- Quarterly Report (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 August 31, 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. x 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 x

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

At October 14, 2010 the registrant had 48,581,599 outstanding shares of $0.001 par value common stock.

TABLE OF CONTENTS


PART I - FINANCIAL INFORMATION

ITEM 1.	Financial Statements	3

	Balance Sheets at August 31, 2010 and February 28, 2009 (Unaudited)	3

	Statements of Operations for the Three and Six Months Ended August 31, 2010 and August 31, 2009 (Unaudited)	4

	Statements of Cash Flows for the Three and Six Months Ended August 31, 2010 and August 31, 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	29

Signatures		31

P ART I
FINANCIAL INFORMATION

I TEM 1. FINANCIAL STATEMENTS



DAYBREAK OIL AND GAS, INC.
B alance Sheets - Unaudited


	As of August 31, 2010			As of February 28, 2010

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,379		$	247,951
Accounts receivable:
Oil and gas sales		177,732			257,110
Joint interest participants, net of allowance for doubtful accounts of $49,202 and $16,237 respectively		445,236			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		19,250			21,735

Total current assets		684,597			1,070,541
OIL AND GAS PROPERTIES, net of accumulated depletion, depreciation, amortization, and impairment, net of $805,217 and $1,783,258 respectively, successful efforts method
Proved properties		1,326,883			1,189,566
Unproved properties		35,530			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		104,467			402,208

Total assets	$	2,476,477		$	3,010,036


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,473,321		$	1,240,909
Accounts payable - related parties		44,444			31,898
Liabilities associated with assets held for sale		—			110,124
Accrued interest		6,468			5,408

Total current liabilities		1,524,233			1,388,339
LONG TERM LIABILITIES:
Notes payable, net of discount of $107,787 and $110,056 respectively		487,213			454,944
Asset retirement obligation		44,621			53,318

Total liabilities		2,056,067			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; 976,565 and 1,008,565 shares issued and outstanding respectively		977			1,009
Common stock- 200,000,000 shares authorized; $0.001 par value, 48,331,599 and 47,785,599 shares issued and outstanding respectively		48,333			47,786
Additional paid-in capital		22,318,069			22,255,802
Accumulated deficit		(21,946,969	)		(21,191,162	)

Total stockholders’ equity		420,410			1,113,435

Total liabilities and stockholders’ equity	$	2,476,477		$	3,010,036

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

3



DAYBREAK OIL AND GAS, INC.
S tatements of Operations - Unaudited


	For the Three Months Ended August 31,						For the Six Months Ended August 31,

	2010			2009			2010			2009

REVENUE:
Oil and gas sales	$	307,006		$	130,147		$	500,057		$	167,420


OPERATING EXPENSES:
Production costs		12,988			134,958			48,931			198,445
Exploration and drilling		71,463			66,460			144,283			103,925
Depreciation, depletion, amortization, and impairment		121,770			44,709			237,057			352,585
Gain on write-off of asset retirement obligation		—			—			(8,324	)		—
Bad debt expense		—			2,306			—			76,689
General and administrative		444,141			410,819			799,893			844,150

Total operating expenses		650,362			659,252			1,221,840			1,575,794

OPERATING LOSS		(343,356	)		(529,105	)		(721,783	)		(1,408,374	)


OTHER INCOME (EXPENSE):
Interest income		493			7,911			1,680			9,869
Interest expense		(23,420	)		(76	)		(46,661	)		(764	)

Total other income (expense)		(22,927	)		7,835			(44,981	)		9,105


LOSS FROM CONTINUING OPERATIONS		(366,283	)		(521,270	)		(766,764	)		(1,399,269	)

DISCONTINUED OPERATIONS
Income from discontinued operations (net of tax of $-0-)		40			50,249			731			60,092
Gain (loss) from sale of oil and gas properties (net of tax of $-0-)		(3,868	)		—			10,226			—

