DAYBREAK OIL & GAS, INC. - Quarter Report: 2009 November (Form 10-Q)

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 November 30, 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 January 8, 2010 the registrant had 47,650,599 outstanding shares of $0.001 par value common stock.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION


ITEM 1.	Financial Statements	3

	Balance Sheets at November 30, 2009 and February 28, 2009 (Unaudited)	3

	Statements of Operations for the Three and Nine Months Ended November 30, 2009 and November 30, 2008 (Unaudited)	4

	Statements of Cash Flows for the Three and Nine Months Ended November 30, 2009 and November 30, 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	28

ITEM 4T.	Controls and Procedures	28

PART II - OTHER INFORMATION


ITEM 1.	Legal Proceedings	30

ITEM 1A.	Risk Factors	30

ITEM 6.	Exhibits	30

Signatures		31

PART I
FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DAYBREAK OIL AND GAS, INC.
Balance Sheets - Unaudited


	As of November 30, 2009			As of February 28, 2009

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	315,557		$	2,282,810
Accounts receivable:
Oil and gas sales		113,857			17,636
Joint interest participants, net of allowance for doubtful accounts of $2,000 and $3,848 respectively		543,559			291,998
Receivables associated with assets held for sale, net of allowance for doubtful accounts of 20,160 and $11,254 respectively		323,123			188,879
Production revenue receivable		25,000			—
Prepaid expenses and other current assets		33,525			2,890

Total current assets		1,354,621			2,784,213
OIL AND GAS PROPERTIES, net of accumulated depletion, depreciation, amortization, and impairment, of $584,418 and $371,497 respectively, successful efforts method
Proved properties		783,470			356,280
Unproved properties		17,350			—
VEHICLES AND EQUIPMENT, net of accumulated depreciation of $29,097 and $23,753 respectively		2,232			7,576
Production revenue receivable - long term		325,000			—
OTHER ASSETS		400,636			390,454

Total assets	$	2,883,309		$	3,538,523


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,287,715		$	356,307
Liabilities associated with assets held for sale		124,980			—

Total current liabilities		1,412,695			356,307
OTHER LIABILITIES
Asset retirement obligation		36,855			20,011

Total liabilities		1,449,550			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; 1,053,565 shares and 1,060,465 shares issued and outstanding respectively		1,054			1,061
Common stock- 200,000,000 shares authorized; $0.001 par value, 47,650,599 and 45,079,899 shares issued and outstanding respectively		47,652			45,081
Additional paid-in capital		22,123,727			22,047,360
Accumulated deficit		(20,738,674	)		(18,931,297	)

Total stockholders’ equity		1,433,759			3,162,205

Total liabilities and stockholders’ equity	$	2,883,309		$	3,538,523

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

DAYBREAK OIL AND GAS, INC.

Statements of Operations - Unaudited


	For the Three Months Ended November 30,						For the Nine Months Ended November 30,

	2009			2008			2009			2008

REVENUE:
Oil and gas sales	$	118,815		$	—		$	285,133		$	—


OPERATING EXPENSES:
Production costs		28,072			—			221,700
Exploration and drilling		52,542			294,177			156,468			538,521
Depreciation, depletion, amortization, and impairment		172,903			107,312			525,112			112,533
Bad debt expense		4,750			—			81,439			—
General and administrative		330,611			979,152			1,175,662			1,843,773

Total operating expenses		588,878			1,380,641			2,160,381			2,494,827

OPERATING LOSS		(470,063	)		(1,380,641	)		(1,875,248	)		(2,494,827	)


OTHER INCOME (EXPENSE):
Interest income		2,043			1,508			11,912			5,255
Dividend income		—			18,419			—			22,137
Interest expense		(96	)		3			(859	)		(366	)

Total other income (expense)		1,947			19,930			11,053			27,026


LOSS FROM CONTINUING OPERATIONS		(468,116	)		(1,360,711	)		(1,864,195	)		(2,467,801	)

DISCONTINUED OPERATIONS
Income (loss) from discontinued operations (net of tax of $ -0-)		(84	)		51,614			56,818			102,909
Gain from sale of oil and gas properties (net of tax of $ -0-)		—			—			—			4,112,823

INCOME (LOSS) FROM DISCONTINUED OPERATIONS		(84	)		51,614			56,818			4,215,732


NET INCOME (LOSS)		(468,200	)		(1,309,097	)		(1,807,377	)		1,747,931

Cumulative convertible preferred stock dividend requirement		(50,561	)		(52,421	)		(153,139	)		(160,321	)


NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS	$	(518,761	)	$	(1,361,518	)	$	(1,960,516	)	$	1,587,610


NET INCOME (LOSS) PER COMMON SHARE
Loss from continuing operations	$	(0.01	)	$	(0.03	)	$	(0.04	)	$	(0.05	)
Income (loss) from discontinued operations		(0.00	)		0.00			0.00			0.09

NET INCOME (LOSS) PER COMMON SHARE - Basic and diluted	$	(0.01	)	$	(0.03	)	$	(0.04	)	$	0.04


WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - Basic and diluted		47,641,559			44,761,899			47,054,303			44,631,309

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

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows - Unaudited


	Nine Months Ended November 30,

	2009			2008

CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,807,377	)	$	1,747,931
Adjustments to reconcile net loss to net cash used in operating activities:
Common stock issued for services		57,255			—
Gain on sale of oil and gas properties		—			(3,993,441	)
Depreciation, depletion, and impairment expense		526,354			250,121
Bad debt expense		81,439			—
Non cash interest income		(10,182	)		(3,729	)
Non cash general and administrative expense		21,676			52,425
Changes in assets and liabilities:
Accounts receivable - oil and gas sales		(96,221	)		(163,976	)
Accounts receivable - joint interest participants		(488,332	)		382,169
Prepaid expenses and other current assets		(30,635	)		20,942
Accounts payable and other accrued liabilities		(569,640	)		(87,384	)

Net cash used in operating activities		(2,315,663	)		(1,794,942	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of reclamation bond		—			(100,000	)
Additions to oil and gas properties		(514,090	)		(281,779	)
Proceeds from sale of oil and gas properties		862,500			5,812,894
Additions to oil and gas prepayments		—			4,782

Net cash provided by investing activities		348,410			5,435,897


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		(1,967,253	)		3,655,655

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		2,282,810			214,578


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	315,557		$	3,870,233


CASH PAID FOR:
Interest	$	859		$	366
Income taxes		—			—

SUPPLEMENTAL CASH FLOW INFORMATION:
Acquisition of additional working interest through assumption of liability	$	1,500,201		$	—
Unpaid additions to oil and gas properties	$	75,394		$	—
Conversion of preferred stock to common stock	$	21		$	441

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

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 nine months ended November 30, 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 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” in its statements of operations, stockholders’ equity and cash flows.

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 nine months ended November 30, 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 November 30, 2009 has an accumulated deficit of $20,738,674, 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. If a sale occurs and the Company receives final regulatory approval from the State of Alabama for the change of the operator in the East Gilbertown Field, the Company will recover $250,000 in cash collateral which was posted to secure an operator-bond in Alabama.

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company does have cash flow from operations, it has not yet established a positive cash flow on a company-wide basis. The Company will need to rely on the debt or equity private or public markets, if available, to fund future operations.

The Company’s financial statements as of November 30, 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.

NOTE 3 — RECENT ACCOUNTING PRONOUNCEMENTS

During the third quarter of the fiscal year, the Company adopted The 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 Accounting Standards Codification (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, in accordance with U.S. GAAP, 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 November 30, 2009 through January 8, 2010, the date these financial statements were issued. During this period, the Company did not have any recognizable or non-recognizable subsequent events.

During the first quarter of the fiscal year, 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 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, in accordance with U.S. GAAP, 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 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.

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 November 30, 2009, three customers represented 100% of crude oil and natural gas sales receivable from all projects in the aggregate.

In accordance with the accounting guidance which requires 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 November 30, 2009				Three Months Ended November 30, 2008

Project	Location	Product	Customer	Revenue		Percentage		Revenue		Percentage


East Slopes	California	Oil	Plains Marketing	$	118,815	85.7	%	$	—	—

East Gilbertown Field	Alabama	Oil	Hunt Crude Oil Supply	$	19,213	13.9	%	$	32,017	56.6	%

				For the Nine Months Ended November 30, 2009				For the Nine Months Ended November 30, 2008

Project	Location	Product	Customer	Revenue		Percentage		Revenue		Percentage


East Slopes	California	Oil	Plains Marketing	$	285,133	81.6	%	$	—	—

East Gilbertown Field	Alabama	Oil	Hunt Crude Oil Supply	$	62,418	17.9	%	$	134,177	51.3	%

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 (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 FASB ASC 360, “Property, Plant and Equipment”.

