DAYBREAK OIL & GAS, INC. - Quarter Report: 2010 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, 2010
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 12, 2011 the registrant had 48,761,599 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, 2010 and February 28, 2010 (Unaudited)	3

	Statements of Operations for the Three and Nine Months Ended November 30, 2010 and November 30, 2009 (Unaudited)	4

	Statements of Cash Flows for the Nine Months Ended November 30, 2010 and November 30, 2009 (Unaudited)	5

	Notes to Unaudited Financial Statements	6

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	28

ITEM 4T.	Controls and Procedures	28

PART II - OTHER INFORMATION

ITEM 1.	Legal Proceedings	29

ITEM 1A.	Risk Factors	29

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29

ITEM 6. EXHIBITS		31

Signatures		32

PART I
FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DAYBREAK OIL AND GAS, INC.
Balance Sheets - Unaudited


	As of November 30, 2010			As of February 28, 2010


ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	123,425		$	247,951
Accounts receivable:
Oil and gas sales		195,660			257,110
Joint interest participants, net of allowance for doubtful accounts of $33,346 and $16,237 respectively		357,072			215,648
Receivables associated with assets held for sale, net of allowance for doubtful accounts of $38,012		—			303,097
Production revenue receivable		25,000			25,000
Prepaid expenses and other current assets		105,270			21,735

Total current assets		806,427			1,070,541
OIL AND GAS PROPERTIES, net of accumulated depletion, depreciation, amortization, and impairment, net of $950,079 and $1,783,258 respectively, successful efforts method Proved properties		1,723,806			1,189,566
Unproved properties		444,577			21,233
VEHICLES AND EQUIPMENT, net of accumulated depreciation of $31,329 and $29,841 respectively		—			1,488
PRODUCTION REVENUE RECEIVABLE -LONG TERM		325,000			325,000
OTHER ASSETS		104,727			402,208

Total assets	$	3,404,537		$	3,010,036


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,987,509		$	1,240,909
Accounts payable - related parties		46,250			31,898
Liabilities associated with assets held for sale		—			110,124
Accrued interest		24,270			5,408
Notes payable, net of discount of $45,158		704,842			—

Total current liabilities		2,762,871			1,388,339
LONG TERM LIABILITIES:
Notes payable, net of discount of $103,636 and $110,056 respectively		491,364			454,944
Asset retirement obligation		74,129			53,318

Total liabilities		3,328,364			1,896,601
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; 916,565 and 1,008,565 shares issued and outstanding respectively		917			1,009
Common stock- 200,000,000 shares authorized; $0.001 par value, 48,761,599 and 47,785,599 shares issued and outstanding respectively		48,763			47,786
Additional paid-in capital		22,424,464			22,255,802
Accumulated deficit		(22,397,971	)		(21,191,162	)

Total stockholders’ equity		76,173			1,113,435

Total liabilities and stockholders’ equity	$	3,404,537		$	3,010,036

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,

	2010			2009			2010			2009

REVENUE:
Oil and gas sales	$	259,064		$	119,481		$	759,121		$	286,900

OPERATING EXPENSES:
Production costs		56,778			52,121			105,709			244,394
Exploration and drilling		18,938			52,542			163,221			156,468
Depreciation, depletion, amortization, and impairment		146,651			173,095			383,708			525,680
Gain on write-off of asset retirement obligation		—			—			(8,324	)		—
Bad debt expense (recovery)		1,119			4,750			(3,928	)		81,439
General and administrative		429,483			297,250			1,234,423			1,092,210

Total operating expenses		652,969			579,758			1,874,809			2,100,191

OPERATING LOSS		(393,905	)		(460,277	)		(1,115,688	)		(1,813,291	)


OTHER INCOME (EXPENSE):
Interest income		267			2,043			1,947			11,912
Interest expense		(57,424	)		(96	)		(104,085	)		(859	)

Total other income (expense)		(57,157	)		1,947			(102,138	)		11,053


LOSS FROM CONTINUING OPERATIONS		(451,062	)		(458,330	)		(1,217,826	)		(1,802,238	)

DISCONTINUED OPERATIONS

Income (loss) from discontinued operations (net of tax of $-0-)		—			(9,870	)		731			(5,139	)
Income (loss) from sale of oil and gas properties (net of tax of $-0-)		60			—			10,286			—

INCOME (LOSS) FROM DISCONTINUED OPERATIONS		60			(9,870	)		11,017			(5,139	)


NET LOSS		(451,002	)		(468,200	)		(1,206,809	)		(1,807,377	)

Cumulative convertible preferred stock dividend requirement		(42,997	)		(50,561	)		(132,722	)		(153,139	)


NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(493,999	)	$	(518,761	)	$	(1,339,531	)	$	(1,960,516	)


NET LOSS PER COMMON SHARE
Loss from continuing operations	$	(0.01	)	$	(0.01	)	$	(0.03	)	$	(0.04	)
Income (loss) from discontinued operations		—			—			—			—

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

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - Basic and diluted		48,592,488			47,641,559			48,147,402			47,054,303

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,

	2010			2009

CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,206,809	)	$	(1,807,377	)
Adjustments to reconcile net loss to net cash used in operating activities:
Stock compensation		65,704			57,255
Gain on write-off of asset retirement obligation		(8,324	)		—
Gain on sale of oil and gas properties		(10,286	)		—
Depreciation, depletion, and impairment expense		383,708			526,354
Amortization of debt discount		26,756			—
Amortization of loan origination fees		5,938			—
Bad debt expense (recovery)		(3,928	)		81,439
Non cash interest income		(1,947	)		(10,182	)
Non cash general and administrative expense		—			21,676
Warrant expense for services		14,600			—
Changes in assets and liabilities:
Accounts receivable - oil and gas sales		61,450			(96,221	)
Accounts receivable - joint interest participants		(137,496	)		(488,332	)
Receivables associated with assets held for sale		303,097			—
Prepaid expenses and other current assets		(65,723	)		(30,635	)
Accounts payable and other accrued liabilities		649,115			(547,292	)
Accounts payable - related parties		14,352			(22,348	)
Accrued interest		18,862			—

Net cash provided by (used in) operating activities		109,069			(2,315,663	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(1,313,023	)		(514,090	)
Disposition of other assets		299,428			—
Proceeds from sale of oil and gas properties		—			862,500

Net cash provided by (used in) investing activities		(1,013,595	)		348,410

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of notes payable		780,000			—

Net cash provided by financing activities		780,000			—

NET DECREASE IN CASH AND CASH EQUIVALENTS		(124,526	)		(1,967,253	)

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


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	123,425		$	315,557


CASH PAID FOR:
Interest	$	108,779		$	859
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	$	349,688		$	75,394
Addition to asset retirement obligation	$	35,304		$	14,629
Discount on notes payable - Long term	$	5,284		$	—
Discount on notes payable - Short term	$	60,210		$	—
Conversion of preferred stock to common stock	$	276		$	21
Stock issued for loan origination fees	$	23,750		$	—

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 on March 11, 1955, as Daybreak Uranium, Inc. under the laws of the State of Washington, the Company was organized to explore for, acquire, and develop mineral properties in the Western United States. In March 2005, management of the Company decided to enter the oil and gas exploration industry, and 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 footnote 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, 2010 are not necessarily indicative of the results that may be expected for the fiscal year ending February 28, 2011.

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 fiscal year ended February 28, 2010.

