UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended August 31, 2016

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.)
1101 N. Argonne Road, Suite A 211, Spokane Valley, WA		99212
(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 company þ

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 October 12, 2016 the registrant had 51,487,373 outstanding shares of $0.001 par value common stock.

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TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS	3
	Balance Sheets at August 31, 2016 and February 29, 2016 (Unaudited)	3
	Statements of Operations for the Three and Six Months Ended August 31, 2016 and August 31, 2015 (Unaudited)	4
	Statements of Cash Flows for the Six Months Ended August 31, 2016 and August 31, 2015 (Unaudited)	5
	NOTES TO UNAUDITED FINANCIAL STATEMENTS	6
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	15
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	33
ITEM 4.	CONTROLS AND PROCEDURES	33
	PART II - OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	34
ITEM 1A.	RISK FACTORS	34
ITEM 5.	OTHER INFORMATION	34
ITEM 6.	EXHIBITS	35
Signatures		36

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PART I

FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

DAYBREAK OIL AND GAS, INC.

Balance Sheets – Unaudited

	As of August 31, 2016			As of February 29, 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	23,974		$	6,995
Accounts receivable:
Oil and natural gas sales		106,721			69,192
Joint interest participants		54,105			106,694
Other receivables, net		79,504			71,237
Production revenue receivable – current		-			45,000
Prepaid expenses and other current assets		93,428			114,461
Note receivable – current		-			420,901
Total current assets		357,732			834,480
OIL AND NATURAL GAS PROPERTIES, successful efforts method, net
Proved properties		3,036,488			3,180,002
Unproved properties		595,480			585,826
PREPAID DRILLING COSTS		16,452			18,802
NOTE RECEIVABLE – NON-CURRENT		5,194,307			4,234,612
OTHER ASSETS		106,319			106,282
Total assets	$	9,306,778		$	8,960,004
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	$	1,883,407		$	1,777,236
Accounts payable – related parties		1,111,218			990,483
Accrued interest		216,420			175,283
Notes payable – related party		250,100			250,100
12% Notes payable		315,000			315,000
12% Notes payable – related party		250,000			250,000
Debt, net		15,863,887			13,668,105
Line of credit		830,947			843,807
Total current liabilities		20,720,979			18,270,014
LONG TERM LIABILITIES:
Asset retirement obligation		83,722			79,979
Total liabilities		20,804,701			18,349,993
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; 724,565 and 724,565 shares issued and outstanding, respectively		725			725
Common stock – 200,000,000 shares authorized; $0.001 par value, 51,487,373 shares issued and outstanding		51,487			51,487
Additional paid-in capital		22,968,714			22,968,714
Accumulated deficit		(34,518,849)			(32,410,915)
Total stockholders’ deficit		(11,497,923)			(9,389,989)
Total liabilities and stockholders’ deficit	$	9,306,778		$	8,960,004

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

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DAYBREAK OIL AND GAS, INC.

Statements of Operations – Unaudited

	For the Three Months Ended August 31,						For the Six Months Ended August 31,
	2016			2015			2016			2015
REVENUE:
Oil and natural gas sales	$	223,877		$	369,834		$	437,353		$	811,118
OPERATING EXPENSES:
Production		59,117			70,001			123,176			145,606
Exploration and drilling		126			8,400			7,069			20,067
Depreciation, depletion, and amortization		62,634			118,889			151,910			257,729
General and administrative		227,973			248,855			514,743			534,503
Total operating expenses		349,850			446,145			796,898			957,905
OPERATING LOSS		(125,973)			(76,311)			(359,545)			(146,787)
OTHER INCOME (EXPENSE):
Interest income		270,573			201,851			551,328			424,604
Interest expense		(1,184,020)			(661,604)			(2,299,717)			(1,330,471)
Total other income (expense)		(913,447)			(459,753)			(1,748,389)			(905,867)
NET LOSS		(1,039,420)			(536,064)			(2,107,934)			(1,052,654)
Cumulative convertible preferred stock dividend requirement		(32,871)			(32,872)			(65,743)			(65,896)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(1,072,291)		$	(568,936)		$	(2,173,677)		$	(1,118,550)
NET LOSS PER COMMON SHARE, basic and diluted	$	(0.02)		$	(0.01)		$	(0.04)		$	(0.02)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic and diluted		51,487,373			51,487,373			51,487,373			51,482,273

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

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DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows – Unaudited

	Six Months Ended
	August 31, 2016			August 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(2,107,934)		$	(1,052,654)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, accretion and impairment expense		151,910			257,730
Amortization of debt discount		55,912			68,196
Amortization of deferred financing costs		215,047			212,564
Debt modification fees		775,562			-
Interest income		(37)			(42)
Changes in assets and liabilities:
Accounts receivable - oil and natural gas sales		(37,529)			78,969
Accounts receivable - joint interest participants		52,589			(2,304)
Accounts receivable – other		(502,061)			79,242
Prepaid expenses and other current assets		21,033			(15,007)
Accounts payable and other accrued liabilities		92,874			57,453
Accounts payable - related parties		120,735			42,935
Accrued interest		1,190,398			9,815
Net cash provided by (used in) operating activities		28,499			(263,103)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties		(1,010)			(135,714)
Prepaid drilling costs		2,350			-
Collections of note receivable		-			627,500
Net cash provided by investing activities		1,340			491,786
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on debt		-			(588,431)
Additions to line of credit		17,140			15,468
Payments on line of credit		(30,000)			(30,000)
Net cash used in financing activities		(12,860)			(602,963)
NET DECREASE IN CASH AND CASH EQUIVALENTS		16,979			(374,280)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		6,995			496,772
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	23,974		$	122,492
CASH PAID FOR:
Interest	$	62,922		$	1,039,896
Income taxes	$	-		$	-
SUPPLEMENTAL CASH FLOW INFORMATION:
Unpaid additions to oil and natural gas properties	$	13,297		$	3,880
Increase in note receivable for interest added to principal	$	538,794		$	-
Interest converted to principal on long term debt	$	1,149,261		$	-
ARO asset and liability increase	$	-		$	140
Conversion of preferred stock to common stock	$	-		$	30

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

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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 natural 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 natural 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 natural 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 six months ended August 31, 2016 are not necessarily indicative of the results that may be expected for the fiscal year ending February 28, 2017.

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 29, 2016.

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 natural gas properties to determine the amount of any impairment of oil and natural 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.

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NOTE 2 — GOING CONCERN:

Financial Condition

The Company’s financial statements for the six months ended August 31, 2016 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 natural gas exploration industry and as of August 31, 2016 has an accumulated deficit of $34,518,849 and a working capital deficit of $20,363,247 which raises substantial doubt about the Company’s ability to continue as a going concern.

Management Plans to Continue as a Going Concern

Daybreak currently has a net revenue interest (“NRI”) in 20 producing oil 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 (“WI”) in these wells is 36.6% and the NRI is 28.5% for these same wells.

Additionally, Daybreak currently has a net revenue interest in 14 producing horizontal oil wells in the Twin Bottoms Field located in Lawrence County, Kentucky with associated natural gas production.  The Company’s average WI in these 14 horizontal oil wells is 22.6% and the average NRI is 19.7% in these same wells.

The Company anticipates revenues will increase when it participates in the drilling of more wells in the Twin Bottoms Field in Kentucky and the East Slopes Project in California.  Given the current decline and instability in hydrocarbon prices, the timing of any drilling activity in Kentucky and California will be dependent on a sustained improvement in hydrocarbon prices and a successful refinancing or restructuring of the Company’s credit facility.  Even during this period of lower hydrocarbon prices, the Company continues to experience positive cash flow from its oil and natural gas properties, however this cash flow hasn’t been sufficient to cover all of the Company’s general and administrative expenses as well as principal and interest payments on its credit facility.  The Company has not made any principal or interest payments on its credit facility since December 2015.

Daybreak believes that its liquidity will improve when there is a sustained improvement in hydrocarbon prices.  The Company’s sources of funds in the past have included the debt or equity markets.  It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future, or through the sale of all or part of its working interest in its properties.  However, the Company cannot offer any assurance that it will be successful in executing the aforementioned plans to continue as a going concern.

Daybreak’s financial statements as of August 31, 2016 do not include any adjustments that might result from the inability to implement or execute the Company’s plans to improve its ability to continue as a going concern.