INCOME (LOSS) FROM DISCONTINUED OPERATIONS		(3,828	)		50,249			10,957			60,092


NET LOSS		(370,111	)		(471,021	)		(755,807	)		(1,339,177	)

Cumulative convertible preferred stock dividend requirement		(43,967	)		(51,289	)		(89,726	)		(102,578	)


NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(414,078	)	$	(522,310	)	$	(845,533	)	$	(1,441,755	)


NET LOSS PER COMMON SHARE
Loss from continuing operations	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.03	)
Income (loss) from discontinued operations		—			—			—			—

NET LOSS PER COMMON SHARE - Basic and diluted	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.03	)


WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - Basic and diluted		48,070,962			47,311,964			47,927,501			46,763,866

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

4



DAYBREAK OIL AND GAS, INC.
S tatements of Cash Flows - Unaudited


	Six Months Ended August 31,

	2010			2009

CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(755,807	)	$	(1,339,177	)
Adjustments to reconcile net loss to net cash used in operating activities:
Stock compensation		42,898			36,604
Gain on write-off of asset retirement obligation		(8,324	)		—
Gain on sale of oil and gas properties		(10,226	)		—
Depreciation, depletion, and impairment expense		237,057			353,030
Amortization of debt discount		7,553			—
Bad debt expense (recovery)		(5,047	)		76,689
Non cash interest income		(1,680	)		(8,148	)
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		79,378			(174,296	)
Accounts receivable - joint interest participants		(224,541	)		(648,888	)
Receivables associated with assets held for sale		303,097			—
Prepaid expenses and other current assets		2,485			(1,667	)
Other assets		299,421			—
Accounts payable and other accrued liabilities		162,622			(623,338	)
Accounts payable - related parties		12,546			—
Accrued interest		1,060			—

Net cash provided by (used in) operating activities		157,092			(2,307,515	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(417,664	)		(358,266	)
Proceeds from sale of oil and gas properties		—			512,500

Net cash provided by (used in) investing activities		(417,664	)		154,234

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of notes payable		30,000			—

Net cash provided by financing activities		30,000			—


NET DECREASE IN CASH AND CASH EQUIVALENTS		(230,572	)		(2,153,281	)

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


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	17,379		$	129,529

CASH PAID FOR:
Interest	$	38,048		$	764
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	$	93,086		$	—
Addition to asset retirement obligation	$	7,584		$	14,629
Discount on notes payable	$	5,284		$	—
Conversion of preferred stock to common stock	$	96		$	—

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

5

DAYBREAK OIL AND GAS, INC.
N OTES 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 six months ended August 31, 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 six months ended August 31, 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 August 31, 2010 has an accumulated deficit of $21,946,969, 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 revenue interest in nine 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 is anticipated to add an additional $20,000 per month to the Company’s revenue based on historical production rates and prices from existing wells. With this purchase, Daybreak’s average net revenue interest in Kern County, California has increased from 21.83% to 29.33%. 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 capital markets in the future.

The Company’s financial statements as of August 31, 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 adopted the provisions of ASU 2010-09 for the period ended August 31, 2010.

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 only one or two buyers available for the purchase of oil production. At August 31, 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 August 31, 2010				Three Months Ended August 31, 2009

Customer	Revenue		Percentage		Revenue		Percentage

Plains Marketing	$	202,989	66.1	%	$	129,665	84.5	%

J.P. Oil**	$	104,017	33.9	%	$	-0-	0	%


	For the Six Months Ended August 31, 2010				For the Six Months Ended August 31, 2009

Customer	Revenue		Percentage		Revenue		Percentage

Plains Marketing	$	396,040	79.2	%	$	166,318	79.0	%

J.P. Oil**	$	104,017	20.8	%	$	-0-	0	%

**During the three months ended August 31, 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.

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 six months ended August 31, 2010 of $10,226 which is presented under “Discontinued Operations” in the Statement of Operations and discussed in Note 7 below.