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 by $100,000 which was recognized as an additional impairment loss. 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, 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 $531,934 of the $1.5 million default remains unpaid and is included in the November 30, 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.

During the quarter ended November 30, 2009, the Company discontinued its participation in the KSU #59 well located in the Krotz Springs Field in St. Landry Parish, Louisiana. The Company is also actively pursuing efforts to sell its interest in the East Gilbertown Field in Alabama. In accordance with the guidance governing the accounting for impairment or disposal of long-lived assets, net results of operations for the Krotz Springs and the East Gilbertown Fields 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 nine month periods ended November 30, 2009 and November 30, 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 nine month presentations of the current year for the East Gilbertown Field reflect certain non-recurring credits that result in this information being additions to revenue rather than deductions from revenue. Because of the low prices for oil and gas in prior periods, we have fully impaired our capitalized cost in all of these properties.


	Three Months Ended November 30, 2009			Three Months Ended November 30, 2008

Oil sales revenue – Saxet Deep Field	$	—		$	12,128
Cost and expenses		—			(61,319	)

Income (loss) from discontinued operations	$	—		$	(49,191	)


	Three Months Ended November 30, 2009			Three Months Ended November 30, 2008

Oil sales revenue – East Gilbertown Field	$	19,213		$	32,017
Cost and expenses		834			73,985

Income (loss) from discontinued operations	$	20,047		$	106,002


	Three Months Ended November 30, 2009			Three Months Ended November 30, 2008

Oil sales revenue – Krotz Springs Field	$	665		$	12,383
Cost and expenses		(20,796	)		(17,580	)

Income (loss) from discontinued operations	$	(20,131	)	$	(5,197	)


	Nine Months Ended November 30, 2009			Nine Months Ended November 30, 2008

Oil sales revenue – Saxet Deep Field	$	—		$	70,202
Cost and expenses		—			(131,348	)

Income (loss) from discontinued operations	$	—		$	(61,146	)


	Nine Months Ended November 30, 2009			Nine Months Ended November 30, 2008

Oil sales revenue – East Gilbertown Field	$	62,418		$	134,177
Cost and expenses		17,722			25,234

Income (loss) from discontinued operations	$	80,140		$	159,411


	Nine Months Ended November 30, 2009			Nine Months Ended November 30, 2008

Oil sales revenue – Krotz Springs Field	$	1,767		$	57,013
Cost and expenses		(25,089	)		(52,369	)

Income (loss) from discontinued operations	$	(23,322	)	$	4,644

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 November 30, 2009, there have been 346,200 shares of the originally issued 1,399,765 shares of Series A Stock converted by 24 shareholders into 1,038,600 shares of the Company’s common stock.

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. As of November 30, 2009, the Company has not declared any dividends.

The table below details the cumulative dividends for each fiscal year since issuance and the interim nine 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
Nine Months Ended November 30, 2009	76		153,139

Total Accumulated Dividends		$	753,671

NOTE 9 — WARRANTS

Warrants outstanding and exercisable as of November 30, 2009 are:


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

Spring 2006 Common Stock Private Placement		4,013,602	$2.00	1.50	4,013,602
Placement Agent Warrants Spring 2006 PP		802,721	$0.75	3.50	802,721
Placement Agent Warrants Spring 2006 PP		401,361	$2.00	3.50	401,361
July 2006 Preferred Stock Private Placement		2,799,530	$2.00	1.75	2,799,530
Placement Agent Warrants July 2006 PP		419,930	$1.00	3.75	419,930
Convertible Debenture Term Extension		150,001	$2.00	2.00	150,001
Spring 2006 PP Goodwill Warrants		3,227,934	$0.65	0.25	3,227,934
July 2006 PP Goodwill Warrants		1,250,264	$0.65	0.25	1,250,264
Placement Agent Warrants January 2008 PP		39,550	$0.25	1.25	39,550

		13,104,893			13,104,893

For the nine months ended November 30, 2009, no warrants were issued or exercised. During the quarter ended November 30, 2009, a total of 90,000 warrants expired. These warrants were issued for a term extension on convertible debentures. As of November 30, 2009 and February 28, 2009, there were 13,104,893 and 13,306,893 warrants issued and outstanding respectively. The intrinsic value of all warrants at November 30, 2009 was $ -0-.

