive cash flow from our continuing crude oil operations in California, we have not yet generated sustainable positive cash flow or earnings on a company-wide basis.  As a small company, we are more susceptible to the numerous business, investment and industry risks that have been more fully described in Item 1A. Risk Factors of this Annual Report on Form 10-K for the fiscal year ended February 28, 2017.

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

Year-to-Date Results

This was a period of time that was full of challenges, primarily managing our cash flow in the face of declining hydrocarbon prices.  During the twelve months ended February 28, 2017, we were successful in selling our Kentucky property which allowed us to restructure our balance sheet through the elimination of approximately $5.4 million in debt associated with the Kentucky project and achieve an additional approximate $3.9 million in debt reduction.

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

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Kern County, California (East Slopes Project)

The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California.  Drilling targets are porous and permeable sandstone reservoirs that exist at depths of 1,200 feet to 4,500 feet.  Since January 2009, we have participated in the drilling of 25 wells in this project.  The crude oil produced from our acreage in the Vedder Sand is considered heavy crude oil.  The produced crude oil ranges from 14° to 16° API gravity and must be heated to separate and remove water prior to sale.  During the twelve months ended February 28, 2017 we had production from 20 vertical crude oil wells.  Our average working interest and NRI in these 20 wells is 36.6% and 28.4%, respectively.  We have been the Operator at the East Slopes Project since March 2009.

Michigan Acreage Acquisition

Daybreak has acquired a 30% working interest in 1,400 acres in the Michigan Basin where we have two shallow crude oil prospects.  The leases have been secured and multiple targets have been identified through a 2-D seismic interpretation.  A 3-D seismic survey was obtained in January and February of 2017.  An analysis of the seismic survey confirmed the prospect identified on the 2-D seismic, as well as identified several additional drilling locations.  We will obtain an additional 3-D survey to better delineate the other locations before a drilling program commences.  The wells will be drilled vertically with conventional completions and no hydraulic fracturing will be required.  The first well is expected to be drilled during the late summer of 2017.

Lawrence County, Kentucky (Twin Bottoms Field)

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

Results of Operations – For the years ended February 28, 2017 and February 29, 2016 – Continuing Operations

California Crude Oil Prices

The price we receive for crude oil sales in California is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) crude oil Cushing, Oklahoma delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs.  We do not have any natural gas revenues in California.

There has been a significant amount of volatility in hydrocarbon prices and dramatic decline in our realized sale price of crude oil since June of 2014, when the monthly average price of WTI oil was $105.79 per barrel.  This decline in the price of crude oil as shown below has had a substantial negative impact on our cash flow from our producing California properties.  A comparison of the average WTI price, average realized crude oil sales price for the twelve months ended February 28, 2017 with adjusted revenue using the twelve months ended February 29, 2016 sales volume is shown in the table below:

	Twelve Months Ended
	February 28, 2017		February 29, 2016		Percentage Change
Average WTI crude oil price	$	46.81	$	45.71	2.4%
Average realized crude oil sales price (Bbl)	$	37.03	$	37.43	(1.1%)
Crude oil revenue (Adjusted for FY 2015-16 volume)	$	523,772	$	529,360	(1.1%)

For the twelve months ended February 28, 2017, the average WTI price was $46.81 and our average realized crude oil sale price was $37.03, representing a discount of $9.78 per barrel or 20.9% lower than the average WTI price.  In comparison, for the twelve months ended February 29, 2016, the average WTI price was $45.71 and our average realized sale price was $37.43 representing a discount of $8.28 per barrel or 18.1% lower than the average WTI price.  Historically, the sale price we receive for California heavy crude oil has been less than the quoted WTI price because of the lower API gravity of our California crude oil in comparison to the API gravity of WTI crude oil.  It is beyond our control and ability to accurately predict how long hydrocarbon prices will continue to decline; when or at what level they may begin to stabilize; or when they may start to rebound as there are many factors beyond our control that dictate the price we receive on our hydrocarbon sales.

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California Crude Oil Revenue and Production

Crude oil sales revenue in California for the twelve months ended February 28, 2017 decreased $46,704 or 8.8% to $482,656 in comparison to revenue of $529,360 for the twelve months ended February 29, 2016.  The average sale price of a barrel of crude oil for the twelve months ended February 28, 2017 was $37.03 in comparison to $37.43 for the twelve months ended February 29, 2016.  The decrease of $0.40 or 1.1% in the average realized price of a barrel of crude oil accounted for $5,619 or 12.0% of the decline in crude oil revenue while a decrease of $41,085 or 88.0% can be attributed to a decline in production for the twelve months ended February 28, 2017.

Our net sales volume for the twelve months ended February 28, 2017 was 13,035 barrels of crude oil in comparison to 14,144 barrels sold for the twelve months ended February 29, 2016.  This decrease in oil sales volume of 1,109 barrels or 7.8% was primarily due to the natural decline in reservoir pressure during the twelve months ended February 28, 2017.

The gravity of our produced oil in California ranges between 14° API and 16° API.  Production for the twelve months ended February 28, 2017 was from 20 wells resulting in 7,187 well days of production in comparison to 7,210 well days of production for the twelve months ended February 29, 2016.

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

	Twelve Months Ended February 28, 2017			Twelve Months Ended February 29, 2016
Project	Revenue		Percentage	Revenue		Percentage
California – East Slopes Project	$	482,656	100.0%	$	529,360	100.0%
Total crude oil revenues*	$	482,656	100.0%	$	529,360	100.0%

*Our average realized sale price on a BOE basis for the twelve months ended February 28, 2017 was $37.03 in comparison to $37.43 for the twelve months ended February 29, 2016, representing a decrease of $0.40 or 1.1% per barrel.

Of the $46,704 or 8.8% decline in revenue for twelve months ended February 28, 2017, approximately $5,619 or 12.0% can be directly attributed to the decline in the realized price of crude oil.

Operating Expenses

Total operating expenses decreased approximately $1.4 million or 50.5% to $1,351,448 for the twelve months ended February 28, 2017 in comparison to $2,732,455 for the twelve months ended February 29, 2016.  As shown below, this decrease in expenses was primarily due to impairment recognition of crude oil properties in California for $1.1 million for the twelve months ended February 29, 2016.  Our operating expenses are set forth in the table below:

	Twelve Months Ended February 28, 2017					Twelve Months Ended February 29, 2016
	Expenses		Percentage	BOE Basis		Expenses		Percentage	BOE Basis
Production expenses	$	163,654	12.1%			$	160,841	5.9%
Exploration and drilling expenses		9,297	0.7%				49,645	1.8%
Depreciation, Depletion, Amortization (“DD&A”)		110,285	8.2%				241,080	8.8%
Impairment of oil and gas properties		-	-				1,108,683	40.6%
General and Administrative (“G&A”) expenses		1,068,212	79.0%				1,172,206	42.9%
Total operating expenses	$	1,351,448	100.0%	$	103.68	$	2,732,455	100.0%	$	193.18

Production expenses include expenses associated with the production of crude oil and natural gas.  These expenses include pumper salaries, electricity, road maintenance, control of well insurance, property taxes and well maintenance and workover expenses; and, relate directly to the number of wells that are on production.  For the twelve months ended February 28, 2017, these expenses increased $2,813, or 1.7% to $163,654 in comparison to $160,841 for the twelve months ended February 29, 2016.  We had 20 wells on production in California for the twelve months ended February 28, 2017 and February 29, 2016.  Production expenses on a BOE basis in California for the twelve months ended February 28, 2017 and February 29, 2016 were $12.56 and $11.37, respectively.  Production expenses represented 12.1% and 5.9% of total operating expenses for the twelve months ended February 28, 2017 and February 29, 2016, respectively.

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Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses decreased $40,348 or 81.3% to $9,297 for the twelve months ended February 28, 2017 in comparison to $49,645 for the twelve months ended February 29, 2016.  Exploration and drilling expenses represented 0.7% and 1.8% of total operating expenses for the twelve months ended February 28, 2017 and February 29, 2016, respectively.

Depreciation, Depletion, Amortization (“DD&A”) expense relates to equipment, proven reserves and property costs, and is another component of operating expenses.  These expenses decreased $130,795 or 54.3% to $110,285 for the twelve months ended February 28, 2017 in comparison to $241,080 for the twelve months ended February 29, 2016.  On a BOE basis, DD&A expense in California for the twelve months ended February 28, 2017 and February 29, 2016 was $8.46 and $17.04, respectively.  DD&A expenses represented 8.2% and 8.8% of total operating expenses for the twelve months ended February 28, 2017 and February 29, 2016, respectively.

Impairment of proved and unproved oil properties in California for the twelve months ended February 28, 2017 and February 29, 2016 was $-0- and $1,108,683, respectively.  The impairment expense during the twelve months ended February 29, 2016 was caused by a decline in hydrocarbon prices resulting in lower economic reserve valuation and a reduction in our estimated future cash flows in California.  Impairment of oil properties represented -0-% and 40.6% of total operating expenses for the twelve months ended February 28, 2017 and February 29, 2016, respectively.

General and administrative (“G&A”) expenses include the salaries of six employees, including management.  Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as for running a public company.  These expenses decreased $103,994 or 8.9% to $1,068,212 for the twelve months ended February 28, 2017 in comparison to $1,172,206 for the twelve months ended February 29, 2016.  The decline in G&A expenses was due to the reclass during the twelve months ended February 29, 2016 of certain fundraising expenses that had previously been recognized as prepaid expenses.  For the year ended February 28, 2017, we received, as Operator of the East Slopes project in California, administrative overhead reimbursement of $53,287, which was used to directly offset certain employee salaries.  We are continuing a program of reducing all of our G&A costs wherever possible.  G&A expenses represented 79.0% and 42.9% of total operating expenses for the twelve months ended February 28, 2017 and February 29, 2016, respectively.

Interest income decreased 18.2% to $81 for the twelve months ended February 28, 2017 in comparison to $99 for the twelve months ended February 29, 2016 after accounting for the settlement of the App Energy Note as a part of the sale of our Kentucky properties.  For further discussion on the sale of our Kentucky properties refer to the Discontinued Operations discussion below in this MD&A.

Interest expense increased $512,610 or 20.7% to 2,994,466 for the twelve months ended February 28, 2017 in comparison to $2,481,856 for the twelve months ended February 29, 2016.  This financing transaction is discussed further in the MD&A section of this 10-K report under the caption “Current debt (short-term borrowings) – Maximilian Credit Facility.”

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 28, 2017 our sales volume on a BOE basis decreased by 7.8% while our revenues decreased 8.8% 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 Michigan.

Discontinued Operations – Twin Bottoms Field, Lawrence County, Kentucky

Effective October 31, 2016, the Company finalized the sale of its interest in the Twin Bottoms Field in Kentucky.  The sale included Daybreak’s interest in 14 producing horizontal oil wells, its mineral rights, its lease acreage and infrastructure.  The sale of the Twin Bottoms Field resulted in a loss on the sale of oil and natural gas properties for the twelve months ended February 28, 2017 of approximately $1.96 million.  In accordance with the guidance provided in ASC 205-20, the Company concluded that this sale qualified for presentation as discontinued operations.  The Company has no ongoing or future plans to be involved in this segment of its oil and natural gas projects.  Prior period income statement balances applicable to the Twin Bottoms Field in Kentucky have been reclassified and are included under the

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Discontinued Operations caption while related assets and liabilities were reclassified to Assets Held for Sale and Liabilities Held for Sale, respectively on the Balance Sheet.

Operating income, interest income, operating expenses and interest expense related to Kentucky for the twelve months ended February 28, 2017 and February 29, 2016 are set forth in the tables below.

	For the Twelve Months Ended
	February 28, 2017		February 29, 2016
Crude oil and natural gas sales revenue	$	280,030	$	724,326
Interest income		760,704		1,039,853
Production, exploration and drilling expenses		(65,157)		(134,016)
Depreciation, Depletion and Amortization (“DD&A”) expenses		(124,169)		(276,790)
General & Administrative expense		(204,056)		-
Interest expense		(723,206)		(873,920)
Loss on note receivable		(1,500,676)		-
Loss on sale of O&G properties		(1,955,315)		-
Gain on debt settlement		3,926,468		-
Income (loss) from discontinued operations	$	(394,623)	$	479,453

The reconciliation of the carrying amounts of major classes of assets and liabilities held of sale from discontinued operations as of February 28, 2017 and February 29, 2016 are set forth in the table below.

Major Classes of Assets Presented as a part of Discontinued Operations	February 28, 2017		February 29, 2016(1)
Kentucky oil and natural gas properties, net	$	-	$	2,822,186
Note receivable – App Energy LLC (Kentucky funding)		-		4,655,513
Trade receivables – Kentucky related		-		104,595
Total Assets Held for Sale (Current and Non-current)	$	-	$	7,582,294

Major Classes of Liabilities Presented as a part of Discontinued Operations	February 28, 2017		February 29, 2016(1)
Trade payables – Kentucky related	$	-	$	136,619
Debt related to Kentucky		-		4,624,863
Asset retirement obligation (ARO) - Kentucky		-		6,766
Total Liabilities Held for Sale (Current and Non-current)	$	-	$	4,768,248

⁽¹⁾Amounts in the February 29, 2016 balance sheet are classified as current and long-term.

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

Certain significant non-cash operating and investing items for discontinued operations in Kentucky during the twelve months ended February 29, 2016 included increase in note receivable for interest added to principal of $683 thousand; unpaid additions to crude oil and natural gas properties of $90 thousand; and DD&A expense of $277 thousand.

Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially on a quarter-to-quarter and year-to-year basis.  Revenues are dependent upon both hydrocarbon production levels and the price we receive for hydrocarbon sales.  Since June of 2014, there has been a significant decline in the WTI price of crude oil and subsequently 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 in California.  Production expenses will fluctuate according to the number and percentage ownership of producing wells that we own.  Exploration and drilling expenses will be dependent upon the amount of capital that we have to invest in future development projects, as well as the success or failure of such projects.  Likewise, the amount of DD&A expense will depend upon the factors cited above including the size of our proven reserves base and the market price of energy products.  G&A expenses will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.  An ongoing goal of the Company is to improve cash flow to cover the current level of G&A expenses and to fund both our oilfield development program in California and future drilling programs in other geographic locations.

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Capital Resources and Liquidity

Our primary financial resource is our base of crude oil reserves.  Our ability to fund our capital expenditure program is dependent upon the prices we receive from our crude oil and natural gas sales; the success of our exploration program in Michigan; and the availability of capital resource financing.  In the next fiscal year, we plan on investing approximately $75,000 in new capital expenditures in California; 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 28, 2017 are set forth in the table below:

	February 28, 2017		February 29, 2016		Increase (Decrease)		Percentage Change
Cash	$	42,003	$	6,995	$	35,008	500.5%
Current Assets	$	309,308	$	834,480	$	(525,172)	(62.9%)
Total Assets	$	1,263,313	$	8,960,004	$	(7,696,691)	(85.9%)
Current Liabilities	$	(13,462,236)	$	(18,270,014)	$	(4,807,778)	(26.3%)
Total Liabilities	$	(14,092,781)	$	(18,349,993)	$	(4,257,212)	(23.2%)
Working Capital Deficit	$	(13,152,928)	$	(17,435,534)	$	(4,282,606)	(24.6%)

Our working capital deficit decreased by approximately $4.2 million or 24.6% from a deficit of $17.4 million at February 29, 2016 to a deficit of $13.2 million at February 28, 2017.  The decrease in the working capital deficit was a result was achieved as a consequence of the sale of our crude oil and natural gas properties in Kentucky.  This sale allowed us to restructure our Balance Sheet through the elimination of approximately $4.5 million in debt associated with the App Energy note for Kentucky and an additional approximate $3.9 million in debt reduction on the Maximilian credit facility shown on our Balance Sheet as a current liability.  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, our lender is under no obligation to advance us any additional funding and, rather, there can be no assurances that out lender will not declare the Company to be in default under the credit facility.  A change of control or management of our lender, among other reasons, could also result in our loan being called due and payable.  While we continue to have ongoing positive cash flow from our crude oil operations in 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 prices allowing us to implement a more aggressive drilling program in the our East Slope operations in Kern County, California and in Michigan.

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

Major sources of funds in the past for us have included the debt or equity markets.  While we have achieved positive cash flow from our operations in 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 crude oil and natural gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources.

Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments 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 will need to seek additional forms of financing through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these instruments which could result in dilution to existing security holders and increased debt and leverage.  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.

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Cash Flows

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

	Twelve Months Ended February 28, 2017		Twelve Months Ended February 29, 2016		Increase (Decrease)		Percentage Change
Net cash provided by (used in) operating activities	$	132,152	$	(496,667)	$	628,819	126.6%
Net cash provided by (used in) investing activities	$	(95,959)	$	636,034	$	(731,993)	(115.1%)
Net cash provided by (used in) financing activities	$	(1,185)	$	(629,144)	$	(627,959)	(99.8%)

Cash Flow Provided by (Used in) Operating Activities

Cash flow from operating activities is derived from the production of our crude oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances.  For the year ended February 28, 2017, cash provided by our operating activities was $132,152 in comparison to cash flow used in operating activities of $496,667 for the twelve months ended February 29, 2016.  This increase in cash provided by operating activities of $628,819 was due to the recognition of a loss on the sale of our Kentucky crude oil and natural gas property.  Non-cash expenses decreased by $0.9 million in comparison to the twelve months ended February 29, 2016.  Accounts receivable balance decreased by $0.5 million and accounts payable balances decreased by $0.2 million.  Accrued interest increased by $0.6 million.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

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

Cash Flow Provided by (Used in) Investing Activities

Cash flow from investing activities is derived from changes in oil and gas property balances and our lending activities that were associated with the App Energy, LLC (“App Energy”) loan.  Cash used in investing activities for the twelve months ended February 28, 2017 was $95,959 in comparison to cash flow provided by investing activities of $636,034 for the twelve months ended February 29, 2016.  During the twelve months ended February 28, 2017, we sold our interest in the Kentucky project and as a part of that transaction the approximate $4.5 million note receivable from App Energy was considered satisfied.

Cash Flow (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 $1,185 for the twelve months ended February 28, 2017 in comparison to cash flow used in our financing activities of $629,144 for the year ended February 29, 2016.  Effective October 31, 2016, the Company finalized the sale of its interest in the Twin Bottoms Field in Kentucky, which allowed us to reduce our outstanding credit facility loan balance with Maximilian.  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 the Company’s financing activities for the twelve months ended February 28, 2017.

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.

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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 28, 2017 and February 29, 2016, the Line of Credit had an outstanding balance of $817,622 and $843,807, respectively.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and was $33,815 and $31,442 for the years ended February 28, 2017 and February 29, 2016, respectively.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

Maximilian Credit Facility

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

Maximilian Loan - Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App Energy, LLC, a Kentucky limited liability company (“App Energy”) in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013.  The amendement increased the amount of the credit facility to $90 million and reduced the annual interest rate to 12%.

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.

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

On 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.  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 held from $0.10 to $0.04.  No other terms of the warrant agreement were changed.  The modification did not result to any accounting since these warrants were deemed to be investor warrants.

On October 14, 2015, the Company entered into a Third Amendment to the Amended and Restated Loan and Security Agreement and Second Warrant Amendment with Maximilian, (the “Third Amendment”).  Pursuant to the Third Amendment, Maximilian agreed to a reduction in the Company’s monthly payments under the loan agreement to $50,000 per month for a period of six months ending on February 29, 2016.  The reduction in monthly payments allowed 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 was 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 Third 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,

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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.

On October 31, 2016, the Company entered into a Fourth Amendment to the Amended and Restated Loan and Security Agreement with Maximilian, which amended the Company’s loan agreement with Maximilian (the “Restructuring Agreement”).  Pursuant to the Restructuring Agreement, in exchange for the proceeds it received from the Kentucky Sale, Maximilian and the Company have agreed to: (1) the deemed payment in full and/or forgiveness of approximately $8.3 million in outstanding indebtedness under the Daybreak Loan Agreement (which includes approximately $5.4 million in indebtedness that was loaned by the Company to App Energy pursuant to the Loan and Security Agreement between the parties dated as of August 28, 2013, as amended from time to time); (2) a commitment by Maximilian to forgive an additional amount of indebtedness under the Daybreak Loan Agreement, currently estimated to be $3.2 million, in the event of the future issuance of senior preferred stock by the Company to it; (3) the deemed payment in full and termination of the App Loan Agreement; (4) the termination and release of all liens, security interests and other interests held by Maximilian or its affiliates in any of the Company’s or App Energy’s Kentucky oil and natural gas assets, including the termination of the overriding royalty interests and net profits interests held by Maximilian and/or its affiliates; (5) amendments to the Daybreak Loan Agreement to suspend principal and interest payments for up to six months and extend the maturity date to February 28, 2020; (6) a commitment by Maximilian to advance up to $250,000 in financing to the Company over the next six months; (7) the pursuit of the Michigan Joint Venture using the $250,000 set aside from the Kentucky Sale.  The Company recognized a gain on debt settlement in aggregate of approximately $3.9 million through the sale of the Kentucky property and reduction in the outstanding credit facility balance.

As a result of the decline in hydrocarbon prices, we 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 restructuring the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue.  Further, our lender is under no obligation to advance us any additional funding and, rather, there can be no assurances that out lender will not declare the Company to be in default under the credit facility.  A change of control or management of our lender, among other reasons, could also result in our loan being called due and payable.  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.

Maximilian Loan Agreement – Michigan Project

At February 28, 2017, the Company had received $84,000 in advances from Maximilian under a separate promissory note agreement dated January 17, 2017 and amended on February 10, 2017 regarding the development of an oilfield project in Michigan.  Advances under this agreement are subject to a 5% (five percent) per annum interest rate.  If a well that the Company elects to participate in is scheduled to be spudded at the Michigan oilfield project on or before December 31, 2017, then the advances under the promissory note must be repaid in full upon the earlier of (a) the time that is ten days prior to the first well being spudded on the Michigan oilfield project or (b) December 31, 2017.  If there is not a well scheduled to be spudded at the Michigan oilfield project on or before December 31, 2017 that the Company elects to participate in, then the Company will assign to Maximilian its working interest in the Michigan oilfield project, in full payment and satisfaction of the advances under the promissory note.  Advances under the promissory note may be prepaid at any time without penalty, and are secured by a mortgage on the Company’s working interest in the Michigan oilfield project.  In the event of a default of any of the Company’s obligations under the promissory note, the amounts due may be called immediately due and payable at Maximilian’s option.

Current debt balances at February 28, 2017 and February 29, 2016 are set forth in the table below:

	February 28, 2017		February 29, 2016
Principal Balance		8,960,444		14,381,131
Less unamortized discount and debt issuance costs		(238,598)		(713,026)
Subtotal – O&G operating debt		8,721,846		13,668,105
Michigan project debt		84,000		-
Net debt	$	8,805,846	$	13,668,105

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App Energy Note Receivable - Loan Agreement

On October 31, 2016, the Company and App Energy, LLC, a Kentucky limited liability company (“App Energy”), sold their interests in the Twin Bottoms field in Kentucky.  The note receivable from App Energy for funds advanced by the company to App Energy for drilling in Kentucky was considered to be paid in full as a part of the sale of the Twin Bottoms Field.  The $3.9 million App Energy received from the sale of their working interest in Kentucky was used to pay down a portion of the associated note receivable.  The remaining balance of approximately $1.5 million was recorded as a loss on the settlement of debt.  The associated debt the Company owed to Maximilian Resources LLC (“Maximilian”) of approximately $5.4 million was eliminated through the sale of the Twin Bottoms Field.  

Non-current debt (long-term borrowings)

12% Subordinated Notes

The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a January 2010 private placement, resulted in $595,000 in gross proceeds (of which $250,000 was from a related party) to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th.  On January 29, 2015, the Company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes for an additional two years to January 29, 2017.  Effective January 29, 2017, the maturity date of the Notes and the expiration date of the warrants that were issued in conjunction with the 12% Subordinated Notes from the January 2010 private placement offering to accredited investors were extended for an additional two years to January 29, 2019.  The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes.  The exercise price of the warrants was lowered from $0.14 to $0.07 as a part of the warrant modification.  The warrant expiration extension applied to noteholders who chose to extend the maturity date of the 12% Subordinated Notes for an additional two years and had not already exercised the associated warrants.  Ten noteholders had the expiration date of their warrants extended to January 29, 2019.

The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes.  The Black-Scholes valuation encompassed the following weighted average assumptions: a risk free interest rate of 1.22%; volatility of 378.73%; and dividend yield of 0.0%.  Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2018.  At February 28, 2017 and February 29, 2016, amortization expense was $1,211 and $-0-, respectively.  The unamortized debt discount at February 28, 2017 and February 29, 2016 was $27,864 and $-0-, respectively.

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

	February 28, 2017		February 29, 2016
12% Subordinated Notes	$	315,000	$	315,000
Debt discount		(15,535)		-
Net 12% Subordinated Note balance	$	299,465	$	315,000

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

	February 28, 2017		February 29, 2016
12% Subordinated Notes – related party	$	250,000	$	250,000
Debt discount		(12,329)		-
Net 12% Subordinated Note – related party balance	$	237,671	$	250,000

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In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.07 and an amended expiration date of January 29, 2019.  The 12% Note warrants that have been exercised are set forth in the table below.  At February 28, 2017, there were 980,000 warrants that were not exercised and had not expired.

Fiscal Period	Warrants Exercised	Shares of Common Stock Issued	Number of Accredited Investors
Year Ended February 28, 2014	100,000	100,000	1
Year Ended February 28, 2015	50,000	50,000	1
Year Ended February 29, 2016	-	-	-
Year Ended February 28, 2017	-	-	-
Totals	150,000	150,000	2

Capital Commitments

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

Encumbrances

The Company’s debt obligations, pursuant to the loan agreement and promissory notes entered into by and among Maximilian and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and two mortgages; one covering our leases in California and the other covering our lease in Michigan.  For further information on the loan agreement with Maximilian refer to the discussion above under the caption above “Current debt (short-term borrowings)” in this MD&A.

Restricted Stock and Restricted Stock Unit Plan

On April 6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted stock and restricted stock unit awards.  Subject to adjustment, the total number of shares of Daybreak’s common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.  We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.  Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.

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

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

⁽¹⁾

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

⁽²⁾

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

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

Crude Oil and Natural Gas Reserves

Daybreak’s total net proved developed and undeveloped crude oil and natural gas reserves on a barrel of oil equivalent (“BOE”) basis decreased by 521,710 BOE, or 57.8%, to 381,070 BOE at February 28, 2017 compared to 902,780 BOE at February 29, 2016.  Our working interest in the Kentucky, Twin Bottoms Field, project was sold effective October 31, 2016.  The Kentucky sale accounted for 486,937 BOE or 93.3% of the decline in proved reserves.  Another 13,145 BOE or 2.5% was accounted for by revisions of previous estimates.  The balance of the decline, 21,628 BOE or 4.1% was due to current year production.  Net California proved developed (“PDP”) reserves decreased by 13,496 BOE or 11.9%, to 99,710 BOE at February 28, 2017 compared to 113,206 BOE at February 29, 2016.  This PDP decrease of 13,496 BOE was due to 13,035 BOE of production and 461 BOE of downward revisions.  Net California proved undeveloped (“PUD”) reserves decreased by 13,063 BOE or 4.4% to 281,360 BOE at February 28, 2017 in comparison to 294,423 at February 29, 2016.  Our reserves were fully engineered by PGH Petroleum and Environmental Engineers, LLC of Austin, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.  For further information on our reserve report, refer to exhibit 99.1 of this Annual Report on Form 10-K.

Changes in Financial Condition

During the year ended February 28, 2017, 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.  Effective October 31, 2016, we sold our working interest in the Twin Bottoms Field in Kentucky.  The sale included our interest in 14 producing horizontal oil wells, its mineral rights, its lease acreage and infrastructure.  As a result of this sale and the restructuring of our Balance Sheet, we recognized approximately $394,623 as income from discontinued operations which includes: an approximate $1.96 million loss on the sale of crude oil and natural gas properties; a reduction of $4.5 million in debt associated with Kentucky; a loss on note receivable settlement of approximately $1.5 million; and a gain on debt settlement of approximately $3.9 million with our lender Maximilian Resources LLC., for the twelve months ended February 28, 2017.  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 on all our producing crude oil and natural gas properties.  During the year ended February 28, 2017, crude oil revenue from continuing operations decreased $46,704 8.8%, to $482,656.  Approximately $5,619 or 12.0% of the decline in revenue can be directly attributed to the decline in hydrocarbon prices for the twelve months ended February 28, 2017.  The remaining $41,085 or 88.0% decline can be attributed to a decline in production.  For the twelve months ended February 28, 2017, we had an operating loss of $868,792 in comparison to an operating loss of $2,203,095 for the twelve months ended February 29, 2016.

Our balance sheet at February 28, 2017 reflects total assets of approximately $1.3 million a decrease of $7.7 million or 85.9% in comparison to approximately $9.0 million at February 29, 2016.  This decrease of $7.7 million in total assets is primarily due to the sale of our Kentucky crude oil and natural gas properties and the elimination of the App Energy note receivable as a part of the sale.

At February 28, 2017, total liabilities were approximately $14.1 million, a decrease of approximately $4.2 million or 23.2% in comparison to approximately $18.3 million at February 29, 2016.  This decrease of $4.2 million was primarily due to the elimination of a portion of debt related to the Twin Bottoms Field Kentucky sale.

There was no change in our common stock issued and outstanding of 51,487,373 shares for the year ended February 28, 2017 in comparison to the year ended February 29, 2016.

Accumulated Deficit

Our financial statements for the year ended February 28, 2017 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  Our financial statements show that the Company has incurred significant operating losses that raise substantial doubt about our ability to continue as a going concern.  The accompanying financial statements do not include any adjustments that might result from this uncertainty.

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The increase in the accumulated deficit from approximately $32.4 million as of February 29, 2016 to $35.9 million as of February 28, 2017 was due to the approximate $3.5 million net loss for the year.  This compares to an approximate net loss of $4.2 million for the twelve months ended February 29, 2016.  With the restructuring of our Balance Sheet, we recognized approximately $394,623 as income from discontinued operations; an approximate $1.96 million loss on the sale of crude oil and natural gas properties; a reduction of $4.5 million in debt associated with Kentucky; a loss on note receivable settlement of approximately $1.5 million; and a gain on debt settlement of approximately $3.9 million with our lender Maximilian Resources LLC., for the twelve months ended February 28, 2017.

Cash Balance

We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations, investments and capital resource funding.  Our cash balances were $42,003 and $6,995 at February 28, 2017 and February 29, 2016, respectively.

Crude oil and natural gas revenues (continuing operations)

Crude oil revenues from continuing operations decreased $46,704 or 8.8% to $482,656 for the twelve months ended February 28, 2017 in comparison to $529,360 for the twelve months ended February 29, 2016.  Approximately $5,619 or 12.0% of this decrease was due to the continuing decline in crude oil prices during the twelve months ended February 28, 2017.