NOTE 6 — NOTES PAYABLE

On March 16, 2010, the Company closed its private placement of 12% Subordinated Notes (“Notes”) resulting in additional gross proceeds of $30,000 for the six months ended August 31, 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 August 31, 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 six months ended August 31, 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 six months ended August 31, 2010 of $10,226, 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 six month periods ended August 31, 2010 and August 31, 2009 which are presented on the Statement of Operations under the caption “Discontinued Operations”. The cost and expense information for both the three months and six months ended August 31, 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 August 31, 2010		Three Months Ended August 31, 2009

Oil sales revenue – East Gilbertown Field	$	—	$	23,239
Cost and expenses		40		27,010

Income from discontinued operations	$	40	$	50,249


	Six Months Ended August 31, 2010		Six Months Ended August 31, 2009

Oil sales revenue – East Gilbertown Field	$	—	$	43,205
Cost and expenses		731		16,887

Income from discontinued operations	$	731	$	60,092

NOTE 8 — 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. On June 9, 2010, 32,000 shares of Series A Preferred stock were converted to 96,000 shares of common stock. Previously in February 2010, shareholders converted 45,000 shares of Series A Preferred stock into 135,000 shares of common stock. As of August 31, 2010, 27 shareholders have converted a total of 423,200 Series A Preferred shares into 1,269,600 shares of common stock. At August 31, 2010, there were 976,565 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 August 31, 2010, the accumulated and unpaid dividends amounted to $879,146. 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 August 31, 2010.

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


Fiscal Period	Shareholders at Period End		Accumulated Dividends

Year Ended February 28, 2007		100	$	153,966
Year Ended February 29, 2008		90		237,752
Year Ended February 28, 2009		78		208,878
Year Ended February 28, 2010		74		188,824
Six Months Ended August 31, 2010		73		89,726

Total Accumulated Dividends			$	879,146

NOTE 9 — WARRANTS

Warrants outstanding and exercisable as of August 31, 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		0.75		4,013,602
Placement Agent Warrants Spring 2006 PP		802,721	$	0.75		2.75		802,721
Placement Agent Warrants Spring 2006 PP		401,361	$	2.00		2.75		401,361
July 2006 Preferred Stock Private Placement		2,799,530	$	2.00		1.00		2,799,530
Placement Agent Warrants July 2006 PP		419,930	$	1.00		3.00		419,930
Convertible Debenture Term Extension		150,001	$	2.00		1.25		150,001
Placement Agent Warrants January 2008 PP		39,550	$	0.25		0.50		39,550
12% Subordinated Note Warrants		1,190,000	$	0.14		4.25		1,190,000
Warrants Issued in 2010 for Services		150,000	$	0.14		4.75		150,000

		9,966,695						9,966,695

During the six months ended August 31, 2010, a total of 60,000 warrants were issued, while before fiscal year end of February 28, 2010, 1,130,000 warrants were issued, leading to the issuance of a total of 1,190,000 warrants as part of the 12% Subordinated Notes private placement as discussed in Note 6 above.

Additionally during the six months ended August 31, 2010, 150,000 warrants were issued to a consultant as payment for additional 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 August 31, 2010 and February 28, 2010, there were 9,966,695 and 9,756,695 warrants issued and outstanding, respectively.

The outstanding warrants as of August 31, 2010, have a weighted average exercise price of $1.60; a weighted average remaining life of 1.64 years; and an intrinsic value of $-0-.

NOTE 10 — RESTRICTED STOCK and RESTRICTED STOCK UNIT PLAN

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

On July 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 policy 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 August 31, 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 six months ended August 31, 2010 and 2009, the Company recognized compensation expense related to the above restricted stock grants of $42,898, and $36,604, respectively. Unamortized compensation expense amounted to $178,456 as of August 31, 2010.

