Daybreak Oil and Gas (DBRM) 10-Q 2014 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x          QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended November 30, 2013

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 1017, 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   ¨ 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 þ   No ¨

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¨		Accelerated filer¨
Non-accelerated filer¨	(Do not check if a smaller reporting company)	Smaller reporting companyþ

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

At January 13, 2014 the registrant had 55,379,411 outstanding shares of $0.001 par value common stock.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS	3
	Balance Sheets at November 30, 2013 and February 28, 2013 (Unaudited)	3
	Statements of Operations for the Three and Nine Months Ended November 30, 2013 and November 30, 2012 (Unaudited)	4
	Statements of Cash Flows for the Nine Months Ended November 30, 2013 and November 30, 2012 (Unaudited)	5
	NOTES TO UNAUDITED FINANCIAL STATEMENTS	6
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	33
ITEM 4.	CONTROLS AND PROCEDURES	33
	PART II - OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	34
ITEM 1A.	RISK FACTORS	34
ITEM 6.	EXHIBITS	35
Signatures		36

2

PART I

FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

DAYBREAK OIL AND GAS, INC.

Balance Sheets – Unaudited

	As of November 30,		As of February 28,
	2013		2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	194,690	$	79,996
Accounts receivable:
Oil and gas sales		229,504		167,925
Joint interest participants		343,006		83,585
Production revenue receivable - current		120,000		-
Loan commitment refund and other receivables, net		29,677		16,315
Note receivable – current portion		1,196,122		-
Prepaid expenses and other current assets		28,486		28,453
Total current assets		2,141,485		376,274
OIL AND GAS PROPERTIES, successful efforts method, net
Proved properties		2,597,460		1,126,783
Unproved properties		1,335,554		362,100
PREPAID DRILLING COSTS		176,628		722
PRODUCTION REVENUE RECEIVABLE, NON-CURRENT		185,000		350,000
DEFERRED FINANCING COSTS, NET		1,309,835		298,051
NOTE RECEIVABLE, NON-CURRENT		1,653,878		-
OTHER ASSETS		106,082		105,924
Total assets	$	9,505,922	$	2,619,854
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	2,193,148	$	2,061,756
Accounts payable, related parties		977,673		794,203
Accrued interest		24,362		44,662
Notes payable, related party		250,100		250,100
Long-term debt, current, related party, net		2,090,265		115,477
Deferred interest		182,263		-
Line of credit		883,384		886,458
Total current liabilities		6,601,195		4,152,656
LONG TERM LIABILITIES:
Notes payable, net		323,516		312,072
Note payable - related party, net		234,194		225,779
Long-term debt, non-current, related party, net		5,015,460		1,235,564
Asset retirement obligation		87,378		55,174
Total liabilities		12,261,743		5,981,245
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ 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; 747,565 and 888,565 shares issued and outstanding, respectively		748		889
Common stock- 200,000,000 shares authorized; $0.001 par value, 55,379,411 and 48,837,939 shares issued and outstanding, respectively		55,379		48,838
Additional paid-in capital		24,591,817		22,663,103
Accumulated deficit		(27,403,765)		(26,074,221)
Total stockholders’ deficit		(2,755,821)		(3,361,391)
Total liabilities and stockholders' deficit	$	9,505,922	$	2,619,854

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

3

DAYBREAK OIL AND GAS, INC.

Statements of Operations – Unaudited

	For the Three Months Ended November 30,				For the Nine Months Ended November 30,
	2013		2012		2013		2012
REVENUE:
Oil and gas sales	$	425,035	$	229,913	$	1,131,847	$	742,034
OPERATING EXPENSES:
Production expenses		44,697		38,223		160,652		81,855
Exploration and drilling		10,991		3,455		245,685		40,005
Depreciation, depletion, amortization, and impairment		56,922		53,424		261,641		172,544
Write down on asset disposal		39,254		-		39,254		-
Bad debt expense		-		239,000		-		239,000
General and administrative		347,722		265,993		943,594		899,984
Total operating expenses		499,586		600,095		1,650,826		1,433,388
OPERATING LOSS		(74,551)		(370,182)		(518,979)		(691,354)
OTHER INCOME (EXPENSE):
Interest income		135,621		120		135,731		343
Interest expense		(472,166)		(90,297)		(946,296)		(321,481)
Loss on settlement of debt		-		(780,938)		-		(780,938)
Total other income (expense)		(336,545)		(871,115)		(810,565)		(1,102,076)
NET LOSS		(411,096)		(1,241,297)		(1,329,544)		(1,793,430)
Cumulative convertible preferred stock dividend requirement		(38,113)		(40,323)		(118,165)		(122,436)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(449,209)	$	(1,281,620)	$	(1,447,709)	$	(1,915,866)
NET LOSS PER COMMON SHARE - Basic and diluted	$	(0.01)	$	(0.03)	$	(0.03)	$	(0.04)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - Basic and diluted		55,072,884		48,807,939		50,967,879		48,797,555

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

4

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows – Unaudited

	Nine Months Ended
	November 30, 2013		November 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,329,544)	$	(1,793,430)
Adjustments to reconcile net loss to net cash used in operating activities:
Loss on settlement of debt		-		780,938
Bad debt expense		-		239,000
Stock compensation		10,546		20,413
Depreciation, depletion, accretion and impairment expense		300,895		172,544
Amortization of warrants and debt discount		117,822		26,177
Amortization of deferred financing costs		133,020		130,023
Interest income		(158)		(343)
Changes in assets and liabilities:
Accounts receivable - oil and gas sales		(61,579)		68,837
Accounts receivable - joint interest participants		(259,421)		6,672
Accounts receivable - other		31,638		(30,113)
Prepaid expenses and other current assets		(33)		31,076
Accounts payable and other accrued liabilities		(187,796)		232,458
Accounts payable - related parties		183,470		195,497
Accrued interest		(20,300)		75,701
Net cash provided by (used in) operating activities		(1,081,440)		155,450
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(1,411,468)		(182,142)
Advances for oil and gas properties		(175,906)		-
Deferred interest		(135,553)		-
Note receivable		(2,208,368)		-
Net cash used in investing activities		(3,931,295)		(182,142)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable and line of credit		5,592,384		-
Payment on notes payable		(298,479)		-
Payment of deferred financing fees		(139,476)		(40,700)
Payments on line of credit		(27,000)		(6,000)
Net cash provided by (used in) financing activities		5,127,429		(46,700)
NET INCREASE (DECREASE)IN CASH AND CASH EQUIVALENTS		114,694		(73,392)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		79,996		73,392
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	194,690	$	-
CASH PAID FOR:
Interest	$	690,788	$	535,324
Income taxes	$	-	$	-
SUPPLEMENTAL CASH FLOW INFORMATION:
Unpaid additions to oil and gas properties	$	228,262	$	26,050
Common stock and warrants issued for oil and gas properties	$	1,073,091	$	-
Common stock and warrants issued for deferred financing costs	$	852,236	$	-
Increase in note receivable for deferred interest	$	317,816	$	-
Increase in note payable for note receivable and deferred financing costs	$	362,816	$	-
ARO asset and liability increase	$	27,079	$	4,702
Unpaid deferred financing fees	$	114,093	$	57,361
Interest added to line of credit principal	$	23,927	$	24,427
Conversion of preferred stock to common stock	$	423	$	24
Repurchase of stock through payment of payroll taxes	$	758	$	173

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

5

DAYBREAK OIL AND GAS, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION:

Organization

Originally incorporated as Daybreak Uranium, Inc., (“Daybreak Uranium”) under the laws of the State of Washington on March 11, 1955, Daybreak Uranium was organized to explore for, acquire, and develop mineral properties in the Western United States.  During 2005, management of the Company decided to enter the oil and gas exploration and production industry.  On October 25, 2005, the Company shareholders approved a name change from Daybreak Mines, Inc. to Daybreak Oil and Gas, Inc. (referred to herein as “Daybreak” or the “Company”) 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 nine months ended November 30, 2013 are not necessarily indicative of the results that may be expected for the fiscal year ending February 28, 2014.

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, 2013.

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.

6

NOTE 2 — GOING CONCERN:

Financial Condition

The Company’s financial statements for the nine months ended November 30, 2013 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 November 30, 2013 has an accumulated deficit of $27,403,765 and a working capital deficit of $4,459,710 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 (“NRI”) in 20 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.  The Company’s average working interest in these wells is 36.8% and the average NRI is 28.4% for these same wells.

Additionally, the Company has become involved in a shallow oil play in an existing gas field in Lawrence County, Kentucky, through its acquisition of a 25% working interest in approximately 6,400 acres in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky (the “Kentucky Acreage”).  The initial drilling program involved drilling five horizontal wells of which all have been completed and are either producing or are expected to be producing by the end of January 2014.  The Company received its first Kentucky oil revenue from October production in November 2013.

The Company anticipates revenues will continue to increase as it participates in the drilling of more wells in California and Kentucky.  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 has experienced revenue growth from its oil properties, it has not yet established a positive cash flow on a company-wide basis.  It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future.  However; the Company cannot offer any assurance that the Company will be successful in executing the aforementioned plans to continue as a going concern.

