UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended August 31, 2009
OR
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)

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

(Former name, former address and former fiscal year, if changed since last report)

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. þ Yes o No

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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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	(Do not check if a smaller reporting company)	Smaller reporting company þ

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

At October 9, 2009 the registrant had 47,629,899 outstanding shares of $0.001 par value common stock.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION
ITEM 1.	Financial Statements	3
	Balance Sheets at August 31, 2009 and February 28, 2009 (Unaudited)	3
	Statements of Operations for the Three and Six Months Ended August 31, 2009 and August 31, 2008 (Unaudited)	4
	Statements of Cash Flows for the Three and Six Months Ended August 31, 2009 and August 31, 2008 (Unaudited)	5
	Notes to Unaudited Financial Statements	6
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	26
ITEM 4T.	Controls and Procedures	26
PART II - OTHER INFORMATION
ITEM 1.	Legal Proceedings	28
ITEM 1A.	Risk Factors	28
ITEM 4.	Submission of Matters to a Vote of Security Holders	28
ITEM 6.	Exhibits	29
Signatures		30

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PART I
FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DAYBREAK OIL AND GAS, INC.
Balance Sheets - Unaudited
	As of August 31, 2009			As of February 28, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	129,529		$	2,282,810
Accounts receivable:
Oil and gas sales		163,352			17,636
Joint interest participants, net of allowance for doubtful accounts of $6,155		759,209			291,998
Receivables associated with assets held for sale, net of allowance for doubtful accounts of $11,254		301,359			188,879
Production revenue receivable		250,000			—
Prepaid expenses and other current assets		4,557			2,890
Total current assets		1,608,006			2,784,213
OIL AND GAS PROPERTIES, net of accumulated depletion, depreciation, amortization, and impairment, successful efforts method
Proved properties		614,524			356,280
Unproved properties		17,350			—
VEHICLES AND EQUIPMENT, net of accumulated depreciation of $28,975 and $23,753 respectively		2,355			7,576
Production revenue receivable - long term		450,000			—
OTHER ASSETS		398,602			390,454
Total assets	$	3,090,837		$	3,538,523
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,147,887		$	356,307
Liabilities associated with assets held for sale		25,655			—
Total current liabilities		1,173,542			356,307
OTHER LIABILITIES
Asset retirement obligation		35,987			20,011
Total liabilities	$	1,209,529		$	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; 1,060,465 shares issued and outstanding		1,061			1,061
Common stock- 200,000,000 shares authorized; $0.001 par value, 47,629,899 and 45,079,899 shares issued and outstanding respectively		47,631			45,081
Additional paid-in capital		22,103,090			22,047,360
Accumulated deficit		(20,270,474	)		(18,931,297	)
Total stockholders’ equity		1,881,308			3,162,205
Total liabilities and stockholders’ equity	$	3,090,837		$	3,538,523

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

3

DAYBREAK OIL AND GAS, INC.

Statements of Operations - Unaudited

	For the Three Months Ended August 31,						For the Six Months Ended August 31,
	2009			2008			2009			2008
REVENUE:
Oil and gas sales	$	130,147		$	29,024		$	167,420		$	39,736
OPERATING EXPENSES:
Production costs		134,958			(14,653	)		198,445			18,296
Exploration and drilling		66,460			158,921			103,925			244,344
Depreciation, depletion, amortization, and impairment		44,709			18,402			352,585			36,054
Bad debt expense		2,306			—			76,689			—
General and administrative		410,819			420,226			844,150			863,723
Total operating expenses		659,252			582,896			1,575,794			1,162,417
OPERATING LOSS		(529,105	)		(553,872	)		(1,408,374	)		(1,122,681	)
OTHER INCOME (EXPENSE):
Interest income		7,911			4,236			9,869			7,465
Dividend income		—			—			—			—
Interest expense		(76	)		(3	)		(764	)		(363	)
Total other income (expense)		7,835			4,233			9,105			7,102
LOSS FROM CONTINUING OPERATIONS		(521,270	)		(549,639	)		(1,399,269	)		(1,115,579	)
DISCONTINUED OPERATIONS
Income (loss) from discontinued operations (net of tax of $ -0-)		50,249			11,102			60,092			179,166
Gain from sale of oil and gas properties (net of tax of $ -0-)		—			3,993,441			—			3,993,441
INCOME FROM DISCONTINUED OPERATIONS		50,249			4,004,543			60,092			4,172,607
NET LOSS		(471,021	)		3,454,904			(1,339,177	)		3,057,028
Cumulative convertible preferred stock dividend requirement		(51,289	)		(55,284	)		(102,578	)		(108,556	)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(522,310	)	$	3,399,620		$	(1,441,755	)	$	2,948,472
NET INCOME (LOSS) PER COMMON SHARE
Loss from continuing operations	$	(0.01	)	$	(0.01	)	$	(0.03	)	$	(0.02	)
Income from discontinued operations		—			0.09			—			0.09
NET LOSS PER COMMON SHARE - Basic and diluted	$	(0.01	)	$	0.08		$	(0.03	)	$	0.07
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - Basic and diluted		47,311,964			44,683,419			46,763,866			44,567,319

