DAYBREAK OIL & GAS, INC. - Annual Report: 2010 (Form 10-K)


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

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

For the fiscal year ended February 28, 2010

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 1012, 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 o 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 o 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 Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, 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 o Noo

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

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


Large accelerated filer o	Accelerated filer o	Non-accelerated filer o	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 o 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 $0.10 on August 31, 2009, as reported by the Over-the-Counter Bulletin Board was $4,225,693.

At May 27, 2010, the registrant had 47,785,599 outstanding shares of $0.001 par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE:

Part III of the Form 10-K incorporates by reference certain portions of the registrant’s proxy statement for its 2010 Annual Meeting of Shareholders to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this report.

TABLE OF CONTENTS


		PAGE

PART I		4
ITEM 1.	DESCRIPTION OF BUSINESS	4
ITEM 1A.	RISK FACTORS	9
ITEM 2.	DESCRIPTION OF PROPERTIES	18
ITEM 3.	LEGAL PROCEEDINGS	23
ITEM 4.	REMOVED AND RESERVED	23
PART II		24
ITEM 5.	MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND SMALL BUSINESS ISSUER PURCHASE OF EQUITY SECURITIES	24
ITEM 6.	SELECTED FINANCIAL INFORMATION	30
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION	31
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	44
	Balance Sheets as of February 28, 2010 and 2009	45
	Statements of Operations for the Years ended February 28, 2010 and 2009	46
	Statements of Changes in Stockholders’ Equity for the Years ended February 28, 2010 and 2009	47
	Statements of Cash Flows for the Years ended February 28, 2010 and 2009	48
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	67
ITEM 9A(T).	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	70
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	70
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	70
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	70
PART IV		71
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	71
GLOSSARY OF TERMS		73
SIGNATURES		76

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 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 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.

PART I

ITEM 1. DESCRIPTION OF BUSINESS

Historical Background

Daybreak Oil and Gas, Inc. (referred to herein as “we,” “our,” “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 1950s, 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 1012, 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

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. We strive to use modern 3-D seismic technology to help us identify potential oil and gas reservoirs and to mitigate our risk. 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.

Significant Customers

At each of our property locations with continuing operations in California and discontinued operations in Alabama, we have oil and gas sales contracts with one dominant purchaser in each respective area. If these purchasers are unable to resell their products or if they lose a significant sales contract then we may incur difficulties in selling our oil and gas. The sales price we receive for oil sales is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) contracts, less deductions which vary by grade of crude oil sold. For the year ended February 28, 2010, the monthly average discount on oil sales from WTI pricing was 11.7% and 28.5% in California and Alabama, respectively. At February 28, 2010, two customers represented 99.7% of crude oil and natural gas sales receivables from all projects in aggregate.

A table disclosing the total amount of revenues from any single customer that exceeds 10% of total revenues follows:


				For the Year Ended February 28, 2010				For the Year Ended February 28, 2009

Project	Location	Product	Customer	Revenue		Percentage		Revenue		Percentage


East Slopes	California	Oil	Plains Marketing	$	469,357	84.5	%	$	1,290	0.6	%

Gilbertown	Alabama	Oil	Hunt Crude Oil Supply	$	84,353	15.2	%	$	148,741	73.7	%

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.

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

Employees and Consultants

At February 28, 2010, we had eight employees and we regularly used the services of three consultants. With the sale of our working interest in the East Gilbertown Field in Alabama effective March 1, 2010, the number of our employees decreased to six employees, of which five are employed on a full-time basis. We also engage consultants on an as-needed basis for accounting, technical, oil field, geological, 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.

Recent Developments

During April 2010, we drilled the Bear #3 and Bear #4 wells at our East Slopes Project in Kern County, California. The Bear #3 well encountered 22 feet of oil pay and the Bear #4 encountered 40 feet of oil pay. Both wells had been placed on production at the end of April 2010.

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 web site at www.daybreakoilandgas.com in the “Shareholder/Financial” section of our web site under the “SEC Filings” button 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 in the “Shareholder/Financial” section of our web site at www.daybreakoilandgas.com under the heading “Corporate Governance.” We intend to promptly disclose via a Current Report on Form 8-K or via an update to our web site, information on any amendment to or waiver of these codes with respect to our executive officers and directors. Waiver information disclosed via the web site will remain on the web site for at least 12 months after the initial disclosure of a waiver. Our Corporate Governance Guidelines and the charters of our Audit Committee, Nominating and Corporate Governance Committee, and Compensation Committee are

also available in the “Shareholder/Financial” section of our web site at www.daybreakoilandgas.com under 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 1012
	Spokane, WA 99201-0613
	Attention: Corporate Secretary
	Telephone: (509) 232-7674

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

ITEM 1A. RISK FACTORS

The following risk factors together with other information set forth in this 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, we have not yet generated a sustainable positive cash flow or earnings. We cannot provide any assurances that we will ever operate profitability. 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;

	•	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 have adversely affected, and in the future may adversely affect, our financial condition, liquidity, results of operations, cash flows, access to the capital markets, and ability to grow.

Our revenues, operating results, liquidity, cash flows, profitability and value 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;

	•	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.

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.

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.

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 future legislation.

The Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States 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 or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

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

In June 2009, the U.S. House of Representatives passed a bill—the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (“ACESA”)—to control and reduce the emission of “greenhouse gases” (“GHGs”), such as carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. The U.S. Senate is currently considering similar legislation that seeks to reduce emission of GHGs in the United States through the granting of emission allowances which would gradually be decreased over time. Moreover, more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of GHGs. Also, on December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has also proposed regulations that would require a reduction in emissions of GHGs from motor vehicles, and this regulatory action, if finalized, could also lead to the imposition of GHG emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. Although our current facilities are not subject to the EPA’s GHG

reporting rule adopted in September 2009, 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. While it is not possible at this time to fully predict how legislation or new regulations that may be adopted in the United States to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas that we produce.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers of Congress would be required to approve identical legislation before it could become law. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

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 expenses 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.

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 each lease, the 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.

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 this 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 Senior Vice-President, Exploration 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 28, 2010 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, you will likely suffer a complete loss of your investment in our securities.

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

We have reported a net loss of approximately $2,259,865 for the year ended February 28, 2010, and we have an accumulated deficit through February 28, 2010 of $21,191,162. Without successful exploration and development of our properties your investment in Daybreak could become devalued or worthless.

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.

An evaluation of our internal controls over financial reporting was conducted for the year ended February 28, 2009 and 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 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 is being designed to reinforce existing resources;

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


	•	a third party has been engaged to assist in efforts to document and test financial reporting controls.

As of the end of the reporting period, February 28, 2010, an evaluation was conducted by Daybreak management, including our President, Chief Executive Officer and 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 28, 2010.

Failure to comply with these 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.

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 “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. In addition, the ability of purchasers in this offering to sell their stock in any secondary market could be adversely restricted.

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 28, 2010, there were 47,785,599 shares of Common Stock and 1,008,565 shares of Series A Convertible Preferred stock outstanding.

In addition to the completed private placements, we may in the future, issue additional previously authorized and unissued Common Stock. These events may result in the further dilution of the ownership interests of our present shareholders and purchasers of Common Stock offered in this prospectus.

Historically we have, and likely will continue to issue additional shares of our Common Stock in connection with the compensation of personnel, future acquisitions, private placements, 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 existing stock ownership.

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

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 these preferred shares. The rights and preferences of the 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 such 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.

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.

ITEM 2. DESCRIPTION OF PROPERTIES

During the past fiscal year, we were involved in onshore oil and gas projects in California, Alabama and Louisiana. In December 2009, we ended our involvement in the Louisiana project. Unless otherwise noted, all of our discussion refers to our continuing operations in California and our discontinued operations in Alabama. We have not filed any estimates of total, proved net oil or gas reserves with any federal agency for the fiscal year ended February 28, 2010. Throughout this Form 10-K, oil is shown in barrels (“Bbls”), and natural gas is shown in thousand cubic feet (“Mcf”). The project areas we are involved in are as follows:

California (East Slopes Project, East Slopes North Project and Expanded AMI Project)

Kern and Tulare Counties. In May 2005, we agreed to jointly explore an area of mutual interest (“AMI”) in the southeastern part of the San Joaquin Basin near Bakersfield, California. As our exploration work has continued, this project has been divided into three major areas referred to as the “East Slopes Project” and the “East Slopes North Project” in Kern County and the “Expanded AMI Project” in Tulare County. Drilling targets are porous and permeable sandstone reservoirs which exist at depths of 1,200 feet to 4,000 feet.

