10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended February 29, 2012

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.)
601 W. Main Ave., Suite 1017, Spokane, WA	99201
(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 ¨   Noþ

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 ¨   Noþ

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨   Noþ

The aggregate market value of the voting and non-voting stock held by non-affiliates of the registrant, based on the closing price of $0.07 on August 31, 2011, as reported by the Over-the-Counter Bulletin Board was $3,030,286.

At May 24,2012, the registrant had 47,787,769 outstanding shares of $0.001 par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE:

None.  

TABLE OF CONTENTS

		PAGE
PART 1		4
ITEM 1.	BUSINESS	4
ITEM 1A.	RISK FACTORS	8
ITEM 1B.	UNRESOLVED STAFF COMMENTS	16
ITEM 2.	PROPERTIES	17
ITEM 3.	LEGAL PROCEEDINGS	25
ITEM 4.	MINE SAFETY DISCLOSURES	25
PART II		26
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	26
ITEM 6.	SELECTED FINANCIAL DATA	31
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	32
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	46
	Balance Sheets as of February 29, 2012 and February 28, 2011	47
	Statements of Operations for the Years Ended February 29, 2012 and February 28, 2011	48
	Statements of Changes in Stockholders' Equity (Deficit) for the Years Ended February 29, 2012 and February 28, 2011	49
	Statements of Cash Flows for the Years Ended February 29, 2012 and February 28, 2011	50
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	67
ITEM 9A.	CONTROLS AND PROCEDURES	68
ITEM 9B.	OTHER INFORMATION	69
PART III		70
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE	70
ITEM 11.	EXECUTIVE COMPENSATION	76
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	83
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	86
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	89
PART IV		90
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	90
GLOSSARY OF TERMS		93
SIGNATURES		96

2

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are based on our current expectations, assumptions, estimates and projections for the future of our business and our industry and are not statements of historical fact.  Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will” and similar expressions identify forward-looking statements.  Examples of forward-looking statements include statements about the following:

·

Our future operating results;

·

Our future capital expenditures;

·

Our future financing;

·

Our expansion and growth of operations; and

·

Our future investments in and acquisitions of oil and natural gas properties.

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

·

General economic and business conditions;

·

Exposure to market risks in our financial instruments;

·

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

·

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

·

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

·

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

·

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

·

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

·

Legislative and regulatory uncertainties, including proposed changes to federal tax law and climate change legislation, 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 and in our other public filings, 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 underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  We specifically undertake no obligation to publicly update or revise any information contained in 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 established for the purpose of mineral exploration and development on claims or leased lands throughout the Western United States. In August 1955, we acquired the assets of Morning Sun Uranium, Inc. By the late 1950’s, we had 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 and development company in the oil and 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 Bulletin Board (OTC:BB) market under the symbol DBRM.OB.  

Our corporate office is located at 601 W. Main Ave., Suite 1017, Spokane, Washington 99201-0613.  Our telephone number is (509) 232-7674.  Our regional operations office is located at 1414 S. Friendswood Dr., Suite 215, Friendswood, Texas 77546.  The telephone number of our office in Friendswood is (281) 996-4176.  

Oil and Gas Overview

Daybreak is an independent oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities and selling the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.  Our focus is to pursue oil and gas drilling opportunities through joint ventures with industry partners as a means of limiting our drilling risk.  Prospects are generally brought to us by other oil and gas companies or individuals.  We identify and evaluate prospective oil and gas properties to determine both the degree of risk and the commercial potential of the project.  We seek projects that offer a mix of low risk with a potential of steady reliable revenue as well as projects with a higher risk, but that may also have a larger return. Modern technology including 3-D seismic helps us identify potential oil and gas reservoirs and to mitigate our risk.  Currently, our core area of activity is located in Kern County, California; although new opportunities may ultimately be secured in other areas.  We seek to maximize the value of our asset base by exploring and developing properties that have both production and reserve growth potential.

In some instances, we strive to be operator of our oil and gas properties.  As the operator, we are more directly in control of the timing, costs of drilling, completion and production operations on our projects.

Competition

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

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

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Significant Customers

At our East Slopes Project, located in Kern County, California, there is only one buyer available for the purchase of our oil production. At February 29, 2012, this one customer represented 100% of crude oil sales receivable.  If this buyer is unable to resell its products or if they lose a significant sales contract then we may incur difficulties in selling our oil and gas.  

The price we receive for oil sales is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma contracts, less transportation costs and deductions that vary by grade of crude oil sold.  Historically, the sale price we receive for California oil sales has been less than the quoted WTI price.  For the year ended February 28, 2011 the average monthly WTI price was $80.80 and the average monthly sale price we received was $74.98 which was a discount of 7.2% from the average monthly WTI price.  However for the year ended February 29, 2012, we have been receiving a premium price in comparison to the WTI price. The average monthly WTI price was $96.96 and the average monthly sale price we received was $104.54 which was a premium of 7.8% higher than the average monthly WTI price.

The revenue from all customers is set forth in the table below.

		Twelve Months Ended February 29, 2012			Twelve Months Ended February 28, 2011
Project	Customer	Revenue		Percentage	Revenue		Percentage
California - East Slopes Project	Plains Marketing	$	1,314,124	100.0%	$	975,479	90.4%
Louisiana - Krotz Springs**	J.P. Van Way		-	-		104,017	9.6%
Total Revenues		$	1,314,124	100.0%	$	1,079,496	100.0%

**During the year ended February 28, 2011, the Company received approximately $104,017 in revenue related to the Krotz Springs Field in Louisiana as a one-time adjustment to gas revenue earned in calendar years 2007, 2008 and 2009 due to a well production revenue misallocation by the unitized field operator.

Title to Properties

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

Regulation

The exploration and development of oil and 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, 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.

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Operational Hazards and Insurance

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, 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 29, 2012, 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 next fiscal year as needed.  All other services are currently contracted for with independent contractors.  We have not obtained “key man” life insurance on any of our officers or directors.

Long Term Success

Our success depends on the successful acquisition, exploration and development of commercial grade oil and gas properties as well as the prevailing prices for oil and natural gas to generate future revenues and operating cash flow. Oil and natural gas prices have been extremely volatile in recent years and are affected by many factors outside of our control.  The volatile nature of the energy markets makes it difficult to estimate future prices of oil and natural gas; however, any prolonged period of depressed prices would have a material adverse effect on our results of operations and financial condition.  Such pricing factors are largely beyond our control, and may result in fluctuations in our earnings. We believe there are significant opportunities available to us in the oil and gas exploration and development industry.

Availability of SEC Filings

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

Website / Available Information

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

We have adopted an Ethical Business Conduct Policy Statement to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures.  We also have adopted a Code of Ethics for Senior Financial Officers that applies to our principal executive officer, principal financial officer, principal accounting officer and controller.  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.  

6

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.

601 W. Main Ave., Suite 1017

Spokane, WA 99201-0613

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.

7

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.  If any of the following risks actually occur, our financial condition and our results of operations could be materially and adversely affected.  Additional risks and uncertainties not presently known to us may also impair our business operations.  In any such case, the trading price of our Common Stock could decline, and you could lose all, or a part, of your investment.

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

We have a limited history of oil and gas production and have minimal proven reserves.  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.  As a result of our limited operating history, we are more susceptible to business risks.  These risks include unforeseen capital requirements, failure to establish business relationships, and competitive disadvantages against larger and more established companies.

The oil and gas business is highly competitive, placing Daybreak at an operating disadvantage.

We expect to be at a competitive disadvantage in (a) seeking to acquire suitable oil and or gas drilling prospects; (b) undertaking exploration and development; and (c) seeking additional financing.  We base our preliminary decisions regarding the acquisition of oil and or 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 large oil and gas companies with longer operating histories and greater financial resources than us.  These larger competitors, by reason of their size and greater financial strength, can more easily:

·

access capital markets;

·

recruit more qualified personnel;

·

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

·

handle longer periods of reduced prices of gas and oil;

·

acquire and evaluate larger volumes of critical information; and

·

compete for industry-offered business ventures.

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

Oil and gas prices are volatile.  Declines in commodity prices in the past have adversely affected, and in the future may adversely affect, our financial condition, liquidity, results of operations, cash flows, access to capital markets, and ability to grow.

Our revenues, operating results, liquidity, cash flows, profitability and valuation of proved reserves depend substantially upon the market prices of oil and natural gas.  Product prices affect our cash flow available for capital expenditures and our ability to access funds through the capital markets.  If commodity prices decline in the future, the decline could have adverse effects on our reserves and availability of funds.

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

·

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

·

market uncertainty;

·

the level of consumer product demands;

·

hurricanes and other weather conditions;

·

domestic governmental regulations and taxes;

·

the foreign supply of oil and natural gas; and

·

overall domestic and foreign economic conditions.

These factors make it very difficult to predict future commodity price movements with any certainty. Oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.

8

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

Our future performance depends upon our ability to find, acquire, and develop oil and gas reserves that are economically recoverable.  Without successful exploration and acquisition activities, we will not be able to develop reserves or generate production revenues to achieve and maintain profitable operating results.  No assurance can be given that we will be able to find, acquire or develop these reserves on acceptable terms.  We also cannot assure that commercial quantities of oil and gas deposits will be discovered that are sufficient to enable us to recover our exploration and development costs.  Although certain management personnel have significant experience in the oil and gas industry, we have not yet established a history of locating and developing properties that have economically feasible oil and gas reserves.

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 $1,432,584 for the year ended February 29, 2012, and we have an accumulated deficit through February 29, 2012 of $23,839,493.  Without successful exploration and development of our properties any investment in Daybreak could become devalued or worthless.

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

Our outstanding indebtedness at February 29, 2012 was approximately $4,407,178.  The level of indebtedness we have affects our operations in a number of ways.  We will need to use a portion of our cash flow to pay principal and interest and meet payables commitments, which will reduce the amount of funds we will have available to finance our operations.  This lack of funds could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate and could limit our ability to make funds available for other purposes, such as future exploration, development or acquisition activities.  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 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.

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

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

9

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

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

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

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

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

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

10

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil we produce.  Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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

On April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities.  The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015.  For well completion operations occurring at such well sites before January 1, 2015, the final regulation allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions.  These regulation also establish specific new requirements regarding emissions from hydrators, storage tanks and other production equipment.  While we do not currently have any natural gas production operations, this new rule and compliance with its requirements could increase our costs of development and productions, though we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

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.

We have a history of net losses and expect that our operating losses will continue over the next 12 months as we continue to implement our business plan.  Our business plan contemplates the development of our current exploration projects and the expansion of our business by identifying, acquiring, and developing additional oil and gas properties.

We need to rely on external sources of financing to meet the capital requirements associated with the development of our current properties and the expansion of our oil and gas operations.  We plan to obtain the funding we need through debt and equity markets.  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.

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

11

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

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

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

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

All of our properties are held under interests in oil and gas mineral leases.  If we fail to meet the specific requirements of any lease, such lease may be terminated or otherwise expire.  We cannot be assured that we will be able to meet our obligations under each lease.  The termination or expiration of our “working interests” (interests created by the execution of an oil and 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 natural gas and oil produced by our leases.  We may not be able to obtain any such additional funds on acceptable terms.

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

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

We anticipate that we, or the person or company acting as “operator” (the individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease, usually pursuant to the terms of a joint operating agreement among the various parties owning the working interest in the well) on the properties that we lease, will examine title prior to any well being drilled.  Even after taking these precautions, deficiencies in the marketability of the title to the leases may still arise.  Such deficiencies may render some leases worthless, negatively impacting our financial condition.

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

Our oil and gas projects are subject to risks inherent in the oil and gas industry.  These risks involve explosions, uncontrollable flows of oil, 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.

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

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

Our President and Chief Executive Officer, who is also acting as our interim principal finance and accounting officer; our former Senior Vice-President, Exploration who effective March 15, 2012 is now a consultant to the Company; our Director of Field Operations; and two directors each have substantial experience in the oil and gas business.  The loss of any of these individuals could adversely affect our business.  If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that a suitable or comparable substitute will be found.  

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

Our financial statements for the year ended February 29, 2012 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.

In the past, we have disclosed material weakness in our internal controls and procedures which could erode investor confidence, jeopardize our ability to obtain insurance and limit our ability to attract qualified persons to serve at Daybreak.

As of the end of the reporting period, February 29, 2012, an evaluation was conducted by Daybreak management, including our Chief Executive Officer, also serving as our interim principal finance and accounting officer, as to the effectiveness of the design and operation of our internal controls over financial reporting pursuant to Rule 13a-15(e) of the Exchange Act.  Based on that evaluation, our management concluded that our internal controls over financial reporting were effective as of February 29, 2012.

When the evaluation of our internal controls over financial reporting was conducted for the year ended February 28, 2009, a determination was made that our internal controls were not effective as of that date. This evaluation is more fully described in our Annual Report on Form 10-K for the year ended February 28, 2009. We have since initiated the following changes in our internal control over financial reporting:

·

developed an additional level of authoritative accounting resource and review to be used in the recognition of extraordinary non-cash transactions;

·

additional training was designed to reinforce existing resources;

·

management added an additional level of oversight for approval of non-routine non-cash transactions; and

·

a third party was engaged to assist in efforts to document and test financial reporting controls.

Failure to comply with rules regarding internal controls and procedures may make it more difficult for us to obtain certain types of insurance, including director and officer liability insurance.  We may be forced to accept reduced policy limits and coverage and/or incur substantially higher costs to obtain the same or similar coverage.  The impact of these events could also make it more difficult for us to attract and retain qualified persons to serve on our Board of Directors, on committees of our Board of Directors, or as executive officers.

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

Our Common Stock is quoted on the Over-the-Counter Bulletin Board (OTC:BB) market under the symbol DBRM.OB.

The Bulletin Board market is characterized by low trading volume.  Because of this limited liquidity, shareholders may be unable to sell their shares at or above the cost of their purchase prices.  The trading price of our shares has experienced wide fluctuations and these shares may be subject to similar fluctuations in the future.

The trading price of our Common Stock may be affected by a number of factors including events described in these risk factors, as well as our operating results, financial condition, announcements of drilling activities, general conditions in the oil and gas exploration and development industry, and other events or factors.

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 may 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.

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

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

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

Our authorized capital stock consists of 200,000,000 shares of Common Stock and 10,000,000 shares of preferred stock.  As of February 29, 2012, there were 48,787,769 shares of Common Stock and 906,565 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.

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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.

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

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

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

We expect to seek to raise additional capital in the future to help fund our acquisition, development, and production of oil and natural gas reserves.  Debt financing, if available, may require restrictive covenants which may limit our operating flexibility.  Future debt financing may also involve debt instruments that are convertible into or exercisable for Common Stock.  The conversion of the debt to equity financing may dilute the equity position of our existing shareholders.

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

We have not paid any cash dividends on our Common Stock since our inception.  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 which 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.

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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

During the years ended February 29, 2012 and February 28, 2011, we were involved in an onshore oil project in Kern County, California.  In the year ended February 28, 2010, we were involved in onshore oil and gas projects in Alabama, California and Louisiana.  Our involvement in the Alabama and Louisiana projects has ended and information presented on these projects is intended to meet disclosure requirements or be for comparative purposes only.  Unless otherwise noted, all of our discussion refers only to our continuing operations in California.  We have not filed any estimates of total, proved net oil or gas reserves with any federal agency other than this report to the SEC for the fiscal year ended February 29, 2012.  Throughout this Annual Report on Form 10-K, oil is shown in barrels (“Bbls”), and natural gas is shown in thousands of cubic feet (“Mcf”) unless otherwise specified.  

Kern County, California (East Slopes Project)

We believe the Company is now well positioned to expand its operations in the East Slopes Project.  We currently have production from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek properties.  The Sunday and Bear properties each have four producing wells.  The Black property is the smallest of all currently producing reservoirs, and we will most likely drill only one or two more development wells at this property.  The Ball and Dyer Creek properties were put on production in late October 2010.  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 seismic data, which we plan to drill in the future.

Producing Properties

Sunday Property

In November 2008, we made our initial oil discovery drilling the Sunday #1 well.  The well was put on production in January 2009.  Production is from the Vedder sand at approximately 2,000 feet.  During 2009, we drilled three development wells, including one horizontal well.  The Sunday reservoir is estimated to be approximately 35 acres in size with the potential for at least three more development wells to be drilled in the future.  With the acquisition of an additional 16.67% working interest in the East Slopes Project in September 2010, we have a 41.67% working interest with a 29.0% net revenue interest in the Sunday #1 well.  We continue to have a 37.5% working interest with a 27% net revenue interest in each of the Sunday #2 and #3 wells.  We also have a 37.5% working interest with a 30.1% net revenue interest in the Sunday #4H well.

Bear Property

In February 2009, we made our second oil discovery drilling the Bear #1 well, which is approximately one mile northwest of our Sunday discovery.  The well was put on production in May 2009.  Production is from the Vedder sand at approximately 2,200 feet.  In December 2009, we began a development program by drilling and completing the Bear #2 well.  In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells.  The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least three more development wells to be drilled in the future including one planned for the summer of 2012.  With the acquisition of an additional 16.67% working interest in the East Slopes Project in September 2010, we have a 41.67% working interest with a 29.0% net revenue interest in each of the Bear wells in this property.

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 2,150 feet.  The Black reservoir is estimated to be approximately 13 acres in size with the potential for up to two more development wells to be drilled in the future.  We have a 37.5% working interest with a 29.8% net revenue interest in this property.

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Sunday Central Processing and Storage Facility

The oil produced from our acreage is considered heavy oil.  The oil ranges from 14° to 16° API gravity.  All of our oil from the Sunday, Bear and Black properties is processed, stored and sold from the Sunday Central Processing and Storage Facility.  The oil must be heated to separate and remove water to prepare it to be sold.  We constructed these facilities during the summer and fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines.  As a result, our average operating costs have been reduced from over $40 per barrel to a monthly average of approximately $26 per barrel of oil for the year ended February 29, 2012.  By having this central facility and permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

Ball Property

The Ball #1-11 well was put on production in late October 2010.  Our 3-D seismic data indicates a reservoir approximately 38 acres in size with the potential for at least two development wells to be drilled in the future.  Production from the Ball #1-11 well is being processed at the Dyer Creek production facility.  In January 2012, we farmed out to a third party, 50% of our working interest covering the Ball and Dyer Creek Fields.  In return, the third party will pay Daybreak’s share of the completed well cost on the next Ball well to be drilled.  We have a 41.67% working interest with a 34.69% net revenue interest in the Ball #1-11 well. For other wells, excluding the Ball 1-11, we will have a 20.84% working interest with a 17.35% net revenue interest in this property.  We expect to drill at least one development well at this property during 2012.   

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.  The Dyer Creek property has the potential for at least one development well in the future.  Production from the DC67X well is also being processed at the Dyer Creek production facility.  We have a 41.67% working interest with a 34.69% net revenue interest in the DC 67X well. For other wells, excluding the DC 67X, we will have a 20.84% working interest with a 17.35% net revenue interest in this property.

Dyer Creek Processing and Storage Facility

The Dyer Creek Processing and Storage Facility serves the Ball and Dyer Creek properties and includes previously abandoned infrastructure that we have refurbished.  We have completed the installation of electrical service to this location, thereby reducing operating costs through the elimination of rental equipment for power generation.  The oil produced into this facility has a similar API gravity to the oil at the Sunday production facility and the oil must also be heated to separate and remove water in preparation for sale.

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Exploration Properties

Bull Run Prospect

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Etchegoin and Santa Margarita sands located between 800 and 1,200 feet deep.  We drilled an exploratory well on this prospect in December 2011 that was determined to be not viable for commercial production and the well was plugged and abandoned.  Utilizing the data received from this well, we expect to drill another exploratory well on this prospect during 2012.  The Bull Run wells will require a pilot steam flood and additional production facilities.  We have a 41.67% working interest in this prospect.

Sherman Prospect

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Olcese and Etchegoin sands between 1,000 and 2,000 feet deep. We plan to drill an exploratory well in 2012.  We have a 41.67% working interest in this prospect.

Breckenridge-Chimney Prospect

This prospect is located in the central portion of our acreage position.  The drilling targets are the Vedder and Eocene sands between 2,000 and 2,500 feet deep.  We plan to drill an exploratory well in 2012.  We have a 41.67% working interest in this prospect.

Tobias Prospect

This prospect is also located in the central portion of our acreage position.  The drilling targets are the Vedder and Eocene sands between 2,000 and 2,500 feet deep.  We plan to drill an exploratory well in 2012.  We have a 41.67% working interest in this prospect.

Glide-Kendall Prospect

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Olcese and Eocene sands between 1,000 and 2,000 feet deep.  We plan to drill an exploratory well in the fall of 2012. We estimate that the Glide Kendall prospect is 200 acres in size with a gross reserve potential of 500,000 barrels of oil. We have a 41.67% working interest in this prospect.

We plan to spend approximately $1,500,000 in new capital investments within the East Slopes Project area in the current fiscal year.

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement entered into by and among Luberski, Inc., a California corporation, as lender, and the Company and RTG Steel Company, LLC, an Arizona limited liability company, as co-borrowers, are secured by mortgages on the Sunday, Bear, Black, Ball and Dyer Creek Properties.  For further discussion of the loan agreement, please refer to Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Short-Term Note (Subsequent Event).”

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Production, Revenue and LOE

Our net production volume, net revenue and net lease operating expenses (“LOE”) by property location for the three months and years ended February 29, 2012 and February 28, 2011 in Kern County, California is set forth in the table below.  Due to certain oil processing credits that we received from December 2009 through August 2010, our overall production costs for the Sunday #1 well and all four Bear wells during that time period were significantly less than the overall production costs for the other Sunday wells and the Black #1 well.  These oil processing credits ended September 1, 2010 with our acquisition of a portion of a third party’s working interest in this project.  Initial LOE costs for the Ball and Dyer Creek locations were higher than average during the first four months of production because of the use of rental equipment to supply power to the wells and production facilities. Electrical power installation has now been completed for these wells and the associated production facility which significantly reduces costs.

	Three Months Ended				Twelve Months Ended
Location	February 29, 2012		February 28, 2011		February 29, 2012		February 28, 2011
Sunday
Production (Bbls)		1,354		1,585		5,689		6,852
Revenue	$	140,071	$	133,390	$	594,669	$	505,888
LOE Costs	$	22,256	$	15,605	$	80,871	$	71,465
Bear
Production (Bbls)		1,138		1,354		5,027		4,365
Revenue	$	117,906	$	114,110	$	525,676	$	330,196
LOE Costs	$	17,363	$	15,645	$	69,659	$	29,737
Black
Production (Bbls)		261		252		907		1,077
Revenue	$	27,061	$	21,179	$	94,939	$	79,903
LOE Costs	$	2,581	$	4,349	$	16,198	$	16,368
Ball
Production (Bbls)		172		229		449		277
Revenue	$	17,477	$	19,270	$	46,658	$	22,970
LOE Costs	$	4,040	$	10,862	$	19,806	$	17,291
Dyer Creek
Production (Bbls)		84		385		499		438
Revenue	$	8,656	$	32,426	$	52,182	$	36,522
LOE Costs	$	4,213	$	10,245	$	18,652	$	15,765
Infrastructure Costs	$	3,252	$	9,844	$	14,822	$	21,264
Total
Production (Bbls)		3,009		3,805		12,571		13,009
Revenue	$	311,171	$	320,375	$	1,314,124	$	975,479
LOE Costs	$	53,705	$	66,550	$	220,008	$	171,890
Average Sales Price	$	103.41	$	84.20	$	104.54	$	74.98
Average LOE Cost	$	17.85	$	17.49	$	17.50	$	13.21

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Reserves

All of our estimated proved reserves of 222,710  barrels of oil at March 1, 2012 were derived from engineering reports prepared by Lonquist & Co. LLC (“Lonquist”) of Austin and Houston, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.

