DAYBREAK OIL & GAS, INC. - Quarter Report: 2011 May (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 May 31, 2011


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 July 14, 2011 the registrant had 48,791,599 outstanding shares of $0.001 par value common stock.

TABLE OF CONTENTS


	PART I - FINANCIAL INFORMATION


ITEM 1.	Financial Statements	3

	Balance Sheets at May 31, 2011 and February 28, 2011 (Unaudited)	3

	Statements of Operations for the Three Months Ended May 31, 2011 and May 31, 2010 (Unaudited)	4

	Statements of Cash Flows for the Three Months Ended May 31, 2011 and May 31, 2010 (Unaudited)	5

	Notes to Unaudited Financial Statements	6

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	25

ITEM 4.	Controls and Procedures	25

	PART II - OTHER INFORMATION

ITEM 1.	Legal Proceedings	26

ITEM 1A.	Risk Factors	26

ITEM 6.	Exhibits	27

Signatures		28

PART I
FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



DAYBREAK OIL AND GAS, INC.
Balance Sheets - Unaudited


	As of May 31, 2011			As of February 28, 2011

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	30,946		$	57,380
Accounts receivable:
Oil and gas sales		266,341			185,836
Joint interest participants, net of allowance for doubtful accounts of $33,346		116,987			163,551
Production revenue receivable		25,000			25,000
Refunds		—			91,632
Prepaid expenses and other current assets		47,462			69,876

Total current assets		486,736			593,275
OIL AND GAS PROPERTIES, net of accumulated depletion, depreciation, amortization and impairment of $950,010 and $871,666, respectively, successful efforts method
Proved properties		1,778,419			1,837,431
Unproved properties		448,598			452,570
VEHICLES AND EQUIPMENT, net of accumulated depreciation of $31,329		—			—
PRODUCTION REVENUE RECEIVABLE - LONG TERM		325,000			325,000
OTHER ASSETS		105,063			104,904

Total assets	$	3,143,816		$	3,313,180


LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,651,059		$	1,790,382
Accounts payable - related parties		219,960			156,370
Accrued interest		23,474			5,477
Notes payable, net of discount of $15,053 and $30,105, respectively		734,947			719,895

Total current liabilities		2,629,440			2,672,124
LONG TERM LIABILITIES:
Notes payable, net of discount of $94,758 and $99,106, respectively		500,242			495,894
Asset retirement obligation		55,735			55,122

Total liabilities		3,185,417			3,223,140
COMMITMENTS
STOCKHOLDERS’ EQUITY (DEFICIT):
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, 906,565 shares issued and outstanding		907			907
Common stock- 200,000,000 shares authorized, $0.001 par value, 48,791,599 shares issued and outstanding		48,792			48,792
Additional paid-in capital		22,470,055			22,447,250
Accumulated deficit		(22,561,355	)		(22,406,909	)

Total stockholders’ equity (deficit)		(41,601	)		90,040

Total liabilities and stockholders’ equity (deficit)	$	3,143,816		$	3,313,180

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 May 31,

	2011			2010

REVENUE:
Oil and gas sales	$	380,357		$	193,051


OPERATING EXPENSES:
Production costs		40,772			35,943
Exploration and drilling		25,802			72,820
Depreciation, depletion, amortization, and impairment		79,571			115,287
Gain on write-off of asset retirement obligation		—			(8,324	)
General and administrative		330,132			355,752

Total operating expenses		476,277			571,478

OPERATING LOSS		(95,920	)		(378,427	)


OTHER INCOME (EXPENSE):
Interest income		169			1,187
Interest expense		(58,695	)		(23,241	)

Total other income (expense)		(58,526	)		(22,054	)


LOSS FROM CONTINUING OPERATIONS		(154,446	)		(400,481	)

DISCONTINUED OPERATIONS
Income from discontinued operations (net of tax of $-0-)		—			691
Gain from sale of oil and gas properties (net of tax of $-0-)		—			14,094

INCOME FROM DISCONTINUED OPERATIONS		—			14,785


NET LOSS		(154,446	)		(385,696	)

Cumulative convertible preferred stock dividend requirement		(41,139	)		(45,758	)


NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(195,585	)	$	(431,454	)


NET LOSS PER COMMON SHARE
Loss from continuing operations	$	(0.00	)	$	(0.01	)
Income from discontinued operations		—			—