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

4

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows - Unaudited

	Six Months Ended August 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,339,177	)	$	3,057,028
Adjustments to reconcile net loss to net cash used in operating activities:
Common stock issued for services		36,604			—
Gain on sale of oil and gas properties		—			(3,993,441	)
Depreciation, depletion, and impairment expense		353,030			105,317
Bad debt expense		76,689			—
Non cash interest and dividend income		(8,148	)		(3,459	)
Non cash general and administrative expense		21,676			—
Changes in assets and liabilities:
Accounts receivable - oil and gas sales		(174,296	)		(162,045	)
Accounts receivable - joint interest participants		(648,888	)		393,829
Prepaid expenses and other current assets		(1,667	)		20,942
Accounts payable and other accrued liabilities		(623,338	)		(182,468	)
Net cash used in operating activities		(2,307,515	)		(764,297	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of marketable securities, net		—			(2,853,718	)
Purchase of reclamation bond		—			(100,000	)
Additions to oil and gas properties		(358,266	)		(2,840	)
Proceeds from sale of oil and gas properties		512,500			5,812,500
Additions to oil and gas prepayments		—			4,782
Net cash provided by investing activities		154,234			2,860,724
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sales of common stock, net		—			14,700
Net cash provided by financing activities		—			14,700
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(2,153,281	)		2,111,127
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		2,282,810			59,133
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	129,529		$	2,170,260
CASH PAID FOR:
Interest	$	764		$	363
SUPPLEMENTAL CASH FLOW INFORMATION:
Acquisition of additional working interest through assumption of liability	$	1,500,201		$	—

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

5

DAYBREAK OIL AND GAS, INC.
NOTES TO UNAUDITED FINANCIAL STATEMENTS

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

Organization

Originally incorporated as Daybreak Uranium, Inc. under the laws of the State of Washington on March 11, 1955, the Company 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., (the “Company” or “Daybreak”) to better reflect the business of the Company.

All of the Company’s oil and gas production is sold under contracts which are market-sensitive. Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. These factors include the level of global demand for 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.

Basis of Presentation

The accompanying unaudited interim financial statements and notes for the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q for quarterly reports under Section 13 or 15 (d) of the Securities Exchange Act of 1934 (the “Exchange Act”). Accordingly, they do not include all of the information and footnotes disclosures normally required by accounting principles generally accepted in the United States of America for complete financial statements.

In the opinion of management, all adjustments considered necessary for a fair presentation have been included and such adjustments are of a normal recurring nature. Operating results for the six months ended August 31, 2009 are not necessarily indicative of the results that may be expected for the fiscal year ending February 28, 2010.

These financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual report on Form 10-K for the year ended February 28, 2009.

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’s management believes that the Company has emerged from its development stage status due to the production and revenue generated by its California oil and gas properties and as such will no longer be presenting the additional financial disclosure category “Inception to Date” that is set forth in SFAS No. 7, “Accounting for Development Stage Entities” (“SFAS No. 7”) in its statements of operations, stockholders’ equity and cash flows.

6

Use of Estimates

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 period. 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.

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 2 — GOING CONCERN

Financial Condition

The Company’s financial statements for the six months ended August 31, 2009 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. The Company has incurred net losses since inception and as of August 31, 2009 has an accumulated deficit of $20,270,474, 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 the Company’s ability to continue as a going concern are underway. The Company is continuing its strategy to develop the East Slopes Project in California through existing cash flow. Additionally, the Company is pursuing the sale of its interest in the East Gilbertown Field in Alabama. Upon receiving final regulatory approval from the State of Alabama for the change of the operator in the East Gilbertown Field, the Company would recover $250,000 in cash collateral which the Company posted to secure an operator-bond in Alabama. Also, the Company plans to seek additional debt or equity funding, if necessary.

The Company’s financial statements as of August 31, 2009 do not include any adjustments that might result from the inability to implement or execute the plans to improve its ability to continue as a going concern.

7

NOTE 3 — RECENT ACCOUNTING PRONOUNCEMENTS

In June 2009, the Financial Accounting Standards Board issued FAS No. 168, “The Financial Accounting Standards Board Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“FAS 168”). FAS 168 replaces Statement of Financial Accounting Standards No. 162, The Hierarchy of Generally Accepted Accounting Principles, to establish the Financial Accounting Standards Board Accounting Standards Codification as the source of authoritative accounting principles recognized by the Financial Accounting Standards Board to be applied by nongovernmental entities in preparation of financial statements in conformity with generally accepted accounting principles in the United States. FAS 168 is effective for interim and annual periods ending after September 15, 2009. The Company does not expect the adoption of this standard to have an impact on its consolidated financial position or results of operations.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“FAS 165”). FAS 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which any entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. FAS 165 is effective for interim and annual periods ending after June 15, 2009 and applies prospectively. The adoption of this standard did not have a material impact on the financial position, results of operations or cash flows of the Company. The Company evaluated all events and transactions after August 31, 2009 through October 9, 2009, the date these financial statements were issued. During this period, the Company did not have any recognizable or non-recognizable subsequent events.

In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FAS 157-4”) to amend SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS 157 when the volume and level of activity for an asset or liability has significantly decreased. In addition, FAS 157-4 includes guidance on identifying circumstances that indicate a transaction is not orderly. FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009. 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 June 2008, FASB ratified EITF No. 07-05, “Determining Whether an Instrument (or an Embedded Feature) Is Indexed to an Entity’s Own Stock” (“EITF 07-05”). EITF 07-05 provides that an entity should use a two-step approach to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock, including evaluating the instrument’s contingent exercise and settlement provisions. EITF 07-05 became effective March 1, 2009, and 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 Securities and Exchange Commission (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, 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. The Company is currently assessing the impact, if any, that the adoption of the pronouncement will have on the Company’s operating results, financial position or cash flows.

8

NOTE 4 — CONCENTRATION OF CREDIT RISK

Substantially all of the Company’s accounts receivable result from natural gas and crude oil sales or joint interest billings to third parties in the oil and gas industry. 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 two producing projects, there is only one or two buyers for the purchase of oil or gas production. At August 31, 2009, three customers represented 100% of crude oil and natural gas sales receivable from all projects in the aggregate.