Lonquist is an independent petroleum engineering consulting firm registered in the State of Texas, and Tereasa Montemayor, a Senior Petroleum Engineer, is the technical person at Lonquist primarily responsible for evaluating the proved reserves covered by their report.  Ms. Montemayor graduated from the University of Texas at Austin with a degree in Petroleum Engineering.  She is a member in good standing of the Society of Petroleum Engineers and has over 24 years experience in evaluating oil and gas reserves.  Ms. Montemayor has been employed by Lonquist for over five years, most recently as a reservoir engineer since 2009.  The services provided by Lonquist 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 Lonquist, 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 Robert Martin, formerly the Senior Vice-President – Exploration, and effective March 15, 2012, a consultant for the Company.  Mr. Martin is a 1977 graduate of McGill University in Montreal, Quebec, Canada with an Honors Bachelor of Science Degree in Geological Science and is a member, in good standing, of the Association of Professional Engineers and Geoscientists of Alberta (APEGA) and entitled to the designation “Professional Geologist” in Alberta.  Mr. Martin has over 30 years of experience in petroleum exploration and management.  

Although we believe that the estimates of reserves prepared by Mr. Martin 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 Lonquist for their analysis all pertinent data needed to properly evaluate our reserves.  Mr. Martin consults regularly with Lonquist during the reserve estimation process to review properties, assumptions, and any new data available.  Additionally, the Company’s senior management reviewed and approved all Daybreak reserve report information contained in this Annual Report on Form 10-K.

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

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

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

Our estimated quantities of proved oil reserves as of February 29, 2012 are set forth in the table below. All of our proved reserves are located in Kern County, California.

Reserve Category	Oil (Bbls)
Developed		85,160
Undeveloped		137,550
Total Proved		222,710

We had a net decrease of 15,120 barrels of proved developed and undeveloped oil reserves for the year ended February 29, 2012 in comparison to the year ended February 28, 2011.

Changes in our estimated proved developed oil reserves for the year ended February 29, 2012 are set forth in the table below.

	Proved Reserves (Bbls)
Balance as of February 28, 2011		88,840
Revisions		8,891
Production		(12,571)
Balance as of February 29, 2012		85,160

Revisions. Net upward revisions of 8,891 barrels of oil resulted from new information derived from production history.  Proved producing reserves accounted for 74.0% of the total proved reserve additions.

The following table summarizes changes in our estimated proved undeveloped reserves for the year ended February 29, 2012.

	Proved Undeveloped Reserves (Bbls)
Balance as of February 28, 2011		148,990
Revisions		3,125
Sales of minerals-in-place		(14,565)
Balance as of February 29, 2012		137,550

Revisions. Net upward revisions of 3,125 barrels of oil resulted from new information derived from changes in economic factors primarily sales price of oil.  Proved undeveloped reserves accounted for 26.0% of the total proved reserve additions.

Sales of minerals-in-place.  In January 2012, we farmed out to a third party 50% of our working interest in leases covering the Ball and Dyer Creek Fields in Kern County, California.  This farm-out resulted in a 14,565 barrel decrease in our proved undeveloped oil reserves.

There are no amounts of proved undeveloped reserves that have remained undeveloped for a period greater than five years.

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Summary Operating Data

The production volume shown in the following table is our net share of annual production in each project for the past three fiscal years.  One barrel of oil equivalent (“BOE”) is roughly equivalent to 6,000 cubic feet or 6 Mcf of gas. Our involvement in the Alabama and Louisiana projects has ended and information presented on these discontinued projects is intended to only meet disclosure requirements.  We do not have any fixed delivery commitments for oil or gas in any project area.  

	For the Year Ended
	February 29, 2012	February 28, 2011	February 28, 2010
Oil and Gas Production Data:
Oil (Bbls)
California	12,571	13,009	7,480
Alabama	-	-	1,739
Louisiana	-	-	-
Subtotal	12,571	13,009	9,219
Gas (Mcf)
Louisiana	-	-	1,327
Total (BOE)
California	12,571	13,009	7,480
Alabama	-	-	1,739
Louisiana	-	-	221
Total	12,571	13,009	9,440

The oil and gas sales revenue shown in the table below is our net share of annual revenue in each project for the past three fiscal years.

	For the Year Ended
	February 29, 2012		February 28, 2011		February 28, 2010
Oil and Gas Revenue:
California	$	1,314,124	$	975,479	$	469,357
Alabama		-		-		84,353
Louisiana*		-		104,017		2,085
Total	$	1,314,124	$	1,079,496	$	555,795
*During the year ended February 28, 2011 we received approximately $104,017 from the field operator in Louisiana as a one-time adjustment to gas sales revenue that occurred from May 2007 through December 2009.

The table below shows the average sales price we received for oil and natural gas in aggregate from each project area on a BOE basis for the past three fiscal years.

	For the Year Ended
	February 29, 2012		February 28, 2011		February 28, 2010
Average Price:
Oil (BOE)
California	$	104.54	$	74.98	$	62.75
Alabama	$	-	$	-	$	48.51
Louisiana	$	-	$	-	$	8.70
Average	$	104.54	$	74.98	$	51.95

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The table below shows the average cost of production for the past three fiscal years on a BOE basis.

	For the Year Ended
	February 29, 2012		February 28, 2011		February 28, 2010
Average Production Costs (BOE):
California	$	17.50	$	13.32	$	32.17
Alabama	$	-	$	-	$	52.14
Louisiana	$	-	$	-	$	115.39
Overall Average	$	17.50	$	13.32	$	33.40

The table below shows the developed and undeveloped oil and gas lease acreage held by us as of February 29, 2012. Undeveloped acres are on lease acreage that wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas.  Gross acres are the total number of acres in which we have an interest. Net acres are the sum of our fractional interests owned in the gross acres.

	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
California	440	185	12,450	5,188	12,890	5,373

The table below summarizes our productive oil and gas wells as of February 29, 2012. Productive wells are producing wells and wells capable of production.  Gross wells are the total number of wells in which we have an interest.  Net wells are the sum of our fractional interests owned in the gross wells.

Property Location	Gross	Net
Kern County, California	11	4.4
Total	11	4.4

The table below shows our exploratory and development well drilling activity for the past three fiscal years. We had no drilling activity in either of our Alabama or Louisiana projects during this time.

	For the Year Ended		For the Year Ended		For the Year Ended
	February 29, 2012		February 28, 2011		February 28, 2010
Property Location	Productive	Dry	Productive	Dry	Productive	Dry
Kern County, California
Exploratory	-	1	2	-	1	-
Developmental	-	-	2	-	4	-
Total	-	1	4	-	5	-

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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 in the over-the-counter market on the OTC Bulletin Board under the symbol “DBRM.OB”.  The following table shows the high and low closing sales prices for our Common Stock for the two most recent fiscal years.  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.

	Year Ended February 29, 2012		Year Ended February 28, 2011
	High	Low	High	Low
First Quarter	0.12	0.08	0.12	0.09
Second Quarter	0.12	0.07	0.10	0.07
Third Quarter	0.08	0.04	0.13	0.07
Fourth Quarter	0.10	0.05	0.13	0.09

As of May 22, 2012, the Company had 2,215 shareholders of record.  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 in the past, and the Company does not anticipate that it will pay cash dividends or make distributions in the foreseeable future.

Sales of Unregistered Securities

None.

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Securities Authorized for Issuance under Equity Compensation Plan

The table below sets forth information regarding outstanding restricted stock awards for the fiscal year ended February 29, 2012.  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)	2,996,170	$0.10	1,003,830(2)
Total	2,996,170	$0.10	1,003,830(2)

⁽¹⁾

On April 6, 2009, the Board of Directors approved the 2009 Restricted Stock and Restricted Stock Unit Plan, as described in detail below, under the heading “2009 Restricted Stock and Restricted Stock Unit Plan.”

⁽²⁾

Reflects initial 4,000,000 shares in the 2009 Restricted Stock and Restricted Stock Unit 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 year ended February 28, 2009; (ii) 1,000,000 shares of restricted stock awarded to our current President and Chief Executive Officer and our former interim President and Chief Executive Officer in recognition of past service as executive officers during the year ended February 28, 2009; (iii)  425,000 and 625,000 shares of restricted stock awarded to employees during the years ended February 28, 2011 and 2010 respectively; (iv) 25,000 shares of restricted stock awarded to non-employee directors under our director compensation policy for the years ended February 28, 2011 and 2010 respectively; and (v) 3,830 shares were returned to the 2009 Plan during the year ended February 29, 2012.

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.

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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 which would materially and adversely affect the rights of any Plan Participant under any Award without the consent of such Plan Participant.

At February 29, 2012, a total of 1,003,830 shares remained available for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan issuances is set forth in the table below:

Grant Date	Shares Awarded	Vesting Period	Shares Vested	Shares Returned	Shares Outstanding (Unvested)
4/7/2009	1,900,000	3 Years	1,266,665	-0-	633,335
7/16/2009	25,000	3 Years	16,665	-0-	8,335
7/16/2009	625,000	4 Years	312,500	1,915	312,500
7/22/2010	25,000	3 Years	8,330	-0-	16,670
7/22/2010	425,000	4 Years	106,250	1,915	318,750
	3,000,000		1,710,410	3,830	1,289,590

For the year ended February 29, 2012, we recognized compensation expense related to the above restricted stock grants of $91,218.  Unamortized compensation expense amounted to $42,054 as of February 29, 2012.

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Common Stock

The Company has 200,000,000 authorized shares of Common Stock with a par value of $0.001 of which 48,787,769 shares were issued and outstanding as of February 29, 2012.  In comparison, at February 28, 2011, a total of 48,791,599 shares were issued and outstanding.  This decrease of 3,830 shares was attributable to the return 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.  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.

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.

On June 30, 2006, the Board of Directors designated 2,400,000 of these Preferred Stock shares as Series A Convertible Preferred Stock.  In July 2006, we completed a private placement of the Series A Convertible Preferred Stock that resulted in the issuance of 1,399,765 shares to 100 accredited investors.  At February 29, 2012, there were 906,565 shares issued and outstanding, that had not been converted into our Common Stock.  During the year ended February 29, 2012, there were no conversions of Series A Convertible Preferred Stock to shares of our Common Stock.

As of February 29, 2012, 30 accredited investors have converted 493,200 Series A Convertible Preferred shares into 1,479,600 shares of Daybreak Common Stock.  Conversions of Series A Convertible Preferred that have occurred since the Series A Convertible 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	-		-	-
Totals	493,200		1,479,600	30

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Series A Convertible Preferred Stock

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

Conversion:

The preferred shareholder shall have the right to convert the Series A Convertible Preferred Stock into the Company’s Common Stock at any time.  Each share of Series A Convertible Preferred Stock is convertible into three shares of Common Stock.

Automatic Conversion:

The Series A Convertible Preferred Stock shall be automatically converted into Common Stock if the Common Stock into which the Series A Convertible Preferred Stock are convertible are 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 Convertible Preferred Stock 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 Convertible Preferred Stock do not bear interest.  Dividends are payable upon declaration by the Board of Directors.

Cumulative dividends earned for each fiscal year 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
		$	1,134,714

Voting Rights:

The holders of the Series A Convertible Preferred Stock 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 Convertible Preferred Stock 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 Convertible Preferred Stock.

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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 period covered by the financial statements. This MD&A should be read in conjunction with the audited financial statements and the related notes and other information included elsewhere in this Annual Report on Form 10-K.

Safe Harbor Provision

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

Introduction and Overview

We are an independent oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities, and selling the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and 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.

We have a limited operating history of oil and gas production and minimal proven reserves, production and cash flow.  To date, we have had limited revenues and have not been able to generate sustainable positive earnings on a Company-wide basis.  Our management cannot provide any assurances that Daybreak will ever operate profitably.  As a result of our limited operating history, we are more susceptible to the numerous business, investment and industry risks that have been described in Item 1A. Risk Factors of this Annual Report on Form 10-K.

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

Our operations are focused on identifying and evaluating prospective oil and gas properties and funding projects that we believe have the potential to produce oil or gas in commercial quantities. We are currently in the process of developing a multi-well oilfield project in Kern County, California.

The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California.  Since January 2009, we have participated in the drilling of fourteen wells in this project.  Eleven of those wells have been successful and have been placed on production.  Drilling targets are porous and permeable sandstone reservoirs which exist at depths of 1,200 feet to 3,000 feet.  Refer to our discussion in Item 2.  Properties, in this Annual Report on Form 10-K for more information on our East Slopes Project.  

32

Revenues are derived entirely from the sale of our share of oil production.  We realized the first revenue from producing wells in our East Slopes Project during February 2009.  The price we receive for oil sales is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma contracts, less deductions that vary by grade of crude oil sold.  Historically, the sale price we receive for California oil sales has been less than the quoted WTI price.  For the year ended February 28, 2011 the average monthly WTI price was $80.80 and the average monthly sale price was $74.98, resulting in a discount of 7.2% from average monthly WTI pricing.  For the year ended February 29, 2012 the average monthly WTI price was $96.96 and the average monthly sale price was $104.54, resulting in a premium that was 7.8% higher than the average monthly WTI pricing.  

Results of Operations - Fiscal Year 2012 Compared to Fiscal Year 2011

Revenues from our East Slopes Project in Kern County, California for the year ended February 29, 2012 increased $338,645, or 34.7%, to $1,314,124 in comparison to revenues of $975,479 for the year ended February 28, 2011.  This revenue represented an average net revenue interest of 29.85% in eleven producing wells.  The average price of a barrel of oil for the year ended February 29, 2012 was $104.54 in comparison to $74.98 for the year ended February 28, 2011. The increase of $29.56 in the average price of a barrel of oil accounted for $338,645 or 100% of the revenue increase for the year ended February 29, 2012.

Our net sales volume for the year ended February 29, 2012 was 12,571 barrels of oil in comparison to 13,009 barrels for the year ended February 28, 2011.  This decrease in production of 438 barrels or 3.4% was due to the natural production decline in our oil wells.  For the year ended February 29, 2012 we had production from eleven wells with a total of 3,916 well days in comparison to production for 3,348 well days for the year ended February 28, 2011.

For the year ended February 29, 2012, the East Slopes Project represented 100% of total revenues.  The table below shows the revenues derived entirely from the sale of our share of oil and gas production from our continuing operations for the years ended February 29, 2012 compared to the year ended February 28, 2011.

	2012		2011
California – East Slopes	$	1,314,124	$	975,479
Louisiana – Krotz Springs**		-		104,017
Total revenues	$	1,314,124	$	1,079,496

**During the year ended February 28, 2011, the Company received approximately $104,017 in revenue related to the Krotz Springs Field in Louisiana as a one-time adjustment to gas revenue earned in calendar years 2007, 2008 and 2009 due to well production revenue misallocation by the unitized field operator.

Operating Expenses. Total operating expenses declined $36,251 or 1.7% to $2,109,994 for the year ended February 29, 2012 as compared to $2,146,245 for the year ended February 28, 2011.  Decreases in our exploration and drilling expenses and general and administrative (“G&A”) expenses were partially offset by increases in production expenses and and depreciation, depletion and amortization (“DD&A”) expense.  The table set forth below details our expenses for the year ended February 29, 2012 in comparison to the year ended February 28, 2011:

	For Year Ended		For Year Ended
	February 29, 2012		February 28, 2011
Production expenses	$	220,008	$	172,250
Exploration and drilling		168,177		184,255
DD&A		319,905		307,023
Gain on write-off of ARO		-		(8,324)
Bad debt expense (recovery)		(4,142)		(3,928)
G&A		1,406,046		1,494,969
Total operating expenses	$	2,109,994	$	2,146,245

33

Production expenses include expenses directly associated with the generation of oil and gas revenues, road maintenance, property taxes and well workover expenses.  These expenses increased $47,758, or 27.7%, for the year ended February 29, 2012 primarily due to power expenses and property taxes.  Production expenses represented 10.4% of total operating expenses.

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses decreased $16,078 or 8.7%, for the year ended February 29, 2012 primarily due to lower lease expenses as we dropped acreage in California that was deemed to be lacking in drillable prospects.  For the year ended February 29, 2012 we drilled one well that was a dry hole that was not commercially producible.  Exploration and drilling expenses represented 8.0% of total operating expenses.

DD&A expenses relate to equipment, proven reserves and property costs, along with impairment and is another component of operating expenses.  These expenses decreased $12,882 or 4.2%, for the year ended February 29, 2012 primarily due to lower amortization rates because of an increase in our proved producing reserve base.  DD&A expenses represented 15.2% of total operating expenses.

Bad debt expense (recovery) increased by $214 or 5.4%, for the year ended February 29, 2012.  Bad debt expense represented (0.2%) of total operating expense.

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 $88,923 or 5.9% for the year ended February 29, 2012.  This decrease was due to increased efforts to limit our overall administrative costs. Significant reductions were achieved in consulting, fundraising, legal, marketing, travel and shareholder expenses. Additionally, accounting and legal fees were reduced by approximately $64,704 for the year ended February 29, 2012. G&A expenses represented approximately 66.6% of total operating expenses for the year ended February 29, 2012.

Interest income decreased $1,474 or 69.3%, for the year ended February 29, 2012 due to lower average cash balances.

Interest expense increased $475,226 to $637,366 for the year ended February 29, 2012 primarily due to interest expense associated with the Well Works Loan discussed further in the MD&A under the caption One-Year Note Payable under Short-Term Borrowings.

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.  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, 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 is to improve cash flow to cover the current level of G&A expenses and to fund our development drilling in California.  

34

Liquidity and Capital Resources

Our primary financial resource is our base of oil reserves. Our ability to fund our capital expenditure program is dependent upon the price levels we receive from our oil sales; the success of our exploration and development program in Kern County, California; and the availability of capital resource financing. In the next fiscal year, we plan on spending approximately $1,500,000 in new capital investments, 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.

The changes in our capital resources at February 29, 2012 compared with February 28, 2011 are:

	February 29, 2012		February 28, 2011		Increase (Decrease)		Percentage Change
Cash	$	73,392	$	57,380	$	16,012	27.9%
Current Assets	$	626,778	$	549,903	$	76,875	14.0%
Total Assets	$	3,155,469	$	3,294,808	$	(139,339)	(4.2%)
Current Liabilities	$	3,848,154	$	2,653,752	$	1,194,402	45.0%
Total Liabilities	$	4,407,178	$	3,204,768	$	1,202,410	37.5%
Working Capital	$	(3,221,376)	$	(2,103,849)	$	(1,117,527)	53.1%

Our working capital deficit increased by $1,117,527, from ($2,103,849) at February 28, 2011 to ($3,221,376) at February 29, 2012.  While we have ongoing positive cash flow from our operations in California we have not yet been able to generate sufficient cash flow to cover all of our general and administrative (“G&A”) and interest expenses. This is the primary factor for the increase in our working capital deficit. We anticipate an increase in our cash flow from our East Slope operations in Kern County, California during the next fiscal year.  

We have repositioned Daybreak to better meet our corporate goals and objectives by disposing of assets that impeded our cash flow and growth in the East Slopes Project. In the last few years we have disposed of properties in Alabama, Louisiana and Texas.  These actions have allowed us to move forward with our drilling and exploration program in Kern County.   

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

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

In the current fiscal year, we continue to seek additional financing for our planned exploration and development activities.  We plan to obtain 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:

	Year Ended February 29, 2012		Year Ended February 28, 2011		Increase (Decrease)		Percentage Change
Net cash provided by (used in) operating activities	$	(37,700)	$	184,673	$	(222,373)	(120.4%)
Net cash (used in) investing activities	$	(231,388)	$	(1,155,244)	$	923,856	80.0%
Net cash provided by financing activities	$	285,100	$	780,000	$	494,900	(63.4%)

Cash Flow Used in Operating Activities

Cash flow from operating activities is derived from the production of our oil reserves and changes in the balances of receivables, payables, or other non-oil property asset account balances.  For the year ended February 29, 2012, we had a deficit in cash flow from operating activities of ($37,700), in comparison to a cash flow of $184,673 for the year ended February 28, 2011.  This decrease of $222,373 in cash flow was the result of a larger net loss and smaller positive changes in receivables and payables balances for the year ended February 29, 2012 in comparison to the year ended February 28, 2011.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

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

Cash Flow Provided by Investing Activities

Cash flow from investing activities is derived from changes in oil and gas property balances and Other Assets account balances.  Cash used in investing activities for the year ended February 29, 2012 was $231,388, a decrease of $923,856 from the $1,155,244 used in investing activities for the year ended February 28, 2011.  This change primarily reflects the lack of drilling activity during the year ended February 29, 2012 in comparison to the year ended February 28, 2011.

Cash Flow Provided by Financing Activities

Cash flow from financing activities is derived from changes in long-term liability account balances or in equity account balances excluding retained earnings.  Cash flow provided by financing activities was $285,100 for the year ended February 29, 2012. This is in comparison to $780,000 provided by financing activities for the year ended February 28, 2011.  The decrease of $494,400 in funds provided by financing was the opening of a credit line and an increase in notes payable – related parties offset by a payment to an escrow agent for a loan commitment for the year ended February 29, 2012.  We anticipate it will be necessary to rely on additional funding from the capital markets in the current fiscal year.

Short-Term Borrowings

One-Year Note Payable

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest in its East Slopes Project from another working interest owner.  The Company financed the additional working interest purchase by issuing, to a third party, Well Works, LLC (“Well Works”), a one-year convertible secured promissory note for the principal amount of $750,000 (the “Well Works Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing.  Interest expense related to the Well Works Loan for the year ended February 29, 2012 was $37,500.  The interest expense was fully amortized at February 29, 2012.  The Company paid in full all amounts due and payable under the Well Work Loan on May 22, 2012.  

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While still outstanding, Well Works had the right to convert up to 50% of the unpaid principal balance into the Company’s Common Stock at a conversion price of $0.16 per share at any time prior to the Well Works Loan being paid in full.  

The Well Works Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in the Company’s East Slopes Project.  Furthermore, as a condition precedent to the Well Works Loan, the Company entered into a Technical and Consulting Services Agreement dated September 17, 2010 (the “Consulting Services Agreement”) with Well Works, whereby Daybreak would provide operating, engineering and technical consulting to Well Works for a one-year period for the purpose of evaluating 22 wells in Hutchinson County, Texas for Well Works.  

The Company also issued 250,000 shares of the Company’s Common Stock to Well Works as a loan origination fee. The fair value of these shares amounted to $23,750 which was deferred and fully amortized over the original term of the Well Works Loan.  Amortization expense for the year ended February 29, 2012 amounted to $11,875.  The loan origination fees were fully amortized as of February 29, 2012.  