NET LOSS PER COMMON SHARE - Basic and diluted	$	(0.00	)	$	(0.01	)


WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING -
Basic and diluted		48,791,599			47,785,599

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



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


	Three Months Ended May 31,

	2011			2010

CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(154,446	)	$	(385,696	)
Adjustments to reconcile net loss to net cash used in operating activities:
Stock compensation		22,805			20,772
Gain on write-off of asset retirement obligation		—			(8,324	)
Gain on sale of oil and gas properties		—			(14,094	)
Depreciation, depletion, and impairment expense		79,571			115,287
Amortization of debt discount		19,400			3,771
Amortization of loan origination fees		5,938			—
Bad debt expense (recovery)		—			(174	)
Non-cash interest income		(159	)		(1,187	)
Warrant expense for services		—			14,600
Changes in assets and liabilities:
Accounts receivable - oil and gas sales		(80,505	)		51,689
Accounts receivable - joint interest participants		46,564			128,885
Accounts receivable - refunds		91,632			—
Prepaid expenses and other current assets		16,476			62
Other assets		—			270,975
Accounts payable and other accrued liabilities		(70,628	)		113,859
Accounts payable - related parties		63,590			(4,172	)
Accrued interest		17,997			17,852

Net cash provided by operating activities		58,235			324,105


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(84,669	)		(116,782	)


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


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(26,434	)		237,323

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		57,380			247,951


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	30,946		$	485,274


CASH PAID FOR:
Interest	$	2,548		$	5,389
Income taxes	$	—		$	—

SUPPLEMENTAL CASH FLOW INFORMATION:
Unpaid additions to oil and gas properties	$	9,952		$	191,450
Addition to asset retirement obligation	$	605		$	7,584
Discount on notes payable - long term	$	—		$	5,284

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, 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 of the financial statements have been included and such adjustments are of a normal recurring nature. Operating results for the three months ended May 31, 2011 are not necessarily indicative of the results that may be expected for the fiscal year ending February 29, 2012.

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, 2011.

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.

NOTE 2 — GOING CONCERN

Financial Condition

The Company’s financial statements for the three months ended May 31, 2011 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 entering the oil and gas exploration industry and as of May 31, 2011 has an accumulated deficit of $22,561,355 and a working capital deficit of $2,142,704 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. Daybreak currently has a net revenue interest in 11 producing wells in its 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. Daybreak’s average net revenue interest in these wells is 29.85%. The Company’s average working interest is 40.15% for these same wells.

The Company anticipates revenues will continue to increase as it participates in the drilling of more wells in California. Daybreak 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 will 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 May 31, 2011 do not include any adjustments that might result from the Company’s 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 regarding 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.

No other new accounting pronouncements issued or effective has had, or is expected to have, a material impact on the Company’s financial statements.

NOTE 4 — CONCENTRATION OF CREDIT RISK

Substantially all of the Company’s accounts receivable result from crude oil sales or joint interest billings to its working interest partners. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors. Accounts receivable are generally not collateralized. Allowances for doubtful accounts at May 31, 2011 and February 28, 2011 relate to amounts due from joint interest owners.

At the Company’s East Slopes Project, there is only one buyer available for the purchase of oil production. At May 31, 2011, one customer represented 100% of crude oil sales receivable.

NOTE 5 — OIL AND GAS PROPERTIES

Oil and gas property balances at May 31, 2011 and February 28, 2011 are set forth in the table below.


	May 31, 2011			February 28, 2011

Proved leasehold costs	$	8,975		$	8,975
Unproved leasehold costs		448,598			452,570
Costs of wells and development		439,356			422,694
Capitalized exploratory well costs		2,232,793			2,229,511
Capitalized asset retirement costs		47,305			47,909

Total cost of oil and gas properties		3,177,027			3,161,659

Accumulated depletion, depreciation, amortization and impairment		(950,010	)		(871,658	)

Net Oil and Gas Properties	$	2,227,017		$	2,290,001

NOTE 6 — ACCOUNTS PAYABLE

On March 1, 2009, the Company became the operator for its East Slopes Project. Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project’s four earning wells program. The Company subsequently sold the same 25% working interest on June 11, 2009. Approximately $320,734 of the $1.5 million default remains unpaid and is included in the May 31, 2011 accounts payable balance.

NOTE 7 — 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 “September 2010 Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing. Interest expense related to the September 2010 Loan for the three months ended May 31, 2011 was $18,750. Unamortized interest expense amounted to $18,750 as of May 31, 2011.