Operating Expenses

Operating expenses for the twelve months ended February 28, 2017 decreased by approximately $1.4 million or 50.5% to $1.3 million in comparison to $2.7 million for the twelve months ended February 29, 2016.  This decrease in expenses was primarily due to the recognition of $1.1 million in impairment of proved and unproved oil properties in California for the twelve months ended February 29, 2016.

Operating Loss

For the year ended February 28, 2017, we reported an operating loss of approximately $0.9 million in comparison to an operating loss of $2.2 million for the twelve months ended February 29, 2016.  This decrease in operating loss was primarily due to the recognition of $1.1 million in impairment of proved and unproved oil properties in California for the twelve months ended February 29, 2016.

Net Loss

Since entering the crude oil and natural gas exploration industry, we have incurred net losses with periodic negative cash flow and have depended on external financing and the sale of crude oil and natural gas assets to sustain our operations.  A net loss of approximately $3.5 million was reported for the twelve months ended February 28, 2017 in comparison to a net loss of $4.2 million for the twelve months ended February 29, 2016.

Management Plans to Continue as a Going Concern

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

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

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

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Critical Accounting Policies

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

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

Crude Oil and Natural Gas Properties

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

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

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

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

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

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

51

Revenue Recognition

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

Suspended Well Costs

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

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

Share Based Payments

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

Off-Balance Sheet Arrangements

As of February 28, 2017, we did not have any relationships with unconsolidated entities or financial partners, such as entities often referred to as structured finance or special purpose entities, which have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.  As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.

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ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Daybreak Oil and Gas, Inc.

Spokane Valley, Washington

We have audited the accompanying balance sheets of Daybreak Oil and Gas, Inc. (the “Company”) as of February 28, 2017 and February 29, 2016 and the related statements of operations, changes in stockholders’ deficit and cash flows for the years then ended.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of February 28, 2017 and February 29, 2016 and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern.  As discussed in Note 2 to the financial statements, the Company suffered losses from operations and has negative operating cash flows, which raises substantial doubt about its ability to continue as a going concern.  Management’s plans regarding those matters are also described in Note 2.  The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ MaloneBailey, LLP

www.malonebailey.com

Houston, Texas

May 26, 2017

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DAYBREAK OIL AND GAS, INC.

Balance Sheets

As of February 28, 2017 and February 29, 2016

	As of February 28, 2017		As of February 29, 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	42,003	$	6,995
Accounts receivable:
Crude oil sales		83,405		39,168
Joint interest participants		55,154		106,694
Other receivables, net		4,489		3,368
Production revenue receivable - current		-		45,000
Prepaid expenses and other current assets		24,197		107,760
ASSETS HELD FOR SALE		-		525,495
Restricted short-term time deposit		100,060		-
Total current assets		309,308		834,480
OIL AND GAS PROPERTIES, successful efforts method, net
Proved properties		853,552		943,641
Unproved properties		59,375		-
PREPAID DRILLING COSTS		41,078		18,802
ASSETS HELD FOR SALE		-		7,056,799
Restricted long-term time deposit		-		106,282
Total assets	$	1,263,313	$	8,960,004
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,727,955	$	1,640,617
Accounts payable - related parties		1,414,481		990,483
Accrued interest		446,232		175,283
Notes payable, related party		250,100		250,100
12% Notes payable		-		315,000
12% Note payable - related party		-		250,000
Debt - current portion, net of deferred financing costs of $238,598 and $641,075, respectively		8,805,846		9,043,242
LIABILITIES HELD FOR SALE		-		4,761,482
Line of credit		817,622		843,807
Total current liabilities		13,462,236		18,270,014
LONG TERM LIABILITIES:
12% Notes payable, net of discount $15,535		299,465		-
12% Note payable - related party, net of discount $12,329		237,671		-
LIABILITIES HELD FOR SALE		-		6,766
Asset retirement obligation		93,409		73,213
Total liabilities		14,092,781		18,349,993
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ DEFICIT:
Preferred stock - 10,000,000 shares authorized, $0.001 par value;		-		-
Series A Convertible Preferred stock - 2,400,000 shares authorized, $0.001 par value, 6% cumulative dividends; 724,565 shares issued and outstanding		725		725
Common stock- 200,000,000 shares authorized; $0.001 par value, 51,487,373 shares issued and outstanding		51,487		51,487
Additional paid-in capital		22,997,789		22,968,714
Accumulated deficit		(35,879,469)		(32,410,915)
Total stockholders’ deficit		(12,829,468)		(9,389,989)
Total liabilities and stockholders' deficit	$	1,263,313	$	8,960,004

The accompanying notes are an integral part of these financial statements

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DAYBREAK OIL AND GAS, INC.

Statements of Operations

For the Twelve Months Ended February 28, 2017 and February 29, 2016

	Twelve Months Ended February 28, 2017		Twelve Months Ended February 29, 2016
REVENUE:
Crude oil sales	$	482,656	$	529,360
OPERATING EXPENSES:
Production		163,654		160,841
Exploration and drilling		9,297		49,645
Depreciation, depletion and amortization		110,285		241,080
Impairment of crude oil properties		-		1,108,683
General and administrative		1,068,212		1,172,206
Total operating expenses		1,351,448		2,732,455
OPERATING LOSS		(868,792)		(2,203,095)
OTHER INCOME (EXPENSE):
Interest income		81		99
Interest expense		(2,994,466)		(2,481,856)
Total other income (expense)		(2,994,385)		(2,481,757)
LOSS FROM CONTINUING OPERATIONS		(3,863,177)		(4,684,852)
DISCONTINUED OPERATIONS: (Note 9)
Income from discontinued operations		394,623		479,453
NET LOSS		(3,468,554)		(4,205,399)
Cumulative convertible preferred stock dividend requirement		(130,415)		(130,925)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(3,598,969)	$	(4,336,324)
NET INCOME (LOSS) PER COMMON SHARE
Loss on continuing operations	$	(0.08)	$	(0.09)
Income from discontinued operations		0.01		0.01
NET LOSS PER COMMON SHARE – Basic and diluted	$	(0.07)	$	(0.08)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING – Basic and diluted		51,487,373		51,484,373

The accompanying notes are an integral part of these financial statements

56

DAYBREAK OIL AND GAS, INC.

Statements of Changes in Stockholders' Deficit

For the Twelve Months Ended February 28, 2017 and February 29, 2016

	Series A Convertible						Additional
	Preferred Stock			Common Stock			Paid-In		Accumulated
	Shares	Amount		Shares	Amount		Capital		Deficit		Total
BALANCE, FEBRUARY 28, 2015	734,565	$	735	51,457,373	$	51,457	$	22,968,734	$	(28,205,516)	$	(5,184,590)
Issuance of common stock for:
Conversion of preferred stock	(10,000)		(10)	30,000		30		(20)		-		-
Net loss	-		-	-		-		-		(4,205,399)		(4,205,399)
BALANCE, FEBRUARY 29, 2016	724,565	$	725	51,487,373	$	51,487	$	22,968,714	$	(32,410,915)	$	(9,389,989)
Extension of 12% Note warrants								29,075				29,075
Net loss	-		-	-		-		-		(3,468,554)		(3,468,554)
BALANCE, FEBRUARY 28, 2017	724,565	$	725	51,487,373	$	51,487	$	22,997,789	$	(35,879,469)	$	(12,829,468)

The accompanying notes are an integral part of these financial statements

57

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows

For the Twelve Months Ended February 28, 2017 and February 29, 2016

	Twelve Months Ended
	February 28, 2017		February 29, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(3,468,554)	$	(4,205,399)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Loss on sale of crude oil and natural gas properties		1,955,315		-
Loss on settlement of Note Receivable		1,500,676		-
Gain on debt settlement		(3,926,468)		-
Depreciation, depletion and ARO expense		234,454		517,870
Impairment of crude oil properties		-		1,108,683
Amortization of debt discount		73,162		132,114
Amortization of deferred financing costs		423,331		427,331
Debt modification fees		1,057,042		-
Interest income		81		(83)
Changes in assets and liabilities:
Accounts receivable – crude oil and natural gas sales		(21,332)		133,540
Accounts receivable - joint interest participants		51,540		(55,312)
Accounts receivable - other		(711,987)		(483,255)
Prepaid expenses and other current assets		86,819		87,232
Accounts payable and other accrued liabilities		395,814		251,755
Accounts payable - related parties		423,998		84,592
Accrued interest		2,058,261		1,504,265
Net cash provided by (used in) operating activities		132,152		(496,667)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to crude oil and natural gas properties		(73,683)		(170,697)
Prepaid drilling costs		(22,276)		(2,350)
Proceeds from the sale of crude oil and natural gas properties		-		31,581
Collections of note receivable		-		777,500
Net cash provided by (used in) investing activities		(95,959)		636,034
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from debt		25,000		25,000
Principal payments on debt		-		(618,431)
Payment of deferred financing fees		-		(9,655)
Payments to line of credit		(26,185)		(26,058)
Net cash provided by (used in) financing activities		(1,185)		(629,144)
NET INCREASE (DECREASE)  IN CASH AND CASH EQUIVALENTS		35,008		(489,777)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		6,995		496,772
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	42,003	$	6,995
CASH PAID FOR:
Interest	$	98,659	$	1,292,066
Income taxes	$	-	$	-

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DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows (continued)

For the Twelve Months Ended February 28, 2017 and February 29, 2016

	Twelve Months Ended
	February 28, 2017		February 29, 2016
SUPPLEMENTAL CASH FLOW INFORMATION:
Unpaid additions to crude oil and natural gas properties	$	-	$	89,804
Interest and fees converted to principal on debt	$	1,567,795	$	1,487,779
Increase in note receivable for interest and fees added to principal	$	745,163	$	683,013
Satisfaction of note receivable through debt reduction	$	3,900,000	$	-
ARO asset and liability increase due to timing differences	$	11,806	$	47,362
Proceeds from sale of crude oil and natural gas properties paid directly to reduce debt	$	600,000	$	-
Unpaid deferred financing costs	$	20,854	$	-
Non-cash addition to debt for unproved O&G properties and prepaid drilling costs	$	84,000	$	-
Non-cash addition to debt for expenses paid directly by lender	$	215,000	$	-
Debt discount addition due to debt modification	$	29,075	$	-
Conversion of preferred stock to common stock	$	-	$	30

The accompanying notes are an integral part of these financial statements

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DAYBREAK OIL AND GAS, INC.

NOTES TO AUDITED FINANCIAL STATEMENTS

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION:

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

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

NOTE 2 — GOING CONCERN:

Financial Condition

Daybreak’s financial statements for the twelve months ended February 28, 2017 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  Daybreak has incurred net losses since inception and has accumulated a deficit of $35,879,469 and a working capital deficit of $13,152,928, which raises substantial doubt about the Company’s ability to continue as a going concern.

Management Plans to Continue as a Going Concern

The Company continues to implement plans to enhance its ability to continue as a going concern.  Daybreak currently has a net revenue interest in 20 producing crude oil wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”).  The revenue from these wells has created a steady and reliable source of revenue.  The Company’s average working interest in these wells is 36.6% and the average net revenue interest is 28.4% for these same wells.

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

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

Daybreak’s financial statements as of February 28, 2017 do not include any adjustments that might result from the inability to implement or execute Daybreak’s plans to improve our ability to continue as a going concern.

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NOTE 3 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Cash and Cash Equivalents

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

Accounts Receivable

The Company routinely assesses the recoverability of all material trade and other receivables.  The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated.  Actual write-offs may exceed the recorded allowance.  Substantially all of the Company’s trade accounts receivable result from crude oil in California or joint interest billings to its working interest partners in California.  This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors.  Trade accounts receivable are generally not collateralized.  There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2017 and February 29, 2016.

Crude Oil and Natural Gas Properties

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

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

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

The Company recognized asset impairments of $-0- and $1,108,683 for the twelve months ended February 28, 2017 and February 29, 2016, respectively.

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

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Property and Equipment

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

Long Lived Assets

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

Fair Value of Financial Instruments

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

Share Based Payments

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

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

Loss per Share of Common Stock

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

Concentration of Credit Risk

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

At the Company’s East Slopes project in California there is only one buyer available for the purchase of all crude oil production.  The Company has no natural gas production in California.  At February 28, 2017 and February 29, 2016, this one individual customer represented 100.0% of crude oil sales receivable from continuing operations.  If this buyer is unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its crude oil production.

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The Company’s accounts receivable from continuing operations in California for crude oil sales at February 28, 2017 and February 29, 2016 are set forth in the table below.

		February 28, 2017			February 29, 2016
Project	Customer	Accounts Receivable Crude Oil Sales		Percentage	Accounts Receivable Crude Oil Sales		Percentage
California – East Slopes Project (Crude oil)	Plains Marketing	$	83,405	100.0%	$	39,168	100.0%

Revenue Recognition

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

Reclamation Bonds

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

Asset Retirement Obligation (“ARO”)

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

Suspended Well Costs

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

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

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Income Taxes

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

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

Use of Estimates and Assumptions

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

·

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

·

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

·

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

·

Estimates regarding the timing and cost of future abandonment obligations.

Recent Accounting Pronouncements

There are no new accounting pronouncements issued or effective that had, or are expected to have, a material impact on the Company’s financial statements.

Reclassifications

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

NOTE 4 — ACCOUNTS RECEIVABLE:

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

Crude oil sales receivables balances from continuing operations of $83,405 and $39,168 at February 28, 2017 and February 29, 2016 represent crude oil sales that occurred in February 2016 and 2015, respectively.

Joint interest participant receivables balances of $55,154 and $106,694 at February 28, 2017 and February 29, 2016, respectively, represent amounts due from working interest partners in California, where the Company is the Operator.  There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2017 and February 29, 2016.

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NOTE 5 — PRODUCTION REVENUE RECEIVABLE:

The production revenue receivable balance of $-0- and $45,000 at February 28, 20178 and February 29, 2016, represents amounts due the Company from a portion of the sale price of a 25% working interest in East Slopes Project in Kern County, California that was acquired through the default of certain original working interest partners in the project.

NOTE 6 — DEFERRED FINANCING COSTS:

Deferred Financing Costs - Maximilian Credit Facility

Deferred financing costs at February 28, 2017 and February 29, 2016 relating to the original and the amended credit facility with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in these notes to the financial statements as “Maximilian”), are set forth in the table below:

	February 28, 2017		February 29, 2016
Deferred financing costs – loan fees	$	181,648	$	160,794
Deferred financing costs – loan commissions		630,662		630,662
Deferred financing costs – fair value of warrants		530,488		530,488
Deferred financing costs – fair value of common stock		419,832		419,832
		1,762,630		1,741,776
Accumulated amortization		(1,524,032)		(1,100,701)
	$	238,598	$	641,075

Amortization expense of deferred financing costs was $423,331 and $427,331 for the twelve months ended February 28, 2017 and February 29, 2016, respectively.  Deferred financing costs of $238,598 at February 28, 2017 includes the fair value of common shares and warrants issued to Maximilian and to a third party that assisted in both the original and the amended financing transactions.  The unamortized deferred financing costs are netted against debt (see Note 13) in the balance sheets.

NOTE 7 — CRUDE OIL PROPERTIES:

Crude oil property balances from continuing operations at February 28, 2017 and February 29, 2016 are set forth in the table below:

	February 28, 2017		February 29, 2016 (1)
Proved leasehold costs	$	115,119	$	115,119
Costs of wells and development		2,293,668		2,293,668
Capitalized exploratory well costs		1,341,494		1,341,494
Capitalized asset retirement costs		56,497		44,692
Total cost of oil and gas properties		3,806,778		3,794,973
Accumulated depletion, depreciation amortization and impairment		(2,953,226)		(2,851,332)
Oil and gas properties, net	$	853,552	$	943,641

⁽¹⁾The February 29, 2016 balances have been adjusted to reflect the sale of the Twin Bottoms Field in Kentucky on October 31, 2016.

NOTE 8 — Asset Retirement Obligation (“ARO”)

The Company’s financial statements reflect the provisions of ASC 410.  The ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws.  The Company determines the ARO on its crude oil and natural gas properties by calculating the present value of estimated cash flows related to the liability.  As of February 28, 2017 and February 29, 2016, ARO obligations were considered to be long-term based on the estimated timing of the anticipated cash flows.  For the twelve months ended February 28, 2017 and February 29, 2016, the Company recognized accretion expense of $8,390 and $2,704, respectively which is included in DD&A in the statement of operations.

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Changes in the asset retirement obligations for the twelve months ended February 28, 2017 and February 29, 2016 are set forth in the table below.

	February 28, 2017		February 29, 2016
Asset retirement obligation, beginning of period	$	73,213	$	26,765
Accretion expense		8,390		2,704
Change in asset retirement estimates		11,806		43,744
Asset retirement obligation, end of period	$	93,409	$	73,213

NOTE 9 — DISCONTINUED OPERATIONS AND ASSETS/LIABILITIES HELD FOR SALE:

Effective October 31, 2016, the Company finalized the sale of its interest in the Twin Bottoms Field in Kentucky.  The sale included Daybreak’s working interest in 14 producing horizontal crude oil wells, its mineral rights, its lease acreage and infrastructure.  As a result of this sale and the restructuring of its Balance Sheet, the Company recognized income of $394,623 on discontinued operations which includes; an approximate $1.96 million loss on the sale of oil and natural gas properties; a reduction of $4.5 million in debt associated with Kentucky; a loss on note receivable settlement of approximately $1.5 million; and gain on debt settlement of approximately $3.9 million with its lender Maximilian for the twelve months ended February 28, 2017.  In accordance with the guidance provided in ASC 205-20, the Company concluded that this sale qualified for presentation as discontinued operations.  The Company has no ongoing or future plans to be involved in this segment of its oil and natural gas projects.  Prior period income statement balances applicable to the Twin Bottoms Field in Kentucky have been reclassified and are included under the Discontinued Operations caption in the statements of operations while related assets and liabilities were reclassified to Assets Held for Sale and Liabilities Held for Sale, respectively on the balance sheet.

Operating income, interest income, operating expenses and interest expense related to Kentucky for the twelve months ended February 28, 2017 and February 29, 2016 are set forth in the tables below.

	For the Twelve Months Ended
	February 28, 2017		February 29, 2016
Crude oil and natural gas sales revenue	$	280,030	$	724,326
Interest income		760,704		1,039,853
Production, exploration and drilling expenses		(65,157)		(134,016)
Depreciation, Depletion and Amortization (“DD&A”) expenses		(124,169)		(276,790)
General & Administrative expense		(204,056)		-
Interest expense		(723,206)		(873,920)
Loss on note receivable settlement		(1,500,676)		-
Loss on sale of O&G properties		(1,955,315)		-
Gain on debt settlement		3,926,468		-
Income (loss) from discontinued operations	$	(394,623)	$	479,453

The reconciliation of the carrying amounts of major classes of assets and liabilities held of sale from discontinued operations as of February 28, 2017 and February 29, 2016 are set forth in the table below.

Major Classes of Assets Presented as a part of Discontinued Operations	February 28, 2017		February 29, 2016(1)
Kentucky oil and natural gas properties, net	$	-	$	2,822,186
Note receivable – App Energy LLC (Kentucky funding)		-		4,655,513
Trade receivables – Kentucky related		-		104,595
Total Assets Held for Sale (Current and Non-current)	$	-	$	7,582,294

Major Classes of Liabilities Presented as a part of Discontinued Operations	February 28, 2017		February 29, 2016(1)
Trade payables – Kentucky related	$	-	$	136,619
Debt related to Kentucky		-		4,624,863
Asset retirement obligation (ARO) - Kentucky		-		6,766
Total Liabilities Held for Sale (Current and Non-current)	$	-	$	4,768,248

⁽¹⁾Amounts in the February 29, 2016 balance sheet are classified as current and long-term.

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

Certain significant non-cash operating and investing items for discontinued operations in Kentucky during the twelve months ended February 29, 2016 included increase in note receivable for interest added to principal of $683 thousand; unpaid additions to crude oil and natural gas properties of $90 thousand; and, DD&A expense of $277 thousand.

NOTE 10 — NOTE RECEIVABLE:

On October 31, 2016, the Company and App Energy, LLC, a Kentucky limited liability company (“App Energy”), sold their interests in the Twin Bottoms field in Kentucky.  The note receivable from App Energy for funds advanced by the company to App Energy for drilling in Kentucky was considered to be paid in full as a part of the sale of the Twin Bottoms Field.  The $3.9 million App Energy received from the sale of their working interest in Kentucky was used to pay down a portion of the associated note receivable.  The remaining balance of approximately $1.5 million was recorded as a loss on the settlement of the note receivable.  The associated debt the Company owed to Maximilian Resources LLC (“Maximilian”) of approximately $5.4 million was eliminated through the sale of the Twin Bottoms Field.

NOTE 11 — ACCOUNTS PAYABLE:

On March 1, 2009, the Company became the operator for the East Slopes Project located in Kern County, California.  Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning wells program.  The Company subsequently sold the 25% working interest on June 11, 2009.  Approximately $244,849 of the $1.5 million default remains unpaid and is included in the February 28, 2017 accounts payable balance.

NOTE 12 — ACCOUNTS PAYABLE- RELATED PARTIES:

The February 28, 2017 and February 29, 2016 accounts payable – related parties balances of $1,414,481 and $990,483, respectively, were comprised primarily of deferred salaries of the Company’s Executive Officers and certain employees; deferred directors’ fees; expense reimbursements; related party consulting fees; and deferred interest payments on the 12% Subordinated Note to the Company’s Chairman, President and Chief Executive Officer.  Payment of these deferred items has been delayed until the Company’s cash flow situation improves.

NOTE 13 — SHORT-TERM AND LONG-TERM BORROWINGS:

Note Payable – Related Party

At February 28, 2017 and February 29, 2016, the Company’s Chairman, President and Chief Executive Officer had loaned the Company an aggregate $250,100 during the years ended February 29, 2012 and February 28, 2013, that was used for a variety of corporate purposes including an escrow requirement on a loan commitment; maturity extension fees on third party loans; and a reduction of principal on the Company’s credit line with UBS Bank.  These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.

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 the Company’s Chairman, President and Chief Executive Officer.  At February 28, 2017 and February 29, 2016, the Line of Credit had an outstanding balance of $817,622 and $843,807, respectively.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $33,815 and $31,442 for the years ended February 28, 2017 and February 29, 2016, respectively.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

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Maximilian Credit Facility

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

Maximilian Loan - Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App Energy, LLC, a Kentucky limited liability company (“App Energy”) in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013.  The amendment increased the amount of the credit facility to $90 million and reduced the annual interest rate to 12%.

As consideration for Maximilian facilitating the Company’s transactions with App Energy 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.

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.

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 are amortized over the term of the amended loan agreement.  Amortization expense of deferred financing costs was $423,331 and $427,331 for the twelve months ended February 28, 2017 and February 29, 2016, respectively.  Unamortized deferred financing costs were $238,598 at February 28, 2017.

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

On 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.

The additional advance, the reduction in the required monthly payment and the reduction in the interest rate were facilitated through the Company’s acquisition of 5,694,823 shares of its common stock held by Maximilian.  The repurchased shares were cancelled and restored to the status of authorized, but unissued stock.  The Company 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 held from $0.10 to $0.04.  No other terms of the warrant agreement were changed.  The modification did not result to any accounting since these warrants were deemed to be investor warrants.

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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 allowed 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 was 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 Third 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.

On October 31, 2016, the Company entered into a Fourth Amendment to the Amended and Restated Loan and Security Agreement with Maximilian, which amended the Company’s loan agreement with Maximilian (the “Restructuring Agreement”).  Pursuant to the Restructuring Agreement, in exchange for the proceeds it received from the Kentucky Sale, Maximilian and the Company have agreed to: (1) the deemed payment in full and/or forgiveness of approximately $8.3 million in outstanding indebtedness under the Daybreak Loan Agreement (which includes approximately $5.4 million in indebtedness that was loaned by the Company to App Energy pursuant to the Loan and Security Agreement between the parties dated as of August 28, 2013, as amended from time to time); (2) a commitment by Maximilian to forgive an additional amount of indebtedness under the Daybreak Loan Agreement, currently estimated to be $3.2 million, in the event of the future issuance of senior preferred stock by the Company to it; (3) the deemed payment in full and termination of the App Loan Agreement; (4) the termination and release of all liens, security interests and other interests held by Maximilian or its affiliates in any of the Company’s or App Energy’s Kentucky oil and natural gas assets, including the termination of the overriding royalty interests and net profits interests held by Maximilian and/or its affiliates; (5) amendments to the Daybreak Loan Agreement to suspend principal and interest payments for up to six months and extend the maturity date to February 28, 2020; (6) a commitment by Maximilian to advance up to $250,000 in financing to the Company over the next six months; (7) the pursuit of the Michigan Joint Venture using the $250,000 set aside from the Kentucky Sale.  The Company recognized a gain on debt settlement in aggregate of approximately $3.9 million through the sale of the Kentucky property and reduction in the outstanding credit facility balance.

As a result of the decline in hydrocarbon prices, the Company has been currently unable to make the interest or principal payments required under the terms of its credit facility with 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 restructuring the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue.  Further, our lender is under no obligation to advance us any additional funding and, rather, there can be no assurances that out lender will not declare the Company to be in default under the credit facility.  A change of control or management of our lender, among other reasons, could also result in our loan being called due and payable.

Maximilian Loan Agreement – Michigan Project

At February 28, 2017, the Company had received $84,000 in advances from Maximilian under a separate promissory note agreement dated January 17, 2017 and amended on February 10, 2017 regarding the development of an oilfield project in Michigan.  Advances under this agreement are subject to a 5% (five percent) per annum interest rate.  If a well that the Company elects to participate in is scheduled to be spudded at the Michigan oilfield project on or before December 31, 2017, then the advances under the promissory note must be repaid in full upon the earlier of (a) the time that is ten days prior to the first well being spudded on the Michigan oilfield project or (b) December 31, 2017.  If there is not a well scheduled to be spudded at the Michigan oilfield project on or before December 31, 2017 that the Company elects to participate in, then the Company will assign to Maximilian its working interest in the Michigan oilfield project, in full payment and satisfaction of the advances under the promissory note.  Advances under the promissory note may be prepaid at any time without penalty, and are secured by a mortgage on the Company’s working interest in the Michigan oilfield project.  In the event of a default of any of the Company’s obligations under the promissory note, the amounts due may be called immediately due and payable at Maximilian’s option.

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Current debt balances at February 28, 2017 and February 29, 2016 are set forth in the table below:

	February 28, 2017		February 29, 2016
Principal Balance	$	8,960,444	$	14,381,131
Less unamortized discount and debt issuance costs		(238,598)		(713,026)
Subtotal – O&G operating debt		8,721,846		13,668,105
Michigan project debt		84,000		-
Net debt	$	8,805,846	$	13,668,105

App Energy Note Receivable - Loan Agreement

On October 31, 2016, the Company and App Energy, LLC, a Kentucky limited liability company (“App Energy”), sold their interests in the Twin Bottoms field in Kentucky.  The note receivable from App Energy for funds advanced by the company to App Energy for drilling in Kentucky was considered to be paid in full as a part of the sale of the Twin Bottoms Field.  The $3.9 million App Energy received from the sale of their working interest in Kentucky was used to pay down a portion of the associated note receivable.  The remaining balance of approximately $1.5 million was recorded as a loss on the settlement of note receivable.  The associated debt the Company owed to Maximilian Resources LLC (“Maximilian”) of approximately $5.4 million was eliminated through the sale of the Twin Bottoms Field.

Non-current debt (Long-term borrowings)

12% Subordinated Notes

The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a January 2010 private placement, resulted in $595,000 in gross proceeds (of which $250,000 was from a related party) to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th.  On January 29, 2015, the Company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes for an additional two years to January 29, 2017.  Effective January 29, 2017, the maturity date of the Notes and the expiration date of the warrants that were issued in conjunction with the 12% Subordinated Notes from the January 2010 private placement offering to accredited investors were extended for an additional two years to January 29, 2019.  The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes.  The exercise price of the warrants was lowered from $0.14 to $0.07 as a part of the warrant modification.  The warrant expiration extension applied to noteholders who chose to extend the maturity date of the 12% Subordinated Notes for an additional two years and had not already exercised the associated warrants.  Ten noteholders had the expiration date of their warrants extended to January 29, 2019.  The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes.  The Black-Scholes valuation encompassed the following weighted average assumptions: a risk free interest rate of 1.22%; volatility of 378.73%; and dividend yield of 0.0%.  Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2018.  At February 28, 2017 and February 29, 2016, amortization expense was $1,211 and $-0-, respectively.  The unamortized debt discount at February 28, 2017 and February 29, 2016 was $27,864 and $-0-, respectively.

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

	February 28, 2017		February 29, 2016
12% Subordinated Notes	$	315,000	$	315,000
Debt discount		(15,535)		-
Net 12% Subordinated Note balance	$	299,465	$	315,000

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

	February 28, 2017		February 29, 2016
12% Subordinated Notes – related party	$	250,000	$	250,000
Debt discount		(12,329)		-
Net 12% Subordinated Note – related party balance	$	237,671	$	250,000

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In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.07 and an amended expiration date of January 29, 2019.  The 12% Note warrants that have been exercised are set forth in the table below.  At February 28, 2017, there were 980,000 warrants that were not exercised and had not expired.

Fiscal Period	Warrants Exercised	Shares of Common Stock Issued	Number of Accredited Investors
Year Ended February 28, 2014	100,000	100,000	1
Year Ended February 28, 2015	50,000	50,000	1
Year Ended February 29, 2016	-	-	-
Year Ended February 28, 2017	-	-	-
Totals	150,000	150,000	2

NOTE 14 — DEBT DISCOUNT – 12% SUBORDINATED NOTES:

On January 29, 2027, the expiration date of the warrants associated with the 12% Subordinated Notes was extended to January 29, 2019.  As a part of this medication of the warrants the exercise price of the warrants was lowered from $0.14 to $0.07.  A Black-Scholes valuation determined the value of the modification to be $29,075.  The valuation is being treated as a discount to debt and is being amortized over the extended term of the expiration date of the warrants.  Amortization expense at February 28, 2017 was $1,211.  Unamortized debt discount was $27,864 at February 28, 2017.

NOTE 15 — STOCKHOLDERS’ DEFICIT:

Preferred Stock

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

Series A Convertible Preferred Stock

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

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

Voluntary Conversion:

The Series A Preferred that is currently issued and outstanding is eligible to be converted by the shareholder at any time into three shares of the Company’s common stock.  During the twelve months ended February 28, 2017 and February 29, 2016, there were no conversions of Series A Preferred.

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At February 28, 2017 there were 724,565 shares issued and outstanding that had not been converted into our common stock.  As of February 28, 2017, there are 43 accredited investors who have 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 is set forth in the table below.