Daybreak’s financial statements as of November 30, 2013 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:

There are no new accounting pronouncements issued or effective that have had or are expected to have, a material impact on the Company’s financial statements.

NOTE 4 — CONCENTRATION OF CREDIT RISK:

Substantially all of the Company’s trade accounts receivable result from crude oil and gas 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.  Trade accounts receivable are generally not collateralized.  There were no allowances for doubtful accounts for the Company’s trade accounts receivable at November 30, 2013 and February 28, 2013 as all joint interest owners have a history of paying their obligations in a timely manner.

At the Company’s East Slopes Project in California and its Twin Bottoms Field in Kentucky, there is only one respective buyer available for the purchase of oil and gas production.  At November 30, 2013, these customers represented 100% of crude oil sales receivable.  If these buyers are unable to resell their products, or if they lose a significant sales contract; then the Company may incur difficulties in selling its oil and gas production.

7

Allowances for doubtful accounts in receivables of loan commitments and other receivables relate to amounts due from third parties that were involved in arranging financing transactions for the Company that have not yet been consummated.  Accounts receivable – loan commitment refund and other receivables balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
Loan commitment and other receivables	$	268,677	$	255,315
Allowance for doubtful accounts		(239,000)		(239,000)
	$	29,677	$	16,315

NOTE 5 — PREPAID DRILLING COSTS:

During the nine months ended November 30, 2013, the Company was engaged in both a spring and fall multi-well drilling program at its East Slopes Project in Kern County, California.  The Company had prepayments to certain of its vendors from these drilling programs of $40,274 at November 30, 2013 and $722 at February 28, 2013.

During the nine months ended November 30, 2013, the Company acquired a 25% working interest in a shallow oil play in an existing gas field project in Lawrence County, Kentucky.  At November 30, 2013, the Company had prepayments to the operator of this project of $136,354 for drilling costs in a multi-well drilling program.

NOTE 6 — OIL AND GAS PROPERTIES:

Oil and gas property balances at November 30, 2013 and February 28, 2013 are set forth in the table below.

	November 30, 2013		February 28, 2013
Proved leasehold costs	$	2,236	$	2,236
Unproved oil and gas properties		1,335,554		362,100
Costs of wells and development		474,846		357,507
Capitalized exploratory well costs		3,609,589		2,170,600
Capitalized asset retirement costs		65,429		38,352
Total cost of oil and gas properties		5,487,654		2,930,795
Accumulated depletion, depreciation, amortization and impairment		(1,554,640)		(1,441,912)
Net Oil and Gas Properties	$	3,933,014	$	1,488,883

During the nine months ended November 30, 2013, the Company acquired a 25% working interest in a shallow oil play in an existing gas field project in Lawrence County, Kentucky.  As of November 30, 2013, unproved oil and gas properties include the fair value of common shares and warrants issued to a third party, Maximilian Investors LLC, amounting to $1.07 million.  Refer to the discussion in Note 12 – Short-Term and Long-Term Borrowings for further information on the issuance of shares and warrants related to oil and gas properties.

NOTE 7 — PRODUCTION REVENUE RECEIVABLE:

Production revenue receivable balances of $305,000 in aggregate represent amounts due the Company from a portion of the sale price of a 25% working interest in East Slopes Project in Kern County, California that was acquired through the default of certain original working interest partners in the project.  Production revenue receivable balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
Production revenue receivable – current	$	120,000	$	-
Production revenue receivable – non-current		185,000		350,000
	$	305,000	$	350,000

8

NOTE 8 — DEFERRED FINANCING COSTS:

Deferred financing costs at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
Deferred financing costs – fees and expenses	$	519,725	$	227,157
Deferred financing costs – fair value of common shares and warrants		950,320		98,084
		1,470,045		325,241
Accumulated amortization		(160,210)		(27,190)
	$	1,309,835	$	298,051

Amortization expense of deferred financing costs for the nine months ended November 30, 2013 was $133,020. Deferred financing costs as of November 30, 2013 include the fair value of common shares and warrants issued to Maximilian amounting to $804,816 and $145,504 to a third party that assisted in the financing transaction.  Refer to the discussion in Note 12 – Short-Term and Long-Term Borrowings for further information on the deferred financing costs.

NOTE 9 — NOTE RECEIVABLE:

On August 28, 2013, the Company amended its credit facility with Maximilian Investors LLC (“Maximilian”) as a part of a financing transaction in which the Company extended to App Energy, LLC, a Kentucky limited liability company (“App”) a credit facility for the development of a shallow oil project in an existing gas field in Lawrence County, Kentucky.  (See Note 12 – Short-Term and Long-Term Borrowings).

The Company’s loan agreement with App, dated August 28, 2013, provides for a revolving credit facility of up to $40 million, maturing on August 28, 2017, with a minimum commitment of $2.65 million (the “Initial Advance”).  All funds advanced to App, as borrower, by Daybreak, as lender, are to be borrowed by Daybreak under its amended loan agreement with Maximilian.  The Initial Advance bears interest of 16.8% per annum, and subsequent loans under the loan agreement bear interest at a rate of 12% per annum.  The App loan agreement also provides for a monthly commitment fee of 0.6% on the outstanding principal balance of the loans.  The obligations under the App loan agreement are secured by a perfected first priority security interest in substantially all of the assets of App, including the Company’s leases in Lawrence County, Kentucky, an indemnity provided by App’s manager, John A. Piedmonte, Jr. and a guarantee by certain affiliates of App.

The App loan agreement contains customary covenants for loan of such type, including, among other things, covenants that restrict App’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The App loan agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of App’s obligations under the App loan agreement could be accelerated by the Company, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

The proceeds of the initial borrowing by App of $2.65 million under the App revolving credit facility were primarily used to (a) pay loan fees and closing costs, (b) repay App’s indebtedness and (c) finance the drilling of three wells by App in the Kentucky Acreage.  Future advances under the facility will primarily be used for oil and gas exploration and development activities.

In connection with the App loan agreement, App also granted to the Company a 25% working interest in the Kentucky Acreage, as described above.  The fair value of the 25% working interest was determined to be $1,073,091 and was recorded as unproved oil and gas properties. Refer to Note 12 for further discussion on the related fair value.

At November 30, 2013, the Company had advanced $2,850,000 to App through its credit facility.  The total amount advanced includes fees paid in connection with the loan amounting to $72,000 and settlement of App’s existing obligation to another lender of $200,386 which were paid directly by Maximilian and $317,816 of interest withheld by Daybreak which is reported as deferred interest in the balance sheets.

9

Note receivable balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
Note receivable – current	$	1,196,122	$	-
Note receivable – non-current		1,653,878		-
	$	2,850,000	$	-

NOTE 10 — ACCOUNTS PAYABLE:

On March 1, 2009, the Company became the operator for its East Slopes Project.  Additionally, the Company, at that time, 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 four earning well program.  The Company subsequently sold the same 25% working interest on June 11, 2009.  Of the $1.5 million default, $263,849 remains unpaid and is included in the November 30, 2013 accounts payable balance.

NOTE 11 — ACCOUNTS PAYABLE- RELATED PARTIES:

The November 30, 2013 and February 28, 2013 accounts payable – related parties balances were comprised primarily of deferred salaries of the Company’s Executive Officers and certain employees; directors’ fees; expense reimbursements; related party consulting fees; and interest to the Company’s President and CEO on the 12% Subordinated Notes further described in Note 12 – Short-Term and Long-Term Borrowings below.  Payment of these deferred items has been delayed until the Company’s cash flow situation improves.

NOTE 12 — SHORT-TERM AND LONG-TERM BORROWINGS:

Line of Credit

During the year ended February 29, 2012, the Company entered into an $890,000 credit line for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer.  At November 30, 2013, the Line of Credit had an outstanding balance of $883,384.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $23,927 for the nine months ended November 30, 2013.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

Short-Term Note Payable – Related Party

The balance as of November 30, 2013 of $250,100 represents non-interest bearing notes issued by the Company to its President and Chief Executive Officer.  Repayment of the notes will be made upon a mutually agreeable date in the future.

Long-Term Borrowings

12% Subordinated Notes

On January 13, 2010, the Company commenced a private placement of 12% Subordinated Notes (“Notes”).  On March 16, 2010, the Company closed its private placement of Notes to 13 accredited investors resulting in total gross proceeds of $595,000.  Interest on the Notes accrues at 12% per annum, payable semi-annually.  The note principal is payable in full at the maturity of the Notes, which is January 29, 2015.  Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then 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 participants’ Notes.

10

In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at the rate of two warrants for every dollar raised through the private placement.  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 nine months ended November 30, 2013 amounted to $19,858.  Unamortized debt discount amounted to $37,290 as of November 30, 2013.