NOTE 10 — 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 November 30, 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

For the three and nine months ended November 30, 2009, the Company recognized compensation expense related to the above restricted stock grants of $20,651 and $57,255 respectively. Unamortized compensation expense amounted to $204,745 as of November 30, 2009.

NOTE 11 — 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:


	Nine Months Ended November 30, 2009			Nine Months Ended November 30, 2008

Computed at U.S. and state statutory rates (40%)	$	(722,951	)	$	(699,175	)
Permanent differences		10,417			3,625
Changes in valuation allowance		712,534			702,800

Total	$	—		$	—

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


	November 30, 2009			February 28, 2009

Deferred tax assets:
Net operating loss carryforwards	$	4,941,943		$	4,130,040
Oil and gas properties		93,926			216,245
Stock based compensation		22,950			—
Less valuation allowance		(5,058,819	)		(4,346,285	)

Total	$	—		$	—

At November 30, 2009, the Company had estimated net operating loss carryforwards for federal and state income tax purposes of approximately $12,354,859 which will begin to expire, if unused, beginning in 2024. The valuation allowance increased approximately $712,534 for the nine months ended November 30, 2009 and increased by $26,465 for the year ended February 28, 2009. Section 382 Rule of the Internal Revenue Code places 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 12 — 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 November 30, 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.

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 California.

Introduction and Overview

The following discussion of our results of operations for the three and nine month periods ended November 30, 2009 and November 30, 2008 and of our financial condition as of November 30, 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

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 nine 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 with continued volatility and lower prices throughout 2009. This in turn has 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 November 30, 2009, operating margins improved somewhat due to an improvement in oil prices, the substantial completion of our production facilities, 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 three successful exploratory wells and four developmental wells as well as two non-commercial wells. During the quarter ended November 30, 2009, we completed the installation of our permanent production facilities and electrical service to our wells in California. We believe these efforts will substantially lower our production costs on each well.

The Company is now well positioned to expand its operations in the East Slopes San Joaquin Project in California having found three reservoirs at our Bear, Sunday, and Black locations. The Sunday location is now fully developed with three vertical wells and one horizontal well. More development drilling is planned for our Bear location, which may include a horizontal well along with several vertical wells. The Bear reservoir is believed to be much larger than the Sunday reservoir. The Black reservoir is the smallest of the three reservoirs and we will most likely drill only one developmental well. There are several other similar prospects on trend with the Bear and Black reservoirs exhibiting the same seismic characteristics. Some of these reservoirs will be produced into the Company’s existing production facilities. In addition to the current field development, there are several other exploratory prospects that have been identified from the seismic data, and will be drilled in the future.

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 factors in financial statement analysis are: Working Capital and Current Ratio.

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


	November 30, 2009			February 28, 2009

Current Assets	$	1,354,621		$	2,784,213
Current Liabilities		1,412,695			356,307

Working Capital	$	(58,074	)	$	2,427,906


Current Ratio		0.96			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 November 30, 2009 compared with February 28, 2009 are:


	November 30, 2009			February 28, 2009		Increase (Decrease)			Percentage Change

Cash	$	315,557		$	2,282,810	$	(1,967,253	)	(86.2	%)
Current Assets	$	1,354,621		$	2,784,213	$	(1,429,592	)	(51.3	%)
Total Assets	$	2,883,309		$	3,538,523	$	(655,214	)	(18.5	%)
Current Liabilities	$	1,412,695		$	356,307	$	1,056,388		296.5	%
Total Liabilities	$	1,449,550		$	376,318	$	1,073,232		285.2	%
Working Capital	$	(58,074	)	$	2,427,906	$	(2,485,980	)	(102.4	%)

Our working capital decreased $2,485,980 from $2,427,906, as of February 28, 2009 to a negative $58,074 as of November 30, 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; additional drilling activity and the construction of permanent production facilities in California. As of November 30, 2009, approximately $531,934 was remaining to be paid from the default of our previous partners in California and is included in the accounts payable balance.