Fiscal Period	Shares of Series A Preferred Converted to Common Stock	Shares of Common Stock Issued from Conversion	Number of Accredited Investors
Year Ended February 29, 2008	102,300	306,900	10
Year Ended February 28, 2009	237,000	711,000	12
Year Ended February 28, 2010	51,900	155,700	4
Year Ended February 28, 2011	102,000	306,000	4
Year Ended February 29, 2012	-	-	-
Year Ended February 28, 2013	18,000	54,000	2
Year Ended February 28, 2014	151,000	453,000	9
Year Ended February 28, 2015	3,000	9,000	1
Year Ended February 29, 2016	10,000	30,000	1
Year Ended February 28, 2017	-	-	-
Totals	675,200	2,025,600	43

Automatic Conversion:

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

Dividend:

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

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

Fiscal Year Ended	Shareholders at Period End	Accumulated Dividends
February 28, 2007	100	$	155,311
February 29, 2008	90		242,126
February 28, 2009	78		209,973
February 28, 2010	74		189,973
February 28, 2011	70		173,707
February 29, 2012	70		163,624
February 28, 2013	68		161,906
February 28, 2014	59		151,323
February 28, 2015	58		132,634
February 29, 2016	57		130,925
February 28, 2017	57		130,415
		$	1,841,917

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 28, 2017 and February 29, 2016.  There were no shares of the Company’s Common Stock issued during the twelve months ended February 28, 2017.

	Common Stock Balance	Par Value
Common stock, Issued and Outstanding, February 28, 2015	51,457,373
Conversion of Series A Convertible Preferred Stock to common stock	30,000	$	30
Common stock, Issued and Outstanding, February 29, 2016	51,487,373
Share issuances during the current year	-
Common stock, Issued and Outstanding, February 28, 2017	51,487,373

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.

Common Stock Issued through Restricted Stock and Restricted Stock Unit Plan

On April 6, 2009, the Board 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 to be eligible to receive restricted stock and restricted stock unit awards.  Refer to the discussion in Note 17 for the issuances made under the 2009 Plan.

NOTE 16 — WARRANTS:

Warrants outstanding and exercisable as of February 28, 2017 are set forth in the table below:

	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining
12% Subordinated notes	1,190,000	$0.07	1.92	980,000
Warrants issued in 2012 for debt financing	2,435,517	$0.044	0.67	316,617
Warrants issued for Kentucky oil project	3,498,601	$0.04	1.50	3,498,601
Warrants issued for Kentucky debt financing	2,623,951	$0.04	1.50	2,623,951
Warrants issued for Kentucky debt financing	309,503	$0.214	1.50	309,503
Warrants issued in share-for-warrant exchange	427,729	$0.04	1.50	427,729
	10,485,301			8,156,401

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Warrant activity for the twelve months ended February 29, 2016 and February 28, 2017 is set forth in the table below:

	Number of Warrants	Weighted Average Exercise Price
Warrants outstanding, February 28, 2015	8,306,401	$0.11
Changes during the twelve months ended February 29, 2016:
Expired / Cancelled / Forfeited	150,000	$0.14
Warrants outstanding, February 29, 2016	8,156,401	$0.06
Changes during the twelve months ended February 28, 2017:
Expired / Cancelled / Forfeited	-
Warrants outstanding, February 28, 2017	8,156,401	$0.05
Warrants exercisable, February 28, 2017	8,156,401	$0.05

On January 29, 2017, the 980,000 warrants associated with the 12% Subordinated Notes were modified to extend the expiration date of the warrants to January 29, 2019.  As a part of this modification the exercise price of the 12% Note warrants was changed from $0.14 to $0.07.  The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes.  No other terms of the warrants were affected by the modification.  The outstanding warrants as of February 28, 2017 and February 29, 2016 have a weighted average exercise price of $0.05 and $0.06; a weighted average remaining life of 1.52 and 2.28 years; and an intrinsic value of $-0-, respectively.

NOTE 17 — RESTRICTED STOCK and RESTRICTED STOCK UNIT PLAN:

On April 6, 2009, the Board approved the 2009 Plan allowing the executive officers, directors, consultants and employees of the Company and its affiliates to be eligible to receive restricted stock and restricted stock unit awards.  Subject to adjustment, the total number of shares of the Company’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.

The Company believes that awards of this type further align the interests of its employees and its shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.  Restricted stock and restricted stock units also enhance the Company’s ability to attract and retain the services of qualified individuals.

During the twelve months ended February 28, 2009, the Compensation Committee of the Board awarded a total of 2,550,000 restricted shares of the Company’s common stock to members of the Board of Directors, officers and employees of the Company.  These shares were granted pursuant to the 2009 Plan and fully vest equally over a period ranging from three to four years.

On July 22, 2010, the Compensation Committee of the Board awarded 25,000 restricted shares of its common stock to the five non-employee Directors as a part of the director compensation policy.  These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of three years.

On July 22, 2010, the Compensation Committee of the Board awarded 425,000 restricted shares of its common stock to five employees of Daybreak.  These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of four years.

For the twelve months ended February 28, 2017 and February 29, 2016 there were no shares that vested.  At February 28, 2017, all issued and outstanding shares in the 2009 stock plan had fully vested.  For the years ended February 28, 2017 and February 29, 2016, the number of common shares available for issuance under the Plan did not increase.

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At February 28, 2017, a total of 3,000,000 shares of restricted stock had been awarded and 2,986,220 shares of the 2009 Plan had fully vested.  A total of 1,013,780 common stock shares remained available for issuance pursuant to the 2009 Plan at February 28, 2016.  For the years ended February 28, 2017 and February 29, 2016 there were not any share that vested.  A summary of the 2009 Plan issuances is set forth in the table below:

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

⁽¹⁾

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

⁽²⁾

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

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

NOTE 18 — INCOME TAXES:

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

	February 28, 2017		February 29, 2016
Computed at U.S. and state statutory rates (40%)	$	(1,387,422)	$	(1,616,023)
Permanent differences		83,606		143,946
Changes in valuation allowance		1,303,816		1,472,077
Total	$	-	$	-

Tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred liabilities are presented below:

	February 28, 2017		February 29, 2016
Deferred tax assets:
Net operating loss carryforwards	$	10,425,780	$	10,217,121
Oil and gas properties		32,488		(944,342)
Stock based compensation		88,723		88,723
Other		(32,618)		(150,945)
Less valuation allowance		(10,514,373)		(9,210,557)
Total	$	-	$	-

At February 28, 2017, the Company had a net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $26,064,450, which will begin to expire, if unused, beginning in 2024.  The valuation allowances increased by $1,303,816 and $1,472,077 for the years ended February 28, 2017 and February 29, 2016, respectively.  Section 382 Rule of the Internal Revenue Code will place annual limitations on the Company’s NOL carryforward.

The above estimates are based upon management’s decisions concerning certain elections that could change the relationship between net income and taxable income.  Management decisions are made annually and could cause the estimates to vary significantly.  The Company’s files federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions.  As a general rule, the Company’s tax returns for the fiscal years after 2011 currently remain subject to examinations by appropriate tax authorities.  None of our tax returns are under examination at this time.

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NOTE 19 — COMMITMENTS AND CONTINGENCIES:

Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities.  While the ultimate outcome of the aforementioned contingencies are not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment.  These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages.  In some instances, the Company may be directed to suspend or cease operations in the affected area.  The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of February 28, 2017.  There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

NOTE 20 — SUBSEQUENT EVENTS:

At May 9, 2017, one holder of the Company’s Series A Convertible Preferred stock converted their 14,997 shares of Series A Preferred stock into 44,991 shares of the Company’s common stock.

NOTE 21 — SUPPLEMENTARY INFORMATION FOR CRUDE OIL PRODUCING ACTIVITIES (UNAUDITED)

Discontinued operations information comprising the sale of the Company’s Kentucky assets, effective October 31, 2016, has not been segregated from our continuing operations in California in the Supplemental Information for Crude Oil Producing Activities presented below for the twelve months ended February 29, 2016.

Capitalized Costs Relating to Crude Oil and Natural Gas Producing Activities

	As of February 28, 2017		As of February 29, 2016
Proved leasehold costs
Mineral Interests	$	115,119	$	654,445
Wells, equipment and facilities		3,691,659		6,095,262
Total Proved Properties		3,806,778		6,749,707
Unproved properties
Mineral Interests		59,375		585,826
Uncompleted wells, equipment and facilities		-		-
Total unproved properties		59,375		585,826
Less accumulated depreciation, depletion amortization and impairment		(2,953,226)		(3,569,705)
Net capitalized costs	$	912,927	$	3,765,828

Costs Incurred in Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	February 28, 2017		February 29, 2016
Acquisition of proved properties	$	-	$	-
Acquisition of unproved properties		59,375		-
Development costs		-		243,823
Exploration costs		-		76,053
Total costs incurred	$	59,375	$	319,876

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Results of Operations from Oil and Gas Producing Activities

Discontinued operations information comprising the sale of the Company’s Kentucky assets, effective October 31, 2016, has not been segregated from our continuing operations in California for the Results of Operations information presented below for the twelve months ended February 29, 2016.

	12 Months Ended		12 Months Ended
	February 28, 2017		February 29, 2016
Oil and gas revenues	$	762,686	$	1,253,686
Production costs		(221,579)		(268,448)
Exploration expenses		(16,529)		(76,053)
Depletion, depreciation and amortization		(234,454)		(517,870)
Impairment of oil properties		-		(1,108,683)
Result of oil and gas producing operations before income taxes		290,124		(717,368)
Provision for income taxes		-		-
Results of oil and gas producing activities	$	290,124	$	(717,368)

Proved Reserves

The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, PGH Petroleum and Environmental Engineers, LLC.  Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods when the estimates were made.  Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available.  The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate.  Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors.  Our proved reserves are summarized in the table below:

	Oil (Barrels)	Natural Gas (Mcf)	BOE (Barrels)
Proved reserves:
February 28,  2015	845,659	254,860	888,136
Revisions(1)	(120,001)	390,693	(54,886)
Discoveries and extensions	76,270	161,320	103,157
Production	(28,818)	(28,853)	(33,627)
February 29, 2016	773,110	778,020	902,780
Revisions(1)	(13,145)	-	(13,145)
Sales of minerals	(360,018)	(761,517)	(486,937)
Production	(18,877)	(16,503)	(21,628)
February 28, 2017	381,070	-	381,070

(1)

The revisions of previous estimates resulted from a decline in the estimated economic life of the reserves due to lower realized crude oil prices in the energy markets.

The Company’s proved reserves are set forth in the table below.

	Developed		Undeveloped		Total Reserves
	Oil (Bbls)	BOE (Bbls)	Oil (Bbls)	BOE (Bbls)	Oil (Bbls)	BOE (Bbls)
February 28, 2017	99,710	99,710	281,360	281,360	381,070	381,070
February 29, 2016	203,131	231,778	569,979	671,002	773,110	902,780
February 28, 2015	278,233	294,585	567,426	593,551	845,659	888,136

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of February 28, 2017 and February 29, 2016 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate.  This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

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Future cash inflows for the years ended February 28, 2017 and February 29, 2016 were estimated as specified by the SEC through calculation of an average price based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from March through February during each respective fiscal year.  The resulting net cash flows are reduced to present value by applying a 10% discount factor.

	12 Months Ended
	February 28, 2017		February 29, 2016
Future cash inflows	$	13,684,350	$	34,077,610
Future production costs(1)		(7,377,450)		(16,255,030)
Future development costs		(2,090,810)		(7,278,930)
Future income tax expenses(2)		-		-
Future net cash flows		4,216,090		10,543,650
10% annual discount for estimated timing of cash flows		(2,493,750)		(6,570,720)
Standardized measure of discounted future net cash flows at the end of the fiscal year	$	1,722,340	$	3,972,930

(1)

Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s oil and gas operations.

(2)

The Company has sufficient tax deductions and allowances related to proved oil and gas reserves to offset future net revenues.

Average hydrocarbon prices are set forth in the table below.

	Average Price		Natural
	Crude Oil (Bbl)		Gas (Mcf)
Year ended February 28, 2017(1)	$	40.00	$	1.59
Year ended February 29, 2016(1)	$	47.45	$	2.51
Year ended February 28, 2015(1)	$	85.53	$	2.99

(1)

Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year.

Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.

Sources of Changes in Discounted Future Net Cash Flows

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by ASC 932, at fiscal year-end are set forth in the table below.

	12 Months Ended
	February 28, 2017		February 29, 2016
Standardized measure of discounted future net cash flows at the beginning of the year	$	3,972,930	$	17,504,700
Extensions, discoveries and improved recovery, less related costs		-		271,190
Revisions of previous quantity estimates		(88,875)		(408,300)
Sales of minerals in place		(1,948,968)		-
Net changes in prices and production costs		(1,289,038)		(10,040,886)
Accretion of discount		397,293		1,750,470
Sales of oil produced, net of production costs		(541,107)		(985,238)
Development costs incurred during the period		4,654		213,576
Changes in future development costs		262,156		526,413
Changes in timing of future production		953,295		(4,858,995)
Net changes in income taxes		-		-
Standardized measure of discounted future net cash flows at the end of the year	$	1,722,340	$	3,972,930

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ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A.   CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

As of the end of the reporting period, February 28, 2017, an evaluation was conducted by Daybreak’s management, including our President and Chief Executive Officer, also serving as our interim principal finance and accounting officer, as to the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Exchange Act.  Such disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods specified by the SEC rules and forms.  Additionally, it is vital that such information is accumulated and communicated to our management including our President and Chief Executive Officer, in a manner to allow timely decisions regarding required disclosures.  Based on that evaluation, our management concluded that our disclosure controls were effective as of February 28, 2017.

Internal Control Over Financial Reporting

The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Our internal controls over financial reporting include those policies and procedures that:

1)

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

2)

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made in accordance with authorizations of management and our Board of Directors; and

3)

provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.

Because of the inherent limitations due to, for example, the potential for human error or circumvention of controls, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Management’s Report on Internal Control Over Financial Reporting

Daybreak’s management, including our President and Chief Executive Officer, also serving as our interim principal finance and accounting officer is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act.  Our management assessed the effectiveness of our internal control over financial reporting as of February 28, 2017.  In making this assessment, management used certain criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.  Based on such assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of February 28, 2017.

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to SEC rules that permit the company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the quarter ended February 28, 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Limitations

Our management does not expect that our disclosure controls or internal controls over financial reporting will prevent all errors or all instances of fraud.  A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met.  Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.

Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected.  These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.  Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls.  The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and any design may not succeed in achieving its stated goals under all potential future conditions.

Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.  Because of the inherent limitation of a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

ITEM 9B.   OTHER INFORMATION

None.

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PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Directors of Daybreak Oil and Gas, Inc.

The following information reflects the business experience of each individual serving on the Board of Directors (the “Board”) of Daybreak Oil and Gas, Inc.

		Director
Name	Age	Since
Wayne G. Dotson	82	2008
Timothy R. Lindsey	65	2007
James F. Meara	64	2008
James F. Westmoreland	61	2008

Wayne G. Dotson has served as a member of the Board of Directors since July 2008.  Mr. Dotson practiced oil and gas law, specializing in representation of various bank energy lending departments, including representing the banks in oil and gas company loans of up to $500 million, secured by oil and gas properties.  His experience includes review of title information on oil and gas leases, preparation of mortgage and other security documents, and preparation of complex credit agreements and other related documents.  From 1961 through 1984, Mr. Dotson was employed with the Texas law firm of Foreman, Dyess, Prewett, Rosenberg & Henderson, which later became Foreman & Dyess.  From 1984 through 1990, Mr. Dotson was employed with the law firm of Dotson, Babcock & Scofield.  In addition to legal practice at Dotson, Babcock and Scofield, Mr. Dotson served as Managing Partner and a member of the Compensation Committee.  After Dotson, Babcock & Scofield merged with Jackson Walker, LLP in 1990, Mr. Dotson continued his service until his retirement from the firm on January 1, 2008.  During his tenure with Jackson Walker, a law firm of 350 attorneys located in seven Texas cities, he also served on the Management Committee, Compensation Committee, and Business Development Committee.  Mr. Dotson received his Bachelor of Business Administration in 1957 and Juris Doctorate in 1961 from the University of Texas.

Timothy R. Lindsey has served as a member of the Board of Directors since January 2007.  He served as the Company’s Interim President and Chief Executive Officer from December 2007 until his resignation in October 2008.  Mr. Lindsey has over 40 years of energy and mineral exploration, technical and executive leadership in global exploration, production, technology, and business development.  From March 2005 to the present, Mr. Lindsey has been the Principal of Lindsey Energy and Natural Resources, an independent consulting firm specializing in energy and mining industry issues.  From May 2008 to the present, Mr. Lindsey has also been the President and a director of Canadian Sahara Energy Inc., a private company incorporated in Canada.  From September 2003 to March 2005, Mr. Lindsey held executive positions including Senior Vice-President, Exploration with The Houston Exploration Company, a Houston-based independent natural gas and oil company formerly engaged in the exploration, development, exploitation and acquisition of domestic natural gas and oil properties.  From October 1975 to February 2003, Mr. Lindsey was employed with Marathon Oil Corporation, a Houston-based company engaged in the worldwide exploration and production of crude oil and natural gas, as well as the domestic refining, marketing and transportation of petroleum products.  During his 27-year tenure with Marathon, Mr. Lindsey held a number of positions including senior management roles in both domestic and international exploration and business development.  Mr. Lindsey served as a director and Chairman of the Board of Directors of Revett Mining Company., a publicly-listed company with mining activities in Montana from April 2009 until the merger of Revett Mining Company into Helca Mining in June 2015.  Mr. Lindsey obtained his Bachelor of Science degree in geology at Eastern Washington University in 1973, and completed graduate studies in economic geology from the University of Montana in 1975.  In addition, he completed the Advanced Executive Program from the Kellogg School of Management, Northwestern University, in 1990.  Mr. Lindsey is a member of the American Association of Petroleum Geologists, the Rocky Mountain Association of Geologists, the Montana Mining Association, and, the American Exploration and Mining Association.

James F. Meara has served as a member of the Board of Directors since March 2008.  From 1980 through December 2007, Mr. Meara was employed with Marathon Oil Corporation, a Houston-based company engaged in the worldwide exploration and production of crude oil and natural gas, as well as the domestic refining, marketing and transportation of petroleum products.  During his 27-year tenure with Marathon, Mr. Meara moved through a series of posts in the tax department, becoming manager of Tax Audit Systems and Planning in 1988, and in 1995 he was named Commercial Director of Sakhalin Energy in Moscow, Russia.  In 2000, Mr. Meara served as Controller and was appointed to Vice President of Tax in January 2002, serving until his retirement in December 2007.  He also serves as a director of Canadian Sahara Energy Inc., a private company incorporated in Canada.  Mr. Meara holds a bachelor’s degree in accounting from the University of Kentucky and a master’s degree in business administration from Bowling Green State University, and is a member of the American Institute of Certified Public Accountants.

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James F. Westmoreland was elected Chairman of the Board of Directors in 2014, and appointed President and Chief Executive Officer and director in October 2008.  He also serves as interim principal finance and accounting officer.  Prior to that, he had been our Executive Vice President and Chief Financial Officer since April 2008.  He also served as the Company’s interim Chief Financial Officer from December 2007 to April 2008.  From August 2007 to December 2007, he consulted with the Company on various accounting and finance matters.  Prior to that time, Mr. Westmoreland was employed in various financial and accounting capacities for The Houston Exploration Company for 21 years, including Vice President, Controller and Corporate Secretary, serving as its Vice President and Chief Accounting Officer from October 1995 until its acquisition by Forest Oil Corporation in June 2007.  Mr. Westmoreland has almost 40 years of experience in oil and gas accounting, finance, corporate compliance and governance, both in the public and private sector.  He earned his Bachelor of Business Administration in accounting from the University of Houston.

When analyzing whether directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board of Directors to satisfy its oversight responsibilities effectively in light of the Company’s business and structure, the Governance Committee and the Board focus on the information as summarized in each of the Directors’ individual biographies set forth above.

In particular, the Governance Committee and the Board considered:

·

Mr. Dotson’s extensive legal career and knowledge of financing in the crude oil and natural gas industry.

·

Mr. Lindsey’s over 40 year career as a successful senior executive in the energy industry, his extensive knowledge of the industry and his active participation in energy related professional organizations are also valuable assets to the Board.  His knowledge and expertise in the energy business and management leadership regarding the issues affecting our business have been invaluable to the Board of Directors in overseeing the business affairs of our Company.  Further, the Committee believes that his extensive background and service with other public companies in the energy and mining sectors and his technical expertise provide the Board with superior leadership and decision-making skills.

·

Mr. Meara’s education, executive leadership roles and 27 year work experience in finance, tax and accounting in the crude oil and natural gas industry provide the knowledge and financial expertise needed to serve on the Board and the Company’s audit committee.

·

Mr. Westmoreland’s almost 40 year career in various financial and accounting capacities, including Vice President, Chief Accounting Officer, Controller and Corporate Secretary at a public crude oil and natural gas company along with his recent experience as President, Chief Executive Officer, Executive Vice President and Chief Financial Officer of the Company.  The Board also considered his role in reorganizing the Company and his day-to-day management of the Company.

Executive Officers of Daybreak Oil and Gas, Inc.

Executive officers are elected annually by our Board and serve at the discretion of the Board.  There are no arrangements or understandings between any of the directors, officers, and other persons pursuant to which such person was selected as an executive officer.

The following information concerns our executive officers, including the business experience of each during the past five years:

		Executive
Name	Age	Since	Office
James F. Westmoreland	61	2007	Chairman of the Board, President and Chief Executive Officer
Bennett W. Anderson	56	2006	Chief Operating Officer

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James F. Westmoreland was elected Chairman of the Board of Directors in 2014, and appointed President and Chief Executive Officer and director in October 2008.  He also serves as interim principal finance and accounting officer.  Prior to that, he had been our Executive Vice President and Chief Financial Officer since April 2008.  He also served as the Company’s interim Chief Financial Officer from December 2007 to April 2008.  From August 2007 to December 2007, he consulted with the Company on various accounting and finance matters.  Prior to that time, Mr. Westmoreland was employed in various financial and accounting capacities for The Houston Exploration Company for 21 years, including Vice President, Controller and Corporate Secretary, serving as its Vice President and Chief Accounting Officer from October 1995 until its acquisition by Forest Oil Corporation in June 2007.  Mr. Westmoreland has over 30 years of experience in crude oil and natural gas accounting, finance, corporate compliance and governance, both in the public and private sector.  He earned his Bachelor of Business Administration in accounting from the University of Houston.

Bennett W. Anderson was appointed Chief Operating Officer in 2006.  Prior to that time, he was a private investor from 2002 - 2006.  He served as a Senior Vice President with Novell, Inc. from 1998-2002.  Mr. Anderson’s duties included product direction, strategy and market direction, and training and support for the field sales staff.  From 1978 to 1982, Mr. Anderson worked as a rig hand and was involved in drilling over a dozen wells in North Dakota.  He holds a Bachelor of Science from Brigham Young University in Computer Science and graduated with University Honors of Distinction.

Legal Proceedings

On October 15, 2010, Canadian Sahara Energy Inc. (“Sahara”), a private Canadian crude oil and natural gas firm of which Mr. Lindsey is an executive officer and director, filed a Notice of Intention to File a Proposal under the Bankruptcy and Insolvency Act (Canada) (“BIA”) in order to obtain a stay of proceedings for a disputed crude oil and natural gas asset located in north Africa.  A Proposal was filed within 30 days as required under the BIA.  The sole creditor under the Proposal did not accept the Proposal, but was otherwise satisfied by the lifting of the stay.  Although no funds were owing, Sahara was deemed to be in bankruptcy, as a technical matter under the BIA.  A second Proposal will result in Sahara emerging from bankruptcy with a certification of full performance when accepted and approved by the Courts.  Sahara has advised that it anticipates that the second Proposal will be accepted.

As of the date hereof, it is the opinion of management that there is no other material proceeding to which any other director, officer or affiliate of the registrant, any owner of record or beneficially of more than five percent of any class of voting securities of the registrant, or any associate of any such director, officer, affiliate of the registrant, or security holder is a party adverse to the registrant or any of its subsidiaries or has a material interest adverse to the registrant or any of its subsidiaries.

None of Daybreak’s other current directors or Executive Officers has, during the past ten years:

a)

Had any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

b)

Been convicted in a criminal proceeding or been subject to a pending criminal proceeding;

c)

Been the subject of any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or

d)

Been found by a court of competent jurisdiction (in a civil action), the Securities and Exchange Commission or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our directors, officers and beneficial owners of more than 10% of our common stock to file initial reports of ownership and reports of changes in ownership of common stock on Forms 3, 4 and 5 with the SEC.  Directors, officers and beneficial owners of more than 10% of our common stock are required by SEC regulations to furnish us with copies of any forms that they file.  We assist our directors and executive officers in complying with these requirements and are required to disclose in this Annual Report on Form 10-K the failure to file these reports on behalf of any reporting person when due.

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With respect to our officers and directors, based solely on our review of such reports and written representations that no other reports were required, we believe that all such Section 16(a) reports for our officers and directors were timely filed during the fiscal year ended February 28, 2017.

Code of Ethics

Ethical Business Conduct Policy Statement and Code of Ethics for Senior Financial Officers

All of our employees, officers and directors are required to comply with our Ethical Business Conduct Policy Statement to help ensure that our business is conducted in accordance with the highest standards of moral and ethical behavior.  Our Ethical Business Conduct Policy covers all areas of professional conduct including:

·

Conflicts of interest;

·

Customer relationships;

·

Insider trading of our securities;

·

Financial disclosure;

·

Protection of confidential information; and

·

Strict legal and regulatory compliance.

Our employees, officers and directors are required to certify their compliance with our Ethical Business Conduct Policy Statement once each year.

In addition to the Ethical Business Conduct Policy Statement, all members of our senior financial management, including our President and Chief Executive Officer, have agreed in writing to our Code of Ethics for Senior Financial Officers, which prescribes additional ethical obligations pertinent to the integrity of our internal controls and financial reporting process, as well as the overall fairness of all financial disclosures.

The full text of our Ethical Business Conduct Policy Statement and the Code of Ethics for Senior Financial Officers are available under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com and are also available upon request, without charge, by contacting the Corporate Secretary at Daybreak Oil and Gas, Inc., 1101 N. Argonne Rd., Suite A 211, Spokane Valley, Washington 99212.

We intend to promptly disclose via a Current Report on Form 8-K or an update to our website information any amendment to, or waiver of, these codes with respect to our executive officers and directors.

Consideration of Nominees and Qualifications for Nominations to the Board of Directors

Our Corporate Governance Guidelines, which can be found under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com, contain Board membership criteria that apply to nominees recommended by the Nominating and Corporate Governance Committee (the “Governance Committee”) for a position on the Board.  The Corporate Governance Guidelines state that the Board’s Governance Committee is responsible for making recommendations to the Board concerning the appropriate size and composition of the Board, as well as for recommending to the Board nominees for election or re-election to the Board.  In formulating its recommendations for Board nominees, the Governance Committee will assess each proffered candidate’s independence and weigh his or her qualifications in accordance with the Governance Committee’s stated Qualifications for Nominations to the Board of Directors, which can be found under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com.

Audit Committee

The Audit Committee is responsible for monitoring the integrity of the Company’s financial reporting standards and practices and its financial statements, overseeing the Company’s compliance with ethics and legal and regulatory requirements, and selecting, compensating, overseeing and evaluating the Company’s independent registered public accountants.

During the fiscal year ended February 28, 2017, the Audit Committee met four times.  The Audit Committee operates under a charter that is available under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com and also upon request, without charge, by contacting the Corporate Secretary at Daybreak Oil and Gas, Inc., 1101 N. Argonne Road, Suite A 211, Spokane Valley, Washington 99212.

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The Audit Committee’s purpose is to assist the Board in fulfilling its responsibility to oversee management activities related to accounting and financial reporting policies, internal controls, auditing practices and related legal and regulatory compliance.  In that connection, the Audit Committee is directly responsible for the appointment, compensation, retention and oversight of the work of our independent registered public accountants for the purposes of preparing or issuing an audit report or performing other audit, review or attest services.  The Audit Committee determines the independence of our independent registered public accountants, and our independent registered public accountants report directly to the Audit Committee, which also must review and pre-approve the current year’s audit and non-audit fees.  The Audit Committee has the authority to select, retain and/or replace consultants to provide independent advice to the Committee.

The Audit Committee charter prescribes the Committee’s functions, which include the following:

·

Maintaining our compliance with legal and regulatory requirements relating to financial reporting accounting and controls;

·

Overseeing our whistleblower procedures;

·

Overseeing the pre-approval of audit fees;

·

Appointing and overseeing our independent registered public accountants;

·

Overseeing our internal audit function;

·

Overseeing the integrity of our financial reporting processes, including the Company’s internal controls;

·

Assessing the effect of regulatory and accounting initiatives, as well as any off-balance sheet structures, on our financial statements;

·

Reviewing our earnings press releases, guidance and SEC filings;

·

Overseeing our risk analysis and risk management procedures;

·

Resolving any disagreements between management and the independent registered public accountants regarding financial reporting;

·

Overseeing our business practices and ethical standards;

·

Preparing an audit committee report to be included in our public filings pursuant to applicable rules and regulations of the SEC.

Wayne G. Dotson, Timothy R. Lindsey and James F. Meara serve on the Audit Committee.  All members of the Audit Committee satisfy all SEC criteria for independence and meet all financial literacy and other SEC and NYSE MKT LLC requirements for Audit Committee service.  The Board has determined that James F. Meara is an “audit committee financial expert” as defined by the rules of the SEC.

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ITEM 11.   EXECUTIVE COMPENSATION

Executive Officers

Named Executive Officers

Named executive officers consist of any individual who served as our Chief Executive Officer during the fiscal year ended February 28, 2017, and up to two of our most highly compensated executive officers other than the Chief Executive Officer during the fiscal year ended February 28, 2017.  For the fiscal year ended February 28, 2017, under the smaller reporting company rules, our named executive officers are: James F. Westmoreland, President and Chief Executive Officer; and Bennett W. Anderson, our Chief Operating Officer (collectively, the “Named Executive Officers”).  Executive officers are elected annually by our Board and serve at the discretion of the Board.  There are no arrangements or understandings between any of the directors, officers, and other persons pursuant to which any such person was selected as an executive officer.

The following information concerns our Named Executive Officers for the fiscal year ended February 28, 2017.

		Executive
Name	Age	Since	Office
James F. Westmoreland	61	2007	President and Chief Executive Officer
Bennett W. Anderson	56	2006	Chief Operating Officer

EXECUTIVE COMPENSATION

We currently qualify as a “smaller reporting company” as such term is defined in Rule 405 of the Securities Act and Item 10 of Regulation S-K.  Accordingly, and in accordance with relevant SEC rules and guidance, we have elected, with respect to the disclosures required by Item 402 (Executive Compensation) of Regulation S-K, to comply with the disclosure requirements applicable to smaller reporting companies.  The following Compensation Overview is not comparable to the “Compensation Discussion and Analysis” that is required of SEC reporting companies that are not smaller reporting companies.