Notes Payable balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
12% Subordinated Notes	$	345,000	$	345,000
12% Subordinated Note Discount		(21,484)		(32,928)
	$	323,516	$	312,072

Notes Payable – Related Party balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
12% Subordinated Notes	$	250,000	$	250,000
12% Subordinated Note Discount		(15,806)		(24,221)
	$	234,194	$	225,779

Maximilian Loan

On October 31, 2012, the Company entered into a loan agreement with Maximilian Investors LLC (“Maximilian”, or “Lender”), which provided for a revolving credit facility of up to $20 million, maturing on October 31, 2016, with a minimum commitment of $2.5 million.  The loan had annual interest of 18% and a monthly commitment fee of 0.5%.  The Company also granted Maximilian a 10% working interest in its share of the oil and gas leases in Kern County, California.  The relative fair value of this 10% working interest amounting to $515,638 was recognized as a debt discount and is being amortized over the term of the loan. Amortization expense for the nine months ended November 30, 2013 amounted to $97,964.  Unamortized debt discount amounted to $377,053 as of November 30, 2013.

The Company also issued in 2012, 2,435,517 warrants to third parties who assisted in the closing of the loan.  The warrants have an exercise price of $0.044; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on October 31, 2017.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $98,084 and included the following assumptions: a risk free interest rate of 0.72%; stock price of $0.04, volatility of 153.44%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the revolving credit facility.

Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App, the Company amended its loan agreement with Maximilian on August 28, 2013. The amended loan agreement provided for an increase in the revolving credit facility from $20 million to $90 million and a reduction in the annual interest rate from 18% to 12%.  The monthly commitment fee of 0.5% per month on the outstanding principal balance remained unchanged.  Advances under the amended loan agreement will mature on August 28, 2017.  The obligations under the amended loan agreement continue to be secured by a perfected first priority security interest in substantially all of the personal property of the Company, including the Company’s leases in Kern County, California.  The amended loan agreement also provided for the revolving credit facility to be divided into two borrowing sublimits.  The first borrowing sublimit is $50 million and is for borrowing by the Company, primarily for its ongoing oil and gas exploration and development activities.  The second borrowing sublimit, of $40 million, is for loans to be extended by the Company, as lender, to App, as borrower pursuant to a Loan and Security Agreement entered into between the Company and App on August 28, 2013 (See Note 9 – Note Receivable).

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The amended loan agreement contains customary covenants for loans of such type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The amended loan agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of the Company’s obligations under the amended loan agreement could be accelerated by the Lender, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

As consideration for Maximilian facilitating the Company’s transactions with App and entering into the amended loan agreement, the Company (a) issued to Maximilian approximately 6.1 million common shares, representing 9.99% of the Company’s outstanding common stock on a fully-diluted basis at the time of grant, and (b) issued approximately 6.1 million warrants to purchase shares of the Company’s common stock representing the right to purchase up to an additional 9.99% of the Company’s outstanding common stock on a fully-diluted basis, calculated as of the date of grant.  The warrants have an exercise price of $0.10; contain a cash exercise provision and are exercisable for a period of three years expiring on August 28, 2016.  The Company also granted to the Lender a 50% net profits interest, after the Company recovers its investment, in the Company’s 25% working interest in the Kentucky Acreage.

The fair value of the 6.1 million shares was determined to be $979,608 based on the Company’s stock price of $0.16 on the grant date.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $898,299 and included the following assumptions: a risk free interest rate of 2.48%; stock price of $0.16, volatility of 184.53%; and a dividend yield of 0.0%.   The Company determined that the common shares and warrants were issued in connection with the increase in the Company’s borrowing limit and App’s $40 million revolving credit facility for which the Company was granted a 25% working interest.  Consequently, the fair value of the common shares and warrants totaling $1,877,907 was allocated to deferred financing costs ($804,816) and unproved oil and gas properties ($1,073,091) based on the amount of the increase in the revolving credit facility that is attributable to Daybreak and App.

The Company also issued 309,503 warrants to third parties who assisted in the closing of the amended and restated loan agreement.  The warrants have an exercise price of $0.214; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on August 28, 2018.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $47,420 and included the following assumptions: a risk free interest rate of 2.48%; stock price of $0.16, volatility of 184.53%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the revolving credit facility.

The Company evaluated the amendment of the revolving credit facility under ASC 470-50-40 and determined that the Company’s borrowing capacity under the amended loan agreement exceeded its borrowing capacity under the old loan agreement.  Consequently, the unamortized discount and deferred financing costs as of the date of amendment of approximately $400,349 and the new deferred financing costs, as mentioned above, were amortized over the term of the amended loan agreement.

During the nine months ended November 30, 2013, the Company received multiple advances totaling $5,955,200 in aggregate that were used to participate in the Company’s spring and fall 2013 drilling programs at its East Slopes Project in Kern County, California; and the drilling of its interest in the Kentucky Acreage and in the extension of the note receivable to App.  The Company has recognized $1,470,045 in deferred financing costs associated with these advances which are being amortized over the amended term of the revolving credit facility.

Current debt balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
Maximilian Note	$	2,228,442	$	246,486
Maximilian Note Discount		(138,177)		(131,009)
	$	2,090,265	$	115,477

Non-current debt balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
Maximilian Note	$	5,254,336	$	1,579,571
Maximilian Note Discount		(238,876)		(344,007)
	$	5,015,460	$	1,235,564

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NOTE 13 — STOCKHOLDERS’ 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.

At November 30, 2013, there were 747,565 shares of Series A Preferred issued and outstanding, held by accredited investors that had not been converted into the Company’s Common Stock.  During the nine months ended November 30, 2013, there were eight shareholders that converted 141,000 Series A Preferred shares into 423,000 shares of Common Stock.  At November 30, 2013, there have been 40 accredited investors who have converted 652,200 Series A Preferred shares into 1,956,600 shares of Daybreak Common Stock.  The conversions of Series A Preferred that have occurred since the Series A Preferred was first issued in July 2006 is set forth in the table below.

Fiscal Period	Shares of Series A Preferred Converted to Common Stock	Shares of Common Stock Issued from Conversion	Number of Accredited Investors
Year Ended February 29, 2008	102,300	306,900	10
Year Ended February 28, 2009	237,000	711,000	12
Year Ended February 28, 2010	51,900	155,700	4
Year Ended February 28, 2011	102,000	306,000	4
Year Ended February 29, 2012	-	-	-
Year Ended February 28, 2013	18,000	54,000	2
Nine Months Ended November 30, 2013	141,000	423,000	8
	652,200	1,956,600	40

Holders of Series A Preferred earn a 6% annual cumulative dividend based on the original purchase price of the shares.  Accumulated dividends do not bear interest and as of November 30, 2013, the accumulated and unpaid dividends amounted to $1,414,785.  Dividends may be paid in cash or Common Stock at the discretion of the Company and are payable upon declaration by the Board of Directors.  Dividends are earned until the Series A Preferred is converted to Common Stock.  No payment of dividends has been declared as of November 30, 2013.

Dividends earned since issuance of the Series A Preferred for each fiscal year and the nine months ended November 30, 2013 are set forth in the table below:

Fiscal Period	Shareholders at Period End	Accumulated Dividends
Year Ended February 28, 2007	100	$	155,311
Year Ended February 29, 2008	90		242,126
Year Ended February 28, 2009	78		209,973
Year Ended February 28, 2010	74		189,973
Year Ended February 28, 2011	70		173,707
Year Ended February 29, 2012	70		163,624
Year Ended February 28, 2013	68		161,906
Nine Months Ended November 30, 2013	60		118,165
		$	1,414,785

Common Stock

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock of which 55,379,411 shares were issued and outstanding as of November 30, 2013.  For the nine months ended November 30, 2013 there were 6,545,552 shares issued, of which 423,000 were through conversion of Series A Preferred stock and 6,122,552 were issued in connection with the Maximilian loan as described in Note 12 – Short-Term and Long-Term Borrowings. Additionally, 4,080 shares were returned to the Company as a part of the Company’s restricted stock plan to satisfy tax liability upon vesting.

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NOTE 14 — WARRANTS:

Warrants outstanding and exercisable as of November 30, 2013 are set forth in the table below:

	Warrants	Exercise Price	Remaining Life (Years)	Exercisable Warrants Remaining
12% Subordinated notes	1,190,000	$0.14	1.00	1,190,000
Warrants issued in 2010 for services	150,000	$0.14	1.50	150,000
Warrants issued in 2012 for debt financing	2,435,517	$0.044	4.00	2,435,517
Warrants issued for Kentucky oil project	3,498,601	$0.10	2.75	3,498,601
Warrants issued for Kentucky debt financing	2,623,951	$0.10	2.75	2,623,951
Warrants issued for Kentucky debt financing	309,503	$0.214	4.75	309,503
	10,207,572			10,207,572

There were no warrants exercised during the nine months ended November 30, 2013.  During the nine months ended November 30, 2013, there were 1,624,012 warrants that expired.  These warrants had been issued to placement agents in conjunction with the Spring 2006 and July 2006 placements of the Company’s Common Stock.  There were 6,432,055 warrants issued during the nine months ended November 30, 2013 in connection with the Maximilian loan as described in Note 12 — Short-Term and Long Term Borrowings.  The outstanding warrants as of November 30, 2013, have a weighted average exercise price of $0.10, a weighted average remaining life of 2.89 years, and an intrinsic value of $3,529,060.