NOTE 11 — INCOME TAXES

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


	Six Months Ended August 31, 2010			Six Months Ended August 31, 2009

Computed at U.S. and state statutory rates (40%)	$	(302,323	)	$	(558,562	)
Permanent differences		20,323			9,636
Changes in valuation allowance		282,000			548,926

Total	$	—		$	—

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


	August 31, 2010			February 28, 2010

Deferred tax assets:
Net operating loss carryforwards	$	5,619,829		$	5,114,269
Oil and gas properties		(100,498	)		123,062
Less valuation allowance		(5,519,331	)		(5,237,331	)

Total	$	—		$	—

At August 31, 2010, the Company had estimated net operating loss carryforwards for federal and state income tax purposes of approximately $14,049,572 which will begin to expire, if unused, beginning in 2024. The valuation allowance increased approximately $282,000 for the six months ended August 31, 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 12 — 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 August 31, 2010. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

NOTE 13 — SUBSEQUENT EVENTS

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 for $517,000. The Company financed the additional working interest 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 unregistered Company common stock at a conversion price of $0.16 per share at any time prior to the Loan being paid in full.

The Company agreed to pay the third party a loan origination fee equal to 250,000 unregistered 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 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 Slope 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.

I TEM 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 six month periods ended August 31, 2010 and August 31, 2009 and of our financial condition as of August 31, 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 nine 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 increase in our working interest is anticipated to add an additional $20,000 per month to our revenue based on historical production rates and prices from existing wells. With this purchase our average net revenue interest in Kern County, California has increased from 21.83% to 29.33%.

East Slopes Project. The installation of permanent production facilities and electrical service to service the wells in the Sunday, Bear and Black property locations has been completed. 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 three reservoirs at our Bear, Sunday, and Black 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. There are several other similar prospects on trend with the Bear and Black 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 end of our fiscal year on February 28, 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 and 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 location.

Sunday Central Processing and Storage Facility

The oil produced from our acreage is considered heavy oil. The oil ranges from 13° to 15° API gravity. All of our oil from the Sunday, Bear and Black locations is processed, stored and sold from this facility. The oil must be heated to separate and remove the water to prepare it to be sold. We constructed these facilities during the Summer and Fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines. As a result, our average operating costs have been reduced from over $40 per barrel to under $10 per barrel of oil. By having this central facility and permanent electrical power, it ensures that our operating expenses are kept to a minimum.

Dyer Creek Prospect

This is a Vedder sand prospect located to the north of the Bear reservoir on the same trapping fault. Several wells have been drilled in this prospect with oil pay or shows in the Vedder sand. Several of the wells drilled in the 1960’s were abandoned due to sand control during testing. We plan to drill this prospect in our fiscal 2011 third quarter. We plan to twin a well that had 20 feet of oil pay in the Vedder sand that was never properly tested. There are abandoned production facilities on the lease that we expect may be utilized, but some repairs will need to be made and electrical lines will have to be extended from the Bear Property.

Ball Prospect

This is a Vedder sand prospect separated by a fault from the Dyer Creek Prospect. Our location will be structurally higher than an abandoned well that had oil pay in the Vedder sand. 3-D seismic indicates approximately 40 acres of closure, similar in size to the Bear Property. We plan to drill an exploratory well

on this prospect during our fiscal 2011 third quarter. If successful, production from the Ball wells should be able to utilize the Dyer Creek production facility.

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 before our fiscal year ending February 28, 2011. If successful, the Bull Run wells will require additional production facilities to handle the oil production.

The table below shows our net production volume, net revenue and net lease operating expenses (LOE) by property location for the three months and six months ended August 31, 2010 and August 31, 2009. Due to certain oil processing credits that we received during the three and six months ended August 31, 2010, our overall production costs for the Sunday #1 well and all the Bear wells during that time period were significantly less than the overall production costs for the other Sunday wells and the Black 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				Six Months Ended
Location	August 31, 2010		August 31, 2009		August 31, 2010		August 31, 2009


Sunday
Production (Bbls)		1,962		1,658		3,516		2,424
Revenue	$	133,840	$	98,932	$	243,705	$	134,246
LOE Costs	$	11,938	$	51,920	$	29,726	$	80,195