Compensation Overview

This Compensation Overview discusses the material elements of the compensation awarded to, earned by or paid to our executive officers, and the Compensation Committee’s role in the design and administration of these programs and policies in making specific compensation decisions for our executive officers, including officers who are considered to be “Named Executive Officers” during the fiscal year ended February 28, 2017.

General Discussion of Executive Compensation

The Compensation Committee is responsible for establishing, implementing and continually monitoring adherence to our compensation philosophy.  In doing so, the Compensation Committee reviews and approves on an annual basis the evaluation process and compensation structure for the Company’s Named Executive Officers.  The Committee reviews and recommends to the Board the annual compensation, including salary, and any incentive and/or equity-based compensation for such officers.  The Committee also provides oversight of management’s decisions concerning the performance and compensation of other employees.

The current and future objectives of Daybreak’s compensation program are to keep compensation aligned with Daybreak’s cost structure, financial position, and strategic business and financial objectives.  Daybreak’s financial position and its plans going forward are integral to the design and implementation of officer and employee compensation.  Therefore, the Compensation Committee reviews the Company’s cash flow with the Chief Executive Officer at a minimum, on an annual basis, in order to evaluate the current compensation program and its effects on the financial position of the Company.  In deciding on the type and amount of compensation for each Named Executive Officer, the Compensation Committee focuses on the market value of the role and pay of the individual, along with the Company’s cost structure and financial position.

Larger companies such as NYSE or NASDAQ listed companies in the crude oil and natural gas industry have well pronounced trends in compensation, including cash and equity components.  Daybreak competes with larger crude oil and natural gas companies that have substantially greater resources.

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For the fiscal years ended February 28, 2017 and February 29, 2016, compensation to our Named Executive Officers consisted primarily of base salaries.  The Board, with the assistance of the Compensation Committee, has reviewed the compensation structure of the Company’s Named Executive Officers.  After taking into consideration the Company’s current cost structure, financial position, and current compensation structure (discussed under the heading “Narrative Disclosure to Summary Compensation Table, Base Salaries”), the Board approved continuation of the current compensation structure.  In addition, the full Board reviewed and discussed the performance and compensation of all of Daybreak’s employees.

In April 2009, the Company approved a 2009 Restricted Stock and Restricted Stock Unit Plan pursuant to which it may compensate executive officers, directors, consultants and employees.  These elements of compensation are described in more detail under “Narrative Disclosure to Summary Compensation Table”, beginning on page 88 of this Form 10-K.

Summary Compensation Table

The following table sets forth summary information concerning the compensation paid to or earned by our Named Executive Officers during the fiscal years ended February 28, 2017 and February 29, 2016.

Name and Principal Position	Fiscal Year Ended	Salary ($)	Bonus ($)	Stock Awards ($)	All Other Compensation ($)	Total ($)
James F. Westmoreland(1)	February 28, 2017	150,000(2)	-	-	-	150,000
President and Chief Executive Officer	February 29, 2016	150,000(3)	-	-	-	150,000
Bennett W. Anderson	February 28, 2017	89,400(4)	-	-	-	89,400
Chief Operating Officer	February 29, 2016	89,400(5)	-	-	-	89,400

⁽¹⁾

Mr. Westmoreland commenced his employment on December 14, 2007 as the Company’s interim Chief Financial Officer and was appointed Executive Vice President and Chief Financial Officer in April 2008.  He was appointed to the position of President and Chief Executive Officer of the Company in October 2008 and also continues to serve as the interim principal finance and accounting officer of the Company.

⁽²⁾

As a result of the effect of declining oil prices on the Company’s cash flow, Mr. Westmoreland deferred partial salary payments during the fiscal year ended February 28, 2017.  During the fiscal year ended February 28, 2017, Mr. Westmoreland was paid $75,000; and $75,000 was accrued, but not paid.  The accrued liability is recorded on our balance sheet under accrued liabilities.

⁽³⁾

As a result of the Company’s limited available cash, Mr. Westmoreland deferred partial salary payments until cash flow improved.  For the fiscal year ended February 29, 2016, Mr. Westmoreland was paid $131,250; and $18,750 was accrued, but not paid.  This liability is recorded on our balance sheet under accrued liabilities.

⁽⁴⁾

As a result of the effect of declining oil prices on the Company’s cash flow, Mr. Anderson deferred partial salary payments during the fiscal year ended February 28, 2017.  During the fiscal year ended February 28, 2017, Mr. Anderson was paid $44,700; and $44,700 was accrued, but not paid.  The accrued liability is recorded on our balance sheet under accrued liabilities.

⁽⁵⁾

As a result of the Company’s limited available cash, Mr. Anderson deferred partial salary payments during the fiscal year ended February 29, 2016.  During the fiscal year ended February 29, 2016, Mr. Anderson was paid $72,300; and $17,100 was accrued, but not paid.  This liability is recorded on our balance sheet under accrued liabilities.  From April 1, 2009 until March 1, 2016, Mr. Anderson’s base salary was $63,000.  Additionally, if Mr. Anderson worked more than 11 days per month, he earned an additional amount equal to $200 per day, with such additional amount being capped at $2,200 per month, for an aggregate annual total of $89,400.  Mr. Anderson’s base salary is currently $89,400.

Narrative Disclosure to Summary Compensation Table

Base Salaries

The Board, with the assistance of the Compensation Committee, has reviewed the compensation structure of the Company’s Named Executive Officers.  After taking into consideration the Company’s current cost structure, financial position, and the current compensation structure, the Board approved continuation of the current compensation structure, which was established on April 6, 2009.

Equity Compensation Plan Information

Although no equity compensation was granted to our Named Executive Officers during the fiscal years ended February 28, 2017 and February 29, 2016, executive officers, directors, consultants and employees of the Company and its affiliates (“Plan Participants”) are eligible to receive restricted stock and restricted stock unit awards under our 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”), as a means of providing management 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.

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We believe that awards of this type further the mutuality of interest between 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 will have 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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Outstanding Equity Awards at Fiscal Year-End

The Company has no unvested outstanding restricted stock awards held by our Named Executive Officers for the fiscal year ended February 28, 2017.  The Company has no qualified or nonqualified stock option plans and has no outstanding stock options.

Other: Securities Trading

We have a policy that executive officers and directors may not purchase or sell exchange traded options to sell or buy Daybreak stock (“puts” and “calls”), engage in short sales with respect to Daybreak stock or otherwise hedge equity positions in Daybreak (e.g., by buying or selling straddles, swaps or other derivatives).

Executive Employment Agreements

Our employees, including our named executive officers, are employed at will and do not have employment agreements.  Our Compensation Committee believes that employment agreements encourage a short-term rather than long-term focus, provide inappropriate security to the executives and employees and undermine the team spirit of the organization.

Payments Upon Termination or Change in Control

We do not have any agreements with any of our named executive officers that affect the amount paid or benefits provided following termination or a change in control.

Pension Plan Benefits

The Company does not have any pension plans that oblige the Company to make payments or provide benefits at, following or in connection with retirement of its Directors, Officers or employees.

Deductibility of Compensation

Section 162(m) of the Code places a $1 million per executive cap on the compensation paid to executives that can be deducted for tax purposes by publicly traded corporations each year.  Amounts that qualify as “performance based” compensation under Section 162(m)(4)(c) of the Code are exempt from the cap and do not count toward the $1 million limit if certain requirements are satisfied.  At our current named executive officer compensation levels, we do not presently anticipate that Section 162(m) of the Code will be applicable, and accordingly, our Compensation Committee did not consider its impact in determining compensation levels for our Named Executive Officers for the fiscal year ended February 28, 2017.

Stock Compensation Expense

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

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DIRECTOR COMPENSATION

The Board has adopted a Non-Employee Director Compensation Policy (the “Director Compensation Policy”) under which it compensates directors who are not employees of the Company.

Each director who is not an employee or officer of the Company (“non-employee director”) receives an annual cash retainer of $9,000.  Each non-employee director also receives $500 per Board meeting attended and $500 per committee meeting attended.  Additionally, the chairman of the Audit Committee receives an additional annual retainer of $1,500 and all other committee chairmen receive an additional $750 annual retainer.  Director fees are paid in cash on a quarterly basis.  Additionally, directors are reimbursed for any out-of-pocket expenses incurred in attending board meetings.

In addition to cash fees, non-employee directors will receive automatic awards of 150,000 shares of restricted common stock of the Company (the “restricted shares”) upon initial election to the Board.  Additionally the Director Compensation Policy provides that each non-employee director may receive a discretionary grant of 5,000 restricted shares annually, which would typically be granted in conjunction with the Company’s Annual Meeting of Shareholders, and pursuant to the 2009 Plan.  No discretionary grants of restricted shares were made to the non-employee director for the fiscal years ended February 28, 2017 and February 29, 2016.  Shares granted to non-employee directors, under the 2009 Plan are restricted and fully vest equally over a period of three years, at a rate of 33 1/3% each year, or immediately upon termination by reason of death, disability or retirement from the Board.  The Board has discretion to remove any restrictions on restricted shares in the case of any other circumstance deemed appropriate by the Board.

The 2009 Plan is described under the heading “Equity Compensation Plan Information” beginning on page 88 of this Form 10-K.

The Compensation Committee periodically reviews our director compensation practices.  The Compensation Committee believes that our director compensation is fair and appropriate in light of the responsibilities and obligations of our directors.

Director Summary Compensation Table

Members of our board of directors are reimbursed for actual expenses incurred in attending Board meetings.  The table below provides information concerning compensation paid to, or earned by, directors for the fiscal year ended February 28, 2017⁽¹⁾.

Name	Fees Earned Or Paid in Cash(2) ($)	Stock Awards(3) ($)	All other compensation ($)	Total ($)
Wayne G. Dotson	14,250	-	-	14,250
Timothy R. Lindsey	15,250	-	-	15,250
James F. Meara	15,000	-	-	15,000

⁽¹⁾

As an employee director, Mr. James F. Westmoreland did not receive any compensation for serving on the Board of Directors during the fiscal year ended February 29, 2016.  Only non-employee directors receive compensation for serving on the Board of Directors.

⁽²⁾

As a result of the Company’s limited available cash, the Board of Directors, beginning in June 2010 postponed receiving payments of meeting fees and quarterly retainer fees until cash flow would allow.  For the fiscal year ended February 28, 2017, director fees were accrued, but not paid.  For the current year, all fees are still currently being accrued and will not be paid until cash flow would allow.  This liability is recorded on our balance sheet under accrued liabilities.

⁽³⁾

No discretionary grants of restricted shares were made to the non-employee directors for the fiscal year ended February 28, 2017.

REPORT OF THE COMPENSATION COMMITTEE

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

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

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

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ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information regarding outstanding restricted stock awards as of the fiscal year ended February 28, 2017.  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.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	-	-	-
Equity compensation plans not approved by security holders(1)	-	-	1,013,780
Total	-	-	1,013,780

⁽¹⁾

Available to be issued pursuant our 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”), as described in detail under the heading “Equity Compensation Plan Information”, beginning on page 88.

Security Ownership of Certain Beneficial Owners and Management

Our largest principal beneficial shareholders, and five directors and officers of the Company, together own and control about 15% percent of our outstanding common stock.

Our shareholders do not have the right to cumulative voting in the election of our directors.  Cumulative voting could allow a minority group to elect at least one director to our Board.  Because there is no provision for cumulative voting, a minority group will not be able to elect any directors.  Conversely, if our principal beneficial shareholders and directors wish to act in concert, they would be able to vote to appoint directors of their choice, and otherwise directly or indirectly control the direction and operation of the Company.

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As of May 25, 2017, based on information available to the Company, the following table shows the beneficial ownership of the Company’s voting securities (Common Stock and Series A Convertible Preferred stock) by: (i) any persons or entities known by management to beneficially own more than 5% of the outstanding shares of the Company’s Common Stock; (ii) each current director of the Company; (iii) each current executive officer of the Company named in the Summary Compensation Table appearing on page 88; and (iv) all of the current directors and executive officers of Daybreak as a group.  The address of each of the beneficial owners, except where otherwise indicated, is the Company’s address.  Unless otherwise indicated, each person shown below has the sole power to vote and the sole power to dispose of the shares of voting stock listed as beneficially owned.

Class of Stock	Name of Beneficial Owner	Amount and Nature of Beneficial Ownership(1,2)	Warrants Currently Exercisable or Exercisable Within 60 Days(3)	Total Beneficial Holdings	Percent of Class(4) (Less than 1% not shown)
Common Stock	Maximilian Resources LLC(5) 1325 Avenue of the Americas, Suite 2717 New York NY 10019	-	5,662,377(5)	5,662,377	9.99
	Timothy R. Lindsey, Director	910,000	-	910,000	1.8
	Wayne G. Dotson, Director	160,000	-	160,000	*
	James F. Meara, Director	160,000	-	160,000	*
	James F. Westmoreland, President and Chief Executive Officer and Director	600,000	500,000(6)	1,100,000	2.1
	Bennett W. Anderson, Chief Operating Officer	400,000	-	400,000	*
	All (5) directors and executive officers as a group	2,230,000	500,000(6)	2,730,000	5.3
Series A Convertible Preferred Stock(7)	Tensas River Farms I,II,III 551 Lawrence 5470 Alicia, AR 72410	66,667	-	66,667	9.4
	Summittcrest Capital Partners 50 California St., Suite 450 San Francisco, CA 94111	58,333	-	58,333	8.2

⁽¹⁾

Includes shares believed to be held directly or indirectly by 5% or higher shareholders, directors and executive officers that have voting power and/or the power to dispose of such shares.  Unless otherwise noted, each individual or member of the group has the sole power to vote and the sole power to dispose of the shares listed as beneficially owned.

⁽²⁾

To reflect “beneficial ownership” as defined in Rule 13d-3 promulgated under the Securities Exchange Act of 1934, this column includes shares as to which each individual has (A) sole voting power, (B) shared voting power, (C) sole investment power, or (D) shared investment power and the right to acquire within sixty days (from May 25, 2017).

⁽³⁾

To reflect “beneficial ownership” as defined in Rule 13d-3 promulgated under the Securities Exchange Act of 1934, this column includes shares as to which each individual has the right to acquire within sixty days (from May 25, 2017).

⁽⁴⁾

Based upon 51,532,364 shares of common stock outstanding as of May 25, 2017 entitled to one vote per share, except for the percentage of beneficial ownership for Mr. Westmoreland, which includes the 500,000 shares underlying warrants held by him that are exercisable within 60 days of May 25, 2017.

⁽⁵⁾

Consists entirely of shares underlying warrants held by Maximilian Resources LLC (“Maximilian”) that are exercisable within 60 days of May 25, 2017.  Maximilian is the holder of the warrants, and the percentage of beneficial ownership for Maximilian, which includes the 5,662,377 shares underlying the warrants held.  On February 14, 2014, the Company at the request of Maximilian, amended the warrant agreement related to the issuance of Maximilian’s 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.  Based on the last known information verified by representatives of Maximilian Resources LLC, owned by Platinum Partners Credit Opportunities Master Fund LP, a Delaware limited partnership.

⁽⁶⁾

Reflects the Warrant to purchase shares of Daybreak’s Common Stock related to Mr. Westmoreland’s participation in the 12% Notes Offering by purchasing a $250,000 Note and receiving the related Warrant to purchase 500,000 shares of Daybreak’s Common Stock at an exercise price of $0.07.

⁽⁷⁾

The Series A Convertible Preferred (“Preferred”) stock has 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 shares.  Each share of Series A Convertible Preferred stock can be converted to three common stock shares at any time.  As of May 25, 2017, 709,568 shares of Daybreak Series A Convertible Preferred stock were outstanding.

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ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons, Promoters and Certain Control Persons

The Board adopted a policy prescribing procedures for review, approval and monitoring of transactions involving Daybreak and “related persons” (directors and executive officers or their immediate family members, or shareholders owning 5% [five percent] or greater of our outstanding stock).  The Policy Statement Regarding Related Party Transactions of Daybreak Oil and Gas, Inc. (“Related Party Transactions Policy”) supplements the conflict of interest provisions in our Ethical Business Policy Conduct Statement and Corporate Governance Guidelines.  The Board has determined that the Governance Committee is best suited to review and consider for approval related party transactions, although the Board may instead determine that a particular related party transaction be reviewed and considered for approval by a majority of disinterested directors.

The Related Party Transactions Policy covers any related person transaction that involves amounts exceeding $50,000 in which a related person has a direct or indirect material interest.  In addition, the new Related Party Transactions Policy applies specifically to transactions involving Daybreak and any of the following:

(1)

all officers;

(2)

directors and director nominees;

(3)

5% shareholders;

(4)

immediate family members of the foregoing individuals (broadly defined to include any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law);

(5)

any entity controlled by any of the individuals in (1), (2), (3) or (4) above (whether through ownership, management authority or otherwise); and

(6)

certain entities at which any of the individuals in (1), (2), (3) or (4) above is employed (generally, if the individual employed is directly involved in the negotiation of the transaction, has or shares responsibility at such entity for such transaction, or might receive compensation tied to such transaction).

During the fiscal years ended February 28, 2017 and February 29, 2016, the Company had no new related party transactions.

Director Independence

Independence of Board Members

We seek individuals who are able to guide our operations based on their business experience, both past and present, or their education.  Our business model is not complex and our accounting issues are straightforward.

The Governance Committee is delegated with the responsibility to review the independence and qualifications of each member of the Board and its various Committees.  Directors are deemed independent only if the Board affirmatively determines that they have no material relationship with Daybreak, directly, or as an officer, shareowner or partner of an organization that has a relationship with us.

The Company has adopted the standards of NYSE MKT LLC for determining the independence of its directors.  The Company is not listed on NYSE MKT LLC and is not subject to the rules of NYSE MKT LLC but applies the rules established by NYSE MKT LLC to establish director independence.

These independence standards specify the relationships deemed sufficiently material to create the presumption that a director is not independent.  No director qualifies as independent unless the Company’s Board affirmatively determines that the director does not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.  In addition, Section 803A of the NYSE MKT LLC Company Guide (and related commentary) sets forth the following non-exclusive list of persons who shall not be considered independent:

(a)

a director who is, or during the past three years was, employed by the Company, other than prior employment as an interim executive officer (provided the interim employment did not last longer than one year);

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(b)

a director who accepted or has an immediate family member who accepted any compensation from the Company in excess of $120,000 during any period of twelve consecutive months within the three years preceding the determination of independence, other than the following:

(i)

compensation for Board or Board committee service,

(ii)

compensation paid to an immediate family member who is an employee (other than an executive officer) of the Company,

(iii)

compensation received for former service as an interim executive officer (provided the interim employment did not last longer than one year), or

(iv)

benefits under a tax-qualified retirement plan, or non-discretionary compensation;

(c)

a director who is an immediate family member of an individual who is, or at any time during the past three years was, employed by the Company as an executive officer;

(d)

a director who is, or has an immediate family member who is, a partner in, or a controlling shareholder or an executive officer of, any organization to which the Company made, or from which the Company received, payments (other than those arising solely from investments in the Company’s securities or payments under non-discretionary charitable contribution matching programs) that exceed 5% of the organization’s consolidated gross revenues for that year, or $200,000, whichever is more, in any of the most recent three fiscal years;

(e)

a director who is, or has an immediate family member who is, employed as an executive officer of another entity where at any time during the most recent three fiscal years any of the issuer’s executive officers serve on the compensation committee of such other entity; or

(f)

a director who is, or has an immediate family member who is, a current partner of the Company’s outside auditor, or was a partner or employee of the Company’s outside auditor who worked on the Company’s audit at any time during any of the past three years.

Directors serving on the Company’s audit committee must also comply with the additional, more stringent requirements set forth in Section 803B of the NYSE MKT LLC Company Guide and Rule 10A-3 of the Securities Exchange Act of 1934, as amended.

Consistent with these considerations, after review of all relevant transactions and/or relationships between each director and any of his family members and Daybreak, its senior management and its independent registered public accountants, the Board affirmatively determined that three of the current directors, Messrs. Wayne G. Dotson, Timothy R. Lindsey, and James F. Meara are independent.  Mr. James F. Westmoreland, our President and Chief Executive Officer, is not independent.  Beginning July 1, 2013, directors serving on the Company’s compensation committee must also comply with the additional, more stringent requirements as set forth in Section 805(c) of the NYSE MKT LLL Company Guide.

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ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES

Fees Billed by Independent Registered Public Accountants

A summary of fees for professional services performed by MaloneBailey, LLP (“MaloneBailey”) for the audit of our financial statements for the fiscal years ended February 28, 2017 and February 29, 2016 is set forth in the table below:

Services Rendered	Fees Billed for the Fiscal Year Ended February 28, 2017		Fees Billed for the Fiscal Year Ended February 29, 2016
Audit fees	$	72,000	$	70,000
Audit-related fees		-		-
Tax fees		-		-
All other fees		-		-
Total	$	72,000	$	70,000

The Audit Committee has reviewed the nature and scope of the services provided by MaloneBailey and considers the services provided to have been compatible with the maintenance of MaloneBailey’s independence.

Pre-Approval Policies and Procedures

The Audit Committee has adopted guidelines for the pre-approval of audit and permitted non-audit services by our independent registered public accountants.  The Audit Committee considers annually and approves the provision of audit services by our independent registered public accountants and considers and pre-approves the provision of certain defined audit and non-audit services.  The Audit Committee also considers on a case-by-case basis and approves specific engagements that are not otherwise pre-approved.  Any proposed engagement that does not fit within the definition of a pre-approved service may be presented to the Chairman of the Audit Committee.  The Chairman of the Audit Committee reports any specific approval of services at the next regular Audit Committee meeting.  The Audit Committee reviews a summary report detailing all services being provided to Daybreak by its independent registered public accountants.  All of the fees and services described above under “audit fees,” “audit-related fees,” “tax fees” and “all other fees” were pre-approved in accordance with the Audit Fee Pre-Approval Policy and pursuant to Section 202 of the Sarbanes-Oxley Act of 2002.

96

PART IV

ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES

The following Exhibits are filed as part of the report:

3.01

Amended and Restated Articles of Incorporation of Daybreak Oil and Gas, Inc. dated July 17, 2009 ⁽¹⁴⁾

3.02

Amended and Restated Bylaws ⁽¹⁾

4.01

Specimen Stock Certificate ⁽²⁾

4.02

Designations of Series A Convertible Preferred Stock ⁽³⁾

4.03

Warrant for the purchase shares of Common Stock, March 2006 private placement ⁽⁴⁾

4.04

Registration rights agreement, March 2006 private placement ⁽⁴⁾

4.05

Warrant for the purchase shares of Common Stock, July 2006 private placement ⁽⁵⁾

4.06

Registration rights agreement, July 2006 private placement ⁽⁵⁾

4.07

Additional warrant to purchase shares of Common Stock associated with the Spring 2006 and the July 2006 private placement offerings ⁽²⁾

4.08

2009 Restricted Stock and Restricted Stock Unit Plan ^(6)*

4.09

Form of Restricted Stock Award Agreement ^(6)*

4.10

Form of Restricted Stock Unit Award Agreement ^(6)*

4.11

Form of 12% Subordinated Note due 2015 ⁽⁷⁾

4.12

Form of Warrant in connection with 12% Subordinated Notes ⁽⁷⁾

4.13

Form of Amendment to 12% Subordinated Note due 2015 and Warrant to Purchase Shares of Common Stock ⁽¹⁹⁾

4.14

Form of Second Amendment to 12% Subordinated Note due 2017 and Warrant to Purchase Shares of Common Stock⁽²⁰⁾

4.15

Warrant Agreement dated as of August 28, 2013, by and between Daybreak Oil and Gas, Inc. and Maximilian Investors LLC ⁽¹³⁾

4.16

First Amendment to Warrant Agreement dated as of February 14, 2014, by and between Daybreak Oil and Gas, Inc. and Maximilian Investors LLC ⁽¹⁵⁾

10.01

Prospect review and non-competition agreement for California project ⁽⁸⁾

10.02

Prospect review agreement for California project ⁽⁸⁾

10.03

Form of Subscription Agreement for 12% Subordinated Note due 2015 ⁽⁷⁾

10.04

Promissory Note, dated June 20, 2011, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland ⁽⁹⁾

10.05

Promissory Note, dated January 31, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland ⁽¹²⁾

10.06

Credit Line Agreement, dated October 24, 2011, by and between Daybreak Oil and Gas, Inc. and UBS Bank USA ⁽¹⁰⁾

10.07

Loan and Security Agreement dated as of October 31, 2012, by and between Daybreak Oil and Gas, Inc., as borrower, and Maximilian Investors LLC, as lender ⁽¹¹⁾

10.08

Promissory Note dated October 31, 2012, by Daybreak Oil and Gas, Inc. in favor of Maximilian Investors LLC ⁽¹¹⁾

10.09

Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of October 31, 2012, executed by Daybreak Oil and Gas, Inc., in favor of Maximilian Investors LLC ⁽¹¹⁾

10.10

Assignment and Assumption Agreement dated as of October 31, 2012, by and between Daybreak Oil and Gas, Inc., as assignor, and Maximilian Investors LLC, as assignee ⁽¹¹⁾

10.11

Promissory Note, dated August 21, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland ⁽¹²⁾

10.12

Amended and Restated Loan and Security Agreement dated as of August 28, 2013, by and between Daybreak Oil and Gas, Inc., as borrower, and Maximilian Investors LLC, as lender ⁽¹³⁾

10.13

Loan and Security Agreement dated as of August 28, 2013, by and between App Energy, LLC, as borrower, and Daybreak Oil and Gas, Inc., as lender ⁽¹³⁾

10.14

Partial Assignment of Interest in Oil and Gas Leases dated as of August 28, 2013, made by App Energy, LLC to Daybreak Oil and Gas, Inc. ⁽¹³⁾

10.15

Assignment of Net Profits Interest dated as of August 28, 2013, made by Daybreak Oil and Gas, Inc. to Maximilian Investors LLC ⁽¹³⁾

10.16

Share Exchange Agreement dated as of May 19, 2014, by and between Daybreak Oil and Gas, Inc. and Maximilian Investors LLC ⁽¹⁵⁾

10.17

First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement, dated August 21, 2014, by and between Daybreak Oil and Gas, Inc. and Maximilian Resources LLC, a Delaware limited liability company ⁽¹⁶⁾

10.18

First Amendment to Loan and Security Agreement, dated August 21, 2014, by and between Daybreak Oil and Gas, Inc. and App Energy, LLC, a Kentucky limited liability company ⁽¹⁶⁾

10.19

Second Amendment to Amended and Restated Loan and Security Agreement and Warrant Amendment, dated May 20, 2015, by and between Daybreak Oil and Gas, Inc. and Maximilian Resources LLC, a Delaware limited liability company ⁽¹⁷⁾

97

10.20

Second Amendment to Loan and Security Agreement, dated May 20, 2015, by and between Daybreak Oil and Gas, Inc. and App Energy, LLC, a Kentucky limited liability company ⁽¹⁷⁾

10.21

Third Amendment to Amended and Restated Loan and Security Agreement and Second Warrant Amendment, dated October 14, 2015, by and between Daybreak Oil and Gas, Inc. and Maximilian Resources LLC, a Delaware limited liability company ⁽¹⁸⁾

10.22

Third Amendment to Loan and Security Agreement, dated October 14, 2015, by and between Daybreak Oil and Gas, Inc. and App Energy, LLC, a Kentucky limited liability company ⁽¹⁸⁾

10.23

Fourth Amendment to Amended and Restated Loan and Security Agreement and Consent Agreement by and between Daybreak Oil and Gas, Inc., and Maximilian Resources LLC, dated October 31, 2016 ⁽¹⁹⁾

10.24

Asset Purchase Agreement by and between: Daybreak Oil and Gas, Inc., App Energy, LLC, and Sandy Valley Gas, Inc., (“Sandy Valley”) and Eagle Well Service, Inc., (“Eagle”) and collectively with Sandy Valley, “Buyer”) dated October 31, 2016 ⁽¹⁹⁾

10.25

Settlement Agreement by and among SSG Advisors, LLC, Chiron Financial LLC, (the “Plaintiffs”) and Daybreak Oil and Gas, Inc., et al, as of December 23, 2016⁽²⁰⁾

23.1

Consent of PGH Petroleum and Environmental Engineers, LLC⁽²⁰⁾

23.2

Consent of MaloneBailey, LLP⁽²⁰⁾

31.1

Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002⁽²⁰⁾

32.1

Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002⁽²⁰⁾

99.1

Reserve Report of PGH Petroleum and Environmental Engineers, LLC, independent petroleum engineering consulting firm, as of February 28, 2016⁽²⁰⁾

101.INS

XBRL Instance Document ⁽²¹⁾

101.SCH

XBRL Taxonomy Schema ⁽²¹⁾

101.CAL

XBRL Taxonomy Calculation Linkbase ⁽²¹⁾

101.DEF

XBRL Taxonomy Definition Linkbase ⁽²¹⁾

101.LAB

XBRL Taxonomy Label Linkbase ⁽²¹⁾

101.PRE

XBRL Taxonomy Presentation Linkbase ⁽²¹⁾

-----------------------

(1)	Previously filed as exhibit to Form 8-K on April 9, 2008, and incorporated by reference herein.
(2)	Previously filed as exhibits to Form 10-K on May 28, 2009, and incorporated by reference herein.
(3)	Previously filed as exhibit to Form SB-2 on July 18, 2006, and incorporated by reference herein. (filed as part of the Articles of Amendment to the Articles of Incorporation of Daybreak Oil & Gas, Inc. dated June 30, 2006.)
(4)	Previously filed as exhibits to Form SB-2 on July 18, 2006, and incorporated by reference herein.
(5)	Previously filed as exhibits to Form 10-KSB on September 21, 2007, and incorporated by reference herein.
(6)	Previously filed as exhibits to Form S-8 filed on April 7, 2009 and incorporated by reference herein.
(7)	Previously filed as exhibits to Form 8-K on February 3, 2010, and incorporated by reference herein.
(8)	Previously filed as exhibits to Form SB-2/A on December 28, 2006, and incorporated by reference herein.
(9)	Previously filed as exhibit to Form 10-Q on October 17, 2011, and incorporated by reference herein.
(10)	Previously filed as exhibit to Form 10-Q on January 13, 2012, and incorporated by reference herein.
(11)	Previously filed as exhibit to Form 8-K on November 5, 2012 and incorporated by reference herein.
(12)	Previously filed as exhibit to Form 10-Q dated January 10, 2013 and filed on January 11, 2013 and incorporated by reference herein.
(13)	Previously filed as exhibit to Form 8-K on September 3, 2013 and incorporated by reference herein.
(14)	Previously filed as exhibit to Form 10-K filed on May 28, 2010 and incorporated by reference herein
(15)	Previously filed as exhibit to Form 10-K filed on May 29, 2014 and incorporated by reference herein
(16)	Previously filed as exhibit to Form 10-Q filed on October 10, 2014 and incorporated by reference herein.
(17)	Previously filed as exhibit to Form 10-K dated May 21, 2015 and filed on May 22, 2015 and incorporated by reference herein
(18)	Previously filed as exhibit to Form 10-Q filed on January 13, 2016 and incorporated by reference herein.
(19)	Previously filed as exhibit to Form 10-Q filed on January 13, 2017 and incorporated by reference herein.
(20)	Filed herewith.
(21)	Furnished herewith.