In accordance with the provisions of SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information,” a table disclosing the total amount of revenues from any single customer that exceeds 10% of total revenues follows:

				Three Months Ended August 31, 2009				Three Months Ended August 31, 2008
Project	Location	Product	Customer	Revenue		Percentage		Revenue		Percentage
East Slopes	California	Oil	Plains Marketing	$	129,665	84.5	%	$	—	—
East Gilbertown Field	Alabama	Oil	Hunt Crude Oil Supply	$	23,239	15.1	%	$	52,652	49.7	%

				For the Six Months Ended August 31, 2009				For the Six Months Ended August 31, 2008
Project	Location	Product	Customer	Revenue		Percentage		Revenue		Percentage
East Slopes	California	Oil	Plains Marketing	$	166,318	79.0	%	$	—	—
East Gilbertown Field	Alabama	Oil	Hunt Crude Oil Supply	$	43,205	20.5	%	$	102,160	49.9	%

NOTE 5 — OIL AND GAS PROPERTIES

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, to a group of three Texas companies. The terms of the sale agreement called for a cash payment of $512,500 and a production revenue payment 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 $232,000) was recorded as an impairment loss in accordance with SFAS 144.

During the quarter ended August 31, 2009, the Company agreed to an upfront payment on a portion of the production revenue due from one of the three Texas entities that acquired an interest in the Company’s East Slopes project. This agreement reduced production revenue receivable – long term by $225,000 and increased

9

production revenue receivable (short term) by the same amount. This upfront payment was received by the Company on September 25, 2009.

NOTE 6 — ACCOUNTS PAYABLE

During January 2009, the Company was notified by its non-Chevron working interest partners, including the project operator, that they could no longer financially continue in the East Slopes Project in California. As a result, these partners defaulted on a portion of the financial obligation of their respective working interests for the drilling and completion costs of the four earning wells program and the Company assumed an additional 25% working interest in the project. On March 1, 2009, the Company became the operator for both of the California project areas. Additionally, the Company then assumed the 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 $631,784 of the $1.5 million default remains unpaid and is included in the August 31, 2009 accounts payable balance.

NOTE 7 — DISCONTINUED OPERATIONS

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. There is no comparative information presented for the Tuscaloosa project for the quarter ended August 31, 2008 since the property was disposed of during the quarter ended May 31, 2008.

The Company is actively pursuing efforts to sell its interest in the East Gilbertown Field in Alabama. In accordance with the provisions of SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), net results of operations for the East Gilbertown Field are presented on the Statement of Operations in the caption “Discontinued Operations”.

The following tables present the revenues and expenses related to the above projects for the three month and six month periods ended August 31, 2009 and August 31, 2008. Prior period income statement amounts applicable to the above projects have been reclassified and included under Income (loss) from discontinued operations. The cost and expense information for both the three month and six month presentations of the current year for the East Gilbertown Field reflect certain non-recurring credits and reclassifications that result in this information being additions to revenue rather than deductions from revenue.

	Three Months Ended August 31, 2009			Three Months Ended August 31, 2008
Oil and gas sales revenue – Saxet Deep Field	$	—		$	24,238
Cost and expenses		(—	)		(32,488	)
Income (loss) from discontinued operations	$	—		$	(8,250	)
	Three Months EndedAugust 31, 2009			Three Months EndedAugust 31, 2008
Oil sales revenue – East Gilbertown	$	23,239		$	52,652
Cost and expenses		27,010			(22,531	)
Income (loss) from discontinued operations	$	50,249		$	30,121

10

	Six Months Ended August 31, 2009			Six Months Ended August 31, 2008
Oil and gas sales revenue – Saxet Deep Field	$	—		$	62,968
Cost and expenses		(—	)		(66,294	)
Income (loss) from discontinued operations	$	—		$	(3,326	)
	Six Months Ended August 31, 2009			Six Months Ended August 31, 2008
Oil sales revenue – East Gilbertown	$	43,205		$	102,160
Cost and expenses		16,887			(39,050	)
Income (loss) from discontinued operations	$	60,092		$	63,110

NOTE 8 — SERIES A CONVERTIBLE PREFERRED STOCK

The Company has designated 2,400,000 shares of the authorized 10,000,000 preferred shares as Series A Convertible Preferred Stock (“Series A Stock”), with a $0.001 par value. The Series A Stock can be converted by the shareholder at any time into three shares of the Company’s common stock. As of August 31, 2009, there have been 339,300 shares of the originally issued 1,399,765 shares of Series A Stock converted by 22 shareholders into 1,017,900 shares of the Company’s common stock.

NOTE 9 — SERIES A CONVERTIBLE PREFERRED STOCK DIVIDEND

A component of the Series A Convertible Preferred Stock is a 6% annual cumulative dividend based on the original purchase price of the shares. The dividends may be paid in cash or common stock at the discretion of the Company. Accumulations of annual dividends do not bear interest and are not payable until a dividend is declared by the Company. Dividends are earned until the Series A Stock is converted to common stock.

The table below details the cumulative dividends for each fiscal year since issuance and the interim six months of the current fiscal year:

Fiscal Period	Shareholders at Period End	Accumulated Dividends
Year Ended February 28, 2007	100	$	153,936
Year Ended February 29, 2008	90		237,741
Year Ended February 28, 2009	78		208,855
Six Months Ended August 31, 2009	78		102,578
Total Accumulated Dividends		$	703,110

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NOTE 10 — WARRANTS

Warrants outstanding and exercisable as of August 31, 2009 are:

Description	Warrants		Exercise Price		Remaining Life (Years)		Exercisable Warrants Remaining
Spring 2006 Common Stock Private Placement		4,013,602	$	2.00		1.75		4,013,602
Placement Agent Warrants Spring 2006 PP		802,721	$	0.75		3.75		802,721
Placement Agent Warrants Spring 2006 PP		401,361	$	2.00		3.75		401,361
July 2006 Preferred Stock Private Placement		2,799,530	$	2.00		2.00		2,799,530
Placement Agent Warrants July 2006 PP		419,930	$	1.00		4.00		419,930
Convertible Debenture Term Extension		150,001	$	2.00		2.25		150,001
Convertible Debenture 3rd Term Extension		90,000	$	0.25		0.25		90,000
Spring 2006 PP Goodwill Warrants		3,227,934	$	0.65		0.50		3,227,934
July 2006 PP Goodwill Warrants		1,250,264	$	0.65		0.50		1,250,264
Placement Agent Warrants January 2008 PP		39,550	$	0.25		1.50		39,550
		13,194,893						13,194,893

For the six months ended August 31, 2009, no warrants were issued or exercised. During the quarter ended August 31, 2009, a total of 112,000 warrants expired. These warrants were issued for a term extension on convertible debentures. As of August 31, 2009 and February 28, 2009, there were 13,194,893 and 13,306,893 warrants issued and outstanding respectively. The intrinsic value of all warrants at August 31, 2009 was $-0-.