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 September 2010 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 was deferred and amortized over the term of the September 2010 Loan. Amortization expense for the three months ended May 31, 2011 amounted to $5,938. Unamortized loan origination fee expense amounted to $5,938 as of May 31, 2011.

The September 2010 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 September 2010 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.

As additional consideration for the September 2010 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 to be amortized over the term of the September 2010 Loan. Amortization expense for the three months ended May 31, 2011 was $15,053. Unamortized debt discount amounted to $15,053 as of May 31, 2011.

The Company analyzed the September 2010 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”) to 13 accredited investors resulting in total gross proceeds of $595,000. The note principal is payable in full at the expiration of the term of the Notes, which is January 29, 2015. The Notes are subject to an annual interest rate of 12%, payable semi-annually. 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. A $250,000 Note was sold to a related party, the Company’s President and Chief Executive Officer. The terms and conditions of the related party Note were identical to the terms and conditions of the other accredited investors’ Notes.

Two Common Stock purchase warrants were issued for every dollar raised through the private placement resulting in 1,190,000 warrants being issued. The warrants 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 $116,557 using the following weighted-average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%. The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method. Amortization expense for the three months ended May 31, 2011 was $4,348. Unamortized debt discount amounted to $94,758 as of May 31, 2011.

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

NOTE 8 — STOCKHOLDERS’ EQUITY (DEFICIT)

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 May 31, 2011, there were no conversions of Series A Preferred to 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 May 31, 2011, the accumulated and unpaid dividends amounted to $1,012,811. 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 May 31, 2011.

Dividends earned on the Series A Preferred for each fiscal year since issuance and the three months ended May 31, 2011 are set forth in the table below:


Fiscal Period	Shareholders at Period End		Accumulated Dividends

Year Ended February 28, 2007		100	$	155,333
Year Ended February 29, 2008		90		242,165
Year Ended February 28, 2009		78		209,974
Year Ended February 28, 2010		74		190,460
Year Ended February 28, 2011		70		173,740
Three Months Ended May 31, 2011		70		41,139

Total Accumulated Dividends			$	1,012,811

Common Stock

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock, of which 48,791,599 shares were issued and outstanding as of May 31, 2011. For the three months ended May 31, 2011, no shares of the Company’s Common Stock were issued.

NOTE 9 — WARRANTS

Warrants outstanding and exercisable as of May 31, 2011 are set forth in the table below:


	Warrants		Exercise Price		Remaining Life (Years)		Exercisable Warrants Remaining

Placement Agent Warrants Spring 2006		802,721		$0.75		2.00		802,721
Placement Agent Warrants Spring 2006		401,361		$2.00		2.00		401,361
July 2006 Private Placement		2,799,530		$2.00		0.25		2,799,530
Placement Agent Warrants July 2006		419,930		$1.00		2.25		419,930
Convertible Debenture Term Extension		150,001		$2.00		0.50		150,001
12% Subordinated Notes		1,190,000		$0.14		3.50		1,190,000
Warrants Issued for Services		150,000		$0.14		4.00		150,000

		5,913,543						5,913,543

There were no warrants issued or exercised during the three months ended May 31, 2011. For the three months ended May 31, 2011, a total of 4,013,602 warrants expired. These warrants were issued to accredited investors in a private placement of the Company’s Common Stock that occurred in the Spring of 2006.

The outstanding warrants as of May 31, 2011, have a weighted average exercise price of $1.34, a weighted average remaining life of 1.50 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 (“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.

At May 31, 2011, a total of 1,000,000 Common Stock shares remained available for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is set forth in the table below:


Grant Date	Shares Awarded		Vesting Period		Shares Vested		Shares Outstanding (Unvested)

4/7/2009		1,900,000		3 Years		1,266,665		633,335
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		—		25,000
7/22/2010		425,000		4 Years		—		425,000

		3,000,000				1,431,245		1,568,755

For the three months ended May 31, 2011, the Company recognized compensation expense related to the above restricted stock grants in the amount of $22,805. Unamortized compensation expense amounted to $110,493 as of May 31, 2011.