NOTE 3 — RECENT ACCOUNTING PRONOUNCEMENTS:

Accounting Standards Issued and Adopted

In April 2015, the FASB issued ASU 2015-03 “Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03).  ASU 2015-03 simplifies the presentation of debt issuance costs by requiring such costs be presented as a deduction from the corresponding debt liability.  The standards are effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, and require retrospective presentation.  Early adoption is permitted.  These standards have been adopted for the periods presented.  Accordingly, $0.4 million and $0.6 million of debt issuance costs as of August 31, 2016 and February 29, 2016, respectively, are now reflected as a direct reduction of debt in our Balance Sheets.

NOTE 4 — CONCENTRATION OF CREDIT RISK:

Substantially all of the Company’s trade accounts receivable result from crude oil and natural 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 including lower oil prices as well as other related factors.  Trade accounts receivable are generally not collateralized.

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At the Company’s Twin Bottoms Field project located in Lawrence County, Kentucky, there is only one buyer available for the purchase of its crude oil production and only two buyers available for the purchase of its natural gas production.  At the Company’s East Slopes project in California there is only one buyer available for the purchase of all crude oil production.  The Company has no natural gas production in California.  At August 31, 2016 and February 29, 2016 these four individual customers represented 100.0% of crude oil and natural gas 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 natural gas production.

The Company’s accounts receivable from Kentucky and California oil and natural gas sales at August 31, 2016 and February 29, 2016 are set forth in the table below.

				August 31, 2016					February 29, 2016
Project		Customer		Revenue Receivable			Percentage		Revenue Receivable			Percentage
Kentucky – Twin Bottoms Field (Oil)		Appalachian Oil		$	26,296		24.6%		$	23,257		33.6%
Kentucky – Twin Bottoms Field (Gas)		Two Vendors			6,058		5.7%			6,767		9.8%
California – East Slopes Project (Oil)		Plains Marketing			74,367		69.7%			39,168		56.6%
				$	106,721		100.0%		$	69,192		100.0%

Crude oil sales receivables balances of $100,663 and $62,425 at August 31, 2016 and February 29, 2016 represent crude oil sales that occurred in August and February 2016, respectively.  The natural gas sales receivable balances of $6,058 and $6,767 represent natural gas sales that occurred during the months of July/August 2016 and January/February 2016, respectively.

Joint interest participant receivables balances of $54,105 and $106,694 at August 31, 2016 and February 29, 2016, respectively represent amounts due from working interest partners in California, where the Company is the Operator.  There were no allowances for doubtful accounts for the Company’s trade accounts receivable at August 31, 2016 and February 29, 2016 as the joint interest owners have a history of paying their obligations.

Other receivables balances primarily include amounts of monthly interest receivable on the loan to App Energy, LLC, a Kentucky limited liability company (“App Energy”).  For additional information on the App Energy loan refer to the discussion in Note 6 – Note Receivable.

NOTE 5 — OIL AND NATURAL GAS PROPERTIES:

Oil and natural gas property balances at August 31, 2016 and February 29, 2016 are set forth in the table below.

	August 31, 2016			February 29, 2016
Proved leasehold costs	$	659,786		$	654,445
Unproved leasehold costs		595,480			585,826
Costs of wells and development		4,538,667			604,684
Capitalized exploratory well costs		1,505,034			5,461,677
Capitalized asset retirement costs		50,873			28,901
Total cost of oil and gas properties		7,349,840			7,335,533
Accumulated depletion, depreciation, amortization and impairment		(3,717,872)			(3,569,705)
Net Oil and Gas Properties	$	3,631,968		$	3,765,828

NOTE 6 — NOTE RECEIVABLE:

At August 31, 2016, the Company had advanced approximately $8.3 million to App Energy through its credit facility.  Note receivable balances at August 31, 2016 and February 29, 2016 are set forth in the table below:

	August 31, 2016			February 29, 2016
Note receivable – current	$	-		$	420,901
Note receivable – non-current		5,194,307			4,234,612
	$	5,194,307		$	4,655,513

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Due to a decline in crude oil and natural gas revenues primarily caused by lower hydrocarbon prices, App Energy has been unable to make the interest or principal payments required under the terms of the credit facility with the Company.  Because of the uncertainty of App Energy’s ability to make principal payments, the entire balance of the note receivable is presented under the Non-Current Asset section of the Balance Sheet at August 31, 2016.  Unpaid monthly interest and fees have been added to the principal balance of the loan.  During the six months ended August 31, 2016, in aggregate $569,444 of interest and fees has been added to the outstanding loan balance.

A series of waivers have been granted by the Company to App Energy for the principal and interest payments that have not made since November 2015.  Due to the waivers granted by the Company, App Energy is currently not considered to be in default under terms of the credit facility.  The Company is continuing to work with App Energy in modifying the credit facility terms during this period of lower hydrocarbon prices.  An allowance for this receivable has not been created since the collateral of the App Energy oil and natural gas interest and its fair value exceed the note receivable balance.

NOTE 7 — 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 partners’ default liability of approximately $1.5 million 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, $244,849 remains unpaid and is included in the August 31, 2016 accounts payable balance.

NOTE 8 — ACCOUNTS PAYABLE- RELATED PARTIES:

The August 31, 2016 and February 29, 2016 accounts payable – related parties balances of $1.1 million and $990,000, respectively, were comprised primarily of deferred salaries of the Company’s Executive Officers and certain employees; directors’ fees; expense reimbursements; and deferred interest payments on a 12% Subordinated Notes owed to the Company’s President and Chief Executive Officer.  Payment of these deferred items has been delayed until the Company’s cash flow situation improves.

NOTE 9 — SHORT-TERM BORROWINGS:

Note Payable – Related Party

As of August 31, 2016 and February 29, 2016, the Company’s President and Chief Executive Officer had loaned the Company $250,100 in aggregate that was 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

The Company has an existing $890,000 line of credit 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 August 31, 2016 and February 29, 2016, the Line of Credit had an outstanding balance of $830,947 and $843,807, respectively.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and was $8,227 for the six months ended August 31, 2016.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

12% Subordinated Notes

The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a March 2010 private placement (of which $250,000 was from a related party) accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th.  On January 29, 2015, the Company and 12 of the 13 note holders agreed to extend the maturity date of the Notes from January 29, 2015 for an additional two years.  The note principal is payable in full at the amended maturity date of the Notes, which is January 29, 2017.  Should the Board of Directors, on the amended 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, 2016.

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12% Note balances at August 31, 2016 and February 29, 2016 are set forth in the table below:

	August 31, 2016			February 29, 2016
12% Subordinated Notes	$	315,000		$	315,000
12% Subordinated Notes, related party		250,000			250,000
	$	565,000		$	565,000

Maximilian Loan (Credit Facility)

On October 31, 2012, the Company entered into a loan agreement with Maximilian, 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 natural gas leases in Kern County, California.  The relative fair value of this 10% working interest amounting to $515,638 was recognized as a discount to debt and is being amortized over the original term of the loan.  Amortization expense was $55,912 for the six months ended August 31, 2016.  Unamortized debt discount was $16,039 at August 31, 2016.

In 2012, the Company also issued 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.  As of August 31, 2016, there were 316,617 of these warrants remaining that were unexercised and outstanding.

Maximilian Credit Facility - Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App Energy in the Twin Bottoms Field in Lawrence County, Kentucky, 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, and a mortgage on 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 natural 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 Energy, as borrower pursuant to a Loan and Security Agreement entered into between the Company and App Energy on August 28, 2013 (See Note 6 – Note Receivable).

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 Maximilian, 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 Energy 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 had 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; and contain an exercise blocker provision that prevents any exercise of the warrants if such exercise and related issuance of common stock would increase the Maximilian holdings of the Company’s common stock to more than 9.99% of the Company’s currently issued and outstanding shares at the time of the exercise.  The Company also granted to Maximilian a 50% net profits interest in the Company’s approximate 25% working interest, after the Company recovers its investment, in the Company’s working interest in its Kentucky acreage, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.

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On May 28, 2014 at Maximilian’s request, the Company finalized a share-for-warrant exchange agreement in which Maximilian returned to the Company 427,729 common shares and was in turn issued the same number of warrants containing the same provisions as the originally issued warrants.  This share-for-warrant exchange occurred so that Maximilian would hold no more than 9.99% of the Company’s common shares, issued and outstanding.  The Company determined that the share-for-warrant exchange did not result in any incremental fair value.