NOTE 15 — 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 November 30, 2013, a total of 2,882,010 shares of restricted stock had been awarded and remained outstanding under the 2009 Plan, and 2,893,750 of the shares had fully vested.  A total of 1,011,740 Common Stock shares remained available at November 30, 2013 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(1)		Shares Returned(2)		Shares Outstanding (Unvested)
4/7/2009	1,900,000	3 Years	1,900,000		-		-
7/16/2009	25,000	3 Years	25,000		-		-
7/16/2009	625,000	4 Years	619,130		5,870		-
7/22/2010	25,000	3 Years	25,000		-		-
7/22/2010	425,000	4 Years	312,880		5,870		106,250
	3,000,000		2,882,010	(1)	11,740	(2)	106,250

⁽¹⁾

Does not include shares that were withheld to satisfy such tax liability upon vesting of a restricted award by a Plan Participant, and subsequently returned to the 2009 Plan.

⁽²⁾

Reflects the number of common shares that were withheld pursuant to the settlement of the number of shares with a fair market value equal to such tax withholding liability, to satisfy such tax liability upon vesting of a restricted award by a Plan Participant.

For the nine months ended November 30, 2013, the Company recognized compensation expense related to the above restricted stock grants in the amount of $10,546.  Unamortized compensation expense amounted to $4,395 as of November 30, 2013.  For the nine months ended November 30, 2013, there were 4,080 shares of the Company’s Common Stock relating to the 2009 Plan returned to the 2009 Plan to satisfy an employee’s payroll tax liability upon the vesting of shares.

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NOTE 16 — 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:

	November 30, 2013		February 28, 2013
Computed at U.S. and state statutory rates (40%)	$	(531,819)	$	(893,890)
Permanent differences		31,154		14,631
Changes in valuation allowance		500,665		879,259
	$	-0-	$	-0-

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:

	November 30, 2013		February 28, 2013
Deferred tax assets:
Net operating loss carryforwards	$	8,161,930	$	7,230,280
Oil and gas properties		(620,141)		(189,156)
Stock based compensation		82,744		82,744
Less valuation allowance		(7,624,533)		(7,123,868)
	$	-0-	$	-0-

At November 30, 2013, Daybreak had estimated net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $20,404,084 which will begin to expire, if unused, beginning in 2024.  The valuation allowance increased $500,665 for the nine months ended November 30, 2013 and increased by $879,259 for the year ended February 28, 2013. Section 382 of the Internal Revenue Code places annual limitations on the Company’s 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 17 — COMMITMENTS AND CONTINGENCIES:

Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities.  While the ultimate outcome of any future contingency is not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment.  These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages.  In some instances, the Company may be directed to suspend or cease operations in the affected area.  The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of November 30, 2013.  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.

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NOTE 18 — SUBSEQUENT EVENTS:

On December 26, 2013, the Company received $111,834 from a third party for the sale of its portion of mineral leases covering the deep drilling rights in Kentucky.

As of January 13, 2014, the Company had received additional advances from its revolving credit facility with Maximilian Investors, LLC of $900,000 in aggregate, of which $500,000 was in turn advanced to App Energy, LLC through its credit facility with the Company.

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

Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) are intended to be covered by the safe harbor provided for under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.

All statements other than statements of historical fact contained in this MD&A report are inherently uncertain and are forward-looking statements.  Statements that relate to results or developments that we anticipate will or may occur in the future are not statements of historical fact.  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 operating results;

·

Our future capital expenditures;

·

Our future financing;

·

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 commitments 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 and nine month periods ended November 30, 2013 and November 30, 2012 and of our financial condition at November 30, 2013, 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 audited financial statements and notes included in our Annual Report on Form 10-K for the year ended February 28, 2013.

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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. A secondary means of generating returns can include the sale of either producing or non-producing lease properties.

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 currently in the process of developing a multi-well oilfield project in Kern County, California and a shallow oil project in an existing gas field in Lawrence County, Kentucky.

We have a limited operating history of oil and gas production and minimal proven reserves, production and cash flow.  To date, we have had limited revenues and have not been able to generate sustainable positive earnings on a Company-wide basis.  Our management cannot provide any assurances that Daybreak will ever operate profitably.  As a result of our limited operating history, we are more susceptible to the numerous business, investment and industry risks that have been described in Item 1A. Risk Factors of our Annual Report on Form 10-K for the fiscal year ended February 28, 2013 and in Part III, Item 1A. Risk Factors of this 10-Q Report.

Kern County, California (East Slopes Project)

The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California.  Drilling targets are porous and permeable sandstone reservoirs which exist at depths of 1,200 feet to 4,500 feet.  Since January 2009, we have participated in the drilling of 25 wells in this project.  During the nine months ended November 30, 2013 we had production from 20 wells including production from seven wells that were drilled and put on production in late May and early June 2013 and two wells that were put on production in November 2013.  We have been the Operator at the East Slopes Project since March 2009.

We currently have production from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations.  The Sunday property has six producing wells, while the Bear property has nine producing wells.  The Black property is the smallest of all currently producing reservoirs, and currently has two producing wells at this property.  The Ball property also has two producing wells while the Dyer Creek property has one producing well.  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.  We are not planning any further major capital investment within the East Slopes Project area during the remainder of the current fiscal year.

Producing Properties

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.  We have a 37.5% working interest with a 26.1% net revenue interest (“NRI”) in the Sunday #1 well.  For both the Sunday #2 and Sunday #3 wells, we have a 33.8% working interest with a 24.3% NRI.  We also have a 33.8% working interest with a 27.1% NRI in the Sunday #4H well.  During May and June 2013, we drilled two additional development wells; the Sunday #5 and Sunday #6 on this property.  We have a 37.5% working interest and a NRI of 30.1% in both of these new wells.  Our average working interest and NRI for the Sunday property in aggregate is 35.6% and 27.0%, respectively.  The Sunday reservoir is estimated to be approximately 35 acres in size with the potential for at least one more development well to be drilled in the future.

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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 have a 37.5% working interest in all wells at the Bear Property.  The Bear #1, Bear #2, Bear #3 and Bear #4 wells have an NRI of 26.1%.  In May and June 2013, we drilled three additional development wells; the Bear #5, Bear #6 and Bear #7 on this property.  We have a NRI of 30.1% in these three wells.  In November 2013, we drilled three additional development wells; the Bear #8, Bear #9 and Bear #10 on this property.  The Bear #10 well was not commercially productive and was subsequently plugged and abandoned.  We have a NRI of 31.7% in the Bear #8 and Bear #9 wells. Our average working interest and NRI for the Bear property in aggregate is 37.5% and 28.7%, respectively.  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.

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 approximately 2,200 feet.  In May 2013, we drilled a development well, the Black #2, on this property.  We have a 37.5% working interest with a 29.8% NRI in all wells on this property.  The Black reservoir is estimated to be approximately 13 acres in size.

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 the 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.  We have completed an upgrade program to this facility including the addition of a second oil storage tank to handle the additional oil production from the wells drilled in 2013.  This will allow us to increase the speed of the well pumps which will in turn increase the fluid production from our existing wells.  We also laid a flow line from the Dyer Creek Processing and Storage Facility to deliver the production from the Ball and Dyer Creek wells to the Sunday facility.  By utilizing the Sunday centralized production facility our average operating costs have been reduced from over $40 per barrel in 2009 to a monthly average of approximately $16 per barrel of oil for the nine months ended November 30, 2013.  With this centralized facility and having 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.  In June 2013, we drilled a development well the Ball #2-11, on this property.  Production on this property is from the Vedder sand at approximately 2,500 feet.  We have a 37.5% working interest with a 31.2% NRI in all wells on this property.  Our 3-D seismic data indicates a reservoir approximately 38 acres in size with the potential for at least two development wells to be drilled in the spring of 2014.  

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.  We have a 37.5% working interest with a 31.2% NRI in all wells on this property.  The Dyer Creek property has the potential for at least one development well in the future.

Dyer Creek Processing and Storage Facility

The Dyer Creek processing and storage facility formerly served the Ball and Dyer Creek properties but its use was discontinued in November 2013.  All production from the Ball and Dyer Creek properties, formerly handled by this facility, is now being handled at the Sunday facility which further reduces our overall oil processing and storage expenses in the East Slopes Project.

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Three Well Drilling Program - Fall 2013

In November 2013, we participated in the drilling of three development wells on our Bear location at the East Slopes Project in Kern County, California.  We successfully drilled and have completed two development wells, the Bear #8 and Bear #9. A third development well on the Bear location, the Bear #10 was not commercially successful.

Exploration Properties

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.  Utilizing the data received from a previously drilled well that was not commercially successful, we expect to drill another exploratory well on this prospect during 2015.  The Bull Run wells will require a pilot steam flood and additional production facilities.  We estimate that the Bull Run prospect is 70 acres in size with a gross recoverable reserve potential of 873,000 barrels of oil.  We have a 37.5% working interest in this prospect.

Glide-Kendall Prospect

This prospect is 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 estimate that the Glide Kendall prospect is 200 acres in size with a gross recoverable reserve potential of 1.8 million barrels of oil.  We have a 37.5% working interest in this prospect.

Sherman Prospect

This prospect is also 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 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 37.5% 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 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 37.5% working interest in this prospect.