NOTE 11 — RESTRICTED STOCK and RESTRICTED STOCK UNIT PLAN

On April 6, 2009, the Board of Directors (the “Board”) of the Company 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. 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.

On July 16, 2009, the Compensation Committee of the Board approved awards of restricted shares of the Company’s common stock to five non-employee directors as a part of their annual compensation. A total of 25,000 restricted shares were granted pursuant to the 2009 Plan and vest in three annual increments or upon the retirement of the Director from the Board.

On July 16, 2009, the Compensation Committee of the Board approved awards of restricted shares of the Company’s common stock to four employees of the Company. A total of 625,000 restricted shares were granted pursuant to the 2009 Plan and generally vest in four annual increments.

At August 31, 2009, 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

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For the three and six months ended August 31, 2009, the Company recognized compensation expense related to the above restricted stock grants of $15,833 and $36,604 respectively. Unamortized compensation expense amounted to $231,396 as of August 31, 2009.

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 rates to income from continuing operations before income taxes is as follows:

	Six Months Ended			Six Months Ended
	August 31, 2009			August 31, 2008
Computed at U.S. and state statutory rates (40%)	$	(558,562	)	$	(624,400	)
Permanent differences		9,636			40,100
Changes in valuation allowance		548,926			584,300
Total	$	—		$	—

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

	Six Months Ended August 31, 2009			Six Months Ended February 28, 2009
Deferred tax assets:
Net operating loss carryforwards	$	4,749,944		$	4,130,040
Oil and gas properties		107,734			216,245
Stock based compensation		37,533			—
Less valuation allowance		(4,895,211	)		(4,346,285	)
Total	$	—		$	—

At August 31, 2009, the Company had estimated net operating loss carryforwards for federal and state income tax purposes of approximately $11,874,860 which will begin to expire, if unused, beginning in 2024. The valuation allowance increased approximately $548,926 for the six months ended August 31, 2009 and increased by $26,465 for the year ended February 28, 2009. Section 382 Rule will place annual limitations on the Company’s net operating loss (NOL) carryforward.

The above estimates are based on management’s decisions concerning 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

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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 August 31, 2009. There can be no assurance; however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) 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.

Some statements contained in this Form 10-Q report relate to results or developments that we anticipate will or may occur in the future and are not statements of historical fact. All statements other than statements of historical facts contained in this MD&A report are inherently uncertain and are forward-looking statements. 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. Factors that might cause such a difference include:

• 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,

• 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, and

• Regulatory uncertainties and potential environmental liabilities.

• Availability of capital to the Company.

The following MD&A is management’s assessment of the historical financial and operating results of the Company and is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our financial statements and notes thereto included elsewhere in this Form 10-Q and in our Annual Report on Form 10-K for the year ended February 28, 2009. Unless otherwise noted, all of our discussion refers to our continuing operations in the California and Louisiana locations.

Introduction and Overview

The following discussion of our results of operations for the three and six month periods ended August 31, 2009 and August 31, 2008 and of our financial condition as of August 31, 2009, should be read in conjunction with the unaudited financial statements and notes thereto included in this Form 10-Q and with the Company’s latest audited financial statements as reported in its Annual Report on Form 10-K for the fiscal year ended February 28, 2009.

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

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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.

Plan of Operation

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.

During the year ended February 28, 2009, and throughout the current six months, we have experienced volatile oil and gas prices that were affected by many factors outside of our control. This 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.

Reduced demand for energy caused by the current recession resulted in a significant deterioration in oil and gas prices during the second half of 2008 and the first quarter of 2009. This in turn led to a significant reduction in drilling activity throughout the oil and gas industry. The prices we pay for field services have declined as a result of reduced demand for those services.

During the quarter ended August 31, 2009, operating margins improved somewhat due to an improvement in oil prices and the lower rates for field services. The effects of improved operating margins on our business are significant since they increase our cash flow from operations and increase the present value of our oil and gas reserves.

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 California. To date in California, we have drilled two successful exploratory wells and two developmental wells as well as two non-commercial wells. We have spent most of the last quarter working on installing permanent production facilities and electrical service to our wells in California. Once completed, we believe these efforts will lower our production costs on each well.

Our longer-term success depends on, among many other factors, the acquisition and drilling of commercial grade oil and gas properties and the prevailing prices of oil and natural gas. Oil and natural gas prices have been extremely volatile in recent years and are affected by many factors outside our control. This 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.

Liquidity and Capital Resources

Liquidity is the ability to convert assets into cash or to obtain cash. Short-term liquidity refers to the ability to meet short-term obligations of 12 months or less. Liquidity is a matter of degree and is expressed in terms of a ratio. Two common liquidity ratios in financial statement analysis are: Working Capital and Current Ratio.

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Our working capital (current assets minus current liabilities) and current ratio (current assets divided by current liabilities) are as follows:

	August 31, 2009		February 28, 2009
Current Assets	$	1,608,006	$	2,784,213
Current Liabilities		1,173,542		356,307
Working Capital	$	434,464	$	2,427,906
Current Ratio		1.37		7.81

While the working capital and current ratio are important in looking at the financial health of a business, numerous other factors may also affect the liquidity and capital resources of a company.