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 set forth in the table below:


	May 31, 2011

Computed at U.S. and state statutory rates (40%)	$	(61,779	)
Permanent differences		15,899
Changes in valuation allowance		45,880

Total	$	—

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


	May 31, 2011			February 28, 2011

Deferred tax assets:
Net operating loss carryforwards	$	5,922,880		$	5,900,491
Oil and gas properties		(212,625	)		(226,994	)
Stock based compensation		44,525			35,403

Less valuation allowance		(5,754,780	)		(5,708,900	)

Total	$	—		$	—

At May 31, 2011, Daybreak had estimated net operating loss carryforwards for federal and state income tax purposes of approximately $14,807,200 which will begin to expire, if unused, beginning in 2024. The valuation allowance increased approximately $45,880 and $471,569 for the three months ended May 31, 2011 and the year ended February 28, 2011, respectively. 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 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. Currently, 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 May 31, 2011. There can be no assurance, however, that current regulatory requirements will not change or that 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 fact 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, without limitation, statements about the following:


	•	Our future financing;

	•	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;

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

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

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

	•	Legislative and regulatory uncertainties, including proposed changes to federal tax law and climate change legislation, and potential environmental liabilities;

	•	Our ability to continue as a going concern;

	•	Our ability to secure financing under any commitment as well as additional capital to fund operations; and

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

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should any 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 any 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 month periods ended May 31, 2011 and May 31, 2010 and of our financial condition as of May 31, 2011, and is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes included elsewhere in this Form 10-Q and in our audited Annual Report on Form 10-K for the year ended February 28, 2011. Unless otherwise noted, all of our discussion refers to our 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, and to 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 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 natural gas in commercial quantities. We are in the process of developing a multi-well oilfield project in Kern County, California. We have participated in the drilling of 11 oil wells that have achieved commercial production.

Kern County, California (East Slopes Project)

East Slopes Project. We believe the Company is now well positioned to expand its operations in the East Slopes Project. We currently have production from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations. The Sunday and Bear properties each have four producing wells. The Black property is the smallest of all currently producing reservoirs, and we will most likely drill only one or two more development wells at this property. The Ball and Dyer Creek properties 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 estimated to be approximately 34.6 acres in size with the potential for at least three more development wells to be drilled in the future. With the acquisition of an 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. We also have a 37.5% working interest with a 30.1% net revenue interest in the Sunday #4H well.

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. The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least three more development wells to be drilled in the future, including one planned for the summer of 2011. With the acquisition of an 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 property is just south of the Bear property on the same fault system. The Black #1 well was completed and put on production in January 2010. Production is from the Vedder sand at 2,150 feet. The Black reservoir is estimated to be approximately 13.4 acres in size with the potential for one or two development wells to be drilled in the future. We have a 37.5% working interest with a 29.8% net revenue interest in this property.

Sunday Central Processing and Storage Facility

The oil produced from our acreage is considered heavy oil. The oil ranges from 14° to 16° API gravity. All of our oil from the Sunday, Bear and Black properties is processed, stored and sold from the Sunday Central Processing and Storage Facility. The oil must be heated to separate and remove 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 available, we are ensuring 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 data indicates a reservoir approximately 37.5 acres in size with the potential for at least two development wells to be drilled in the future. 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 in this property. We expect to drill at least one development well at this property during the summer of 2011.

Dyer Creek Property

The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010. This well is producing from the Vedder sand and is located to the north of the Bear property on the same trapping fault. The Dyer Creek property has the potential for at least one development well in the future. Production from the DC67X 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 in this property.

Dyer Creek Processing and Storage Facility

The Dyer Creek Processing and Storage Facility serves the Ball and Dyer Creek properties and includes previously abandoned infrastructure that we have refurbished. We have completed the installation of electrical service to this location, thereby reducing operating costs through the elimination of rental equipment for power generation. The oil produced into this facility has similar API gravity to the oil at the Sunday production facility and the oil must also be heated to separate and remove water in preparation for sale.

Bull Run Prospect

This prospect is located in the southern portion of our acreage position. The drilling targets are the Etchegoin and Santa Margarita sands located between 800 and 1,200 feet deep. We plan to drill an exploratory well on this prospect during the summer 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 with a gross recoverable reserve potential of 6 million barrels of oil. The Bull Run wells will require a pilot steam flood and additional production facilities. We have a 41.67% working interest in this prospect.

Glide-Kendall Prospect

This prospect is also located in the southern portion of our acreage position. The drilling targets are the Olcese and Eocene sands between 1,000 and 2,000 feet deep. We plan to drill an exploratory well in the fall of 2011. We estimate that the Glide Kendall prospect is 200 acres in size with a gross recoverable reserve potential of 500,000 barrels of oil. We have a 41.67% working interest in this prospect.