East Slopes Project, Kern County, California. In June 2007, Daybreak and its partners (“Daybreak et al”), entered into a Seismic Option Farmout Agreement with Chevron U.S.A. Inc. (“Chevron”), for a seismic and drilling program in the East Slopes Project area in Kern County, California. By contributing approximately 3,658 acres and paying the full cost of a 35 square mile, high resolution, 3-D seismic survey program over the entire acreage block, referred to herein as the East Slopes Project, Chevron has earned a 50% working interest in the lands contributed by Daybreak et al to the East Slopes Project area. After paying 50% of the cost for drilling and completion of the first four initial earning wells, Daybreak earned a 25% interest in the Chevron lands that were contributed to the East Slopes Project area. We are continuing to evaluate our seismic data and have recently reprocessed it to enhance the quality of the data. We currently have 8 to 10 exploration prospects on this acreage. We expect to add to the exploration prospect inventory in the fiscal year ending February 28, 2011 as a result of the seismic reprocessing.

Sunday Location

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 now fully developed and we have no other plans to drill any more wells in this reservoir. Daybreak owns a 25% working interest and a 16.5% net revenue interest in the Sunday #1 well and a 37.5% working interest and a 27% net revenue interest in each of the Sunday #2 and #3 wells. In the Sunday #4 well we own a 37.5% working interest and a 30.1% net revenue interest.

Bear Location

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. We plan to drill at least three

more development wells during the year ending February 28, 2011. Daybreak owns a 25% working interest and a 16.5% net revenue interest at this location.

Black Location

The Black property was acquired through a farm-in arrangement with a local operator. The Black location is just south of the Bear location on the same fault system. During January 2010, we drilled the Black #1 well. The well was completed and put on production in January 2010. Production is from the Vedder sand at 2,150 feet. Initial results from the production indicate that the reservoir is small. We will monitor the well performance and evaluate it before making any decisions to drill anymore wells. Daybreak owns a 37.5% working interest and a 29.8% net revenue interest at this location.

Sunday Central Processing and Storage Facility

The oil produced from our acreage is considered heavy oil. The oil ranges from 13° to 15° API gravity. All of our oil from the Sunday, Bear and Black locations is processed stored and sold from this facility. The oil must be heated to separate and remove the 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 operating costs have been reduced from over $30 per barrel to under $10 per barrel of oil. By having this central facility and permanent electrical power, it ensures that our operating expenses are kept to a minimum.

Dyer Creek Prospect

This is a Vedder sand prospect located to the north of the Bear reservoir on the same trapping fault. Several wells have been drilled in this prospect with oil pay or shows in the Vedder sand. Several of the wells drilled in the 1960’s were abandoned due to sand control during testing. We plan to twin a well that had 20 feet of oil pay in the Vedder sand that was never properly tested. There are abandoned production facilities on the lease that can be utilized, but some repairs will need to be made and electrical lines will have to be extended from the Bear location.

Ball Prospect

This is a Vedder sand prospect separated by a fault from the Dyer Creek Prospect. Our location will be up dip from an abandoned well that had oil pay in the Vedder sand. 3-D seismic indicates approximately 40 acres of closure, similar to the Bear location. If successful, the Ball wells will be able to utilize the Dyer Creek production facility.

We are currently developing other prospects in the southern portion of our acreage position in the East Slopes Project.

We plan to spend approximately $900,000 in new capital investments within the East Slopes Project area in the fiscal year ending February 28, 2011.

Reserves

At March 1, 2010, we had net proved reserves of 62,155 Bbls of oil in the East Slopes Project according to SEC guidelines as determined by the certified independent engineering firm, Huddleston & Co., Inc.

East Slopes North Project, Kern County, California.

Daybreak has acquired a 25% working interest in a 14,100 acre Seismic Option area under lease. The acreage is immediately north of our East Slopes Project area in Kern County, California. Part of the seismic option area adjoins the prolific oil producing Jasmin Field. We will be exploring the Vedder sands on this acreage block. We plan to shoot a 3-D seismic survey in 2011.

Tulare County, California. The Expanded AMI Project is also located in the San Joaquin Basin in Tulare County and is a separate project area from the East Slopes Project in Kern County. Since 2006, Daybreak and its partners have leased approximately 9,000 acres. Three prospect areas have been identified to the north of the East Slopes Project area in Kern County. A 3-D seismic survey will have to be obtained over the prospect area before any exploration drilling can be done. We anticipate spending $50,000 in the fiscal year ending February 28, 2011 on lease rentals and brokerage fees.

Alabama (East Gilbertown Field)

Choctaw County. In December 2006, we acquired a working interest in an existing oil field project, the East Gilbertown Field that produces relatively heavy oil (approximately 18° API). During the fiscal year ended February 28, 2010, we made the decision to exit this project.

On March 15, 2010, we finalized the sale of our 12.5% working interest in the East Gilbertown Field project located in Choctaw County, Alabama. On April 30, 2010, the Alabama Oil & Gas Board approved our change of Operator request for this Field and our involvement with this project ended. This sale will improve our cash reserves and allow us to focus on projects that better meet our corporate goals and objectives.

Reserves

At March 1, 2010, the Company chose not to evaluate the proved reserves of this field due to the pending disposition of the project.

Louisiana (Krotz Springs Field)

St. Landry Parish. The Krotz Springs Field is a gas play with production coming from a Cockfield Sands reservoir. We were the operator for this project during the drilling and completion phases. When production commenced in May of 2007, the unitized field operator of the Krotz Springs Field became the operator of this well. In December 2009, we withdrew from this project and effectively ended all further involvement in this project.

Total Reserves from All Projects

At March 1, 2010, we had an aggregate amount of net proved reserves of 62,155 Bbls of oil from all of our projects according to SEC guidelines as determined by the certified independent engineering firm, Huddleston & Co., Inc.

Summary Operating Data

The production and revenue shown in the following table is Daybreak’s net share of annual production volume and revenue in each project as of February 28, 2010. Oil is shown in barrels (“Bbls”), and natural gas is shown in thousands of cubic feet (“Mcf”).


		Oil				Gas				Total Revenue

State	Field	Net Bbls		Net Revenue		Net Mcf**		Net Revenue

California	East Slopes		7,480	$	469,357		—	$	—	$	469,357
Alabama	East Gilbertown		1,739		84,353		—		—		84,353
Louisiana	Krotz Springs		—		—		246		2,085		2,085

			9,219	$	553,710		246	$	2,085	$	555,795

** Gas per Mcf (Thousand cubic feet) includes natural gas liquids (wet gas) if any.

The following table shows the average sales price per unit of oil and natural gas as well as the average cost of production in barrels of oil equivalent (“BOE”) conversion, for the past three fiscal years for continuing operations. One barrel of oil is roughly equivalent to 6,000 cubic feet of natural gas. Oil is shown in barrels (“Bbls”), and natural gas is shown in thousands of cubic feet (“Mcf”).


	Average Sales Price						Average Cost of Production*
	Oil (Bbl)		Gas (Mcf)**		BOE		Average Cost of Production*

February 28, 2010	$	60.06	$	7.82	$	51.95	$	33.40
February 28, 2009	$	63.31	$	3.33	$	41.47	$	26.01
February 29, 2008	$	56.13	$	3.00	$	21.67	$	14.21


	*	Variation in Average Cost is due to a change in the percentage mix of yearly oil and gas sales. In fiscal year 2008, we primarily were a gas producer. In fiscal year 2010, we were primarily a heavy oil producer. Additionally, in fiscal year 2010, the temporary production facilities at our East Slopes Project that were in use the majority of the year were replaced during the fourth quarter by permanent facilities.

	**	Gas per Mcf (Thousand cubic feet) includes natural gas liquids (wet gas) if any.

The following table shows the developed and undeveloped oil and gas lease acreage held by us as of February 28, 2010. Undeveloped acres are acres on which 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
Acres

Undeveloped
Acres

Location

Gross

Net

Gross

Net

California

1,729

443

32,532

8,383

Alabama

2,025

253

—

Total

3,539

632

27,777

9,194

The following table summarizes our productive oil and gas wells as of February 28, 2010. 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.


State	Field	Gross	Net

California	East Slopes	7	2.25
Alabama	Gilbertown	17	2.13
Louisiana	Krotz Springs	—	—

Total		24	4.38

The following table shows our exploratory and development well drilling activity for the fiscal years ended February 28, 2010 and 2009. We had no drilling activity in either of our Alabama or Louisiana projects during the time shown in the table below.


	Fiscal Year 2010				Fiscal Year 2009
State	Productive		Dry		Productive		Dry

California
Exploratory		1		—		2		2
Development		4		—		—		—

Total		5		0		2		2

Please see Note 15 under Item 8 of this Form 10-K for more information about our proved reserves.

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. REMOVED AND RESERVED

PART II

ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND SMALL BUSINESS ISSUER PURCHASE 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.


Fiscal Year Ending February 28, 2010	High Closing		Low Closing

First Quarter	$	0.12	$	0.07
Second Quarter	$	0.15	$	0.09
Third Quarter	$	0.14	$	0.10
Fourth Quarter	$	0.14	$	0.10

Fiscal Year Ending February 28, 2009	High Closing		Low Closing

First Quarter	$	0.51	$	0.24
Second Quarter	$	0.51	$	0.29
Third Quarter	$	0.33	$	0.16
Fourth Quarter	$	0.20	$	0.07

As of May 27, 2010, the Company had 2,227 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 web site 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.