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, 2010 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. The Company has incurred net losses since inception and as of November 30, 2010 has an accumulated deficit of $22,397,971 which raises substantial doubt about the Company’s ability to continue as a going concern.

Management Plans to Continue as a Going Concern

The Company continues to implement plans to enhance Daybreak’s ability to continue as a going concern. The Company currently has a net revenue interest in eleven producing wells in our East Slopes Project located in Kern County, California (the “East Slopes Project”). The revenue from these wells has created a steady and reliable source of revenue for the Company.

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest from another working interest owner in the East Slopes Project. This increase in the Company’s working interest increased its monthly net revenue by 75.76% or between $15,000 and $20,000 per month on the five wells that were affected by this purchase. Daybreak’s average net revenue interest in Kern County, California has increased from 21.83% to 28.77%. The Company anticipates revenues will continue to increase as it participates in the drilling of more wells in California. The Company plans to continue its development drilling program at a rate that is compatible with its cash flow and funding opportunities.

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company does have positive cash flow from its oil and gas properties, it has not yet established a positive cash flow on a company-wide basis. The Company anticipates it may be necessary to rely on additional funding from the private or public debt or equity markets in the future.

The Company’s financial statements as of November 30, 2010 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

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact the Company’s operating results, financial position or cash flows and related disclosures.

In February 2010, FASB issued ASU No. 2010-09, Amendments to Certain Recognition and Disclosure Requirements (ASU 2010-09). This update amends Subtopic 855-10 and gives a definition to the Securities and Exchange Commission (the “SEC”) filer, and requires SEC filers to assess for subsequent events through the issuance date of the financial statements. This amendment states that an SEC filer is not required to disclose the date through which subsequent events have been evaluated for a reporting period. ASU 2010-09 becomes effective upon issuance of the final update. The Company has adopted the provisions of ASU 2010-09.

NOTE 4 — CONCENTRATION OF CREDIT RISK

Substantially all of the Company’s accounts receivable result from 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 the Company’s East Slopes Project, there are a limited number of buyers available for the purchase of oil production. At November 30, 2010, one customer represented 100% of crude oil sales receivable 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, 2010					Three Months Ended November 30, 2009

Customer	Revenue		Percentage			Revenue		Percentage

Plains Marketing	$	259,064		100.0	%	$	118,815		99.44	%
J.P. Oil	$	-0-		-0-	%	$	666		0.56	%

	Nine Months Ended November 30, 2010					Nine Months Ended November 30, 2009

Customer	Revenue		Percentage			Revenue		Percentage

Plains Marketing	$	655,104		86.3	%	$	285,133		99.38	%
J.P. Oil**	$	104,017		13.7	%	$	1,767		0.62	%

**During the nine months ended November 30, 2010, the Company received $104,017 in revenue related to the Krotz Springs Field in Louisiana as a one-time adjustment to revenue earned in calendar years 2007, 2008 and 2009 due to well production revenue misallocation by the unitized field operator.

NOTE 5 — OIL AND GAS PROPERTIES

On March 19, 2010, the Company closed on the sale of its interest in the East Gilbertown Field in Choctaw County, Alabama to a third party with an effective date of March 1, 2010. There was no effect on net oil and gas property balances from the sale of this property since the Company had previously fully impaired its capitalized cost of approximately $257,000 in this property due to low oil prices in prior periods. In connection with the sale, the Company recognized a gain from sale of oil and gas properties for the nine months ended November 30, 2010 of $10,286 which is presented under “Discontinued Operations” in the Statement of Operations and discussed in Note 7 below. The gain resulted mainly from the extinguishment of certain liabilities associated with the Gilbertown interest.

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

NOTE 6 — NOTES PAYABLE

Short-Term

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest in its East Slopes Project from another working interest owner. The Company financed the additional working interest purchase by issuing, to a third party, a one-year convertible secured promissory note for the principal amount of $750,000 (the “Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing. The third party may convert up to 50% of the unpaid principal balance into the Company’s common stock at a conversion price of $0.16 per share at any time prior to the Loan being paid in full.

The Company also issued 250,000 shares of the Company’s common stock to the third party as a loan origination fee. The fair value of these shares amounted to $23,750 which were deferred and amortized over the term of the Loan. Amortization expense for the nine months ended November 30, 2010 amounted to $5,938.

The Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in the Company’s East Slopes Project. Furthermore, as a condition precedent to the Loan, the Company entered into a Technical and Consulting Services Agreement with the third party, whereby the Company will provide operating, engineering and technical consulting to the third party for a one-year period for the purpose of evaluating 22 wells in Hutchinson County, Texas for the third party. After six months, Daybreak, at its sole discretion, will have the right to obtain a 10% working interest in the 22 wells in Hutchinson County, Texas at no additional cost.

As additional consideration for the Loan the Company executed an Assignment of Net Profits Interest in favor of the third party, whereby the Company assigned two percent of the net profits realized by the Company on its leases in the East Slopes Project. The fair value of the two percent net profits interest was determined to be $60,210 and has been recognized as a discount to the debt. The debt discount is amortized over the term of the Loan. Amortization expense for the nine months ended November 30, 2010 amounted to $15,053.

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

Long-Term

On March 16, 2010, the Company closed its private placement of 12% Subordinated Notes (the “Notes”) resulting in additional gross proceeds of $30,000 for the nine months ended November 30, 2010. Gross proceeds from the private placement were $565,000 before the fiscal year end of February 28, 2010, for total

gross proceeds of $595,000 from the issuance of the Notes. A total of 1,190,000 warrants were issued in conjunction with the private placement. The Notes are subject to an annual interest rate of 12%, payable semi-annually, and mature on January 29, 2015. On the maturity date, the Company may elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2014. As of November 30, 2010, Notes issued to a related party amounted to $250,000.

Two common stock purchase warrants were issued for every dollar raised through the private placement, which included 60,000 warrants being issued during the nine months ended November 30, 2010. All warrants issued in conjunction with the Notes private placement have an exercise price of $0.14 and expire on January 29, 2015. The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $5,284 using the following assumptions: a risk free interest rate of 2.37%; volatility of 144.1%; and dividend yield of 0.0%. The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method.

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

NOTE 7 — DISCONTINUED OPERATIONS

On March 19, 2010, the Company finalized the sale of its interest in the East Gilbertown Field in Choctaw County, Alabama. The East Gilbertown sale resulted in a gain from the sale of oil and gas properties for the nine months ended November 30, 2010 of $10,286, primarily as a result of the elimination of the associated asset retirement obligation.

The following tables present the revenues and expenses related to the East Gilbertown Field for each of the three month and nine month periods ended November 30, 2010 and 2009 which are presented on the Statement of Operations under the caption “Discontinued Operations”. The cost and expense information for the three months ended November 30, 2010 and 2009 reflect certain credits that result in this information being additions to revenue rather than deductions from revenue. Prior period income statement amounts applicable to the above projects have been reclassified and included under Income (loss) from discontinued operations.


	Three Months Ended November 30, 2010		Three Months Ended November 30, 2009

Oil sales revenue – East Gilbertown Field	$	—	$	19,213
Cost and expenses		60		29,083

Income (loss) from discontinued operations	$	60	$	(9,870	)


	Nine Months Ended November 30, 2010		Nine Months Ended November 30, 2009

Oil sales revenue – East Gilbertown Field	$	—	$	62,418
Cost and expenses		731		67,557

Income (loss) from discontinued operations	$	731	$	(5,139	)

NOTE 8 — COMMON STOCK

Company agreed to pay the third party a loan origination fee equal to 250,000 shares of the Company’s common stock within 60 days after September 17, 2010 or such later date as mutually agreed to between the Company and the third party. These shares were issued on October 8, 2010. The closing price of the Company’s stock on September 17, 2010 was $0.095 and the stock issuance was valued at $23,750.