^* Contract or compensatory plan or arrangement in which directors and/or officers may participate.

98

GLOSSARY OF TERMS

The following are abbreviations and definitions of terms commonly used in the crude oil and natural gas industry and this Form 10-K.

3-D seismic.  An advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

API.  American Petroleum Institute, a petroleum induction association that sets standards for oil field equipment and operations.  Also see Oil Gravity.

BOE.  A barrel of crude oil equivalent (BOE) is the standard convention used to express crude oil and natural gas volumes on a comparable crude oil equivalent basis.  Natural gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or natural gas liquid.

Bbl.  One barrel, or 42 U.S. gallons of liquid volume.

Completion.  The installation of permanent equipment for the production of crude oil or natural gas.

DD&A.  Refers to depreciation, depletion and amortization of the Company’s property and equipment.

Development well.  A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as a crude oil or natural gas well.

Fracturing.  A procedure undertaken to attempt to increase the flow of crude oil or natural gas from a well.  A fluid (usually crude oil, diesel oil or water) is pumped into the reservoir with such great force that the reservoir rock is physically broken and split open.  Usually the “frac fluid” carries small pellets or beads mixed in with it; the idea is for them to get caught in the fractures and prop them open (the beads or pellets are called the propping agnet or proppant).  As the pumping pressures are gradually released at the surface, the natural reservoir pressures will force the “frac fluid” out of the reservoir, and back into the well as the well begins to flow.  The proppant remains behind, holding the fractures open, thereby increasing the flow of crude oil or natural gas from the reservoir into the well.  This procedure is also called hydraulic fracturing.  To “frac a well” means to hydraulically fracture a reservoir in a well.

Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir.

Gas.  Refers to natural gas.  A mixture of gaseous hydrocarbons formed naturally in the earth.

Gross acres or wells.  Refers to the total acres or wells in which the Company has a working interest.

Horizontal drilling.  A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

Hydrocarbons.  A large class of organic compounds composed of hydrogen and carbon.  Crude oil, natural gas and natural gas condensate are all mixtures of various hydrocarbons, among which methane is the simplest.  

Hydraulic fracturing.  Refer to the definition of fracturing.

Net acres or wells.  Refers to the gross sum of fractional working interest ownership in gross acres or wells.

Net production.  Crude oil and natural gas production that is owned by the Company, less royalties and production due others.

99

NYMEX.  New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded.

Oil.  Refers to crude oil or condensate.  A naturally occurring mixture of liquid hydrocarbons as it comes out of the ground.

Oil Gravity.  The density of liquid hydrocarbons generally measured in degrees API.  The lighter the crude oil, the higher the API gravity.  Heavy oil has an API gravity of 20° API or less.  For example, motor lubricating oil is around 26° API; while gasoline is approximately 55° API.

Operator.  The individual or company responsible for the exploration, development and production of a crude oil or natural gas well or lease.

Productive wells. Producing wells and wells mechanically capable of production.

Proved Developed Reserves.  Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves.  Proved crude oil and natural gas reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  (i) The area of the reservoir considered as proved includes:  (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or natural gas on the basis of available geoscience and engineering data.  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved crude oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities.

Proved undeveloped reserves (PUD).  Undeveloped crude oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Royalty.  An interest in an crude oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.  Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

100

SEC.  The United States Securities and Exchange Commission.

Standardized measure of discounted future net cash flows.  Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes.

Undeveloped acreage.  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil or natural gas, regardless of whether such acreage contains proved reserves.

Working interest.  An interest in an crude oil and natural gas lease that gives the owner of the interest the right to drill for and produce crude oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.  The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

Workover.  Operations on a producing well to restore or increase production.

101

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

DAYBREAK OIL AND GAS, INC.
By:	/s/ JAMES F. WESTMORELAND
	James F. Westmoreland, its
	President, Chief Executive Officer and
	interim principal finance and
	accounting officer
	Date:  May 26, 2017

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

By:	/s/ JAMES F. WESTMORELAND	By:	/s/ WAYNE G. DOTSON
	James F. Westmoreland		Wayne G. Dotson
	Director / President and Chief Executive Officer		Director
	Date:  May 26, 2017		Date:  May 26, 2017
By:	/s/ TIMOTHY R. LINDSEY	By:	/s/ JAMES F. MEARA
	Timothy R. Lindsey		James F. Meara
	Director		Director
	Date:  May 26, 2017		Date:  May 26, 2017

102

EX-4

Exhibit 4.14

SECOND AMENDMENT TO 12% SUBORDINATED NOTE DUE 2017 AND WARRANT TO PURCHASE

SHARES OF COMMON STOCK

This SECOND AMENDMENT TO 12% SUBORDINATED NOTE AND WARRANT TO PURCHASE SHARES OF COMMON STOCK (this “Agreement”) is by and between DAYBREAK OIL AND GAS, INC., a Washington corporation with its chief executive offices located at 601 W. Main Ave., Suite 1017, Spokane, Washington 99201 (the “Company”), and the undersigned (together with any successors or assigns, the “Holder”).

W I T N E S S E T H:

WHEREAS, pursuant to a 2010 private placement (the “Private Placement”), the Company issued to the Holder and other purchasers (collectively, the “Purchasers”) (a) a 12% Subordinated Note due 2015 (the “Notes”) and (b) a Warrant to Purchase Shares of Common Stock giving the Holder the right to purchase a number of shares of the Company’s common stock at an exercise price of $0.14 per share on the terms set forth therein (the “Warrants”).

WHEREAS, the Notes and the Warrants were amended pursuant to the terms of an Amendment to 12% Subordinated Note due 2015 and Warrant to Purchase Shares of Common Stock entered into between each Purchaser and the Company, which extended the maturity date of the Notes and the expiration date of the Warrants until January 29, 2017.

WHEREAS, the Board of Directors of the Company has determined that it is in the best interest of the Company and its shareholders to offer to (a) extend the maturity date of the Notes and the expiration date of the Warrants to January 29, 2019 and (b) reduce the exercise price of the Warrants to $0.07, on the terms as set forth in this Agreement, and the Holder desires to agree to such extensions and lowered exercise price, on the terms and subject to the conditions set forth in this Amendment.

NOW, THEREFORE, in consideration of the foregoing premises, the agreements herein set forth and other good and valuable consideration the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.

Amendment to Note.  The Holder’s Note is hereby amended to amend the definition of Maturity Date (as defined in the Note) set forth in the Note to mean January 29, 2019.  Further, (a) all references in the Holder’s Note to January 29, 2017 shall hereafter be deemed references to January 29, 2019, and (b) the reference in the fourth paragraph of such Note to December 31, 2014 shall hereafter be deemed a reference to December 31, 2018.

2.

Amendment to Warrant. The Holder’s Warrant is hereby amended to (a) amend the definition of Expiration Date (as defined in the Warrant) to mean January 29, 2019 and (b) amend the definition of Exercise Price (as defined in the Warrant) set forth in the Note to mean $0.07 per share of Common Stock (as defined in the Warrant).

3.

Waiver.  The Holder acknowledges that the terms of the Notes provide that no cash payments will be made under any of the Notes unless a pro rata cash payment is simultaneously made under all the Notes (the “Payment Provision”).  However, although it is anticipated that each Purchase will enter into this Agreement, each Purchaser has the choice of whether or not to agree to an extension of the maturity date of their Notes and those holders who do not agree to such extension may have their Notes repaid in full.  Therefore, in such event, the Holder hereby waives the application of the Payment Provision of the Holder’s Note, solely with respect to any repayments made by the Company to other Purchasers who do not agree to a maturity date extension.

4.

Limited Effect. Except as expressly provided hereby, all of the terms and provisions of the Holder’s Note and Warrant, as amended to date, are and shall remain in full force and effect and are hereby ratified and confirmed by the Holder. The amendments contained herein shall not be construed as a waiver or amendment of any other provision of the Holder’s Note or Warrant or for any purpose except as expressly set forth herein.

5.

Successors.  All the covenants and provisions of this Agreement by or for the benefit of the Company and the Holder inure to the benefit of their respective successors and assigns hereunder.

6.

Governing Law.  This Agreement shall be deemed to be a contract made under the laws of the State of Washington with respect to contracts made and to be wholly performed in said State and for all purposes shall be construed in accordance with the laws of said State without regard to the principles of conflicts of law thereof that would defer to the substantive laws of another jurisdiction.

7.

Counterparts.  This Agreement may be executed in any number of counterparts and each of such counterparts shall for all purposes be deemed to be an original, and such counterparts shall together constitute but one and the same instrument.

8.

Effective Date.  This Agreement shall become effective upon January 29, 2017 (the “Effective Date”) if and only if (a) the Company shall have received a copy, duly executed and delivered by the Holder on or prior to such date, and (b) every Purchaser has entered into an agreement with the Company with respect to the subject matter hereof.

[signature page follows]

-2-

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed, to be effective as of the Effective Date.

COMPANY:
DAYBREAK OIL AND GAS, INC., a Washington corporation
By:
	Name:  James F. Westmoreland
	Title:  President and Chief Executive Officer
HOLDER:
If an Entity:
Entity Name:
Signature:
Name:
Title:
If an Individual:
Signature:
Name:
Date:
Address:

EX-10

Exhibit 10.25

EXECUTION VERSION

SETTLEMENT AGREEMENT

This settlement agreement (the “Agreement”), by and among SSG Advisors, LLC (“SSG”), Chiron Financial LLC (“Chiron”) (SSG, together with Chiron, the “Plaintiffs”) and Daybreak Oil and Gas, Inc. (“Daybreak”), Maximilian Resources, LLC (“Maximilian”), Platinum Partners Credit Opportunities Master Fund, LP, improperly named as Platinum Partners LP, (“Platinum”), and Zach Weiner (“Weiner”) (Daybreak, together with, Maximilian, Platinum, and Weiner, the “Defendants”) (Defendants, together with Plaintiffs, the “Parties”), in SSG Advisors, LLC v. Daybreak Oil and Gas, Case No, 2016-79687, pending in the 215^th Judicial District of Harris County, Texas, sets forth the terms upon which the Parties have agreed to settle the Plaintiff’s claims against the Defendants.

RECITALS

WHEREAS, on September 9, 2016, the Plaintiffs and Daybreak executed an engagement agreement (the “Engagement Agreement”), and

WHEREAS, on November 17, 2016, the Plaintiffs made a demand on Defendants for payment of amounts purportedly due and owing under the Engagement Agreement, and commenced the above-referenced action against Defendants (the “Lawsuit”), alleging that Daybreak breached the Engagement Agreement and alleging that Maximilian, Platinum, and Weiner tortuously interfered with Plaintiffs’ contract with Daybreak (the “Plaintiff’s Claims”);

WHEREAS, the Defendants deny liability; and

WHEREAS, the Parties have determined to resolve their disputes on the terms and subject to the conditions set forth in this Agreement; and

NOW, THEREFORE, in consideration of the promises and mutual covenants contained herein and other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, it is stipulated and agreed by and between the Parties, as follows:

1.

The recitals set forth above are incorporated herein by reference.

2.

Consideration: In full and final settlement and satisfaction of the Plaintiffs’ Claims and all other claims or losses of whatsoever kind or character that the Plaintiffs have, or may ever have had, against any Defendant, Daybreak, on behalf and for the benefit of itself and all other Defendants shall pay to the Plaintiffs, as consideration for this Agreement, the sum of $215,000 (the “Settlement Sum”). The Settlement Sum shall be payable by wire transfer to the account identified on Exhibit 1 (the “Payment”). The Settlement Sum consists of the only payments to be made to Plaintiffs. No Further Payments will be made other than the ones outlined above.

3.

Releases:

a.

Release of Defendants. Effective upon the Plaintiffs’ receipt of a fully executed copy of this Agreement and the Payment, the Plaintiffs, on behalf of themselves, and each of their predecessors, successors, parents, subsidiaries, divisions, affiliates, assigns, and any of their current or former agents, directors, officers, employees, consultants, committees, fiduciaries, representatives, attorneys, and all persons and entities acting by, through, under or in concert with any of them currently or in the past, release, acquit, and discharges the Defendants, and their successors and assigns, and each of their predecessors, parents, subsidiaries, divisions,

1

affiliates, and any of their current or former agents, directors, officers, employees, consultants, committees, fiduciaries, representatives, and attorneys of and from the Plaintiffs’ Claims and any and all known and unknown charges, complaints, claims, grievances, liabilities, obligations, promises, agreements, damages, actions, causes of action, suits, rights, demands, costs, losses, debts, penalties, fees, expenses (including attorneys' fees and costs actually incurred) and punitive damages, of any nature whatsoever, known or unknown, and whether asserted or unasserted, which any Plaintiff has, or may have had, against any Defendant, whether or not apparent or yet to be discovered, or which may hereafter develop, for any acts or omissions related to or arising from the Plaintiff’s Claims and the Engagement Agreement or any other business dealings between any Plaintiff and Daybreak on or prior to the date hereof; provided, however, that nothing contained herein shall be deemed to release any obligations the Defendants have under this Agreement.

b.

Release of Plaintiffs. Effective upon the Defendants’ receipt of a fully executed copy of this Agreement, each of the Defendants, on behalf of himself or itself, and its or his predecessors, successors, parents, subsidiaries, divisions, affiliates, assigns, and any of its current or former agents, directors, officers, employees, consultants, committees, fiduciaries, representatives, attorneys, and all persons and entities acting by, through, under or in concert with it currently or in the past, release, acquit, and discharges the Plaintiffs, and their successors and assigns, of and from any and all known and unknown charges, complaints, claims, grievances, liabilities, obligations, promises, agreements, damages, actions, causes of action, suits, rights, demands, costs, losses, debts, penalties, fees, expenses (including attorneys' fees and costs actually incurred) and punitive damages, of any nature whatsoever, known or unknown, and whether asserted or unasserted, which it has, or may have had, against any Plaintiff, whether or not apparent or yet to be discovered, or which may hereafter develop, for any acts or omissions related to or arising from the Plaintiff’s Claims and the Engagement Agreement or any other business dealings between any Plaintiff and Daybreak on or prior to the date hereof;  provided, however, that nothing contained herein shall be deemed to release any obligations the Plaintiffs have under this Agreement.

4.

Release Binding: The Agreement shall be binding on the Parties and their administrators, representatives, executors, successors, parents, subsidiaries, divisions, affiliates, and any of their current or former agents, directors, officers, employees, consultants, committees, fiduciaries, representatives, attorneys, and all persons and entities acting by, through, under or in concert with any of them currently or in the past, and shall inure to the benefit of their, administrators, representatives, executors, successors, parents, subsidiaries, divisions, affiliates, and any of their current or former agents, directors, officers, employees, consultants, committees, fiduciaries, representatives, attorneys, and all persons and entities acting by, through, under or in concert with any of them currently or in the past. Further, each party represents and warrants that it currently knows of no existing act or omission by any other party that may constitute a claim or liability excluded from the release in Section 3 above.

5.

Knowing and Voluntary Release: Each person signing this Agreement represents and warrants that he/she has been duly authorized and has the requisite authority to execute and deliver this Agreement on behalf of such party, to bind his or her respective client or clients to the terms and conditions of this Agreement, if applicable, and to act with respect to the rights and claims that are being altered or otherwise affected by this Agreement. Further, the Parties represent and agree that they have knowingly and voluntarily entered into this Agreement, that they have been given a reasonable period of time to discuss all aspects of this Agreement and the effect of the Agreement with their attorneys, and that they fully understand all of the provisions of the Agreement.

6.

No Admission of Wrongdoing: The Parties acknowledge that this Agreement is a compromise of disputed claims and that neither admits, and each expressly denies, any liability on its part.

7.

Dismissal of Lawsuit: Promptly upon the Plaintiff’s receipt of (i) the Initial Payment; and (ii) the Parties’ receipt of a fully executed copy of this Agreement, the Plaintiff shall file a stipulation of dismissal of the Lawsuit with prejudice and take whatever other actions are necessary to ensure that the Lawsuit is dismissed in its entirety as to all the Defendants, with prejudice and without costs or fees, including without limitation the filing of a notice of non-suit with prejudice of the lawsuit within three days of their receipt of the Initial Payment.

2

8.

Termination of Engagement Agreement:  For the avoidance of doubt, the Engagement Agreement, including any and all terms of the Engagement Agreement that by their terms survive termination of such agreement, is terminated effective upon the Plaintiff’s receipt of (i) the Initial Payment; and (ii) the Parties’ receipt of a fully executed copy of this Agreement.

9.

Confidentiality: The Parties agree to keep the terms of this Agreement and all confidential or proprietary information of, in the case of the Plaintiffs, the Defendants, and in the case of the Defendants, the Plaintiffs, and in its possession completely confidential (such information, “Confidential Information”). The Parties agree that they will not disclose the contents of this Agreement, including the amounts of monetary payments, or any other Confidential Information to anyone other than their respective legal and financial advisors, pursuant to an appropriate order from a court or other entity with competent jurisdiction, or pursuant to applicable law, rule or regulation, including but not limited to securities law disclosure requirements. Nothing in this Section 9 of the Agreement shall be construed to limit a Party’s right to bring an action to enforce the terms of this Agreement.

10.

Taxes. The Plaintiffs shall be solely responsible for, and are legally bound to make payment of, any taxes determined to be due and owing (including penalties and interest related thereto) by it to any federal, state, local or regional taxing authority as a result of the payment of the Settlement Sum.

11.

No Transfers or Assignments: The Parties represent that they have not transferred or assigned to any person or entity any claim related to this Agreement or any portion thereof, or any interest therein.

12.

Forum and Construction; Venue: This Agreement shall, in all respects, be interpreted, enforced, and governed under the laws of the State of Texas, and the Parties waive the application of any conflicts of laws principles of any and all states or other jurisdictions.  The language of this Agreement shall, in all cases, be construed as a whole, according to its fair meaning, and not strictly for, or against, any of the Parties. Further, the Parties agree that any action relating to enforcement of this Agreement shall be brought in the state or federal courts of Harris County, Texas.

13.

Enforceability: In the event that an action is commenced by any party to enforce the provisions of this Agreement, the prevailing party shall be entitled to an award, in addition to any other claims or damages, of its costs and expenses including attorney’s fees in connection with said action.

14.

New or Different Facts: No Effect. Except as provided herein, this Agreement shall be, and remain, in effect despite any alleged breach of this Agreement or the discovery or existence of any new or additional fact, or any fact different from that which any Party now knows or believes to be true.

15.

Severability: Should a court declare or determine that any provision of this Release is illegal or invalid, the validity of the remaining parts, terms or provisions of this Release will not be affected and any illegal or invalid part, term, or provision will be deemed to not be a part of this Agreement.

16.

Execution: This Agreement may be executed in any number of counterparts, each of which shall be deemed an original, but all of which together shall deemed one and the same instrument.

17.

Entire Agreement; Modification: This Agreement sets forth the entire agreement between the Parties pertaining to the subject matter in this Agreement, and fully supersedes any and all prior agreements or understandings between the Parties pertaining to the subject matter in this Agreement. No modification of this Agreement will be valid unless it is in writing identified as an amendment to the Agreement and is signed by all of the Parties.

18.

Closing: The settlement shall be conditioned upon, and closed, simultaneously by the exchange of the consideration to be paid with the executed Agreement. In the event the consideration is not funded, then the Agreement is void and without effect.

*The remainder of the page has been left intentionally blank.  The signature page follows.*

3

Dated: December 23, 2016.

SSG ADVISORS, LLC
By:
	/s/ MARK E. CHESEN
	Name:	Mark E. Chesen
	Title:	Managing Director
CHIRON FINANCIAL LLC
By:
	/s/ JAY H. KRASOFF
	Name:	Jay H. Krasoff
	Title:	Manager
DAYBREAK OIL AND GAS, INC.
By:
	/s/ JAMES F. WESTMORELAND
	Name:	James F. Westmoreland
	Title:	President
PLATINUM PARTNERS CREDIT OPPORTUNITIES MASTER FUND, LP.
By:
	/s/ BURT SCHWARTZ, as Receiver
	Name:	Burt Schwartz
	Title:	Receiver
MAXIMILIAN RESOURCES, LLC
By:
	/s/ BURT SCHWARTZ, as Receiver
	Name:	Burt Schwartz
	Title:	Receiver
ZACH WEINER
By:
	/s/ ZACH WEINER
	Name:	Zach Weiner

4

EX-23

Exhibit 23.1

EX-23

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statement on Form S-8 (File No. 333-158448) of our report dated May 26, 2017 with respect to the audited financial statements of Daybreak Oil and Gas, Inc. for the years ended February 28, 2017 and February 29, 2016.  Our report contains an explanatory paragraph regarding the Company’s ability to continue as a going concern.

/s/ MaloneBailey, LLP

www.malone−bailey.com

Houston, Texas

May 26, 2017

EX-31

Exhibit 31.1

Certification

I, James F. Westmoreland, certify that:

(1)

I have reviewed this annual report on Form 10-K of Daybreak Oil and Gas, Inc.

(2)

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

(3)

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(4)

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the  registrant’s internal control over financial reporting; and

(5)

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 26, 2017

By /s/  JAMES F. WESTMORELAND

James F. Westmoreland, President, Chief Executive Officer

and interim principal finance and accounting officer

(Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer)

EX-32

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Daybreak Oil and Gas, Inc. on Form 10-K for the period ending February 28, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, the undersigned, in the capacity and on the date indicated below, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  May 26, 2017

By /s/  JAMES F. WESTMORELAND

James F. Westmoreland, President, Chief Executive Officer

and interim principal finance and accounting officer

(Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer)

EX-99

Exhibit 99.1

April 21, 2017

Mr. James F. Westmoreland

President and CEO

Daybreak Oil and Gas, Inc.

1101 N. Argonne Road

Suite A-211

Spokane Valley, WA  99212

Ref:

Daybreak Oil and Gas, Inc.

Proved (“1P”) Reserve Report – SEC Case

As of February 28, 2017

Dear Mr. Westmoreland

In accordance with your request, PGH Petroleum & Environmental Engineers, LLC (“PGH”, “we”, “our”) has performed an engineering evaluation to estimate proved oil and gas reserves and projected the associated future revenues for certain properties owned by Daybreak Oil and Gas, Inc. (“Daybreak”) interests in select oil and gas properties located in Kern County, California as of February 28, 2017.  This evaluation was prepared for public disclosure by Daybreak in filings made with the United States Securities and Exchange Commission (“SEC”) in accordance with the disclosure requirements set forth in the SEC regulations and is an annual update of evaluated properties.  The assumptions, data and procedures used in the preparation of this report are appropriate for this purpose.  This report was completed on April 21, 2017 and is effective as of February 28, 2017.

As presented in this report, we estimate the net reserves and future net revenue to Daybreak’s interests as follows:

Daybreak Oil and Gas, Inc.

Total Proved Reserves

As of February 28, 2017

	Net Oil, MBbl	Net Gas, MMcf	Future Net Revenue, M$	Present Worth 10%, M$
Proved Producing	99.71	-	1,135.68	781.73
Proved Undeveloped	281.36	-	3,080.41	940.61
Grand Total	381.07	-	4,216.09	1,722.34

                       Note:  Columns may not add due to rounding.

Projections of the reserves and future net revenue were estimated in accordance with our understanding of the definitions and disclosure guidelines of the SEC contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). A copy of the applicable SEC oil and gas reserve definitions for “Proved” reserves are attached hereto.  Additionally, this report has also been prepared in accordance with the Society of Petroleum Engineers (“SPE”) - Petroleum Resources Management System (“SPE-PRMS”).  Risk factors have not been applied to these estimates.  This report also conforms to our understanding of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by SPE and the Guidelines for Application of Definitions for Oil and Gas Reserves prepared by the Society of Petroleum Evaluation Engineers (“SPEE”).

California Prospects (Kern County):

Ball Prospect

The Ball prospect is the northern most pool and contains two producing wells in the Vedder formation.  The pool area encompasses approximately 40 Acres and the cumulative production from the producing wells is 20,460 barrels of oil.

Bear Prospect

Nine wells have been completed in the Bear pool and one well the Bear No. 10 was an unsuccessful completion.  All of these wells are producing from the Vedder formation.  In addition to these wells, there are ten more locations categorized as proved.  The pool area conservatively encompasses approximately 62.5 Acres.  The cumulative production for the producing wells is 158,528 barrels of oil.

Black Prospect

The Black pool is located to the South of the Bear pool and contains two producing wells in the Vedder formation.  In addition to the producing wells, there are three more locations which are categorized as proved.  The pool area encompasses approximately 13.4 Acres.  The cumulative production for the producing wells is 31,446 barrels of oil.

Dyer Creek Prospect

The Dyer Creek structure lies between the Bear and the Ball pools and is open to the South.  The Dyer Creek Pool has approximately 23 acres and the cumulative production for the producing well is 10,389 barrels of oil.

Sunday Prospect

The Sunday pool area encompasses approximately 34.6 acres and contains six producing wells along with five proved undeveloped locations.  The cumulative production for the producing wells out of the Vedder formation is 152,884 barrels of oil.

Reserves

The oil reserves shown are expressed in barrels where one barrel equals 42 US gallons.  The California properties evaluated by PGH in this report represent 100 percent of Daybreak’s total net proved reserves as of February 28, 2017.  The California properties represent 100 percent of the total proved developed net liquid hydrocarbon reserves and 100 percent of the total proved undeveloped net liquid hydrocarbon reserves of Daybreak as of February 28, 2017.

Future reserves in this report are based on volumetric calculations (oil in place) and conventional decline curve analysis. The volumetric calculations were based off of well log analysis (reservoir thickness, porosity and water saturation).

The reserves projections in this evaluation are based on the use of available data and accepted industry engineering methods.  Future changes in any operational or economic parameters or production characteristics of the evaluated properties could increase or decrease the reserves.  Unforeseen changes in market demand or allowables set by various regulatory agencies could also cause actual production rates to vary from those projected.

Values for reserves are expressed in terms of future net revenue and present worth of future net revenue.  Future net revenue is defined as revenue that will accrue to the appraised interests from the production and sale of the estimated net reserves after deducting production taxes, ad valorem taxes, direct lease operating expenses and capital costs.  Neither plug and abandonment costs nor salvage was considered in this evaluation.  No estimate of Federal Income Tax has been made in this report.  Present worth is defined as the future net revenue discounted at the rate shown per year, compounded monthly.

2

As of February 28, 2017, the net remaining 1P reserves were estimated to be 381,070 barrels of oil. This volume represents 100 percent of the total proved reserves of Daybreak. The net present value, discounted at 10%, of the total proved reserves was $1,722,340.

Price Assumptions

Oil

The reserve estimates use oil prices based on the Cushing, OK West Texas Intermediate (“WTI”) Spot Price, for the twelve month period (unweighted arithmetic average of the first day of the month) prior to the ending date of the report (March 2016 – February 2017) resulting in a base price of $45.85 per barrel.

A differential of ($9.94) has been applied to reflect actual commodity sale prices from March 2016 through February 2017 resulting in an average realized price of $35.91 per barrel for the California properties.

It should be emphasized that with current economic uncertainties, fluctuations in market conditions could significantly change the economics of the properties included in this report.

Expenses & Capital Costs

Lease operating expenses are used to establish the economic limit of each property in this report and were not escalated.  Lease operating expenses as well as state and local tax rates were provided by Daybreak.  Future proved undeveloped wells were assigned expenses based on actual lease operating costs for each of the prospect areas.  

Capital costs for each well to be drilled and completed in the future were based on a summary provided by Daybreak.  This report assumes that a typical well will cost approximately $315,000 on a gross basis for the remaining proved locations.  The drilling schedule for this report was based on a proposed drilling schedule provided by Daybreak.

Report Qualifications

All reserve estimates herein have been performed in accordance with sound engineering principles and generally accepted industry practice.  As in all aspects of oil and gas evaluations, there are uncertainties inherent in the interpretation of engineering and geologic data and all conclusions and projections contained herein represent the informed, professional judgment of the undersigned.  The reserves may or may not be recovered, and the revenues there from and the cost related thereto could be more or less than the estimated amounts.  Estimates of reserves may increase or decrease as a result of future operations, governmental policies, product supply and demand, and also are subject to revision as additional operating history becomes available and as economic conditions change.

The evaluation of potential environmental liability costs from the operation and abandonment of the properties evaluated was beyond the scope of this report.  In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations and reporting requirements.  Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein.

The operations of Daybreak may be subject to various levels of government controls and regulations.  These controls and regulations may include matters relating to land tenure, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income taxes all of which may be subject to change from time to time.  Such changes in government regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

3

Data Sources

Daybreak provided basic well information, production data, capital expenses, operating costs, initial test rates and ownership interests which we have accepted as correct.  This data has not been independently verified.  Historical production data was also obtained from public sources such as state regulatory agencies and IHS Energy production data base.  Basic geologic and field performance data together with our engineering work sheets along with digital, hard copy and other pertinent data relating to the properties evaluated will be retained in our files and will be available for review upon request.  We have not inspected or performed well tests on the individual properties in this report.

Independent Evaluation

We do not own an interest in the subject properties.  The employment to make this study and the compensation is not contingent on our estimates of reserves and future income for the subject properties.  We appreciate the opportunity to prepare this report.  If you have any questions regarding this report, please contact the undersigned.

Sincerely,

/s/Frank Muser, P.E.

Frank J. Muser, P.E.

PGH Petroleum & Environmental Engineers, L.L.C.