On August 21, 2014, the Company entered into a First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement (the “Amendment”) with Maximilian under its Amended and Restated Loan and Security Agreement dated as of August 28, 2013.  The Amendment secured for the Company an additional advance of $2,200,000 under its credit facility with Maximilian since the advances made by Maximilian had already exceeded its minimum funding commitment.  Additionally, Maximilian agreed to temporarily reduce the required monthly payment made by the Company until it had paid $1,000,000 less than principal payments required by the previous agreement.  Furthermore, Maximilian agreed to reduce the regular interest rate applicable to the loan from 12% per annum to 9% per annum and the default interest rate by 3%.

The additional advance, the reduction in the required monthly payment and the reduction in the interest rate were facilitated through the Company’s acquisition of 5,694,823 shares of its common stock held by Maximilian.  The repurchased shares were cancelled and restored to the status of authorized, but unissued stock.  The Company paid for the share repurchase transaction through an advance of $1,708,447 under the existing loan agreement with Maximilian.

On May 20, 2015, the Company entered into a Second Amendment to Amended and Restated Loan and Security Agreement (the “2^nd Amendment”) with Maximilian under its Amended and Restated Loan and Security Agreement dated as of August 28, 2013.  The 2^nd Amendment modified the calculation of the required monthly payment for a three-month period ending June 30, 2015.  As consideration for entering into the loan modification, the Company agreed to modify the exercise price of the warrants Maximilian currently holds from $0.10 to $0.04.  No other terms of the warrant agreement were changed.  The Company determined that the modification of the warrant exercise price did not result in any incremental fair value.

On October 14, 2015, the Company entered into a Third Amendment to the Amended and Restated Loan and Security Agreement and Second Warrant Amendment with Maximilian, which amended the Company’s loan agreement with Maximilian (the “Maximilian Amendment”).  Pursuant to the Maximilian Amendment, Maximilian agreed to a reduction in the Company’s monthly payments under the loan agreement to $50,000 per month for a period of six months ending on February 29, 2016.  The reduction in monthly payments allowed for additional funds to be used by the Company in drilling and completing additional wells in Kentucky.  As consideration for the reduction in the monthly payment amount, the Company agreed that twenty percent (20%) of the amount by which the monthly payment was reduced would be added to the loan balance, and the portion of the monthly payment savings that constitutes savings in interest or commitment fees would be treated as an additional advance of principal under the loan agreement (the “Deemed Advances”).  The twenty percent (20%) fee is being recognized as additional interest expense.  The Company agreed to grant to Maximilian an overriding royalty interest of 1.5% of its working interest in four wells in Kentucky.  As part of the Maximilian Amendment, the Company also agreed to extend the expiration date of all warrants held by Maximilian to purchase up to 6,550,281 shares of common stock of the Company to August 28, 2018.  The Company determined that the modification of the warrant expiration date did not result in any incremental fair value.

With the cooperation of Maximilian, the Company is currently working with an investment banking firm to assist in securing refinancing of its debt with Maximilian, since the long-term commitment needed to develop the Kentucky and California projects no longer fits the Maximilian business model.  Due to a decline in crude oil and natural gas revenues, the Company has been unable to make the interest or principal payments required under the terms of the credit facility with Maximilian.  The unpaid monthly interest payments and fees have been added to the principal balance including the previously mentioned 20% fee.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not made since December 2015.  During the six months ended August 31, 2016, interest of $1,149,261 and debt modification fees of $775,562 were added to the outstanding loan balance with Maximilian.

Due to the waivers granted by Maximilian for the six months ended August 31, 2016, and for the months of September and October 2016, the Company is currently not considered to be in default under terms of the credit facility.  Maximilian is continuing to work with the Company in modifying the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurance this cooperation will continue.  Furthermore, there can be no assurances that Maximilian will not declare the Company to be in default under the terms of the credit facility.

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In accordance with the guidance found in ASC-470-10-45 and because the loan maturity date is less than the 12 months in the future, the entire balance of the Maximilian loan is presented under the current liabilities section of the balance sheets.  In accordance with the guidance found in ASC 835-35 the net amount of the deferred finance costs associated with the credit facility are included with the debt discount as a reduction of the loan balance shown on the Balance Sheets as of August 31, 2016 and February 29, 2016, respectively.  For the six months ended August 31, 2016, the Company recognized amortization expense of $215,047 in deferred financing costs and $55,912 in debt discount.

Current debt balances at August 31, 2016 and February 29, 2016 are set forth in the table below:

	August 31, 2016			February 29, 2016
Principal Amount	$	16,305,954		$	14,381,131
Less unamortized discount and debt issuance costs		(442,067)			(713,026)
Net debt less unamortized discount and debt issuance costs	$	15,863,887		$	13,668,105

NOTE 10 — STOCKHOLDERS’ DEFICIT:

Preferred Stock

The Company is authorized to issue up to 10,000,000 shares of preferred stock with a par value of $0.001.  The Company’s preferred stock may be entitled to preference over the common stock with respect to the distribution of assets of the Company in the event of liquidation, dissolution, or winding-up of the Company, whether voluntarily or involuntarily, or in the event of any other distribution of assets of the Company among its shareholders for the purpose of winding-up its affairs.  The authorized but unissued shares of preferred stock may be divided into and issued in designated series from time to time by one or more resolutions adopted by the Board of Directors.  The directors in their sole discretion shall have the power to determine the relative powers, preferences, and rights of each series of preferred stock.

Series A Convertible 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.  At August 31, 2016, there were 724,565 shares issued and outstanding, that had not been converted into the Company’s common stock.  As of August 31, 2016, there are 43 accredited investors who have converted 675,200 Series A Preferred shares into 2,025,600 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
Year ended February 28, 2014		151,000		453,000		9
Year ended February 28, 2015		3,000		9,000		1
Year ended February 29, 2016		10,000		30,000		1
Six months ended August 31, 2016		-		-		-
Totals		675,200		2,025,600		43

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Holders of Series A Preferred shall be paid dividends, in the amount of 6% of the original purchase price per annum.  Dividends are cumulative from the date of the final closing of the private placement, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.  As of August 31, 2016, no dividends have been paid.  Dividends earned, but not paid since issuance for each fiscal year and the six months ended August 31, 2016 are set forth in the table below:

Fiscal Period		Shareholders at Period End		Earned 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
Year ended February 28, 2014		59			151,323
Year ended February 28, 2015		58			132,634
Year ended February 29, 2016		57			130,925
Six months ended August 31, 2016		57			65,743
Total Accumulated Dividends				$	1,777,245

Common Stock

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value common stock of which 51,487,373 shares were issued and outstanding as of August 31, 2016 and February 29, 2016.

NOTE 11 — WARRANTS:

Warrants outstanding and exercisable as of August 31, 2016 are set forth in the table below:

		Warrants		Exercise Price		Remaining Life (Years)		Exercisable Warrants Remaining
12% Subordinated Notes		1,190,000		$0.14		0.42		980,000
Warrants issued in 2012 for debt financing		2,435,517		$0.044		1.17		316,617
Warrants issued for Kentucky oil project		3,498,601		$0.04		2.00		3,498,601
Warrants issued for Kentucky debt financing		2,623,951		$0.04		2.00		2,623,951
Warrants issued for Kentucky debt financing		309,503		$0.214		2.00		309,503
Warrants issued in share-for-warrant exchange		427,729		$0.04		2.00		427,729
		10,485,301						8,156,401

During the six months ended August 31, 2016 there were no warrants issued or exercised.  Additionally, there were no warrants that expired.  As of August 31, 2016, the remaining outstanding warrants have a weighted average exercise price of $0.06, a weighted average remaining life of 1.78 years, and an intrinsic value of -$0-.

NOTE 12 — INCOME TAXES:

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

	August 31, 2016			February 29, 2016
Computed at U.S. and state statutory rates (40%)	$	(843,173)		$	(1,616,023)
Permanent differences		28,680			143,946
Changes in valuation allowance		814,493			1,472,077
Total	$	-		$	-

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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:

	August 31, 2016			February 29, 2016
Deferred tax assets:
Net operating loss carryforwards	$	10,923,579		$	10,217,121
Oil and gas properties		(917,667)			(944,342)
Stock based compensation		88,723			88,723
Other		(69,585)			(150,945)
Less valuation allowance		(10,025,050)			(9,210,557)
Total	$	-		$	-

At August 31, 2016, Daybreak had estimated net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $27,308,803 which will begin to expire, if unused, beginning in 2024.  The valuation allowance increased $814,493 for the six months ended August 31, 2016 and increased by $1,472,077 for the year ended February 29, 2016.  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 13 — 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 natural 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 natural gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages.  In some instances, the Company may be directed to suspend or cease operations in the affected area.  The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of August 31, 2016.  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 natural gas properties.