NOTE 9 — SERIES A CONVERTIBLE PREFERRED STOCK

The Company is authorized to issue up to 10,000,000 shares of $0.001 par value preferred stock. The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as “Series A Convertible Preferred Stock” (“Series A Preferred”), with a $0.001 par value. The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s common stock. During the three months ended November 30, 2010, a total of 60,000 shares of Series A Preferred stock were converted to 180,000 shares of common stock. For the nine months ended November 30, 2010, a total of 92,000 shares of Series A Preferred stock were converted to 276,000 shares of common stock. As of November 30, 2010, 29 shareholders have converted 483,200 Series A Preferred shares into 1,449,600 shares of common stock. At November 30, 2010, there were 916,565 Series A Preferred shares outstanding that had not been converted into the Company’s common stock.

Holders of Series A Preferred earn a 6% annual cumulative dividend based on the original purchase price of the shares. Accumulated dividends do not bear interest; and as of November 30, 2010, the accumulated and unpaid dividends amounted to $922,048. Dividends may be paid in cash or common stock at the discretion of the Company and are payable upon declaration by the Board of Directors. Dividends are earned until the Series A Preferred is converted to common stock. No payment of dividends has been declared as of November 30, 2010.

The table below details the cumulative dividends on the Series A Preferred 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		237,740
Year Ended February 28, 2009	78		208,855
Year Ended February 28, 2010	74		188,795
Nine Months Ended November 30, 2010	71		132,722

Total Accumulated Dividends		$	922,048

NOTE 10 — WARRANTS

Warrants outstanding and exercisable as of November 30, 2010 are shown in the table below:


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

Spring 2006 Common Stock Private Placement (“PP”)		4,013,602		$2.00		0.50		4,013,602
Placement Agent Warrants Spring 2006 PP		802,721		$0.75		2.50		802,721
Placement Agent Warrants Spring 2006 PP		401,361		$2.00		2.50		401,361
July 2006 Preferred Stock PP		2,799,530		$2.00		0.75		2,799,530
Placement Agent Warrants July 2006 PP		419,930		$1.00		2.75		419,930
Convertible Debenture Term Extension		150,001		$2.00		1.00		150,001
Placement Agent Warrants January 2008 PP		39,550		$0.25		0.25		39,550
12% Subordinated Note Warrants		1,190,000		$0.14		4.00		1,190,000
Warrants Issued in 2010 for Services		150,000		$0.14		4.50		150,000

		9,966,695						9,966,695

During the nine months ended November 30, 2010, a total of 60,000 warrants were issued as part of the 12% Subordinated Note private placement, while prior to the fiscal year end of February 28, 2010, 1,130,000 warrants were issued, leading to a total issuance of 1,190,000 warrants as part of the 12% Subordinated Notes private placement as discussed in Note 6 above.

Additionally during the nine months ended November 30, 2010, 150,000 warrants were issued to a consultant as payment for services rendered. These warrants have an exercise price of $0.14 and expire on April 16, 2015. The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $14,600 using the following assumptions: a risk free interest rate of 2.49%; volatility of 143.5%; and dividend yield of 0.0%.

No warrants were exercised or expired during the period. As of November 30, 2010 and February 28, 2010, there were 9,966,695 and 9,756,695 warrants issued and outstanding, respectively.

The outstanding warrants as of November 30, 2010, have a weighted average exercise price of $1.60; a weighted average remaining life of 1.39 years; and an intrinsic value of $-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 22, 2010, a total of 25,000 restricted shares were granted to the five non-employee directors, as approved by the Compensation Committee of the Board. These restricted shares were granted under the Company’s director compensation plan and pursuant to the 2009 Plan and fully vest equally over a period of three years or upon the retirement of the director from the Board.

On July 22, 2010, a total of 425,000 restricted shares of the Company’s common stock were granted to five employees of the Company, as approved by the Compensation Committee of the Board. These restricted shares were granted pursuant to the 2009 Plan and fully vest equally over a period of four years.

At November 30, 2010, a total of 1,000,000 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 (Unvested)

4/7/2009		1,900,000		3 Years		633,331		1,266,669
7/16/2009		25,000		3 Years		8,330		16,670
7/16/2009		625,000		4 Years		156,250		468,750
7/22/2010		25,000		3 Years		0		25,000
7/22/2010		425,000		4 Years		0		425,000

		3,000,000				797,911		2,202,089

For the nine months ended November 30, 2010 and 2009, the Company recognized compensation expense related to the above restricted stock grants of $65,704, and $57,255, respectively. Unamortized compensation expense amounted to $156,100 as of November 30, 2010.

NOTE 12 — INCOME TAXES

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


	Nine Months Ended November 30, 2010			Nine Months Ended November 30, 2009

Computed at U.S. and state statutory rates (40%)	$	(482,725	)	$	(722,951	)
Permanent differences		37,979			10,417
Changes in valuation allowance		444,746			712,534

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, 2010			February 28, 2010

Deferred tax assets:
Net operating loss carryforwards	$	5,812,210		$	5,114,269
Oil and gas properties		(130,133	)		123,062
Less valuation allowance		(5,682,077	)		(5,237,331	)

Total	$	—		$	—

At November 30, 2010, the Company had estimated net operating loss carryforwards for federal and state income tax purposes of approximately $14,530,525 which will begin to expire, if unused, beginning in 2024. The valuation allowance increased approximately $444,746 for the nine months ended November 30, 2010 and increased by $891,047 for the year ended February 28, 2010. Section 382 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 13 — COMMITMENTS AND CONTINGENCIES

Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities. At the current time, the Company is not involved in any lawsuits or claims. While the ultimate outcome of any future contingency is 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, 2010. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

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. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:


	•	General economic and business conditions,

	•	Exposure to market risks in our financial instruments,

	•	Fluctuations in worldwide prices and demand for oil and natural gas,

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

	•	Fluctuations in the levels of our oil and natural gas exploration and development activities in a concentrated area,

	•	Risks associated with oil and natural gas exploration and development activities,

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

	•	Technological changes and developments in the oil and natural gas industry,

	•	Legislative and regulatory uncertainties, including proposed changes to federal tax laws, drilling industry legal change, climate change legislation, and potential environmental liabilities,

	•	Our ability to continue as a going concern,

	•	Our ability to secure additional capital to fund operations, and

	•	Other factors discussed elsewhere in this Form 10-Q and in our public filings, press releases and discussions with Company management.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically undertake no obligation to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except as required by law. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Introduction and Overview

The following MD&A is management’s assessment of the historical financial and operating results of the Company for the three and nine month periods ended November 30, 2010 and November 30, 2009 and of our financial condition as of November 30, 2010 and is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and results of operations and cash flows; and, should be read in conjunction with our unaudited financial statements and notes included elsewhere in this Form 10-Q and in our Annual Report on Form 10-K for the fiscal year ended February 28, 2010. Unless otherwise noted, all of this discussion refers to continuing operations in Kern County, California.