During the nine months ended November 30, 2009, we reported an operating loss of approximately $1,875,248 as compared with an operating loss of approximately $2,494,827 from the comparative nine month period in the prior year. This decrease of approximately $619,579 in the comparative periods of net operating loss is primarily due to a reduction in our general and administrative expenses offset by an increase in our depreciation, depletion, amortization and impairment (“DD&A”) expense. The increase in DD&A costs comes from the recognition of an impairment loss of approximately $342,000 on the additional 25% working interest acquired from certain defaulting working interest partners and an increase in depletion expense associated with an increase in production from the California project. We believe the production costs in California will continue to decline as we are able to increase the use of the permanent production facilities and the electrical service that is 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 external sources, should we be unable to achieve sustainable profitability this could cause any 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 project in Texas. We are in the process of marketing with the intent of selling our East Gilbertown Field project in Alabama and have

discontinued our participation in the KSU #59 well in the Krotz Springs Field in St. Landry Parish, Louisiana. 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 positive cash flow on a company-wide basis. We will need to rely on the debt or equity private or public 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:


	November 30, 2009			November 30, 2008			Increase (Decrease)			Increase (Decrease)

Net cash used in operating activities	$	(2,315,663	)	$	(1,794,942	)	$	520,721		29.0	%
Net cash provided by investing activities	$	348,410		$	5,435,897		$	(5,087,487	)	(93.6	%)
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 nine months ended November 30, 2009, we had a negative cash flow from operating activities of $2,315,663, in comparison to a negative cash flow of $1,794,942 for the nine months ended November 30, 2008. This change was primarily the result of our becoming the Operator of the East Slopes project in California. We experienced substantial increases in our accounts receivable and accounts payable balances because we became the Operator of this project. The significant change in our DD&A account balance was as a result of the impairment on the sale of a 25% working interest in California as well as drilling and production activity in California. 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 for the nine months ended November 30, 2009 was $348,410 a decrease of $5,087,487 from the $5,435,897 for the nine months ended November 30, 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 $862,500 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 nine months ended November 30, 2009, where no financing activity occurred in comparison to the nine months ended November 30, 2008.

A major source of funds for Daybreak in the past has been through the debt or equity private or public markets. Since we have currently been unable to establish sustained, profitable oil and gas operations this

will 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.

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 $315,557 and $3,870,233 for the nine months ended November 30, 2009 and November 30, 2008, respectively. The decrease of approximately $3.55 million was due to the drilling of eight wells and the construction of permanent production facilities in California as well as the assumption of certain defaulting partners debt in California as previously discussed in this MD&A.

The cash balance declined approximately $1.96 million during the last nine months from $2,282,810 at February 28, 2009 to a balance of $315,557 at November 30, 2009. This decrease as discussed previously was primarily due to our increased exploration and development activities; our becoming the operator of our California project and the default of certain prior working interest partners in California. As of November 30, 2009, approximately $531,934 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 Income (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 $468,200 was reported for the three months ended November 30, 2009, as compared to a net loss of $1,309,097 for the three months of the comparative period of the prior year. The decrease in net loss of $840,897 from the prior year was due to: (1) a reduction of $648,541 in G&A expenses and (2) lower exploration and drilling costs in the three months ended November 30, 2009 in comparison to the three months ended November 30, 2008. In the comparative period of the prior year we drilled two non-commercial (dry-hole) wells in California.

The net loss of $1,807,377 for the nine months ended November 30, 2009 compares to a net gain of $1,747,931 for the nine months ended November 30, 2008. The gain from the prior year was due to the recognition of the sale of our Tuscaloosa property in Louisiana. Excluding the impact of the gain from the Tuscaloosa sale, there was a net loss of $2,364,892 for the nine months ended November 30, 2008. The smaller net loss for the nine months ended November 30, 2009, excluding such property sale, a decrease of $557,515, was primarily due to a reduction of G&A costs.

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

(LINE GRAPH)

Three Months Ended November 30, 2009 compared to the Three Months Ended November 30, 2008 - Continuing Operations

The following discussion compares our results for the three month periods ended November 30, 2009 and November 30 2008. These results only cover our continuing operations at the East Slopes project in California.

Revenues. Revenues are derived entirely from the sale of our share of oil production from our producing wells in California. We realized the first revenues from producing wells in California during February 2009. Prior to that date, we had no revenues from continuing operations.

For the three months ended November 30, 2009, total oil revenues from continuing operations were $118,815 in comparison to no revenue from the three months ended November 30, 2008. Our revenue was from the four producing wells in California. Our net share of production was 1,836 barrels for the three months ended November 30, 2009. A table of our revenues for the three months ended November 30, 2009 compared to the three months ended November 30, 2008 follows:


	Three Months Ended November 30, 2009		Three Months Ended November 30, 2008

California – East Slopes	$	118,815	$	—

Total Revenues	$	118,815	$	—

Costs and Expenses. Total operating expenses for the three months ended November 30, 2009 decreased by $791,763, compared to the three months ended November 30, 2008. Significant decreases occurred in exploration and drilling costs as well as G&A costs in comparison with the three months ended November 30, 2008, while DD&A costs increased.