Bear
Production (Bbls)		763		505		1,647		530
Revenue	$	52,030		30,733	$	115,025	$	32,072
LOE Costs	$	209	$	37,255	$	9	$	69,324

Black
Production (Bbls)		251		—		533		—
Revenue	$	17,119	$	—	$	37,310	$	—
LOE Costs	$	4,025	$	—	$	7,272	$	—

Infrastructure Costs	$	3,343	$	4,867	$	12,901	$	9,734

Total
Production (Bbls)		2,976		2,162		5,696		2,954
Revenue	$	202,989	$	129,665	$	396,040	$	166,318
LOE Costs	$	19,514	$	89,175	$	49,908	$	149,519

Average Sales Price	$	68.20	$	59.97	$	69.53	$	56.30

Average LOE Cost	$	6.56	$	41.24	$	8.76	$	50.61

The table below shows our net sales volume, net revenue and net LOE for all California properties for the last five quarterly periods ended August 31, 2010.


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


Production (Bbls)		2,162		1,836		2,690		2,720		2,976
Revenue	$	129,665	$	118,816	$	184,224	$	193,051	$	202,989
LOE Costs	$	89,175	$	72,182	$	18,907	$	35,943	$	19,514

Average Sales Price	$	59.97	$	64.71	$	68.48	$	70.97	$	68.20

Average LOE Cost	$	41.25	$	39.31	$	7.03	$	13.21	$	6.56

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.

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.

Liquidity and Capital Resources

Our primary financial resource is our base of oil reserves. Our ability to fund the planned 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 six months ended August 31, 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 August 31, 2010 have an accumulated deficit of $21,946,969, 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.

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

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


	August 31, 2010			February 28, 2010

Current Assets	$	684,597		$	1,070,541
Current Liabilities		1,524,233			1,388,339

Working Capital	$	(839,636	)	$	(317,798	)


Current Ratio		0.45			0.77

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

The changes in our capital resources at August 31, 2010 compared with February 28, 2010 are:


	August 31, 2010			February 28, 2010			Increase (Decrease)			Percentage Change

Cash	$	17,379		$	247,951		$	(230,572	)	(93.0	%)
Current Assets	$	684,597		$	1,070,541		$	(385,944	)	(36.1	%)
Total Assets	$	2,476,477		$	3,010,036		$	(533,559	)	(17.7	%)
Current Liabilities	$	1,524,233		$	1,388,339		$	135,894		9.8	%
Total Liabilities	$	2,056,067		$	1,896,601		$	159,466		8.4	%
Working Capital	$	(839,636	)	$	(317,798	)	$	(521,838	)	(164.2	%)

Our working capital decreased $521,838 from ($317,798) as of February 28, 2010 to ($839,636) as of August 31, 2010. This decrease in working capital was principally due to the drilling activity that has occurred during the six months ended August 31, 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 general and administrative (“G&A”) costs. As of August 31, 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 six months ended August 31, 2010, we reported an operating loss of approximately $721,783 as compared with an operating loss of approximately $1,408,374 from the comparative six month period ended August 31, 2009. This decrease in the operating loss of approximately $686,591 or 48.8% from the comparative period 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 2,742 barrels of oil or 192.8% through sales from nine producing wells in comparison to sales from four producing wells in the six months ended August 31, 2009. The average price of oil increased by $13.23 to $69.53 per barrel or 23.5% for the six months ended August 31, 2010 in comparison to the six months ended August 31, 2009.

Operating expenses declined by 22.5% or $353,954 to $1,221,840 from $1,575,794 for the six months ended August 31, 2010 and 2009, respectively. Production costs and G&A expenses experienced the greatest reductions with a combined reduction of 24.2% or $270,460. This reduction was offset by an increase in exploration and drilling expenses.