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

The following discussion is management’s assessment of the current and historical financial and operating results of the Company and of our financial condition.  It is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q for the six months ended August 31, 2016 and in our Annual Report on Form 10-K for the year ended February 29, 2016.  References to “Daybreak”, the “Company”, “we”, “us” or “our” mean Daybreak Oil and Gas, Inc.

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 natural 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, regulation of hydraulic fracturing 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; in our other public filings and press releases; and discussions with Company management.

Our reserve estimates are determined through a subjective process and are subject to revision.

Should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended February 29, 2016 and 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.

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Introduction and Overview

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 natural 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 natural 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 natural 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, such as we are now experiencing, 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 natural gas properties and funding projects that we believe have the potential to produce oil or natural gas in commercial quantities.  We conduct all of our drilling, exploration and production activities in the United States, and all of our revenues are derived from sales to customers within the United States.  Currently, we are in the process of developing two multi-well oilfield projects; one in Lawrence County, Kentucky and the other in Kern County, California.

Our management cannot provide any assurances that Daybreak will ever operate profitably.  We have not been able to generate sustained positive earnings on a Company-wide basis.  As a small company, 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 29, 2016 and in Part III, Item 1A. Risk Factors of this 10-Q Report.  Throughout this Quarterly Report on Form 10-Q, oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).

Below is summary of our oil and natural gas projects in Kentucky and California.

Lawrence County, Kentucky (Twin Bottoms Field)

The Twin Bottoms Field, comprising approximately 7,220 acres in two large contiguous blocks, is located in the Appalachian Basin of eastern Kentucky.  Log data from existing vertical natural gas wells in the field indicate the existence of proved oil reserves in the Berea sandstone, located at approximately 2,000 feet.  Since October 2013, we have participated in the drilling of 14 horizontal oil wells in this project.  The oil produced from our acreage in Kentucky is light sweet crude oil measuring between 42° and 44° API (American Petroleum Institute) gravity.  During the six month ended August 31, 2016, we had production from 14 wells.  Our average working interest (“WI”) and net revenue interest (“NRI”) in these 14 wells is 22.6% and 19.7%, respectively.  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.  However, we have our own personnel onsite during critical operations such as drilling, fracturing and completing operations.

Kentucky Drilling Plans

Selected wells may be drilled from time to time to maintain production and leases, however; implementation of our full development plan will not resume until there is a sustained improvement in crude oil prices and additional financing is put in place.  We plan to spend approximately $0.5 million in new capital investments in the Twin Bottoms Field Project area in the 2016 - 2017 fiscal year if we are able to secure financing.

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.  The oil produced in our acreage from the Vedder Sand is considered heavy oil.  The oil ranges from 14° to 16° API gravity and must be heated to separate and remove water prior to sale.  During the six months ended August 31, 2016 we had production from 20 vertical oil wells.  Our average WI and NRI in these 20 wells is 36.6% and 28.4%, respectively.  We have been the Operator at the East Slopes Project since March 2009.

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California Drilling Plans

Planned drilling activity and implementation of our oilfield development plan will not resume until there is a sustained improvement in crude oil prices and additional financing is in put in place.  No capital investments are currently planned within the East Slopes Project area in the 2016 – 2017 fiscal year.

Encumbrances

The Company’s debt obligations, pursuant to a loan agreement entered into by and between Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to “Maximilian”), 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 “Current Debt (Short-Term Borrowings)” in this MD&A.

Results of Operations – Six months ended August 31, 2016 compared to the six months ended August 31, 2015

Hydrocarbon Prices

The price we receive for oil sales in both Kentucky and California is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs.  The price we receive for natural gas sales in Kentucky per Mcf is based on the Columbia Gas Transmission Corp. Appalachia Index (“TCO Appalachia”) whereby we will receive either 76% or 79% (depending on buyer) of the TCO Appalachia price per dekatherm (DTH) less $0.25 compression cost for each Mcf of natural gas delivered.  We do not have any natural gas revenues in California.

Since June 2014, there has been a significant decline in the WTI price of crude oil and subsequently in the realized price we receive from oil sales.  This decline in the price of crude oil has had a substantial negative impact on our cash flow from both our Kentucky and California properties as shown in the table below.

		August 2016			June 2014			Percentage Decline
Monthly average WTI crude oil price		$	44.72		$	105.79		57.7%
Monthly average realized crude oil sales price (Bbl)		$	37.93		$	101.45		62.6%
Monthly crude oil revenue sales (Adjusted for June 2014 volume)		$	69,864		$	191,347		63.5%

Crude Oil and Natural Gas Revenue, Production and Prices in Aggregate

Our revenues are derived entirely from the sale of our share of crude oil production in Kentucky and California and natural gas sales in Kentucky.  Crude oil and natural gas revenues for the six months ended August 31, 2016 in aggregate decreased $373,765 or 46.1%, to $437,353 in comparison to revenues of $811,118 for the six months ended August 31, 2015.  Crude oil and natural gas sales volume decreased 5,174 BOE (barrels of oil equivalent) or 27.8% to 13,463 (BOE) for the six months ended August 31, 2016, in comparison to 18,637 (BOE) for the six months ended August 31, 2015.  The decrease in volume was primarily due to the natural decline in oil producing reservoir pressure in Kentucky.  The average WTI price for the six months ended August 31, 2016 was $43.86 in comparison to $52.57 for the six months ended August 31, 2015.  Our average realized sale price on a BOE basis for the six months ended August 31, 2016 was $32.49 in comparison to $43.52 for the six months ended August 31, 2015, representing a decline of $11.04 or 25.4% per barrel.  Approximately $205,682 or 55.0% of the decline in revenue can be directly attributed to the decline in hydrocarbon prices for the six months ended August 31, 2016.

Kentucky Oil Prices

For the six months ended August 31, 2016, our average realized oil sale price was $42.54 in comparison to the average WTI price of $43.86 representing a discount of $1.32 per barrel or 3.0% lower than the average WTI price.  In comparison, for the six months ended August 31, 2015, the average WTI price was $52.57 and our average realized sale price was $51.36 representing a discount of $1.21 per barrel or 2.3% lower than the average WTI price.

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Kentucky Crude Oil Revenue and Production

Crude oil revenue in Kentucky for the six months ended August 31, 2016 decreased $269,934 or 58.1% to $194,504 in comparison to revenue of $464,438 for the six months ended August 31, 2015.  The average realized sale price of a barrel of oil for the six months ended August 31, 2016 was $42.54 in comparison to $51.36 for the six months ended August 31, 2015.  The decrease of $8.82 or 17.2% in the average realized price of a barrel of oil accounted for $79,777 or 29.6% of the decline in oil revenue while a decrease of $190,157 or 70.4% can be attributed to a decline in production for the six months ended August 31, 2016 in comparison to the six months ended August 31, 2015.

Our net sales volume for the six months ended August 31, 2016 was 4,573 barrels of oil in comparison to 9,043 barrels sold for the six months ended August 31, 2015.  This decrease in oil sales volume of 4,470 barrels or 49.4% was due to the natural decline in reservoir pressure.

The gravity of our produced oil in Kentucky ranges between 42° API and 44° API.  Production for the six months ended August 31, 2016 was from 14 wells resulting in 2,017 well days of production in comparison to 2,188 well days of production from 13 wells for the six months ended August 31, 2015.  The decline of 7.8% in well days of production was primarily due to field infrastructure work that was being done on the natural gas pipeline and associated equipment during the six months ended August 31, 2016.  Our gross average daily oil production was 135 Bbls/Day (Barrels per Day) during the six months ended August 31, 2016.

Kentucky Natural Gas Prices

For the six months ended August 31, 2016, our average realized natural gas sale price was $1.09 per Mcf (thousand cubic feet) in comparison to the average Henry Hub price of $2.30 per million BTU representing a discount of $1.21 per Mcf or 52.6% lower than the average Henry Hub price.  In comparison, for the six months ended August 31, 2015, the average realized sale price was $1.75 per Mcf in comparison to the average Henry Hub price of $2.78 per million BTU representing a discount of $1.03 or 37.0% lower than the average Henry Hub price.

Kentucky Natural Gas Revenue and Production

Natural gas revenue for the six months ended August 31, 2016 decreased $12,245 or 47.5% to $13,559 in comparison to revenue of $25,804 for the six months ended August 31, 2015.  The average sale price per Mcf for the six months ended August 31 2016 was $1.09 in comparison to $1.75 for the six months ended August 31, 2015.