Lawrence County, Kentucky (Twin Bottoms Field)

The Twin Bottoms Field, comprising approximately 6,400 acres in two large contiguous blocks, is located in the Appalachian Basin of eastern Kentucky.  Log data from existing vertical gas wells in the field indicate the existence of proved oil reserves in the Berea Oil Sand, located at approximately 2,000 feet.  The lateral leg of each well will be between 2,000 feet and 4,500 feet in length.  We have an average 25% working interest and an average NRI of 21.9% in all horizontal wells in this project.  We are not the Operator of the Twin Bottoms Field project, but we rely on the experience of the current Operator and their knowledge of this Field.  Oil reserves are expected to have an estimated ultimate recovery of 50,000 barrels of oil per well.

Gerald Grove Property

The first well, the Grove H-1 was completed in September and put on production in mid-October. The well was drilled to a measured depth of 4,036 feet and a vertical depth of 1,171 feet.  Logs and other measurement data indicate the horizontal section of the well encountered approximately 2,588 feet of oil-bearing sandstone.  Our second well, the Grove H-3 well was completed in October and put on production in December 2013.  The Grove H-3 was drilled to a measured depth of 4,461 feet and a vertical depth of 1,175 feet.  Logs and other measurement data indicate the horizontal section of the well encountered approximately 3,017 feet of oil-bearing sandstone.  Our fourth and fifth wells, the Grove H-4 and Grove H-5 were drilled in December 2013 and are expected to be put on production sometime in January 2014.

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Dwight Dillon Property

Our third well, the Dillon H-6 well was drilled in October and is expected to be put on production in January 2014.  The Dillon H-6 was drilled to a measured depth of 5,100 feet and a vertical depth of 1,442 feet.  Logs and other measurement data indicate the horizontal section of the well encountered approximately 3,546 feet of oil-bearing sandstone.

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement entered into by and among Maximilian Investors LLC, a Delaware limited liability company, as lender, and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and a mortgage on our leases in Kern County, California encompassing the Sunday, Bear, Black, Ball and Dyer Creek properties.  For further information on the loan agreement refer to the discussion under the caption “Long-Term Borrowings” in this MD&A.

Results of Operations – Three Months Ended November 30, 2013 compared to the Three Months Ended November 30, 2012

Revenues.  Monthly revenues are derived entirely from the sale of our share of oil and gas production.  We realized the first revenue from our producing oil wells in California during February 2009 and the first revenue from the Kentucky oil and gas sales during October 2013.  The price we receive for oil sales in both California and Kentucky is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma contracts, less deductions that vary by grade of crude oil sold.  The price we receive for gas in Kentucky is based on the TCO Appalachia index in southwest Pennsylvania.  Oil and gas revenues for California and Kentucky for the three months ended November 30, 2013 and November 30 2012 are set forth in the table below:

	Three Months Ended November 30, 2013		Three Months Ended November 30, 2012
California - East Slopes (Oil only)	$	339,800	$	229,913
Kentucky – Twin Bottoms (Oil)		83,601		-
Kentucky – Twin Bottoms (Gas)		1,635		-
	$	425,035	$	229,913

California Oil Sales

Historically, the sale price we receive for California heavy oil has been less than the quoted WTI price.  However, from March of 2011 through May 31, 2013 we received a premium for our California oil in comparison to the WTI price.  For the three months ended November 30, 2013, the average monthly WTI price was $100.22 and the average monthly sale price we received was $93.57, resulting in a discount of $6.65 per barrel or 6.6% lower than the average monthly WTI price.  This compares to the three months ended November 30, 2012 when the average monthly WTI price was $90.18 and the average monthly sale price was $96.28, resulting in a premium that was $6.10 per barrel or 6.3% higher than the average monthly WTI pricing.  We are unable to forecast if we will again receive a premium for our oil in comparison to the WTI price as there are many factors beyond our control that dictate the price we receive for our oil.

Revenues for the three months ended November 30, 2013 increased $109,887 or 47.8% to $339,800 in comparison to revenue of $229.913 for the three months ended November 30, 2012.  The average monthly sale price of a barrel of oil for the three months ended November 30, 2013 was $93.57 in comparison to $96.28 for the three months ended November 30, 2012.  The decrease of $2.71 or 2.81% in the average monthly sale price of a barrel of oil was offset by the overall increase in sales volume.

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Production for the three months ended November 30, 2013 was from 20 wells resulting in 1,554 well days of production in comparison to 969 well days for the three months ended November 30, 2012.  We had 572 well days of production from the nine new development wells that were put on production in calendar year 2013.  Our net sales volume for the three months ended November 30, 2013 was 3,632 barrels of oil in comparison to 2,388 barrels for the three months ended November 30, 2012.  This increase in oil sales of 1,244 barrels or 52.1% was due to the nine new development wells.  Sales volume from the 11 wells that were producing in the comparative period was 1,902 barrels a decrease of 486 barrels from 2,388 for the three months ended November 30, 2012.  The decrease was due to the natural production decline in our oil wells.  A recently completed upgrade of our Sunday Central Processing Facility has allowed us to increase the speed of our individual well pumps; thereby increasing our current oil production which will more than offset the decline experienced in the three months ended November 30, 2013.  The increase in sales volume in aggregate accounted for all of the revenue increase for the three months ended November 30, 2013.

Kentucky Oil and Gas Sales

The Operator of the Twin Bottoms Field in Kentucky has negotiated an oil sales contract through November 2014, whereby we will be paid $3.00 over the spot WTI price per barrel on all oil sales less customary deductions for transportation.  The sales price we receive for gas per Mcf (Thousand Cubic Feet) is based on the Columbia Gas Transmission Corp. Appalachian Index (TCO Appalachia) whereby we will receive 76% of the Appalachian Index price per dekatherm less $0.25 compression cost for each Mcf of gas delivered.

Our first oil sales in Kentucky occurred on October 19, 2013.  The average monthly sale price of a barrel of oil for the three months ended November 30, 2013 was $94.65.  Production for the three months ended November 30, 2013 was from one well the Grove H-1.  Production from this well was very intermittent throughout October and November due to storage capacity issues.  Our net sales volume for the three months ended November 30, 2013 was 917 barrels of oil.

Operating Expenses.  Total operating expenses for the three months ended November 30, 2013 decreased by $100,509 or 16.7% to $499,586, compared to $600,095 for the three months ended November 30, 2012.

Operating expenses for the three months ended November 30, 2013 and November 30, 2012 are set forth in the table below:

	Three Months Ended November 30, 2013		Three Months Ended November 30, 2012
Production expenses	$	44,697	$	38,223
Exploration and drilling		10,991		3,455
Depreciation, Depletion, Amortization, and Impairment (“DD&A”)		56,922		53,424
Bad debt expense		-		239,000
Write down on facility abandonment		39,254		-
General and Administrative  (“G&A”)		347,722		265,993
	$	499,586	$	600,095

Production expenses include expenses associated with the generation of oil and gas revenues, road maintenance, control of well insurance, property taxes and well workover costs.  These expenses generally relate directly to the number of wells that are in production.  For the three months ended November 30, 2013, these expenses increased by $6,474 or 16.9% in comparison to the three months ended November 30, 2012.  This increase in production expenses is primarily due to the addition of nine new development wells during the current calendar year.  Production expenses represented 8.9% of total operating expenses.  Production expenses in California and Kentucky for the three months ended November 30, 2013 and November 30, 2012 are set forth in the table below:

	Three Months Ended November 30, 2013		Three Months Ended November 30, 2012
California - East Slopes	$	43,890	$	38,223
Kentucky – Twin Bottoms		807		-
	$	44,697	$	38,223

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses increased $7,536 for the three months ended November 30, 2013 in comparison to the three months ended November 30, 2012, primarily due to the timing of leasing activities.  Exploration and drilling expenses represented 2.2% of total operating expenses.

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DD&A expenses relate to equipment, proven reserves and property costs, along with impairment and is another component of operating expenses.  For the three months ended November 30, 2013, DD&A expenses increased $3,498 or 6.5% due to production from the Grove H-1 well in Kentucky in comparison to the three months ended November 30, 2012.  DD&A expenses represented 11.4% of total operating expenses.

During the three months ended November 30, 2013, we discontinued the use of the Dyer Creek production facility and are now processing all of our oil production at the Sunday production facility. After recognizing the three month depreciation on the Dyer Creek facility the remaining book balance was written down from the abandonment of the Dyer Creek facility. The abandonment represented 7.9% of our operating expenses for the three months ended November 30, 2013.

G&A expenses include the salaries of six full-time and two part-time employees, including management.  Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as for running a public company.  For the three months ended November 30, 2013, these expenses increased $81,729 to $347,722 in comparison to $265,993 for the three months ended November 30, 2012.  Management and employee salaries, director fees and stock compensation were relatively unchanged for the three months ended November 30, 2013 in comparison to the three months ended November 30, 2012.  Advertising, marketing and press release expense increased by $8,608 for the three months ended November 30, 2013, primarily due to public announcements relating to the new development wells being brought into production in California and the drilling results in Kentucky.  Travel expenses increased by $10,079 because of drilling activities during the three months ended November 30, 2013.  For the three months ended November 30, 2013, we received, as Operator, administrative overhead reimbursement of $22,692 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 expenses represented 69.6% of total operating expenses for the three months ended November 30, 2013.