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 or development properties and also acquiring existing producing properties. Our ability to generate future revenues and operating cash flow will depend on successful exploration and/or acquisition of oil and gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources, 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:


	Six Months Ended August 31, 2010			Six Months Ended August 31, 2009			Increase (Decrease)			Percentage Change

Net cash provided by (used in) operating activities	$	157,092		$	(2,307,515	)	$	2,464,607		106.8	%
Net cash provided by (used in) investing activities	$	(417,664	)	$	154,234		$	(571,898	)	(370.8	%)
Net cash provided by financing activities	$	30,000			—		$	30,000		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 six months ended August 31, 2010, we had a positive cash flow from operating activities of $157,092, in comparison to a negative cash flow of ($2,307,515) for the six months ended August 31, 2009. This change 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 account balances. Cash used in investing activities for the six months ended August 31, 2010 was $417,664, an increase of $571,898 from the $154,234 provided by investing activities for the six months ended August 31, 2009. This change was primarily from the increase in our oil and gas property balances resulting from the successful drilling of the Bear #3 and Bear #4 wells 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 six months ended August 31, 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 $30,000 for the six months ended August 31, 2010, whereas no financing activity occurred in comparative six months ended August 31, 2009. This change for the six months ended August 31, 2010 is from funds received through the sale of a portion of the 12% Subordinated Notes in a private placement during the six months ended August 31, 2010.

Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms. Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself. These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company. A major source of capital for Daybreak in the past has been through the debt or equity 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.

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 $17,379 and $247,951 as of August 31, 2010 and February 28, 2010, respectively. The decrease of approximately $230,572 was due to the costs of drilling of the Bear #3 and Bear #4 wells; payment of outstanding invoices acquired from certain original partners default; and payment of ongoing G&A expenses incurred through normal operations of the Company.

Operating Income (Loss)

During the six months ended August 31, 2010, we reported an operating loss of approximately $721,783 compared with an operating loss of approximately $1,408,374 from the comparative six month period ended August 31, 2009. This decrease of approximately $686,591 or 48.8% decline was a result of increased revenue from oil sales and lower operating expenses than in the comparative six month period ended August 31, 2009.

Net Income (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 $755,807 was reported for the six months ended August 31, 2010, compared to a net loss of $1,339,177 for the six months ended August 31, 2009. The decrease in net loss of $583,370 or 43.6% for the six months ended August 31, 2010 primarily was due to an increase of $332,637 in revenue generated from oil sales; and a reduction of $353,954 in operating expenses in comparison to the six months ended August 31, 2009.

Three Months Ended August 31, 2010 compared to the Three Months Ended August 31, 2009 - Continuing Operations

The following discussion compares our results for the three month periods ended August 31, 2010 and August 31, 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. We realized the first revenues from producing wells in California during February 2009. For the three months ended August 31, 2010, oil and gas revenues from continuing operations were $307,006 in comparison to $130,147 for the three months ended August 31, 2009. This represents an increase of $176,859 or 135.9%.

The revenues for the three months ended August 31, 2010 were from nine producing wells in California and 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 California, our net share of production was 2,976 and 2,162 barrels with an average price of $68.20 per barrel and $59.97 for the three months ended August 31, 2010 and August 31, 2009, respectively. A table of our revenues follows:


	Three Months Ended August 31, 2010		Three Months Ended August 31, 2009

California - East Slopes Project	$	202,989	$	129,665
Louisiana - Krotz Springs		104,017		482

Total Revenues	$	307,006	$	130,147

Costs and Expenses. Operating expenses for the three months ended August 31, 2010 decreased by $8,890 or 1.3% compared to the three months ended August 31, 2009. A significant decrease of $121,970 or 90.4% occurred in production costs, but this was offset by an increase of $77,061 or 172.4% in depreciation, depletion and amortization (“DD&A”), which is directly related to the nine producing wells and production facilities in Kern County, California.