Our net sales volume for the six months ended August 31, 2016 was 12,441 Mcf or 2,074 BOE in comparison to 14,733 Mcf or 2,456 BOE for the six months ended August 31, 2015.  The decline in natural gas production volume was due to the natural decline in reservoir pressure.

California Oil Prices

For the six months ended August 31, 2016, the average WTI price was $43.86 and our average realized oil sale price was $33.64, representing a discount of $10.22 per barrel or 23.3% lower than the average WTI price.  In comparison, for the six months ended August 31, 2015, the average WTI price was $52.57 and our average realized sale price was $44.95 representing a discount of $7.62 per barrel or 7.6% lower than the average WTI price.  Historically, the sale price we receive for California heavy oil has been less than the quoted WTI price because of the lower API gravity of our California oil in comparison to WTI oil API gravity.

California Crude Oil Revenue and Production

Crude oil revenue in California for the six months ended August 31, 2016 decreased $91,586 or 28.5% to $229,290 in comparison to revenue of $320,876 for the six months ended August 31, 2015.  The average sale price of a barrel of crude oil for the six months ended August 31, 2016 was $33.64 in comparison to $44.95 for the six months ended August 31, 2015.  The decrease of $11.31 or 25.2% in the average realized price of a barrel of oil accounted for $80,767 or 88.2% of the decline in oil revenue while a decrease of $10,818 or 11.8% can be attributed to a decline in production for the six months ended August 31, 2016.

Our net sales volume for the six months ended August 31, 2016 was 6,817 barrels of oil in comparison to 7,138 barrels sold for the six months ended August 31, 2015.  This decrease in oil sales volume of 322 barrels or 4.5% was primarily due to the natural decline in reservoir pressure during the six months ended August 31, 2016.

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The gravity of our produced oil in California ranges between 14° API and 16° API.  Production for the six months ended August 31, 2016 was from 20 wells resulting in 3,656 well days of production in comparison to 3,662 well days of production from 20 wells for the six months ended August 31, 2015.  Our gross average daily oil production was 127 Bbls/Day (Barrels per Day) during the six months ended August 31, 2016.

Crude oil and natural gas revenues for the six months ended August 31, 2016 and 2015 are set forth in the following table.

		Six Months Ended August 31, 2016					Six Months Ended August 31, 2015
Project		Revenue			Percentage		Revenue			Percentage
Kentucky - Twin Bottoms Field (Crude oil)		$	194,504		44.5%		$	464,438		57.3%
Kentucky – Twin Bottoms Field (Natural gas)			13,559		3.1%			25,804		3.2%
California - East Slopes Project (Crude oil)			229,290		52.4%			320,876		39.5%
		$	437,353		100.0%		$	811,118		100.0%

*Our average realized sale price on a BOE basis for the six months ended August 31, 2016 was $32.49 in comparison to $43.52 for the six months ended August 31, 2015, representing a decrease of $11.04 or 25.4% per barrel.

Of the $373,765 or 46.1% decline in revenue for six months ended August 31, 2016 in comparison to the six months ended August 31, 2015, approximately $205,682 or 55.0% can be directly attributed to the decline in the price of crude oil and natural gas.

Operating Expenses

Total operating expenses for the six months ended August 31, 2016 were $796,898, a decrease of $161,007 or 16.8% compared to $957,905 for the six months ended August 31, 2015.  Decreases were achieved in all categories of operating expenses for the six months ended August 31, 2016 in comparison to the six months ended August 31, 2015.  Operating expenses for the six months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Six Months Ended August 31, 2016								Six Months Ended August 31, 2015
		Expenses			Percentage		BOE Basis			Expenses			Percentage		BOE Basis
Production expenses		$	123,176		15.4%					$	145,606		15.2%
Exploration and drilling expenses			7,069		0.9%						20,067		2.1%
Depreciation, Depletion, Amortization (“DD&A”)			151,910		19.1%						257,729		26.9%
General and Administrative (“G&A”) expenses			514,743		64.6%						534,503		55.8%
Total operating expenses		$	796,898		100.0%		$	59.19		$	957,905		100.0%		$	51.40

Production expenses include expenses associated with the production of oil and natural gas.  These expenses include contract pumpers, electricity, road maintenance, control of well insurance, property taxes and well workover expenses; and, relate directly to the number of wells that are in production.  For the six months ended August 31, 2016, these expenses decreased by $22,430 or 15.4% to $123,176 in comparison to $145,606 for the six months ended August 31, 2015.  For the six months ended August 31, 2016 we had 20 wells on production in California and 14 wells on production in Kentucky in comparison to 20 wells in California and 13 wells in Kentucky for the six months ended August 31, 2015.  Production expenses represented 15.4% of total operating expenses.

Production expenses in Kentucky and California for the six months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Six Months Ended August 31, 2016					Six Months Ended August 31, 2015
		Expenses			Percentage		Expenses			Percentage
Kentucky – Twin Bottoms Field		$	43,116		35.0%		$	58,555		40.2%
California – East Slopes Project			80,060		65.0%			87,051		59.8%
Total production expenses		$	123,176		100.0%		$	145,606		100.0%

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Production expenses on a BOE basis in Kentucky and California for the six months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Six Months Ended
		August 31, 2016			August 31, 2015
Kentucky – Twin Bottoms Field (BOE)		$	6.49		$	5.09
California – East Slopes Project (BOE)		$	11.74		$	12.19
Aggregate production expenses (BOE)		$	9.15		$	7.81

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses decreased $12,998 or 64.8% to $7,069 for the six months ended August 31, 2016 in comparison to $20,067 the six months ended August 31, 2015.  Exploration and drilling expenses represented 0.9% 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 six months ended August 31, 2016, DD&A expenses decreased $105,819 or 41.1% to $151,910 in comparison to $257,729 for the six months ended August 31, 2015.  The decrease in DD&A is directly related to the level of our hydrocarbon production in both Kentucky and California.  DD&A expenses represented 19.1% of total operating expenses.

DD&A and impairment expenses in Kentucky and California for the six months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Six Months Ended August 31, 2016					Six Months Ended August 31, 2015
		Expenses			Percentage		Expenses			Percentage
Kentucky – Twin Bottoms Field		$	96,016		63.2%		$	174,725		67.8%
California – East Slopes Project			55,894		36.8%			83,004		32.2%
Total DD&A expenses		$	151,910		100.0%		$	257,729		100.0%

DD&A and impairment expenses on a BOE basis in Kentucky and California for the six months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Six Months Ended
		August 31, 2016			August 31, 2015
Kentucky – Twin Bottoms Field (BOE)		$	14.45		$	15.20
California – East Slopes Project (BOE)		$	8.20		$	11.63
Aggregate DD&A expenses (BOE)		$	11.28		$	13.83

G&A expenses include the salaries of our six full-time employees, including management.  Fifty percent of certain employee’s salaries are currently being deferred until the Company’s cash flow improves, however the entire expense is currently being recognized in G&A.  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 natural gas properties as well as for running a public company.  For the six months ended August 31, 2016, G&A expenses decreased $19,760 or 3.7% to $514,743 in comparison to $534,503 for the six months ended August 31, 2014.  We received, as Operator in California, administrative overhead reimbursement of $26,644 during the six months ended August 31, 2016 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 64.6% of total operating expenses.

Interest income for the six months ended August 31, 2016 increased $126,724 or 29.8% to $551,328 in comparison to $424,604 for the six months ended August 31, 2015 due to the loan modification terms of the note receivable from App Energy.  Refer to the discussion of the App Loan Agreement under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Current Debt (Short-Term Borrowings) in this MD&A.

Interest expense for the six months ended August 31, 2016 increased $969,246 or 72.8% to $2,299,717 in comparison to $1,330,471 for the six months ended August 31, 2015.  The increase in interest expense is directly related to the modified loan payment terms on our credit facility with Maximilian.  Refer to the discussion of the Maximilian Credit Facility – Amended and Restated Loan Agreement under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Current Debt (Short-Term Borrowings) in this MD&A.