Interest income for the three months ended November 30, 2013 increased $135,501 in comparison to the three months ended November 30, 2012 primarily due to interest income earned on the Note receivable from App Energy. For further discussion on this Note refer to the App Loan Agreement under Long-term Financing section in this MD&A.

Interest expense for the three months ended November 30, 2013 increased $381,869 in comparison to the three months ended November 30, 2012.  The increase in interest expense was primarily due to higher balances on our credit facility due to advances made to fund the eleven well drilling program in California and our drilling activities and loan activities in Kentucky.  This financing transaction is further discussed in the MD&A section of this 10-Q report under the caption “Long-Term Borrowings – Maximilian Loan.”

Results of Operations – Nine Months Ended November 30, 2013 compared to the Nine Months Ended November 30, 2012

Revenues.  For the nine months ended November 30, 2013, the average monthly WTI price was $98.57 and the average monthly sale price we received was $96.63, resulting in a discount of $1.94 per barrel or 2.0% lower than the average monthly WTI price.  This compares to the nine months ended November 30, 2012 when the average monthly WTI price was $93.22 and the average monthly sale price we received was $99.00, resulting in a premium of $5.78 per barrel or 6.2% higher than the average monthly WTI pricing.  We are unable to forecast if we will again receive a premium for our oil in comparison to the WTI price as there are many factors beyond our control that dictate the price we receive for our oil.  Oil and gas revenues in California and Kentucky for the nine months ended November 30, 2013 and November 30, 2012 are set forth in the table below:

	Nine Months Ended November 30, 2013		Nine Months Ended November 30, 2012
California - East Slopes (Oil only)	$	1,046,611	$	742,034
Kentucky – Twin Bottoms (Oil)		83,601		-
Kentucky – Twin Bottoms (Gas)		1,635		-
	$	1,131,847	$	742,034

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California Oil Sales

Revenues for the nine months ended November 30, 2013 increased $304,577 or 41.0% to $1,046,611 in comparison to revenue of $742,034 for the nine months ended November 30, 2012.  The average monthly sale price of a barrel of oil for the nine months ended November 30, 2013 was $96.63 in comparison to $99.00 for the nine months ended November 30, 2012.  The decrease of $2.38 per barrel or 2.4% in the average monthly sale price of a barrel of oil was offset by the increase in oil sales volume.

Production for the nine months ended November 30, 2013 was from 20 wells resulting in 4,180 well days of production in comparison to 2,876 well days for the nine months ended November 30, 2012.  We had 1,184 well days of production from the nine new development wells that were put on production during calendar year 2013.  Our net sales volume for the nine months ended November 30, 2013 was 10,831 barrels of oil in comparison to 7,495 barrels for the nine months ended November 30, 2012.  This increase in oil sales of 3,336 barrels or 44.5% was due to the nine new development wells.  Sales volume from the 11 wells that were producing in the comparative period was 6,628 barrels a decrease of 867 barrels from 7,495 barrels for the nine months ended November 30, 2012.  The decrease was due to the natural production decline in our oil wells. The increase sales volume in aggregate accounted for all of the revenue increase for the nine months ended November 30, 2013.

Kentucky Oil and Gas Sales

The Operator of the Twin Bottoms Field in Kentucky has negotiated an oil sales contract through November 2014, whereby we will be paid $3.00 over the spot WTI price per barrel on all oil sales less customary deductions for transportation.  The sales price we receive for gas per Mcf (Thousand Cubic Feet) is based on the Columbia Gas Transmission Corp. Appalachian Index (TCO Appalachia) whereby we will receive 76% of the Appalachian Index price per dekatherm less $0.25 compression cost for each Mcf of gas delivered.

Our first oil sales in Kentucky occurred on October 19, 2013.  The average monthly sale price of a barrel of oil for the nine months ended November 30, 2013 was $94.65.  Production for the nine months ended November 30, 2013 was from one well, the Grove H-1. Production from this well was very intermittent throughout October and November due to storage capacity issues.  Our net sales volume for the quarter ended November 30, 2013 was 917 barrels of oil.

Operating Expenses.  Total operating expenses for the nine months ended November 30, 2013 increased by $217,438 or 15.2% to $1,650,826, compared to $1,433,388 for the nine months ended November 30, 2012.

Operating expenses for the nine months ended November 30, 2013 and November 30, 2012 are set forth in the table below:

	Nine Months Ended November 30, 2013		Nine Months Ended November 30, 2012
Production expenses	$	160,652	$	81,855
Exploration and drilling		245,685		40,005
DD&A		261,641		172,544
Bad debt expense		-		239,000
Write down on facility abandonment		39,254		-
G&A		943,594		899,984
Total operating expenses	$	1,650,826	$	1,433,388

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Production expenses include expenses associated with the generation of oil and gas revenues, road maintenance, control of well insurance, property taxes and well workover costs.  These expenses generally relate directly to the number of wells that are in production.  For the nine months ended November 30, 2013, these expenses increased by $78,797 in comparison to the nine months ended November 30, 2012.  This increase in production expenses is primarily due to the addition of nine new development wells and the replacement of a downhole pump in one of our existing wells. Production expenses represented 9.7% of total operating expenses.  Production expenses for California and Kentucky for the nine months ended November 30, 2013 and November 30 2012 are set forth in the table below:

	Nine Months Ended November 30, 2013		Nine Months Ended November 30, 2012
California - East Slopes	$	159,845	$	81,855
Kentucky – Twin Bottoms		807		-
	$	160,652	$	81,855

Exploration and drilling expenses include G&G expenses as well as leasehold maintenance and dry hole expenses.  These expenses increased $205,680 for the nine months ended November 30, 2013 in comparison to $40,005 for the nine months ended November 30, 2012.  Drilling expenses increased to $212,256 due to dry hole expense from the Chimney #1-1 well in June 2013.  Exploration and drilling expenses represented 14.9% of total operating expenses.

DD&A expenses relate to equipment, proven reserves and property costs, along with impairment, and is another component of operating expenses.  For the nine months ended November 30, 2013, DD&A expenses increased $89,097 in comparison to $172,544 for the nine months ended November 30, 2012 primarily due to the $84,929 impairment of unproved properties on the Chimney leasehold.  DD&A expenses represented 15.8% of total operating expenses.

During the nine months ended November 30, 2013, we discontinued the use of the Dyer Creek production facility and are now processing all of our oil production at the Sunday production facility.  After recognizing the nine month depreciation on the Dyer Creek facility the remaining book balance was written down from the abandonment of the Dyer Creek facility.  The abandonment represented 2.4% of our operating expenses for the nine months ended November 30, 2013.

G&A expenses include the salaries of six full-time and two part-time employees, including management.  Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as for running a public company.  For the nine months ended November 30, 2013, these expenses increased $43,610 or 4.8% to $943,594 in comparison to $899,984 for the nine months ended November 30, 2012.  Management and employee salaries, director fees and stock compensation were relatively unchanged for the nine months ended November 30, 2013 in comparison to the nine months ended November 30, 2012.  Advertising, marketing and press release expense increased by $33,055 for the nine months ended November 30, 2013, primarily due to the nine new development wells being brought into production and drilling in Kentucky.  Travel expenses increased by $12,127 because of drilling activities during the nine months ended November 30, 2013.   For the nine months ended November 30, 2013, we received, as Operator, administrative overhead reimbursement of $75,849 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 expenses represented 57.2% of total operating expenses for the nine months ended November 30, 2013.

Interest income for the nine months ended November 30, 2013 increased $135,388 in comparison to the nine months ended November 30, 2012 primarily due to interest income earned on the Note receivable from App Energy.  For further discussion on this Note refer to the App Loan Agreement under Long-term Financing section in this MD&A.

Interest expense for the nine months ended November 30, 2013 increased $624,815 in comparison to the nine months ended November 30, 2012.  The increase in interest expense was due to higher balances on our credit facility due to advances made to fund the eleven well drilling program in California and our drilling activities and loan activities in Kentucky.  This financing transaction is further discussed in the MD&A section of this 10-Q report under the caption “Long-Term Borrowings – Maximilian Loan.”

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Due to the nature of our business, 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 expenses and revenues will fluctuate according to the number and percentage ownership of producing wells as well as the amount of revenues we receive based on the price of oil.  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 will depend upon the factors cited above including the size of our proven reserves base and the market price of energy products.  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.  An ongoing goal of the Company is to improve cash flow to cover the current level of G&A expenses and to fund our development drilling programs in California and Kentucky.

Capital Resources and Liquidity

Our primary financial resource is our proven oil reserves base.  Our ability to fund any future capital expenditure programs is dependent upon the prices we receive from oil sales, the success of our exploration and development program in Kern County, California and Lawrence County, Kentucky and the availability of capital resource financing.  We plan to spend approximately $400,000 in the current fiscal year in new capital investments; however our actual expenditures may vary significantly from this estimate if our plans for exploration and development activities change during the year.  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.