Sherman Prospect

This prospect is located in the southern portion of our acreage position. The drilling targets are the Olcese and Etchegoin sands between 1,000 and 2,000 feet deep. We plan to drill an exploratory well in early 2012. We estimate that the Sherman Prospect is 100 acres in size with a gross recoverable reserve potential of 300,000 barrels of oil. We have a 41.67% working interest in this prospect.

Baker Prospect

This prospect is located in the northern portion of our acreage position approximately one mile south of our Sunday property. This drilling target is the Vedder sand which is approximately 2,000 feet deep. We plan to drill an exploratory well in early 2012. We estimate that the Baker prospect is 70 acres in size with a gross recoverable reserve potential of 200,000 barrels of oil. We have a 41.67% working interest in this prospect.

Breckenridge-Chimney Prospect

This prospect is located in the central portion of our acreage position. The drilling targets are the Vedder and Eocene sands between 2,000 and 2,500 feet deep. We plan to drill an exploratory well in 2012. We estimate that the Breckenridge-Chimney prospect is 60 acres in size with a gross recoverable reserve potential of 1.5 million barrels of oil. We have a 41.67% working interest in this prospect.

Tobias Prospect

This prospect is also located in the central portion of our acreage position. The drilling targets are the Vedder and Eocene sands between 2,000 and 2,500 feet deep. We plan to drill an exploratory well in 2012. We estimate that the Tobias prospect is 60 acres in size with a gross recoverable reserve potential of 700,000 barrels of oil. We have a 41.67% working interest in this prospect.

Our net sales volume, revenue and lease operating expenses (“LOE”) for all California properties during the year ended February 28, 2011 and the three month period ended May 31, 2011 are set forth in the following table:


	Three Months Ended May 31, 2011		Three Months Ended February 28, 2011		Three Months Ended November 30, 2010		Three Months Ended August 31, 2010		Three Months Ended May 31, 2010


Sales (Barrels)		3,502		3,805		3,508		2,976		2,720
Revenue	$	380,357	$	320,375	$	259,064	$	202,987	$	193,051
LOE	$	40,772	$	62,524	$	56,778	$	19,514	$	35,943

Average Sales Price	$	108.61	$	84.20	$	73.85	$	68.21	$	70.97

Average LOE	$	11.64	$	16.43	$	16.18	$	6.56	$	13.21

Three Months Ended May 31, 2011 compared to the Three Months Ended May 31, 2010

The following discussion compares our results for the three month periods ended May 31, 2011 and May 31, 2010 at our East Slopes Project.

Revenues. Revenues are derived entirely from the sale of our share of oil production. We realized the first revenues from producing wells in our East Slopes Project during February 2009. The price we receive for oil sales is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) contracts, less deductions, that vary by grade of crude oil sold. Historically, the sales price we receive for California oil sales is less than the quoted WTI price. For the three months ended May 31, 2010, the average discount from WTI pricing on oil sales in California was 10.4%. For the three months ended May 31, 2011, the average monthly sales price was a premium of 4.3% higher than the average WTI pricing.

Revenues for the three months ended May 31, 2011 increased $187,306 or 97.0% to $380,357 in comparison to revenue of $193,051 for the three months ended May 31, 2010. The average price of a barrel of oil for the three months ended May 31, 2011 was $108.61 in comparison to $70.97 for the three months ended May 31, 2010. The increase of $37.64 or 53.0% in the average price of a barrel of oil accounted for $102,372 or 54.6% of the revenue increase from the comparative three month period ended May 31, 2010.

The revenues for the three months ended May 31, 2011 were from 11 producing wells in California in comparison to nine producing wells for the three months ended May 31, 2010. The Bear #3 and Bear #4 wells were on production for 41 and 34 days, respectively, for the three months ended May 31, 2010. Our net share of production for the three months ended May 31, 2011 was 3,502 barrels in comparison to 2,720 barrels for the three months ended May 31, 2010. The increase in production of 782 barrels or 28.8% accounted for $84,934 or 45.4% of the revenue increase from the comparative three month period ended May 31, 2010. A table of our revenues is set forth below:


	Three Months Ended May 31, 2011		Three Months Ended May 30, 2010

California - East Slopes Project	$	380,357	$	193,051

Total Revenues	$	380,357	$	193,051

Costs and Expenses. Operating expenses for the three months ended May 31, 2011 decreased by $95,201 or 16.7% compared to the three months ended May 31, 2010. Significant decreases in exploration and drilling ($47,018); depreciation, depletion and amortization (“DD&A”) ($35,716); and general and administrative (“G&A”) costs (25,620), totaling $108,354 in aggregate, were offset by an increase of $4,829 or 13.4% in production costs.