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Results of Operations – Three months ended August 31, 2016 compared to the three months ended August 31, 2015

Crude Oil and Natural Gas Revenue, Production and Prices in Aggregate

Our revenues are derived entirely from the sale of our share of crude oil production in Kentucky and California and natural gas sales in Kentucky.  Crude oil and natural gas revenues for the three months ended August 31, 2016 in aggregate decreased $145,957 or 39.5%, to $223,877 in comparison to revenues of $369,834 for the three months ended August 31, 2015.  Crude oil and natural gas sales volume decreased 2,834 BOE (barrels of oil equivalent) or 32.7% to 5,846 (BOE) for the three months ended August 31, 2016, in comparison to 8,680 (BOE) for the three months ended August 31, 2015.  The decrease in volume was primarily due to the natural decline in oil producing reservoir pressure in Kentucky.  Our average realized sale price on a BOE basis for the three months ended August 31, 2016 was $38.29 in comparison to $42.61 for the three months ended August 31, 2015, representing a decline of $4.32 or 10.1% per barrel.  Approximately $37,450 or 25.7% of the decline in revenue can be directly attributed to the decline in hydrocarbon prices for the three months ended August 31, 2016 in comparison to the three months ended August 31, 2015.

Kentucky Crude Oil Prices

For the three months ended August 31, 2016, our average realized crude oil sale price was $45.01 in comparison to the average WTI price of $46.04 representing a discount of $1.03 per barrel or 2.3% lower than the average WTI price.  In comparison, for the three months ended August 31, 2015, the average WTI price was $51.28 and our average realized sale price was $50.78 representing a discount of $0.50 per barrel or 1.0% lower than the average WTI price.

Kentucky Crude Oil Revenue and Production

Crude Oil revenue in Kentucky for the three months ended August 31, 2016 decreased $105,263 or 53.7% to $90,791 in comparison to revenue of $196,054 for the three months ended August 31, 2015.  The average sale price of a barrel of crude oil for the three months ended August 31, 2016 was $45.01 in comparison to $50.78 for the three months ended August 31, 2015.  The decrease of $5.77 or 11.4% in the average realized price of a barrel of oil accounted for $22,290 or 21.2% of the decline in oil revenue while a decrease of $82,974 or 78.8% can be attributed to a decline in production for the three months ended August 31, 2016 in comparison to the three months ended August 31, 2015.

Our net sales volume for the three months ended August 31, 2016 was 2,017 barrels of crude oil in comparison to 3,861 barrels sold for the three months ended August 31, 2015.  This decrease in oil sales volume of 1,844 barrels or 47.8% was due to the natural decline in reservoir pressure.

The gravity of our produced oil in Kentucky ranges between 42° API and 44° API.  Production for the three months ended August 31, 2016 was from 14 wells resulting in 842 well days of production in comparison to 1,044 well days of production from 13 wells for the three months ended August 31, 2015.  The decline of 19.3% in well days of production was primarily due to field infrastructure work that was being done on the natural gas pipeline and associated equipment during the three months ended August 31, 2016.  Our gross average daily oil production was 123 Bbls/Day (Barrels per Day) during the three months ended August 31, 2016.

Kentucky Natural Gas Prices

For the three months ended August 31, 2016, our average realized natural gas sale price was $4.53 per Mcf (thousand cubic feet) in comparison to the average Henry Hub price of $2.74 per million BTU representing an increase of $1.79 per Mcf or 65.2% higher than the average Henry Hub price.  The reason we received a premium to the Henry Hub price was due to an adjustment in production volume estimates from the prior quarter.  In comparison, for the three months ended August 31, 2015, the average realized sale price was $1.63 per Mcf in comparison to the average Henry Hub price of $2.80 per million BTU representing a discount of $1.17 or 41.7% lower than the average Henry Hub price.

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Kentucky Natural Gas Revenue and Production

Natural gas revenue for the three months ended August 31, 2016 decreased $2,582 or 22.4% to $8,942 in comparison to revenue of $11,524 for the three months ended August 31, 2015.  The average sale price per Mcf for the three months ended August 31 2016 was $4.53 in comparison to $1.63 for the three months ended August 31, 2015.  The reason for the increase in the realized price for the quarter was due to an adjustment in production volume estimates from the prior quarter.

Our net sales volume for the three months ended August 31, 2016 was 1,976 Mcf or 329 BOE in comparison to 7,059 Mcf or 1,177 BOE for the three months ended August 31, 2015.  The decrease in natural gas production volume was due to an adjustment in production volume estimates from the prior quarter.

California Crude Oil Prices

For the three months ended August 31, 2016, the average WTI price was $46.04 and our average realized crude oil sale price was $35.47, representing a discount of $10.57 per barrel or 23.0% lower than the average WTI price.  In comparison, for the three months ended August 31, 2015, the average WTI price was $51.28 and our average realized sale price was $44.55 representing a discount of $6.73 per barrel or 13.1% lower than the average WTI price.  Historically, the sale price we receive for California heavy oil has been less than the quoted WTI price because of the lower API gravity of our California oil in comparison to WTI oil API gravity.

California Crude Oil Revenue and Production

Crude oil revenue in California for the three months ended August 31, 2016 decreased $38,110 or 23.5% to $124,145 in comparison to revenue of $162,255 for the three months ended August 31, 2015.  The average sale price of a barrel of crude oil for the three months ended August 31, 2016 was $35.47 in comparison to $44.55 for the three months ended August 31, 2015.  The decrease of $9.08 or 20.4% in the average realized price of a barrel of crude oil accounted for $33,047 or 86.7% of the decline in oil revenue while a decrease of $5,062 or 13.3% can be attributed to a decline in production for the three months ended August 31, 2016 in comparison to the three months ended August 31, 2015.

Our net sales volume for the three months ended August 31, 2016 was 3,500 barrels of crude oil in comparison to 3,642 barrels sold for the three months ended August 31, 2015.  This decrease in oil sales volume of 142 barrels or 3.9% was primarily due to the natural decline in reservoir pressure during the three months ended August 31, 2016.

The gravity of our produced oil in California ranges between 14° API and 16° API.  Production for the three months ended August 31, 2016 was from 20 wells resulting in 1,827 well days of production in comparison to 1,837 well days of production from 20 wells for the three months ended August 31, 2015.  Our gross average daily oil production was 129 Bbls/Day (Barrels per Day) during the three months ended August 31, 2016.

Oil and natural gas revenues for the three months ended August 31, 2016 and August 31, 2015 are set forth in the following table.

		Three Months Ended August 31, 2016					Three Months Ended August 31, 2015
Project		Revenue			Percentage		Revenue			Percentage
Kentucky - Twin Bottoms Field (Oil)		$	90,791		40.5%		$	196,054		53.0%
Kentucky – Twin Bottoms Field (Natural Gas)			8,941		4.0%			11,525		3.1%
California - East Slopes Project (Oil)			124,145		55.5%			162,255		43.9%
		$	223,877		100.0%		$	369,834		100.0%

*Our average realized sale price on a BOE basis for the three months ended August 31, 2016 was $38.29 in comparison to $42.61 for the three months ended August 31, 2015, representing a decrease of $4.31 or 10.1% per barrel.

Of the $145,957 or 39.5% decline in revenue for three months ended August 31, 2016 in comparison to the three months ended August 31, 2015, approximately $37,450 or 25.7% can be directly attributed to the decline in the price of crude oil and natural gas prices.

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Operating Expenses

Total operating expenses for the three months ended August 31, 2016 were $349,850, a decrease of $96,295 or 21.6% compared to $446,145 for the three months ended August 31, 2015.  Decreases were achieved in all categories of operating expenses for the three months ended August 31, 2016 in comparison to the three months ended August 31, 2015.  Operating expenses for the three months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Three Months Ended August 31, 2016								Three Months Ended August 31, 2015
		Expenses			Percentage		BOE Basis			Expenses			Percentage		BOE Basis
Production expenses		$	59,117		16.9%					$	70,001		15.7%
Exploration and drilling expenses			126		-%						8,400		1.9%
Depreciation, Depletion, Amortization (“DD&A”)			62,634		17.9%						118,889		26.6%
General and Administrative (“G&A”) expenses			227,973		65.2%						248,855		55.8%
Total operating expenses		$	349,850		100.0%		$	59.84		$	446,145		100.0%		$	51.40

For the three months ended August 31, 2016, production expenses decreased by $10,884 or 15.5% to $59,117 in comparison to $70,001 for the three months ended August 31, 2015.  For the three months ended August 31, 2016 we had 20 wells on production in California and 14 wells on production in Kentucky in comparison to 20 wells in California and 13 wells in Kentucky for the three months ended August 31, 2015.  Production expenses represented 16.9% of total operating expenses for the three months ended August 31, 2016.