Texas Engineering License No. 93590

Texas Firm Registration No. F-9137

4

XML

Document and Entity Information - USD ($)	12 Months Ended
	Feb. 28, 2017	May 26, 2017	Aug. 31, 2016
Document And Entity Information
Entity Registrant Name	Daybreak Oil & Gas, Inc.
Entity Central Index Key	0001164256
Document Type	10-K
Document Period End Date	Feb. 28, 2017
Amendment Flag	false
Current Fiscal Year End Date	--02-28
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 1,420,667
Entity Common Stock, Shares Outstanding		51,532,364
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2017

XML

Balance Sheets - USD ($)	Feb. 28, 2017	Feb. 29, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 42,003	$ 6,995
Accounts receivable:
Crude oil sales	83,405	39,168
Joint interest participants	55,154	106,694
Other receivables, net	4,489	3,368
Production revenue receivable, current	0	45,000
Prepaid expenses and other current assets	24,197	107,760
ASSETS HELD FOR SALE	0	525,495
Restricted short-term time deposit	100,060	0
Total current assets	309,308	834,480
OIL AND GAS PROPERTIES, successful efforts method, net
Proved properties	853,552	943,641
Unproved properties	59,375	0
PREPAID DRILLING COSTS	41,078	18,802
ASSETS HELD FOR SALE	0	7,056,799
Restricted long-term time deposit	0	106,282
Total assets	1,263,313	8,960,004
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	1,727,955	1,640,617
Accounts payable - related parties	1,414,481	990,483
Accrued interest	446,232	175,283
Notes payable - related party	250,100	250,100
12% Notes payable	0	315,000
12% Note payable - related party	0	250,000
Debt, current portion, net	8,805,846	9,043,242
LIABILITIES HELD FOR SALE	0	4,761,482
Line of credit	817,622	843,807
Total current liabilities	13,462,236	18,270,014
LONG TERM LIABILITIES:
12% Notes payable, net	299,465	0
12% Note payable - related party, net	237,671	0
LIABILITIES HELD FOR SALE	0	6,766
Asset retirement obligation	93,409	73,213
Total liabilities	14,092,781	18,349,993
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' DEFICIT:
Preferred stock	0	0
Common stock	51,487	51,487
Additional paid-in capital	22,997,789	22,968,714
Accumulated deficit	(35,879,469)	(32,410,915)
Total stockholders' deficit	(12,829,468)	(9,389,989)
Total liabilities and stockholders' deficit	1,263,313	8,960,004
Series A Convertible Preferred Stock
STOCKHOLDERS' DEFICIT:
Preferred stock	$ 725	$ 725

XML

Balance Sheets (Parenthetical) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Preferred stock, par value in dollars	$ 0.001	$ 0.001
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value in dollars	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	51,487,373	51,487,373
Common stock, shares outstanding	51,487,373	51,487,373
Deferred financing costs	$ 238,598	$ 641,075
Unearned debt discount	15,535
Unearned debt discount, related party	$ 12,329
Series A Convertible Preferred Stock
Preferred stock, par value in dollars	$ 0.001	$ 0.001
Preferred stock, shares authorized	2,400,000	2,400,000
Preferred stock, shares issued	724,565	724,565
Preferred stock, shares outstanding	724,565	724,565
Preferred stock, cumulative dividend rate	6.00%	6.00%

XML

Statements of Operations - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
REVENUE:
Crude oil sales	$ 482,656	$ 529,360
OPERATING EXPENSES:
Production	163,654	160,841
Exploration and drilling	9,297	49,645
Depreciation, depletion, and amortization	110,285	241,080
Impairment of crude oil properties	0	1,108,683
General and administrative	1,068,212	1,172,206
Total operating expenses	1,351,448	2,732,455
OPERATING LOSS	(868,792)	(2,203,095)
OTHER INCOME (EXPENSE):
Interest income	81	99
Interest expense	(2,994,466)	(2,481,856)
Total other income (expense)	(2,994,385)	(2,481,757)
LOSS FROM CONTINUING OPERATIONS	(3,863,177)	(4,684,852)
DISCONTINUED OPERATIONS
Income from discontinued operations	394,623	479,453
NET LOSS	(3,468,554)	(4,205,399)
Cumulative convertible preferred stock dividend requirement	(130,415)	(130,925)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$ (3,598,969)	$ (4,336,324)
NET INCOME (LOSS) PER COMMON SHARE
Loss on continuing operations	$ (0.08)	$ (0.09)
Income from discontinued operations	0.01	0.01
NET LOSS PER COMMON SHARE, basic and diluted	$ (0.07)	$ (0.08)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING, Basic and diluted	51,487,373	51,484,373

XML

Statements of Changes in Stockholders' Deficit - USD ($)	Series A Convertible Preferred Stock	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Beginning balance, value at Feb. 28, 2015	$ 735	$ 51,457	$ 22,968,734	$ (28,205,516)	$ (5,184,590)
Beginning balance, shares at Feb. 28, 2015	734,565	51,457,373
Conversion of preferred stock, value	$ (10)	$ 30	(20)		0
Conversion of preferred stock, shares	(10,000)	30,000
Net loss	$ 0	$ 0	0	(4,205,399)	(4,205,399)
Ending balance, value at Feb. 29, 2016	$ 725	$ 51,487	22,968,714	(32,410,915)	(9,389,989)
Ending balance, shares at Feb. 29, 2016	724,565	51,487,373
Extension of 12% Note warrants			29,075		29,075
Net loss	$ 0	$ 0	0	(3,468,554)	(3,468,554)
Ending balance, value at Feb. 28, 2017	$ 725	$ 51,487	$ 22,997,789	$ (35,879,469)	$ (12,829,468)
Ending balance, shares at Feb. 28, 2017	724,565	51,487,373

XML

Statements of Changes in Stockholders' Deficit (Parenthetical)	Feb. 28, 2017
Statement of Stockholders' Equity [Abstract]
Rate of note warrants	12.00%

XML

Statements of Cash Flows - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$ (3,468,554)	$ (4,205,399)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Loss on sale of crude oil and natural gas properties	1,955,315	0
Loss on settlement of Note Receivable	1,500,676	0
Gain on debt settlement	(3,926,468)	0
Depreciation, depletion and ARO expense	234,454	517,870
Impairment of crude oil properties	0	1,108,683
Amortization of debt discount	73,162	132,114
Amortization of deferred financing costs	423,331	427,331
Debt modification fees	1,057,042	0
Interest income	81	(83)
Changes in assets and liabilities:
Accounts receivable - crude oil and natural gas sales	(21,332)	133,540
Accounts receivable - joint interest participants	51,540	(55,312)
Accounts receivable - other	(711,987)	(483,255)
Prepaid expenses and other current assets	86,819	87,232
Accounts payable and other accrued liabilities	395,814	251,755
Accounts payable - related parties	423,998	84,592
Accrued interest	2,058,261	1,504,265
Net cash provided by (used in) operating activities	132,152	(496,667)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to crude oil and natural gas properties	(73,683)	(170,697)
Prepaid drilling costs	(22,276)	(2,350)
Proceeds from the sale of crude oil and natural gas properties	0	31,581
Collections of note receivable	0	777,500
Net cash provided by (used in) investing activities	(95,959)	636,034
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from debt	25,000	25,000
Principal payments on debt	0	(618,431)
Payment of deferred financing fees	0	(9,655)
Payments to line of credit	(26,185)	(26,058)
Net cash provided by (used in) financing activities	(1,185)	(629,144)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	35,008	(489,777)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	6,995	496,772
CASH AND CASH EQUIVALENTS AT END OF PERIOD	42,003	6,995
Cash paid for Interest	98,659	1,292,066
Cash paid for Income taxes	0	0
SUPPLEMENTAL CASH FLOW INFORMATION:
Unpaid additions to crude oil and natural gas properties	0	89,804
Interest and fees converted to principal on debt	1,567,795	1,487,779
Increase in note receivable for interest and fees added to principal	745,163	683,013
Satisfaction of note receivable through debt reduction	3,900,000	0
ARO asset and liability increase due to timing differences	11,806	47,362
Proceeds from sale of crude oil and natural gas properties paid directly to reduce debt	600,000	0
Unpaid deferred financing costs	20,854	0
Non-cash addition to debt for unproved O&G properties and prepaid drilling costs	84,000	0
Non-cash addition to debt for expenses paid directly by lender	215,000	0
Debt discount addition due to debt modification	29,075	0
Conversion of preferred stock to common stock	$ 0	$ 30

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Organization and Basis of Presentation

12 Months Ended

Feb. 28, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Presentation

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION:

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

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

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Going Concern

12 Months Ended

Feb. 28, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Going Concern

NOTE 2 — GOING CONCERN:

Financial Condition

Daybreak’s financial statements for the twelve months ended February 28, 2017 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. Daybreak has incurred net losses since inception and has accumulated a deficit of $35,879,469 and a working capital deficit of $13,152,928, which raises substantial doubt about the Company’s ability to continue as a going concern.

Management Plans to Continue as a Going Concern

The Company continues to implement plans to enhance its ability to continue as a going concern. Daybreak currently has a net revenue interest in 20 producing crude oil wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”). The revenue from these wells has created a steady and reliable source of revenue. The Company’s average working interest in these wells is 36.6% and the average net revenue interest is 28.4% for these same wells.

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

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

Daybreak’s financial statements as of February 28, 2017 do not include any adjustments that might result from the inability to implement or execute Daybreak’s plans to improve our ability to continue as a going concern.

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Summary of Significant Accounting Policies

12 Months Ended

Feb. 28, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

NOTE 3 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Cash and Cash Equivalents

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

Accounts Receivable

The Company routinely assesses the recoverability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Actual write-offs may exceed the recorded allowance. Substantially all of the Company’s trade accounts receivable result from crude oil in California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors. Trade accounts receivable are generally not collateralized. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2017 and February 29, 2016.

Crude Oil and Natural Gas Properties

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

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

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

The Company recognized asset impairments of $-0- and $1,108,683 for the twelve months ended February 28, 2017 and February 29, 2016, respectively.

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

Property and Equipment

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

Long Lived Assets

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

Fair Value of Financial Instruments

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

Share Based Payments

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

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

Loss per Share of Common Stock

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

Concentration of Credit Risk

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

At the Company’s East Slopes project in California there is only one buyer available for the purchase of all crude oil production. The Company has no natural gas production in California. At February 28, 2017 and February 29, 2016, this one individual customer represented 100.0% of crude oil sales receivable from continuing operations. If this buyer is unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its crude oil production.

The Company’s accounts receivable from continuing operations in California for crude oil sales at February 28, 2017 and February 29, 2016 are set forth in the table below.

		February 28, 2017			February 29, 2016
Project	Customer	Accounts Receivable Crude Oil Sales		Percentage	Accounts Receivable Crude Oil Sales		Percentage
California – East Slopes Project (Crude oil)	Plains Marketing	$	83,405	100.0%	$	39,168	100.0%

Revenue Recognition

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

Reclamation Bonds

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

Asset Retirement Obligation (“ARO”)

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

Suspended Well Costs

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

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

Income Taxes

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

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

Use of Estimates and Assumptions

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

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

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

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

• Estimates regarding the timing and cost of future abandonment obligations.

Recent Accounting Pronouncements

There are no new accounting pronouncements issued or effective that had, or are expected to have, a material impact on the Company’s financial statements.

Reclassifications

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

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Accounts Receivable

12 Months Ended

Feb. 28, 2017

Receivables [Abstract]

Accounts Receivable

NOTE 4 — ACCOUNTS RECEIVABLE:

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

Crude oil sales receivables balances from continuing operations of $83,405 and $39,168 at February 28, 2017 and February 29, 2016 represent crude oil sales that occurred in February 2016 and 2015, respectively.

Joint interest participant receivables balances of $55,154 and $106,694 at February 28, 2017 and February 29, 2016, respectively, represent amounts due from working interest partners in California, where the Company is the Operator. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2017 and February 29, 2016.

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Production Revenue Receivable

12 Months Ended

Feb. 28, 2017

Receivables [Abstract]

Production Revenue Receivable

NOTE 5 — PRODUCTION REVENUE RECEIVABLE:

The production revenue receivable balance of $-0- and $45,000 at February 28, 20178 and February 29, 2016, represents amounts due the Company from a portion of the sale price of a 25% working interest in East Slopes Project in Kern County, California that was acquired through the default of certain original working interest partners in the project.

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Deferred Financing Costs

12 Months Ended

Feb. 28, 2017

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Deferred Financing Costs

NOTE 6 — DEFERRED FINANCING COSTS:

Deferred Financing Costs - Maximilian Credit Facility 

Deferred financing costs at February 28, 2017 and February 29, 2016 relating to the original and the amended credit facility with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in these notes to the financial statements as “Maximilian”), are set forth in the table below:

	February 28, 2017		February 29, 2016
Deferred financing costs – loan fees	$	181,648	$	160,794
Deferred financing costs – loan commissions		630,662		630,662
Deferred financing costs – fair value of warrants		530,488		530,488
Deferred financing costs – fair value of common stock		419,832		419,832
		1,762,630		1,741,776
Accumulated amortization		(1,524,032)		(1,100,701)
	$	238,598	$	641,075

Amortization expense of deferred financing costs was $423,331 and $427,331 for the twelve months ended February 28, 2017 and February 29, 2016, respectively. Deferred financing costs of $238,598 at February 28, 2017 includes the fair value of common shares and warrants issued to Maximilian and to a third party that assisted in both the original and the amended financing transactions. The unamortized deferred financing costs are netted against debt (see Note 13) in the balance sheets.

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Crude Oil Properties

12 Months Ended

Feb. 28, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Crude Oil Properties

NOTE 7 — CRUDE OIL PROPERTIES:

Crude oil property balances from continuing operations at February 28, 2017 and February 29, 2016 are set forth in the table below:

	February 28, 2017		February 29, 2016 (1)
Proved leasehold costs	$	115,119	$	115,119
Costs of wells and development		2,293,668		2,293,668
Capitalized exploratory well costs		1,341,494		1,341,494
Capitalized asset retirement costs		56,497		44,692
Total cost of oil and gas properties		3,806,778		3,794,973
Accumulated depletion, depreciation amortization and impairment		(2,953,226)		(2,851,332)
Oil and gas properties, net	$	853,552	$	943,641

⁽¹⁾ The February 29, 2016 balances have been adjusted to reflect the sale of the Twin Bottoms Field in Kentucky on October 31, 2016.

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Asset Retirement Obligation

12 Months Ended

Feb. 28, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

NOTE 8 — Asset Retirement Obligation (“ARO”)

The Company’s financial statements reflect the provisions of ASC 410. The ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determines the ARO on its crude oil and natural gas properties by calculating the present value of estimated cash flows related to the liability. As of February 28, 2017 and February 29, 2016, ARO obligations were considered to be long-term based on the estimated timing of the anticipated cash flows. For the twelve months ended February 28, 2017 and February 29, 2016, the Company recognized accretion expense of $8,390 and $2,704, respectively which is included in DD&A in the statement of operations.

Changes in the asset retirement obligations for the twelve months ended February 28, 2017 and February 29, 2016 are set forth in the table below.

	February 28, 2017		February 29, 2016
Asset retirement obligation, beginning of period	$	73,213	$	26,765
Accretion expense		8,390		2,704
Change in asset retirement estimates		11,806		43,744
Asset retirement obligation, end of period	$	93,409	$	73,213

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Discontinued Operations and Assets/Liabilities Held for Sale

12 Months Ended

Feb. 28, 2017

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations and Assets/Liabilities Held for Sale

NOTE 9 — DISCONTINUED OPERATIONS AND ASSETS/LIABILITIES HELD FOR SALE:

Effective October 31, 2016, the Company finalized the sale of its interest in the Twin Bottoms Field in Kentucky. The sale included Daybreak’s working interest in 14 producing horizontal crude oil wells, its mineral rights, its lease acreage and infrastructure. As a result of this sale and the restructuring of its Balance Sheet, the Company recognized income of $394,623 on discontinued operations which includes; an approximate $1.96 million loss on the sale of oil and natural gas properties; a reduction of $4.5 million in debt associated with Kentucky; a loss on note receivable settlement of approximately $1.5 million; and gain on debt settlement of approximately $3.9 million with its lender Maximilian for the twelve months ended February 28, 2017. In accordance with the guidance provided in ASC 205-20, the Company concluded that this sale qualified for presentation as discontinued operations. The Company has no ongoing or future plans to be involved in this segment of its oil and natural gas projects. Prior period income statement balances applicable to the Twin Bottoms Field in Kentucky have been reclassified and are included under the Discontinued Operations caption in the statements of operations while related assets and liabilities were reclassified to Assets Held for Sale and Liabilities Held for Sale, respectively on the balance sheet.

Operating income, interest income, operating expenses and interest expense related to Kentucky for the twelve months ended February 28, 2017 and February 29, 2016 are set forth in the tables below.

	For the Twelve Months Ended
	February 28, 2017		February 29, 2016
Crude oil and natural gas sales revenue	$	280,030	$	724,326
Interest income		760,704		1,039,853
Production, exploration and drilling expenses		(65,157)		(134,016)
Depreciation, Depletion and Amortization (“DD&A”) expenses		(124,169)		(276,790)
General & Administrative expense		(204,056)		-
Interest expense		(723,206)		(873,920)
Loss on note receivable settlement		(1,500,676)		-
Loss on sale of O&G properties		(1,955,315)		-
Gain on debt settlement		3,926,468		-
Income (loss) from discontinued operations	$	(394,623)	$	479,453

The reconciliation of the carrying amounts of major classes of assets and liabilities held of sale from discontinued operations as of February 28, 2017 and February 29, 2016 are set forth in the table below.

Major Classes of Assets Presented as a part of Discontinued Operations	February 28, 2017		February 29, 2016(1)
Kentucky oil and natural gas properties, net	$	-	$	2,822,186
Note receivable – App Energy LLC (Kentucky funding)		-		4,655,513
Trade receivables – Kentucky related		-		104,595
Total Assets Held for Sale (Current and Non-current)	$	-	$	7,582,294

Major Classes of Liabilities Presented as a part of Discontinued Operations	February 28, 2017		February 29, 2016(1)
Trade payables – Kentucky related	$	-	$	136,619
Debt related to Kentucky		-		4,624,863
Asset retirement obligation (ARO) - Kentucky		-		6,766
Total Liabilities Held for Sale (Current and Non-current)	$	-	$	4,768,248

⁽¹⁾Amounts in the February 29, 2016 balance sheet are classified as current and long-term.

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

Certain significant non-cash operating and investing items for discontinued operations in Kentucky during the twelve months ended February 29, 2016 included increase in note receivable for interest added to principal of $683 thousand; unpaid additions to crude oil and natural gas properties of $90 thousand; and, DD&A expense of $277 thousand.

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Note Receivable

12 Months Ended

Feb. 28, 2017

Receivables [Abstract]

Note Receivable

NOTE 10 — NOTE RECEIVABLE:

On October 31, 2016, the Company and App Energy, LLC, a Kentucky limited liability company (“App Energy”), sold their interests in the Twin Bottoms field in Kentucky. The note receivable from App Energy for funds advanced by the company to App Energy for drilling in Kentucky was considered to be paid in full as a part of the sale of the Twin Bottoms Field. The $3.9 million App Energy received from the sale of their working interest in Kentucky was used to pay down a portion of the associated note receivable. The remaining balance of approximately $1.5 million was recorded as a loss on the settlement of the note receivable. The associated debt the Company owed to Maximilian Resources LLC (“Maximilian”) of approximately $5.4 million was eliminated through the sale of the Twin Bottoms Field.

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Accounts Payable

12 Months Ended

Feb. 28, 2017

Payables and Accruals [Abstract]

Accounts Payable

NOTE 11 — ACCOUNTS PAYABLE:

On March 1, 2009, the Company became the operator for the East Slopes Project located in Kern County, California. Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning wells program. The Company subsequently sold the 25% working interest on June 11, 2009. Approximately $244,849 of the $1.5 million default remains unpaid and is included in the February 28, 2017 accounts payable balance.

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Accounts Payable - Related Parties

12 Months Ended

Feb. 28, 2017

Related Party Transactions [Abstract]

Accounts Payable - Related Parties

NOTE 12 — ACCOUNTS PAYABLE- RELATED PARTIES:

The February 28, 2017 and February 29, 2016 accounts payable – related parties balances of $1,414,481 and $990,483, respectively, were comprised primarily of deferred salaries of the Company’s Executive Officers and certain employees; deferred directors’ fees; expense reimbursements; related party consulting fees; and deferred interest payments on the 12% Subordinated Note to the Company’s Chairman, President and Chief Executive Officer. Payment of these deferred items has been delayed until the Company’s cash flow situation improves.

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Short-Term and Long-Term Borrowings

12 Months Ended

Feb. 28, 2017

Debt Disclosure [Abstract]

Short-Term and Long-Term Borrowings

NOTE 13 — SHORT-TERM AND LONG-TERM BORROWINGS:

Note Payable – Related Party

At February 28, 2017 and February 29, 2016, the Company’s Chairman, President and Chief Executive Officer had loaned the Company an aggregate $250,100 during the years ended February 29, 2012 and February 28, 2013, that was used for a variety of corporate purposes including an escrow requirement on a loan commitment; maturity extension fees on third party loans; and a reduction of principal on the Company’s credit line with UBS Bank. These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.

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 the Company’s Chairman, President and Chief Executive Officer. At February 28, 2017 and February 29, 2016, the Line of Credit had an outstanding balance of $817,622 and $843,807, respectively. Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $33,815 and $31,442 for the years ended February 28, 2017 and February 29, 2016, respectively. The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

Maximilian Credit Facility

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

Maximilian Loan - Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App Energy, LLC, a Kentucky limited liability company (“App Energy”) in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013. The amendment increased the amount of the debt facility to $90 million and reduced the annual interest rate to 12%.

As consideration for Maximilian facilitating the Company’s transactions with App Energy 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.

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.

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 are amortized over the term of the amended loan agreement. Amortization expense of deferred financing costs was $423,331 and $427,331 for the twelve months ended February 28, 2017 and February 29, 2016, respectively. Unamortized deferred financing costs were $238,598 at February 28, 2017.

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

On 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.

The additional advance, the reduction in the required monthly payment and the reduction in the interest rate were facilitated through the Company’s acquisition of 5,694,823 shares of its common stock held by Maximilian. The repurchased shares were cancelled and restored to the status of authorized, but unissued stock. The Company 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 held from $0.10 to $0.04. No other terms of the warrant agreement were changed. The modification did not result to any accounting since these warrants were deemed to be investor warrants.

On October 14, 2015, the Company entered into a Third Amendment to the Amended and Restated Loan and Security Agreement and Second Warrant Amendment with Maximilian, (the “Third Amendment”). Pursuant to the Third Amendment, Maximilian agreed to a reduction in the Company’s monthly payments under the loan agreement to $50,000 per month for a period of six months ending on February 29, 2016. The reduction in monthly payments allowed 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 was 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 Third 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.

On October 31, 2016, the Company entered into a Fourth Amendment to the Amended and Restated Loan and Security Agreement with Maximilian, which amended the Company’s loan agreement with Maximilian (the “Restructuring Agreement”). Pursuant to the Restructuring Agreement, in exchange for the proceeds it received from the Kentucky Sale, Maximilian and the Company have agreed to: (1) the deemed payment in full and/or forgiveness of approximately $8.3 million in outstanding indebtedness under the Daybreak Loan Agreement (which includes approximately $5.4 million in indebtedness that was loaned by the Company to App Energy pursuant to the Loan and Security Agreement between the parties dated as of August 28, 2013, as amended from time to time); (2) a commitment by Maximilian to forgive an additional amount of indebtedness under the Daybreak Loan Agreement, currently estimated to be $3.2 million, in the event of the future issuance of senior preferred stock by the Company to it; (3) the deemed payment in full and termination of the App Loan Agreement; (4) the termination and release of all liens, security interests and other interests held by Maximilian or its affiliates in any of the Company’s or App Energy’s Kentucky oil and natural gas assets, including the termination of the overriding royalty interests and net profits interests held by Maximilian and/or its affiliates; (5) amendments to the Daybreak Loan Agreement to suspend principal and interest payments for up to six months and extend the maturity date to February 28, 2020; (6) a commitment by Maximilian to advance up to $250,000 in financing to the Company over the next six months; (7) the pursuit of the Michigan Joint Venture using the $250,000 set aside from the Kentucky Sale. The Company recognized a gain on debt settlement in aggregate of approximately $3.9 million through the sale of the Kentucky property and reduction in the outstanding credit facility balance.

As a result of the decline in hydrocarbon prices, the Company has been currently unable to make the interest or principal payments required under the terms of its credit facility with 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 restructuring the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue. Further, our lender is under no obligation to advance us any additional funding and, rather, there can be no assurances that out lender will not declare the Company to be in default under the credit facility. A change of control or management of our lender, among other reasons, could also result in our loan being called due and payable.

Maximilian Loan Agreement – Michigan Project

At February 28, 2017, the Company had received $84,000 in advances from Maximilian under a separate promissory note agreement dated January 17, 2017 and amended on February 10, 2017 regarding the development of an oilfield project in Michigan. Advances under this agreement are subject to a 5% (five percent) per annum interest rate. If a well that the Company elects to participate in is scheduled to be spudded at the Michigan oilfield project on or before December 31, 2017, then the advances under the promissory note must be repaid in full upon the earlier of (a) the time that is ten days prior to the first well being spudded on the Michigan oilfield project or (b) December 31, 2017. If there is not a well scheduled to be spudded at the Michigan oilfield project on or before December 31, 2017 that the Company elects to participate in, then the Company will assign to Maximilian its working interest in the Michigan oilfield project, in full payment and satisfaction of the advances under the promissory note. Advances under the promissory note may be prepaid at any time without penalty, and are secured by a mortgage on the Company’s working interest in the Michigan oilfield project. In the event of a default of any of the Company’s obligations under the promissory note, the amounts due may be called immediately due and payable at Maximilian’s option.

Current debt balances at February 28, 2017 and February 29, 2016 are set forth in the table below:

	February 28, 2017		February 29, 2016
Principal Balance	$	8,960,444	$	14,381,131
Less unamortized discount and debt issuance costs		(238,598)		(713,026)
Subtotal – O&G operating debt		8,721,846		13,668,105
Michigan project debt		84,000		-
Net debt	$	8,805,846	$	13,668,105

App Energy Note Receivable - Loan Agreement

On October 31, 2016, the Company and App Energy, LLC, a Kentucky limited liability company (“App Energy”), sold their interests in the Twin Bottoms field in Kentucky. The note receivable from App Energy for funds advanced by the company to App Energy for drilling in Kentucky was considered to be paid in full as a part of the sale of the Twin Bottoms Field. The $3.9 million App Energy received from the sale of their working interest in Kentucky was used to pay down a portion of the associated note receivable. The remaining balance of approximately $1.5 million was recorded as a loss on the settlement of note receivable. The associated debt the Company owed to Maximilian Resources LLC (“Maximilian”) of approximately $5.4 million was eliminated through the sale of the Twin Bottoms Field.

Non-current debt (Long-term borrowings)

12% Subordinated Notes

The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a January 2010 private placement, resulted in $595,000 in gross proceeds (of which $250,000 was from a related party) to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th. On January 29, 2015, the Company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes for an additional two years to January 29, 2017. Effective January 29, 2017, the maturity date of the Notes and the expiration date of the warrants that were issued in conjunction with the 12% Subordinated Notes from the January 2010 private placement offering to accredited investors were extended for an additional two years to January 29, 2019. The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes. The exercise price of the warrants was lowered from $0.14 to $0.07 as a part of the warrant modification. The warrant expiration extension applied to noteholders who chose to extend the maturity date of the 12% Subordinated Notes for an additional two years and had not already exercised the associated warrants. Ten noteholders had the expiration date of their warrants extended to January 29, 2019. The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes. The Black-Scholes valuation encompassed the following weighted average assumptions: a risk free interest rate of 1.22%; volatility of 378.73%; and dividend yield of 0.0%. Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2018. At February 28, 2017 and February 29, 2016, amortization expense was $1,211 and $-0-, respectively. The unamortized debt discount at February 28, 2017 and February 29, 2016 was $27,864 and $-0-, respectively.

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

	February 28, 2017		February 29, 2016
12% Subordinated Notes	$	315,000	$	315,000
Debt discount		(15,535)		-
Net 12% Subordinated Note balance	$	299,465	$	315,000

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

	February 28, 2017		February 29, 2016
12% Subordinated Notes – related party	$	250,000	$	250,000
Debt discount		(12,329)		-
Net 12% Subordinated Note – related party balance	$	237,671	$	250,000

In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement. The warrants have an exercise price of $0.07 and an amended expiration date of January 29, 2019. The 12% Note warrants that have been exercised are set forth in the table below. At February 28, 2017, there were 980,000 warrants that were not exercised and had not expired.

Fiscal Period	Warrants Exercised	Shares of Common Stock Issued	Number of Accredited Investors
Year Ended February 28, 2014	100,000	100,000	1
Year Ended February 28, 2015	50,000	50,000	1
Year Ended February 29, 2016	-	-	-
Year Ended February 28, 2017	-	-	-
Totals	150,000	150,000	2

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Debt Discount - 12% Subordinated Notes

12 Months Ended

Feb. 28, 2017

Subordinated Borrowings [Abstract]

Debt Discount - 12% Subordinated Notes

NOTE 14 — DEBT DISCOUNT – 12% SUBORDINATED NOTES:

On January 29, 2027, the expiration date of the warrants associated with the 12% Subordinated Notes was extended to January 29, 2019. As a part of this medication of the warrants the exercise price of the warrants was lowered from $0.14 to $0.07. A Black-Scholes valuation determined the value of the modification to be $29,075. The valuation is being treated as a discount to debt and is being amortized over the extended term of the expiration date of the warrants. Amortization expense at February 28, 2017 was $1,211. Unamortized debt discount was $27,864 at February 28, 2017.

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Stockholders' Deficit

12 Months Ended

Feb. 28, 2017

Equity [Abstract]

Stockholders' Deficit

NOTE 15 — STOCKHOLDERS’ DEFICIT:

Preferred Stock

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

Series A Convertible Preferred Stock

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

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

Voluntary Conversion:

The Series A Preferred that is currently issued and outstanding is eligible to be converted by the shareholder at any time into three shares of the Company’s common stock. During the twelve months ended February 28, 2017 and February 29, 2016, there were no conversions of Series A Preferred.

At February 28, 2017 there were 724,565 shares issued and outstanding that had not been converted into our common stock. As of February 28, 2017, there are 43 accredited investors who have 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 is set forth in the table below.

Fiscal Period	Shares of Series A Preferred Converted to Common Stock	Shares of Common Stock Issued from Conversion	Number of Accredited Investors
Year Ended February 29, 2008	102,300	306,900	10
Year Ended February 28, 2009	237,000	711,000	12
Year Ended February 28, 2010	51,900	155,700	4
Year Ended February 28, 2011	102,000	306,000	4
Year Ended February 29, 2012	-	-	-
Year Ended February 28, 2013	18,000	54,000	2
Year Ended February 28, 2014	151,000	453,000	9
Year Ended February 28, 2015	3,000	9,000	1
Year Ended February 29, 2016	10,000	30,000	1
Year Ended February 28, 2017	-	-	-
Totals	675,200	2,025,600	43

Automatic Conversion:

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

Dividend:

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

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

Fiscal Year Ended	Shareholders at Period End	Accumulated Dividends
February 28, 2007	100	$	155,311
February 29, 2008	90		242,126
February 28, 2009	78		209,973
February 28, 2010	74		189,973
February 28, 2011	70		173,707
February 29, 2012	70		163,624
February 28, 2013	68		161,906
February 28, 2014	59		151,323
February 28, 2015	58		132,634
February 29, 2016	57		130,925
February 28, 2017	57		130,415
		$	1,841,917

Liquidation Preference:

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

Voting Rights:

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

Common Stock

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock of which 51,487,373 shares were issued and outstanding as of February 28, 2017 and February 29, 2016. There were no shares of the Company’s Common Stock issued during the twelve months ended February 28, 2017.