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. The volatile nature of the energy markets makes it difficult to estimate future prices of oil and natural gas; however, any prolonged period of depressed prices would have a material adverse effect on our results of operations and financial condition. Our operations are focused on identifying and evaluating prospective oil and gas properties and funding projects that we believe have the potential to produce oil or gas in commercial quantities. We are in the process of developing a multi-well oilfield project in Kern County, California and have participated in the drilling of eleven oil wells that have achieved commercial production. This project is comprised of three project areas: East Slopes, East Slopes North and the Expanded AMI project.

Kern County, California (East Slopes Project and East Slopes North Project)

On September 17, 2010, we finalized the acquisition of an additional 16.67% working interest from another working interest owner in the East Slopes Project. This additional working interest is anticipated to increase our monthly revenue from the five wells affected by this purchase by 75.76% or between $15,000 and $20,000. With this purchase our average net revenue interest in Kern County, California has increased from 21.83% to 28.77%.

East Slopes Project. The installation of permanent production facilities and electrical power to service the wells in the Sunday, Bear and Black property locations has been completed. Work is continuing on the completion of electrical service to our production facilities at the Dyer Creek Field location. Our 3-D seismic data evaluation is continuing and the reprocessing of the data to enhance the quality of prospects is expected to yield more than the current 8 to 10 exploration prospects already identified on this acreage. Refer to the discussion below for additional information on our producing properties in the East Slopes Project area.

The Company is now well positioned to expand its operations in the East Slopes Project having found five reservoirs at our Bear, Sunday, Black, Ball and Dyer Creek locations. The Sunday location is now fully developed with three vertical wells and one horizontal well. At least one more development well is planned for our Bear location. 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. The Dyer Creek and Ball reservoirs were put on production in late October 2010. There are several other similar prospects on trend with the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic characteristics. Some of these prospects, if successful, would utilize the Company’s existing production

facilities. In addition to the current field development, there are several other exploratory prospects that have been identified from the seismic data, which we plan to drill in the future.

Sunday Property

In November 2008, we made our initial oil discovery drilling the Sunday #1 well. The well was put on production in January 2009. Production is from the Vedder sand at approximately 2,000 feet. During 2009, we drilled three development wells including one horizontal well. The Sunday reservoir is now fully developed and we have no other plans to drill any more wells in this reservoir. With the acquisition of the additional 16.67% working interest in the East Slopes Project in September 2010, we have a 41.67% working interest with a 29.0% net revenue interest in the Sunday #1 well. We continue to have a 37.5% working interest with a 27% net revenue interest in each of the Sunday #2 and #3 wells. In the Sunday #4 well, we own a 37.5% working interest with a 30.1% net revenue interest.

Bear Property

In February 2009, we made our second oil discovery drilling the Bear #1 well which is approximately one mile northwest of our Sunday discovery. The well was put on production in May 2009. Production is from the Vedder sand at approximately 2,200 feet. In December 2009, we began a development program by drilling and completing the Bear #2 well. In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells. We plan to drill at least one more development well before the Spring of 2011. With the acquisition of the additional 16.67% working interest in the East Slopes Project in September 2010, we have a 41.67% working interest with a 29.0% net revenue interest in each of the Bear wells in this property.

Black Property

The Black property was acquired through a farm-in arrangement with a local operator. The Black location is just south of the Bear location on the same fault system. During January 2010, we drilled the Black #1 well. The well was completed and put on production in January 2010. Production is from the Vedder sand at 2,150 feet. We have a 37.5% working interest with a 29.8% net revenue interest at this property.

Sunday Central Processing and Storage Facility

The oil produced from our acreage is considered heavy oil. The oil ranges from 13º to 15º API gravity. All of our oil from the Sunday, Bear and Black locations is processed, stored and sold from this facility. The oil must be heated to separate and remove the water to prepare it to be sold. We constructed these facilities during the Summer and Fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines. As a result, our average operating costs have been reduced from over $40 per barrel to below $17 per barrel of oil after accounting for the loss of certain oil processing credits that ceased with our purchase of an additional 16.67% working interest in September 2010. By having this central facility and permanent electrical power, it ensures that our operating expenses are kept to a minimum.

Ball Property

The Ball #1-11 well was put on production in late October 2010. Our 3-D seismic indicates approximately 40 acres of closure, similar in size to the Bear Property. We are currently planning a development program for this property. Production from the Ball #1-11 well is being processed at the Dyer Creek production facility. We have a 41.67% working interest with a 34.69% net revenue interest at this property.

Dyer Creek Property

The Dyer Creek #67X-11 well was also put on production in late October 2010. This well is producing from the 1^st Vedder sand and is located to the north of the Bear reservoir on the same trapping fault. We are currently planning a development program for this property. Production from the Dyer Creek #67X-11 well

is also being processed at the Dyer Creek production facility. We have a 41.67% working interest with a 34.69% net revenue interest at this property.

Dyer Creek Processing and Storage Facility

The Dyer Creek Processing and Storage Facility serves the Dyer Creek and Ball properties and includes previously abandoned infrastructure that we have refurbished. We are currently in the process of installing electrical service to this location. Once this is completed, our oil processing costs should be significantly reduced. The oil produced into this facility has similar API gravity to the oil at the Sunday production facility in that the oil must be heated to separate and remove the water to prepare it to be sold.

Bull Run Prospect

This is an Etchegoin and Santa Margarita sand prospect with drilling targets located between 800 and 1,200 feet deep. We plan to drill an exploratory well on this prospect during the early part of 2011. Based on wells drilled by previous operators and our recently reprocessed 3-D seismic data, we estimate that the Bull Run Prospect is approximately 280 acres in size and has oil pay thickness that ranges from 35 feet to 70 feet. The Bull Run wells will require a pilot steam flood and additional production facilities.

Production, Revenue and LOE

The table below shows our net production volume, net revenue and net lease operating expenses (“LOE”) by property location for the three months and nine months ended November 30, 2010 and November 30, 2009 in Kern County, California. Due to certain oil processing credits that we received from December 2009 through August 2010, our overall production costs for the Sunday #1 well and all four Bear wells during that time period were significantly less than the overall production costs for the other Sunday wells and the Black #1 well. These oil processing credits ended September 1, 2010 with our acquisition of a portion of another working interest owner’s interest in this project.


	Three Months Ended					Nine Months Ended
Property	November 30, 2010		November 30, 2009			November 30, 2010		November 30, 2009

Sunday
Production (Bbls)		1,751		1,545			5,267		3,968
Revenue	$	128,794	$	99,745		$	372,498	$	233,991
LOE Costs	$	22,319	$	42,546		$	52,045	$	108,735

Bear
Production (Bbls)		1,364		292			3,011		822
Revenue	$	101,063	$	19,070		$	216,087	$	51,142
LOE Costs	$	11,056	$	11,694		$	11,065	$	66,937

Black
Production (Bbls)		292		—			825		—
Revenue	$	21,414	$	—		$	58,723	$	—
LOE Costs	$	3,845	$	—		$	11,117	$	—

Dyer Creek/Ball
Production (Bbls)		101		—			101		—
Revenue	$	7,796	$	—		$	7,796	$	—
LOE Costs	$	11,236	$	—		$	11,236	$	—

Infrastructure Costs	$	8,322	$	(2,119	)	$	20,246	$	14,765

Total
Production (Bbls)		3,508		1,836			9,204		4,791
Revenue	$	259,064	$	118,815		$	655,104	$	285,134
LOE Costs	$	56,778	$	52,121		$	105,709	$	190,437

Average Sales Price	$	73.85	$	64.70		$	71.18	$	59.52

Average LOE Cost	$	16.19	$	28.39		$	11.49	$	39.75

For the nine months ended November 30, 2010, production on the Sunday property was from four wells in comparison to three wells for the comparative nine months ended November 30, 2009. The Bear property had production from two wells for nine months and an additional two wells for seven months during the nine months ended November 30, 2010 in comparison to one well for the nine months ended November 30, 2009.