The changes in our capital resources at August 31, 2009 compared with February 28, 2009 are:

	August 31, 2009		February 28, 2009		Increase (Decrease)			Percentage Change
Cash	$	129,529	$	2,282,810	$	(2,153,281	)	-94.3	%
Current Assets	$	1,608,006	$	2,784,213	$	(1,176,207	)	-42.2	%
Total Assets	$	3,090,837	$	3,538,523	$	(447,686	)	-12.7	%
Current Liabilities	$	1,173,542	$	356,307	$	817,235		229.4	%
Total Liabilities	$	1,209,529	$	376,318	$	833,211		221.4	%
Working Capital	$	434,464	$	2,427,906	$	(1,993,442	)	-82.1	%

Our working capital decreased $1,993,442, from $2,427,906, as of February 28, 2009 to $434,464 as of August 31, 2009. This decrease was principally due to paying off a portion of the $1.5 million debt we assumed when we acquired the additional 25% working interest in California. As of August 31, 2009, approximately $631,784 was remaining to be paid from the default and is included in the accounts payable balance. Also contributing to the decrease in working capital was our participation in the drilling of two developmental wells and construction of permanent production facilities in the California project.

During the six months ended August 31, 2009, we reported an operating loss of approximately $1,408,374 as compared with an operating loss of approximately $1,122,681 from the comparative six month period in the prior year. This larger net operating loss of approximately $285,693 is due to a number of factors including 1) the recognition of bad debt expense of approximately $76,689 related to the default and settlement of a lawsuit against one of our working interest partners in the Krotz Springs project in Louisiana 2) the recognition of an impairment loss of approximately $232,000 on the additional 25% working interest acquired from certain defaulting working interest partners and 3) an increase in production costs and depletion and impairment expenses associated with an increase in production from the California project. The production costs of the California project will decline substantially once the permanent production facilities are completed and the electrical service installed in the field.

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.

For the last two years, we have been working to reposition Daybreak to better meet our corporate goals and objectives by selling our Tuscaloosa Project in Louisiana and our Saxet Deep Field in Texas. We are in the

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process of selling our East Gilbertown Field project in Alabama. These actions are allowing us to move forward with the current exploration and development program in California.

Cash Flows

Our sources of funds in the past have included the debt or equity markets and, while we have had cash flow from operations, we have not yet established sustainable positive cash flow from those operations. We may again have to rely on the debt or equity markets, if available, to fund future operations. Our business model is focused on acquiring exploration or development properties and also acquiring existing producing properties. 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.

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

	August 31, 2009			August 31, 2008			Increase (Decrease)			Increase (Decrease)
Net cash used in operating activities	$	(2,307,515	)	$	(764,297	)	$	1,543,218		201.9	%
Net cash provided by investing activities	$	154,234		$	2,860,724		$	(2,706,490	)	(94.6	%)
Net cash provided by financing activities	$	—		$	14,700		$	(14,700	)	(100.0	%)

Cash Flow Used in Operating Activities

Substantially all of our cash flow from operating activities is derived from the production of our oil and gas reserves. For the six months ended August 31, 2009, we had a negative cash flow from operating activities of $2,307,515, in comparison to a negative cash flow of $764,297 for the six months ended August 31, 2008. This change was primarily the result of recognizing the sale of our interest in the Tuscaloosa project in the prior fiscal year. Additionally, we had substantial increases in both our accounts receivable and accounts payable balances as a result of becoming the operator of the California project. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash Flow Provided by Investing Activities

Cash provided by investing activities decreased by $2,706,490 for the six months ended August 31, 2009, in comparison to the six months ended August 31, 2008. This change was primarily from the receipt of sale proceeds on the sale of our Tuscaloosa property in the prior comparative period offset slightly by the receipt of approximately $512,500 in proceeds from the sale of the additional 25% working interest in California, which we acquired from certain defaulting working interest partners in the current period.

Cash Flow Provided by Financing Activities

Cash provided by financing activities decreased by $14,700 for the six months ended August 31, 2009, in comparison to the six months ended August 31, 2008, because no financing activity occurred in the six months ended August 31, 2009.

A major source of funds for Daybreak in the past has been through the debt or equity markets. Since we have currently been unable to establish sustained, profitable oil and gas operations this may also have to be a source of funds in the future. Our business model is focused on acquiring exploration and developmental 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 profitable oil and gas producing properties, which will very likely require us to continue to raise equity or debt capital from sources outside of the Company if available.

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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.

Changes in Financial Condition and Results of Operations

Cash Balance

We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations and investments. Our cash balances were $129,529 and $2,170,160 for the six months ended August 31, 2009 and August 31, 2008, respectively. The decrease of approximately $2 million was due to the drilling of six wells in California and the assumption of certain defaulting partners debt in California as discussed in this MD&A.

The cash balance declined $2,153,281 during the last six months from $2,282,810 at February 28, 2009 to a balance of $129,529 at August 31, 2009. This decrease was primarily due to our exploration and development activities in California as well as our acquisition of an additional 25% working interest in our California project as well as our becoming the operator of our California project. As part of that acquisition, we assumed an approximate $1.5 million default from certain defaulting working interest partners. As of August 31, 2009, approximately $631,784 was remaining to be paid from the default.

Our expenditures consist primarily of exploration and drilling 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 general and administrative (“G&A”) expenses, which we have incurred in order to address necessary organizational activities.