Recent Sales of Unregistered Securities

Subordinated Notes

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 the other participants’ Notes.

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 January 29, 2015, 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.

Two Common Stock purchase warrants were issued for every dollar raised through the private placement resulting in a total of 1,190,000 warrants being issued through March 16, 2010. The warrants expire on January 29, 2015 and have an exercise price of $0.14. The fair value of the warrants issued with the Notes, 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.

Common Stock Warrants

For the fiscal year ended February 28, 2010, a total of 4,680,198 warrants expired. These warrants were related to convertible debt term extensions and warrants issued to 2006 private placement participants. Through February 28, 2010, a total of 1,130,000 warrants were issued as a part of the private placement of Notes discussed above. Refer to the discussion above on Subordinated Notes for terms of the warrants issued. There were no warrants exercised during the year. The intrinsic value of all warrants as of February 28, 2010 was $-0-.

Private Placement Sale

On May 22, 2008, Daybreak closed an unregistered offering of its Common Stock through a private placement under the securities transaction exemption Regulation D Rule 506 of the Securities Act of 1933. Shares were offered at $0.25 per share to “accredited investors” only as defined in Regulation D under the Securities Act of 1933. For the year ended February 28, 2009, a total of 60,000 shares of unregistered Common Stock were sold directly by the Company to two investors for $15,000. Net proceeds were used to meet leasehold expenses in California and general and administrative (“G&A”) expenses.

Securities Authorized for Issuance under Equity Compensation Plan

The following table provides information regarding outstanding restricted stock awards for the fiscal year ended February 28, 2010. 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⁾		2,550,000	$	0.105		1,450,000	⁽²⁾

Total		2,550,000	$	0.105		1,450,000	⁽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 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) 625,000 shares of restricted stock awarded to employees; and (iv) 25,000 shares of restricted stock awarded to non-employee directors under our director compensation policy.

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.

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.

Common Stock

The Company is authorized to issue 200,000,000 shares of Common Stock with a par value of $0.001 of which 47,785,599 shares were issued and outstanding as of February 28, 2010. In comparison, at February 28, 2009, a total of 45,079,899 shares were issued and outstanding. This increase of 2,705,700 shares was due to the conversion of Series A Preferred Stock to Common Stock (155,700 shares) and the granting of stock awards to current and former executive officers

(1,000,000 shares), non-employee directors (925,000 shares) and employees (625,000 shares). 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, in action by the Board of Directors, 2,400,000 of these Preferred Stock shares were designated 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. At February 28, 2010, there were 1,008,565 shares issued and outstanding. During the year ended February 28, 2010, there were a total of 51,900 shares of Series A Convertible Preferred Stock that were converted to 155,700 shares of our Common Stock.

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.

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.

ITEM 6. SELECTED FINANCIAL INFORMATION

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

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

The following management’s discussion and analysis (“MD&A”) is management’s assessment of the historical financial and operating results of Daybreak during 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 Form 10-K.

Safe Harbor Provision

Certain statements contained in our Management’s Discussion and Analysis of Financial Condition or Plan of Operation 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. To understand more about forward looking statements, please refer to the section labeled “Cautionary Statement About Forward-Looking Statements” at the beginning of this 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.

We have a limited operating history 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. 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 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.

During the past two fiscal years, we have been involved in the drilling of nine wells in Kern County, California. We have achieved commercial production in seven of these wells. To improve our overall cash flow, we have changed our focus to concentrate on operations in California and have divested our interests in Alabama and Louisiana.

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 level of prices 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 fiscal year ending February 28, 2011, we plan on spending approximately $900,000 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 28, 2010 compared with February 28, 2009 are:


	February 28, 2010			February 28, 2009		Increase (Decrease)			Percentage Change

Cash	$	247,951		$	2,282,810	$	(2,034,859	)		(89.1	%)
Current Assets	$	1,070,541		$	2,784,213	$	(1,713,672	)		(61.5	%)
Total Assets	$	3,010,036		$	3,538,523	$	(528,487	)		(14.9	%)
Current Liabilities	$	1,388,339		$	356,307	$	1,032,032			289.6	%
Total Liabilities	$	1,896,601		$	376,318	$	1,520,283			404.0	%
Working Capital	$	(317,798	)	$	2,427,906	$	(2,745,704	)		(113.1	%)

Our working capital decreased by $2,745,704, from $2,427,906 as of February 28, 2009 to ($317,798) as of February 28, 2010. This decrease was due to the amount of successful drilling activity that we undertook in California; the assumption of the Operator role in California operations; the construction of the associated production facilities in California; and the assumption of the debt of the original default partners in California. The use of these associated production facilities has lowered our operating costs substantially and should assist us in achieving a positive cash flow from operations in 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 Kern County, California. 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 exterior 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 California, we will probably 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 potential economic downturn, may restrict our ability to obtain needed capital.

Cash Flows

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


	For the Year Ended						Increase (Decrease)			Percentage Change
	February 28, 2010			February 28, 2009			Increase (Decrease)			Percentage Change

Net Cash Provided by or (Used in)
Operating activities	$	(2,699,671	)	$	(2,791,659	)	$	(91,988	)		0.3	%
Investing activities	$	99,812		$	5,000,636		$	(4,900,824	)		(98.0	%)
Financing activities	$	565,000		$	14,700		$	550,300			3,743.5	%

Cash Flow Used in Operating Activities

Substantially all of our cash flow from operating activities is derived from the production of our oil reserves. For the year ended February 28, 2010 we had a negative cash flow from operating activities of $2.70 million in comparison to a negative cash flow of $2.79 million from the prior year, a difference of approximately $90,000. Material increases occurred in both accounts receivable and accounts payable in comparison to the prior year. This was a result of our becoming the Operator of our East Slopes Project and having drilled three successful wells in California during the fourth quarter of the fiscal year ended February 28, 2010. Additionally, the assumption of our original defaulted partners’ debt in California increased the accounts payable balance at February 28, 2010, by approximately $432,000. Variations in cash flow from operating activities can directly impact our level of exploration and development expenditures.

Cash Flow Provided by Investing Activities

Cash flow provided by investing activities decreased approximately $4.9 million to $99,812 for the year ended February 28, 2010, in comparison to an approximate $5.0 million from the prior year. This decrease was directly due to the sale of our Tuscaloosa Project property in Louisiana and the Saxet Deep Field project in Texas in the fiscal year ended February 28, 2009. Sources of funds for the current year included the sale of the additional 25% working interest in California that was acquired from our original defaulted partners and the drilling and completion of five additional wells and infrastructure in California. Oil and gas properties showed a net increase of $662,688 as a result of our successful drilling program in California throughout the fiscal year ended February 28, 2010.

Cash Flow Provided by Financing Activities

Cash flow provided by financing activities increased by $550,300 to $565,000 for the fiscal year ended February 28, 2010, in comparison to $14,700 from the prior fiscal year. This increase was directly due to the issuance of our 12% Subordinated Notes in a private placement in January and February 2010.

Changes in Financial Condition

We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations or from financing activities. The cash balance for the year ended February 28, 2010 declined to $247,951. This was a decrease of $2,034,859 from the cash balance at February 28, 2009, of $2,282,810. This decrease was primarily due to successful drilling and completion activities and the installation of our permanent production facilities at our East Slopes Project as well as the payment of a portion of the debt that was assumed from our original default partners in California and on-going G&A expenses.

12% Subordinated Notes

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. This private placement concluded on March 16, 2010. 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 January 29, 2015, 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.

Proceeds from the fundraising 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.

We anticipate it will be necessary to rely on additional funding from the capital markets in the current fiscal year.

Our expenditures consist primarily of exploration and drilling costs; production costs; geological and engineering services; acquiring mineral leases; and travel. 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 necessary organizational activities.

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.

On April 7, 2009, the Compensation Committee of the Board awarded 1,000,000 restricted shares of our Common Stock to a current and a former executive officer of Daybreak. These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of three years.

On April 7, 2009, the Compensation Committee of the Board awarded 900,000 restricted shares of our Common Stock to the five non-employee Directors. These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of three years.

On July 16, 2009, 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 16, 2009, the Compensation Committee of the Board awarded 625,000 restricted shares of our Common Stock to four employees of Daybreak. These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of four years.

At February 28, 2010, a total of 1,450,000 shares remained available for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is shown below:


Grant Date	Shares Awarded	Vesting Period	Shares Vested	Shares Outstanding

4/7/2009	1,900,000	3 Years	0	1,900,000
7/16/2009	25,000	3 Years	0	25,000
7/16/2009	625,000	4 Years	0	625,000

				2,550,000

For the year ended February 28, 2010, we recognized compensation expense related to the above restricted stock grants of $78,146. Unamortized compensation expense amounted to $189,854 as of February 28, 2010.