As additional consideration for the Well Works Loan, the Company executed an Assignment of Net Profits Interest dated September 17, 2010 (the “Assignment of Net Profits Interest”) in favor of Well Works, whereby Daybreak assigned two percent of the net profits realized by the Company on its leases in the East Slopes Project.  The fair value of the two percent net profits interest was determined to be $60,210 and was recognized as a discount to the debt.  The debt discount was deferred and fully amortized over the original term of the Well Works Loan.  Amortization expense for the year ended February 29, 2012 amounted to $30,105.  The debt discount was fully amortized as of February 29, 2012.

The Company analyzed the Well Works Loan for derivative accounting consideration and determined that derivative accounting did not apply to this instrument.

A Loan Extension Agreement (the “Loan Extension Agreement”) between Well Works and the Company was executed on September 19, 2011 extending the Well Works Loan for a period of 30 days.  As compensation for the extension, Daybreak agreed to pay an extension fee to Well Works of $50,000 and pay legal fees and a partial principal payment of $150,000 in aggregate.  

On October 24, 2011, Well Works and the Company executed a Forbearance Agreement whereby Daybreak requested that Well Works forbear from exercising its rights and remedies under the Well Works Loan and the Loan Extension Agreement from October 19, 2011 to November 10, 2011 (the “Forbearance Period”).  The Company agreed to pay interest and legal fees of $21,253 in aggregate during the Forbearance Period.  In addition, Daybreak assigned to Well Works a 3% overriding royalty interest proportionately reduced to the Company’s interest in all its leases in the East Slopes Project effective November 1, 2011.  Furthermore, Daybreak and Well Works agreed to cancel, in its entirety, the Assignment of Net Profits Interest.  Finally, the Consulting Services Agreement was extended until November 10, 2012.

On November 11, 2011, Well Works and the Company executed a new Forbearance Agreement further extending the date of the payoff from November 11, 2011 to November 18, 2011.  As compensation for the extension, Daybreak agreed to pay a fee of $12,500 plus interest due of $3,353 on the entire outstanding balance of the Well Works Loan from November 11, 2011 to November 18, 2011 at an 18% per annum default interest rate.

On November 18, 2011, the Company made a payment to Well Works of $600,000 thereby reducing the outstanding principal balance owed on the Well Works Loan and associated loan interest and fees to $253,581.

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On November 19, 2011 Well Works and the Company executed a new Forbearance Agreement (the “Forbearance Agreement II”) further extending the date of the payoff from November 18, 2011 to December 20, 2011 (the “Termination Date”).  Daybreak agreed to pay an extension fee of 20% on the outstanding balance of the Well Works Loan, associated fees and interest as of November 19, 2011, or $50,716 plus legal fees of $4,000.  Furthermore, interest is payable on the entire outstanding balance of $308,297 for the 30-day period at the default interest rate of 18% per annum, resulting in additional interest of $4,561 for a total balance of $312,858 due on or before the Termination Date.

If the Company is unable to pay on or before the Termination Date all amounts owed under the Forbearance Agreement II, there shall be an additional late fee of $250,000 and an increase in the default interest rate from 18% per annum to 24% per annum (2% per month) until all amounts are repaid.  Since the Company was not able to repay the loan by the Termination Date, the Company recognized the late fee of $250,000 which is included in accrued interest as of February 29, 2012.

The Company and Well Works further agreed that the term of the Consulting Services Agreement would be extended until December 20, 2012.

On January 30, 2012, the Company and Well Works executed Forbearance Agreement III extending the Termination Date of the Well Works loan to May 20, 2012.  Along with the late fee of $250,000 under the Forbearance Agreement II, Daybreak agreed to pay a fee of $25,000 to extend the Termination Date of the loan as well as interest of $11,100 and to make monthly interest payments on the outstanding balance of the Well Works Loan through the Termination Date. Furthermore the Consulting Services Agreement term was extended through May 20, 2013.

On May 22, 2012, the Company paid Well Works $595,744 representing the outstanding principal balance and all interest and fees due in regards to the Well Works Loan that was executed on September 17, 2010, and the security interest granted by the Company in favor of Well Works in the Company's Kern County, California leases was terminated.

Short-Term (Related Party)

On June 20, 2011, the Company issued a $200,000 non-interest bearing promissory note to the Company’s President and Chief Executive Officer as consideration for a $200,000 loan made by him to the Company.  The term of the note provided for repayment on or before June 30, 2011, or such other date as may be agreed to by the Company and its President.  The Company and its President have agreed that repayment will be made upon the successful completion of long-term financing.  Proceeds from the note were used to meet the escrow requirement on a loan commitment from a third party that was announced in June 2011.  The escrow requirement amount is reflected as an account receivable on the Balance Sheet and will be refunded to the Company upon closing.  

On January 31, 2012, the Company issued a $35,100 non-interest bearing note to the Company’s President and Chief Executive Officer.  The term of the note provided for repayment on such other date as may be agreed to by the Company and its President.  The Company and its President have agreed that repayment will be made upon the successful completion of long-term financing.  Proceeds from the note were used to pay an extension fee related to the Well Works Loan.

Short-Term Note (Subsequent Event)

On May 18, 2012, the Company entered into a Loan Agreement (the “Loan”) with Luberski, Inc., a California corporation, as lender, and RTG Steel Company, LLC, an Arizona limited liability company, as co-borrower (“RTG”), pursuant to which the Company and RTG together borrowed a principal amount of $1,500,000. Daybreak received $719,061.97 and the remainder of the loan proceeds were paid to RTG. The Loan bears interest at a rate of 5% per month, has a term of 120 days, and may be prepaid at any time in part or in full without premium or penalty.  The Loan calls for a minimum interest payment of $150,000.00. The co-borrowers’ failure to repay the principal at maturity will constitute an event of default.  The Loan is a joint and several obligation of Daybreak and RTG, and is secured by the Company’s currently producing leases in Kern Country, California and certain personal property, accounts receivable and net profits of RTG as well as a personal unconditional guarantee of the Loan by RTG’s sole managing member.

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The Loan proceeds received by the Company were used to repay in full, effective May 22, 2012, all amounts outstanding and owed in regards to the Well Works Loan.  The security interest granted by Daybreak in favor of Well Works in the Company’s Kern County, California leases was terminated.

Line of Credit

During the year ended February 29, 2012 we negotiated an $890,000 credit line for working capital purposes with UBS Bank USA (“UBS”) established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer.  At February 29, 2012, we had an outstanding balance of $883,905 with an unused borrowing capacity of $6,095 on the line of credit.  Interest is 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.

Long-Term Borrowings

12% Subordinated Notes

On January 13, 2010, we commenced a private placement of 12% Subordinated Notes (“the Notes”).  On March 16, 2010, the Company closed its private placement of Notes to 13 accredited investors resulting in total gross proceeds of $595,000.  Interest on the Notes accrues at 12% per annum, payable semi-annually.  The note principal is payable in full at the expiration of the term of the Notes, which is January 29, 2015.  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, 2014.

In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.14 and expire on January 29, 2015.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $116,557 using the following weighted average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%.  The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method.  Amortization expense for the year ended February 29, 2012 amounted to $19,023.  Unamortized debt discount amounted to $80,083 as of February 29, 2012.

Proceeds from the Notes were used to meet operating expenses and fund a portion of our development drilling program in Kern County, California.  This offering of securities was made pursuant to a private placement held under Regulation D promulgated under the Securities Act of 1933, as amended.

Warrants Issued for Services

During the year ended February 28, 2011, a total of 150,000 warrants were issued to a consultant for services.  These warrants have an exercise price of $0.14 and expire on April 16, 2015.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $14,600 using the following assumptions: a risk free interest rate of 2.49%; volatility of 143.5%; and dividend yield of 0.0%.

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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.

During the year 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 our Common Stock to the five non-employee Directors as a part of our 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 our 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 year ended February 29, 2012, the number of common shares available for issuance under the Plan increased by 3,830 shares. This increase was attributable to the return 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.

At February 29, 2012, a total of 1,003,830 shares remained available for issuance pursuant to the 2009 Plan.

A summary of the 2009 Plan issuances is set forth in the table below:

Grant Date	Shares Awarded	Vesting Period	Shares Vested	Shares Returned	Shares Outstanding (Unvested)
4/7/2009	1,900,000	3 Years	1,266,665	-0-	633,335
7/16/2009	25,000	3 Years	16,665	-0-	8,335
7/16/2009	625,000	4 Years	312,500	1,915	312,500
7/22/2010	25,000	3 Years	8,330	-0-	16,670
7/22/2010	425,000	4 Years	106,250	1,915	318,750
	3,000,000		1,710,410	3,830	1,289,590

For the year ended February 29, 2012, we recognized compensation expense related to the above restricted stock grants of $91,219.  Unamortized compensation expense amounted to $42,054 as of February 29, 2012.

Oil Reserves

Daybreak’s total proved developed and undeveloped oil reserves decreased by 15,120 barrels, or 6.4% to 222,710 barrels for the year ended February 29, 2012 compared to 237,830 barrels of oil for the year ended February 28, 2011. Proved developed reserves decreased by 3,680 barrels, or 4.1%, to 85,160 barrels for the year ended February 29, 2012, compared to 88,840 barrels of oil for the year ended February 28, 2011. Production of 12,571 barrels was offset by an increase of 8,891 barrels in revisions of proved developed reserves.  Proved undeveloped reserves decreased by 11,440 barrels, or 7.7% to 137,550 barrels for the year ended February 29, 2012, compared to 148,990 barrels of oil for the year ended February 28, 2011. A farm-out of 50% of the Company’s leases in the Ball and Dyer Creek Fields resulted in a decrease of 14,565 barrels that was offset by an increase of 3,125 barrels in revisions primarily due to oil sales pricing.  Our reserves were fully engineered by Lonquist & Co. LLC (“Lonquist”) of Austin and Houston, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.

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Changes in Financial Condition

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 $73,392 and $57,380 as of February 29, 2012 and February 28, 2011, respectively.

Operating Expenses

Operating expenses decreased by $36,251 or 1.7% to $2,109,994 for the year ended February 29, 2012.  Exploration and drilling expenses and G&A expenses experienced a combined reduction of $105,001 in aggregate.  This reduction was offset by an increase of $47,758 in production expenses for the year ended February 29, 2012.

Operating Loss

For the year ended February 29, 2012, we reported an operating loss of approximately $795,870 in comparison to an operating loss of approximately $1,066,749 for the year ended February 28, 2011.  This reduction in the operating loss of approximately $270,879 or 25.4% was achieved through increased revenues realized from higher oil sales prices and lowering overall operating expenses primarily G&A expenses.  The average price of oil increased by $29.56 or 39.4% to $104.54 per barrel for the year ended February 29, 2012.

Net Loss

Since entering the oil and gas exploration industry, we have incurred recurring losses with periodic negative cash flow and have depended on external financing and the sale of oil and gas assets to sustain our operations.  A net loss of $1,432,584 was reported for the year ended February 29, 2012 in comparison to a net loss of $1,215,747 for the year ended February 28, 2011.  The increase in net loss of $216,837 or 17.8% for the year ended February 29, 2012 was due to an increase of $475,226 in interest expense related to the Well Works Loan.

Selected Financial Information

During the year ended February 29, 2012, we received oil sales revenue from eleven wells in our East Slopes Project in Kern County, California. Our commitment to improving corporate profitability remains unchanged, and we were successful in reducing the operating loss for the year ended February 29, 2012 in comparison to the year ended February 28, 2011.  The decline in our operating loss for the year ended February 29, 2012 in comparison to the year ended February 28, 2011, is a result of both an increase in our oil sales revenue and a decrease in our overall expenses.  

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Our balance sheet at February 29, 2012 shows total assets of $3,155,469 comprised primarily of $73,392 in cash; accounts receivable (including oil sales, joint interest participants, production revenue and refunds) of $858,609; prepaid expenses $44,777; oil and gas properties (net of Depreciation, Depletion, Amortization (“DD&A”)) of $2,073,185 and Operator Bond of $105,506.  This compares with the February 28, 2011 total assets of $3,294,808 comprised of $57,380 in cash; accounts receivable of $772,647; prepaid expenses $69,876; oil and gas properties of $2,290,001 and Operator Bond of $104,904.  The net decrease in total assets of $139,339 or 4.2% is attributed to changes in oil and gas properties and associated DD&A account balances.

At February 29, 2012, total liabilities of $4,407,178 were comprised of accounts payable (including trade and related parties) of $2,160,618, short-term and long-term notes payable (including related parties) and accrued interest of $1,318,548; credit line of $883,905 and $44,107 in asset retirement obligation (“ARO”), as compared with the February 28, 2011 total liabilities of $3,204,768 comprised of $1,928,380 in accounts payable; $1,221,266 in notes payable and interest; and $55,122 in ARO.  The net increase in total liabilities of $1,202,410 or 37.5% is attributed primarily to the credit line balance of $883,905 and an increase in accounts payable of $232,238.   

Our Common Stock issued and outstanding decreased by 3,830 shares to 48,787,769 for the year ended February 29, 2012 in comparison to 47,791,599 for the year ended February 28, 2011. This decrease was due to shares being returned to the 2009 Employee Stock Plan.  Series A Convertible Preferred Stock issued and outstanding remained unchanged for the year ended February 29, 2012 compared to the year ended February 28, 2011.  

Accumulated Deficit

Our financial statements for the year ended February 29, 2012 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 also state that the Company has incurred significant operating losses that raise substantial doubt about our ability to continue as a going concern. The accompanying financial statements do not include any adjustments that might result from this uncertainty.  The increase of $1,432,584 or 6.4% in the accumulated deficit from $22,406,909 as of February 28, 2011, to $23,839,493 as of February 29, 2012 was due to the $1,432,584 net loss from continuing operations.  While the net operating loss for the year ended February 29, 2012 decreased by $270,879 or 25.4% to $795,870, the loss from continuing operations increased by $205,821 or 16.8% to $1,432,584 in comparison to the $1,226,763 loss from the year ended February 28, 2011 primarily due to interest expenses associated with the Well Works loan.  We expect to continue this trend of a decrease in the net operating loss in the current year because of increased oil sales revenue from more wells being in production.

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 eleven producing 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 net revenue interest in these producing wells is 29.85%. Our average working interest in 40.15% for these same wells.

We anticipate revenues will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project.  The Company plans to continue its development drilling program at a rate that is compatible with its cash flow and funding opportunities.

As a result of our successful drilling activity, we believe that our liquidity will continue to improve.  Our sources of funds in the past have included the debt or equity markets and, while the Company does have positive cash flow from its oil and 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

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.  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.  

Oil and Gas Properties

We use the successful efforts method of accounting for oil and gas property acquisition, exploration, development, and production activities.  Costs to acquire mineral interests in oil and 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 oil and gas properties that are individually significant are also periodically assessed for impairment of value.  An impairment loss for unproved oil and gas properties is recognized at the time of impairment by providing an impairment allowance.

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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 oil and gas properties are classified as long term other assets.

Revenue Recognition

We use the sales method to account for sales of crude oil and natural gas.  Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers.  The volumes sold may differ from the volumes to which we are entitled based on our interests in the properties. These differences create imbalances, which are recognized as a liability only when the imbalance exceeds the estimate of remaining reserves.  We had no significant imbalances as of February 29, 2012 and February 28, 2011.

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 29, 2012, 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, Washington

We have audited the accompanying balance sheets of Daybreak Oil and Gas, Inc. as of February 29, 2012 and February 28, 2011 and the related statements of operations, stockholders’ equity (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 Daybreak Oil and Gas, Inc. as of February 29, 2012  and February 28, 2011 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 Daybreak Oil and Gas, Inc. will continue as a going concern.  As discussed in Note 2 to the financial statements, Daybreak Oil and Gas, Inc. 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 25, 2012

46

DAYBREAK OIL AND GAS, INC.
Balance Sheets
As of February 29, 2012 and February 28, 2011
	February 29,		February 28,
	2012		2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	73,392	$	57,380
Accounts receivable:
Oil and gas sales		192,639		185,836
Joint interest participants, net of allowance for doubtful accounts of $ -0- and $33,346 respectively		92,220		139,234
Loan commitment refund and other receivables		223,750		97,577
Prepaid expenses and other current assets		44,777		69,876
Total current assets		626,778		549,903
OIL AND GAS PROPERTIES, net of accumulated depletion, amortization, and impairment, net of $1,186,212 and $871,658 respectively, successful efforts method
Proved properties		1,634,545		1,837,431
Unproved properties		438,640		452,570
VEHICLES AND EQUIPMENT, net of accumulated depreciation of $31,329		-		-
PRODUCTION REVENUE RECEIVABLE		350,000		350,000
OTHER ASSETS		105,506		104,904
Total assets	$	3,155,469	$	3,294,808
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,663,303	$	1,772,010
Accounts payable - related parties		497,315		156,370
Accrued interest		418,531		5,477
Notes payable, net of discount of $ -0- and $30,105 respectively		150,000		719,895
Notes payable - related party		235,100		-
Line of credit		883,905		-
Total current liabilities		3,848,154		2,653,752
LONG TERM LIABILITIES:
Notes payable, net of discount of $46,149 and $57,119 respectively		298,851		287,881
Notes payable - related parties, net of discount of $33,934 and $41,987 respectively		216,066		208,013
Asset retirement obligation		44,107		55,122
Total liabilities		4,407,178		3,204,768
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY (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; 906,565 shares issued and outstanding		907		907
Common stock- 200,000,000 shares authorized; $0.001 par value, 48,787,769 and 48,791,599 shares issued and outstanding respectively		48,788		48,792
Additional paid-in capital		22,538,089		22,447,250
Accumulated deficit		(23,839,493)		(22,406,909)
Total stockholders’ equity		(1,251,709)		90,040
Total liabilities and stockholders' equity (deficit)	$	3,155,469	$	3,294,808

The accompanying notes are an integral part of these financial statements.

47

DAYBREAK OIL AND GAS, INC.
Statements of Operations
For the Years Ended February 29, 2012 and February 28, 2011
	Years Ended
	February 29, 2012		February 28, 2011
REVENUE:
Oil and gas sales	$	1,314,124	$	1,079,496
OPERATING EXPENSES:
Production costs		220,008		172,250
Exploration and drilling		168,177		184,255
Depreciation, depletion, amortization, and impairment		319,905		307,023
Gain on write-off of asset retirement obligation		-		(8,324)
Bad debt expense (recovery)		(4,142)		(3,928)
General and administrative		1,406,046		1,494,969
Total operating expenses		2,109,994		2,146,245
OPERATING LOSS		(795,870)		(1,066,749)
OTHER INCOME (EXPENSE):
Interest income		652		2,126
Interest expense		(637,366)		(162,140)
Total other income (expense)		(636,714)		(160,014)
LOSS FROM CONTINUING OPERATIONS		(1,432,584)		(1,226,763)
DISCONTINUED OPERATIONS
Income from discontinued operations  (net of tax of $ -0-)		-		731
Gain from sale of oil and gas properties  (net of tax of $ -0-)		-		10,285
INCOME FROM DISCONTINUED OPERATIONS		-		11,016
NET LOSS		(1,432,584)		(1,215,747)
Cumulative convertible preferred stock dividend requirement		(163,624)		(173,707)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(1,596,208)	$	(1,389,454)
NET LOSS PER COMMON SHARE
Loss from continuing operations	$	(0.03)	$	(0.03)
Income from discontinued operations		0.00		0.00
NET LOSS PER COMMON SHARE - Basic   and diluted	$	(0.03)	$	(0.03)
WEIGHTED AVERAGE NUMBER OF  COMMON SHARES OUTSTANDING -
Basic and diluted		48,789,641		48,300,733

The accompanying notes are an integral part of these financial statements.

48

DAYBREAK OIL AND GAS, INC.
Statements of Changes in Stockholders' Equity (Deficit)
For the Years Ended February 29, 2012 and February 28,  2011
	Series A Convertible						Additional
	Preferred Stock			Common Stock			Paid-In		Accumulated
	Shares	Amount		Shares	Amount		Capital		Deficit		Total
BALANCE, FEBRUARY 28, 2010	1,008,565		1,009	47,785,599		47,786		22,255,802		(21,191,162)		1,113,435
Issuance of common stock for:
Company stock plan	-		-	450,000		450		88,058		-		88,508
Conversion of preferred stock	(102,000)		(102)	306,000		306		(204)		-		-
Loan origination fees	-		-	250,000		250		23,500		-		23,750
												-
Debt discount on short term notes payable	-		-	-		-		65,494		-		65,494
												-
Warrants issued in connection with fund raising	-		-	-		-		14,600		-		14,600
												-
Net loss	-		-	-		-		-		(1,215,747)		(1,215,747)
BALANCE, FEBRUARY 28, 2011	906,565		907	48,791,599		48,792		22,447,250		(22,406,909)		90,040
Issuance of common stock for:
Company stock plan	-		-	-		-		91,218		-		91,218
Cancellation of stock plan issuances	-		-	(3,830)		(4)		(379)		-		(383)
												-
Net loss	-		-	-		-		-		(1,432,584)		(1,432,584)
BALANCE, FEBRUARY 29, 2012	906,565	$	907	48,787,769	$	48,788	$	22,538,089	$	(23,839,493)	$	(1,251,709)

The accompanying notes are an integral part of these financial statements.

49

DAYBREAK OIL AND GAS, INC.
Statements of Cash Flows
For the Years Ended February 29, 2012 and February 28, 2011
	Years Ended
	February 29, 2012		February 28, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,432,584)	$	(1,215,747)
Adjustments to reconcile net loss to net cash used in operating activities:
Stock compensation		91,218		88,508
Gain on write-off of asset retirement obligation		-		(8,324)
Gain on sale of oil and gas properties		-		(10,285)
Depreciation, depletion, and impairment expense		319,905		307,023
Amortization of debt discount		49,128		46,339
Amortization of loan origination fees		11,875		11,875
Bad debt expense (recovery)		(4,142)		(3,928)
Non cash interest income		(602)		(2,124)
Warrant expense for services		-		14,600
Changes in assets and liabilities:
Accounts receivable - oil and gas sales		(6,803)		71,274
Accounts receivable - joint interest participants		51,156		56,025
Accounts receivable - other		73,444		(91,632)
Receivables associated with assets held for sale		-		303,097
Prepaid expenses and other current assets		38,224		(36,266)
Accounts payable and other accrued liabilities		8,577		529,697
Accounts payable - related parties		340,945		124,472
Accrued interest		421,959		69
Net cash provided by (used in) operating activities		(37,700)		184,673
CASH FLOWS FROM INVESTING ACTIVITIES:
Disposition of other assets		-		299,428
Additions to oil and gas properties		(231,388)		(1,454,672)
Net cash used in investing activities		(231,388)		(1,155,244)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable - related parties		235,100		-
Proceeds from credit line		250,000		-
Payment to escrow for loan commitment		(200,000)		-
Proceeds from notes payable		-		780,000
Net cash provided by financing activities		285,100		780,000
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		16,012		(190,571)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		57,380		247,951
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	73,392	$	57,380
CASH PAID FOR:
Interest	$	107,684	$	141,357
Income taxes	$	-	$	-
SUPPLEMENTAL CASH FLOW INFORMATION:
Notes payable paid directly from proceeds of line of credit	$	600,000	$	-
Travel advances paid directly from proceeds of line of credit	$	25,000	$	-
Accrued interest added to note principal	$	8,905	$	-
Unpaid additions to oil and gas properties	$	62,839	$	271,979
Changes in estimates to asset retirement obligation, net	$	16,366	$	14,561
Discount on notes payable - Long term	$	19,023	$	5,284
Discount on notes payable - Short term	$	-	$	60,210
Conversion of preferred stock to common stock	$	-	$	306
Stock issued for loan origination fees	$	-	$	23,750
Cancellation of stock plan issuances	$	383	$	-

The accompanying notes are an integral part of these financial statements.