	Common Stock Balance	Par Value
Common stock, Issued and Outstanding, February 28, 2015	51,457,373
Conversion of Series A Convertible Preferred Stock to common stock	30,000	$	30
Common stock, Issued and Outstanding, February 29, 2016	51,487,373
Share issuances during the current year	-
Common stock, Issued and Outstanding, February 28, 2017	51,487,373

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.

Common Stock Issued through Restricted Stock and Restricted Stock Unit Plan

On April 6, 2009, the Board 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 to be eligible to receive restricted stock and restricted stock unit awards. Refer to the discussion in Note 17 for the issuances made under the 2009 Plan.

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Warrants

12 Months Ended

Feb. 28, 2017

Equity [Abstract]

Warrants

NOTE 16 — WARRANTS:

Warrants outstanding and exercisable as of February 28, 2017 are set forth in the table below:

	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining
12% Subordinated notes	1,190,000	$0.07	1.92	980,000
Warrants issued in 2012 for debt financing	2,435,517	$0.044	0.67	316,617
Warrants issued for Kentucky oil project	3,498,601	$0.04	1.50	3,498,601
Warrants issued for Kentucky debt financing	2,623,951	$0.04	1.50	2,623,951
Warrants issued for Kentucky debt financing	309,503	$0.214	1.50	309,503
Warrants issued in share-for-warrant exchange	427,729	$0.04	1.50	427,729
	10,485,301			8,156,401

Warrant activity for the twelve months ended February 29, 2016 and February 28, 2017 is set forth in the table below:

	Number of Warrants	Weighted Average Exercise Price
Warrants outstanding, February 28, 2015	8,306,401	$0.11
Changes during the twelve months ended February 29, 2016:
Expired / Cancelled / Forfeited	150,000	$0.14
Warrants outstanding, February 29, 2016	8,156,401	$0.06
Changes during the twelve months ended February 28, 2017:
Expired / Cancelled / Forfeited	-
Warrants outstanding, February 28, 2017	8,156,401	$0.05
Warrants exercisable, February 28, 2017	8,156,401	$0.05

On January 29, 2017, the 980,000 warrants associated with the 12% Subordinated Notes were modified to extend the expiration date of the warrants to January 29, 2019. As a part of this modification the exercise price of the 12% Note warrants was changed from $0.14 to $0.07. The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes. No other terms of the warrants were affected by the modification. The outstanding warrants as of February 28, 2017 and February 29, 2016 have a weighted average exercise price of $0.05 and $0.06; a weighted average remaining life of 1.52 and 2.28 years; and an intrinsic value of $-0-, respectively.

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Restricted Stock and Restricted Stock Unit Plan

12 Months Ended

Feb. 28, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Restricted Stock and Restricted Stock Unit Plan

NOTE 17 — RESTRICTED STOCK and RESTRICTED STOCK UNIT PLAN:

On April 6, 2009, the Board approved the 2009 Plan allowing the executive officers, directors, consultants and employees of the Company and its affiliates to be eligible to receive restricted stock and restricted stock unit awards. Subject to adjustment, the total number of shares of the Company’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.

The Company believes that awards of this type further align the interests of its employees and its shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance. Restricted stock and restricted stock units also enhance the Company’s ability to attract and retain the services of qualified individuals.

During the twelve months ended February 28, 2009, the Compensation Committee of the Board awarded a total of 2,550,000 restricted shares of the Company’s common stock to members of the Board of Directors, officers and employees of the Company. These shares were granted pursuant to the 2009 Plan and fully vest equally over a period ranging from three to four years.

On July 22, 2010, the Compensation Committee of the Board awarded 25,000 restricted shares of its common stock to the five non-employee Directors as a part of the director compensation policy. These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of three years.

On July 22, 2010, the Compensation Committee of the Board awarded 425,000 restricted shares of its common stock to five employees of Daybreak. These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of four years.

For the twelve months ended February 28, 2017 and February 29, 2016 there were no shares that vested. At February 28, 2017, all issued and outstanding shares in the 2009 stock plan had fully vested. For the years ended February 28, 2017 and February 29, 2016, the number of common shares available for issuance under the Plan did not increase.

At February 28, 2017, a total of 3,000,000 shares of restricted stock had been awarded and 2,986,220 shares of the 2009 Plan had fully vested. A total of 1,013,780 common stock shares remained available for issuance pursuant to the 2009 Plan at February 28, 2016. For the years ended February 28, 2017 and February 29, 2016 there were not any share that vested. A summary of the 2009 Plan issuances is set forth in the table below:

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

^{(1) Does not include the number of common shares that were withheld to satisfy such tax liability upon vesting of a restricted award by a Plan Participant, and subsequently returned to the 2009 Plan.}

^{(2) Reflects the number of common shares that were withheld pursuant to the settlement of the number of shares with a fair market value equal to such tax withholding liability, to satisfy such tax liability upon vesting of a restricted award by a Plan Participant.}

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

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Income Taxes

12 Months Ended

Feb. 28, 2017

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 18 — INCOME TAXES:

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

	February 28, 2017		February 29, 2016
Computed at U.S. and state statutory rates (40%)	$	(1,387,422)	$	(1,616,023)
Permanent differences		83,606		143,946
Changes in valuation allowance		1,303,816		1,472,077
Total	$	-	$	-

Tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred liabilities are presented below:

	February 28, 2017		February 29, 2016
Deferred tax assets:
Net operating loss carryforwards	$	10,425,780	$	10,217,121
Oil and gas properties		32,488		(944,342)
Stock based compensation		88,723		88,723
Other		(32,618)		(150,945)
Less valuation allowance		(10,514,373)		(9,210,557)
Total	$	-	$	-

At February 28, 2017, the Company had a net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $26,064,450, which will begin to expire, if unused, beginning in 2024. The valuation allowances increased by $1,303,816 and $1,472,077 for the years ended February 28, 2017 and February 29, 2016, respectively. Section 382 Rule of the Internal Revenue Code will place annual limitations on the Company’s NOL carryforward.

The above estimates are based upon management’s decisions concerning certain elections that could change the relationship between net income and taxable income. Management decisions are made annually and could cause the estimates to vary significantly. The Company’s files federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for the fiscal years after 2011 currently remain subject to examinations by appropriate tax authorities. None of our tax returns are under examination at this time.

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Commitments and Contingencies

12 Months Ended

Feb. 28, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

NOTE 19 — COMMITMENTS AND CONTINGENCIES:

Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities. While the ultimate outcome of the aforementioned contingencies are not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of February 28, 2017. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

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Subsequent Events

12 Months Ended

Feb. 28, 2017

Subsequent Events [Abstract]

Subsequent Events

NOTE 20 — SUBSEQUENT EVENTS:

At May 9, 2017, one holder of the Company’s Series A Convertible Preferred stock converted their 14,997 shares of Series A Preferred stock into 44,991 shares of the Company’s common stock.

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Supplementary Information for Crude Oil Producing Activities

12 Months Ended

Feb. 28, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplementary Information for Crude Oil Producing Activities

NOTE 21 — SUPPLEMENTARY INFORMATION FOR CRUDE OIL PRODUCING ACTIVITIES (UNAUDITED)

Discontinued operations information comprising the sale of the Company’s Kentucky assets, effective October 31, 2016, has not been segregated from our continuing operations in California in the Supplemental Information for Crude Oil Producing Activities presented below for the twelve months ended February 29, 2016.

Capitalized Costs Relating to Crude Oil and Natural Gas Producing Activities

	As of February 28, 2017		As of February 29, 2016
Proved leasehold costs
Mineral Interests	$	115,119	$	654,445
Wells, equipment and facilities		3,691,659		6,095,262
Total Proved Properties		3,806,778		6,749,707
Unproved properties
Mineral Interests		59,375		585,826
Uncompleted wells, equipment and facilities		-		-
Total unproved properties		59,375		585,826
Less accumulated depreciation, depletion amortization and impairment		(2,953,226)		(3,569,705)
Net capitalized costs	$	912,927	$	3,765,828

Costs Incurred in Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	February 28, 2017		February 29, 2016
Acquisition of proved properties	$	-	$	-
Acquisition of unproved properties		59,375		-
Development costs		-		243,823
Exploration costs		-		76,053
Total costs incurred	$	59,375	$	319,876

Results of Operations from Oil and Gas Producing Activities

Discontinued operations information comprising the sale of the Company’s Kentucky assets, effective October 31, 2016, has not been segregated from our continuing operations in California for the Results of Operations information presented below for the twelve months ended February 29, 2016.

	12 Months Ended		12 Months Ended
	February 28, 2017		February 29, 2016
Oil and gas revenues	$	762,686	$	1,253,686
Production costs		(221,579)		(268,448)
Exploration expenses		(16,529)		(76,053)
Depletion, depreciation and amortization		(234,454)		(517,870)
Impairment of oil properties		-		(1,108,683)
Result of oil and gas producing operations before income taxes		290,124		(717,368)
Provision for income taxes		-		-
Results of oil and gas producing activities	$	290,124	$	(717,368)

Proved Reserves

The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, PGH Petroleum and Environmental Engineers, LLC. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods when the estimates were made. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors. Our proved reserves are summarized in the table below:

	Oil (Barrels)	Natural Gas (Mcf)	BOE (Barrels)
Proved reserves:
February 28, 2015	845,659	254,860	888,136
Revisions(1)	(120,001)	390,693	(54,886)
Discoveries and extensions	76,270	161,320	103,157
Production	(28,818)	(28,853)	(33,627)
February 29, 2016	773,110	778,020	902,780
Revisions(1)	(13,145)	-	(13,145)
Sales of minerals	(360,018)	(761,517)	(486,937)
Production	(18,877)	(16,503)	(21,628)
February 28, 2017	381,070	-	381,070

(1) The revisions of previous estimates resulted from a decline in the estimated economic life of the reserves due to lower realized crude oil prices in the energy markets.

The Company’s proved reserves are set forth in the table below.

	Developed		Undeveloped		Total Reserves
	Oil (Bbls)	BOE (Bbls)	Oil (Bbls)	BOE (Bbls)	Oil (Bbls)	BOE (Bbls)
February 28, 2017	99,710	99,710	281,360	281,360	381,070	381,070
February 29, 2016	203,131	231,778	569,979	671,002	773,110	902,780
February 28, 2015	278,233	294,585	567,426	593,551	845,659	888,136

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of February 28, 2017 and February 29, 2016 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

Future cash inflows for the years ended February 28, 2017 and February 29, 2016 were estimated as specified by the SEC through calculation of an average price based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from March through February during each respective fiscal year. The resulting net cash flows are reduced to present value by applying a 10% discount factor.

	12 Months Ended
	February 28, 2017		February 29, 2016
Future cash inflows	$	13,684,350	$	34,077,610
Future production costs(1)		(7,377,450)		(16,255,030)
Future development costs		(2,090,810)		(7,278,930)
Future income tax expenses(2)		-		-
Future net cash flows		4,216,090		10,543,650
10% annual discount for estimated timing of cash flows		(2,493,750)		(6,570,720)
Standardized measure of discounted future net cash flows at the end of the fiscal year	$	1,722,340	$	3,972,930

(1) Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s oil and gas operations.

(2) The Company has sufficient tax deductions and allowances related to proved oil and gas reserves to offset future net revenues.

Average hydrocarbon prices are set forth in the table below.

	Average Price		Natural
	Crude Oil (Bbl)		Gas (Mcf)
Year ended February 28, 2017(1)	$	40.00	$	1.59
Year ended February 29, 2016(1)	$	47.45	$	2.51
Year ended February 28, 2015(1)	$	85.53	$	2.99

(1) Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year.

Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.

Sources of Changes in Discounted Future Net Cash Flows

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by ASC 932, at fiscal year-end are set forth in the table below.

	12 Months Ended
	February 28, 2017		February 29, 2016
Standardized measure of discounted future net cash flows at the beginning of the year	$	3,972,930	$	17,504,700
Extensions, discoveries and improved recovery, less related costs		-		271,190
Revisions of previous quantity estimates		(88,875)		(408,300)
Sales of minerals in place		(1,948,968)		-
Net changes in prices and production costs		(1,289,038)		(10,040,886)
Accretion of discount		397,293		1,750,470
Sales of oil produced, net of production costs		(541,107)		(985,238)
Development costs incurred during the period		4,654		213,576
Changes in future development costs		262,156		526,413
Changes in timing of future production		953,295		(4,858,995)
Net changes in income taxes		-		-
Standardized measure of discounted future net cash flows at the end of the year	$	1,722,340	$	3,972,930

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Accounting Policies (Policies)

12 Months Ended

Feb. 28, 2017

Accounting Policies [Abstract]

Cash and Cash Equivalents

Cash and Cash Equivalents

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

Accounts Receivable

Accounts Receivable

The Company routinely assesses the recoverability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Actual write-offs may exceed the recorded allowance. Substantially all of the Company’s trade accounts receivable result from crude oil in California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors. Trade accounts receivable are generally not collateralized.

Crude Oil and Natural Gas Properties

Crude Oil and Natural Gas Properties

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

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

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

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

Property and Equipment

Property and Equipment

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

Long Lived Assets

Long Lived Assets

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

Fair Value of Financial Instruments

Fair Value of Financial Instruments

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

Share Based Payments

Share Based Payments

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

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

Loss per Share of Common Stock

Loss per Share of Common Stock

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

Concentration of Credit Risk

Concentration of Credit Risk

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

At the Company’s East Slopes project in California there is only one buyer available for the purchase of all crude oil production. The Company has no natural gas production in California. At February 28, 2017 and February 29, 2016, this one individual customer represented 100.0% of crude oil sales receivable from continuing operations. If this buyer is unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its crude oil production.

Revenue Recognition

Revenue Recognition

The Company uses the sales method to account for sales of crude oil and natural gas. Under this method, revenues are recognized based on actual volumes of crude oil and natural gas sold to purchasers. The volumes sold may differ from the volumes to which the Company is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the imbalance exceeds the estimate of remaining reserves.

Reclamation Bonds

Reclamation Bonds

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

Asset Retirement Obligation

Asset Retirement Obligation (“ARO”)

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

Suspended Well Costs

Suspended Well Costs

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

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

Income Taxes

Income Taxes

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

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

Use of Estimates and Assumptions

Use of Estimates and Assumptions

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

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

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

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

• Estimates regarding the timing and cost of future abandonment obligations.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

There are no new accounting pronouncements issued or effective that had, or are expected to have, a material impact on the Company’s financial statements.

Reclassifications

Reclassifications

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

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Summary of Significant Accounting Policies - Concentration of Credit Risk (Tables)

12 Months Ended

Feb. 28, 2017

Risks and Uncertainties [Abstract]

Schedule of Concentration of Risk, by Risk Factor

		February 28, 2017			February 29, 2016
Project	Customer	Accounts Receivable Crude Oil Sales		Percentage	Accounts Receivable Crude Oil Sales		Percentage
California – East Slopes Project (Crude oil)	Plains Marketing	$	83,405	100.0%	$	39,168	100.0%

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Deferred Financing Costs (Tables)

12 Months Ended

Feb. 28, 2017

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of Deferred Costs, Capitalized, Prepaid, and Other Assets

	February 28, 2017		February 29, 2016
Deferred financing costs – loan fees	$	181,648	$	160,794
Deferred financing costs – loan commissions		630,662		630,662
Deferred financing costs – fair value of warrants		530,488		530,488
Deferred financing costs – fair value of common stock		419,832		419,832
		1,762,630		1,741,776
Accumulated amortization		(1,524,032)		(1,100,701)
	$	238,598	$	641,075

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Crude Oil Properties (Tables)

12 Months Ended

Feb. 28, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Crude Oil and Natural Gas Activities

	February 28, 2017		February 29, 2016 (1)
Proved leasehold costs	$	115,119	$	115,119
Costs of wells and development		2,293,668		2,293,668
Capitalized exploratory well costs		1,341,494		1,341,494
Capitalized asset retirement costs		56,497		44,692
Total cost of oil and gas properties		3,806,778		3,794,973
Accumulated depletion, depreciation amortization and impairment		(2,953,226)		(2,851,332)
Oil and gas properties, net	$	853,552	$	943,641

⁽¹⁾The February 29, 2016 balances have been adjusted to reflect the sale of the Twin Bottoms Field in Kentucky on October 31, 2016.

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Asset Retirement Obligation (Tables)

12 Months Ended

Feb. 28, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligations

	February 28, 2017		February 29, 2016
Asset retirement obligation, beginning of period	$	73,213	$	26,765
Accretion expense		8,390		2,704
Change in asset retirement estimates		11,806		43,744
Asset retirement obligation, end of period	$	93,409	$	73,213

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Discontinued Operations and Assets/Liabilities Held for Sale (Tables)

12 Months Ended

Feb. 28, 2017

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Discontinued Operations and Assets/Liabilities Held for Sale

	For the Twelve Months Ended
	February 28, 2017		February 29, 2016
Crude oil and natural gas sales revenue	$	280,030	$	724,326
Interest income		760,704		1,039,853
Production, exploration and drilling expenses		(65,157)		(134,016)
Depreciation, Depletion and Amortization (“DD&A”) expenses		(124,169)		(276,790)
General & Administrative expense		(204,056)		-
Interest expense		(723,206)		(873,920)
Loss on note receivable settlement		(1,500,676)		-
Loss on sale of O&G properties		(1,955,315)		-
Gain on debt settlement		3,926,468		-
Income (loss) from discontinued operations	$	(394,623)	$	479,453

Major Classes of Assets Presented as a part of Discontinued Operations	February 28, 2017		February 29, 2016(1)
Kentucky oil and natural gas properties, net	$	-	$	2,822,186
Note receivable – App Energy LLC (Kentucky funding)		-		4,655,513
Trade receivables – Kentucky related		-		104,595
Total Assets Held for Sale (Current and Non-current)	$	-	$	7,582,294

Major Classes of Liabilities Presented as a part of Discontinued Operations	February 28, 2017		February 29, 2016(1)
Trade payables – Kentucky related	$	-	$	136,619
Debt related to Kentucky		-		4,624,863
Asset retirement obligation (ARO) - Kentucky		-		6,766
Total Liabilities Held for Sale (Current and Non-current)	$	-	$	4,768,248

⁽¹⁾Amounts in the February 29, 2016 balance sheet are classified as current and long-term.

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Short-Term and Long-Term Borrowings (Tables)

12 Months Ended

Feb. 28, 2017

Debt Disclosure [Abstract]

Schedule of Line of Credit Facilities

	February 28, 2017		February 29, 2016
Principal Balance	$	8,960,444	$	14,381,131
Less unamortized discount and debt issuance costs		(238,598)		(713,026)
Subtotal – O&G operating debt		8,721,846		13,668,105
Michigan project debt		84,000		-
Net debt	$	8,805,846	$	13,668,105

Schedule of Long-Term Debt

	February 28, 2017		February 29, 2016
12% Subordinated Notes	$	315,000	$	315,000
Debt discount		(15,535)		-
Net 12% Subordinated Note balance	$	299,465	$	315,000

Related Party	February 28, 2017		February 29, 2016
12% Subordinated Notes – related party	$	250,000	$	250,000
Debt discount		(12,329)		-
Net 12% Subordinated Note – related party balance	$	237,671	$	250,000

Schedule of 12% Subordinated Note Warrants

Fiscal Period	Warrants Exercised	Shares of Common Stock Issued	Number of Accredited Investors
Year Ended February 28, 2014	100,000	100,000	1
Year Ended February 28, 2015	50,000	50,000	1
Year Ended February 29, 2016	-	-	-
Year Ended February 28, 2017	-	-	-
Totals	150,000	150,000	2

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Stockholders' Deficit (Tables)

12 Months Ended

Feb. 28, 2017

Equity [Abstract]

Schedule of Stockholder's Equity

Fiscal Period	Shares of Series A Preferred Converted to Common Stock	Shares of Common Stock Issued from Conversion	Number of Accredited Investors
Year Ended February 29, 2008	102,300	306,900	10
Year Ended February 28, 2009	237,000	711,000	12
Year Ended February 28, 2010	51,900	155,700	4
Year Ended February 28, 2011	102,000	306,000	4
Year Ended February 29, 2012	-	-	-
Year Ended February 28, 2013	18,000	54,000	2
Year Ended February 28, 2014	151,000	453,000	9
Year Ended February 28, 2015	3,000	9,000	1
Year Ended February 29, 2016	10,000	30,000	1
Year Ended February 28, 2017	-	-	-
Totals	675,200	2,025,600	43

Schedule of Dividends Payable

Fiscal Year Ended	Shareholders at Period End	Accumulated Dividends
February 28, 2007	100	$	155,311
February 29, 2008	90		242,126
February 28, 2009	78		209,973
February 28, 2010	74		189,973
February 28, 2011	70		173,707
February 29, 2012	70		163,624
February 28, 2013	68		161,906
February 28, 2014	59		151,323
February 28, 2015	58		132,634
February 29, 2016	57		130,925
February 28, 2017	57		130,415
		$	1,841,917

Schedule of Common Stock Outstanding

	Common Stock Balance	Par Value
Common stock, Issued and Outstanding, February 28, 2015	51,457,373
Conversion of Series A Convertible Preferred Stock to common stock	30,000	$	30
Common stock, Issued and Outstanding, February 29, 2016	51,487,373
Share issuances during the current year	-
Common stock, Issued and Outstanding, February 28, 2017	51,487,373

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Warrants (Tables)

12 Months Ended

Feb. 28, 2017

Equity [Abstract]

Schedule of Stockholders' Equity Note Warrants and Rights

	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining
12% Subordinated notes	1,190,000	$0.07	1.92	980,000
Warrants issued in 2012 for debt financing	2,435,517	$0.044	0.67	316,617
Warrants issued for Kentucky oil project	3,498,601	$0.04	1.50	3,498,601
Warrants issued for Kentucky debt financing	2,623,951	$0.04	1.50	2,623,951
Warrants issued for Kentucky debt financing	309,503	$0.214	1.50	309,503
Warrants issued in share-for-warrant exchange	427,729	$0.04	1.50	427,729
	10,485,301			8,156,401

Schedule of Warrant Activity

	Number of Warrants	Weighted Average Exercise Price
Warrants outstanding, February 28, 2015	8,306,401	$0.11
Changes during the twelve months ended February 29, 2016:
Expired / Cancelled / Forfeited	150,000	$0.14
Warrants outstanding, February 29, 2016	8,156,401	$0.06
Changes during the twelve months ended February 28, 2017:
Expired / Cancelled / Forfeited	-
Warrants outstanding, February 28, 2017	8,156,401	$0.05
Warrants exercisable, February 28, 2017	8,156,401	$0.05

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Restricted Stock and Restricted Stock Unit Plan (Tables)

12 Months Ended

Feb. 28, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Restricted Stock and Restricted Stock Unit Activity

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

^{(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.}

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Income Taxes (Tables)

12 Months Ended

Feb. 28, 2017

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense Benefit

	February 28, 2017		February 29, 2016
Computed at U.S. and state statutory rates (40%)	$	(1,387,422)	$	(1,616,023)
Permanent differences		83,606		143,946
Changes in valuation allowance		1,303,816		1,472,077
Total	$	-	$	-

Schedule of Deferred Tax Assets and Liabilities

	February 28, 2017		February 29, 2016
Deferred tax assets:
Net operating loss carryforwards	$	10,425,780	$	10,217,121
Oil and gas properties		32,488		(944,342)
Stock based compensation		88,723		88,723
Other		(32,618)		(150,945)
Less valuation allowance		(10,514,373)		(9,210,557)
Total	$	-	$	-

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Supplementary Information for Crude Oil Producing Activities (Tables)

12 Months Ended

Feb. 28, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Capitalized Costs Relating to Crude Oil and Natural Gas Producing Activities

	As of February 28, 2017		As of February 29, 2016
Proved leasehold costs
Mineral Interests	$	115,119	$	654,445
Wells, equipment and facilities		3,691,659		6,095,262
Total Proved Properties		3,806,778		6,749,707
Unproved properties
Mineral Interests		59,375		585,826
Uncompleted wells, equipment and facilities		-		-
Total unproved properties		59,375		585,826
Less accumulated depreciation, depletion amortization and impairment		(2,953,226)		(3,569,705)
Net capitalized costs	$	912,927	$	3,765,828

Cost Incurred in Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	February 28, 2017		February 29, 2016
Acquisition of proved properties	$	-	$	-
Acquisition of unproved properties		59,375		-
Development costs		-		243,823
Exploration costs		-		76,053
Total costs incurred	$	59,375	$	319,876

Results of Operations from Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	February 28, 2017		February 29, 2016
Oil and gas revenues	$	762,686	$	1,253,686
Production costs		(221,579)		(268,448)
Exploration expenses		(16,529)		(76,053)
Depletion, depreciation and amortization		(234,454)		(517,870)
Impairment of oil properties		-		(1,108,683)
Result of oil and gas producing operations before income taxes		290,124		(717,368)
Provision for income taxes		-		-
Results of oil and gas producing activities	$	290,124	$	(717,368)

Schedule of Proved Developed and Undeveloped Oil and Gas Reserves

	Oil (Barrels)	Natural Gas (Mcf)	BOE (Barrels)
Proved reserves:
February 28, 2015	845,659	254,860	888,136
Revisions(1)	(120,001)	390,693	(54,886)
Discoveries and extensions	76,270	161,320	103,157
Production	(28,818)	(28,853)	(33,627)
February 29, 2016	773,110	778,020	902,780
Revisions(1)	(13,145)	-	(13,145)
Sales of minerals	(360,018)	(761,517)	(486,937)
Production	(18,877)	(16,503)	(21,628)
February 28, 2017	381,070	-	381,070

(1) The revisions of previous estimates resulted from a decline in the estimated economic life of the reserves due to lower realized crude oil prices in the energy markets.

	Developed		Undeveloped		Total Reserves
	Oil (Bbls)	BOE (Bbls)	Oil (Bbls)	BOE (Bbls)	Oil (Bbls)	BOE (Bbls)
February 28, 2017	99,710	99,710	281,360	281,360	381,070	381,070
February 29, 2016	203,131	231,778	569,979	671,002	773,110	902,780
February 28, 2015	278,233	294,585	567,426	593,551	845,659	888,136

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves

	12 Months Ended
	February 28, 2017		February 29, 2016
Future cash inflows	$	13,684,350	$	34,077,610
Future production costs(1)		(7,377,450)		(16,255,030)
Future development costs		(2,090,810)		(7,278,930)
Future income tax expenses(2)		-		-
Future net cash flows		4,216,090		10,543,650
10% annual discount for estimated timing of cash flows		(2,493,750)		(6,570,720)
Standardized measure of discounted future net cash flows at the end of the fiscal year	$	1,722,340	$	3,972,930

(1) Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s oil and gas operations.

(2) The Company has sufficient tax deductions and allowances related to proved oil and gas reserves to offset future net revenues.

Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure

	Average Price		Natural
	Crude Oil (Bbl)		Gas (Mcf)
Year ended February 28, 2017(1)	$	40.00	$	1.59
Year ended February 29, 2016(1)	$	47.45	$	2.51
Year ended February 28, 2015(1)	$	85.53	$	2.99

(1) Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year.

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows

	12 Months Ended
	February 28, 2017		February 29, 2016
Standardized measure of discounted future net cash flows at the beginning of the year	$	3,972,930	$	17,504,700
Extensions, discoveries and improved recovery, less related costs		-		271,190
Revisions of previous quantity estimates		(88,875)		(408,300)
Sales of minerals in place		(1,948,968)		-
Net changes in prices and production costs		(1,289,038)		(10,040,886)
Accretion of discount		397,293		1,750,470
Sales of oil produced, net of production costs		(541,107)		(985,238)
Development costs incurred during the period		4,654		213,576
Changes in future development costs		262,156		526,413
Changes in timing of future production		953,295		(4,858,995)
Net changes in income taxes		-		-
Standardized measure of discounted future net cash flows at the end of the year	$	1,722,340	$	3,972,930

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Going Concern (Details Narrative)	Feb. 28, 2017 USD ($) Number	Feb. 29, 2016 USD ($)
Accumulated deficit	$ (35,879,469)	$ (32,410,915)
Working capital deficit	$ 13,152,928
Average Working and Revenue Interest | East Slopes Project
Number of producing wells, net revenue interest | Number	20
Average working interest	36.60%
Average net revenue interest	28.40%

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Summary of Significant Accounting Policies - Schedule of Concentration of Risk, by Risk Factor (Details) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Concentration Risk [Line Items]
Revenue receivable	$ 83,405	$ 39,168
Percent of revenue	100.00%	100.00%
Customer Concentration Risk | Accounts Receivable - Crude Oil Sales | Plains Marketing (California - East Slopes Project (Crude Oil))
Concentration Risk [Line Items]
Revenue receivable	$ 83,405	$ 39,168
Percent of revenue	100.00%	100.00%

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Summary of Significant Accounting Policies (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Crude Oil and Natural Gas Properties
Asset impairment of oil and gas properties	$ 0	$ 1,108,683
Property and Equipment
Expected useful lives	3 years
Concentration Risk
Concentration risk, customer	One individual customer	One individual customer
Crude oil and gas sales receivables, customer concentration	100.00%	100.00%
Asset Retirement Obligation
Reclamation bond	$ 100,000

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Accounts Receivable (Details Narrative) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Receivables [Abstract]
Accounts receivable - crude oil and natural gas sales	$ 83,405	$ 39,168
Accounts receivable - joint interest participants	$ 55,154	$ 106,694

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Production Revenue Receivable (Details Narrative) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Receivables [Abstract]
Production revenue receivables	$ 0	$ 45,000

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Deferred Financing Costs - Schedule of Deferred Financing Costs (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Deferred financing costs, gross	$ 1,762,630	$ 1,741,776
Accumulated amortization	(1,524,032)	(1,100,701)
Deferred finance costs, net	238,598	641,075
Revolving Credit Facility | Common Stock
Deferred financing costs, gross	419,832	419,832
Revolving Credit Facility | Warrants
Deferred financing costs, gross	530,488	530,488
Revolving Credit Facility | Loan Commissions
Deferred financing costs, gross	630,662	630,662
Revolving Credit Facility | Loan Fees
Deferred financing costs, gross	$ 181,648	$ 160,794

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Deferred Financing Costs (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Amortization of deferred financing costs	$ 423,331	$ 427,331
Deferred financing costs	$ 238,598

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Crude Oil Properties - Schedule of Crude Oil and Natural Gas Properties (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016	[1]
Crude Oil and Natural Gas Property, Successful Effort Method, Net
Proved leasehold costs	$ 115,119	$ 115,119
Costs of wells and development	2,293,668	2,293,668
Capitalized exploratory well costs	1,341,494	1,341,494
Capitalized asset retirement costs	56,497	44,692
Total cost of oil and gas properties	3,806,778	3,794,973
Accumulated depletion, depreciation, amortization and impairment	(2,953,226)	(2,851,332)
Oil and gas properties, net	$ 853,552	$ 943,641

[1] The February 29, 2016 balances have been adjusted to reflect the sale of the Twin Bottoms Field in Kentucky on October 31, 2016.