Results of Operations

Revenues from all projects, both continuing and discontinued operations, experienced a 98.7% increase in the current year to a total of $555,795. The average revenue of a barrel of oil equivalent (BOE) basis for the year ended February 28, 2010 was $58.86 in comparison to $44.96 in the prior year. East Slopes Project revenues increased by $468,067.

Our loss from continuing operations declined from $4.4 million for the year ended February 28, 2009 to $2.4 million for the current year. This decrease in the operating loss of approximately $2 million was due to an improvement in revenues of approximately $420,000, while exploration and

drilling costs decreased by approximately $1.0 million and G&A expenses decreased by approximately $700,000 in comparison to the prior year.

Selected Financial Information

With revenues being received from seven wells from the East Slopes Project during the year ended February 28, 2010, we anticipate being able to continue our growth towards profitability. While we still reported a loss from continuing operations of $2.4 million for the year ended February 28, 2010, this was a substantial improvement of approximately $2 million from the net loss of $4.4 million shown from continuing operations in the prior year. The net loss experienced this year of $2.3 million was greater than the net loss of $0.13 million for the year ended February 28, 2009. The smaller net loss in the prior year was due to the impact of the sale of our Tuscaloosa property in Louisiana.

Our balance sheet at February 28, 2010 shows total assets of $3,010,036 comprised primarily of cash of $247,951; accounts receivable (including oil sales, joint interest participants and assets held for sale) of $800,855; and oil and gas properties (net of Depreciation, Depletion, Amortization and Impairment (“DD&A”)) of $1,193,449. This compares with the February 28, 2009 balances for oil and gas properties of $356,280; cash and marketable securities of $2,282,810 and accounts receivable of $498,513. The above changes can be attributed to the success of our exploratory and development drilling program in California and the assumption of the role as Operator in our East Slopes Project.

At February 28, 2010, we had total liabilities of $1,896,601, comprised of $1,388,339 (including trade, related parties and liabilities associated with assets held for sale), notes payable of $454,944 and $53,318 in asset retirement obligation (“ARO”) as compared with the February 28, 2009 balances for total liabilities of $376,318, comprised of $356,307 in accounts payable and $20,011 in ARO.

Our Common Stock issued and outstanding has increased by 2,705,700 shares during the year ended February 28, 2010. This increase was a result of conversions from our Series A Convertible Preferred Stock (155,700 shares) and awards of restricted stock made under the 2009 Plan (2,550,000) to various current and former executive officers, non-employee directors and employees. Series A Convertible Preferred Stock issued and outstanding decreased by 51,900 shares to 1,008,565 shares as of February 28, 2010, compared to 1,060,465 shares as of February 28, 2009.

Accumulated Deficit

Our financial statements for the year ended February 28, 2010 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 in the accumulated deficit from $18,931,297 as of February 28, 2009, to $21,191,162 was due to the $2,259,865 net loss for the year ended February 28, 2010. The loss from continuing operations for the year ended February 28, 2010, decreased by $2,057,751 to $2,367,464 in comparison to the $4,425,215 loss from the year ended February 28, 2009. We

expect a continuing decrease in net operating loss for the year ending February 28, 2011 due to increased production and lower operating costs experienced at our East Slopes Project.

Management Plans to Continue as a Going Concern

Implementation of plans to enhance Daybreak’s ability to continue as a going concern are underway. During the year ended February 28, 2010, six additional wells at our East Slopes Project contributed to a significant increase in revenues for the Company. Additionally, Daybreak completed the sale of the additional 25% working interest it acquired in California from the default of certain original partners which generated an additional $762,500 during the year. Daybreak plans to continue its development drilling program at a rate that is compatible with its cash flow.

On January 13, 2010, we commenced a private placement of 12% Subordinated Notes. We sold $595,000 of Notes to 13 accredited investors. The private placement concluded on March 16, 2010.

On March 15, 2010, we finalized the sale of our 12.5% working interest in the East Gilbertown Field in Choctaw County, Alabama. On April 30, 2010, the Alabama Oil & Gas Board approved our change of Operator request for this Field and our involvement with this project ended. This sale will improve our cash reserves and allow us to focus on projects that better meet our corporate goals and objectives.

As a result of these transactions and the results of our drilling activity, our liquidity will be substantially improved. In addition, we believe we have the ability to secure additional funding in the capital markets if necessary. We cannot offer any assurance that we will be successful in executing the aforementioned plans to continue as a going concern.

Fiscal Year 2010 Compared to Fiscal Year 2009 – Continuing Operations

This discussion comparing the year ended February 28, 2010 results with the year ended February 28, 2009 results covers our continuing operations in California and the Krotz Springs Field in Louisiana.

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 nine wells in this project. Seven 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.

St. Landry Parish. The Krotz Springs Field is a gas play with current production coming from a Cockfield Sands reservoir. We were the operator for this project during the drilling and completion phases. When production commenced in May of 2007, the unitized field operator of the Krotz Springs Field became the operator of this well. In December 2009, we withdrew from this project and effectively ended all further involvement in this project.

Revenues. The table below shows the revenues derived entirely from the sale of our share of oil and gas production from our continuing operations. Prior to February 2009, we had no revenues from our East Slopes Project.

A table of our revenues for the year 2010 compared to the year 2009 follows:


	2010		2009

California – East Slopes	$	469,357	$	1,290
Louisiana – Krotz Springs		2,085		51,881

Total Revenues	$	471,442	$	53,171

For the year ended February 28, 2010, the East Slopes Project represented 99.6% of total revenues. The Krotz Springs Field in Louisiana revenues represented 0.4% of total revenues. For the year ended February 28, 2010, total revenues from continuing operations increased by $418,271 in comparison with the year ended February 28, 2009. The revenues we recorded for the year ended February 28, 2010 represented our interests in eight producing wells.

Daybreak net sales volume from seven wells at our East Slopes Project for the year ended February 28, 2010 was 7,480 barrels in comparison to 44 barrels from the prior year which only included one month of sales. The average sales price of a barrel of oil for the year ended February 28, 2010 was $63.01 in comparison to $29.13 in the year ended February 28, 2009.

Costs and Expenses. Total operating expenses declined by 37.0% or $1,670,847 for the fiscal year ended February 28, 2010 as compared to the year ended February 28, 2009. The decreases in exploration costs of $1,002,982, bad debt expense of $213,179 and G&A expenses of $703,120 were offset by increases in production costs of $212,772 and DD&A expenses of $35,662. The increases in production costs and DD&A were due to the costs associated with seven wells producing at our East Slopes Project in Kern County, California. G&A expense declined due to salary reductions taken by our executive officers and an aggressive cost control program and lower accounting and legal expenses.

A table of our costs and expenses for the year 2010 compared to the year 2009 follows:


	2010		2009

Production Costs	$	269,820	$	57,048
Exploration Costs		301,912		1,304,894
Depreciation, Depletion, Amortization & Impairment		550,755		515,093
Bad Debt Expense		113,528		326,707
General & Administrative		1,606,874		2,309,994

Total Operating Expenses	$	2,842,889	$	4,513,736

Expenses incurred by the Company include production costs associated directly with the generation of oil and gas revenues (also including well workover projects and plugging and abandonment activities); unsuccessful exploratory drilling; lease rentals; DD&A and impairment charges; and, G&A expenses (including legal and accounting expenses, director and management fees, investor relations expenses, and other G&A costs).

Production costs increased $212,772 or 372.9% for the year ended February 28, 2010 and relate directly to the seven wells that were operating at our East Slopes Project during the year ended February 28, 2010, in comparison to the one well that operated for two months in the prior year.

Now that permanent production facilities have been installed we expect the production costs to decrease dramatically, as we have already seen during the fourth quarter of the fiscal year ended February 28, 2010.

Exploration expenses decreased $1,002,982 or 76.9% from the year ended February 28, 2009. The majority of this decrease was because of the two dry holes that were drilled in at our East Slopes Project during the prior year. For the year ended February 28, 2010, we did not drill any dry holes.

DD&A and impairment expenses increased $35,662 or 6.9% from the year ended February 28, 2009. This increase relates directly to having seven producing wells in at our East Slopes Project during the year ended February 28, 2010.

G&A costs including bad debt expense decreased $916,299 or 34.8% from the year ended February 28, 2009. This decrease was due to increased efforts to limit our overall administrative costs. Areas where we experienced significant reductions included: executive officer salary reductions ($151,887) plus associated payroll taxes; other management, consulting and director fees ($94,815); and bad debt expense ($213,178). Additionally, accounting and legal fees were reduced by approximately $173,952.

Interest and dividend income decreased $24,440 or 64.4% from the prior year due primarily to lower cash balances.

Interest expense increased by $6,927 due to the issuance of the 12% Subordinated Notes in January and February of 2010.

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 and impairment costs will depend upon the factors cited above, as well as numerous other factors including general market conditions. An immediate goal for this current year is to improve cash flow to cover the current level of G&A expenses and to fund our development drilling in California.