50

NOTE 1 — ORGANIZATION:

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 oil and gas exploration and production industry.  On October 25, 2005, the 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 oil and 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, 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 oil and 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.

NOTE 2 — GOING CONCERN:

Financial Condition

Daybreak’s financial statements for the year ended February 29, 2012 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 $23,839,493 and a working capital deficit of $3,221,376, 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 eleven producing 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 40.15% and the average net revenue interest is 29.85% for these same wells.  

The Company anticipates revenues will continue to increase as it participates in the drilling of more wells in California.  Daybreak plans to continue its development drilling program at a rate that is compatible with its cash flow and funding opportunities.  

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company has experienced revenue growth from its oil and 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 29, 2012 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.

51

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 routinely maintains balances in financial institutions where deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”). As of February 29, 2012, the Company had no cash deposits in excess of FDIC insured limits at various financial institutions.

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.  As of February 29, 2012 and February 28, 2011 the Company has recognized an allowance for doubtful accounts of $-0- and $33,346, respectively.

Oil and Gas Properties

The Company uses the successful efforts method of accounting for oil and gas property acquisition, exploration, development, and production activities.  Costs to acquire mineral interests in oil and 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 B Codification (“ASC”) Topic 360, “Property, Plant and Equipment” the Company reviews 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. 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 oil and gas.  Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s oil and gas properties in subsequent periods.  Unproved oil and gas properties that are individually significant are also periodically assessed for impairment of value. An impairment loss for unproved oil and gas properties is recognized at the time of impairment by providing an impairment allowance.

There were no asset impairments recorded for the years ended February 29, 2012 and February 28, 2011.

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.

52

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 is 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 approximate 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 (“Warrants”) on the grant date using an option-pricing model. The Company uses 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 and natural gas sales or joint interest billings to its working interest partners.  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.  Accounts receivable are generally not collateralized.  Allowances for doubtful accounts at February 29, 2012 and February 28, 2011 of $-0- and $33,346, respectively relate to amounts due from joint interest owners.  

53

At the Company’s Kern County, California project, there is only one buyer for the purchase of oil production.  At February 29, 2012, one customer represented 100.0% of crude oil sales receivable.  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 oil and gas production.   

The revenue from all customers is set forth in the table below.

		Twelve Months Ended February 29, 2012			Twelve Months Ended February 28, 2011
Project	Customer	Revenue		Percentage	Revenue		Percentage
California - East Slopes Project	Plains Marketing	$	1,314,124	100.0%	$	975,479	90.4%
Louisiana - Krotz Springs**	J.P. Van Way		-	-		104,017	9.6%
Total Revenues		$	1,314,124	100.0%	$	1,079,496	100.0%

**During the year ended February 28, 2011, the Company received approximately $104,017 in revenue related to the Krotz Springs Field in Louisiana as a one-time adjustment to gas revenue earned in calendar years 2007, 2008 and 2009 due to well production revenue misallocation by the unitized field operator.

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 oil and 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.  The Company had no significant imbalances as of February 29, 2012 and February 28, 2011.

Reclamation Bonds

Included in other assets as of February 29, 2012, are funds which 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.

Asset Retirement Obligation

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.

54

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

On March 1, 2007, the Company adopted 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 oil and gas properties to determine the amount of any impairment of oil and 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 has had, or is 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.

55

NOTE 4 — ACCOUNTS RECEIVABLE:

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

Oil and gas sales receivables balances at February 29, 2012 and February 28, 2011 represent oil sales that occurred during the months of February 2012 and 2011, respectively.

Joint interest participant receivables balances at February 29, 2012 and February 28, 2011 represent amounts due from working interest partners net of an allowance for doubtful accounts of $-0- and $33,346, respectively.

Production revenue receivable balance of $350,000 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.    

The refund and other receivables balance of $223,750 is primarily comprised of a loan commitment refund for future funding and receivables from contract consulting operations.    

NOTE 5 — OIL AND GAS PROPERTIES:

On March 19, 2010, the Company closed on the sale of its interest in the East Gilbertown Field in Choctaw County, Alabama to a third party with an effective date of March 1, 2010.  There was no effect on net oil and gas property balances from the sale of this property since the Company had previously fully impaired its capitalized cost of approximately $257,000 in this property due to low oil prices in prior periods.  In connection with the sale, the Company recognized a gain from sale of oil and gas properties for the year ended February 28, 2011 of $10,285 which is presented under “Discontinued Operations” in the Statement of Operations.  The gain resulted mainly from the extinguishment of certain liabilities associated with the Gilbertown interest.

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest from another working interest owner in the East Slopes Project.  This purchase resulted in an increase to the gross balances of proved oil and gas properties of approximately $61,869 and unproved oil and gas properties of approximately $421,464.

Oil and gas property balances at February 29, 2012 and February 28, 2011 are set forth in the table below:

	February 29, 2012		February 28, 2011
Proved leasehold costs	$	2,254	$	8,975
Unproved leasehold costs		438,640		452,570
Costs of wells and development		470,653		422,694
Capitalized exploratory well costs		2,316,305		2,229,511
Capitalized asset retirement costs		31,545		47,909
Total cost of oil and gas properties		3,259,397		3,161,659
Accumulated depletion, depreciation amortization and impairment		(1,186,212)		(871,658)
Oil and gas properties, net	$	2,073,185	$	2,290,001

Asset Retirement Obligation

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 oil and gas properties by calculating the present value of estimated cash flows related to the liability.  As of February 29, 2012 and February 28, 2011, ARO obligations were considered to be long term based on the estimated timing of the anticipated cash flows.  For the years ended February 29, 2012 and February 28, 2011, the Company recognized accretion expense of $5,351 and $5,519, respectively, which is included in DD&A in the statement of operations.  

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Changes in the asset retirement obligations for the year ended February 29, 2012 are set forth in the table below..

Asset retirement obligation, beginning of period	$	55,122
Accretion expense		5,351
Change in asset retirement estimates		(16,366)
Asset retirement obligation, end of period	$	44,107

NOTE 6 — 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 $285,343 of the $1.5 million default remains unpaid and is included in the February 29, 2012 accounts payable balance.

NOTE 7 — LINE OF CREDIT:

The Company has an $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 President and Chief Executive Officer.  At February 29, 2012, the Company had an outstanding balance of $883,905 with an unused borrowing capacity of $6,095 on the line of credit.  Interest is 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.

NOTE 8 — SHORT-TERM AND LONG-TERM BORROWING:

Short-Term Notes Payable

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest in its East Slopes Project from another working interest owner.  The Company financed the additional working interest purchase by issuing, to a third party, Well Works, LLC (“Well Works”), a one-year convertible secured promissory note for the principal amount of $750,000 (the “Well Works Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing.  Interest expense related to the Well Works Loan for the year ended February 29, 2012 was $37,500.  The interest expense was fully amortized at February 29, 2012.  The Company paid in full all amounts due and payable under the Well Work Loan on May 22, 2012.  

The Well Works Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in the Company’s East Slopes Project.  Furthermore, as a condition precedent to the Well Works Loan, the Company entered into a Technical and Consulting Services Agreement dated September 17, 2010 (the “Consulting Services Agreement”) with Well Works, whereby Daybreak would provide operating, engineering and technical consulting to Well Works for a one-year period for the purpose of evaluating 22 wells in Hutchinson County, Texas for Well Works.  

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The Company also issued 250,000 shares of the Company’s Common Stock to Well Works as a loan origination fee.  The fair value of these shares amounted to $23,750 which was deferred and fully amortized over the original term of the Well Works Loan.  Amortization expense for the year ended February 29, 2012 amounted to $11,875.  The loan origination fees were fully amortized as of February 29, 2012.

As additional consideration for the Well Works Loan, the Company executed an Assignment of Net Profits Interest dated September 17, 2010 (the “Assignment of Net Profits Interest”) in favor of Well Works, whereby Daybreak assigned two percent of the net profits realized by the Company on its leases in the East Slopes Project.  The fair value of the two percent net profits interest was determined to be $60,210 and was recognized as a discount to the debt.  The debt discount was deferred and fully amortized over the original term of the Well Works Loan.  Amortization expense for the year ended February 29, 2012 amounted to $30,105.  The debt discount was fully amortized as of February 29, 2012.

The Company analyzed the Well Works Loan for derivative accounting consideration and determined that derivative accounting did not apply to this instrument.

A Loan Extension Agreement (the “Loan Extension Agreement”) between Well Works and the Company was executed on September 19, 2011 extending the Well Works Loan for a period of 30 days.  As compensation for the extension, Daybreak agreed to pay a fee to Well Works of $50,000 and pay interest and legal fees of $16,105 in aggregate.  

On October 24, 2011, Well Works and the Company executed a Forbearance Agreement whereby Daybreak requested that Well Works forbear from exercising its rights and remedies under the Well Works Loan and the Loan Extension Agreement from October 19, 2011 to November 10, 2011 (the “Forbearance Period”).  The Company agreed to pay interest and legal fees of $21,253 in aggregate during the Forbearance Period.  In addition, Daybreak assigned to Well Works a 3% overriding royalty interest proportionately reduced to the Company’s working interest in all its leases in the East Slopes Project effective November 1, 2011.  Furthermore, Daybreak and Well Works agreed to cancel, in its entirety, the Assignment of Net Profits Interest.  Finally, the Consulting Services Agreement was extended until November 10, 2012.

On November 11, 2011, Well Works and the Company executed a new Forbearance Agreement further extending the date of the payoff from November 11, 2011 to November 18, 2011.  As compensation for the extension, Daybreak agreed to pay a fee of $12,500 plus interest due of $3,353 on the entire outstanding balance of the Well Works Loan from November 11, 2011 to November 18, 2011 at an 18% per annum default interest rate.

On November 18, 2011, the Company made a payment to Well Works of $600,000 thereby reducing the outstanding principal balance owed on the Well Works Loan and associated loan interest and fees to $253,581.

On November 19, 2011 Well Works and the Company executed a new Forbearance Agreement (the “Forbearance Agreement II”) further extending the date of the payoff from November 18, 2011 to December 20, 2011 (the “Termination Date”).  Daybreak agreed to pay an extension fee of 20% on the outstanding balance of the Well Works Loan, associated fees and interest as of November 19, 2011, or $50,716 plus legal fees of $4,000.  Furthermore, interest is payable on the entire outstanding balance of $308,297 for the 30-day period at the default interest rate of 18% per annum, resulting in additional interest of $4,561 for a total balance of $312,858 due on or before the Termination Date.

If the Company is unable to pay on or before the Termination Date all amounts owed under the Forbearance Agreement II, there shall be an additional late fee of $250,000 and an increase in the default interest rate from 18% per annum to 24% per annum (2% per month) until all amounts are repaid.  Since the Company was not able to repay the loan by the Termination Date, the Company recognized a late fee of $250,000 which is included in accrued interest as of February 29, 2012.

The Company and Well Works further agreed that the term of the Consulting Services Agreement be extended until December 20, 2012.

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On January 30, 2012, the Company and Well Works executed Forbearance Agreement III extending the Termination Date of the Well Works loan to May 20, 2012.  Along with the late fee of $250,000 under the Forbearance Agreement II, Daybreak agreed to pay a fee of $25,000 to extend the Termination Date of the loan as well as interest of $11,100 and to make monthly interest payments on the outstanding balance of the Well Works Loan through the Termination Date.  Furthermore it was agreed that the Consulting Services Agreement term be extended through May 20, 2013.

At February 29, 2012 the outstanding principal balance of the Well Works Loan was $150,000.

On May 22, 2012, the Company paid off the outstanding principal balance and all interest and fees related to the Well Works Loan.  In connection with the Well Works Payoff, the security interest granted by the Company in favor of Well Works in the Company's Kern County, California leases was terminated.

Short-Term Notes Payable (Related Party)

On June 20, 2011, the Company issued a $200,000 non-interest bearing note to the Company’s President and Chief Executive Officer.  The term of the note provided for repayment on or before June 30, 2011, or such other date as may be agreed to by the Company and its President.  The Company and its President have agreed that repayment will be made upon the successful completion of long-term financing.

Proceeds from the note were used to meet the escrow requirement on a loan commitment from a third party that was announced in June 2011.  The escrow requirement amount is reflected as an account receivable on the Balance Sheet and will be refunded to the Company upon closing.

On January 31, 2012, the Company issued a $35,100 non-interest bearing note to the Company’s President and Chief Executive Officer.  The term of the note provided for repayment on such other date as may be agreed to by the Company and its President.  The Company and its President have agreed that repayment will be made upon the successful completion of long-term financing.  Proceeds from the note were used to pay an extension fee related to the Well Works Loan.

Long-Term Notes Payable

12% Subordinated Notes

On January 13, 2010 the Company commenced a private placement of 12% Subordinated Notes (“Notes”).  On March 16, 2010, the Company closed its private placement of Notes to 13 accredited investors resulting in total gross proceeds of $595,000.  Interest on the Notes accrues at 12% per annum, payable semi-annually.  The note principal is payable in full at the expiration of the term of the Notes, which is January 29, 2015.  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, 2014.  A total of $250,000 in Notes was sold to a related party, the Company’s President and Chief Executive Officer.  The terms and conditions of the related party Note were identical to the terms and conditions of the other participants’ Notes.   

In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at the rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.14 and expire on January 29, 2015. The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $116,557 using the following weighted-average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%. The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method.  Amortization expense for the year ended February 29, 2012 amounted to $19,023.  Unamortized debt discount amounted to $80,083 as of February 29, 2012.

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The Company analyzed the Notes and warrants for derivative accounting consideration and determined that derivative accounting does not apply to these instruments.

NOTE 9 — STOCKHOLDERS’ EQUITY (DEFICIT):

Series A Convertible Preferred Stock

The Company is authorized to issue up to 10,000,000 shares of $0.001 par value preferred stock.  The Company has designated 2,400,000 shares of the 10,000,000 total preferred shares as “Series A Convertible Preferred Stock” (“Series A Preferred”), with a $0.001 par value.  The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s Common Stock.

At February 29, 2012, there were 906,565 shares issued and outstanding, held by accredited investors that had not been converted into the Company’s Common Stock.  During the year ended February 29, 2012, there were no shares of Series A Preferred that were converted to shares of Common Stock.  As of February 29, 2012, there have been 30 accredited investors convert 493,200 Series A Preferred shares into 1,479,600 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	-	-	-
Totals	493,200	1,479,600	30

Holders of Series A Preferred earn a dividend, in the amount of 6% of the original purchase price per year.  Accumulated dividends do not bear interest; and as of February 29, 2012 dividends amounted to $1,134,714.  Dividends can be paid in cash or stock at the discretion of the Company and are payable upon declaration by the Board of Directors.  Dividends are earned until the Series A Preferred is converted to Common Stock. No dividends have been declared as of February 29, 2012.    

Cumulative dividends earned for each fiscal year since issuance is set forth in the table below.

	Shareholders	Accumulated
Fiscal Year Ended	at Period End	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
		$	1,134,714

Common Stock

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock of which 48,787,769 shares were issued and outstanding as of February 29, 2012. For the year ended February 29, 2012 there were no shares issued.

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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 11 for the issuances made under the 2009 Plan.  

NOTE 10 – WARRANTS:

Common Stock warrants outstanding and exercisable as of February 29, 2012 are set forth in the table below:

Description	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining
Placement Agent Warrants - Spring 2006 PP	802,721	$0.75	1.25	802,721
Placement Agent Warrants - Spring 2006 PP	401,361	$2.00	1.25	401,361
Placement Agent Warrants - July 2006 PP	419,930	$1.00	1.50	419,930
12% Subordinated Note Warrants	1,190,000	$0.14	2.75	1,190,000
Warrants Issued for Services	150,000	$0.14	3.25	150,000
	2,964,012			2,964,012

For the year ended February 29, 2012, a total of 6,963,133 warrants expired.  These warrants were issued to private placement subscribers of our Common Stock and Series A Preferred Stock that occurred in the Spring of 2006 and July 2006, respectively. There were no warrants issued or exercised during the year ended February 29, 2012.

As of February 29, 2012 and February 28, 2011, there were 2,964,012 and 9,927,145 warrants issued and outstanding, respectively.

The outstanding warrants as of February 29, 2012, have a weighted average exercise price of $0.68; a weighted average remaining life of 1.99 years; and an intrinsic value of $-0-.

NOTE 11 — 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 year 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.  

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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 year ended February 29, 2012, an aggregate of 912,499 shares vested and 3,830 shares were cancelled and returned to the 2009 Plan

At February 29, 2012, a total of 1,003,830 shares remained available for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan issuances is set forth in the table below:

Grant Date	Shares Awarded	Vesting Period	Shares Vested	Shares Returned	Shares Outstanding (Unvested)
4/7/2009	1,900,000	3 Years	1,266,665	-0-	633,335
7/16/2009	25,000	3 Years	16,665	-0-	8,335
7/16/2009	625,000	4 Years	312,500	1,915	312,500
7/22/2010	25,000	3 Years	8,330	-0-	16,670
7/22/2010	425,000	4 Years	106,250	1,915	318,750
	3,000,000		1,710,410	3,830	1,289,590

For the year ended February 29, 2012, the Company recognized compensation expense related to the above restricted stock grants of $91,218.  Unamortized compensation expense amounted to $42,054 as of February 29, 2012.

NOTE 12 — 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 29, 2012		February 28, 2011
Computed at U.S. and state statutory rates (40%)	$	(573,035)	$	(486,300)
Permanent differences		37,325		14,731
Changes in valuation allowance		535,710		471,569
Total	$	-0-	$	-0-

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

	February 29, 2012		February 28, 2011
Deferred tax assets:
Net operating loss carryforwards	$	6,319,866	$	5,900,491
Oil and gas properties		(147,148)		(226,994)
Stock based compensation		71,891		35,403
Less valuation allowance		(6,244,609)		(5,708,900)
Total	$	-0-	$	-0-

At February 29, 2012, the Company had a net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $15,799,666, which will begin to expire, if unused, beginning in 2024.  The valuation allowance increased by approximately $535,709 for the year ended February 28, 2012 and increased $471,569 for the year ended February 28, 2011.  Section 382 Rule of the Internal Revenue Code will place annual limitations on the Company’s NOL carryforward.

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The above estimates are based upon management’s decisions concerning certain elections which could change the relationship between net income and taxable income.  Management decisions are made annually and could cause the estimates to vary significantly.

NOTE 13 — 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 clean-up 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 29, 2012.  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 14 — SUBSEQUENT EVENTS:

On May 18, 2012, the Company entered into a loan agreement with a third party as lender and another party as co-borrower, pursuant to which the Company and the co-borrower together borrowed a principal amount of $1,500,000.  The Company received $719,062 and the remainder of the loan proceeds were paid to the co-borrower. The loan bears interest at a rate of 5% per month, has a term of 120 days, and may be prepaid at any time in part or in full without premium or penalty.  The loan calls for a minimum interest payment of $150,000.  Either borrowers’ failure to repay the principal at maturity will constitute an event of default.  The loan is a joint and several obligation of the Company and the co-borrower, and is secured by the Company’s currently producing leases in Kern Country, California and certain personal property, accounts receivable and net profits of the co-borrower as well as a personal unconditional guarantee of the loan by the co-borrower’s sole managing member.

On May 22, 2012 the Company paid Well Works $595,744 representing the outstanding principal balance and all interest and fees due in regards to the Well Works Loan that was executed on September 17, 2010.  The security interest granted by Daybreak in favor of Well Works in the Company’s Kern County, California leases was terminated.

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NOTE 15 — SUPPLEMENTARY INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

All of the Company’s continuing operations are directly related to oil and natural gas producing activities located in California.

Capitalized Costs Relating to Oil and Gas Producing Activities

	As of February 29, 2012		As of February 28, 2011
Proved leasehold costs
Mineral Interests	$	2,254	$	2,254
Wells, equipment and facilities		2,818,503		2,706,835
Total Proved Properties		2,820,757		2,709,089
Unproved properties
Mineral Interests		431,895		431,895
Uncompleted wells, equipment and facilities		6,745		20,675
Total unproved properties		438,640		452,570
Less accumulated depreciation, depletion amortization and impairment		(1,186,212)		(871,658)
Net capitalized costs	$	2,073,185	$	2,290,001

Costs Incurred in Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	February 29, 2012		February 28, 2011
Acquisition of proved properties	$	-	$	1,128
Acquisition of unproved properties		6,745		431,337
Development costs		90,993		946,753
Exploration costs		168,177		184,255
Total costs incurred	$	259,915	$	1,563,473

Results of Operations from Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	February 29, 2012		February 28, 2011
Oil and gas revenues	$	1,314,124	$	1,079,496
Production costs		(220,008)		(172,250)
Exploration expenses		(168,177)		(184,255)
Depletion, depreciation, amortization and impairment		(319,905)		(307,023)
Result of oil and gas producing operations before income taxes		607,034		415,968
Provision for income taxes		-0-		-0-
Results of oil and gas producing activities	$	607,034	$	415,968

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Proved Reserves

The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, Lonquist & CO. 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)	BOE (Barrels)
Proved reserves:
February 28, 2010	62,155	62,155
Revisions(1)	24,890	24,890
Extensions and discoveries	145,648	145,648
Production	(13,009)	(13,009)
Purchases (sales) of minerals-in-place	18,146	18,146
February 28, 2011	237,830	237,830
Revisions(1)	12,016	12,016
Production	(12,571)	(12,571)
Purchases (sales) of minerals-in-place	(14,565)	(14,565)
February 29, 2012	222,710	222,710

(1)

The revisions of previous estimates resulted from a revised increased estimate of reserve value after continued reservoir production and increased hydrocarbon 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, 2010	38,648	38,648	23,507	23,507	62,155	62,155
February 28, 2011	88,840	88,840	148,990	148,990	237,830	237,830
February 29, 2012	85,160	85,160	137,550	137,550	222,710	222,710

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 29, 2012 and February 28, 2011 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 29, 2012 and February 28, 2011 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 29, 2012		February 28, 2011
Future cash inflows	$	23,248,780	$	18,138,730
Future production costs (1)		(7,802,160)		(6,896,130)
Future development costs		(1,431,250)		(1,667,310)
Future income tax expenses (2)		-		-
Future net cash flows		14,015,370		9,575,290
10% annual discount for estimated timing of cash flows		(6,757,920)		(4,215,510)
Standardized measure of discounted future net cash flows at the end of the fiscal year	$	7,257,450	$	5,359,780

(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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Average oil prices are set forth in the table below.