Net Gain (Loss)

Since our inception, we have incurred recurring losses from operations with negative cash flow and have depended on external financing and the sale of oil and gas assets to sustain our operations. A net loss of $471,021 was reported for the quarter ended August 31, 2009, as compared to a net gain of $3,454,904 from the same quarter of the prior year. The increase of $3,925,925 in the net loss from the prior year was due to: (1) the recognition of the gain of the Tuscaloosa project in Louisiana in the prior comparative period; (2) the drilling of two non-commercial wells in California; (3) higher production costs associated with an increase in production in the current period than in the comparable period; (4) the recognition of bad debt expense from the settlement of the default of a working interest partner in Louisiana in the current period; (5) the timing of some G&A expenses from both the current and comparative six month period; (6) the recognition of income from discontinued operations in the prior period; and (7) the recognition of an impairment of approximately $232,000 on the 25% working interest that we acquired from certain defaulting working interest partners in our East Slopes project in California in the current period.

The quarterly net loss for the quarter ended August 31, 2009 of $471,021 was an improvement of $397,135 from the net loss of $868,156 which was experienced for the quarter ended May 31, 2009. This decrease in the net loss was a direct result of increased production revenue in California. We received revenue from four producing wells for the quarter ended August 31, 2009. We believe that the revenue and corresponding net income will continue to increase as we are able to bring more wells into production in California.

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The chart below shows the corresponding net gain (loss) for previous accounting periods by quarter for the last two fiscal years.

Three Months Ended August 31, 2009 compared to the Three Months Ended August 31, 2008 - Continuing Operations

The following discussion compares our results for the three month periods ended August 31, 2009 and August 31, 2008. These results cover our continuing operations at the East Slopes project in California and the Krotz Springs Field project in Louisiana.

Revenues. Revenues are derived entirely from the sale of our share of oil and gas production from our producing wells. We realized first revenues from producing wells in May 2007. Prior to that date, we had no revenues from continuing operations.

For the three months ended August 31, 2009, total oil and gas revenues from continuing operations increased by $101,123, or 348%, compared to the three months ended August 31, 2008. This increase in revenue was due to the result of our four producing wells in California. The Krotz Springs well, in Louisiana, was shut-in during the entire second quarter of the current fiscal year and thus did not contribute any revenue for the quarter. Overall production on a Barrel of Oil Equivalent (“BOE”) basis increased by 1,083 barrels, or 200%, as compared to the same period from the prior year. We recorded revenues from our interests in four producing wells from continuing operations for the three months ended August 31, 2009. A table of our revenues for the three months ended August 31, 2009 compared to the three months ended August 31, 2008 follows:

	Three Months Ended August 31, 2009		Three Months Ended August 31, 2008
California – East Slopes	$	129,665	$	—
Louisiana – Krotz Springs		482		29,024
Total Revenues	$	130,147	$	29,024

The Krotz Springs well in Louisiana was shut-in (not producing) for the three months ended August 31, 2009 as a result of reservoir depletion in the current productive zone. We are not participating as a working interest in any future activities to recomplete this well and attempts to put it back on production.

Costs and Expenses. Total operating expenses increased by $76,356, compared to the same three months from the prior year. Significant increases occurred in the production costs and the depreciation, depletion, amortization (“DD&A”) and impairment categories. These increases were directly related to the increase in production that occurred in our California project and producing into temporary facilities which involves heating the oil before it is sold; and, generating electricity with rental generators. Production costs are

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expected to decrease dramatically when the permanent production facilities are completed and the installation of permanent electrical service to the field is completed. We expect both of these activities will be completed by the end of October 2009.

Production costs include costs directly associated with the generation of oil and gas revenues, severance taxes and well workover projects. Exploration costs include geological and geophysical costs as well as leasehold maintenance costs and dry hole expenses. DD&A and impairment of equipment costs, proven reserves and property costs are another component of Operating Expenses. General & Administrative (“G&A”) expenses include employee salaries, legal and accounting expenses, director and management fees, investor relations and travel expenses. A table of our costs and expenses for the three months ended August 31, 2009 compared to the three months ended August 31, 2008 follows:

	Quarter Ended August 31, 2009		Quarter Ended August 31, 2008
Production Costs	$	134,958	$	(14,653	)
Exploration Costs		66,460		158,921
Depreciation, Depletion, Amortization & Impairment		44,709		18,402
Bad debt expense		2,306		—
General & Administrative		410,819		420,226
Total Operating Expenses	$	659,252	$	582,896

Production costs increased $149,611, compared to the same three months of the prior year. The increase in costs relates directly to increased production from our wells in California. These production costs are higher than normal because of the lack of permanent electrical service and the need to use rental equipment for temporary production facilities. Production costs are expected to decrease dramatically when the permanent production facilities are completed and electrical service to the field is installed in California. These production costs represented 20.5% of total operating expenses from continuing operations for the three months ended August 31, 2009.

Exploration expenses decreased $92,461, or 58.2%, compared to the same three months of the prior year. This decrease relates directly to lower geological and geophysical costs (“G&G”) for the three months ended August 31, 2009 than the three months in the prior comparative period. These costs represented 10.1% of total operating expenses from continuing operations for the three months ended August 31, 2009.

DD&A expenses increased $26,307, or 143%, compared to the same three months of the prior comparative period. This increase relates directly to the increase in production in our California project. These costs represented 6.8% of total operating expenses from continuing operations for the three months ended August 31, 2009.

G&A costs decreased $9,407, or 2.2%, compared to the same three months of the prior year. We are continuing a program of reducing these costs wherever possible. G&A costs represented 62.3% of total operating costs for the three months ended August 31, 2009.

Interest and dividend income increased $3,675, or 86.8%, compared to the three months ended August 31, 2008, due to slightly higher average cash and cash equivalent balances.

Due to the nature of our business, as well as the relative immaturity 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

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depend upon the factors cited above. G&A costs will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.

California (East Slopes and Expanded AMI Projects)

Kern and Tulare Counties. In May 2005, we agreed to jointly explore an area of mutual interest (an “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 two major areas referred to as the “East Slopes Project” in Kern County and the “Expanded AMI Project” in Tulare County. Drilling targets are porous and permeable sandstone reservoirs at depths of 1,200 feet to 4,000 feet.