Fiscal Year 2010 Compared to Fiscal Year 2009 – Discontinued Operations

This discussion comparing the year ended February 28, 2010 results with year ended February 28, 2009 results covers our discontinued operations in the East Gilbertown Field in Alabama; the Saxet Field project in Texas and the Tuscaloosa project in Louisiana.

During the year ended February 28, 2009, the Company finalized the disposal of two oil and gas properties, the Tuscaloosa Project in Louisiana during the first quarter; and the Saxet Deep Field in Texas during the fourth quarter.

Effective March 1, 2010, Daybreak assigned its interest in the East Gilbertown Field in Alabama to a third party. The cost and expense information for both the years ended February 28, 2010 and, 2009 for the East Gilbertown Field reflect certain credits that result in this information being additions to revenue rather than deductions from revenue.

In accordance with the guidance governing the accounting for impairment or disposal of long-lived assets, net results of operations for the East Gilbertown Field, the Saxet Field and the Tuscaloosa project are presented on the Statement of Operations in the caption “Discontinued Operations” under the appropriate fiscal years.


	Year Ended February 28, 2010		Year Ended February 28, 2009

Gas & oil sales revenue – Tuscaloosa Project	$	—	$	234,474
Cost and expenses		—		(115,092	)

Income (loss) from discontinued operations	$	—	$	119,382


	Year Ended February 28, 2010		Year Ended February 28, 2009

Gas & oil sales revenue – Saxet Deep Field	$	—	$	77,728
Cost and expenses		—		(144,459	)

Income (loss) from discontinued operations	$	—	$	(66,731	)


	Year Ended February 28, 2010		Year Ended February 28, 2009

Oil sales revenue – East Gilbertown Field	$	84,353	$	148,741
Cost and expenses		23,246		32,506

Income (loss) from discontinued operations	$	107,599	$	181,247

Off-Balance Sheet Arrangements

As of February 28, 2010, 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.

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 FASB 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.

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 its 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 28, 2010 and 2009.

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.

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.

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 28, 2010 and 2009 and the related statements of operations, stockholders’ equity, 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 28, 2010 and 2009 and the results of its operations and 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 28, 2010

DAYBREAK OIL AND GAS, INC.

Balance Sheets

As of February 28, 2010 and 2009


	2010			2009

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	247,951		$	2,282,810
Accounts receivable:
Oil and gas sales		257,110			13,731
Joint interest participants, net of allowance for doubtful accounts of $16,237 and $3,848 respectively		215,648			288,548
Receivables associated with assets held for sale, net of allowance for doubtful accounts of $38,012 and $11,255 respectively		303,097			196,234
Production revenue receivable		25,000			—
Prepaid expenses and other current assets		21,735			2,890

Total current assets		1,070,541			2,784,213
OIL AND GAS PROPERTIES, net of accumulated depletion, depreciation, amortization, and impairment, of $1,783,258 and $1,583,113 respectively, successful efforts method
Proved properties		1,193,449			356,280
Unproved properties		17,350			—
VEHICLES AND EQUIPMENT, net of accumulated depreciation of $29,841 and $23,753 respectively		1,488			7,576
PRODUCTION REVENUE RECEIVABLE - LONG TERM		325,000			—
OTHER ASSETS		402,208			390,454

Total assets	$	3,010,036		$	3,538,523


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,240,909		$	323,572
Accounts payable-related parties		31,898			7,384
Liabilities associated with assets held for sale		110,124			25,351
Accrued interest		5,408			—

Total current liabilities		1,388,339			356,307
LONG TERM LIABILITIES:
Notes payable, net of discount of $110,056		454,944			—
Asset retirement obligation		53,318			20,011

Total liabilities		1,896,601			376,318
COMMITMENTS
STOCKHOLDERS’ EQUITY:
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; 1,008,565 shares and 1,060,465 shares issued and outstanding respectively		1,009			1,061
Common stock- 200,000,000 shares authorized; $0.001 par value, 47,785,599 and 45,079,899 shares issued and outstanding respectively		47,786			45,081
Additional paid-in capital		22,255,802			22,047,360
Accumulated deficit		(21,191,162	)		(18,931,297	)

Total stockholders’ equity		1,113,435			3,162,205

Total liabilities and stockholders’ equity	$	3,010,036		$	3,538,523

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

45

DAYBREAK OIL AND GAS, INC.

Statements of Operations

For the Years ended February 28, 2010 and 2009


	Years Ended

	February 28, 2010			February 28, 2009

REVENUE:
Oil and gas sales	$	471,442		$	53,171


OPERATING EXPENSES:
Production costs		269,820			57,048
Exploration and drilling		301,912			1,304,894
Depreciation, depletion, amortization, and impairment		550,755			515,093
Bad debt expense		113,528			326,707
General and administrative		1,606,874			2,309,994

Total operating expenses		2,842,889			4,513,736

OPERATING LOSS		(2,371,447	)		(4,460,565	)


OTHER INCOME (EXPENSE):
Interest income		13,487			7,671
Dividend income		—			30,256
Interest expense		(9,504	)		(2,577	)

Total other income (expense)		3,983			35,350


LOSS FROM CONTINUING OPERATIONS		(2,367,464	)		(4,425,215	)

DISCONTINUED OPERATIONS
Income from discontinued operations (net of tax of $ -0-)		107,599			233,898
Gain from sale of oil and gas properties (net of tax of $ -0-)		—			4,060,820

INCOME FROM DISCONTINUED OPERATIONS		107,599			4,294,718


NET LOSS		(2,259,865	)		(130,497	)

Cumulative convertible preferred stock dividend requirement		(188,824	)		(208,878	)


NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(2,448,689	)	$	(339,375	)


NET INCOME (LOSS) PER COMMON SHARE
Loss from continuing operations	$	(0.05	)	$	(0.10	)
Income from discontinued operations		0.00			0.09
NET LOSS PER COMMON SHARE - Basic and diluted	$	(0.05	)	$	(0.01	)


WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - Basic and diluted		47,207,830			44,731,420

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

46

DAYBREAK OIL AND GAS, INC.

Statements of Changes in Stockholders’ Equity

For the Years ended February 28, 2009 and 2010


	Series A Convertible Preferred Stock						Common Stock				Additional Paid-In Capital			Accumulated Deficit

	Shares			Amount			Shares		Amount								Total


BALANCE, FEBRUARY 29, 2008		1,297,465		$	1,298			44,293,299	$	44,294	$	21,980,785		$	(18,800,800	)	$	3,225,577

Issuance of common stock for:
Cash		—			—			60,000		60		14,640			—			14,700
Conversion of preferred stock		(237,000	)		(237	)		711,000		711		(474	)		—			—
Other		—			—			15,600		16		(16	)		—			—

Issuance of goodwill warrants		—			—			—		—		52,425			—			52,425

Net loss		—			—			—		—		—			(130,497	)		(130,497	)


BALANCE, FEBRUARY 28, 2009		1,060,465			1,061			45,079,899		45,081		22,047,360			(18,931,297	)		3,162,205


Issuance of common stock for:
Services		—			—			2,550,000		2,550		75,596			—			78,146
Conversion of preferred stock		(51,900	)		(52	)		155,700		155		(103	)		—			—

Issuance of warrants related to private placement		—			—			—		—		21,676			—			21,676
Warrants issued in connection with debt		—			—			—		—		111,273			—			111,273

Net loss		—			—			—		—		—			(2,259,865	)		(2,259,865	)


BALANCE, FEBRUARY 28, 2010		1,008,565		$	1,009			47,785,599	$	47,786	$	22,255,802		$	(21,191,162	)	$	1,113,435

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

47

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows

For the Years ended February 28, 2010 and 2009


	Years Ended

	February 28,			February 28,

	2010			2009


CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(2,259,865	)	$	(130,497	)
Adjustments to reconcile net loss to net cash used in operating activities:
Shares issued for services		78,146			—
Gain on sale of oil and gas properties		—			(4,060,820	)
Depreciation, depletion, and impairment expense		551,430			624,575
Amortization of debt discount		1,217			—
Bad debt expense		113,528			326,707
Non cash interest and dividend income		(11,754	)		(5,427	)
Non cash general and administrative expense		21,676			52,425
Changes in assets and liabilities:
Investment in marketable securities		—			155,445
Accounts receivable - oil and gas sales		(243,379	)		(135,598	)
Accounts receivable - joint interest participants		(147,491	)		216,013
Prepaid expenses and other current assets		(18,845	)		18,052
Accounts payable and other accrued liabilities		(789,742	)		147,466
Accrued interest		5,408			—

Net cash used in operating activities		(2,699,671	)		(2,791,659	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of reclamation bond		—			(100,000	)
Additions to oil and gas properties		(662,688	)		(716,646	)
Proceeds from sale of oil and gas properties		762,500			5,812,500
Additions to oil and gas prepayments		—			4,782

Net cash provided by investing activities		99,812			5,000,636

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of notes payable		565,000			—
Proceeds from sales of common stock, net		—			14,700

Net cash provided by financing activities		565,000			14,700

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(2,034,859	)		2,223,677
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		2,282,810			59,133

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	247,951		$	2,282,810

CASH PAID FOR:
Interest	$	4,096		$	2,577
SUPPLEMENTAL CASH FLOW INFORMATION:
Acquisition of additional working interest through assumption of liability	$	1,454,372		$	—
Unpaid additions to oil and gas properties	$	361,994		$	—
Conversion of preferred stock to common stock	$	155		$	—
Debt discount from warrants issued with debt	$	111,273		$	711

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

48

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 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 “we,” “our,” “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.