	Average Price
	Oil (Barrel)
Year ended February 29, 2012 (1)	$	104.39
Year ended February 28, 2011 (1)	$	76.27
Year ended February 28, 2010 (1)	$	58.86

(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 29, 2012		February 28, 2011
Standardized measure of discounted future net cash flows at the beginning of the year	$	5,359,780	$	1,975,928
Extensions, discoveries and improved recovery, less related costs		-		3,053,440
Revisions of previous quantity estimates		(82,670)		560,714
Purchase of minerals in place		-		513,643
Net changes in prices and production costs		2,644,294		(491,475)
Accretion of discount		535,978		197,593
Sales of oil produced, net of production costs		(1,094,116)		(802,245)
Development costs incurred during the period		238,760		597,796
Changes in future development costs		(1,493)		(256,408)
Changes in timing of future production		(343,083)		10,794
Net changes in income taxes		-		-
Standardized measure of discounted future net cash flows at the end of the year	$	7,257,450	$	5,359,780

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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 29, 2012, 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 29, 2012.  

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 29, 2012. 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 29, 2012.

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.

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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 29, 2012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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	77	2008
Dale B. Lavigne	81	1965
Ronald D. Lavigne	57	1999
Timothy R. Lindsey	60	2007
James F. Meara	59	2008
James F. Westmoreland	56	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.

Dale B. Lavigne is Chairman of the Board and has served as a director of the Company since 1965.  Mr. Lavigne served as the Company’s President from 1989 until December 2004.  For the past 53 years, Mr. Lavigne has been the Chairman and a director of the Osburn Drug Company, Inc., a four-store chain of retail pharmacies in North Idaho.  Mr. Lavigne is President and a director of Metropolitan Mines, Inc., a reporting publicly-held, inactive mineral exploration company.  Mr. Lavigne is the former Chairman of the First National Bank of North Idaho; a former member of the Gonzaga University Board of Regents; former President of the Silver Valley Economic Development Corporation and a former member of the Governor’s Task Force on Rural Idaho.  Mr. Lavigne is the father of Ronald D. Lavigne and the father-in-law of Thomas C. Kilbourne, our Controller and Assistant Corporate Secretary.  Mr. Lavigne graduated from the University of Montana with a Bachelor of Science degree in pharmacy.

Ronald D. Lavigne has served as a member of the Board of Directors since July 1999.  Mr. Lavigne is the President, Chief Executive Officer, and a director of the Lavigne Drug Group, where with his over 30 years of experience in the practice of pharmacy and various capacities in managing the day-to-day operations of the Lavigne Drug Group, he is also responsible for the implementation of all the inventory technology advancements of the business.  Mr. Lavigne also served as former President of the Idaho State Pharmaceutical Association, and currently serves on its Board of Directors.  He also managed several local hospital pharmacies as well as consulted with long-term care facilities.  Additionally, Mr. Lavigne is also a director of various other public non-reporting inactive mineral exploration companies.  He is the son of Dale B. Lavigne and the brother-in-law of Thomas C. Kilbourne, our Controller and Assistant Corporate Secretary.  Mr. Lavigne graduated from the University of Montana with a Bachelor of Science degree in pharmacy.

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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 thirty years of 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 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 serves as Chairman of the Board of Directors of Revett Minerals Inc., a publicly-listed Canadian company with mining activities in Montana.  He also formerly served as a director for Challenger Energy Corp., a Calgary-based oil and gas company and Rock Energy Resources, Inc., a Houston-based oil and gas company currently transforming to a mining company.  Mr. Lindsey is also the President and founder of Canadian Sahara Energy Inc., a private company.  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 and the Montana Mining Association; ;and, a Trustee for the Northwest 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.  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.

James F. Westmoreland was 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 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 oil and gas industry.  

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·

Mr. Dale Lavigne’s 50 plus years of serving as Chairman and a director of the Osburn Drug Company, Inc., which contributes to his financial knowledge, experience, management leadership, and risk assessment along with his years of service on many public and private company boards, was a particular focus of the Board.  Mr. Lavigne’s 47 year history with Daybreak, his knowledge, management and leadership expertise regarding the issues affecting the Company have been invaluable to the Board of Directors in overseeing the business affairs of our Company.  

·

Mr. Ronald Lavigne’s role as President, Chief Executive Officer and a director of the Lavigne Drug Group, as well as his service on boards of various public non-reporting inactive mineral exploration companies, along with his leadership and management expertise, provide a valuable service to Daybreak’s Board.  His 13 years of service on the Company’s Board and his in depth knowledge of the Company are also invaluable to the Board.  

·

Mr. Lindsey’s over 30 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 oil and gas industry provide the knowledge and financial expertise needed to serve on the Board and the Company’s audit committee.  

·

Mr. Westmoreland’s over 30 year career in various financial and accounting capacities, including Vice President, Chief Accounting Officer, Controller and Corporate Secretary at a public oil and 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.  

Family Relationships

Dale B. Lavigne and Ronald D. Lavigne are father and son.  Thomas C. Kilbourne, Controller and Assistant Corporate Secretary, is Dale B. Lavigne’s son-in-law and Ronald D. Lavigne’s brother-in-law.

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	56	2007	President and Chief Executive Officer
Bennett W. Anderson	51	2006	Chief Operating Officer

James F. Westmoreland was 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 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.

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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

As of the date hereof, it is the opinion of management that there is no material proceeding to which any 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 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.

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 were timely filed during the fiscal year ended February 29, 2012.  

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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., 601 W. Main Avenue, Suite 1017, Spokane, Washington 99201.

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 29, 2012, the Audit Committee met seven 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., 601 W. Main Avenue, Suite 1017, Spokane, Washington 99201.

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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, Dale B. Lavigne, Ronald D. Lavigne 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, NYSE AMEX 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 29, 2012, and our two most highly compensated executive officers other than the Chief Executive Officer during the fiscal year ended February 29, 2012.  For the fiscal year ended February 29, 2012, under the smaller reporting company rules, our named executive officers are: James F. Westmoreland, President and Chief Executive Officer; Robert N. Martin, Former Senior Vice President, Exploration; 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 29, 2012.

		Executive
Name	Age	Since	Office
James F. Westmoreland	56	2007	President and Chief Executive Officer
Robert N. Martin*	57	2004	Former Senior Vice President, Exploration
Bennett W. Anderson	51	2006	Chief Operating Officer

*Effective March 15, 2012, the Company eliminated the Company’s position of Senior Vice President, Exploration.  Robert N. Martin, the Company’s Senior Vice President, Exploration prior to such elimination, will continue to provide geological services to the Company as a consultant on an as needed basis.

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 29, 2012.  

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.

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

For the fiscal years ended February 29, 2012 and February 28, 2011, compensation to our Named Executive Officers consisted primarily of base salaries.  For the past three years, 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 78 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 29, 2012 and February 28, 2011.    

Name and Principal Position	Fiscal Year Ended	Salary ($)	Bonus ($)	Stock Awards ($)(1)	All Other Compensation ($)	Total ($)
James F. Westmoreland(2)	February 29, 2012	150,000(3)	-	-	-	150,000(3)
President and Chief Executive Officer	February 28, 2011	150,000(4)	-	-	-	150,000(4)
Robert N. Martin(5)	February 29, 2012	87,000(6)	-	-	-	87,000(6)
Former Senior Vice President, Exploration	February 28, 2011	87,000	-	-	-	87,000
Bennett W. Anderson	February 29, 2012	89,400	-	-	-	89,400
Chief Operating Officer	February 28, 2011	89,400	-	7,000(7)	-	96,400

⁽¹⁾

Amounts reflect the aggregate grant date fair value of stock awards computed in accordance with FASB ASC Topic 718, disregarding any estimates of forfeitures relating to service-based vesting.  The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to the FASB ASC Topic 718 determined value.  The fair value is calculated based on the closing price of our stock on the grant date.  For a discussion of valuation assumptions, see “Note 11 - RESTRICTED STOCK and RESTRICTED STOCK UNIT PLAN” of the Notes to Consolidated Financial Statements included in our annual report under Item 8 of this Form 10-K.

⁽²⁾

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.  

⁽³⁾

As a result of the Company’s limited available cash, Mr. Westmoreland postponed salary payment until long-term financing is in place.  For the year ended February 29, 2012, Mr. Westmoreland’s full salary of $150,000 was accrued, but not paid.  This liability is recorded on our balance sheet under accrued liabilities.  For the current fiscal year, Mr. Westmoreland’s salary is also being accrued and will not be paid until long-term financing is obtained.  

⁽⁴⁾

As a result of the Company’s limited available cash, Mr. Westmoreland postponed salary payment until long-term financing is obtained.  For the year ended February 28, 2011, Mr. Westmoreland’s salary consisted of $62,500 paid, and $87,500 accrued.  This liability is recorded on our balance sheet under accrued liabilities.  

⁽⁵⁾

Payments for Mr. Martin’s services, which are on a part-time basis, are paid directly to 413294 Alberta Ltd., a private Canadian consulting firm.Effective March 15, 2012, the Company eliminated the Company’s position of Senior Vice President, Exploration.  Robert N. Martin, the Company’s Senior Vice President, Exploration prior to such elimination, will continue to provide geological services to the Company as a consultant on an as needed basis.

⁽⁶⁾

As a result of the Company’s limited available cash, Mr. Martin deferred payment for his services during the second, third and fourth quarter of the fiscal year ended February 29, 2012.  For the year ended February 29, 2012, Mr. Martin’s was paid $21,750; and $65,250 was accrued, but not paid.  This liability is recorded on our balance sheet under accrued liabilities.  

⁽⁷⁾

The Compensation Committee awarded restricted shares to four Daybreak employees, including 100,000 restricted shares to Mr. Anderson.  On the grant date of July 22, 2010, the closing price of our stock was $0.07 per share.  The restricted shares were granted pursuant to the 2009 Plan and fully vest equally over a period of four years at a rate of 25% each year.  The 2009 Plan is described below under the heading “Equity Compensation Plan Information”.

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Narrative Disclosure to Summary Compensation Table

Base Salaries

For the past three years, 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.  The Board, with the assistance of the Compensation Committee, after reviewing the Company’s cost structure and financial position, approved a reduction of the base salaries of the Company’s Named Executive Officers.  Effective April 1, 2009, the salary of James F. Westmoreland, President and Chief Executive Officer, was reduced by 25% to $150,000.  The salaries of Robert N. Martin, Former Senior Vice President – Exploration, and Bennett W. Anderson, Chief Operating Officer, were reduced by 50% to $87,000 and $63,000, respectively.  Additionally, if Mr. Anderson works more than 11 days per month, he will earn an additional amount equal to $200 per day, with such additional amount being capped at $2,200 per month.

Equity Compensation Plan Information

Effective April 6, 2009, 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.   

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.  

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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 which 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 which 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 following table provides information regarding our outstanding restricted stock awards held by our Named Executive Officers at the end of the fiscal year ended February 29, 2012.  The Company has no qualified or nonqualified stock option plans and has no outstanding stock options.

	Stock Awards
Name and Principal Position	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)
James F. Westmoreland	166,667(1)	10,000(2)
President and Chief Executive Officer, former Executive Vice President and Chief Financial Officer
Robert Martin	-	-
Former Senior Vice President, Exploration
Bennett W. Anderson	75,000(3)	4,500(2)
Chief Operating Officer

⁽¹⁾

On April 6, 2009, the Compensation Committee approved an award to Mr. Westmoreland of 500,000 shares of restricted common stock of the Company, with a grant date of April 7, 2009, as further compensation for his past services, as discussed in detail under the heading “Narrative Disclosure to Summary Compensation Table - Base Salaries; Compensation for Past Services”, beginning on page 80.  These shares of restricted stock were awarded pursuant to the 2009 Plan and fully vest equally over a period of three years at a rate of 33 1/3%.  In accordance with the award, on April 7, 2010, 166,666 shares were vested; and 166,667 shares were vested in 2011.  The remaining 166,667 restricted shares were subject to restrictions that expired in April 2012.  

⁽²⁾

Amount reflects the aggregate value of the shares that have not vested using the closing market price of the Company's stock at the end of the last completed fiscal year.  On February 29, 2012, the closing price of our stock was $0.06.

⁽³⁾

The Compensation Committee has awarded restricted shares to four Daybreak employees, including 100,000 restricted shares to Mr. Anderson.  On the grant date of July 22, 2010, the closing price of our stock was $0.07 per share.  The restricted shares were granted pursuant to the 2009 Plan and fully vest equally over a period of four years at a rate of 25% each year.  In accordance with the award, on July 22, 2011, 25,000 shares were vested.  The remaining 75,000 restricted shares are subject to restrictions that expire as follows: 25,000 in 2012; 25,000 in 2013 and 25,000 in 2014.  The 2009 Plan is described under the heading “Equity Compensation Plan Information” beginning on page 78.  

Compensation for Past Services

On October 20, 2008, the Board appointed James F. Westmoreland to the position of President and Chief Executive Officer of the Company.  Mr. Westmoreland stepped down from his role as Executive Vice President and Chief Financial Officer of the Company, but continues to serve as the interim principal finance and accounting officer of the Company.  In connection with Mr. Westmoreland’s appointment as President and Chief Executive Officer, the Compensation Committee approved an annual salary payable to him of $200,000, retroactive to October 1, 2008.  As Mr. Westmoreland previously served as an officer of the Company without compensation, the Compensation Committee also awarded a cash bonus of $150,000 to Mr. Westmoreland in recognition of his past services.  As further compensation for his services during the fiscal year ended February 28, 2009, the Compensation Committee agreed to award Mr. Westmoreland shares of common stock of the Company, in an amount to be determined.  Subsequently, on April 6, 2009, the Compensation Committee approved an award to Mr. Westmoreland of 500,000 shares of restricted common stock of the Company, with a grant date of April 7, 2009.  

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).

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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 29, 2012.

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.

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, effective as of April 6, 2009, non-employee directors 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 is typically 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 directors for the fiscal year ended February 29, 2012.  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.  

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On July 22, 2010, pursuant to our Director Compensation Policy, each non-employee director received 5,000 restricted shares, typically granted in conjunction with the Company’s Annual Meeting of Shareholders, and pursuant to the 2009 Plan.  On the grant date of July 22, 2010, the closing price of our stock was $0.07 per share.  The restricted shares were granted pursuant to the 2009 Plan 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 78 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 29, 2012.(1)

Name	Fees Earned or Paid in Cash(2) ($)	Stock Awards(3) ($)	All other compensation ($)	Total ($)
Wayne G. Dotson	20,000	-	-	20,000
Dale B. Lavigne	20,750	-	-	20,750
Ronald D. Lavigne	20,250	-	-	20,250
Timothy R. Lindsey	15,000	-	-	15,000
James F. Meara	21,500	-	-	21,500

⁽¹⁾

Mr. James F. Westmoreland did not receive any compensation for serving on the Board of Directors during the fiscal year ended February 29, 2012. 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 with the second quarter of the year ended February 28, 2011, postponed receiving payments of meeting fees and quarterly retainer fees until long-term financing is in place.  For the year ended February 29, 2012, director fees were accrued, but not paid.  For the current year, all fees are still currently being accrued and will not be paid until long-term financing is obtained.  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 29, 2012.  

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 29, 2012.  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	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	-	-	-
Equity compensation plans not approved by security holders(1)	2,996,170	$0.10	1,003,830(2)
Total	2,996,170	$0.10	1,003,830(2)

⁽¹⁾

On April 6, 2009, the Board of Directors approved the 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 78.

⁽²⁾

Reflects initial 4,000,000 shares in the 2009 Plan, reduced by (i) 900,000 shares of restricted stock awarded to the Company’s non-employee directors in recognition of their leadership and contribution during the restructuring and transformation of the Company during the fiscal year ended February 28, 2009, (ii) 1,000,000 shares of restricted stock awarded to our current President and Chief Executive Officer and our former interim President and Chief Executive Officer in recognition of past service as executive officers (iii) 425,000 and 625,000 shares of restricted stock awarded to employees during the fiscal years ended February 28, 2011 and 2010 respectively; and (iv) 25,000 shares of restricted stock awarded to non-employee directors in accordance with the director compensation policy for the fiscal years ended February 28, 2011 and 2010 respectively, as described in detail under the heading “Director Compensation”, beginning on page 81.  Also reflects 3,830 shares that were returned to the 2009 Plan.

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Security Ownership of Certain Beneficial Owners and Management

Our largest principal beneficial shareholder, and eight directors and officers of the Company, together own and control about 19% 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.

As of May 22, 2012, 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 77; 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	Keith A. Hooper(5)  1529 W. Adams St.  Chicago, IL  60607	3,176,077	-	3,176,077	6.5
	Dale B. Lavigne, Chairman of the Board	1,032,555(6)	-	1,032,555	2.1
	Timothy R. Lindsey,  Director	910,000(7)	-	910,000	1.9
	Ronald D. Lavigne,  Director	855,414(6)	-	855,414	1.8
	Wayne G. Dotson,  Director	160,000(8)	-	160,000	*
	James F. Meara,  Director	160,000(8)	-	160,000	*
	Robert Martin, Former Senior Vice President, Exploration	1,380,000(9)	-	1,380,000	2.8
	James F. Westmoreland, President and Chief Executive Officer and Director	600,000(10)	500,000(11)	1,100,000	2.2
	Bennett W. Anderson, Chief Operating Officer	400,000(12)	-	400,000	*
	All (8) directors and executive officers as a group	5,497,969	-	5,997,969	12.2
Series A Convertible Preferred Stock(13)	William Hieronymus 15 Reservoir Rd. Wayland, MA 01778	75,000	-	75,000	8.3
	Tensas River Farms I,II,III 551 Lawrence 5470 Alicia, AR 72410	66,667	-	66,667	7.4
	Summittcrest Capital Partners 50 California St., Suite 450 San Francisco, CA 94111	58,333	-	58,333	6.4

⁽¹⁾

Includes shares believed to be held directly or indirectly by 5% or higher shareholders, directors and executive officers which 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 22, 2012).  

⁽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 22, 2012).

⁽⁴⁾

Based upon 48,787,769 shares of common stock outstanding as of May 22, 2012 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 of May 22, 2012.

⁽⁵⁾

Based on the last known information verified by Mr. Hooper, and includes 2,936,077 shares held directly or as a trustee by Mr. Hooper; and 240,000 shares held indirectly by Hooper Group, a company controlled by Mr. Hooper.  

⁽⁶⁾

Includes 5,001 shares of restricted stock (with sole voting power) subject to restrictions expiring as follows: 1,667 shares in 2012; and 3,334 shares in 2013.  In accordance with the award, on April 7, 2012, 66,667 shares were vested.

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⁽⁷⁾

Includes 5,001 shares of restricted stock (with sole voting power) subject to restrictions expiring as follows: 1,667 shares in 2012; and 3,334 shares in 2013.  In accordance with the award, on April 7, 2012, 233,334 shares were vested.

⁽⁸⁾

Includes 5,001 shares of restricted stock (with sole voting power) subject to restrictions expiring as follows: 1,667 shares in 2012; and 3,334 shares in 2013.  In accordance with the award, on April 7, 2012, 50,000 shares were vested.

⁽⁹⁾

Mr. Martin’s shares are held by 413294 Alberta Ltd., a Canadian Company, that is controlled by Mr. Martin.

⁽¹⁰⁾

In accordance with the award given on April 7, 2009, on April 7, 2011, the final 166,667 shares were vested.

⁽¹¹⁾

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 $0.14.

⁽¹²⁾

Includes 75,000 shares of restricted stock (with sole voting power) subject to restrictions expiring as follows: 25,000 shares in 2012; 25,000 shares in 2013; and 25,000 shares in 2014.  In accordance with the award, on July 22, 2011, 25,000 shares were vested.  

⁽¹³⁾

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 22, 2012, 906,565 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 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, as amended and restated in February 2009, 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 29, 2012, and February 28, 2011, we had the following related party transactions:

On January 31, 2012, the Company issued a $35,100 non-interest bearing note to the Company’s President and Chief Executive Officer.  The term of the note provided for repayment on such other date as may be agreed to by the Company and its President.  The Company and its President have agreed that repayment will be made upon the successful completion of long-term financing.  Proceeds from the note were used to pay an extension fee related to the Well Works Loan.

On June 20, 2011, the Company issued a $200,000 non-interest bearing note from the Company’s President and Chief Executive Officer.  The term of the note provided for repayment on or before June 30, 2011, or such other date as may be agreed to by the Company and its President.  The Company and its President have agreed that repayment will be made upon the successful completion of long-term financing.

Proceeds from the note were used to meet the escrow requirement on a loan commitment.  The escrow requirement amount is reflected as an account receivable on the Balance Sheet and will be refunded to the Company upon closing.  

On January 13, 2010, we commenced a private placement of 12% Subordinated Notes (the “Notes”).  We sold $595,000 of Notes to 13 accredited investors through the closing date of March 16, 2010.  One of the accredited investors, a related party, is our Company President and Chief Executive Officer.  The terms and conditions of the related party Note were identical to the terms and conditions of other participants’ Notes and are described more fully under “Liquidity and Capital Resources – Long Term Borrowings.”

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Mr. Westmoreland, President and Chief Executive Officer, participated in the offering, purchasing a $250,000 Note and receiving the related Warrant to purchase 500,000 shares of Daybreak’s Common Stock.  The Board established a Special Committee comprised of disinterested members to perform extensive due diligence for terms, conditions and provisions for a Private Placement providing for the issuance of Notes to accredited investors.  The Special Committee’s duties were to assist the Board in making a fair transaction for the Company’s shareholders and investors.  Mr. Westmoreland’s participation in the offering was reviewed and approved by the Special Committee of the Board, and the full Board of Directors, in advance of his participation.  The terms and conditions of the Note and Warrant issued to Mr. Westmoreland are identical to the terms and conditions of the Notes and Warrants of all the other participants in the offering.     

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 Amex LLC for determining the independence of its directors.  The Company is not listed on NYSE Amex LLC and is not subject to the rules of NYSE Amex LLC but applies the rules established by NYSE Amex 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 Amex 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);

(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;

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(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 Amex 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 five of the current directors, Messrs. Wayne G. Dotson, Dale B. Lavigne, Ronald D. Lavigne, Timothy R. Lindsey, and James F. Meara are independent.  Mr. James F. Westmoreland, our President and Chief Executive Officer, is not independent.   

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Fees Billed by Independent Registered Public Accountants

The following table provides 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 29, 2012 and February 28, 2011:

Services Rendered	Fees Billed FY 2012		Fees Billed FY 2011
Audit fees	$	84,000	$	89,650
Audit-related fees		-		-
Tax fees		-		-
All other fees		-		-
Total	$	84,000	$	89,650

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.