Initial production costs for the Dyer Creek and Ball properties were higher than normal because of the generator rental and fuel costs in the place of electricity. Once the installation of electrical service is completed to the Dyer Creek Processing and Storage Facility, the production costs will be significantly reduced and are anticipated to be similar to the wells on the Sunday, Bear and Black properties on an average per well basis.

The table below shows our net sales volume, net revenue and net LOE for all California properties for the last five quarterly periods ended November 30, 2010.


	Three Months Ended November 30, 2010		Three Months Ended August 31, 2010		Three Months Ended May 31, 2010		Three Months Ended February 28, 2010		Three Months Ended November 30, 2009

Production (Bbls)		3,508		2,976		2,720		2,690		1,836
Revenue	$	259,064	$	202,987	$	193,051	$	184,224	$	118,815
LOE Costs	$	56,778	$	19,514	$	30,393	$	23,815	$	52,121

Average Sales Price	$	73.85	$	68.21	$	70.97	$	68.48	$	64.70

Average LOE Cost	$	16.18	$	6.56	$	11.17	$	8.85	$	28.39

As evidenced in the table above, quarterly LOE costs have generally declined since the start-up of our production facilities during the quarter ended November 30, 2009, even with the increased production resulting from the additional wells that have been drilled since November 2009. Certain oil processing credits that we were receiving on the Sunday #1 well and the four Bear wells had been recorded as a reduction of production costs for those five wells. These oil processing credits began in December 2009 and ended on September 1, 2010.

East Slopes North Project. As part of the sale of a 25% working interest by us 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 East Slopes Project area. We are considering plans to acquire a seismic survey over that area in 2011.

Tulare County, California (Expanded AMI Project)

Expanded AMI Project. This project in Tulare County, California is also located in the San Joaquin Basin. Since 2006, Daybreak and its partners have leased approximately 9,000 acres. Three prospect areas have been identified to the north of the East Slopes Project and East Slopes North Project areas in Kern County. A 3-D seismic survey over the prospect area is required before any exploration drilling can be done. We currently have a 50% working interest in this project area.

Three Months Ended November 30, 2010 compared to the Three Months Ended November 30, 2009 - Continuing Operations

The following discussion compares our results for the three month periods ended November 30, 2010 and November 30, 2009. In December 2009, we ended our involvement in the Krotz Springs Project in Louisiana. Unless otherwise referenced, these operating results only cover our continuing operations at the East Slopes Project in Kern County, California.

Revenues. Revenues are derived entirely from the sale of our share of oil production. We realized the first revenues from producing wells in California during February 2009. For the three months ended November

30, 2010, oil revenues from continuing operations were $259,064 in comparison to $118,815 for the three months ended November 30, 2009. This represents an increase of $140,249 or 118.0%.

The revenues for the three months ended November 30, 2010 were from eleven producing wells in California. The Ball #1-11 and Dyer Creek #67X-11 wells, located on the Ball and Dyer Creek properties, were put into production in late October 2010. Our net share of production was 3,508 and 1,836 barrels with an average price of $73.85 and $64.70 per barrel for the three months ended November 30, 2010 and November 30, 2009, respectively. A table of our revenues follows:


	Three Months Ended November 30, 2010		Three Months Ended November 30, 2009

California - East Slopes Project	$	259,064	$	118,815
Louisiana - Krotz Springs		-0-		666

Total Revenues	$	259,064	$	119,481

Costs and Expenses. Operating expenses for the three months ended November 30, 2010 increased by $73,211 or 12.6% compared to the three months ended November 30, 2009. A significant decrease of $60,048 or 26.6% occurred in exploration & drilling and depreciation, depletion and amortization (“DD&A”) costs, but this was offset by an increase of $132,233 or 44.5% in general and administrative (“G&A”) costs. Production costs and bad debt expense for the three months ended November 30, 2010 remained relatively unchanged in comparison to the three months ended November 30, 2009.

A table of our costs and expenses for the three months ended November 30, 2010 and November 30, 2009 follows:


	November 30, 2010		November 30, 2009

Production Costs	$	56,778	$	52,121
Exploration and Drilling		18,938		52,542
DD&A		146,651		173,095
Bad debt expense		1,119		4,750
G&A		429,483		297,250

Total Operating Expenses	$	652,969	$	579,758

Production costs include costs directly associated with the generation of oil and gas revenues, road maintenance and well workover costs. For the three months ended November 30, 2010, these costs increased by $4,657 or 8.9% compared to the three months ended November 30, 2009. The increase in production costs is directly related to the number of producing wells in the two comparative periods. For the three months ended November 30, 2010 we had eleven producing wells, nine of which produced for the entire three month period. The other two wells were put on production in late October 2010. In the three months ended November 30, 2009 we had four producing wells in California. Production costs for the two wells that were put on production in October 2010 are currently higher than they will be once electrical service installation is completed to the wells and associated production facilities. The oil processing credits that we were receiving for five wells using the Sunday Central Processing and Storage Facility ended September 1, 2010 and this also contributed to higher production costs at this facility. Production costs represented 8.7% of total operating expenses.

Exploration and drilling 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, 2010 these costs decreased $33,604 or 64.0%, in comparison to the three months ended November 30, 2009. Exploration costs decreased primarily because of fewer leases and the timing of when certain leases became due to renewal dates on the leases. Exploration and drilling costs represented 2.9% of total operating expenses.

DD&A of equipment costs, proven reserves and property costs along with impairment are another component of operating expenses. DD&A expenses decreased $26,444 or 15.3% for the three months ended

November 30, 2010 compared to the three months ended November 30, 2009. DD&A represented 22.4% of total operating expenses.

Bad debt expense decreased $3,631 or 76.4% for the three months ended November 30, 2010 in comparison to the three months ended November 30, 2009. Bad debt expense represented 0.2% of total operating expenses.

G&A expenses, including management and employee salaries, legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative costs for the three months ended November 30, 2010 increased $132,233 or 44.5%, compared to the three months ended November 30, 2009. G&A expenses were higher in legal, accounting, advertising & marketing and fundraising costs for the three months ended November 30, 2010. Management and employee salaries, director fees and stock compensation decreased by $6,270 or 2.9%. Travel and associated costs decreased by $10,010 or 61.9% for the three months ended November 30, 2010. For the three months ended November 30, 2009, we received, as Operator, administrative overhead reimbursement of approximately $26,318 for the East Gilbertown Field in Alabama which was used to directly offset certain employee salaries. Since we are no longer involved in this project there was no corresponding offset to employee salaries for the three months ended November 30, 2010. We are continuing a program of reducing all of our G&A costs wherever possible. G&A costs represented 65.8% of total operating expenses from continuing operations.

Interest income for the three months ended November 30, 2010 decreased $1,776 or 86.9% compared to the three months ended November 30, 2009, due to lower average cash balances.