Exploration Stage Company

On March 1, 2005 (the inception date), the Company commenced oil and gas exploration and development activities. As of August 31, 2009, the Company emerged from its development stage status due to the production and revenue generated by its California oil and gas properties and as such the additional financial disclosure category “Inception to Date” in its statements of operations, stockholders’ equity and cash flows is no longer presented.

NOTE 2 — GOING CONCERN:

Financial Condition

Daybreak’s financial statements for the year ended February 28, 2010 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 $21,191,162, which raises substantial doubt about the Company’s ability to continue as a going concern.

Management Plans to Continue as a Going Concern

Implementation of plans to enhance Daybreak’s ability to continue as a going concern are underway. During the fiscal year ended February 28, 2010, six additional wells at our East Slopes Project contributed to a significant increase in revenues for the Company. Additionally, Daybreak completed the sale of the additional 25% working interest it acquired in California from the default of certain original partners which generated an additional $762,500 during the year. The Company plans to continue its development drilling program at a rate that is compatible with its cash flow.

On January 13, 2010 we commenced a private placement of 12% Subordinated Notes. We sold $595,000 of Notes to 13 accredited investors through March 16, 2010, the date the private placement concluded.

On March 15, 2010, the Company finalized the sale of its 12.5% working interest in the East Gilbertown Field in Choctaw County, Alabama. On April 30, 2010, the Alabama Oil & Gas Board approved a change of Operator request for this Field and consequently the Company’s involvement with this project

ended. The sale is expected to improve the Company’s cash reserves and allow Daybreak to focus on projects that better meet the Company goals and objectives. In addition, the Company believes it has the ability to secure additional debt or equity funding, if necessary.

Daybreak’s financial statements as of February 28, 2010 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.

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”) in excess of the federally insured amount of $250,000. As of February 28, 2010, 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. For the years ended February 28, 2010 and 2009 the Company has recognized an allowance for doubtful accounts of $54,249 and $15,103 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.

Pursuant to the provisions of FASB 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.

Asset impairments of $341,871 and $494,871 were recorded for the years ended February 28, 2010 and 2009, respectively which is included in Depreciation, Depletion, Amortization and Impairment (“DD&A”) in the statement of operations.

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 lives of three years.

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 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 our 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.

At each of the Company’s three producing projects, there is only one buyer for the purchase of oil or gas production. At February 28, 2010, two customers represented 99.7% of crude oil and natural gas sales receivable from all projects in aggregate.

A table disclosing the total amount of revenues from any single customer that exceeds 10% of total revenues follows:


				For the Year Ended February 28, 2010				For the Year Ended February 28, 2009

Project	Location	Product	Customer	Revenue		Percentage		Revenue		Percentage


East Slopes	California	Oil	Plains Marketing	$	469,357		84.5%	$	1,290	0.6%

Gilbertown	Alabama	Oil	Hunt Crude Oil Supply	$	84,353		15.2%	$	148,741	73.7%

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 28, 2010 and 2009.

Reclamation Bonds

Included in other assets as of February 28, 2010, are funds which have been pledged as collateral in connection with asset retirement obligations for future plugging, abandonment and site remediation in various states. The amounts pledged for operator bonds in California, Alabama and Louisiana are approximately $100,000, $250,000 and $25,000 plus accrued interest respectively. The pledging of these funds is required by the various states 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.

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 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 abandonment obligations.

Recent Accounting Pronouncements

During the third quarter of the year ended February 28, 2010, the Company adopted FASB Accounting Standards Codification (“ASC” or “Codification”) and the Hierarchy of Generally Accepted Accounting Principles (“GAAP”) which establishes the Codification as the sole source for authoritative U.S. GAAP and will supersede all accounting standards in U.S. GAAP, aside from those issued by the SEC. The adoption of the Codification did not have an impact on the Company’s results of operations, cash flows or financial position. Since the adoption of the ASC, the Company’s notes to the consolidated financial statements will no longer make reference to Statement of Financial Accounting Standards (SFAS) or other U.S. GAAP pronouncements.

During the first quarter of the fiscal year ended February 28, 2010, in accordance with FASB ASC Topic 855, “Subsequent Events”, the Company adopted the standards on subsequent events. This pronouncement establishes standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. The Company evaluated all events and transactions after February 28, 2010 through the date these financial statements were issued.

During the first quarter of the year ended February 28, 2010, the Company adopted the guidance for estimating fair value when the volume and level of activity for an asset or liability has significantly decreased as well as the guidance on identifying circumstances that indicate a transaction is not orderly. The Company has determined that the adoption of this guidance did not have an impact on the Company’s operating results, financial position or cash flows.

During first quarter of the fiscal year ended February 28, 2010, the Company adopted the guidance on determining whether an instrument (or embedded feature) is indexed to an entity’s own stock. This guidance requires entities to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock in order to determine if the instrument should be accounted for as a derivative. The guidance is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. The Company has determined that the adoption of this pronouncement did not have an impact on the Company’s operating results, financial position or cash flows.

In December 2008, the SEC released Final Rule, “Modernization of Oil and Gas Reporting.” The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require that companies 1) report the independence and qualifications of its reserves preparer or auditor, 2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit, and 3) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. We have adopted these changes and conformed our reserves estimation and disclosure practices in accordance with the guidance contained in this release.

Reclassifications

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

NOTE 4 — ACCOUNTS RECEIVABLE – JOINT INTEREST PARTICIPANTS:

In January 2008, the Company instituted legal action against California Oil and Gas Company (“COGC”), a 25% working interest participant, for their default in meeting the financial commitments in the drilling and completion of the KSU #59 well in Louisiana. On November 17, 2008, the Company requested a summary judgment against COGC and on December 9, 2008, a written order for summary judgment against COGC was entered by the court. On March 2, 2009 COGC assigned its undeveloped interest in the Dyer Creek and S.E. Edison Projects in Kern County, California and undeveloped leases in Tulare County, California, along with the COGC interest in the Krotz Springs Field to satisfy the judgment. As of February 28, 2009, the Company had received $166,891 from the net production revenue in the Krotz Springs Field in partial satisfaction of the debt. Receivables from COGC that were deemed to be uncollectable amounting to $311,604 were written off during the year.

In March 2009, the Company became Operator of its East Slopes Project, and as such, it is responsible for collecting from its other working interest partners reimbursement of lease rentals that have occurred. As of February 28, 2009, receivables related to these lease rentals amounted to $152,427. This outstanding balance was collected during the year ended February 28, 2010.

NOTE 5 — OIL AND GAS PROPERTIES:

Oil and gas properties, at cost:


	February 28, 2010			February 28, 2009

Proved leasehold costs	$	58,142		$	51,422
Unproved leasehold costs		17,350			—
Costs of wells and development		1,442,949			1,881,463
Capitalized exploratory well costs		1,439,126
Capitalized asset retirement costs		36,490			6,508

Total cost of oil and gas properties		2,994,057			1,939,393
Accumulated depletion, depreciation, amortization and impairment		(1,783,258	)		(1,583,113	)

Oil and gas properties, net	$	1,210,799		$	356,280

On June 11, 2009, the Company closed on the sale of the additional 25% working interest in its East Slopes project, which was acquired from the default of its Canadian company partners (see Note 6), to a group of three Texas companies. Pursuant to the terms of the sale agreement, the Company received in June 2009, a cash payment of $512,500, and recorded a production revenue receivable equal to $700,000. The Company continues to own its original 25% working interest in the project. The excess of the net book value over the selling price (approximately $242,000) was recorded as an impairment loss in accordance with ASC 360.

During the quarter ended August 31, 2009, the Company agreed to an upfront payment on a portion of the production revenue receivable due from two of the three Texas entities that acquired an interest in the Company’s East Slopes project. This agreement resulted in a reduction of the selling price of the additional 25% interest sold on June 11, 2009, by $100,000 which was recognized as an additional impairment loss. This upfront payment was received by the Company on September 25, 2009.

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 28, 2010 and 2009, ARO obligations were considered to be long term based on the estimated timing of the anticipated cash flows. For the years ended February 28, 2010 and 2009, the Company recognized accretion expense of $3,325 and $2,739, respectively, which is included in DD&A in the statement of operations.

The following table describes the changes in the asset retirement obligations for the year ended February 28, 2010.