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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 ⁽¹⁸⁾

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 ⁽¹⁷⁾

4.12

Form of Warrant in connection with 12% Subordinated Notes ⁽¹⁷⁾

10.01

Development agreement with Chicago Mill Joint Venture for Louisiana project ⁽⁷⁾

10.02

Prospect review and non-competition agreement for California project ⁽⁷⁾

10.03

Joint Venture Agreement with Nomad Hydrocarbons, Ltd. for California project ⁽⁷⁾

10.04

Prospect review agreement for California project ⁽⁷⁾

10.05

Development agreement with Vision Exploration for Krotz Springs 3D Prospect ⁽⁷⁾

10.06

Subscription agreement and letter of investment intent, March 2006 private placement ⁽⁴⁾

10.07

Pipeline license agreement for Tuscaloosa project in Louisiana ⁽⁷⁾

10.08

Subscription agreement and letter of investment intent, July 2006 private placement ⁽⁵⁾

10.09

Purchase of additional mineral interest in Tuscaloosa project in Louisiana ⁽⁸⁾

10.10

Farmout agreement with Monarch Gulf Exploration, Inc. ⁽⁹⁾

10.11

Oil and gas lease with Anadarko E&P Company, L.P. ⁽¹⁰⁾

10.12

Drilling contract with Energy Drilling for two wells in Louisiana ⁽¹¹⁾

10.13

Seismic Option Farmin Agreement with Chevron U.S.A. ⁽¹²⁾

10.14

Joint Development Participation Agreement for Tuscaloosa project in Louisiana ⁽¹³⁾

10.15

Purchase and Sale Agreement with Lasso Partners, LLC ⁽¹⁴⁾

10.16

Letter of Agreement to amend the Purchase and Sale Agreement with Lasso Partners, LLC ⁽¹⁵⁾

10.17

Purchase of Tuscaloosa interest from Kirby Cochran ⁽¹⁴⁾

10.18

Purchase of Tuscaloosa interest from 413294 Alberta Ltd. (Robert N. Martin) ⁽¹⁴⁾

10.19

Purchase of Tuscaloosa interest from Tempest Energy, Inc (Eric L. Moe) ⁽¹⁴⁾

10.20

Letter of Agreement on North Shuteston Assignment of Interest ⁽¹⁴⁾

10.21

Exchange Option Agreement with O&G Energy Partners and San Joaquin Investments, Inc. ⁽¹⁶⁾

10.22

Form of Subscription Agreement ⁽¹⁷⁾

10.23

Purchase and Sale Agreement with Arabella Enterprises for the sale of working interest in the East Gilbertown Field in Alabama ⁽¹⁸⁾

10.24

Partial Release of Production Payment between O&G Energy Partners, LLC and Daybreak Oil and Gas, Inc. ⁽¹⁸⁾

10.25

Asset Sale and Purchase Agreement with Chevron U.S.A. Inc. effective July 1, 2010⁽¹⁹⁾

10.26

Assignment of Oil and Gas Leases and Agreements Among Chevron U.S.A. Inc., San Joaquin Investments, Inc. and Daybreak Oil & Gas, Inc. ⁽¹⁹⁾

10.27

Bill of Sale among Chevron U.S.A. Inc., San Joaquin Investments, Inc. and Daybreak Oil & Gas, Inc. ⁽¹⁹⁾

10.28

Secured Convertible Promissory Note from Daybreak Oil & Gas, Inc. to Well Works, LLC ⁽²⁰⁾

90

10.29

Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement from Daybreak Oil & Gas, Inc. to Well Works, LLC ⁽²⁰⁾

10.30

Technical and Consulting Services Agreement between Daybreak Oil & Gas, Inc. to Well Works, LLC ⁽²⁰⁾

10.31

Assignment of Net Profits Interest from Daybreak Oil & Gas, Inc. to Well Works, LLC ⁽²⁰⁾

10.32

Promissory Note, dated June 20, 2011, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland^{. (21)}

10.33

Promissory Note, dated January 31, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland^{. (21)}

10.34

Credit Line Agreement, dated October 24, 2011, by and between Daybreak Oil and Gas, Inc. and UBS Bank USA. ⁽²²⁾

10.35

Loan Extension Agreement, dated September 19, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC. ⁽²²⁾

10.36

Forbearance Agreement, dated October 24, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC. ⁽²²⁾

10.37

Forbearance Agreement, dated November 11, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC. ⁽²²⁾

10.38

Assignment of Net Profits Interest Termination Agreement, effective October 31, 2011,by and between Daybreak Oil and Gas, Inc. and Well Works, LLC. ⁽²²⁾

10.39

Override Grant Deed, effective November 1, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC. ⁽²²⁾

10.40

Forbearance Agreement II, dated November 19, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC. ⁽²²⁾

10.41

Forbearance Agreement III, dated January 12, 2012, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC. ⁽²⁴⁾

10.42

Participation Agreement, dated January 26, 2012, by and between Daybreak Oil and Gas, Inc, and AC Exploration, LLC. ⁽²⁴⁾

10.43

Loan Agreement dated as of May 18, 2012, by and among Daybreak Oil and Gas, Inc. and RTG Steel Company, LLC, as borrowers, and Luberski, Inc., as lender. ⁽²³⁾

10.44

Promissory Note dated as of May 18, 2012, by and among Daybreak Oil and Gas, Inc. and RTG Steel Company, LLC in favor of Luberski, Inc., as lender. ⁽²³⁾

10.45

Borrower Sharing Agreement dated as of May 18, 2012, between Daybreak Oil and Gas, Inc. and RTG Steel Company, LLC. ⁽²³⁾

10.46

Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of May 18, 2012, executed by Daybreak Oil and Gas, Inc., in favor of Luberski, Inc. ⁽²³⁾

23.1

Consent of Lonquist & Co. LLC. ⁽²⁴⁾

23.2

Consent of MaloneBailey, LLP ⁽²⁴⁾

31.1

Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 ⁽²⁴⁾

32.1

Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ⁽²⁴⁾

99.1

Reserves Report of Lonquist & Co. LLC, independent petroleum engineering consulting firm, as of March 1, 2012. ⁽²⁴⁾

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

(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.

91

(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 SB-2/A on December 28, 2006, and incorporated by reference herein.

(8)

Previously filed as exhibit to Form 8-K on September 28, 2006, and incorporated by reference herein.

(9)

Previously filed as exhibit to Form 8-K on October 26, 2006, and incorporated by reference herein.

(10)

Previously filed as exhibit to Form 8-K on November 7, 2006, and incorporated by reference herein.

(11)

Previously filed as exhibit to Form 8-K on November 17, 2006, and incorporated by reference herein.

(12)

Previously filed as exhibit to Form 8-K on July 16, 2007, and incorporated by reference herein.

(13)

Previously filed as exhibit to Form 8-K on July 20, 2007, and incorporated by reference herein.

(14)

Previously filed as exhibits to Form 10-KSB filed on May 27, 2008, and incorporated by reference herein.

(15)

Previously filed as exhibit to Form 8-K on May 2, 2008, and incorporated by reference herein.

(16)

Previously filed as exhibit to Form 8-K on June 16, 2009, and incorporated by reference herein.

(17)

Previously filed as exhibits to Form 8-K on February 3, 2010, and incorporated by reference herein.

(18)

Previously filed as exhibit to Form 10-K on May 28, 2010, and incorporated by reference herein.

(19)

Previously filed as exhibit to Form 10-Q on October 15, 2010, and incorporated by reference herein.

(20)

Previously filed as exhibit to Form 8-K on September 23, 2010, and incorporated by reference herein.

(21)

Previously filed as exhibit to Form 10-Q on October 17, 2011, and incorporated by reference herein.

(22)

Previously filed as exhibit to Form 10-Q on January 13, 2012, and incorporated by reference herein.

(23)

Previously filed as exhibit to Form 8-K on May 23, 2012, and incorporated by reference herein.

(24)

Filed herewith.

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

92

GLOSSARY OF TERMS

The following are abbreviations and definitions of terms commonly used in the oil and 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 oil equivalent (BOE) is the standard convention used to express oil and gas volumes on a comparable oil equivalent basis.  Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of 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 oil or 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 an oil or 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 an oil or gas 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 oil or natural gas in another reservoir.

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.

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

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

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

Oil.  Crude oil or condensate.

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

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

93

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 oil and gas reserves are those quantities of oil and 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 oil or 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 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 oil and 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 oil and 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.

SEC.  The United States Securities and Exchange Commission.

94

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 oil or gas, regardless of whether such acreage contains proved reserves.

Working interest.  An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and 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.

95

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 Officerand
	interim principal finance and
	accounting officer
	Date:  May 25, 2012

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/ DALE B. LAVIGNE
	James F. Westmoreland		Dale B. Lavigne
	Director / President and Chief Executive Officer		Director / Chairman
	Date:  May 25, 2012		Date:  May 25, 2012
By:	/s/ TIMOTHY R. LINDSEY	By:	/s/ WAYNE G. DOTSON
	Timothy R. Lindsey		Wayne G. Dotson
	Director		Director
	Date:  May 25, 2012		Date:  May 25, 2012
By:	/s/ RONALD D. LAVIGNE	By:	/s/ JAMES F. MEARA
	Ronald D. Lavigne		James F. Meara
	Director		Director
	Date:  May 25, 2012		Date:  May 25, 2012

96

EX-10

Exhibit 10.41

FORBEARANCE AGREEMENT III

This FORBEARANCE AGREEMENT III (this “Agreement”), dated as of January 30, 2012, is by and among DAYBREAK OIL AND GAS, INC., a Washington corporation (“Daybreak”) and WELL WORKS, LLC, a Utah limited liability company (“Well Works”).

WHEREAS, Daybreak and Well Works are parties to that certain Forbearance Agreement dated as of October 24, 2011 which contained a “Termination Date” of 11:59 p.m. Houston, Texas time on November 10, 2011; and

WHEREAS, for good and sufficient consideration, that “Termination Date” was extended to November 18, 2011 by virtue of an Agreement signed by the parties hereto and dated as of November 11, 2011; and

WHEREAS, on November 18, 2011, Daybreak wired the sum of Six Hundred Thousand Dollars ($600,000) to Well Works as a partial payment of the $853,581 owed by Daybreak to Well Works on said November 18, 2011; and

WHEREAS, following the receipt by Well Works of $600,000 (as a partial payment)  on November 18, 2011, Daybreak still owed Well Works the sum of $253,581 as of November 19, 2011; Well Works agreed to forbear once again and charged the sum of $50,716 (20% of the $253,581 owed on November 19, 2011) to forbear for an additional 30 days plus $4,000 in legal fees and $4,561 in accrued interest. The total due then on Tuesday December 20, 2011 was $312,858. This Agreement, signed by both parties, carried the title of Forbearance II.

WHEREAS, payment in the amount of $312,858.00 was not received on December 21, 2011, the due date and accordingly per the Forbearance II Agreement, a $250,000.00 late fee was added, bringing the total owed as of that date to $562,858.00. The monthly interest rate on all outstanding loan balances also increased from 1.5% to 2% per month or to $370.00 per day.

WHEREAS, Well Works has been forbearing from December 21, 2011 through January 20, 2012, at no additional cost to Daybreak, other than the interest on the outstanding balance of $562,858.00 accruing at the rate of $370 a day ($11,100. for the 30-day period). Accordingly, the amount owing as of January 20, 2012 is $573,958.00 including interest for the prior 30-day period.

WHEREAS, the parties hereto, given the above circumstances, have agreed to enter into this Agreement of January 30, 2012 which will re-publish and re-affirm all the representations, warranties, terms and conditions of the November 11, 2011 Forbearance Agreement and the October 24, 2011 Forbearance Agreement after reducing: (i) the total amount due to Well Works on November 18, 2011 from Daybreak by the $600,000 Daybreak payment of November 18, 2011; (ii) providing a new forbearance period running from January 21, 2012 to the new termination date of May 20, 2012; (iii) providing a fee for the new forbearance period; (iv) providing for interest on the outstanding balance due and payable monthly.   

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

1.

Well Works agrees to a new Forbearance Period of 120 days, i.e. from January 21, 2012 through May 20, 2012.  

2.

In order to make this new Forbearance Period effective, Well Works must be paid by Daybreak the sum of $644,874.00 (this number arrived at by deducting the $600,000 payment Well Works received on Friday, November 18, 2011 from the $853,581.00 set forth as the total payments due in Section 5 of the Forbearance Agreement II between the parties dated as of November 11, 2011, (which comes to $253,581) and adding the following):

·

$250,000.00 late fee as agreed upon for the forbearance period of November 19, 2011 to December 20, 2011;

·

$50,716 (20% of the $253,581 owed on November 19, 2011) to forbear for the  additional 30 days for the forbearance period of November 19, 2011 to December 20, 2011;

·

$4,000 in legal fees for the forbearance period of November 19, 2011 to December 20, 2011;

·

$4,561 in accrued interest for the forbearance period of November 19, 2011 to December 20, 2011;

·

$25,000.00 for the forbearance period of January 21, 2012 through May 20, 2012 plus;

·

$11,100.00 for the interest owed from December 20, 2011 through January  21, 2012.

·

To keep the forbearance of January 21, 2012 through May 20, 2012 in good standing Daybreak will pay Well Works monthly interest of $11,479.00 on the outstanding balance on or before February 20, 2012, March 20, 2012, April 20, 2012 and May 20, 2012 respectively.

·

The $25,000.00 for this 120 day forbearance period of January 21, 2012 through May 20, 2012, and the past due interest of $11,100.00 recited above, are due as of January 21, 2012 and payable at the same time this 120-day forbearance is signed but in no event to be paid later than 4:00 PM MST on  January 31, 2012.

3.

If the amount of $644,874.00 is not paid by Daybreak to Well Works on or before the Termination Date of May 20, 2012, under this new Forbearance Period, Well Works will pursue the remedies available under the recorded Mortgage, Deed of Trust.

4.

All representations, warranties, terms and conditions of the Forbearance Agreement dated as of October 24, 2011 as well as the Forbearance Agreement dated as of November 11, 2011, included but not limited to, the Representations and Warranties of Daybreak in Sections 2, 3, 4, 5 (less the $600,000 payment by Daybreak on November 18, 2011), 6, 7,  8, 9, 10, 11 and 13 and Exhibit A (again less the $600,000 payment by Daybreak on  November 18, 2011) as well as Exhibit B, all as set forth in the Forbearance Agreement dated as of November 11, 2011,   as well as Section 5 as set forth in the Forbearance Agreement II dated as of November 19, 2011 are hereby republished and reaffirmed by this Agreement. It is acknowledged by Well Works that the payment of $600,000 by Daybreak to Well Works has been received as a partial payment of the amount due on said November 18, 2011 to Well Works and it is the only partial payment received by Well Works to date.   

This Agreement confirms the balance owing as well as the terms and conditions set forth above. It further confirms that the current Mortgage, Deed of Trust continues to pledge the same collateral and Daybreak represents that this collateral has not been diminished in value and is sufficient to provide security for the numbers set forth above.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed on the date first written above.

DAYBREAK OIL AND GAS, INC.
By:	/s/ JAMES F. WESTMORELAND
	Name: James F. Westmoreland
	Title: President and Chief Executive Officer
WELL WORKS, LLC
By:	/s/ ERIC B. HALE
	Name: Eric B. Hale
	Title: Managing Member

EX-10

Exhibit 10.42

Daybreak Oil and Gas, Inc.

Corporate Office:	Houston Office:
601 West Main Ave    Suite 1012	1414 S. Friendswood Dr., Suite 215
Spokane, WA   99201	Friendswood, TX 77546
Phone: (509) 232-7674	Phone: (281) 996-4176
Fax: (509) 455-8483	Fax: (281) 996-4176

January 26, 2012

AC Exploration, LLC

952 Echo Lane, Suite 390

Houston, Texas 77024

Re:	Participation Agreement
	Dyer Creek Area
	Kern County, California

Gentlemen:

This agreement (the "Agreement") is made and entered into by and between Daybreak Oil and Gas, Inc., (hereinafter referred to as "Assignor") and AC Exploration, L.L.C., (hereinafter referred to as "Assignee").

Assignor represents that it is the present owner of 41.67% of the right, title and interest in and to the oil and gas leases more fully described in Exhibit "A" attached hereto and incorporated herein for all purposes.  Said leases cover lands in Sections 2, 3, 10, 11 in T26S-R27E, Kern County, California (hereinafter referred to as the "Leases").  The Leases cover the lands within the outlined Area “A” on the plat attached hereto as Exhibit "B" which is incorporated herein for all purposes.

Assignee is desirous of acquiring from Assignor one half of Assignor’s undivided interest herein described in the Leases and participating in the drilling of a test well for oil and gas thereon subject to the terms, conditions, reservations and limitations provided here­after.  The parties therefore agree as follows:

1.

CONSIDERATION

For and in consideration as set forth below, Assignor agrees to assign, within thirty (30) days after the date the Test Well is drilled and completed as a producing well, but effective as of January 1, 2012, with warranty of title, by, through and under Assignor, but not otherwise, and further subject to the terms, reservations and conditions hereinafter set forth, one half of Assignor’s leasehold interest in the Leases

Page 1 of 5

to Assignee; provided, however, as a condition precedent to such assignment, Assignee shall have paid all of Assignor’s pro rata share of costs necessary to drill the Test Well to Total Depth, evaluate same with a triple combination log and plug and abandon same if a dry hole, or to complete same if a producer.  Such costs shall be paid to Assignor pursuant to an Authority For Expenditure ("AFE") to be submitted by Assignor to Assignee.

2.

OVERRIDING ROYALTY

It is understood and agreed that the Leases described in Exhibit “A” shall be burdened with a proportionately reduced overriding royalty interest in favor of Chet Pohle, Brian Hirst and Randy Metz (“Pohle, et al”).  Said overriding royalties equal 3% of 8/8ths.  

3.

TEST WELL

On or before May 1, 2012, Daybreak Oil and Gas, Inc., as operator, shall commence operations for the drilling of a test well (hereinafter referred to as the "Test Well") in Section 11, T26S-R27E, and shall thereafter diligently and in a good and workmanlike manner proceed to cause the drilling of the Test Well to a true vertical depth of approximately 2,350 feet beneath the surface of the earth, or a depth sufficient to test the Vedder formation, whichever is lesser (hereinafter referred to as "Total Depth").

4.

CASING POINT, COMPLETION ELECTION AND SUBSEQUENT OPERATIONS

After the Test Well has reached Total Depth, Assignor shall evaluate all prospective formations in accordance with prudent operating standards.  In the event the Test Well is not completed and is plugged and abandoned as a dry hole, Assignee shall bear all of Assignor’s actual costs in connection with the drilling, testing, plugging and abandonment of the Test Well.  Alternatively, should a completion attempt be made upon the Test Well, Assignee shall bear Assignor’s share of all subsequent risks, costs and expenses in connection with such completion attempt.  

5.

OPERATING AGREEMENT

All operations on the lands covered by the Leases and the AMI shall be conducted in accordance with the terms of this Agreement and the Operating Agreement ("Operating Agreement"), a copy of which is attached hereto as Exhibit "C" and incorporated herein for all purposes.   The terms and provisions of this Agreement shall control and prevail until the spudding of the Test Well, after which, the terms and provisions of the Operating Agreement shall prevail.

Page 2 of 5

6.

WELL INFORMATION

Assignee or its representatives shall have access at its own risk and at all times to the location and derrick floor during the drilling of any well hereunder.  Assignee shall further be entitled to all information concerning any well drilled hereunder and the Leases unless any such party is nonconsent or is delinquent in the payment of its joint interest billings to Operator for a period greater than sixty (60) days, in which event Operator at its sole option may withhold any information to such delinquent party.

7.

AREA OF MUTUAL INTEREST

The parties hereto hereby establish an Area of Mutual Interest ("AMI") which covers and includes all lands in Area “C” and Area “E” included within the heavy black outline on the plat attached hereto as Exhibit "B".  In the event that any party hereto hereafter proposes to drill a well or as nonoperator has a well proposed to them, each party hereto shall have an option to participate as to its proportionate interest subject to this Agreement. The non-proposing party shall, within thirty (30) days after receipt of such proposal, elect whether to participate with its interest by paying its share of the actual cost and expenses, if any, incurred by the proposing party.  Failure by the non-proposing party to timely notify the proposing party shall be deemed an election by such non-proposing party not to participate for its ratable interest in the leasehold interest and well proposal offered.  When the non-proposing party elects not to participate for  its ratable interest from the proposing party, such non-proposing party's interest in such lease or contract which is the subject of such offer shall be wholly owned by the proposing party and shall not be subject to this Agreement.  Unless otherwise mutually agreed, this AMI shall terminate six (6) months after the expiration of the last lease within the AMI.

All lands in Areas “B” and “D” outlined on Exhibit “B” shall be excluded from this AMI and Assignee shall have no right to acquire or participate in the acquisition of any mineral interest owned or acquired by Assignor in such lands.

8.

MISCELLANEOUS

A.

Paragraph Headings.

The paragraph headings inserted in this Agreement are utilized solely for reference purposes and do not constitute substantive matter to be considered in construing the terms of this Agreement.

B.

Time is of the Essence.

It is specifically understood and agreed that time is of the essence hereunder.

C.

Liability.

It is not the purpose of this Agreement to create a partnership, mining partnership, partnership for a specific purpose, joint venture, or any other relationship which would render the parties liable as partners, associates, or joint venturers.

D.

Entire Agreement.

Page 3 of 5

This Agreement shall constitute the entire Agreement between the parties hereto and supersedes any prior agreements, promises, negotiations or representations, whether written or oral, not expressly set forth in this Agreement.  No variations, modifications, or changes herein or hereof shall be effective unless evidenced by written document executed by the parties hereto.

E.

Counterparts.

This Agreement may be executed in any number of counterparts and each counterpart so executed shall be deemed an original for all purposes and shall be binding upon each party executing same whether or not executed by all parties.

F.

Governing Law.

This Agreement shall be governed by the laws of the State of Texas.

G.

Binding Agreement.

The terms, covenants and conditions of this Agreement shall be binding upon, and shall inure to the benefit of, the parties hereto and to their respective heirs, executors, administrators, successors and assigns, and such terms, covenants and conditions shall be deemed as covenants running with the lands and leases covered hereby.  It is stipulated, however, that no assignment or transfer by or, however accomplished, of any right, title or interest acquired hereunder shall relieve such party of any liability or obligation herein assumed, except with written consent of the other party.

H.

Notices.

The address of the parties for notice purposes under this agreement are as follows:

If to Assignor:

Daybreak Oil and Gas, Inc.

1414 S. Friendswood Dr., Suite 215

Friendswood, TX 77546

Attn:

Mr. James Westmoreland, President

Telephone:

(281)996-4176

Facsimile:

(281)996-4176

Email:

jimw@daybreakoilandgas.com

If to Assignee:

AC Exploration, L.L.C.

952 Echo Lane, Suite 390

Houston, Texas 77024

Attn:

Mr. Kenneth A. Floyd

Telephone:

(713)881-9030

Facsimile:

(713)881-9078

Email:

kfloyd@acexploration.com

[Signature Page to Follow]

Page 4 of 5

If the foregoing fully sets forth your understanding of our agreement, please so indicate by execution in the space provided below and return one (1) fully executed original hereof together with your share of the Initial Consideration described in Section 1. herein.  If this Agreement is not accepted and returned within fifteen (15) days from the date hereof with your share of the Initial Consideration, this Agreement shall be voidable at the sole option of Assignor.

Sincerely,
DAYBREAK OIL AND GAS, INC.
By:	/s/ JAMES F. WESTMORELAND
Name:	James F. Westmoreland
Title:	President and Chief Executive Officer

AGREED TO AND ACCEPTED THIS

26TH DAY OF       January       , 2012.

AC EXPLORATION, L.L.C.

By:	/s/ KENNETH A. FLOYD
Name:	Kenneth A. Floyd
Title:	Co-Manager

Page 5 of 5

EX-23

Exhibit 23.1

May 25, 2012

Daybreak Oil and Gas, Inc.

601 W. Main Ave

Suite 1017

Spokane, WA  99201

Re: Securities and Exchange Commission Annual Report on Form 10-K

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name Lonquist & Co. LLC; and to references to Lonquist & Co. LLC an independent petroleum engineering firm; and to the inclusion of information contained in our reports as of March 1, 2012, in your Annual Report on Form 10-K for the year ended February 29, 2012 to be filed on or around May 25, 2012.