Interest expense for the three months ended November 30, 2010 increased $57,328 compared to the three months ended November 30, 2009, due to amortization of the debt discount and interest on the 12% Subordinated Notes that were sold from January 2010 through March 2010 and amortization of loan origination fees and the fair value of the net profits interest associated with the $750,000 note payable from the acquisition of the additional working interest in Kern County, California.

Due to the nature of our business, as well as the relative immaturity of the Company, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially on a quarter-to-quarter and year-to-year basis. 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.

Three Months Ended November 30, 2010 compared to the Three Months Ended November 30, 2009 - Discontinued Operations

Alabama (East Gilbertown Field)

On March 19, 2010, we closed the sale of our interest in the East Gilbertown Field to a third party with an effective date of March 1, 2010. The cost and expense information for the three months ended November 30, 2010 reflect certain credits that result in this information being additions to revenue rather than deductions from revenue. 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 had previously 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 month periods ended November 30, 2010 and November 30, 2009.


	Three Months Ended November 30, 2010		Three Months Ended November 30, 2009

Oil sales revenue	$	—	$	19,213
Cost and expenses		60		29,083

Income (loss) from discontinued operations	$	60	$	(9,870	)

Nine Months Ended November 30, 2010 compared to the Nine Months Ended November 30, 2009 - Continuing Operations

The following discussion compares our results for the nine month periods ended November 30, 2010 and November 30, 2009. Unless otherwise referenced, these results only cover our continuing operations at the East Slopes Project in Kern County, California.

Revenues. Revenues are derived entirely from the sale of our share of oil production. For the nine months ended November 30, 2010, oil and gas revenues from continuing operations were $759,121 in comparison to $286,900 for the nine months ended November 30, 2009. This represents an increase of $472,221 or 164.6%.

The revenues for the nine months ended November 30, 2010 include a special one-time revenue adjustment in regards to the Krotz Springs well in Louisiana. The revenue adjustment of $104,017 represented additional gas revenue from May 2007 through December 2009. In Kern County, California, our net share of production was 9,204 and 4,791 barrels of oil with an average price per barrel of $71.18 and $59.52 for the nine months ended November 30, 2010 and November 30, 2009, respectively. A table of our revenues follows:


	Nine Months Ended November 30, 2010		Nine Months Ended November 30, 2009

California - East Slopes Project	$	655,104	$	285,133
Louisiana - Krotz Springs		104,017		1,767

Total Revenues	$	759,121	$	286,900

Costs and Expenses. Total operating expenses for the nine months ended November 30, 2010 decreased by $225,382 or 10.7% compared to the nine months ended November 30, 2009. Significant decreases occurred in production costs, DD&A and bad debt expense in comparison to the nine months ended November 30, 2009. These decreases were offset by an increase in G&A costs for the nine months ended November 30, 2010. Exploration and drilling showed a slight increase for the nine months ended November 30, 2010 in comparison to the nine months ended November 30, 2009.

A table of our costs and expenses for the nine months ended November 30, 2010 and November 30, 2009 follows:


	Nine Months Ended November 30, 2010			Nine Months Ended November 30, 2009

Production Costs	$	105,709		$	244,394
Exploration and Drilling		163,221			156,468
DD&A		383,708			525,680
Gain on Write-Off of Asset Retirement Obligation		(8,324	)		—
Bad debt expense (recovery)		(3,928	)		81,439
G&A		1,234,423			1,092,210

Total Operating Expenses	$	1,874,809		$	2,100,191

Production costs for the nine months ended November 30, 2010 decreased by $138,685 or 56.7% compared to the nine months ended November 30, 2009 primarily because of the completion of our production facilities. Production costs represented 5.6% of total operating expenses.

Exploration and drilling costs increased by $6,753 or 4.3% for the nine months ended November 30, 2010 compared to the nine months ended November 30, 2009 primarily because of higher leasing costs on lease renewals. Exploration and drilling costs represented 8.7% of total operating expenses.

DD&A and impairment expenses for the nine months ended November 30, 2010 decreased $141,972 or 27.0% compared to the nine months ended November 30, 2009. This decrease was due to extra impairment charges being recognized in California for the nine months ended November 30, 2009. DD&A costs represented 20.5% of total operating expenses.

Bad debt expense decreased $85,367 for the three months ended November 30, 2010 in comparison to the three months ended November 30, 2009. This decrease was primarily from the recognition of a third party bad debt related to the Krotz Springs project in Louisiana during the nine months ended November 30, 2009.

G&A expense increased $142,213, or 13.0%, for the nine months ended November 30, 2010 compared to the nine months ended November 30, 2009. Reductions were realized in the areas of travel and associated costs as well as shareholder services. Legal expenses increased $39,922 primarily due to costs associated with the 12% Subordinated notes and our acquisition of additional working interest in California during the nine months ended November 30, 2010. Management and employee salaries, director fees and stock compensation also decreased by $19,557 or 2.9% for the three months ended November 30, 2010. For the nine months ended November 30, 2009, we received, as Operator, administrative overhead reimbursement of approximately $76,279 for the East Gilbertown Field in Alabama which was used to directly offset certain employee salaries. Since we are no longer involved in this project there was no corresponding offset to employee salaries for the nine months ended November 30, 2010. We are continuing to reduce our G&A expenses wherever possible. G&A costs represented 65.8% of total operating expenses.

Interest income for the nine months ended November 30, 2010 decreased $9,965 or 83.7% compared to the nine months ended November 30, 2009 due to lower average cash balances.

Interest expense increased $103,226 for the nine months ended November 30, 2010 compared to the nine months ended November 30, 2009 due to amortization of debt discount and interest on the 12% Subordinated Notes that were sold from January 2010 through March 2010 and amortization of loan origination fees and the fair value of the net profit interest associated with the $750,000 note payable from the acquisition of the additional working interest in Kern County, California.

Nine Months Ended November 30, 2010 compared to the Nine Months Ended November 30, 2009 - Discontinued Operations

Alabama (East Gilbertown Field)

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 nine months ended November 30, 2010 reflect certain credits that result in this information being additions to revenue rather than deductions from revenue. Because of the low prices for oil in prior periods, we had previously fully impaired our capitalized cost in this property.

The following table presents the revenues and expenses related to the East Gilbertown Field for the nine month periods ended November 30, 2010 and November 30, 2009.


	Nine Months Ended November 30, 2010		Nine Months Ended November 30, 2009

Oil sales revenue	$	—	$	62,418
Cost and expenses		731		67,557

Income (loss) from discontinued operations	$	731	$	(5,139	)

Liquidity and Capital Resources

Our primary financial resource is our oil reserves base. Our ability to fund a future capital expenditure program is dependent upon the level of prices we receive from oil sales; the success of our exploration and development program in Kern County, California; and the availability of capital resource financing. Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.

The Company’s financial statements for the nine months ended November 30, 2010 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. We have incurred net losses since inception and as of November 30, 2010 have an accumulated deficit of $22,397,971, which raises substantial doubt about our ability to continue as a going concern.

For the last two years, we have been working to reposition Daybreak to better meet our corporate goals and objectives by selling our interest in projects that were not contributing to the strategic growth of the Company. These projects included the Saxet Deep Field in Texas and the East Gilbertown Field in Alabama. Additionally, we have discontinued participation in the KSU #59 well in the Krotz Springs Field in St. Landry Parish, Louisiana. These actions have allowed us to improve cash flow and move forward with the current exploration and development program in Kern County, California.