Asset retirement obligations, beginning of period	$	20,011
Accretion expense		3,325
Asset retirement additions		31,280
Change in asset retirement estimates		(1,298	)
Asset retirement eliminations due to sale of assets		—

Asset retirement obligations, end of period	$	53,318

NOTE 6 — ACCOUNTS PAYABLE:

On March 1, 2009, the Company became the operator for both its East Slopes and Expanded AMI Project areas in California. Additionally, the Company then assumed the original defaulting partners’ approximate $1.5 million liability from 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 (see Note 5). Approximately $432,084 of the $1.5 million default remains unpaid and is included in the February 28, 2010 accounts payable balance.

NOTE 7 — NOTES PAYABLE:

12% Subordinated Notes

On January 13, 2010 the Company commenced a private placement of 12% Subordinated Notes (“Notes”). As of February 28, 2010, the Company had sold $565,000 of Notes to 12 accredited investors. The private placement concluded on March 16, 2010. A total of $250,000 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 other participants’ Notes. The Notes are subject to an annual interest rate of 12%, payable semi-annually, and mature in full on January 29, 2015. On the maturity date, the Company may 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.

Two Common Stock purchase warrants were issued for every dollar raised through the private placement resulting in 1,130,000 warrants being issued through February 28, 2010. The warrants expire on January 29, 2015 and have an exercise price of $0.14. The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $111,273 using the following weighted-average assumptions: a risk free interest rate of 2.33%; volatility of 147.7%; 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.

NOTE 8 — DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE:

The Company finalized the disposal of two oil and gas properties during the year ended February 28, 2009. The properties disposed of were the Tuscaloosa Project in Louisiana and the Saxet Deep Field in Texas.

The following tables present the revenues and expenses related to the Tuscaloosa Project and the Saxet Deep Field for the years ended February 28, 2010 and 2009.


	2010		2009

Oil and gas sales revenues	$	—	$	312,202
Cost and expenses		—		(259,551	)

Income from discontinued operations	$	—	$	52,651

On March 15, 2010, the Company finalized the sale of its 12.5% working interest in the East Gilbertown Field located in Choctaw County, Alabama by assigning its interest to a third party. On April 30, 2010, the Alabama Oil and Gas Board approved the Company’s change of Operator request for this field and the Company’s involvement in this project ended.

The following tables present the revenues and expenses related to the East Gilbertown Field for the years ended February 28, 2010 and 2009. The cost and expense information for both the years ended February 28, 2010 and 2009 for the East Gilbertown Field reflect certain credits that result in this information being additions to revenue rather than deductions from revenue.


	2010		2009

Oil sales revenue – East Gilbertown Field	$	84,353	$	148,741
Cost and expenses		23,246		32,506

Income from discontinued operations	$	107,599	$	181,247

Oil and gas properties held for sale, at cost – East Gilbertown Field:


	February 28, 2010			February 28, 2009

Proved leasehold costs	$	248,149		$	248,149
Unproved leasehold costs		—			—
Costs of wells and development		—			—
Unevaluated capitalized exploratory well costs		—			—
Capitalized asset retirement costs		7,371			7,371

Total cost of oil and gas properties		255,520			255,520
Accumulated depletion, depreciation, amortization and impairment		(255,520	)		(255,520	)

Oil and gas properties, net	$	—		$	—

NOTE 9 — STOCKHOLDERS’ EQUITY:

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 28, 2010, there were 1,008,565 Series A Preferred shares outstanding that had not been converted into the Company’s Common Stock.

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 28, 2010 dividends amounted to $789,420. 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 28, 2010.

The table below details the cumulative dividends earned for each fiscal year since issuance:


Fiscal Year Ended	Shareholders at Period End		Accumulated Dividends

February 28, 2007		100	$	153,966
February 29, 2008		90		237,752
February 28, 2009		78		208,878
February 28, 2010		74		188,824

Total Accumulated Dividends			$	789,420

Common Stock

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock of which 47,785,599 shares were issued and outstanding as of February 28, 2010.

During the year ended February 28, 2010, the Company issued a total of 155,700 shares of Common Stock in connection with the conversion of 51,900 shares of Series A Convertible Preferred Stock.

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:

Warrants outstanding and exercisable as of February 28, 2010 are as follows:


Description	Warrants		Exercise Price		Remaining Life (Years)		Exercisable Warrants Remaining

Spring 2006 Common Stock Private Placement		4,013,602	$	2.00		1.25		4,013,602
Placement Agent Warrants - Spring 2006 PP		802,721	$	0.75		3.25		802,721
Placement Agent Warrants - Spring 2006 PP		401,361	$	2.00		3.25		401,361
July 2006 Preferred Stock Private Placement PP		2,799,530	$	2.00		1.50		2,799,530
Placement Agent Warrants - July 2006 PP		419,930	$	1.00		3.50		419,930
Convertible Debenture Term Extension		150,001	$	2.00		1.75		150,001
Placement Agent Warrants - January 2008 PP		39,550	$	0.25		1.00		39,550
12% Subordinated Notes		1,130,000	$	0.14		4.75		1,130,000

		9,756,695						9,756,695

For the year ended February 28, 2010, a total of 4,680,198 warrants expired. These warrants were related to convertible debt term extensions and warrants issued to 2006 private placement participants. A total of 1,130,000 warrants were issued as a part of the private Placement of Notes. Refer to Note 7 for details of these issuances. There were no warrants exercised during the year.

The outstanding warrants as of February 28, 2010 have a weighted average exercise price of $1.63; a weighted average remaining life of 2.11 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.

On April 7, 2009, the Compensation Committee of the Board awarded 1,000,000 restricted shares of the Company’s Common Stock to a current and a former executive officer of the Company. These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of three years.

On April 7, 2009, the Compensation Committee of the Board awarded 900,000 restricted shares of the Company’s Common Stock, to the five non-employee members of the Board of Directors. These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of three years.

On July 16, 2009, the Compensation Committee of the Board awarded 25,000 restricted shares of the Company’s Common Stock to the five non-employee directors, as 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 16, 2009, the Compensation Committee of the Board awarded 625,000 restricted shares of the Company’s Common Stock, to four employees of the Company. These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of four years.

At February 28, 2010, a total of 1,450,000 shares remained available for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is shown below:


Grant Date	Shares Awarded		Vesting Period	Shares Vested	Shares Outstanding

4/7/2009		1,900,000	3 Years	0		1,900,000
7/16/2009		25,000	3 Years	0		25,000
7/16/2009		625,000	4 Years	0		625,000

						2,550,000

For the year ended February 28, 2010, the Company recognized compensation expense related to the above restricted stock grants of $78,146. Unamortized compensation expense amounted to $189,854 as of February 28, 2010.

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:


	2010

Computed at U.S. and State statutory rates (40%)	$	(903,946	)
Permanent differences		12,900
Changes in valuation allowance		891,046

Total	$	—

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


	2010			2009

Deferred tax assets:
Net operating loss carryforwards	$	5,114,269		$	4,130,040
Oil and gas properties		123,062			216,245
Less valuation allowance		(5,237,331	)		(4,346,285	)

Total	$	—		$	—

At February 28, 2010, the Company had a net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $12,785,673, which will begin to expire, if unused, beginning in 2024. The valuation allowance increased by approximately $891,046 for the fiscal year ended February 28, 2010 and by $26,465 for the fiscal year ended February 28, 2009. Section 382 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.

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 28, 2010. 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:

12% Subordinated Notes

On March 16, 2010, the Company received the final $30,000 of the proceeds from our 12% Subordinated Notes (the “Notes”) offering that commenced on January 13, 2010. A total of 60,000 warrants were issued in connection with this Note under the same terms as discussed in Note 7.

Warrants for Services

On April 16, 2010, the Compensation Committee of the Board granted a third party 150,000 Common Stock purchase warrants as compensation for services. The terms of the warrants are identical to the terms of the warrants issued in conjunction with the 12% Subordinated Notes described above in Note 7.

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 and Louisiana.