Production expenses in Kentucky and California for the three months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Three Months Ended August 31, 2016					Three Months Ended August 31, 2015
		Expenses			Percentage		Expenses			Percentage
Kentucky – Twin Bottoms Field		$	20,076		34.0%		$	28,847		41.2%
California – East Slopes Project			39,041		66.0%			41,154		58.8%
Total production expenses		$	59,117		100.0%		$	70,001		100.0%

Production expenses on a BOE basis in Kentucky and California for the three months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Three Months Ended
		August 31, 2016			August 31, 2015
Kentucky – Twin Bottoms Field (BOE)		$	8.56		$	5.73
California – East Slopes Project (BOE)		$	11.16		$	11.30
Aggregate production expenses (BOE)		$	10.11		$	8.06

For the three months ended August 31, 2016, exploration and drilling expenses decreased $8,274 or 98.5% to $126 in comparison to $8,400 for the three months ended August 31, 2015.  Exploration and drilling expenses represented -% of total operating expenses for the three months ended August 31, 2016.

For the three months ended August 31, 2016, DD&A expenses decreased $56,255 or 47.3% to $62,634 in comparison to $118,889 for the three months ended August 31, 2015.  The decrease in DD&A is directly related to the lower hydrocarbon production volumes in both Kentucky and California.  DD&A expenses represented 17.9% of total operating expenses for the three months ended August 31, 2016.

DD&A and impairment expenses in Kentucky and California for the three months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Three Months Ended August 31, 2016					Three Months Ended August 31, 2015
		Expenses			Percentage		Expenses			Percentage
Kentucky – Twin Bottoms Field		$	33,966		54.2%		$	76,572		64.4%
California – East Slopes Project			28,668		45.8%			42,317		35.6%
Total DD&A expenses		$	62,634		100.0%		$	118,889		100.0%

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DD&A and impairment expenses on a BOE basis in Kentucky and California for the three months ended August 31, 2016 and August 31, 2015 are set forth in the table below:

		Three Months Ended
		August 31, 2016			August 31, 2015
Kentucky – Twin Bottoms Field (BOE)		$	14.47		$	15.20
California – East Slopes Project (BOE)		$	8.19		$	11.62
Aggregate DD&A expenses (BOE)		$	10.71		$	13.70

For the three months ended August 31, 2016, G&A expenses decreased $20,882 or 8.4% to $227,973 in comparison to $248,855 for the three months ended August 31, 2015.  We received, as Operator in California, administrative overhead reimbursement of $13,322 during the three months ended August 31, 2016 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 65.2% of total operating expenses for the three months ended August 31, 2016.

Interest income for the three months ended August 31, 2016 increased $68,722 or 34.0% to $270,573 in comparison to $201,851 for the three months ended August 31, 2015 due to the loan modification of the note receivable from App Energy.

Interest expense for the three months ended August 31, 2016 increased $522,416 or 79.0% to $1,184,020 in comparison to $661,604 for the three months ended August 31, 2015.  The increase in interest expense is directly related to the modified loan payment terms on our credit facility with Maximilian.  The credit facility activity is discussed further in the discussion of the Maximilian Credit Facility – Amended and Restated Loan Agreement under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Current Debt (Short-Term Borrowings) in this MD&A.

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.  Revenues are dependent upon both hydrocarbon production levels and the price we receive for hydrocarbon sales.  Since June of 2014, there has been a significant decline in the WTI price of crude oil and subsequently in the realized price we receive from oil sales.  This decline in the price of crude oil has had a substantial negative impact on our cash flow from both our Kentucky and California properties.  Production expenses will fluctuate according to the number and percentage ownership of producing wells that we own.  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 and natural gas reserve base.  Our ability to fund any future capital expenditure programs is dependent upon the prices we receive from oil sales, the success of our development drilling program in Kentucky, our exploration and development program in Kern County, California and the availability of capital resource financing.  Since June 2014, there has been a significant decline in the WTI price of crude oil and consequently in the realized price we receive from oil sales.  This decline in the price of crude oil has had a substantial negative impact on our cash flow from both our Kentucky and California properties.

In the current fiscal year we plan to spend approximately $500,000 in capital investments in Kentucky, dependent on the successful completion of refinancing our credit facility.  However our actual expenditures may vary significantly from this estimate if our plans for exploration and development activities change during the year or if we are not able to obtain financing to fund these capital investments.  Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the current fiscal year.

The Company has engaged an investment banking firm to assist in securing refinancing of its debt at more favorable terms and implement our development plans in California and Kentucky.

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Changes in our capital resources at August 31, 2016 in comparison to February 29, 2016 are set forth in the table below:

							Increase			Percentage
	August 31, 2016			February 29, 2016			(Decrease)			Change
Cash	$	23,974		$	6,995		$	16,979		242.7%
Current Assets	$	357,732		$	834,480		$	(476,748)		(57.1%)
Total Assets	$	9,306,778		$	8,960,004		$	346,774		3.9%
Current Liabilities	$	(20,720,979)		$	(18,270,014)		$	2,450,965		13.4%
Total Liabilities	$	(20,804,701)		$	(18,349,993)		$	2,454,708		13.4%
Working Capital Deficit	$	(20,363,247)		$	(17,435,534)		$	2,927,713		16.8%

Our working capital deficit increased $2,927,713 or 16.8% to $20,363,247 at August 31, 2016 in comparison to $17,435,534 at February 29, 2016.  The increase in our working capital deficit was due to our operating loss of $359,545; the reclassification of the short-term portion of the App Energy note receivable to long-term, and the increase in interest and fees on the Maximilian loan due to our inability to make principal and interest payments since December 2015.  Refer to the discussion below under Current Debt (Short-Term Borrowings) – Maximilian Loan (Credit Facility) for more information on the loan payment modifications.

While we have ongoing positive cash flow from our oil and natural gas operations in Kentucky and California, 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 Twin Bottoms Field in Lawrence County, Kentucky will occur when we are able to return to our planned drilling program that will result in an increase in the number of wells on production.

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 Kentucky and California, 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 natural gas producing properties, and stabilized hydrocarbon prices, which may very likely require us to continue to raise equity or debt capital from outside sources or sales of all or part of our working interests in our properties.

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 will cause us to seek additional forms of 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.  The current uncertainty in the credit and capital markets as well as the decline in oil prices may restrict our ability to obtain needed capital.  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 all or part of our working interests in our properties may be another source of cash flow available to us.

The Company’s financial statements for the six months ended August 31, 2016 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.  Since entering the oil and gas exploration industry, we have mostly incurred quarterly net losses.  As of August 31, 2016, we have an accumulated deficit of $34,518,849 and a working capital deficit of $20,363,247 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 Kentucky and California.  The Company has engaged an investment banking firm to assist in securing refinancing of its debt under more favorable terms and implement its development plans in California and Kentucky.  We plan to obtain financing through various methods, including issuing debt securities, equity securities, or 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 all or part of our working interests in our properties may be another source of cash flow available to us.

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Changes in Financial Condition

During the six months ended August 31, 2016, we received oil and natural gas sales revenue from 14 wells in Kentucky and 20 wells in California.  Our commitment to improving corporate profitability remains unchanged.  During the six months ended August 31, 2016, we had an operating loss of $359,545.  We experienced a decline in revenues of 46.1% or $373,765 to $437,353 for the six months ended August 31, 2016 in comparison to revenues of $811,118 for the six months ended August 31, 2015.  The decline in the realized sale price we received on a BOE basis was $11.04 to $32.49 in comparison to $43.52 for the six months ended August 31, 2015.  Of the $373,765 decline in revenue $205,682 was related to the decline in price and $168,083 was related to the decline in sales volume.

Our balance sheet at August 31, 2016 reflects total assets of approximately $9.3 million in comparison to approximately $8.9 million at February 29, 2016.  This increase of approximately $0.4 million is due to modifications of the App Energy loan from Daybreak.

At August 31, 2016, total liabilities were approximately $20.8 million in comparison to approximately $18.3 million at February 29, 2016.  The increase in liabilities of approximately $2.5 million was due to increases in payables and our credit facility balance with Maximilian.

There was no change in our common stock issued and outstanding at August 31, 2016 in comparison to the 51,487,373 common shares issued and outstanding at February 29, 2016.