LONQUIST & CO., LLC

Texas Firm registration No. F-8952

AUSTIN, TEXAS

May 25, 2012

/s/ Don E. Charbula

Don E. Charbula, P.E.

Vice President

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 Daybreak Oil and Gas, Inc. of our report dated May 25, 2012 related to the financial statements of  Daybreak Oil and Gas, Inc. as of and for the years ended February 29, 2012 and February 28, 2011.

/s/ MaloneBailey, LLP

www.malonebailey.com

Houston, Texas

May 25, 2012

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 25, 2012

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 29, 2012, 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 25, 2012

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

DAYBREAK OIL AND GAS, INC.

Southern San Joaquin Basin, East Slopes Project

Kern County, California

Estimated Future Reserves and Revenues

As of March 1, 2012

SEC Guideline Case

_{Table of Contents}

Letter of Transmittal

Areas of Interest Map

SEC Definitions of Oil and Gas Reserves

Reserve and Revenue Projections

Summary by Reserve Classification

One-Line Property Listing

Ranked by Class, State and County

Ranked by Discounted Value

Detailed Projections and Production Plots

Proved Developed Producing

Proved Undeveloped

May 9, 2012

Mr. James F. Westmoreland

President & CEO

Daybreak Oil and Gas, Inc.

601 West Main Ave., Suite 1012

Spokane, WA 99201

Re: Daybreak Oil and Gas, Inc.

1P Reserve Report

As of March 1, 2012

SEC Guideline Case

Dear Mr. Westmoreland:

Pursuant  to  your  request,  Lonquist  &  Co.  LLC, (“L&Co”) has estimated the future oil and  gas Reserves and projected the associated future revenues for certain properties owned by Daybreak Oil and Gas, Inc. (“Daybreak”). The properties evaluated herein are located in Kern County, California. At the request of Daybreak, we have evaluated Proved Developed Producing (“PDP”) and Proved Undeveloped (“PUD”) Reserves.

Effective March 1, 2012, our conclusions are as follows:

Net to Daybreak Oil and Gas, Inc.
	Proved Developed		Proved	Total	Total	Total	Grand
SEC Pricing as of March 1, 2012	Producing	Non-Producinga	Undeveloped	Provedb	Probableb	Possibleb	Totalb
Estimated Future Net Oil/Condensate, bbl	85,160	0	137,550	222,710	0	0	222,710
Estimated Future Net Gas, MMcf	0	0	0	0	0	0	0
Total Future Gross Revenue, $	8,890,000	0	14,358,780	23,248,780	0	0	23,248,780
Estimated Future Production Taxes, $	105,290	0	170,070	275,360	0	0	275,360
Estimated Future Operating Expenses, $	3,860,280	0	3,666,510	7,526,790	0	0	7,526,790
Estimated Future Capital Costs, $	0	0	1,431,250	1,431,250	0	0	1,431,250
Estimated Future Net Revenue ("FNR"), $	4,924,430	0	9,090,940	14,015,370	0	0	14,015,370
Discounted FNR at 10%, $	2,698,870	0	4,558,580	7,257,450	0	0	7,257,450
Discounted FNR at 15%, $	2,228,080	0	3,572,160	5,800,240	0	0	5,800,240
Estimated Net Revenues by Year, $
2012	591,920	0	-28,430	563,500	0	0	563,500
2013	544,650	0	1,080,210	1,624,860	0	0	1,624,860
2014	434,930	0	1,145,220	1,580,150	0	0	1,580,150
Subtotal	1,571,500	0	2,197,000	3,768,510	0	0	3,768,510
Thereafter	3,352,930	0	6,893,940	10,246,860	0	0	10,246,860
Total	4,924,430	0	9,090,940	14,015,370	0	0	14,015,370
Estimated Average Net Production Rate - 2012
Oil/Condensate, bbl/D	23	0	30	53	0	0	53
Gas, Mcf/D	0	0	0	0	0	0	0

^aColumn includes the Proved Developed Non-Producing, behind pipe, and shut-in cash flows and volumes.

^bTotals might not match due to computer rounding.

Daybreak Oil and Gas, Inc. – March 1, 2012 Reserve Report

SEC 1P Reserve Report

May 9, 2012

Page 2 of 5

Purpose of Report and Standards of Practice

This report was prepared to provide the management of Daybreak Oil and Gas, Inc. with a projection of  estimated  remaining  hydrocarbon  Reserves  and  projected  future  net  revenues,  effective March 1, 2012. These estimates have not been adjusted for risk.

This report has been prepared in accordance with our understanding of the Securities and Exchange Commission, S-X Reg. §210.4-10a, dated December 30, 2008 (Modernization of Oil and Gas Reporting; Final Rule; January 14, 2009); we have evaluated the 1P Reserves. The applicable SEC oil and gas Reserve definitions are attached hereto.

Liquid hydrocarbon volumes are expressed in standard 42-gallon barrels. All natural gas volumes are sales gas expressed at the official pressure and temperature bases of the areas in which the gas Reserves are located.

All currencies in this report are expressed in U.S. dollars.

Reserve Estimates

Well-by-well production data in this report were updated through February 29, 2012. Extrapolation of historical production data was utilized for those producing properties where sufficient data were available to suggest decline trends. Reserves assigned to the remaining producing properties and the volumes associated with non-producing assets were determined by analogy to offset wells producing from similar formations or by volumetric analyses. Hydrocarbon volumes assigned by analogy and volumetric  analyses  are  subject  to  greater  revision  than  those  projected  using  established performance trends.

As of March 1, 2012, the 1P net remaining Reserves were estimated to be 222,710 barrels of oil. The net present value, discounted at 10%, of the total Proved Reserves was $7,257,450. Of the total net revenue, discounted at 10%, 37.2% was derived from the PDP Reserves. The Reserve life index (“R/P”) of the PDP Reserves was estimated to be 10 years.

Property Overview

The San Joaquin East Slope Region, located in Kern County California, is operated by Daybreak Oil and Gas. On this leasehold, 3D seismic survey data have been shot on 22,000 acres. Using these data, twelve prospective areas have been identified, of which five have been drilled. The areas evaluated in this report, Sunday, Bear, Black, Dyer Creek and Ball have been classified as Proved, and are in the development phase. All production is from the Vedder formation, which is typically an unconsolidated reservoir requiring gravel packed completions.

Sunday Prospect

To date, the Sunday #1, #2, #3 and #4 have produced 70,760 barrels of oil from the Vedder formation. The Sunday #4 was drilled as a horizontal well but is producing as a vertical well after a workover. The Vedder net pay map over the Sunday Prospect contains 34.6 acres and three PUD locations were assigned.

Daybreak Oil and Gas, Inc. – March 1, 2012 Reserve Report

SEC 1P Reserve Report

May 9, 2012

Page 3 of 5

Bear Prospect

To date, four wells have been drilled in the Bear Prospect with a cumulative production of 45,900 barrels of oil. The Bear #1, #2, #3 and #4 are all producing from the Vedder formation. The Bear #3, the southernmost well in the pool, is believed to have mechanical problems and has never performed up to expectations. As a result of the mechanical issues, the Bear #3 has an estimated ultimate recovery of 5,757 barrels of oil. An offset location was not assigned in this area.  At the time of this report, the identified pool covers 62 acres, of which 38 acres contain Proved Reserves. In addition, three PUD locations were identified.

Black Prospect

The Black Prospect is located south of the Bear Prospect, and contains 13.4 acres in the Vedder formation. The Black #1 is the only producing property in this area. After looking at core data and low productivity, a workover has been scheduled at the end of the current economic life to recover additional Reserves. At the time of this report, two PUD locations were identified.

Ball Prospect

The Ball Prospect is the northernmost pool in the Dyer Creek Field Trend and has 37.5 acres of mapped closure in the Vedder formation. The Ball #1-11 was drilled and completed in October 2010. At the time of this report, two PUD locations were identified.

Dyer Creek Prospect

The Dyer Creek structure, which lies between the Bear and the Ball, is not closed to the south and therefore may be in communication with the Bear structure. The Dyer Creek #67X-11 was drilled and completed in October 2010. Due to completion problems, this well has an estimated ultimate recovery of 4,697 barrels of oil. At the time of this report, one PUD was identified.

Product Prices

The base oil price of $97.56 per barrel utilized herein is the average closing oil price of the first trading day of each month for the prior twelve months as of February 29, 2012, as reported by the Energy Information Administration. As stipulated by SEC regulations, no price escalations were included in this report. Product price differentials were calculated by comparing the realized prices, as calculated from revenue statements, to the average NYMEX futures price for the same calendar month. This average differential is expressed as a percentage multiplier on price in the economic model.

Daybreak Oil and Gas, Inc. – March 1, 2012 Reserve Report

SEC 1P Reserve Report

May 9, 2012

Page 4 of 5

Operating Expenses

Direct operating expense data, input as dollars per month in the economic models, were supplied by Daybreak. These direct operating costs were based on actual expenses from March 2011 through February 2012, and were adjusted for non-recurring costs, where applicable.

Severance and ad valorem taxes were deducted as a percentage of gross revenues or as a charge per unit of production. The individual well projections of oil and gas cease when the operating expenses exceed the gross revenues.

Operating expenses were not escalated in this report.

Capital Expenses

Estimated capital costs were input as approximate costs for the operations that would be performed on  wells  in the  PUD  Reserve  category.  A  more  accurate  cost  estimate  for  these  individual investments will be generated at the time they are carried out. These operations were modeled to start at a specific point in the future. Any deviation from these dates will result in a change in the projected future net revenues for those properties evaluated herein.

Capital expenditures were not escalated in this report.

Values Not Considered

In all cases we have attempted to account for all deductions from gross revenues except for the following:

·

Federal Income Tax

·

Depreciation, depletion, and/or amortization, if any

·

Costs in excess of revenues from uneconomic leases

·

Plugging and abandonment costs in excess of salvage value

·

Environmental restoration costs, if any

·

Product price hedges, if any

No value has been assigned to non-producing acreage or to acreage held by production.

Report Qualifications

The future net revenues were based on projections of recoverable hydrocarbons, rates of production, timing of recompletions and drilling, proration by state and federal agencies, direct taxes, and product prices. All estimated future net revenues presented in this report are after the deduction of royalties, production costs, and development costs. This evaluation does not include indirect costs such as administrative, overhead, and other miscellaneous expenses. Any unusual combination of the many factors, including weather, political risk or acts of terrorism could result in future receipts being considerably less or more than those estimated herein.

THE REVENUES AND PRESENT WORTH OF FUTURE NET REVENUES PRESENTED HEREIN ARE NOT REPRESENTED TO BE MARKET VALUES EITHER FOR THE INDIVIDUAL PROPERTIES OR ON A TOTAL PROPERTY BASIS.

Daybreak Oil and Gas, Inc. – March 1, 2012 Reserve Report

SEC 1P Reserve Report

May 9, 2012

Page 5 of 5

Data Sources

Data including basic well information, geological interpretations, realized product prices, operating costs, initial test rates, and ownership interests were supplied by Daybreak. L&Co has accepted this data as correct.

Historical production data were obtained from Daybreak as well as public sources, such as Lasser Production Data Services, DrillingInfo.com, and HPDI Production Data Applications. Production data was updated though February 2012. We retain in our files digital databases for all properties and certain other hard copy information that we believe pertinent.

We have not inspected the properties evaluated in this report, nor have we conducted independent well tests.

Independent Evaluation

Neither Lonquist & Co. LLC nor any of its employees have any interest or ownership in the subject properties, and neither our employment nor compensation is contingent on our findings herein.

Sincerely,

Lonquist & Co., LLC

Texas Registration No. F-8952

/s/ Don E. Charbula

Don E. Charbula, P.E.

Vice President

Texas License No. 73435

Date Signed: May 9, 2012

Austin, Texas

/s/ Tereasa S. Montemayor

Tereasa S. Montemayor

Sr. Petroleum Engineer

AREA OF INTEREST

Daybreak Oil and Gas, Inc.

OIL AND GAS RESERVE DEFINITIONS

The Securities and Exchange Commission, SX Reg. § 210.4-10 dated November 18, 1981 as amended

September 19, 1989 requires adherence to the following definitions of “Proved” oil and gas reserves:

Definitions:

(2) Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves";   (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

(3) Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

(4) Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates, for proved undeveloped reserves be attributable to any acreage or which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Amended SEC guidelines Reg. § 210.4-10 definitions (Modernization of Oil and Gas Reporting; Final Rule; January 14, 2009):

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.  When probabilistic methods are used, there should be at least a 10 percent probability that the total quantities ultimately recovered will equal or exceed the estimated proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain.  Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by defined project.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus reserves. When probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.  Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

XML

GOING CONCERN

12 Months Ended

Feb. 29, 2012

Going Concern

GOING CONCERN

NOTE 2 — GOING CONCERN:

Financial Condition

Daybreak’s financial statements for the year ended February 29, 2012 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 $23,839,493 and a working capital deficit of $3,221,376, 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 eleven producing 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 40.15% and the average net revenue interest is 29.85% for these same wells.

The Company anticipates revenues will continue to increase as it participates in the drilling of more wells in California. Daybreak plans to continue its development drilling program at a rate that is compatible with its cash flow and funding opportunities.

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company has experienced revenue growth from its oil and 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 29, 2012 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.

XML

ORGANIZATION

12 Months Ended

Feb. 29, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION

NOTE 1 — ORGANIZATION:

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 oil and gas exploration and production industry. On October 25, 2005, the 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 oil and 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, 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 oil and 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.

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Balance Sheets (USD $)	Feb. 29, 2012	Feb. 28, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 73,392	$ 57,380
Accounts receivable:
Oil and gas sales	192,639	185,836
Joint interest participants, net of allowance for doubtful accounts of $0 and $33,346 respectively	92,220	139,234
Loan commitment refund and other receivables	223,750	97,577
Prepaid expenses and other current assets	44,777	69,876
Total current assets	626,778	549,903
OIL AND GAS PROPERTIES, net of accumulated depletion, amortization, and impairment, of $1,186,212 and $871,658 respectively, successful efforts method
Proved properties	1,634,545	1,837,431
Unproved properties	438,640	452,570
VEHICLES AND EQUIPMENT, net of accumulated depreciation of $31,329	0	0
PRODUCTION REVENUE RECEIVABLE	350,000	350,000
OTHER ASSETS	105,506	104,904
Total assets	3,155,469	3,294,808
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	1,663,303	1,772,010
Accounts payable-related parties	497,315	156,370
Accrued interest	418,531	5,477
Notes payable, net of discount of $0 and $30,105, respectively	150,000	719,895
Notes payable - related party	235,100	0
Line of credit	883,905	0
Total current liabilities	3,848,154	2,653,752
LONG TERM LIABILITIES:
Notes payable, net of discount of $46,149 and $57,119 respectively	298,851	287,881
Notes payable - related parties, net of discount of $33,934 and $41,987 respectively	216,066	208,013
Asset retirement obligation	44,107	55,122
Total liabilities	4,407,178	3,204,768
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY (DEFICIT):
Common stock	48,788	48,792
Additional paid-in capital	22,538,089	22,447,250
Accumulated deficit	(23,839,493)	(22,406,909)
Total stockholders' equity	(1,251,709)	90,040
Total liabilities and stockholders' equity (deficit)	3,155,469	3,294,808
Preferred Stock
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock	0	0
Series A Convertible Preferred Stock
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock	$ 907	$ 907

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Shareholders Equity (USD $)	Series A Convertible Preferred Stock	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Beginning balance, value at Feb. 28, 2010	$ 1,009	$ 47,786	$ 22,255,802	$ (21,191,162)	$ 1,113,435
Beginning balance, shares at Feb. 28, 2010	1,008,565	47,785,599
Issuance of common stock for company stock plan, value		450	88,058		88,508
Issuance of common stock for company stock plan, shares		450,000
Issuance of common stock for conversion of preferred stock, value	(102)	306	(204)		0
Issuance of common stock for conversion of preferred stock, shares	(102,000)	306,000
Issuance of common stock for loan origination fees, value		250	23,500		23,750
Issuance of common stock for loan origination fees, shares		250,000
Debt discount on short term notes payable			65,494		65,494
Warrants issued in connection with fundraising			14,600		14,600
Net loss				(1,215,747)	(1,215,747)
Ending balance, value at Feb. 28, 2011	907	48,792	22,447,250	(22,406,909)	90,040
Ending balance, shares at Feb. 28, 2011	906,565	48,791,599
Issuance of common stock for company stock plan, value			91,218		91,218
Cancellation of stock plan issuances, value		(4)	(379)		(383)
Cancellation of stock plan issuances, shares		(3,830)
Warrants issued in connection with fundraising					0
Net loss				(1,432,584)	(1,432,584)
Ending balance, value at Feb. 29, 2012	$ 907	$ 48,788	$ 22,538,089	$ (23,839,493)	$ (1,251,709)
Ending balance, shares at Feb. 29, 2012	906,565	48,787,769

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SUPPLEMENTARY INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES

12 Months Ended

Feb. 29, 2012

Supplementary Information For Oil And Gas Producing Activities

SUPPLEMENTARY INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES

NOTE 15 — SUPPLEMENTARY INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

All of the Company’s continuing operations are directly related to oil and natural gas producing activities located in California.

Capitalized Costs Relating to Oil and Gas Producing Activities

	As of February 29, 2012		As of February 28, 2011
Proved leasehold costs
Mineral Interests	$	2,254	$	2,254
Wells, equipment and facilities		2,818,503		2,706,835
Total Proved Properties		2,820,757		2,709,089
Unproved properties
Mineral Interests		431,895		431,895
Uncompleted wells, equipment and facilities		6,745		20,675
Total unproved properties		438,640		452,570
Less accumulated depreciation, depletion amortization and impairment		(1,186,212)		(871,658)
Net capitalized costs	$	2,073,185	$	2,290,001

Costs Incurred in Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	February 29, 2012		February 28, 2011
Acquisition of proved properties	$	-	$	1,128
Acquisition of unproved properties		6,745		431,337
Development costs		90,993		946,753
Exploration costs		168,177		184,255
Total costs incurred	$	259,915	$	1,563,473

Results of Operations from Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	February 29, 2012		February 28, 2011
Oil and gas revenues	$	1,314,124	$	1,079,496
Production costs		(220,008)		(172,250)
Exploration expenses		(168,177)		(184,255)
Depletion, depreciation, amortization and impairment		(319,905)		(307,023)
Result of oil and gas producing operations before income taxes		607,034		415,968
Provision for income taxes		-0-		-0-
Results of oil and gas producing activities	$	607,034	$	415,968

Proved Reserves

The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, Lonquist & CO. 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)	BOE (Barrels)
Proved reserves:
February 28, 2010	62,155	62,155
Revisions(1)	24,890	24,890
Extensions and discoveries	145,648	145,648
Production	(13,009)	(13,009)
Purchases (sales) of minerals-in-place	18,146	18,146
February 28, 2011	237,830	237,830
Revisions(1)	12,016	12,016
Production	(12,571)	(12,571)
Purchases (sales) of minerals-in-place	(14,565)	(14,565)
February 29, 2012	222,710	222,710

(1) The revisions of previous estimates resulted from a revised increased estimate of reserve value after continued reservoir production and increased hydrocarbon 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, 2010	38,648	38,648	23,507	23,507	62,155	62,155
February 28, 2011	88,840	88,840	148,990	148,990	237,830	237,830
February 29, 2012	85,160	85,160	137,550	137,550	222,710	222,710

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 29, 2012 and February 28, 2011 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 29, 2012 and February 28, 2011 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 29, 2012		February 28, 2011
Future cash inflows	$	23,248,780	$	18,138,730
Future production costs (1)		(7,802,160)		(6,896,130)
Future development costs		(1,431,250)		(1,667,310)
Future income tax expenses (2)		-		-
Future net cash flows		14,015,370		9,575,290
10% annual discount for estimated timing of cash flows		(6,757,920)		(4,215,510)
Standardized measure of discounted future net cash flows at the end of the fiscal year	$	7,257,450	$	5,359,780

(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 oil prices are set forth in the table below.

	Average Price
	Oil (Barrel)
Year ended February 29, 2012 (1)	$	104.39
Year ended February 28, 2011 (1)	$	76.27
Year ended February 28, 2010 (1)	$	58.86

(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 29, 2012		February 28, 2011
Standardized measure of discounted future net cash flows at the beginning of the year	$	5,359,780	$	1,975,928
Extensions, discoveries and improved recovery, less related costs		-		3,053,440
Revisions of previous quantity estimates		(82,670)		560,714
Purchase of minerals in place		-		513,643
Net changes in prices and production costs		2,644,294		(491,475)
Accretion of discount		535,978		197,593
Sales of oil produced, net of production costs		(1,094,116)		(802,245)
Development costs incurred during the period		238,760		597,796
Changes in future development costs		(1,493)		(256,408)
Changes in timing of future production		(343,083)		10,794
Net changes in income taxes		-		-
Standardized measure of discounted future net cash flows at the end of the year	$	7,257,450	$	5,359,780

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Statements of Cash Flows (USD $)	12 Months Ended
	Feb. 29, 2012	Feb. 28, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (1,432,584)	$ (1,215,747)
Adjustments to reconcile net loss to net cash used in operating activities:
Stock compensation	91,218	88,508
Gain on write-off of asset retirement obligation	0	(8,324)
Gain on sale of oil and gas properties	0	(10,285)
Depreciation, depletion, and impairment expense	319,905	307,023
Amortization of debt discount	49,128	46,339
Amortization of loan origination fees	11,875	11,875
Bad debt expense (recovery)	(4,142)	(3,928)
Non cash interest income	(602)	(2,124)
Warrant expense for services	0	14,600
Changes in assets and liabilities:
Accounts receivable - oil and gas sales	(6,803)	71,274
Accounts receivable - joint interest participants	51,156	56,025
Accounts receivable - other	73,444	(91,632)
Receivables associated with assets held for sale	0	303,097
Prepaid expenses and other current assets	38,224	(36,266)
Accounts payable and other accrued liabilities	8,577	529,697
Accounts payable - related parties	340,945	124,472
Accrued interest	421,959	69
Net cash provided by (used in) operating activities	(37,700)	184,673
CASH FLOWS FROM INVESTING ACTIVITIES:
Disposition of other assets	0	299,428
Additions to oil and gas properties	(231,388)	(1,454,672)
Net cash used in investing activities	(231,388)	(1,155,244)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable - related parties	235,100	0
Proceeds from credit line	250,000	0
Payment to escrow for loan commitment	(200,000)	0
Proceeds from notes payable	0	780,000
Net cash provided by financing activities	285,100	780,000
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	16,012	(190,571)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	57,380	247,951
CASH AND CASH EQUIVALENTS AT END OF PERIOD	73,392	57,380
Cash paid for Interest	107,684	141,357
Cash paid for Income taxes	0	0
SUPPLEMENTAL CASH FLOW INFORMATION:
Notes payable paid directly from proceeds of line of credit	600,000	0
Travel advances paid directly from proceeds of line of credit	25,000	0
Accrued interest added to note principal	8,905	0
Unpaid additions to oil and gas properties	62,839	271,979
Changes in estimates to asset retirement obligation, net	16,366	14,561
Discount on notes payable - Long term	19,023	5,284
Discount on notes payable - Short term	0	60,210
Conversion of preferred stock to common stock	0	306
Stock issued for loan origination fees		23,750
Cancellation of stock plan issuances	$ 383	$ 0

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Balance Sheets (Parenthetical) (USD $)	Feb. 29, 2012	Feb. 28, 2011
Joint interest participants, allowance for doubtful accounts	$ 0	$ 33,346
Oil and gas properties, accumulated depletion, amortization, and impairment, successful efforts method	1,186,212	871,658
Vehicles and equipment, accumulated depreciation	31,329	31,329
Current notes payable, unamortized debt discount	0	30,105
Long term notes payable, unamortized debt discount	46,149	57,119
Notes payable - related party, unamortized debt discount	$ 33,934	$ 41,987
Common stock, par value in dollars	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	48,787,769	48,791,599
Common stock, shares outstanding	48,787,769	48,791,599
Preferred Stock
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
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	906,565	906,565
Preferred stock, shares outstanding	906,565	906,565
Preferred stock, cumulative dividend rate	6.00%	6.00%

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WARRANTS

12 Months Ended

Feb. 29, 2012

Warrants

WARRANTS

NOTE 10 – WARRANTS:

Common Stock warrants outstanding and exercisable as of February 29, 2012 are set forth in the table below:

Description	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining
Placement Agent Warrants - Spring 2006 PP	802,721	$0.75	1.25	802,721
Placement Agent Warrants - Spring 2006 PP	401,361	$2.00	1.25	401,361
Placement Agent Warrants - July 2006 PP	419,930	$1.00	1.50	419,930
12% Subordinated Note Warrants	1,190,000	$0.14	2.75	1,190,000
Warrants Issued for Services	150,000	$0.14	3.25	150,000
	2,964,012			2,964,012

For the year ended February 29, 2012, a total of 6,963,133 warrants expired. These warrants were issued to private placement subscribers of our Common Stock and Series A Preferred Stock that occurred in the Spring of 2006 and July 2006, respectively. There were no warrants issued or exercised during the year ended February 29, 2012.