A table of our costs and expenses for the three months ended November 30, 2009 compared to the three months ended November 30, 2008 follows:


	Three Months Ended November 30, 2009		Three Months Ended November 30, 2008

Production Costs	$	28,072	$	—
Exploration Costs		52,542		294,177
Depreciation, Depletion, Amortization & Impairment		172,903		107,312
Bad debt expense		4,750		—
General & Administrative		330,611		979,152

Total Operating Expenses	$	588,878	$	1,380,641

Production costs include costs directly associated with the generation of oil and gas revenues, severance taxes and well workover costs. These costs for the three months ended November 30, 2009 were $28,072, and were lower than expected because of a reclassification of $44,109 in production costs from the prior quarter. The installation of permanent production facilities including a tank battery and electrical service to the tank battery and the wells during the quarter are expected to contribute to a decline in individual well production costs. These production costs represented 4.8% of total operating expenses from continuing operations.

Exploration costs include geological and geophysical (“G&G”) costs as well as leasehold maintenance costs and dry hole expenses. For the three months ended November 30, 2009 these costs decreased $241,635, or 82.1%, compared to the three months ended November 30, 2008. Exploration costs were higher in the prior comparative period because of recognition for the drilling of two non-commercial wells in California. These costs represented 8.9% of total operating expenses from continuing operations.

DD&A of equipment costs, proven reserves and property costs are another component of operating expenses. DD&A expenses increased $65,591, or 61.1%, compared to the three months ended November 30, 2008. This increase relates directly to the additional impairment of $100,000 that occurred with the early payoff of a production revenue receivable. These costs represented 29.4% of total operating expenses from continuing operations.

G&A expenses include employee salaries, legal and accounting expenses, director and management fees, investor relations and travel expenses. For the three months ended November 30, 2009 G&A costs decreased $648,541 or 66.2%, compared to the same three months ended November 30, 2008. These expenses were higher in the prior comparative period because of the recognition of non-cash expenses associated with the issuance of goodwill warrants to investors in two private placement offerings that occurred in 2006. We are continuing a program of reducing these costs wherever possible. G&A costs represented 56.1% of total operating expenses from continuing operations.

Interest and dividend income decreased $17,983, or 90.2%, compared to the three months ended November 30, 2008, due to lower 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 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 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 “Chevron AMI,” Chevron earned a 50% working interest in the lands contributed by Daybreak et al to the Chevron AMI project area. After the drilling of the four earning wells, Daybreak 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 14.7º 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. During the second quarter of the current fiscal year, two developmental wells (the Sunday #2 and Sunday #3) were also drilled and have been completed. The Sunday #2, completed in June 2009, 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.

During the three months ended November 30, 2009 our net share of oil production was 1,836 barrels compared to 2,162 barrels for the three months ended August 31, 2009. The decrease in production was due to a temporary cutback on oil production while we were involved in the completion of our permanent production facilities, comprising electrical service to both the Sunday and Bear prospects and construction of a common tank battery for the same prospects. The average price of oil during the three months ended November 30, 2009 was $64.78 per barrel compared with $60.00 per barrel during the three months ended August 31, 2009. We have a variable net revenue interest ranging from 16.5% to 27% in the four producing wells in California.

In December 2009, after construction of the permanent production facilities was completed, we returned to our developmental drilling program on the Sunday, Bear, and Black prospects. The Bear #2 was drilled to 2,509 feet and completed in the Vedder sand between 2,104 and 2,138 feet. This well is initially producing at a rate of 50 barrels of oil per day. This rate may be increased over time depending on the initial performance of the well. Further development wells in the Bear prospect, which may include a horizontal well, will be drilled after evaluating the performance of the Bear #2. The Sunday #4-H is our first horizontally drilled well in the East Slopes project. The well encountered 375 feet of horizontal oil pay in the 20 foot vertical section of the Vedder Sand. This well is currently being completed.

The Black #1 was drilled to 2,300 feet and encountered 20 feet of oil pay in the Vedder sand between 2,141 and 2,161 feet. This well is currently being completed. The Marshall lease, where this well was drilled, was obtained through a farm-in arrangement from another operator. This lease is located approximately one-half mile from our tank battery and will be connected to it. The well is located in a separate reservoir from our two previously discovered reservoirs, which we identified through interpretation of our 3-D Seismic.