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. By contributing 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 “Chevron AMI,” Chevron has earned a 50% working interest in the lands contributed by Daybreak et al to the Chevron AMI project area. After drilling of the four earning wells, Daybreak has earned a 25% interest in the Chevron lands that were contributed to the Chevron AMI project area.

Drilling of the four earning wells commenced in November 2008 and was completed in March 2009. Two successful exploratory wells were drilled, the Sunday #1 and the Bear #1. The Sunday #1 well, which encountered 20 feet of oil pay in the Vedder sand at 2,000 feet, was completed in January 2009. It initially produced 50 Barrels of Oil per Day (“BOPD”) at approximately 14.7° API gravity into temporary production facilities. The Bear #1 well encountered 26 feet of oil pay in the Vedder sands at 2,200 feet and tested at 50 BOPD. Two developmental wells have been drilled since the completion of the Sunday #1 and Bear #1 wells. These wells are the Sunday #2 and the Sunday # 3 wells. The Sunday #2 was completed in June of 2009 and encountered 20 feet of oil pay in the Vedder sand at around 1,900 feet. Completed in July of 2009, the Sunday #3 well encountered 20 feet of oil pay in the Vedder sand at 1,920 feet. The Sunday #3 well was drilled, completed and put on production in July 2009.

Permanent production facilities are being constructed to facilitate oil production from the Sunday and Bear locations. When these facilities are completed we plan to return to our developmental drilling program. Further exploration will continue following the completion of the development program later in 2009. We plan to spend approximately $750,000 in new capital investments within the Chevron AMI in the upcoming twelve months.

We also have a 25% working interest in a 14,100 acre Seismic Option Area immediately to the north of our Chevron AMI. We are considering plans to acquire a seismic survey over that area in late 2010.

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 Chevron AMI area in Kern County. A 3-D seismic survey over the prospect area is required before any exploration drilling can be done. As a part of the default settlement with respect to the Krotz Springs Field project in Louisiana, we were assigned the interest owned by our partner in this area. Daybreak currently has a 50% working interest in this project area. We anticipate spending $50,000 in the next fiscal year on lease rentals and brokerage fees.

Louisiana (Krotz Springs Project)

St. Landry Parish. The Krotz Springs well produces natural gas from a Cockfield Sands reservoir. In December 2008, we participated in the installation of a gas lift system. The gas lift system did not increase the gas production from the current producing reservoir and currently the well is shut in. We will attempt to

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farm out or assign our interest in this project to the other working interest partners and do not anticipate any further capital spending on this property. Because of the current low prices for gas and oil, we have fully impaired our capitalized cost in this property.

Three Months Ended August 31, 2009 compared to the Three Months Ended August 31, 2008 - Discontinued Operations

Alabama (East Gilbertown Field)

We are actively pursuing the sale of our interest in the East Gilbertown Field to a third party. The closing of the sale will be dependent upon receiving final regulatory approval from the State of Alabama. Prior period income statement amounts applicable to the East Gilbertown Field have been reclassified and included under Income (loss) from discontinued operations.

The following table presents the revenues and expenses related to the East Gilbertown Field for the three months ended August 31, 2009 and August 31, 2008.

	Three Months Ended August 31, 2009		Three Months Ended August 31, 2008
Oil sales revenues – East Gilbertown	$	23,239	$	52,652
Cost and expenses		27,010		(22,531	)
Income (loss) from discontinued operations	$	50,249	$	30,121

Six Months Ended August 31, 2009 compared to the Six Months Ended August 31, 2008 - Continuing Operations

The following discussion compares our results for the six month periods ended August 31, 2009 and August 31, 2008. These results cover our continuing operations at the East Slopes project in California and the Krotz Springs Field project in Louisiana.

Revenues. Revenues are derived entirely from the sale of our share of oil and gas production from our producing wells. We realized first revenues from producing wells in May 2007. Prior to that date, we had no revenues from continuing operations.

For the six months ended August 31, 2009, total oil and gas revenues from continuing operations increased by $127,684, or 321%, compared to the six months ended August 31, 2008. This increase in revenue was the result of four wells in California being brought into production and receiving higher average oil prices than in the prior year. Overall production on a BOE basis decreased by 1,111 barrels, or 26.6%, as compared to the same period from the prior year. We recorded revenues from our interests in four producing wells from continuing operations for the six months ended August 31, 2009. A table of revenues for the six months ended August 31, 2009 compared to the six months ended August 31, 2008 follows:

	Six Months Ended August 31, 2009		Six Months Ended August 31, 2008
California – East Slopes	$	166,318	$	—
Louisiana – Krotz Springs		1,102		39,736
Total Revenues	$	167,420	$	39,736

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The Krotz Springs well in Louisiana was shut-in (not producing) for the three months ended August 31, 2009 as a result of reservoir depletion in the current productive zone. We will not participate in any recompletion activities designed to put this well back on production.

Costs and Expenses. Total operating expenses increased by $413,377, compared to the same six months from the prior year. Significant increases occurred in the production costs and the DD&A and impairment categories. These increases were directly related to the increase in production that occurred in our California project. Production costs are expected to decrease dramatically when the permanent production facilities are completed and electrical service to the field is installed in California.

A table of our costs and expenses for the six months ended August 31, 2009 compared to the six months ended August 31, 2008 follows:

	Six Months Ended August 31, 2009		Six Months Ended August 31, 2008
Production Costs	$	198,445	$	18,296
Exploration Costs		103,925		244,344
Depreciation, Depletion, Amortization & Impairment		352,585		36,054
Bad debt expense		76,689		—
General & Administrative		844,150		863,723
Total Operating Expenses	$	1,575,794	$	1,162,417

Production costs increased $180,149, compared to the same six months of the prior year. The increase in costs relates directly to the production in California. These production costs are higher than normal because of the lack of electrical service and the need to use rental equipment for temporary production facilities. We are working as quickly as possible to lower the production costs through the installation of both electrical service to the area and the installation of permanent production facilities for our California project. Once these two goals are achieved, we believe that the production costs in California will drop substantially. These production costs represented 12.6% of total operating expenses from continuing operations for the six months ended August 31, 2009.