Changes in our capital resources at November 30, 2013 in comparison with February 28, 2013 are set forth in the table below:

					Increase		Percentage
	November 30, 2013		February 28, 2013		(Decrease)		Change
Cash	$	194,690	$	79,996	$	114,694	143.4%
Current Assets	$	2,141,485	$	376,274	$	1,765,211	469.1%
Total Assets	$	9,505,922	$	2,619,854	$	6,886,068	262.8%
Current Liabilities	$	6,601,195	$	4,152,656	$	2,448,539	59.0%
Total Liabilities	$	12,261,743	$	5,981,245	$	6,280,498	105.0%
Working Capital	$	(4,459,710)	$	(3,776,382)	$	(683,328)	(18.1)%

Our working capital deficit increased $683,328 or 18.1% to $4,459,710 at November 30, 2013 in comparison to $3,776,382 at February 28, 2013.  This increase in the working capital deficit was primarily due to expenses incurred during our eleven well drilling program and financing activities associated with our credit facility.  While we have ongoing positive cash flow from our operations in California and Kentucky we have not yet been able to generate sufficient cash flow to cover all of our G&A and interest expense requirements.  We anticipate an increase in our cash flow from our operations in Kern County, California and Lawrence County, Kentucky during the current fiscal year.

Our business is capital intensive.  Our ability to grow is dependent upon favorably obtaining outside capital and generating cash flows from operating activities necessary to fund our investment activities.  There is no assurance that we will be able to achieve profitability.  Since our future operations will continue to be dependent on successful exploration and development activities and our ability to seek and secure capital from external sources, should we be unable to achieve sustainable profitability this could cause any equity investment in the Company to become worthless.

Major sources of funds in the past for us have included the debt or equity markets.  While we have achieved positive cash flow from operations in California and Kentucky, we will have to rely on these capital markets to fund future operations and growth.  Our business model is focused on acquiring exploration or development properties as well as existing production.  Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of oil and gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources.

Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company.  The current uncertainty in the credit and capital markets, and the economic downturn, may restrict our ability to obtain needed capital.

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The Company’s financial statements for the nine months ended November 30, 2013 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 entering the oil and gas exploration industry and as of nine months ended November 30, 2013 have an accumulated deficit of $27,403,765 and a working capital deficit of $4,459,710 which raises substantial doubt about our ability to continue as a going concern.

In the current fiscal year, we will continue to seek additional financing for our planned exploration and development activities in both California and Kentucky.  We plan to obtain 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.  No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all.  Sales of interests in our assets may be another source of cash flow.

Cash Flows

Changes in the net funds provided by and (used in) our operating, investing and financing activities are set forth in the table below:

	Nine Months November 30, 2013		Nine Months November 30, 2012		Increase (Decrease)	Percentage Change
Net cash (used in) provided by operating activities	$	(1,081,440)	$	155,450	(1,236,890)	(795.7)%
Net cash (used in) investing activities	$	(3,931,295)	$	(182,142)	(3,749,153)	2,058.4%
Net cash provided by (used in) financing activities	$	5,127,429	$	(46,700)	5,174,129	(11,079.5)%

Cash Flow (Used In) 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 non-cash accounts, receivables, payables or other non-energy property asset account balances.  For the nine months ended November 30, 2013, we had a cash flow deficit from operating activities of $1,081,440 in comparison to a positive cash flow of $155,450 for the nine months ended November 30, 2012.  This decrease of $1,236,890 was due to changes in non-cash account balances related to DD&A of $128,351; amortization of warrants, debt discount and deferred financing costs of $94,642. In the prior comparative period there were additional changes in our non-cash account balances of $1,019,938 that were not present for the nine months ended November 30, 2013. Changes in our receivables and payables balances of $894,149 related to our drilling activities in Kern County, California and Lawrence County, Kentucky for the nine months ended November 30, 2013 in comparison to the nine months ended November 30, 2012.  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 balances and our lending activities associated with the App Energy loan. Cash used in investing activities for the nine months ended November 30, 2013 was $3,931,295, an increase of $3,749,153 from the $182,142 used in investing activities for the nine months ended November 30, 2012.  This increase was due to two drilling programs that were undertaken in the nine months ended November 30, 2013 and advances made for drilling in Kentucky on a shallow oil project as well as $2.85 million in advances to App Energy.  Refer to Note 9 – Note Receivable for further discussion of the App Energy loan.

Cash Flow Provided by Financing Activities

Cash flow from financing activities is derived from changes in long-term liability account balances or in equity account balances, excluding retained earnings.  Cash provided by our financing activities was approximately $5.13 million for the nine months ended November 30, 2013 in comparison to cash used in our financing activities of $46,700 for the nine months ended November 30, 2012.  We received advances on our loan commitment for drilling activities in California and Kentucky of approximately $3.15 million in aggregate offset by payments on our credit line, note payable and deferred financing fees.  

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Short-Term Borrowings

Related Party

During the years ended February 29, 2012 and February 28, 2013, the Company’s President and Chief Executive Officer loaned the Company $250,100 in aggregate that has been used for a variety of corporate purposes including an escrow requirement on a loan commitment; extension fees on third party loans; and, a reduction of principal on the Company’s credit line with UBS Bank.  These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.

Line of Credit

During the year ended February 29, 2012, the Company entered into an $890,000 credit line for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer.  At November 30, 2013, the Line of Credit had an outstanding balance of $883,384.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $23,927 for the nine months ended November 30, 2013.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

Long-Term Borrowings

12% Subordinated Notes

The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a March 2010 private placement, resulted in $595,000 in gross proceeds to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th.  The note principal is payable in full at the maturity of the Notes, which is January 29, 2015.  In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement.  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 nine months ended November 30, 2013 amounted to $19,858.  Unamortized debt discount amounted to $37,290 as of November 30, 2013.

Maximilian Loan

On October 31, 2012, the Company entered into a loan agreement with Maximilian Investors LLC (“Maximilian”, or “Lender”) which provided for a revolving credit facility of up to $20 million, maturing on October 31, 2016, with a minimum commitment of $2.5 million.  The loan had annual interest of 18% and a monthly commitment fee of 0.5%.  The Company also granted Maximilian a 10% working interest in its share of the oil and gas leases in Kern County, California. The relative fair value of this 10% working interest amounting to $515,638 was recognized as a debt discount and is being amortized over the term of the loan. Amortization expense for the nine months ended November 30, 2013 amounted to $97,964.  Unamortized debt discount amounted to $377,053 as of November 30, 2013.

The Company also issued in 2012, 2,435,517 warrants to third parties who assisted in the closing of the loan.  The warrants have an exercise price of $0.044; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on October 31, 2017.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $98,084 and included the following assumptions: a risk free interest rate of 0.72%; stock price of $0.04, volatility of 153.44%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the loan.

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Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App, the Company amended its loan agreement with Maximilian on August 28, 2013. The amended loan agreement provided for an increase in the revolving credit facility from $20 million to $90 million and a reduction in the annual interest rate from 18% to 12%.   The monthly commitment fee of 0.5% per month on the outstanding principal balance remained unchanged.  Advances under the amended loan agreement will mature on August 28, 2017.  The obligations under the amended loan agreement continue to be secured by a perfected first priority security interest in substantially all of the personal property of the Company, including the Company’s leases in Kern County, California.  The amended loan agreement also provided for the revolving credit facility to be divided into two borrowing sublimits.  The first borrowing sublimit is $50 million and is for borrowing by the Company, primarily for its ongoing oil and gas exploration and development activities.  The second borrowing sublimit, of $40 million, is for loans to be extended by the Company, as lender, to App, as borrower pursuant to a Loan and Security Agreement entered into between the Company and App on August 28, 2013 (See Note 9 – Long-term Note Receivable).

The amended loan agreement contains customary covenants for loan of such type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The amended loan agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of the Company’s obligations under the amended loan agreement could be accelerated by the Lender, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

As consideration for Maximilian facilitating the Company’s transactions with App and entering into the amended loan agreement, the Company (a) issued to Maximilian approximately 6.1 million common shares, representing 9.99% of the Company’s outstanding common stock on a fully-diluted basis at the time of grant, and (b) issued approximately 6.1 million warrants to purchase shares of the Company’s common stock representing the right to purchase up to an additional 9.99% of the Company’s outstanding common stock on a fully-diluted basis, calculated as of the date of grant.  The warrants have an exercise price of $0.10; contain a cash exercise provision and are exercisable for a period of three years expiring on August 28, 2016.  The Company also granted to the Lender a 50% net profits interest in the Company’s 25% working interest, after the Company recovers its investment, in the Company’s working interest in the Kentucky Acreage, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.

The fair value of the 6.1 million shares was determined to be $979,608 based on the Company’s stock price on the grant date of $0.16.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $898,299 and included the following assumptions: a risk free interest rate of 2.48%; stock price of $0.16, volatility of 184.53%; and a dividend yield of 0.0%.   The Company determined that the common shares and warrants were issued in connection with the increase in Company’s borrowing limit and App’s $40 million revolving credit facility for which the Company was granted a 25% working interest.  Consequently, the fair value of the common shares and warrants totaling to $1,877,907 was allocated to deferred financing costs ($804,816) and unproved oil and gas properties ($1,073,091) based on the amount of the increase in the revolving credit facility that is attributable to Daybreak and App.