Operating expenses for the three months ended May 31, 2011 and May 31, 2010 are set forth in the table below:


	May 31, 2011		May 31, 2010

Production Costs	$	40,772	$	35,943
Exploration and Drilling		25,802		72,820
DD&A		79,571		115,287
Gain on write-off of ARO		—		(8,324	)
G&A		330,132		355,752

Total Operating Expenses	$	476,277	$	571,478

Production costs include costs directly associated with the generation of oil and gas revenues, road maintenance, well insurance and well workover costs. For the three months ended May 31, 2011, these costs increased by $4,829 or 13.4% in comparison to the three months ended May 31, 2010. This increase in production costs is directly related to the number of producing wells in the two comparative periods. For the three months ended May 31, 2011, we had 11 producing wells. In the three months ended May 31, 2010, we had nine wells producing, however the Bear #3 and Bear #4 wells only produced for 41 and 34 days, respectively. Additionally, for the three months ended May 31, 2010, we received approximately $16,473 in oil processing credits for the Sunday #1 and Bear #1, #2, #3 and #4 wells that were using the Sunday Central Processing Facility. These oil processing credits ceased on September 1, 2010. Production costs represented 8.6% of total operating expenses.

Exploration and drilling expenses include geological and geophysical (“G&G”) costs as well as leasehold maintenance costs and dry hole expenses. For the three months ended May 31, 2011 these expenses decreased $47,018 or 64.6%, in comparison to the three months ended May 31, 2010. Exploration expenses decreased primarily because of fewer lease rentals due to expiration of certain leases. For the three months ended May 31, 2011, we did not drill any dry hole or non-commercial wells. Exploration and drilling expenses represented 12.7% of total operating expenses.

DD&A expenses relating to equipment, proven reserves and property costs, along with impairment, are another component of operating expenses. DD&A expenses decreased $35,716 or 31.0% for the three months ended May 31, 2011, in comparison to the three months ended May 31, 2010. This decrease is directly related to an increase in our proven oil reserve base at February 28, 2011. DD&A represented 20.2% of total operating expenses.

The gain on write-off of asset retirement obligation (“ARO”) of $8,324 that occurred in the three months ended May 31, 2010 related to the Krotz Springs project in Louisiana. There was no activity in this account for the three months ended May 31, 2011.

G&A expenses include 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 expenses. For the three months ended May 31, 2011, G&A expenses decreased $25,620 or 7.2%, in comparison to the three months ended May 31, 2010. Legal and accounting expenses increased by $4,883 for the three months ended May 31, 2011. Advertising and marketing expenses decreased by $13,990 for the three months ended May 31, 2011. Management and employee salaries, director fees and stock compensation were relatively unchanged for the three months ended May 31, 2011 in comparison to the three months ended May 31, 2010. Travel and associated costs decreased by $9,966 or 79.6% for the three months ended May 31, 2011, primarily due to the timing of drilling new wells. For the three months ended May 31, 2011, we received, as Operator, administrative overhead reimbursement of approximately $16,050 for the East Slopes Project which was used to directly offset certain employee salaries. We are continuing a program of reducing all of our G&A costs wherever possible. G&A costs represented 62.3% of total operating expenses.

Interest income for the three months ended May 31, 2011 decreased $1,018 or 85.8% in comparison to the three months ended May 31. 2010. This decrease was due to lower average cash balances.

Interest expense for the three months ended May 31, 2011 increased $35,454 or 152.5% in comparison to the three months ended May 31, 2010. The increase in interest expense was primarily due to the recognition of interest expense ($18,750) and the debt discount ($15,053) associated with the $750,000 short-term note payable executed in connection with our purchase of the additional working interest in our East Slopes Project.

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 and revenues will fluctuate according to the number and percentage ownership of producing 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 on the success or failure of such projects. Likewise, the amount of DD&A expense and impairment costs will primarily depend upon the number of producing wells and the size of our proven reserves base. G&A expenses will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.