Exploration expenses decreased $140,419, compared to the same six months of the prior year. This decrease relates directly to lower G&G costs for the six months ended August 31, 2009 than the six months in the prior comparative period. These costs represented 6.6% of total operating expenses from continuing operations for the six months ended August 31, 2009.

DD&A and impairment expenses increased $316,531, compared to the same six months of the prior comparative period. This increase relates directly to our acquisition of an additional 25% working interest from certain defaulting working interest partners in our California project. An impairment of approximately $232,000 was recognized in the acquisition of that additional 25% working interest. Additionally our increased production in California resulted in an increase in depletion costs, as compared with the six months ended August 31, 2008. These costs represented 22.4% of total operating expenses from continuing operations for the six months ended August 31, 2009.

Bad debt expense of $76,689 was incurred for the six months ended August 31, 2009 primarily because of the final write-off of a receivable on the Krotz Springs project from a working interest partner who defaulted in the project. This cost represented 4.9% of total operating expenses from continuing operations for the six months ended August 31, 2009.

G&A costs decreased $19,573, or 2.3%, compared to the same six months of the prior year. Our accounting and legal costs, both components of G&A decreased approximately $73,858, or 32%, from the same period in the prior year as we have improved our internal controls over financial reporting and are finishing the

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additional compliance projects that we had implemented. G&A costs represented 53.6% of total operating costs for the six months ended August 31, 2009.

Interest and dividend income increased $2,404, or 32%, compared to the six months ended August 31, 2008, due to higher average cash and cash equivalent balances.

Six Months Ended August 31, 2009 compared to the Six Months Ended August 31, 2008 - Discontinued Operations

Alabama (East Gilbertown Field)

We are actively pursuing the sale of our interest in the East Gilbertown Field to a third party. The closing of the sale will be dependent upon receiving final regulatory approval from the State of Alabama. Prior period income statement amounts applicable to the East Gilbertown Field have been reclassified and included under Income (loss) from discontinued operations.

The following table presents the revenues and expenses related to the East Gilbertown Field for the six months ended August 31, 2009 and August 31, 2008.

	Six Months Ended August 31, 2009		Six Months Ended August 31, 2008
Oil sales revenues – East Gilbertown	$	43,205	$	102,160
Cost and expenses		16,887		(39,050	)
Income (loss) from discontinued operations	$	60,092	$	63,110

Summary

We may obtain the funds for any future development activities through various methods, including bank debt, issuing of equity or debt securities or obtaining joint venture partners. Raising additional funds by issuing common or preferred stock would further dilute our existing stockholder base. No assurances can be given that we will be able to obtain any additional financing on favorable terms, if at all.

Critical Accounting Policies

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2009.

Off-Balance Sheet Arrangements

As of August 31, 2009, we did not have any off-balance sheet arrangements or relationships with unconsolidated entities or financial partners that have been, or are reasonably likely to have, a material effect on our financial position or results of operations.

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ITEM 3. 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 4T. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

As of the end of the reporting period, August 31, 2009, an evaluation was conducted by Daybreak management, including our Chief Executive and interim principal finance and accounting officer, as to the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Exchange Act. Such disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods specified by the SEC rules and forms. Additionally, it is vital that such information is accumulated and communicated to our management including our Chief Executive Officer, in a manner to allow timely decisions regarding required disclosures. Based on that evaluation, our management concluded that our disclosure controls were effective as of August 31, 2009.

Changes in Internal Control over Financial Reporting

As a result of our evaluation of our Internal Controls over Financial Reporting that was conducted for the year ended February 28, 2009 determining that our internal controls were not effective as of February 28, 2009, which is more fully described in our Annual Report on Form 10-K for the year ended February 28, 2009, the Company has initiated the following changes described below in our internal control over financial reporting:

• we are developing 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 is adding a further level of oversight for approval of non-routine non-cash transactions; and

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

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.

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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.

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PART II
OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On July 16, 2009, an annual meeting of shareholders was held in Spokane, Washington. At that meeting the following items were submitted to be voted upon by the Daybreak security holders.

          Item 1. Election of Directors.

	Voting Results
Director	For		Withheld
Wayne G. Dotson		34,472,605		557,140
Dale B. Lavigne		34,470,182		559,563
Ronald D. Lavigne		34,470,182		559,563
Timothy R. Lindsey		34,589,395		440,350
James F. Meara		34,472,605		557,140
James F. Westmoreland		34,472,605		557,140

All nominees for director were elected by a majority vote of security holders.

Item 2. Ratification of the appointment by the Board of Directors of Malone & Bailey, PC as the independent public accountants of the Company for the fiscal year ending February 28, 2010.

Voting Results
For	Against	Abstentions
34,540,195	324,975	164,575

The appointment by the Board of Directors of Malone and Bailey, PC as the independent public accountants of the Company was ratified by a majority vote of security holders.

Item 3. Approval of Amended and Restated Articles of Incorporation of the Company.

Voting Results
For	Against	Abstentions
33,832,583	350,938	846,224

The approval of the Amended and Restated Articles of Incorporation of the Company was ratified by a majority vote of security holders.

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ITEM 6. EXHIBITS

The following Exhibits are filed as part of the report:

Exhibit Number	Description
3.1	Amended and Restated Articles of Incorporation of Daybreak Oil and Gas, Inc. dated July 16, 2009 (incorporated by reference to Appendix A included in the Company’s Schedule 14A filed with the SEC on June 1, 2009.
31.1(1)	Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1(1)	Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1)          Filed herewith.

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SIGNATURES

Pursuant to the requirements 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: October 9, 2009

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