A table of our costs and expenses for the three months ended August 31, 2010 and August 31, 2009 follows:


	August 31, 2010		August 31, 2009

Production Costs	$	12,988	$	134,958
Exploration and Drilling		71,463		66,460
DD&A		121,770		44,709
G&A		444,141		413,125

Total Operating Expenses	$	650,362	$	659,252

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 August 31, 2010, these costs decreased by $121,970 or 90.4% compared to the three months ended August 31, 2009. The decrease in production costs is directly related to the completion of our permanent production facilities rather than using rental equipment for production facilities. This decrease occurred even though there were nine wells producing in the three months ended August 31, 2010 in comparison to having four producing wells in the three months ended August 31, 2009. Another factor in reducing our production costs are the recurring credits that we receive on oil processing for certain wells due to one of our working interest partners not participating in the construction of the production facilities. These credits ended effective September 1, 2010 because of our acquisition of a portion of another working interest owner’s interest in this project. Production costs represented 2.0% 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 August 31, 2010 these costs increased $5,003 or 7.5%, in comparison to the three months ended August 31, 2009. Exploration costs increased because of a working interest partner choosing to not participate in certain leases. Exploration and drilling costs represented 11.0% 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 increased $77,061 or 172.4% for the three months ended August 31, 2010 compared to the three months ended August 31, 2009. This increase relates directly to the increased production from our nine producing wells. DD&A represented 18.7% of total operating expenses.

G&A expenses include management and employee salaries, legal and accounting expenses, director fees, bad debt expense, investor relations fees, travel expenses, insurance, SOX (Sarbanes-Oxley) compliance expenses and other administrative costs. For the three months ended August 31, 2010, G&A costs increased $31,016 or 7.5%, compared to the three months ended August 31, 2009. G&A expenses were higher in legal, marketing and fundraising costs for the three months ended August 31, 2010. We are continuing a program of reducing all of our G&A costs wherever possible. G&A costs represented 68.3% of total operating expenses from continuing operations.

Interest income for the three months ended August 31, 2010 decreased $7,418 or 93.8% compared to the three months ended August 31, 2009, due to lower average cash balances.

Interest expense for the three months ended August 31, 2010 increased $23,344 compared to the three months ended August 31, 2009, due to amortization of the debt discount and interest on the 12% Subordinated Notes that were sold from January 2010 through March 2010.

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 quarter-to-quarter and year-to-year. Production costs will fluctuate according to the number and percentage ownership of producing wells, as well as the amount of revenues being contributed by such wells. Exploration and drilling expenses will be dependent upon the amount of capital that we have to invest in future development projects, as well as the success or failure of such projects. Likewise, the amount of DD&A expense and impairment costs will depend upon the factors cited above. G&A costs will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.

Three Months Ended August 31, 2010 compared to the Three Months Ended August 31, 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 August 31, 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 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 August 31, 2010 and August 31, 2009.


	Three Months Ended August 31, 2010		Three Months Ended August 31, 2009

Oil sales revenue	$	—	$	23,239
Cost and expenses		40		27,010

Income from discontinued operations	$	40	$	50,249

Six Months Ended August 31, 2010 compared to the Six Months Ended August 31, 2009 - Continuing Operations

The following discussion compares our results for the six month periods ended August 31, 2010 and August 31, 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 six months ended August 31, 2010, oil and gas revenues from continuing operations were $500,057 in comparison to $167,420 for the six months ended August 31, 2009. This represents an increase of $332,637 or 198.7%.

The revenues for the six months ended August 31, 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 California, our net share of production was 5,696 and 2,954 barrels with an average price per barrel of $69.53 and $56.30 for the six months ended August 31, 2010 and August 31, 2009, respectively. A table of our revenues follows:


	Six Months Ended August 31, 2010		Six Months Ended August 31, 2009

California - East Slopes Project	$	396,040	$	166,318
Louisiana - Krotz Springs		104,017		1,102

Total Revenues	$	500,057	$	167,420

Costs and Expenses. Total operating expenses for the six months ended August 31, 2010 decreased by $353,954 or 22.5% compared to the six months ended August 31, 2009. Significant decreases occurred in production costs, DD&A and G&A in comparison to the six months ended August 31, 2009. We experienced an increase in exploration and drilling due to higher G&G costs for the six months ended August 31, 2010 in comparison to the six months ended August 31, 2009.