Liquidity and Capital Resources

Our primary financial resource is our proven oil reserves base. Our ability to fund a future capital expenditure program is dependent upon the 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 capital expenditures during the next fiscal year.

The Company’s financial statements for the three months ended May 31, 2011 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 May 31, 2011 have an accumulated deficit of $22,561,355 and a working capital deficit of $2,142,704, 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.

On June 21, 2011, the Company announced that it had received a funding commitment for a $3,500,000 secured loan (the “July 2011 Loan”) from a third party. The term of the July 2011 Loan will be for three years with an interest rate of 6% per annum. Also, in accordance with the terms of the commitment, the Company will make monthly payments of interest on the proposed July 2011 Loan, with the entire principal balance due at the end of the term. The July 2011 Loan will be secured by the Company’s leases at its East Slopes Project. While there can be no assurance, the July 2011 Loan is expected to close after completion of definitive documentation, due diligence and customary closing conditions. Proceeds of the July 2011 Loan will be used to expand the development of the Company’s East Slopes Project as well as repay the $750,000 principal amount under its existing Secured Promissory Note due September 17, 2011, and for other general corporate purposes.

We will continue to pursue possible funding alternatives in the future, 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 May 31, 2011 in comparison with February 28, 2011 are set forth in the following table:


	May 31, 2011			February 28, 2011			Increase (Decrease)			Percentage Change

Cash	$	30,946		$	57,380		$	(26,434	)		(46.1	%)
Current Assets	$	486,736		$	593,275		$	(106,539	)		(18.0	%)
Total Assets	$	3,143,816		$	3,313,180		$	(169,364	)		(5.1	%)
Current Liabilities	$	2,629,440		$	2,672,124		$	(42,684	)		(1.6	%)
Total Liabilities	$	3,185,417		$	3,223,140		$	(37,723	)		(1.2	%)
Working Capital	$	(2,142,704	)	$	(2,078,849	)	$	(63,855	)		(3.1	%)

Our working capital deficit increased $63,855 or 3.1% to ($2,142,704) at May 31, 2011 in comparison to ($2,078,849) at February 28, 2011. The increase in the working capital deficit was principally due to meeting the ongoing financial commitments reflected in our G&A expenses and the continuing reduction of the $1.5 million debt we assumed when we acquired the additional 25% working interest in California in March 2009. As of May 31, 2011, approximately $320,734 remained to be paid from the default of our original working interest partners in California and is included in the accounts payable balance.

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 may 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 expenses, 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:


	Three Months Ended May 31, 2011			Three Months Ended May 31, 2010			Increase (Decrease)			Percentage Change

Net cash provided by operating activities	$	58,235		$	324,105		$	(265,870	)		(82.0	%)
Net cash (used in) investing activities	$	(84,669	)	$	(116,782	)	$	32,113			(27.5	%)
Net cash provided by financing activities	$	—		$	30,000		$	(30,000	)		(100.0	%)

Cash Flow Provided by 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 three months ended May 31, 2011, we had a positive cash flow from operating activities of $58,235, in comparison to a positive cash flow of $324,105 for the three months ended May 31, 2010. This decrease of $265,870 or 82.0% was the result of redeeming operator bonds for Alabama and Louisiana in the three months ended May 31, 2010. Our net loss decreased by $231,250 or 60.0% for the three months ended May 31, 2011. Additionally, we increased our oil revenues, reduced our operating expenses and increased collections of outstanding receivable amounts for the three months ended May 31, 2011. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash Flow (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 three months ended May 31, 2011 was ($84,669); a decrease of $32,113 or 27.5% from the ($116,782) used in investing activities for the three months ended May 31, 2010. This change was primarily due to the lack of drilling activity that occurred during the three months ended May 31, 2011 in comparison to the three months ended May 31, 2010.

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. For the three months ended May 31, 2011 we had no cash flow from financing activities, in comparison to a cash flow of $30,000 from financing activities for the three months ended May 31, 2010. Financing activity for the three months ended May 31, 2010 consisted of funds received through the sale of a $30,000 12% Subordinated Note in a private placement in March 2010.

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 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 $250,000 Note was sold to a related party, the Company’s President and Chief Executive Officer. The terms and conditions of the related party Note were identical to the terms and conditions of the other accredited investor’ 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 “September 2010 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 September 2010 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 was deferred and amortized over the term of the September 2010 Loan. Amortization expense for the three months ended May 31, 2011 amounted to $5,938. Unamortized loan origination fee expense amounted to $5,938 as of May 31, 2011.