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Asset Retirement Obligation - Schedule of Change in Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Asset Retirement Obligation Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning of period	$ 73,213	$ 26,765
Accretion expense	8,390	2,704
Change in asset retirement estimates	11,806	47,362
Asset retirement obligation, end of period	$ 93,409	$ 73,213

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Asset Retirement Obligation (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Asset Retirement Obligation Disclosure [Abstract]
Accretion expense	$ 8,390	$ 2,704

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Discontinued Operations and Assets/Liabilities Held for Sale - Schedule of Discontinued Operations Disclosures (Details) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016		Feb. 28, 2015
Operating Income (Expense) - Kentucky (Twin Bottoms Field)
Loss on note receivable settlement	$ (1,500,676)	$ 0
Loss on sale of O&G properties	(1,955,315)	0
Gain on debt settlement	3,926,468	0
Income (loss) from discontinued operations	394,623	479,453
Major Classes of Liabilities Presented as a part of Discontinued Operations
Asset retirement obligation (ARO), Kentucky	93,409	73,213		$ 26,765
Twin Bottoms Field - Kentucky
Operating Income (Expense) - Kentucky (Twin Bottoms Field)
Crude oil and natural gas sales revenue	280,030	724,326
Interest income	760,704	1,039,853
Production, exploration and drilling expenses	(65,157)	(134,016)
Depreciation, Depletion and Amortization ("DD&A") expenses	(124,169)	(276,790)
General & Adminstrative expense	(204,056)	0
Interest expense	(723,206)	(873,920)
Loss on note receivable settlement	(1,500,676)	0
Loss on sale of O&G properties	(1,955,315)	0
Gain on debt settlement	3,926,468	0
Income (loss) from discontinued operations	394,623	479,453
Major Classes of Assets Presented as a part of Discontinued Operations
Kentucky oil and natural gas properties, net	0	2,822,186	[1]
Note receivable, App Energy LLC (Kentucky funding)	0	4,655,513	[1]
Trade receivables, Kentucky related	0	104,595	[1]
Total Assets Held for Sale (Current and Non-current)	0	7,582,294	[1]
Major Classes of Liabilities Presented as a part of Discontinued Operations
Trade payables, Kentucky related	0	136,619	[1]
Debt related to Kentucky	0	4,624,863	[1]
Asset retirement obligation (ARO), Kentucky	0	6,766	[1]
Total Liabilities Held for Sale (Current and Non-current)	$ 0	$ 4,768,248	[1]

[1] Amounts in the February 29, 2016 balance sheet are classified as current and long-term.

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Discontinued Operations and Assets/Liabilities Held for Sale (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Loss from sale of crude oil and natural gas properties	$ (1,955,315)	$ 0
Income from discontinued operations	394,623	479,453
Gain on debt settlement	3,926,468	0
Loss on settlement of Note Receivable	1,500,676	0
Non-cash addition to debt for expenses paid directly by lender	215,000	0
Interest added to note receivable	1,567,795	1,487,779
Depreciation, depletion, and amortization	110,285	241,080
Unpaid additions to crude oil and natural gas properties	0	89,804
Twin Bottoms Field - Kentucky
Loss from sale of crude oil and natural gas properties	(1,955,315)	0
Income from discontinued operations	394,623	479,453
Gain on debt settlement	3,926,468	0
Loss on settlement of Note Receivable	1,500,676	0
Proceeds from sale of crude oil and natural gas properties	600,000
Non-cash addition to debt for expenses paid directly by lender	215,000
Interest added to note receivable	745,000	683,000
Depreciation, depletion, and amortization	124,000	277,000
Unpaid additions to crude oil and natural gas properties	$ 13,000	$ 90,000

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Note Receivable (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Reduction of notes receivable	$ 745,163	$ 683,013
Loss on note receivable settlement	1,500,676	0
Satisfaction of note receivable through debt reduction, approximate	3,900,000	$ 0
App Energy, LLC
Reduction of notes receivable	(3,900,000)
Loss on note receivable settlement	(1,500,676)
Satisfaction of note receivable through debt reduction, approximate	$ 5,400,000

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Accounts Payable (Details Narrative)	12 Months Ended
	Feb. 28, 2017 USD ($)
Payables and Accruals [Abstract]
Acquisition and disposition of East Slopes Project	On March 1, 2009, the Company became the operator for the East Slopes Project. The Company assumed certain original defaulting partners' approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning well program. The Company subsequently sold the 25% working interest on June 11, 2009.
Accounts payable balance	$ 244,849

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Accounts Payable - Related Parties (Details Narrative) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Related Party Transactions [Abstract]
Accounts payable - related parties	$ 1,414,481	$ 990,483

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Short-Term Borrowings - Schedule of Line of Credit Facilities (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Line of Credit Facility [Line Items]
Net debt less unamortized discount and debt issuance costs	$ 8,805,846	$ 9,043,242
Revolving Credit Facility
Line of Credit Facility [Line Items]
Principal amount	8,960,444	14,381,131
Less unamortized discount and debt issuance costs	(238,598)	(713,026)
Subtotal - O&G operating debt	8,721,846	13,668,105
Michigan project debt	84,000	0
Net debt less unamortized discount and debt issuance costs	$ 8,805,846	$ 13,668,105

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Short-Term and Long-Term Borrowings - Subordinated Notes (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Debt Instrument [Line Items]
12% Notes payable, net	$ 299,465	$ 0
12% Note payable - related party, net	237,671	0
12% Subordinated Notes
Debt Instrument [Line Items]
Convertible subordinated debt, current	315,000	315,000
Debt discount	(15,535)	0
12% Notes payable, net	299,465	315,000
12% Subordinated Notes | Chief Executive Officer
Debt Instrument [Line Items]
Convertible subordinated debt, current	250,000	250,000
Debt discount	(12,329)	0
12% Note payable - related party, net	$ 237,671	$ 250,000

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Short-Term and Long-Term Borrowings - Schedule of 12% Subordinated Note Warrants (Details)	12 Months Ended
	Feb. 28, 2017 Number shares	Feb. 29, 2016 Number shares	Feb. 28, 2015 Number shares	Feb. 28, 2014 Number shares
Accredited investors | Number	43
12% Subordinated Notes | Warrants
Warrants exercised | shares	0	0	50,000	100,000
Shares of common stock issued | shares	0	0	50,000	100,000
Accredited investors | Number	0	0	1	1

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Short-Term and Long-Term Borrowings (Details Narrative) - USD ($)	1 Months Ended							6 Months Ended	12 Months Ended
	Feb. 28, 2017	Oct. 31, 2016	Oct. 31, 2015	May 31, 2015	May 31, 2014	Feb. 28, 2014	Oct. 31, 2012	Aug. 31, 2013	Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2015	Feb. 28, 2010	May 20, 2015
Debt Instrument [Line Items]
Interest rate	12.00%								12.00%
Warrants outstanding	8,156,401								8,156,401
Warrants, exercise price	$ 0.05								$ 0.05	$ 0.06
Amortization of debt discount									$ 73,162	$ 132,114
Unamortized discount, noncurrent	$ 15,535								15,535
Unamortized deferred financing costs	$ 238,598								238,598
Line of credit, debt modification fees									$ 1,057,042	$ 0
Common stock issued, shares	51,487,373								51,487,373	51,487,373
Notes payable, related party	$ 250,100								$ 250,100	$ 250,100
Unproved oil and gas properties	$ 59,375								59,375	585,826
Gain on debt settlement									3,926,468	0
Reduction of notes receivable									745,163	683,013
Loss on note receivable settlement									1,500,676	0
Satisfaction of note receivable through debt reduction, approximate									3,900,000	$ 0
App Energy, LLC
Debt Instrument [Line Items]
Reduction of notes receivable									(3,900,000)
Loss on note receivable settlement									(1,500,676)
Satisfaction of note receivable through debt reduction, approximate									$ 5,400,000
Share-for-Warrant Exchange
Debt Instrument [Line Items]
Warrants outstanding	427,729								427,729
Warrants issued					427,729
Warrants, exercise price	$ 0.04								$ 0.04
Stock repurchased and retired, shares					427,729
12% Subordinated Notes
Debt Instrument [Line Items]
Interest rate										12.00%		12.00%
Maturity date										Jan. 29, 2019		Jan. 29, 2017
Payment terms												Payable semi-annually on January 29th and July 29th. Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2018.
Proceeds from subordinate notes												$ 595,000
Subordinate notes, outstanding balance										$ 565,000
Warrants outstanding	980,000								980,000	1,190,000
Warrants issued												1,190,000
Warrants, exercise price	$ 0.07								$ 0.07	$ 0.07		$ 0.14
Warrant expiration date									Jan. 29, 2019			Jan. 29, 2017
Fair value of warrants									$ 29,075	$ 29,075
Weighted average risk free interest rate										1.22%
Weighted average volatility rate										378.73%
Amortization of debt discount									1,211	$ 0
Amortization expense									1,211
Unamortized debt discount	$ (15,535)								(15,535)	0
Unamortized discount, noncurrent	27,864								27,864	0
Line of Credit | UBS Bank USA
Debt Instrument [Line Items]
Maximum borrowing	890,000								890,000	890,000
Line of credit, amount outstanding	817,622								817,622	843,807
Line of credit, interest expense									$ 33,815	$ 31,442
Line of credit, interest rate description									Payable monthly at a stated reference rate of 0.249% + 337.5 basis points. The reference rate is based on the 30 day LIBOR ("London Interbank Offered Rate") and is subject to change from UBS.	Payable monthly at a stated reference rate of 0.249% + 337.5 basis points. The reference rate is based on the 30 day LIBOR ("London Interbank Offered Rate") and is subject to change from UBS.
Revolving Credit Facility | Maximilian Loan
Debt Instrument [Line Items]
Amortization expense									$ 423,331	$ 427,331
Unamortized debt discount	$ 238,598								238,598	238,598
Credit facility, description							The Company entered into a loan agreement with Maximilian Investors LLC 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.
Maximum borrowing							$ 20,000,000
Credit facility, expiration date							Oct. 31, 2016
Minimum commitment terms							Minimum commitment of $2,500,000
Revolving Credit Facility | Maximilian Loan | Michigan Project
Debt Instrument [Line Items]
Credit facility, description	Advances under this notes are secured by the 30% working interest and mortgage on leases the Company owns in the Michigan project.
Credit facility, advances	$ 84,000
Credit facility, expiration date	Dec. 31, 2017
Line of credit facility, interest rate	5.00%
Revolving Credit Facility | Maximilian - Amended and Restated Loan Agreement
Debt Instrument [Line Items]
Warrants issued						6,100,000		6,100,000
Warrants, exercisable date								Aug. 28, 2013
Amortization expense								$ 400,349
Maximum borrowing								$ 90,000,000
Line of credit facility, interest rate								12.00%
Common stock issued, shares								6,100,000
Revolving Credit Facility | Maximilian- First Amendment to Amended and Restated Loan Agreement
Debt Instrument [Line Items]
Credit facility, advances											$ 2,200,000
Stock repurchased and retired, shares											5,694,823
Stock repurchased and retired, value											$ 1,708,447
Revolving Credit Facility | Maximilian- Second Amendment to Amended and Restated Loan Agreement
Debt Instrument [Line Items]
Warrants, exercise price													$ 0.04
Credit facility, reduction to required monthly payments				The 2nd 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.
Revolving Credit Facility | Maximilian - Third Amendment to Amended and Restated Loan Agreement
Debt Instrument [Line Items]
Payment terms			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 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 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.
Warrant expiration date			Aug. 28, 2018
Credit facility, reduction to required monthly payments			Monthly payments in the amount of $50,000 per month for a period of six months ending on February 29, 2016.
Revolving Credit Facility | Maximilian - Fourth Amendment to Amended and Restated Loan Agreement
Debt Instrument [Line Items]
Credit facility, description		Pursuant to the Restructuring Agreement, in exchange for the proceeds it received from the Kentucky Sale, Maximilian and the Company have agreed to: (1) the deemed payment in full and/or forgiveness of approximately $8.3 million in outstanding indebtedness under the Daybreak Loan Agreement (which includes approximately $5.4 million in indebtedness that was loaned by the Company to App Energy pursuant to the Loan and Security Agreement between the parties dated as of August 28, 2013, as amended from time to time); (2) a commitment by Maximilian to forgive an additional amount of indebtedness under the Daybreak Loan Agreement, currently estimated to be $3.2 million, in the event of the future issuance of senior preferred stock by the Company to it; (3) the deemed payment in full and termination of the App Loan Agreement; (4) the termination and release of all liens, security interests and other interests held by Maximilian or its affiliates in any of the Company's or App Energy's Kentucky oil and natural gas assets, including the termination of the overriding royalty interests and net profits interests held by Maximilian and/or its affiliates; (5) amendments to the Daybreak Loan Agreement to suspend principal and interest payments for up to six months and extend the maturity date to February 28, 2020; (6) a commitment by Maximilian to advance up to $250,000 in financing to the Company over the next six months; (7) the pursuit of the Michigan Joint Venture using the $250,000 set aside from the Kentucky Sale.
Gain on debt settlement		$ 3,926,468
Chief Executive Officer
Debt Instrument [Line Items]
Notes payable, related party	$ 250,100								250,100	250,100
Chief Executive Officer | 12% Subordinated Notes
Debt Instrument [Line Items]
Unamortized debt discount	$ (12,329)								$ (12,329)	$ 0

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Debt Discount - 12% Subordinated Notes (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2010
Warrants, exercise price	$ 0.05	$ 0.06
Unamortized discount, noncurrent	$ 15,535
12% Subordinated Notes
Fair value of warrants	$ 29,075	$ 29,075
Warrants, exercise price	$ 0.07	$ 0.07	$ 0.14
Warrant expiration date	Jan. 29, 2019		Jan. 29, 2017
Amortization expense	$ 1,211
Unamortized discount, noncurrent	$ 27,864	$ 0

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Stockholders' Deficit - Conversions of Series A Preferred Stock (Details)	12 Months Ended
	Feb. 28, 2017 Number shares	Feb. 29, 2016 Number shares	Feb. 28, 2015 Number shares	Feb. 28, 2014 Number shares	Feb. 28, 2013 Number shares	Feb. 29, 2012 Number shares	Feb. 28, 2011 Number shares	Feb. 28, 2010 Number shares	Feb. 28, 2009 Number shares	Feb. 29, 2008 Number shares	Jul. 31, 2006 Number
Series A preferred shares converted to common stock	675,200
Shares of common stock issued from conversion	2,025,600
Accredited investors | Number	43
Series A Convertible Preferred Stock
Series A preferred shares converted to common stock	(675,200)	(10,000)	(3,000)	(151,000)	(18,000)	0	(102,000)	(51,900)	(237,000)	(102,300)
Shares of common stock issued from conversion	2,025,600	30,000	9,000	453,000	54,000	0	306,000	155,700	711,000	306,900
Accredited investors | Number	43	1	1	9	2	0	4	4	12	10	100

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Stockholders' Deficit - Preferred Stock Dividends Earned (Details)	12 Months Ended
	Feb. 28, 2017 USD ($) Number	Feb. 29, 2016 USD ($) Number	Feb. 28, 2015 USD ($) Number	Feb. 28, 2014 USD ($) Number	Feb. 28, 2013 USD ($) Number	Feb. 29, 2012 USD ($) Number	Feb. 28, 2011 USD ($) Number	Feb. 28, 2010 USD ($) Number	Feb. 28, 2009 USD ($) Number	Feb. 29, 2008 USD ($) Number	Feb. 28, 2007 USD ($) Number
Equity [Abstract]
Preferred shareholders at period end | Number	57	57	58	59	68	70	70	74	78	90	100
Earned dividends	$ 130,415	$ 130,925	$ 132,634	$ 151,323	$ 161,906	$ 163,624	$ 173,707	$ 189,973	$ 209,973	$ 242,126	$ 155,311
Total accumulated dividends	$ 1,841,917

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Stockholders' Deficit (Details Narrative)	12 Months Ended
	Feb. 28, 2017 Number $ / shares shares	Feb. 29, 2016 Number $ / shares shares	Feb. 28, 2015 Number shares	Feb. 28, 2014 Number shares	Feb. 28, 2013 Number shares	Feb. 29, 2012 Number shares	Feb. 28, 2011 Number shares	Feb. 28, 2010 Number shares	Feb. 28, 2009 Number shares	Feb. 29, 2008 Number shares	Jul. 31, 2006 Number shares
Preferred stock, par value in dollars | $ / shares	$ 0.001	$ 0.001
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Series A preferred shares converted to common stock	(675,200)
Shares of common stock issued from conversion	2,025,600
Accredited investors | Number	43
Common stock, par value in dollars | $ / shares	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	51,487,373	51,487,373
Common stock, shares outstanding	51,487,373	51,487,373
Series A Convertible Preferred Stock
Preferred stock, par value in dollars | $ / shares	$ 0.001	$ 0.001
Preferred stock, shares authorized	2,400,000	2,400,000
Preferred stock, shares issued	724,565	724,565									1,399,765
Preferred stock, shares outstanding	724,565	724,565
Series A preferred shares converted to common stock	675,200	10,000	3,000	151,000	18,000	0	102,000	51,900	237,000	102,300
Shares of common stock issued from conversion	2,025,600	30,000	9,000	453,000	54,000	0	306,000	155,700	711,000	306,900
Accredited investors | Number	43	1	1	9	2	0	4	4	12	10	100
Preferred Stock
Preferred stock, par value in dollars | $ / shares	$ 0.001
Preferred stock, shares authorized	10,000,000
Preferred stock, cumulative dividend rate	6.00%
Common Stock
Common stock, par value in dollars | $ / shares	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	51,487,373	51,487,373
Common stock, shares outstanding	51,487,373	51,487,373

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Warrants - Schedule of Stockholders' Equity Note Warrants and Rights (Details) - $ / shares	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2010
Class of Warrant or Right [Line Items]
Warrants	8,156,401
Exercise price	$ 0.05	$ 0.06
Remaining life (years)	1 year 6 months	2 years 3 months
Exercisable warrants remaining	8,156,401
Warrants | Kentucky Debt Financing #2
Class of Warrant or Right [Line Items]
Warrants	309,503
Exercise price	$ 0.214
Remaining life (years)	1 year 6 months
Exercisable warrants remaining	309,503
Warrants | Kentucky Debt Financing #1
Class of Warrant or Right [Line Items]
Warrants	2,623,951
Exercise price	$ 0.04
Remaining life (years)	1 year 6 months
Exercisable warrants remaining	2,623,951
Warrants | Kentucky Oil Project
Class of Warrant or Right [Line Items]
Warrants	3,498,601
Exercise price	$ 0.04
Remaining life (years)	1 year 6 months
Exercisable warrants remaining	3,498,601
Warrants | Debt Financing
Class of Warrant or Right [Line Items]
Warrants	2,435,517
Exercise price	$ 0.044
Remaining life (years)	8 months
Exercisable warrants remaining	316,617
Share-for-Warrant Exchange
Class of Warrant or Right [Line Items]
Warrants	427,729
Exercise price	$ 0.04
Remaining life (years)	1 year 6 months
Exercisable warrants remaining	427,729
12% Subordinated Notes
Class of Warrant or Right [Line Items]
Warrants	980,000	1,190,000
Exercise price	$ 0.07	$ 0.07	$ 0.14
Remaining life (years)	1 year 10 months
Exercisable warrants remaining	980,000

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Warrants - Schedule of Warrant Activity (Details) - $ / shares	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Warrants outstanding, beginning of period	8,156,401	8,306,401
Warrants Expired / Cancelled / Forfeited	0	150,000
Warrants outstanding, end of period	8,156,401	8,156,401
Warrants exercisable, end of period	8,156,401
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value
Weighted average exercise price of warrants outstanding, beginning of period	$ 0.06	$ 0.11
Weighted average exercise price, Expired / Cancelled / Forfeited	0	0.14
Weighted average exercise price of warrants outstanding, end of period	0.05	$ 0.06
Weighted average exercise price of warrants exercisable, end of period	$ 0.05

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Warrants (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2010
Outstanding warrants, weighted average exercise price	$ 0.05	$ 0.06
Weighted average remaining life	1 year 6 months	2 years 3 months
Intrinsic value	$ 0	$ 0
Warrants outstanding	8,156,401
12% Subordinated Notes
Outstanding warrants, weighted average exercise price	$ 0.07	$ 0.07	$ 0.14
Weighted average remaining life	1 year 10 months
Warrants outstanding	980,000	1,190,000
Warrant expiration date	Jan. 29, 2019		Jan. 29, 2017
Fair value of warrants	$ 29,075

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Restricted Stock and Restricted Stock Unit Plan (Details)	12 Months Ended
	Feb. 28, 2017 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, awarded	3,000,000
Restricted shares, vested	2,986,220	[1]
Restricted shares, returned	13,780	[2]
Grant Date - 04/07/2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, awarded	1,900,000
Restricted shares, vesting period	3 years
Restricted shares, vested	1,900,000	[1]
Restricted shares, returned	0	[2]
Restricted shares, outstanding, unvested	0
Grant Date (A) - 07/16/2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, awarded	25,000
Restricted shares, vesting period	3 years
Restricted shares, vested	25,000	[1]
Restricted shares, returned	0	[2]
Restricted shares, outstanding, unvested	0
Grant Date (B) - 07/16/2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, awarded	625,000
Restricted shares, vesting period	4 years
Restricted shares, vested	619,130	[1]
Restricted shares, returned	5,870	[2]
Restricted shares, outstanding, unvested	0
Grant Date (A) - 07/22/2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, awarded	25,000
Restricted shares, vesting period	3 years
Restricted shares, vested	25,000	[1]
Restricted shares, returned	0	[2]
Restricted shares, outstanding, unvested	0
Grant Date (B) - 07/22/2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, awarded	425,000
Restricted shares, vesting period	4 years
Restricted shares, vested	417,090	[1]
Restricted shares, returned	7,910	[2]
Restricted shares, outstanding, unvested	0

[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.

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Restricted Stock and Restricted Stock Unit Plan (Details Narrative) - shares		1 Months Ended		12 Months Ended
		Jul. 31, 2010	Feb. 28, 2009	Feb. 28, 2017	Feb. 29, 2016	Apr. 30, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, awarded				3,000,000
Restricted shares, vested	[1]			2,986,220
2009 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock available for grant						4,000,000
2009 Plan | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock available for grant					1,013,780
Restricted shares, awarded		425,000	2,550,000	3,000,000
Restricted shares, vested				2,986,220
Restricted shares, vesting period		4 years
2009 Plan | Restricted Stock | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, vesting period			3 years
2009 Plan | Restricted Stock | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, vesting period			4 years
2009 Plan | Restricted Stock | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares, awarded		25,000
Restricted shares, vesting period		3 years

[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.

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Income Taxes - Income Tax Expense Benefit Reconciliation (Details) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation
Computed at U.S. and state statutory rates (40%)	$ (1,387,422)	$ (1,616,023)
Permanent differences	83,606	143,946
Changes in valuation allowance	1,303,816	1,472,077
Income tax expense (benefit)	$ 0	$ 0

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Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Deferred tax assets:
Net operating loss carryforwards	$ 10,425,780	$ 10,217,121
Oil and gas properties	32,488	(944,342)
Stock based compensation	88,723	88,723
Other	(32,618)	(150,945)
Less valuation allowance	(10,514,373)	(9,210,557)
Deferred tax assets, net	$ 0	$ 0

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Income Taxes (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Income Tax Disclosure [Abstract]
Net operating loss carryforwards, federal and state, approximate	$ 26,064,450
Net operating loss carryforwards, expiration date	Feb. 28, 2024
Approximate increase in valuation allowance	$ 1,303,816	$ 1,472,077

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Subsequent Events (Details Narrative) - shares	2 Months Ended	12 Months Ended
	May 25, 2017	Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2015	Feb. 28, 2014	Feb. 28, 2013	Feb. 29, 2012	Feb. 28, 2011	Feb. 28, 2010	Feb. 28, 2009	Feb. 29, 2008	May 09, 2017
Subsequent Event [Line Items]
Series A Convertible Preferred Stock converted		675,200
Common stock issued upon conversion of Series A convertible preferred stock converted		2,025,600
Series A Convertible Preferred Stock
Subsequent Event [Line Items]
Series A Convertible Preferred Stock converted		(675,200)	(10,000)	(3,000)	(151,000)	(18,000)	0	(102,000)	(51,900)	(237,000)	(102,300)
Common stock issued upon conversion of Series A convertible preferred stock converted		2,025,600	30,000	9,000	453,000	54,000	0	306,000	155,700	711,000	306,900
Subsequent Event | Series A Convertible Preferred Stock
Subsequent Event [Line Items]
Series A Convertible Preferred Stock converted	14,997
Common stock issued upon conversion of Series A convertible preferred stock converted												44,991

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Supplementary Information - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Proved leasehold costs
Mineral Interests	$ 115,119	$ 654,445
Wells, equipment and facilities	3,691,659	6,095,262
Total cost of oil and natural gas properties	3,806,778	6,749,707
Unproved properties
Mineral Interests	59,375	585,826
Uncompleted wells, equipment and facilities	0	0
Total unproved properties	59,375	585,826
Less accumulated depreciation, depletion amortization and impairment	(2,953,226)	(3,569,705)
Net oil and natural gas properties	$ 912,927	$ 3,765,828

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Supplementary Information - Cost Incurred in Oil and Gas Producing Activities (Details) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Costs Incurred Acquisition Of Oil And Gas Properties
Acquisition of proved properties	$ 0	$ 0
Acquisition of unproved properties	59,375	0
Development costs	0	243,823
Exploration costs	0	76,053
Total costs incurred	$ 59,375	$ 319,876

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Supplementary Information - Results of Operations from Oil and Gas Producing Activities (Details) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Results Of Operations From Oil And Gas Producing Activities
Oil and gas revenues	$ 762,686	$ 1,253,686
Production costs	(221,579)	(268,448)
Exploration expenses	(16,529)	(76,053)
Depletion, depreciation, amortization and impairment	(234,454)	(517,870)
Impairment of oil properties	0	(1,108,683)
Result of oil and gas producing operations before income taxes	290,124	(717,368)
Provision for income taxes	0	0
Results of oil and gas producing activities	$ 290,124	$ (717,368)

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Supplementary Information - Schedule of Proved Oil and Gas Reserves (Details)		12 Months Ended
		Feb. 28, 2017 Boe bbl	Feb. 29, 2016 Boe bbl
Proved Developed and Undeveloped Reserves
Proved reserves - beginning balance		773,110	845,659
Proved reserves - ending balance		381,070	773,110
Proved Developed and Undeveloped Reserve (Energy)
Proved reserves - beginning balance | Boe		902,780	888,136
Proved reserves - ending balance | Boe		381,070	902,780
Oil (Barrels)
Proved Developed and Undeveloped Reserves
Proved reserves - beginning balance		773,110	845,659
Proved reserves - revisions	[1]	(13,145)	(120,001)
Proved reserves - extensions and discoveries			76,270
Proved reserves - sales of minerals		(360,018)
Proved reserves - production		(18,877)	(28,818)
Proved reserves - ending balance		381,070	773,110
Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves
Proved reserves - beginning balance		778,020	254,860
Proved reserves - revisions	[1]	0	390,693
Proved reserves - extensions and discoveries			161,320
Proved reserves - sales of minerals		(761,517)
Proved reserves - production		(16,503)	(28,853)
Proved reserves - ending balance		0	778,020
BOE (Barrels)
Proved Developed and Undeveloped Reserve (Energy)
Proved reserves - beginning balance | Boe		902,780	888,136
Proved reserves - revisions | Boe	[1]	(13,145)	(54,886)
Proved reserves - extensions and discoveries | Boe			103,157
Proved reserves - sales of minerals | Boe		(486,937)
Proved reserves - production | Boe		(21,628)	(33,627)
Proved reserves - ending balance | Boe		381,070	902,780

[1] The revisions of previous estimates resulted from a decline in the estimated economic life of the reserves due to lower realized crude oil prices in the energy markets.

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Supplementary Information - Schedule of Proved Developed and Undeveloped Reserves (Details)	Feb. 28, 2017 Boe bbl	Feb. 29, 2016 Boe bbl	Feb. 28, 2015 Boe bbl
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, net | bbl	381,070	773,110	845,659
Proved developed and undeveloped reserves, net - BOE | Boe	381,070	902,780	888,136
Proved Developed Reserves
Reserve Quantities [Line Items]
Proved developed reserves | bbl	99,710	203,131	278,233
Proved developed reserves - BOE | Boe	99,710	231,778	294,585
Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved undeveloped reserves | bbl	281,360	569,979	567,426
Proved undeveloped reserves - BOE | Boe	281,360	671,002	593,551

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Supplementary Information - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves (Details) - USD ($)		Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2015
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Standardized Measure
Future cash inflows		$ 13,684,350	$ 34,077,610
Future production costs	[1]	(7,377,450)	(16,255,030)
Future development costs		(2,090,810)	(7,278,930)
Future income tax expenses	[2]	0	0
Future net cash flows		4,216,090	10,543,650
10% annual discount for estimated timing of cash flows		(2,493,750)	(6,570,720)
Standardized measure of discounted future net cash flows at the end of the fiscal year		$ 1,722,340	$ 3,972,930	$ 17,504,700

[1] Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company's oil and gas operations.

[2] The Company has sufficient tax deductions and allowances related to proved oil and gas reserves to offset future net revenues.

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Supplementary Information - Oil and Gas Net Production, Average Sales Price and Production Costs (Details) - $ / bbl		12 Months Ended
		Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2015
Oil (Barrel)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average oil and gas sales price	[1]	40.00	47.45	85.53
Natural Gas
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average oil and gas sales price	[1]	1.59	2.51	2.99

[1] Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year.

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Supplementary Information - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flow Relating To Proved Oil And Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at the beginning of the year	$ 3,972,930	$ 17,504,700
Extensions, discoveries and improved recovery, less related costs	0	271,190
Revisions of previous quantity estimates	(88,875)	(408,300)
Sales of minerals in place	(1,948,968)	0
Net changes in prices and production costs	(1,289,038)	(10,040,886)
Accretion of discount	397,293	1,750,470
Sales of oil produced, net of production costs	(541,107)	(985,238)
Development costs incurred during the period	4,654	213,576
Changes in future development costs	262,156	526,413
Changes in timing of future production	953,295	(4,858,995)
Net changes in income taxes	0	0
Standardized measure of discounted future net cash flows at the end of the year	$ 1,722,340	$ 3,972,930