We are continuing to pursue funding alternatives, including, but not limited to, debt or equity securities, to fund the development of the East Slopes Project. However no assurance can be given that we will be able to obtain any additional financing on favorable terms, if at all.

The changes in our capital resources at November 30, 2010 compared with February 28, 2010 are:


	November 30, 2010			February 28, 2010			Increase (Decrease)			Percentage Change

Cash	$	123,425		$	247,951		$	(124,526	)		(50.2	%)
Current Assets	$	806,427		$	1,070,541		$	(264,114	)		(24.7	%)
Total Assets	$	3,404,537		$	3,010,036		$	394,501			13.1	%
Current Liabilities	$	2,762,871		$	1,388,339		$	1,374,532			99.0	%
Total Liabilities	$	3,328,364		$	1,896,601		$	1,431,763			75.5	%
Working Capital	$	(1,956,444	)	$	(317,798	)	$	(1,638,646	)		(515.6	%)

Our working capital decreased $1,638,646 from ($317,798) as of February 28, 2010 to ($1,956,444) as of November 30, 2010. This decrease in working capital was principally due to the drilling activity that has occurred during the nine months ended November 30, 2010; the continuing reduction in the $1.5 million debt we assumed when we acquired the additional 25% working interest in California in March 2009; and meeting ongoing financial commitments reflected in our G&A costs. As of November 30, 2010, approximately $334,213 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, 2010, we reported an operating loss of approximately $1,115,688 as compared with an operating loss of approximately $1,813,291 from the comparative nine month period ended November 30, 2009. This decrease in the operating loss of approximately $697,603 or 38.5% from the comparative nine months ended November 30, 2009 was achieved by increasing revenue and lowering operating costs. Revenue increased due to both an increase in production and an improvement in the sales price of oil. We increased production by 4,413 barrels of oil or 92.1% through sales from eleven producing wells in comparison to sales from four producing wells in the nine months ended November 30, 2009. The average price of oil increased by $11.66 to $71.18 per barrel or 19.6% for the nine months ended November 30, 2010 in comparison to the nine months ended November 30, 2009.

Operating expenses decreased by 10.7% or $225,382 to $1,874,809 from $2,100,191 for the nine months ended November 30, 2010 and 2009, respectively. Production costs and DD&A expenses experienced the greatest reductions with a combined reduction of 36.4% or $280,657. This reduction was offset by an increase in G&A expenses for the nine months ended November 30, 2010.

Cash Flows

Our sources of funds in the past have included the debt or equity markets and, while we have positive cash flow from our oil and gas properties, 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 and 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, if available.

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

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


	Nine Months Ended November 30, 2010			Nine Months Ended November 30, 2009			Increase (Decrease)			Percentage Change

Net cash provided by (used in) operating activities	$	109,069		$	(2,315,663	)	$	2,424,732			104.7	%
Net cash provided by (used in) investing activities	$	(1,013,595	)	$	348,410		$	(1,362,005	)		(390.9	%)
Net cash provided by financing activities	$	780,000			—		$	780,000			100.0	%

Cash Flow Provided by (Used in) Operating Activities

Cash flow from operating activities is derived from the production of our oil and gas reserves and changes in the balances of receivables, payables or other non-oil property asset account balances. For the nine months ended November 30, 2010, we had a positive cash flow from operating activities of $109,069, in comparison to a negative cash flow of ($2,315,663) for the nine months ended November 30, 2009. This change of $2,424,732 was the result of an increase in oil revenues; a reduction in operating expenses; increased collections of outstanding receivable amounts; and refund of Operator bonds from states we are no longer operating in. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash Flow Provided by (Used in) Investing Activities

Cash flow from investing activities is derived from changes in oil and gas property and other assets account balances. Cash used in investing activities for the nine months ended November 30, 2010 was ($1,013,595), an increase of $1,362,005 from the $348,410 provided by investing activities for the nine months ended

November 30, 2009. This change was primarily from the increase in our oil and gas property balances resulting from the successful drilling of four wells and the increase in our working interest in five currently producing wells all in Kern County, California offset by our receipt of proceeds on the sale of the additional 25% working interest in California (acquired from certain defaulting working interest partners) during the nine months ended November 30, 2009.

Cash Flow Provided by Financing Activities

Cash flow from financing activities is derived from changes in equity account balances excluding retained earnings or changes in long-term liability account balances. Cash flow provided by financing activities increased by $780,000 for the nine months ended November 30, 2010, whereas no financing activity occurred in comparative nine months ended November 30, 2009. This change for the nine months ended November 30, 2010 is from funds received through the sale of the $30,000 portion of the 12% Subordinated Notes in a private placement during the nine months ended November 30, 2010 and the financing we received for the purchase of the additional working interest in Kern County, California.

Daybreak has ongoing capital commitments to develop all of its oil and gas leases pursuant to their underlying terms. Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself. These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company. A major source of capital for Daybreak in the past has been through the sale of debt or equity securities in the private or public markets. The debt or equity markets, if available to us, will continue to be capital sources for Daybreak until sustained positive cash flow has been achieved. The current uncertainty in the credit and capital markets, may restrict our ability to obtain needed capital.

12% Subordinated Notes

On March 16, 2010 we closed a private placement of 12% Subordinated Notes (the “Notes”) resulting in total gross proceeds of $595,000. A total of $250,000 Notes were sold to a related party, the Company’s President and Chief Executive Officer. The terms and conditions of the related party Note were identical to the terms and conditions of the other participants’ Notes. The Notes are subject to an annual interest rate of 12%, payable semi-annually, and mature on January 29, 2015. On the maturity date, the Company may elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days prior to December 31, 2014. Proceeds from the sale of the notes were used to meet operating expenses and fund a portion of our development drilling program in Kern County, California. This offering of securities was made pursuant to a private placement held under Regulation D promulgated under the Securities Act of 1933, as amended.

One-Year Note Payable

On September 17, 2010, we exercised a preferential right to acquire an additional 16.67% working interest in our East Slopes Project from another working interest owner. We financed the additional working interest purchase by issuing, to a third party, a one-year convertible secured promissory note for the principal amount of $750,000 (the “Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing. The third party may convert up to 50% of the unpaid principal balance into the Company’s common stock at a conversion price of $0.16 per share at any time prior to the Loan being paid in full.

We also issued 250,000 shares of the Company’s common stock to the third party as a loan origination fee. The fair value of these shares amounted to $23,750 which were deferred and amortized over the term of the Loan. Amortization expense for the nine months ended November 30, 2010 amounted to $5,938.

The Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in our East Slope Project. Furthermore, as a condition precedent to the Loan, we entered into a Technical and Consulting Services Agreement with the third party,

whereby we will provide operating, engineering and technical consulting to the third party for a one-year period for the purpose of evaluating 22 wells in Hutchinson County, Texas for the third party. After six months, Daybreak, at its sole discretion, will have the right to obtain a 10% working interest in the 22 wells in Hutchinson County, Texas at no additional cost.

As additional consideration for the Loan we executed an Assignment of Net Profits Interest in favor of the third party, whereby we assigned two percent of the net profits realized by us on our leases in the East Slopes Project. The fair value of the two percent net profits interest was determined to be $60,210 and has been recognized as a discount to the debt. The debt discount is amortized over the term of the Loan. Amortization expense for the nine months ended November 30, 2010 amounted to $15,053.