We anticipate drilling at least twelve more wells in calendar year 2010, subject to funding. We plan to spend approximately $1,250,000 in new capital investments within the Chevron AMI in the upcoming twelve months, also subject to funding.

As part of the sale of the defaulted partner 25% working interest in May 2009 to a group of Texas companies, we acquired 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. 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.

Three Months Ended November 30, 2009 compared to the Three Months Ended November 30, 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. Because of the low prices for oil in prior periods, we have fully impaired our capitalized cost in this property.

The following table presents the revenues and expenses related to the East Gilbertown Field for the three months ended November 30, 2009 and November 30, 2008. The cost and expense information for the East Gilbertown Field reflects certain non-recurring credits that result in this information being additions to revenue rather than deductions from revenue.


	Three Months Ended November 30, 2009		Three Months Ended November 30, 2008

Oil sales revenue – East Gilbertown Field	$	19,213	$	32,017
Cost and expenses		834		73,985

Income (loss) from discontinued operations	$	20,047	$	106,002

Louisiana (Krotz Springs Project)

St. Landry Parish. The Krotz Springs well completed in May 2007 produced hydrocarbons from a Cockfield Sands reservoir. In December 2008, we participated in the installation of a gas lift system designed to increase production. The gas lift system did not increase the gas production from the current producing reservoir as hoped and we decided to no longer continue our participation in this project. We are in the process of transferring our interest to third parties and will no longer participate in future activities on this property. Because of the low prices for gas and oil in prior periods, we have fully impaired our capitalized cost in this property.

The Krotz Springs well was shut-in during the entire second quarter of the current fiscal year and produced only periodically during the three months ended November 30, 2009.


	Three Months Ended November 30, 2009			Three Months Ended November 30, 2008

Oil sales revenue – Krotz Springs Field	$	665		$	12,383
Cost and expenses		(20,796	)		(17,580	)

Income (loss) from discontinued operations	$	(20,131	)	$	(5,197	)

Effective December 31, 2008, we assigned our interest in the Saxet Deep Field in Corpus Christi, Texas to the field operator in exchange for a release from all future plug and abandonment liability. We are not presenting any financial information relating to revenues or expenses since there is no comparative information for three months ended November 30, 2009.

Nine Months Ended November 30, 2009 compared to the Nine Months Ended November 30, 2008 - Continuing Operations

The following discussion compares our results for the nine month periods ended November 30, 2009 and November 30 2008. These results only cover our continuing operations at the East Slopes project in California.

For the nine months ended November 30, 2009, total oil revenues from continuing operations were $285,133 in comparison to no revenue from the nine months ended November 30, 2008. Our revenue was from the four producing wells in California. Our net share of production was 4,791 barrels with an average price of $59.99 per barrel for the nine months ended November 30, 2009. A table of our revenues for the nine months ended November 30, 2009 compared to the nine months ended November 30, 2008 follows:


	Nine Months Ended November 30, 2009		Nine Months Ended November 30, 2008

California – East Slopes	$	285,133	$	—

Total Revenues	$	285,133	$	—

Costs and Expenses. Total operating expenses for the nine months ended November 30, 2009 decreased by $334,446, compared to the nine months ended November 30, 2008. Significant decreases occurred in exploration and drilling costs as well as G&A costs in comparison with the three months ended November 30, 2008. We experienced substantial increases in both production costs and DD&A costs for the nine months ended November 30, 2009 in comparison to the nine months ended November 30, 2008.

A table of our costs and expenses for the nine months ended November 30, 2009 compared to the nine months ended November 30, 2008 follows:


	Nine Months Ended November 30, 2009		Nine Months Ended November 30, 2008

Production Costs	$	221,700	$	—
Exploration Costs		156,468		538,521
Depreciation, Depletion, Amortization & Impairment		525,112		112,533
Bad debt expense		81,439		—
General & Administrative		1,175,662		1,843,773

Total Operating Expenses	$	2,160,381	$	2,494,827

Production costs for the nine months ended November 30, 2009 were $221,700, which is higher than normal because of the lack of permanent electrical service and the need to use rental equipment for temporary production facilities. The installation of permanent production facilities was completed during the quarter ended November 30, 2009 and production costs are expected to decline on a per well basis. These production costs represented 10.3% of total operating expenses from continuing operations.