As of February 29, 2012 and February 28, 2011, there were 2,964,012 and 9,927,145 warrants issued and outstanding, respectively.

The outstanding warrants as of February 29, 2012, have a weighted average exercise price of $0.68; a weighted average remaining life of 1.99 years; and an intrinsic value of $-0-.

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Document and Entity Information (USD $)	12 Months Ended
	Feb. 29, 2012	May 24, 2012	Aug. 31, 2011
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. 29, 2012
Amendment Flag	false
Current Fiscal Year End Date	--02-29
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			$ 3,030,286
Entity Common Stock, Shares Outstanding		47,787,769
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2012

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RESTRICTED STOCK and RESTRICTED STOCK UNIT PLAN

12 Months Ended

Feb. 29, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

RESTRICTED STOCK and RESTRICTED STOCK UNIT PLAN

NOTE 11 — 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 year 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 year ended February 29, 2012, an aggregate of 912,499 shares vested and 3,830 shares were cancelled and returned to the 2009 Plan

At February 29, 2012, a total of 1,003,830 shares remained available for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is set forth in the table below:

Grant Date	Shares Awarded	Vesting Period	Shares Vested	Shares Returned	Shares Outstanding (Unvested)
4/7/2009	1,900,000	3 Years	1,266,665	-0-	633,335
7/16/2009	25,000	3 Years	16,665	-0-	8,335
7/16/2009	625,000	4 Years	312,500	1,915	312,500
7/22/2010	25,000	3 Years	8,330	-0-	16,670
7/22/2010	425,000	4 Years	106,250	1,915	318,750
	3,000,000		1,710,410	3,830	1,289,590

For the year ended February 29, 2012, the Company recognized compensation expense related to the above restricted stock grants of $91,218. Unamortized compensation expense amounted to $42,054 as of February 29, 2012.

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Statements of Operations (USD $)	12 Months Ended
	Feb. 29, 2012	Feb. 28, 2011
REVENUE:
Oil and gas sales	$ 1,314,124	$ 1,079,496
OPERATING EXPENSES:
Production costs	220,008	172,250
Exploration and drilling	168,177	184,255
Depreciation, depletion, amortization, and impairment	319,905	307,023
Gain on write-off of asset retirement obligation	0	(8,324)
Bad debt expense (recovery)	(4,142)	(3,928)
General and administrative	1,406,046	1,494,969
Total operating expenses	2,109,994	2,146,245
OPERATING LOSS	(795,870)	(1,066,749)
OTHER INCOME (EXPENSE):
Interest income	652	2,126
Interest expense	(637,366)	(162,140)
Total other income (expense)	(636,714)	(160,014)
LOSS FROM CONTINUING OPERATIONS	(1,432,584)	(1,226,763)
DISCONTINUED OPERATIONS
Income from discontinued operations (net of tax of $-0-)	0	731
Gain from sale of oil and gas properties (net of tax of $-0-)	0	10,285
INCOME FROM DISCONTINUED OPERATIONS	0	11,016
NET LOSS	(1,432,584)	(1,215,747)
Cumulative convertible preferred stock dividend requirement	(163,624)	(173,707)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$ (1,596,208)	$ (1,389,454)
NET LOSS PER COMMON SHARE
Loss from continuing operations	$ (0.03)	$ (0.03)
Income from discontinued operations	$ 0.00	$ 0.00
NET LOSS PER COMMON SHARE - Basic and diluted	$ (0.03)	$ (0.03)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - Basic and diluted	48,789,641	48,300,733

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OIL AND GAS PROPERTIES

12 Months Ended

Feb. 29, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

OIL AND GAS PROPERTIES

NOTE 5 — OIL AND GAS PROPERTIES:

On March 19, 2010, the Company closed on the sale of its interest in the East Gilbertown Field in Choctaw County, Alabama to a third party with an effective date of March 1, 2010. There was no effect on net oil and gas property balances from the sale of this property since the Company had previously fully impaired its capitalized cost of approximately $257,000 in this property due to low oil prices in prior periods. In connection with the sale, the Company recognized a gain from sale of oil and gas properties for the year ended February 28, 2011 of $10,285 which is presented under “Discontinued Operations” in the Statement of Operations. The gain resulted mainly from the extinguishment of certain liabilities associated with the Gilbertown interest.

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest from another working interest owner in the East Slopes Project. This purchase resulted in an increase to the gross balances of proved oil and gas properties of approximately $61,869 and unproved oil and gas properties of approximately $421,464.

Oil and gas property balances at February 29, 2012 and February 28, 2011 are set forth in the table below:

	February 29, 2012		February 28, 2011
Proved leasehold costs	$	2,254	$	8,975
Unproved leasehold costs		438,640		452,570
Costs of wells and development		470,653		422,694
Capitalized exploratory well costs		2,316,305		2,229,511
Capitalized asset retirement costs		31,545		47,909
Total cost of oil and gas properties		3,259,397		3,161,659
Accumulated depletion, depreciation amortization and impairment		(1,186,212)		(871,658)
Oil and gas properties, net	$	2,073,185	$	2,290,001

Asset Retirement Obligation

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 oil and gas properties by calculating the present value of estimated cash flows related to the liability. As of February 29, 2012 and February 28, 2011, ARO obligations were considered to be long term based on the estimated timing of the anticipated cash flows. For the years ended February 29, 2012 and February 28, 2011, the Company recognized accretion expense of $5,351 and $5,519, respectively, which is included in DD&A in the statement of operations.

Changes in the asset retirement obligations for the year ended February 29, 2012 are set forth in the table below..

Asset retirement obligation, beginning of period	$	55,122
Accretion expense		5,351
Change in asset retirement estimates		(16,366)
Asset retirement obligation, end of period	$	44,107

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ACCOUNTS RECEIVABLE

12 Months Ended

Feb. 29, 2012

Receivables [Abstract]

ACCOUNTS RECEIVABLE

NOTE 4 — ACCOUNTS RECEIVABLE:

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

Oil and gas sales receivables balances at February 29, 2012 and February 28, 2011 represent oil sales that occurred during the months of February 2012 and 2011, respectively.

Joint interest participant receivables balances at February 29, 2012 and February 28, 2011 represent amounts due from working interest partners net of an allowance for doubtful accounts of $-0- and $33,346, respectively.

Production revenue receivable balance of $350,000 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.

The refund and other receivables balance of $223,750 is primarily comprised of a loan commitment refund for future funding and receivables from contract consulting operations.

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INCOME TAXES

12 Months Ended

Feb. 29, 2012

Income Tax Disclosure [Abstract]

INCOME TAXES

NOTE 12 — 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 29, 2012		February 28, 2011
Computed at U.S. and state statutory rates (40%)	$	(573,035)	$	(486,300)
Permanent differences		37,325		14,731
Changes in valuation allowance		535,710		471,569
Total	$	-0-	$	-0-

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

	February 29, 2012		February 28, 2011
Deferred tax assets:
Net operating loss carryforwards	$	6,319,866	$	5,900,491
Oil and gas properties		(147,148)		(226,994)
Stock based compensation		71,891		35,403
Less valuation allowance		(6,244,609)		(5,708,900)
Total	$	-0-	$	-0-

At February 29, 2012, the Company had a net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $15,799,666, which will begin to expire, if unused, beginning in 2024. The valuation allowance increased by approximately $535,709 for the year ended February 28, 2012 and increased $471,569 for the year ended February 28, 2011. 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 which could change the relationship between net income and taxable income. Management decisions are made annually and could cause the estimates to vary significantly.

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SHORT-TERM AND LONG-TERM BORROWING

12 Months Ended

Feb. 29, 2012

Debt Disclosure [Abstract]

SHORT-TERM AND LONG-TERM BORROWING

NOTE 8 — SHORT-TERM AND LONG-TERM BORROWING:

Short-Term Notes Payable

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest in its East Slopes Project from another working interest owner. The Company financed the additional working interest purchase by issuing, to a third party, Well Works, LLC (“Well Works”), a one-year convertible secured promissory note for the principal amount of $750,000 (the “Well Works Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing. Interest expense related to the Well Works Loan for the year ended February 29, 2012 was $37,500. The interest expense was fully amortized at February 29, 2012. The Company paid in full all amounts due and payable under the Well Work Loan on May 22, 2012.

The Well Works Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in the Company’s East Slopes Project. Furthermore, as a condition precedent to the Well Works Loan, the Company entered into a Technical and Consulting Services Agreement dated September 17, 2010 (the “Consulting Services Agreement”) with Well Works, whereby Daybreak would provide operating, engineering and technical consulting to Well Works for a one-year period for the purpose of evaluating 22 wells in Hutchinson County, Texas for Well Works.

The Company also issued 250,000 shares of the Company’s Common Stock to Well Works as a loan origination fee. The fair value of these shares amounted to $23,750 which was deferred and fully amortized over the original term of the Well Works Loan. Amortization expense for the year ended February 29, 2012 amounted to $11,875. The loan origination fees were fully amortized as of February 29, 2012.

As additional consideration for the Well Works Loan, the Company executed an Assignment of Net Profits Interest dated September 17, 2010 (the “Assignment of Net Profits Interest”) in favor of Well Works, whereby Daybreak assigned two percent of the net profits realized by the Company on its leases in the East Slopes Project. The fair value of the two percent net profits interest was determined to be $60,210 and was recognized as a discount to the debt. The debt discount was deferred and fully amortized over the original term of the Well Works Loan. Amortization expense for the year ended February 29, 2012 amounted to $30,105. The debt discount was fully amortized as of February 29, 2012.

The Company analyzed the Well Works Loan for derivative accounting consideration and determined that derivative accounting did not apply to this instrument.

A Loan Extension Agreement (the “Loan Extension Agreement”) between Well Works and the Company was executed on September 19, 2011 extending the Well Works Loan for a period of 30 days. As compensation for the extension, Daybreak agreed to pay a fee to Well Works of $50,000 and pay interest and legal fees of $16,105 in aggregate.

On October 24, 2011, Well Works and the Company executed a Forbearance Agreement whereby Daybreak requested that Well Works forbear from exercising its rights and remedies under the Well Works Loan and the Loan Extension Agreement from October 19, 2011 to November 10, 2011 (the “Forbearance Period”). The Company agreed to pay interest and legal fees of $21,253 in aggregate during the Forbearance Period. In addition, Daybreak assigned to Well Works a 3% overriding royalty interest proportionately reduced to the Company’s working interest in all its leases in the East Slopes Project effective November 1, 2011. Furthermore, Daybreak and Well Works agreed to cancel, in its entirety, the Assignment of Net Profits Interest. Finally, the Consulting Services Agreement was extended until November 10, 2012.

On November 11, 2011, Well Works and the Company executed a new Forbearance Agreement further extending the date of the payoff from November 11, 2011 to November 18, 2011. As compensation for the extension, Daybreak agreed to pay a fee of $12,500 plus interest due of $3,353 on the entire outstanding balance of the Well Works Loan from November 11, 2011 to November 18, 2011 at an 18% per annum default interest rate.

On November 18, 2011, the Company made a payment to Well Works of $600,000 thereby reducing the outstanding principal balance owed on the Well Works Loan and associated loan interest and fees to $253,581.

On November 19, 2011 Well Works and the Company executed a new Forbearance Agreement (the “Forbearance Agreement II”) further extending the date of the payoff from November 18, 2011 to December 20, 2011 (the “Termination Date”). Daybreak agreed to pay an extension fee of 20% on the outstanding balance of the Well Works Loan, associated fees and interest as of November 19, 2011, or $50,716 plus legal fees of $4,000. Furthermore, interest is payable on the entire outstanding balance of $308,297 for the 30-day period at the default interest rate of 18% per annum, resulting in additional interest of $4,561 for a total balance of $312,858 due on or before the Termination Date.

If the Company is unable to pay on or before the Termination Date all amounts owed under the Forbearance Agreement II, there shall be an additional late fee of $250,000 and an increase in the default interest rate from 18% per annum to 24% per annum (2% per month) until all amounts are repaid. Since the Company was not able to repay the loan by the Termination Date, the Company recognized a late fee of $250,000 which is included in accrued interest as of February 29, 2012.

The Company and Well Works further agreed that the term of the Consulting Services Agreement be extended until December 20, 2012.

On January 30, 2012, the Company and Well Works executed Forbearance Agreement III extending the Termination Date of the Well Works loan to May 20, 2012. Along with the late fee of $250,000 under the Forbearance Agreement II, Daybreak agreed to pay a fee of $25,000 to extend the Termination Date of the loan as well as interest of $11,100 and to make monthly interest payments on the outstanding balance of the Well Works Loan through the Termination Date. Furthermore it was agreed that the Consulting Services Agreement term be extended through May 20, 2013.

At February 29, 2012 the outstanding principal balance of the Well Works Loan was $150,000.

On May 22, 2012, the Company paid off the outstanding principal balance and all interest and fees related to the Well Works Loan. In connection with the Well Works Payoff, the security interest granted by the Company in favor of Well Works in the Company's Kern County, California leases was terminated.

Short-Term Notes Payable (Related Party)

On June 20, 2011, the Company issued a $200,000 non-interest bearing note to the Company’s President and Chief Executive Officer. The term of the note provided for repayment on or before June 30, 2011, or such other date as may be agreed to by the Company and its President. The Company and its President have agreed that repayment will be made upon the successful completion of long-term financing.

Proceeds from the note were used to meet the escrow requirement on a loan commitment from a third party that was announced in June 2011. The escrow requirement amount is reflected as an account receivable on the Balance Sheet and will be refunded to the Company upon closing.

On January 31, 2012, the Company issued a $35,100 non-interest bearing note to the Company’s President and Chief Executive Officer. The term of the note provided for repayment on such other date as may be agreed to by the Company and its President. The Company and its President have agreed that repayment will be made upon the successful completion of long-term financing. Proceeds from the note were used to pay an extension fee related to the Well Works Loan.

Long-Term Notes Payable

12% Subordinated Notes

On January 13, 2010 the Company commenced a private placement of 12% Subordinated Notes (“Notes”). On March 16, 2010, the Company closed its private placement of Notes to 13 accredited investors resulting in total gross proceeds of $595,000. Interest on the Notes accrues at 12% per annum, payable semi-annually. The note principal is payable in full at the expiration of the term of the Notes, which is January 29, 2015. 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, 2014. A total of $250,000 in Notes was sold to a related party, the Company’s President and Chief Executive Officer. The terms and conditions of the related party Note were identical to the terms and conditions of the other participants’ Notes.

In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at the rate of two warrants for every dollar raised through the private placement. The warrants have an exercise price of $0.14 and expire on January 29, 2015. The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $116,557 using the following weighted-average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%. The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method. Amortization expense for the year ended February 29, 2012 amounted to $19,023. Unamortized debt discount amounted to $80,083 as of February 29, 2012.

The Company analyzed the Notes and warrants for derivative accounting consideration and determined that derivative accounting does not apply to these instruments.

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ACCOUNTS PAYABLE

12 Months Ended

Feb. 29, 2012

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE

NOTE 6 — 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 $285,343 of the $1.5 million default remains unpaid and is included in the February 29, 2012 accounts payable balance.

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LINE OF CREDIT

12 Months Ended

Feb. 29, 2012

Line Of Credit

LINE OF CREDIT

NOTE 7 — LINE OF CREDIT:

The Company has an $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 President and Chief Executive Officer. At February 29, 2012, the Company had an outstanding balance of $883,905 with an unused borrowing capacity of $6,095 on the line of credit. Interest is 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.

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STOCKHOLDERS EQUITY (DEFICIT)

12 Months Ended

Feb. 29, 2012

Equity [Abstract]

STOCKHOLDERS EQUITY (DEFICIT)

NOTE 9 — STOCKHOLDERS’ EQUITY (DEFICIT):

Series A Convertible Preferred Stock

The Company is authorized to issue up to 10,000,000 shares of $0.001 par value preferred stock. The Company has designated 2,400,000 shares of the 10,000,000 total preferred shares as “Series A Convertible Preferred Stock” (“Series A Preferred”), with a $0.001 par value. The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s Common Stock.

At February 29, 2012, there were 906,565 shares issued and outstanding, held by accredited investors that had not been converted into the Company’s Common Stock. During the year ended February 29, 2012, there were no shares of Series A Preferred that were converted to shares of Common Stock. As of February 29, 2012, there have been 30 accredited investors convert 493,200 Series A Preferred shares into 1,479,600 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	-	-	-
Totals	493,200	1,479,600	30

Holders of Series A Preferred earn a dividend, in the amount of 6% of the original purchase price per year. Accumulated dividends do not bear interest; and as of February 29, 2012 dividends amounted to $1,134,714. Dividends can be paid in cash or stock at the discretion of the Company and are payable upon declaration by the Board of Directors. Dividends are earned until the Series A Preferred is converted to Common Stock. No dividends have been declared as of February 29, 2012.

Cumulative dividends earned for each fiscal year since issuance is set forth in the table below.

	Shareholders	Accumulated
Fiscal Year Ended	at Period End	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
		$	1,134,714

Common Stock

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock of which 48,787,769 shares were issued and outstanding as of February 29, 2012. For the year ended February 29, 2012 there were no shares issued.

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 11 for the issuances made under the 2009 Plan.

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SUBSEQUENT EVENTS

12 Months Ended

Feb. 29, 2012

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

NOTE 14 — SUBSEQUENT EVENTS:

On May 18, 2012, the Company entered into a loan agreement with a third party as lender and another party as co-borrower, pursuant to which the Company and the co-borrower together borrowed a principal amount of $1,500,000. The Company received $719,062 and the remainder of the loan proceeds were paid to the co-borrower. The loan bears interest at a rate of 5% per month, has a term of 120 days, and may be prepaid at any time in part or in full without premium or penalty. The loan calls for a minimum interest payment of $150,000. Either borrowers’ failure to repay the principal at maturity will constitute an event of default. The loan is a joint and several obligation of the Company and the co-borrower, and is secured by the Company’s currently producing leases in Kern Country, California and certain personal property, accounts receivable and net profits of the co-borrower as well as a personal unconditional guarantee of the loan by the co-borrower’s sole managing member.

On May 22, 2012 the Company paid Well Works $595,744 representing the outstanding principal balance and all interest and fees due in regards to the Well Works Loan that was executed on September 17, 2010. The security interest granted by Daybreak in favor of Well Works in the Company’s Kern County, California leases was terminated.

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Statements of Operations (Parenthetical) (USD $)	12 Months Ended
	Feb. 29, 2012	Feb. 28, 2011
Income Statement [Abstract]
Income from discontinued operations, tax effect	$ 0	$ 0
Gain from sale of oil and gas properties discontinued operations, tax effect	$ 0	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Feb. 29, 2012

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 routinely maintains balances in financial institutions where deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”). As of February 29, 2012, the Company had no cash deposits in excess of FDIC insured limits at various financial institutions.

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. As of February 29, 2012 and February 28, 2011 the Company has recognized an allowance for doubtful accounts of $-0- and $33,346, respectively.

Oil and Gas Properties

The Company uses the successful efforts method of accounting for oil and gas property acquisition, exploration, development, and production activities. Costs to acquire mineral interests in oil and 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 B Codification (“ASC”) Topic 360, “Property, Plant and Equipment” the Company reviews 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. 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 oil and gas. Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s oil and gas properties in subsequent periods. Unproved oil and gas properties that are individually significant are also periodically assessed for impairment of value. An impairment loss for unproved oil and gas properties is recognized at the time of impairment by providing an impairment allowance.

There were no asset impairments recorded for the years ended February 29, 2012 and February 28, 2011.

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 is 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 approximate 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 (“Warrants”) on the grant date using an option-pricing model. The Company uses 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 and natural gas sales or joint interest billings to its working interest partners. 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. Accounts receivable are generally not collateralized. Allowances for doubtful accounts at February 29, 2012 and February 28, 2011 of $-0- and $33,346, respectively relate to amounts due from joint interest owners.

At the Company’s Kern County, California project, there is only one buyer for the purchase of oil production. At February 29, 2012, one customer represented 100.0% of crude oil sales receivable. 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 oil and gas production.

The revenue from all customers is set forth in the table below.

		Twelve Months Ended February 29, 2012			Twelve Months Ended February 28, 2011
Project	Customer	Revenue		Percentage	Revenue		Percentage
California - East Slopes Project	Plains Marketing	$	1,314,124	100.0%	$	975,479	90.4%
Louisiana - Krotz Springs**	J.P. Van Way		-	-		104,017	9.6%
Total Revenues		$	1,314,124	100.0%	$	1,079,496	100.0%

**During the year ended February 28, 2011, the Company received approximately $104,017 in revenue related to the Krotz Springs Field in Louisiana as a one-time adjustment to gas revenue earned in calendar years 2007, 2008 and 2009 due to well production revenue misallocation by the unitized field operator.

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 oil and 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. The Company had no significant imbalances as of February 29, 2012 and February 28, 2011.

Reclamation Bonds

Included in other assets as of February 29, 2012, are funds which 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.

Asset Retirement Obligation

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

On March 1, 2007, the Company adopted 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 oil and gas properties to determine the amount of any impairment of oil and 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 has had, or is 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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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Feb. 29, 2012

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 13 — 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 clean-up 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 29, 2012. 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.