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 $123,425 and $247,951 as of November 30, 2010 and February 28, 2010, respectively. The decrease of approximately $124,526 was due to the costs of drilling of four additional wells in the nine months ended November 30, 2010; payment of outstanding invoices acquired from certain original partners default; and payment of ongoing LOE and G&A expenses incurred through normal operations of the Company.

Operating Loss

During the nine months ended November 30, 2010, we reported an operating loss of approximately $1,115,688 compared with an operating loss of approximately $1,813,291 from the comparative nine month period ended November 30, 2009. This decrease of approximately $697,603 or 38.5% in the operating loss was a result of increased revenue from oil sales and lower operating expenses than in the comparative nine month period ended November 30, 2009.

Net Loss

Since entering the oil and gas exploration industry, we have incurred recurring losses 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 $1,206,809 was reported for the nine months ended November 30, 2010, compared to a net loss of $1,807,377 for the nine months ended November 30, 2009. The decrease in net loss of $600,568 or 33.2% for the nine months ended November 30, 2010 was primarily due to an increase of $472,221 in revenue generated from oil sales; and a reduction of $225,382 in operating expenses in comparison to the nine months ended November 30, 2009.

Restricted Stock and Restricted Stock Unit Plan

On April 6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted stock and restricted stock unit awards. Subject to adjustment, the total number of shares of Daybreak’s common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.

We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.

Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.

At November 30, 2010, a total of 1,000,000 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		633,331		1,266,669
7/16/2009		25,000		3 Years		8,330		16,670
7/16/2009		625,000		4 Years		156,250		468,750
7/22/2010		25,000		3 Years		0		25,000
7/22/2010		425,000		4 Years		0		425,000

		3,000,000				797,911		2,202,089

For the three and nine months ended November 30, 2010, the Company recognized compensation expense related to the above restricted stock grants of $22,805 and $65,704, respectively. Unamortized compensation expense amounted to $156,100 as of November 30, 2010.

Summary

We are continuing to execute the Company’s business plan of developing Daybreak’s acreage position in Kern County, California. The production and operating infrastructure is now in place and operating. We will continue to 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 with the expectation for higher oil prices, will increase our net cash flow.

We anticipate the need to obtain 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 could 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.

Critical Accounting Policies

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2010.

Off-Balance Sheet Arrangements

As of November 30, 2010, 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, 2010, an evaluation was conducted by Daybreak management, including our President and 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 President and Chief Executive Officer, in a manner to allow timely decisions regarding required disclosures. Based on that evaluation, our management concluded that our disclosure controls were effective as of November 30, 2010.

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the three months ended November 30, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Limitations

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

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

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

PART II
OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

The following risk factor updates the Risk Factors included in our Form 10-K for the fiscal year ended February 28, 2010. Except as set forth below, there have been no material changes to the risks described in Part I, Item 1A, of the Form 10-K for the fiscal year ended February 28, 2010.

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

Our outstanding indebtedness at November 30, 2010 was $1,345,000, which constituted the $750,000 Loan and the $595,000 principal amount outstanding on the Notes. Our level of indebtedness affects our operations in a number of ways. The Notes and the secured convertible promissory note governing our Loan contain covenants resulting in a substantial portion of our cash flow from operations to be dedicated to the payment of interest on our indebtedness. Accordingly, these funds will not be available for other purposes, such as future exploration, development or acquisition activities. Our ability to meet our debt service obligations and reduce our total indebtedness will depend upon our future performance. Our future performance, in turn, is dependent upon many factors that are beyond our control such as general economic, financial and business conditions. We cannot guarantee that our future performance will not be adversely affected by such economic conditions and financial, business and other factors.

The $750,000 Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in the Company’s East Slopes Project. If the Company were to default on this Loan, the Company would lose two of its primary leases.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On October 26, 2010 and November 16, 2010, the Company issued 120,000 and 60,000 shares of common stock, respectively, to accredited investors pursuant to the terms of a Daybreak private placement offering held in July 2006, during which the accredited investors received shares of Daybreak Series A Convertible Preferred Stock, the terms of which are disclosed in the Company’s Amended and Restated Articles of Incorporation. The Series A Convertible Preferred Stock can be converted by the shareholder at any time into three shares of the Company’s common stock. Pursuant to the terms of the Series A Convertible Preferred Stock, the common stock was issued to the accredited investors upon the conversion of 40,000 and 20,000 shares of Series A Convertible Preferred Stock by the accredited investors, respectively, in reliance on an exemption from registration provided by Section 3(a)(9) of the Securities Act of 1933 relating to securities exchanged by the issuer with its existing security holders exclusively where no commission or other remuneration is paid or given directly or indirectly for soliciting such exchange.

As of November 30, 2010, there have been 29 accredited investors convert 483,200 Series A Convertible Preferred shares into 1,449,600 shares of Daybreak common stock. At November 30, 2010, there were 916,565 Series A Convertible Preferred shares outstanding, held by accredited investors that had not been converted into the Company’s common stock. The table below shows the conversions of Series A

Convertible Preferred that have occurred since the Series A Convertible Preferred was first issued in July 2006.


Fiscal Period	Shares of Series A Preferred Converted to Common Stock		Shares of Common Stock Issued from Conversion		Number of Accredited Investors

Year Ended February 29, 2008		102,300		306,900		10
Year Ended February 28, 2009		237,000		711,000		12
Year Ended February 28, 2010		51,900		155,700		4
Nine Months Ended November 30, 2010		92,000		276,000		3

Totals		483,200		1,449,600		29

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest in its East Slopes Project from another working interest owner. The Company financed the additional working interest by issuing, to an accredited third party, a one-year convertible secured promissory note. The Company agreed to pay the third party a loan origination fee equal to 250,000 shares of the Company’s common stock within 60 days after September 17, 2010. These shares were issued on October 8, 2010. The closing price of the Company’s common stock on September 17, 2010 was $0.095 and the stock issuance was valued at $23,750. The shares were issued in reliance on an exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

ITEM 6. EXHIBITS

The following Exhibits are filed as part of the report:


Exhibit Number		Description

10.1⁽¹⁾		Secured Convertible Promissory Note, dated September 17, 2010, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC.

10.2⁽¹⁾		Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement, dated September 17, 2010, by and between Daybreak Oil and Gas, Inc., as mortgagor, and Well Works, LLC, as trustee and beneficiary.

10.3⁽¹⁾		Technical and Consulting Services Agreement, dated September 17, 2010, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC.

10.4⁽¹⁾		Assignment of Net Profits Interest, dated September 17, 2010, by and between Daybreak Oil and Gas, Inc., as assignor, and Well Works, LLC, as assignee.

10.5⁽²⁾		Asset Purchase and Sale Agreement with Chevron U.S.A. Inc., effective July 1, 2010.

10.6⁽²⁾		Assignment of Oil and Gas Leases and Agreements among Chevron U.S.A. Inc., as assignor, and Daybreak Oil and Gas, Inc. and San Joaquin Investments, Inc., as assignees, effective July 1, 2010.

10.7⁽²⁾		Bill of Sale among Chevron U.S.A. Inc., as seller, and Daybreak Oil and Gas, Inc. and San Joaquin Investments, Inc., as buyers, effective July 1, 2010.

31.1⁽³⁾		Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1⁽³⁾		Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


	(1)	Previously filed as exhibits to Form 8-K on September 23, 2010, and incorporated by reference herein.

	(2)	Previously filed as exhibits to Form 10-Q on October 15, 2010, and incorporated by reference herein.

	(3)	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 13, 2011