For the nine months ended November 30, 2009 exploration costs decreased $382,053 or 70.9%, compared to the nine months ended November 30, 2008. Exploration costs (“G&G”) and dry hole expenses were both higher in the prior comparative period because of lease acquisition costs and the recognition for the drilling of two non-commercial wells in California. These costs represented 7.2% of total operating expenses from continuing operations.

DD&A and impairment expenses increased $412,579 or 366% for the nine months ended November 30, 2009 compared to the nine months ended November 30, 2008. This increase relates directly to the impairment on the sale of the additional 25% working interest acquired from certain defaulting working interest partners in our California project. An impairment of approximately $342,000 was recognized in the acquisition of that additional 25% working interest. The balance of the increase is due to depreciation of our production facilities and depletion in our producing wells in California. These costs represented 24.3% of total operating expenses from continuing operations.

Bad debt expense of $81,439 was incurred for the nine months ended November 30, 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 3.8% of total operating expenses from continuing operations.

G&A costs decreased $668,111, or 36.2%, for the nine months ended November 30, 2009 in comparison to the nine months ended November 30, 3008. While we continue to cut and control our G&A expenses wherever possible, the primary reason for the decline in expenses when compared to the nine months ended November 30, 2008 was the recognition of certain non-cash expenses associated with the issuance of goodwill warrants to investors in two private placement offerings that occurred in 2006 in the prior comparative period. Our accounting and legal costs, both components of G&A, decreased approximately $154,561, or 42.4%, from the nine months ended November 30, 2008 as we have improved our internal controls over financial reporting and have completed the additional corporate compliance projects that we planned to implement. G&A costs represented 54.4% of total operating expenses from continuing operations.

Interest and dividend income decreased $15,973, or 59.1%, compared to the nine months ended November 30, 2008 due to lower average cash and cash equivalent balances.

Nine Months Ended November 30, 2009 compared to the Nine Months Ended November 30, 2008 - Discontinued Operations

Alabama (East Gilbertown Field)

The following table presents the revenues and expenses related to the East Gilbertown Field for the nine months ended November 30, 2009 and November 30, 2008. Prior period income statement amounts applicable to the East Gilbertown Field have been reclassified and included under Income (loss) from discontinued operations. The cost and expense information for the East Gilbertown Field reflects certain non-recurring credits that result in this information being additions to revenue rather than deductions from revenue.


	Nine Months Ended November 30, 2009		Nine Months Ended November 30, 2008

Oil sales revenue – East Gilbertown Field	$	62,418	$	134,177
Cost and expenses		17,722		25,234

Income (loss) from discontinued operations	$	80,140	$	159,411

Louisiana (Krotz Springs Project)

Gas production from the current producing reservoir has declined significantly and we have decided to no longer continue our participation in this project. We are in the process of transferring our interest to third parties and will no longer participate in future activities on this property. Because of the low prices for gas and oil in prior periods, we have fully impaired our capitalized cost in this property.


	Nine Months Ended November 30, 2009			Nine Months Ended November 30, 2008

Oil sales revenue – Krotz Springs Field	$	1,767		$	57,013
Cost and expenses		(25,089	)		(52,369	)

Income (loss) from discontinued operations	$	(23,322	)	$	4,644

Summary

Daybreak Oil and Gas, Inc. continues to execute its plan to develop its acreage in Kern County California. The production and operating infrastructure is now in place and operating. We will now focus our efforts on drilling development wells, as well as drilling several exploration wells over the next twelve months, which coupled with the completion of our production and operating infrastructure and expectation for higher oil prices, will increase our net cash flow. This process has already begun with the drilling of three wells in December 2009 and early January 2010. We will need to obtain the funds for our future exploration and development activities through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these instruments which can result in dilution to existing security holders and increased debt and leverage. We are pursuing financing alternatives; however no assurance can be given that we will be able to obtain any additional financing on favorable terms, if at all. The Company is also

continuing its efforts to sell its Gilbertown property in Alabama, which would include the release of its certificate of deposit of $250,000 which collateralizes the Company’s operator’s bond.

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 November 30, 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.

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, November 30, 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 November 30, 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.

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.

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 6. EXHIBITS

The following Exhibits are filed as part of the report:


Exhibit Number		Description

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.

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
		(Principal Executive Officer, Principal Financial
		Officer and Principal Accounting Officer)

Date:		January 8, 2010