The Company also issued 309,503 warrants to third parties who assisted in the closing of the amended and restated loan agreement.  The warrants have an exercise price of $0.214; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on August 28, 2018.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $47,420 and included the following assumptions: a risk free interest rate of 2.48%; stock price of $0.16, volatility of 184.53%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the revolving credit facility.

The Company evaluated the amendment of the revolving credit facility under ASC 470-50-40 and determined that the Company’s borrowing capacity under the amended loan agreement exceeded its borrowing capacity under the old loan agreement.  Consequently, the unamortized discount and deferred financing costs as of the date of amendment of approximately $400,349 and the new deferred financing costs, as mentioned above, were amortized over the term of the amended loan agreement.

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During the nine months ended November 30, 2013 the Company received multiple advances totaling $5,955,200 in aggregate that were used to participate in the Company’s spring and fall 2013 drilling programs at its East Slopes Project in Kern County, California and the drilling at its interest in the Kentucky Acreage and in the extension of the long-term note receivable to App.  The Company has recognized $1,470,045 in deferred financing costs associated with these advances which are being amortized over the amended term of the revolving credit facility.

Current debt balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
Maximilian Note	$	2,228,442	$	246,486
Maximilian Note Discount		(138,177)		(131,009)
	$	2,090,265	$	115,477

Non-current debt balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
Maximilian Note	$	5,254,336	$	1,579,571
Maximilian Note Discount		(238,876)		(344,007)
	$	5,015,460	$	1,235,564

App Loan Agreement

On August 28, 2013, the Company amended its credit facility with Maximilian Investors LLC as a part of a financing transaction in which the Company extended to App Energy, LLC, a Kentucky limited liability company (“App”) a credit facility for the development of a shallow oil project in an existing gas field in Lawrence County, Kentucky.

The App Loan Agreement provides for a revolving credit facility of up to $40 million, maturing on August 28, 2017, with a minimum commitment of $2.65 million (the “Initial Advance”).  All funds advanced to App, as borrower, by Daybreak, as lender, are to be borrowed by Daybreak under its Amended Loan Agreement with the Lender.  The Initial Advance bears interest at a rate per annum equal to 16.8%, and subsequent loans under the Loan Agreement bear interest at a rate per annum equal to 12%.  The App Loan Agreement also provides for a monthly commitment fee of 0.6% per month of the outstanding principal balance of the loans.  The obligations under the App Loan Agreement are secured by a perfected first priority security interest in substantially all of the assets of App, including the Company’s leases in Lawrence County, Kentucky.

The proceeds of the initial borrowing by App of $2.65 million under the App facility were primarily used to (a) pay loan fees and closing costs, (b) repay indebtedness and (c) finance the drilling of three wells by App in the Kentucky Acreage in which the Company has a 25% working interest.  Future advances under the facility will primarily be used for oil and gas exploration and development activities.

The App Loan Agreement contains customary covenants for loan of such type, including, among other things, covenants that restrict App’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The App Loan Agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of App’s obligations under the App Loan Agreement could be accelerated by the Company, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

In connection with the App Loan Agreement, App also granted to the Company the 25% working interest approximately 6,400 acres in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky (the “Kentucky Acreage”), and entered into a corresponding promissory note and a Mortgage, Leasehold Mortgage, Assignment of Production, Security Agreement and Financing Statement, both dated as of August 28, 2013.  App’s manager, John A. Piedmonte, Jr., also entered into a limited Indemnity Agreement in connection with the loan.  The loans under the App Loan Agreement are also guaranteed by certain of App’s affiliates.

At November 30, 2013, the Company had advanced $2,850,000 to App through its credit facility.  The total amount advanced includes fees paid in connection with the loan amounting to $72,000 and settlement of App’s existing obligation to another lender of $200,386 which were paid directly by Maximilian Investors LLC and $317,816 of interest withheld by Daybreak which is reported as deferred interest in the balance sheets.

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Note receivable balances at November 30, 2013 and February 28, 2013 are set forth in the table below:

	November 30, 2013		February 28, 2013
Note receivable – current	$	1,196,122	$	-
Note receivable – non-current		1,653,878		-
	$	2,850,000	$	-

Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company.  The current uncertainty in the credit and capital markets, and the economic downturn, may restrict our ability to obtain needed capital.

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement entered into by and among Maximilian Investors LLC, a Delaware limited liability company, as lender, and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and a mortgage on our leases in Kern County, California.  This includes mortgages on the Sunday, Bear, Black, Ball and Dyer Creek Properties in California.  For further information on the loan agreement refer to the discussion under the caption “Long-Term Borrowings” in this MD&A.

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.

At November 30, 2013, a total of 2,882,010 shares of restricted stock had been awarded and remained outstanding under the 2009 Plan, and 2,893,750 of the shares had fully vested.  A total of 1,011,740 Common Stock shares remained available at November 30, 2013 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(1)		Shares Returned(2)		Shares Outstanding (Unvested)
4/7/2009	1,900,000	3 Years	1,900,000		-		-
7/16/2009	25,000	3 Years	25,000		-		-
7/16/2009	625,000	4 Years	619,130		5,870		-
7/22/2010	25,000	3 Years	25,000		-		-
7/22/2010	425,000	4 Years	312,880		5,870		106,250
	3,000,000		2,882,010	(1)	11,740	(2)	106,250

⁽¹⁾

Does not include shares that were withheld to satisfy such tax liability upon vesting of a restricted award by a Plan Participant, and subsequently returned to the 2009 Plan.

⁽²⁾

Reflects the number of common shares that were withheld pursuant to the settlement of the number of shares with a fair market value equal to such tax withholding liability, to satisfy such tax liability upon vesting of a restricted award by a Plan Participant.

For the nine months ended November 30, 2013, the Company recognized compensation expense related to the above restricted stock grants in the amount of $10,546.  Unamortized compensation expense amounted to $4,395 as of November 30, 2013.  For the nine months ended November 30, 2013, there were 4,080 shares of the Company’s Common Stock relating to the 2009 Plan returned to the 2009 Plan to satisfy an employee’s payroll tax liability upon the vesting of shares.

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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 20 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.  The Company’s average working interest in these wells is 36.8% and the average net revenue interest is 28.4%.  During the current year, the Company has successfully drilled nine additional development wells at its Sunday, Bear, Black and Ball locations.

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.

Additionally, the Company has become involved in a shallow oil play in an existing gas field in Lawrence County, Kentucky, through its acquisition of a 25% working interest in approximately 6,400 acres in two large contiguous acreage blocks in the Twin Bottoms Field in Lawrence County, Kentucky (the “Kentucky Acreage”).  The initial drilling program involved drilling five horizontal wells of which all have been completed and are either producing or will be producing by the end of January 2014.  The Company received its first Kentucky oil revenue from October production in November.

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company has experienced revenue growth from its oil properties, it has not yet established a positive cash flow on a company-wide basis.  It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future.  However the Company cannot offer any assurance that the Company will be successful in executing the aforementioned plans to continue as a going concern.

Critical Accounting Policies

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2013.

Off-Balance Sheet Arrangements

As of November 30, 2013, we did not have any off-balance sheet arrangements or relationships with unconsolidated entities or financial partners that have been, or are reasonably likely to have, a material effect on our financial position or results of operations.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.  CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

As of the end of the reporting period, November 30, 2013, 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 November 30, 2013.

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the three months ended November 30, 2013 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.

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PART II

OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

None

ITEM 1A.  RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the period ended February 28, 2013, which could materially affect our business, financial condition or future results. The risks described in this report are not the only risks we face.   Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial could have a material adverse effect on our business, financial condition and results of operations.

Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays.

Our Kentucky drilling operations currently use the process of hydraulic fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. For example, the Environmental Protection Agency (“EPA”) has asserted federal regulatory authority over hydraulic fracturing involving fluids that contain diesel fuel under the Safe Drinking Water Act’s Underground Injection Control Program and has released draft permitting guidance for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states where the EPA is the permitting authority, including Kentucky. Such efforts could have an adverse effect on our oil and natural gas production activities.

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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.

101.INS⁽²⁾

XBRL Instance Document

101.SCH⁽²⁾

XBRL Taxonomy Schema

101.CAL⁽²⁾

XBRL Taxonomy Calculation Linkbase

101.DEF⁽²⁾

XBRL Taxonomy Definition Linkbase

101.LAB⁽²⁾

XBRL Taxonomy Label Linkbase

101.PRE⁽²⁾

XBRL Taxonomy Presentation Linkbase

⁽¹⁾

Filed herewith.

⁽²⁾

Furnished herewith

35

SIGNATURES

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

DAYBREAK OIL AND GAS, INC.
By:	/s/ JAMES F. WESTMORELAND
	James F. Westmoreland, its
	President, Chief Executive Officer and interim
	principal finance and accounting officer
	(Principal Executive Officer, Principal Financial
	Officer and Principal Accounting Officer)
Date:  January 14, 2014

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