The September 2010 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 Slopes Project. Furthermore, as a condition precedent to the September 2010 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.

As additional consideration for the September 2010 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 September 2010 Loan. Amortization expense for the three months ended May 31, 2011 was $15,053. Unamortized debt discount amounted to $15,053 as of May 31, 2011.

Financing Commitment - Three-Year Note Payable

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 $30,946 and $57,380 as of May 31, 2011 and February 28, 2011, respectively. The decrease of approximately $26,434 was due to meeting ongoing financial commitments as a part of our G&A expenses and continuing reduction of outstanding balances associated with the default of certain original partners default in our East Slopes Project.

Operating Loss

During the three months ended May 31, 2011 we reported an operating loss of approximately $95,920 in comparison to an operating loss of approximately $378,427 for the three months ended May 31, 2010. This reduction in operating loss of approximately $282,507 or 74.7% from the operating loss for the three months ended May 31, 2010 was achieved by increasing revenue and lowering operating costs. Revenue increased due to both an increase in production and an increase in the sales price of oil. We increased production by 782 barrels of oil or 28.8% through sales from 11 producing wells in comparison to sales from nine producing wells in the three months ended May 31, 2010. The average price of oil increased by $37.64 or 53.0% to $108.61 per barrel for the three months ended May 31, 2011 in comparison to the three months ended May 31, 2010.

Operating expenses decreased by 16.7% or $95,201 to $476,277 for the three months ended May 31, 2011 in comparison to $571,478 for the three months ended May 31, 2010. Exploration and drilling, DD&A and G&A expenses experienced the greatest reductions with a combined reduction of 19.9% or $108,354. This reduction was offset by an increase of $4,829 in production expenses for the three months ended May 31, 2011.

We continue to make progress each fiscal quarter towards the goal of achieving positive operating income on a company-wide basis.

Net Loss

Since entering the oil and gas exploration industry, we have incurred recurring losses with periodic 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 $154,446 was reported for the three months ended May 31, 2011, in comparison to a net loss of $385,696 for the three months ended May 31, 2010. The decrease in net loss of $231,250 or 60.0% for the three months ended May 31, 2011 was primarily due to an increase of $187,306 in revenue generated from oil sales and a reduction of $95,202 in operating expenses in comparison to the three months ended May 31, 2010.

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 Common Stock and restricted Common Stock unit awards. Subject to adjustment, the total number of shares of Daybreak 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 May 31, 2011, a total of 1,000,000 shares remained available for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is set forth in the table shown below:


Grant Date	Shares Awarded		Vesting Period		Shares Vested		Shares Outstanding (Unvested)

4/7/2009		1,900,000		3 Years		1,266,665		633,335
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				1,431,245		1,568,755

For the three months ended May 31, 2011 and May 31, 2010, the Company recognized compensation expense related to the above restricted stock grants of $22,805 and $20,772, respectively. Unamortized compensation expense amounted to $110,493 as of May 31, 2011.

Summary

We are continuing to execute the Company’s business plan of developing Daybreak’s acreage position in Kern County, California. 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 that we will need additional financing in the future for our planned exploration and development activities. We may seek financing 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, however no assurance can be given that we will be able to obtain funding under the July 2011 Loan or 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, 2011.

Off-Balance Sheet Arrangements

As of May 31, 2011, 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 4. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

As of the end of the reporting period, May 31, 2011, an evaluation was conducted by Daybreak management, including our President and Chief Executive Officer, who is also serving as our 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 May 31, 2011.

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 May 31, 2011 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

As of the date of this filing, there have been no material changes from the risk factors previously disclosed in our “Risk Factors” described in Part 1, Item 1A, of the Form 10-K for the year ended February 28, 2011.

ITEM 6. EXHIBITS

The following Exhibits are filed as part of the report:


Exhibit Number	Description

31.1⁽¹⁾	Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1⁽¹⁾	Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1) Filed herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


DAYBREAK OIL AND GAS, INC.

By:	/s/ JAMES F. WESTMORELAND

		James F. Westmoreland, its
		President, Chief Executive Officer and interim
		principal finance and accounting officer
		(Principal Executive Officer, Principal Financial
		Officer and Principal Accounting Officer)

Date: July 15, 2011