A table of our costs and expenses for the six months ended August 31, 2010 and August 31, 2009 follows:


	August 31, 2010			August 31, 2009

Production Costs	$	48,931		$	198,445
Exploration and Drilling		144,283			103,925
DD&A		237,057			352,585
Gain on Write-Off of Asset Retirement Obligation (“ARO”)		(8,324	)		—
Bad debt expense		—			76,689
G&A		799,893			844,150

Total Operating Expenses	$	1,221,840		$	1,575,794

Production costs for the six months ended August 31, 2010 decreased by $149,514 or 75.3% compared to the six months ended August 31, 2009 primarily because of the completion of our production facilities. Production costs represented 4.0% of total operating expenses.

Exploration and drilling costs increased by $40,358 or 38.8% for the six months ended August 31, 2010 compared to the six months ended August 31, 2009 primarily because of higher leasing costs. Exploration and drilling costs represented 11.8% of total operating expenses.

DD&A and impairment expenses for the six months ended August 31, 2010 decreased $115,528 or 32.8% compared to the six months ended August 31, 2009. This decrease was due to extra impairment charges being recognized in California for the six months ended August 31, 2009. DD&A costs represented 19.4% of total operating expenses.

G&A costs and bad debt expense decreased $120,946, or 13.1%, for the six months ended August 31, 2010 compared to the six months ended August 31, 2009. Significant reductions were made in the areas of accounting, legal, bad debt expense and travel to achieve these savings. We are continuing to reduce our G&A expenses wherever possible. G&A costs represented 65.5% of total operating expenses.

Interest income for the six months ended August 31, 2010 decreased $8,189 or 83.0% compared to the six months ended August 31, 2009 due to lower average cash balances.

Interest expense increased $45,897 for the six months ended August 31, 2010 compared to the six months ended August 31, 2009 due to amortization of debt discount and interest on the 12% Subordinated Notes.

Six Months Ended August 31, 2010 compared to the Six Months Ended August 31, 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 three months ended August 31, 2010 and 2009 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 six month periods ended August 31, 2010 and August 31, 2009.


	Six Months Ended August 31, 2010		Six Months Ended August 31, 2009

Oil sales revenue	$	—	$	43,205
Cost and expenses		731		16,887

Income from discontinued operations	$	731	$	60,092

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 August 31, 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 six months ended August 31, 2010, the Company recognized compensation expense related to the above restricted stock grants of $22,126 and $42,898, respectively. Unamortized compensation expense amounted to $178,456 as of August 31, 2010.

Summary

We are continuing to execute the Company’s primary 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 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 August 31, 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.

I TEM 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.

I TEM 4T. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

As of the end of the reporting period, August 31, 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 August 31, 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 quarter ended August 31, 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.

P ART II
OTHER INFORMATION

I TEM 1. LEGAL PROCEEDINGS

None.

I TEM 1A. RISK FACTORS

As of the date of this filing, there have been no material changes from the risk factors previously disclosed in our “Risk Factors” in the Annual Report on Form 10-K for the year ended February 28, 2010.

I TEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In February 2010 and on June 9, 2010, the Company issued 135,000 and 96,000 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 Preferred Stock, the common stock was issued to the accredited investors upon the conversion of 45,000 and 32,000 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.

On April 16, 2010, a consultant of the Company received 150,000 warrants as payment for additional services rendered to the Company, in reliance on an exemption from registration provided by Section 4(2) of the Securities Act of 1933. The 150,000 warrants give the consultant the right to purchase up to 150,000 shares of common stock for $0.14 per share at anytime on or before April 16, 2015.

I TEM 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 ⁽²⁾	Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 ⁽²⁾	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)	Filed herewith.

S IGNATURES

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: October 15, 2010