Capitalized Costs Relating to Oil and Gas Producing Activities


	As of
	February 28, 2010			February 28, 2009


Proved properties
Mineral interests	$	58,142		$	51,422
Wells, equipment and facilities		2,918,565			1,887,971

Total proved properties		2,976,707			1,939,393

Unproved properties
Mineral interests		17,350			—
Uncompleted wells, equipment and facilities		—			—

Total unproved properties		17,350			—

Less accumulated depreciation, depletion, amortization and impairment		(1,783,258	)		(1,583,113	)

Net Capitalized Costs	$	1,210,799		$	356,280

Costs Incurred in Oil and Gas Producing Activities


	Twelve Months Ended
	February 28, 2010		February 28, 2009

Acquisition of proved properties	$	6,720	$	2,839
Acquisition of unproved properties		17,350		—
Development costs		952,154		468,701
Exploration costs		301,912		1,322,852

Total Costs Incurred	$	1,278,136	$	1,794,392

Results of Operations from Oil and Gas Producing Activities


	Twelve Months Ended
	February 28, 2010			February 28, 2009


Oil and gas revenues	$	555,795		$	514,114
Production costs		(164,528	)		(327,632	)
Exploration expenses		(301,912	)		(1,304,894	)
Depletion, depreciation, amortization and impairment		(544,667	)		(624,574	)

Result of oil and gas producing operations before income taxes		(455,312	)		(1,742,986	)
Provision for income taxes		—			—

Results of Oil and Gas Producing Operations	$	(455,312	)	$	(1,742,986	)

Proved Reserves

The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, Huddleston & Co., Inc. 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 (Bbls)			Gas (Mcf)**			BOE

Proved reserves:
February 29, 2008		13,112			65,500			24,029
Revisions⁽¹⁾		(68	)		(31,257	)		(5,278	)
Extensions and discoveries		17,250			—			17,250
Production		(4,119	)		(27,220	)		(8,656	)
Purchases (sales) of minerals-in-place		(8,925	)		(7,023	)		(10,095	)

February 28, 2009		17,250			—			17,250
Revisions⁽²⁾		(10,414	)		—			(10,414	)
Extensions and discoveries		45,184			—			45,184
Production		(3,142	)		—			(3,142	)
Purchases (sales) of minerals-in-place		13,277			—			13,277

February 28, 2010		62,155			—			62,155

** Gas per Mcf (Thousand cubic feet) includes natural gas liquids (wet gas) if any.


	(1)	The revisions of previous estimates for the fiscal year ended February 28, 2009, resulted from a revised lower estimate of reserve value due to depressed hydrocarbon prices in the energy markets.

	(2)	The revisions of previous estimates for the fiscal year ended February 28, 2010, resulted from a revised lower estimate of reserve value after continued reservoir production.

The Company’s proved reserves are as follows:


	Developed						Undeveloped
													Total
	Oil (Bbls)		Gas (Mcf)		BOE (Bbls)		Oil (Bbls)		Gas (Mcf)		BOE (Bbls)		BOE (Bbls)

February 28, 2010		38,648		—		38,648		23,507		—		23,507	62,155
February 28, 2009		8,625		—		8,625		8,625		—		8,625	17,250
February 29, 2008		12,515		58,000		22,182		597		7,500		1,847	24,029

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

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of February 28, 2010 and 2009 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 year ended February 28, 2009 were estimated by applying year-end oil prices adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves. The resulting net cash flows are reduced to present value by applying a 10% discount factor. Use of a 10% discount rate and year-end prices were required for 2009. At February 28, 2010, as specified by the SEC, the price for oil used in this calculation was the unweighted 12-month average of the first day of the month (12 month unweighted average) cash price quotes.


	Twelve Months Ended
	February 28, 2010			February 28, 2009


Future cash inflows	$	3,657,798		$	597,368
Future production costs ⁽¹⁾		(809,091	)		(151,111	)
Future development costs		(345,567	)		(12,500	)
Future income tax expenses ⁽²⁾		—			—

Future net cash flows		2,503,140			433,757
10% annual discount for estimated timing of cash flows		(527,212	)		(77,478	)

Standardized measure of discounted future net cash flows at the end of the year	$	1,975,928		$	356,279


	(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.

See the following table for average prices.


	Average Price

Year Ended	Oil (Bbl)		Gas (Mcf)**

February 28, 2010	$	58.86	$	7.82
February 28, 2009	$	35.40	$	3.33
February 29, 2008	$	56.13	$	3.00

** Gas per Mcf (Thousand cubic feet) includes natural gas liquids (wet gas) if any.

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 year end are set forth in the table below.


	Twelve Months Ended

	February 28, 2010			February 28, 2009


Standardized measure of discounted future net cash flows at the beginning of the year	$	356,279		$	1,130,265
Extensions, discoveries and improved recovery, less related costs		1,849,004			—
Revisions of previous quantity estimates		(333,444	)		(37,959	)
Changes in estimated future development costs		—			(464,940	)
Purchases of minerals in place		—			370,671
Sales of minerals in place		—			(954,039	)
Net changes in prices and production costs		270,243			(116,325	)
Accretion of discount		35,628			113,027
Sales of oil and gas produced, net of production costs		(207,641	)		(186,482	)
Development costs incurred during the period		112,343			464,939
Changes in future development costs		(142,978	)		37,122
Changes in timing of future production		36,494			—
Net change in income taxes		—			—

Standardized measure of discounted future net cash flows at the end of the year	$	1,975,928		$	356,279

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

None.

ITEM 9A(T). CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

As of the end of the reporting period, February 28, 2010, an evaluation was conducted by Daybreak management 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 in a manner to allow timely decisions regarding required disclosures.

Management (with the participation of our President, Chief Executive Officer and interim principal finance and accounting officer) determined that as of February 28, 2010, these disclosure controls and procedures are effective ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

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

Our management 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. Management assessed the effectiveness of our internal control over financial reporting as of February 28, 2010. In making this assessment, management used certain criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on such

assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of February 28, 2010.

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 temporary rules of the SEC that permit the company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the fourth quarter ended February 28, 2010 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

PART III

Certain information required by Part III is omitted from this Annual Report on Form 10-K because we will file a definitive proxy statement pursuant to Regulation 14A (the “Proxy Statement”), not later than 120 days after the end of the fiscal year covered by this Form 10-K, and certain information to be included therein is incorporated herein by reference.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Information regarding our Ethical Business Conduct Policy Statement and the Code of Ethics for Senior Financial Officers is described in the introductory pages of this Annual Report under the caption “Website / Available Information.” The information required by Item 10 that relates to our directors and executive officers is incorporated by reference from the information appearing under the captions “Proposal Number 1: Election of Directors,” “Executive Officers,” “Corporate Governance,” “Section 16(a) Beneficial Ownership Reporting Compliance” and “Report of the Audit Committee of the Board of Directors” in our Proxy Statement.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 that relates to compensation of our principal executive officers and our directors is incorporated by reference from the information appearing under the captions “Executive Compensation”, “Director Compensation”, “Compensation Committee Report” and “Compensation Committee Interlocks and Insider Participation” in our Proxy Statement.

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

The information required by Item 12 that relates to the ownership of securities by management and others is incorporated by reference from the information appearing under the caption “Security Ownership of Certain Beneficial Owners and Management” in our Proxy Statement.

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

The information required by Item 13 that relates to business relationships and transactions with our management and other related parties is incorporated by reference from the information appearing under the captions “Corporate Governance”, “Board Leadership, Structure and Risk Oversight” and “Transactions Between the Company and Management” in our Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by Item 14 that relates to services provided by our registered public accounting firm and the fees incurred for services provided during fiscal years 2010 and 2009 is incorporated by reference from the information appearing under the caption “Fees Billed by Independent Public Accountants” in our Proxy Statement.

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⁾

23.1	Consent of Huddleston & Co., Inc. ⁽¹⁸⁾


23.2	Consent of MaloneBailey, LLP ⁽¹⁸⁾

31.1	Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 ⁽¹⁸⁾

32.1	Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ⁽¹⁸⁾

99.1	Reserves Audit Report of Huddleston & Co., Inc., independent petroleum engineering consulting firm, dated May 6, 2010. ⁽¹⁸⁾

(1)	Previously filed as exhibit to Form 8-K on April 9, 2008, and incorporated by reference herein.

(2)	Previously filed as exhibits to Form 10-K on May 28, 2009, and incorporated by reference herein.

(3)	Previously filed as exhibit to Form SB-2 on July 18, 2006, and incorporated by reference herein. (filed as part of the Articles of Amendment to the Articles of Incorporation of Daybreak Oil & Gas, Inc. dated June 30, 2006.)

(4)	Previously filed as exhibits to Form SB-2 on July 18, 2006, and incorporated by reference herein.

(5)	Previously filed as exhibits to Form 10-KSB on September 21, 2007, and incorporated by reference herein.

(6)	Previously filed as exhibits to Form S-8 filed on April 7, 2009 and incorporated by reference herein.

(7)	Previously filed as exhibits to Form 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)	Filed herewith.

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

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.

BOE. Means a barrel of oil equivalent and is a 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 gross the sum of fractional ownership working interest 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.

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

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

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

Proved reserves. Proved 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.

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.

SIGNATURES

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


	DAYBREAK OIL AND GAS, INC.

	By:	/s/ JAMES F. WESTMORELAND

		James F. Westmoreland, its President, Chief Executive Officer and interim principal finance and accounting officer
		Date: May 28, 2010

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 28, 2010		Date: May 28, 2010

By:	/s/ TIMOTHY R. LINDSEY	By:	/s/ WAYNE G. DOTSON

	Timothy R. Lindsey		Wayne G. Dotson
	Director		Director
	Date: May 28, 2010		Date: May 28, 2010

By:	/s/ RONALD D. LAVIGNE	By:	/s/ JAMES F. MEARA

	Ronald D. Lavigne		James F. Meara
	Director		Director
	Date: May 28, 2010		Date: May 28, 2010