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:

	Six Months Ended August 31, 2016			Six Months Ended August 31, 2015			Increase (Decrease)			Percentage Change
Net cash provided by (used in) operating activities	$	28,499		$	(263,103)			291,602		110.8%
Net cash provided by investing activities	$	1,340		$	491,786			(490,446)		(99.7%)
Net cash used in financing activities	$	(12,860)		$	(602,963)			(590,103)		(97.9%)

Cash Flow Provided by (Used In) Operating Activities

Cash flow from operating activities is derived from the production of our oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances.  For the six months ended August 31, 2016, cash flow provided by operating activities was $28,499 in comparison to cash flow used in operating activities of $263,103 for the six months ended August 31, 2015.  This increase in operating cash flow of $291,602 or 110.8% is directly related to a decline in our receivables balances; an increase in our payables balances; and, an increase in accrued interest offset by our net loss for the six months ended August 31, 2016.  Non-cash account balances relating to DD&A; amortization of debt discount; deferred financing costs and debt modification fees were $1,198,394 in aggregate for the six months ended August 31, 2016.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash Flow Provided by 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 flow provided by investing activities for the six months ended August 31, 2016 was $1,340 a decline of $490,446 from the $491,786 provided by investing activities for the six months ended August 31, 2015.  This decline of $490,446 was due to a decline in drilling activity because of lower hydrocarbon prices and the inability of App Energy to make the principal and interest payments during the six months ended August 31, 2016.  The credit facility and our lending activity to App Energy is discussed further under the caption “Current Debt (Short-Term Borrowings) – Maximilian Loan (Credit Facility)” in this MD&A.

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Cash Flow Used In 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 flow used in our financing activities was $12,860 for the six months ended August 31, 2016 in comparison to cash flow used in our financing activities of $602,963 for the six months ended August 31, 2015.  This decline of $590,103 in cash flow used was due to our inability to make principal and interest payments on our credit facility with Maximilian.  The credit facility and our lending activity to App Energy is discussed further in the discussion of the Maximilian Credit Facility – Amended and Restated Loan Agreement under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Short-Term Borrowings) in this MD&A.

The following discussion is a summary of cash flows provided by, and used in, the Company’s financing activities at August 31, 2016.

Current Debt (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 was 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

The Company has an existing $890,000 line of credit 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 August 31, 2016, the Line of Credit had an outstanding balance of $830,947.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and was $8,227 for the six months ended August 31, 2016.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

12% Subordinated Notes

The Company’s 12% Subordinated Notes (“the Notes”) were issued pursuant to a March 2010 private placement (of which $250,000 was issued to a related party) and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th.  On January 29, 2015, the company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes for an additional two years to January 29, 2017.  The note principal of $565,000 is payable in full at the amended maturity of the Notes.  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, 2016.

12% Notes balances at August 31, 2016 and February 29, 2016 are set forth in the table below:

	August 31, 2016			February 29, 2016
12% Subordinated Notes	$	315,000		$	315,000
12% Subordinated Notes, related party		250,000			250,000
	$	565,000		$	565,000

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 an amended expiration date of January 29, 2017.  The 12% Note warrants that have been exercised are set forth in the table below.

Fiscal Period		Warrants Exercised		Shares of Common Stock Issued		Number of Accredited Investors
Year ended February 28, 2014		100,000		100,000		1
Year ended February 28, 2015		50,000		50,000		1
Year ended February 29, 2016		-		-		-
Six months ended August 31, 2016		-		-		-
Totals		150,000		150,000		2

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Maximilian Loan (Credit Facility)

On October 31, 2012, the Company entered into a loan agreement with Maximilian, 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 natural 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 was $55,912 for the six months ended August 31, 2016.  Unamortized debt discount amounted to $16,039 at August 31, 2016.

In 2012, the Company also issued 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.  On March 10, 2014, one of the third parties exercised 2,118,900 warrants resulting in the issuance of 1,873,554 shares of our common stock.  As of August 31, 2016, there were 316,617 of these warrants unexercised.

Maximilian Credit Facility - Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App Energy, LLC (“App”) the Twin Bottoms Field in Lawrence County, Kentucky, 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, and a mortgage on 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 natural 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 6 – 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 Maximilian, 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 had an exercise price of $0.10; include a cash exercise provision; were exercisable for a period of three years expiring on August 28, 2016; and contain an exercise blocker provision that prevents any exercise of the warrants if such exercise and related issuance of common stock would increase the Maximilian holdings of the Company’s common stock to more than 9.99% of the Company’s currently issued and outstanding shares at the time of the exercise.  The Company also granted to Maximilian 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 its Kentucky acreage, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.

On May 28, 2014 at Maximilian’s request, the Company finalized a share-for-warrant exchange agreement in which Maximilian returned to the Company 427,729 common shares and was in turn issued the same number of warrants containing the same provisions as the originally issued warrants.  This share-for-warrant exchange occurred so that Maximilian would hold no more than 9.99% of the Company’s common shares issued and outstanding.  The Company determined that the share-for-warrant exchange did not result in any incremental fair value.

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On August 21, 2014, the Company entered into a First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement (the “Amendment”) with Maximilian under its Amended and Restated Loan and Security Agreement dated as of August 28, 2013.  The Amendment secured for the Company an additional advance of $2,200,000 under its credit facility with Maximilian since the advances made by Maximilian had already exceeded its minimum funding commitment.  Additionally, Maximilian agreed to temporarily decrease the required monthly payment made by the Company until it had paid $1,000,000 less than the principal payments required by the previous agreement.  Furthermore, Maximilian agreed to reduce the regular interest rate applicable to the loan from 12% per annum to 9% per annum and the default interest rate by 3%.

The additional advance, the reduction in the required monthly payment and the reduction in the interest rate were facilitated through the company’s acquisition of 5,694,823 shares of our common stock held by Maximilian.  The repurchased shares were cancelled and restored to the status of authorized, but unissued stock.  The Company paid for the share repurchase transaction through an advance of $1,708,447 under the existing loan agreement with Maximilian.

On May 20, 2015, the Company entered into a Second Amendment to Amended and Restated Loan and Security Agreement (the “2^nd Amendment”) with Maximilian under its Amended and Restated Loan and Security Agreement dated as of August 28, 2013.  The 2^nd Amendment modified the calculation of the required monthly payment for a three-month period ending June 30, 2015.  As consideration for entering into the loan modification, the Company agreed to lower the exercise price of the warrants Maximilian currently holds from $0.10 to $0.04.  No other terms of the warrant agreement were changed.

On October 14, 2015, the Company entered into a Third Amendment to the Amended and Restated Loan and Security Agreement and Second Warrant Amendment with Maximilian, which amended the Company’s loan agreement with Maximilian (the “Maximilian Amendment”).  Pursuant to the Maximilian Amendment, Maximilian agreed to a reduction in the Company’s monthly payments under the loan agreement to $50,000 per month for a period of six months ending on February 29, 2016.  The reduction in monthly payments allows for additional funds to be used by the Company in drilling and completing additional wells in Kentucky.  As consideration for the reduction in the monthly payment amount, the Company agreed that twenty percent (20%) of the amount by which the monthly payment was reduced would be added to the loan balance, and the portion of the monthly payment savings that constitutes savings in interest or commitment fees would be treated as an additional advance of principal under the loan agreement (the “Deemed Advances”).  The Company also agreed to grant to Maximilian an overriding royalty interest of one and one-half percent (1.5%) of its working interest in four wells in Kentucky.  As part of the Maximilian Amendment, the Company also agreed to extend the expiration date of the warrants held by Maximilian to purchase up to 6,550,281 shares of common stock of the Company to August 28, 2018.  The Company determined that the accounting of the loan modification was not substantial.  Likewise the Company determined that the modification of the warrant term did not result in any accounting since these warrants were deemed to be investor warrants.

With the cooperation of Maximilian, the Company is currently working with an investment banking firm to assist in securing refinancing of its debt with Maximilian, since the long-term commitment needed to develop the Kentucky and California projects no longer fits the Maximilian business model.  Due to a decline in crude oil and natural gas revenues, the Company has been unable to make the interest or principal payments required under the terms of the credit facility since December 2015.  The unpaid monthly interest payments and associated fees have been added to the principal balance including the previously discussed 20% fee.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not been made.  During the six months ended August 31, 2016, an additional $1,924,823 in interest and fees were added to the outstanding loan balance.

Due to the waivers granted by Maximilian for the six month period ended August 31, 2016, and for the months September and October 2016, the Company is currently not considered to be in default under terms of the credit facility.  Maximilian is continuing to work with the Company in modifying the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurance this cooperation will continue.  Furthermore, there can be no assurances that Maximilian will not declare the Company to be in default under the terms of the credit facility.  In accordance with the guidance found in ASC-470-10-45, the entire balance of the Maximilian loan is presented under the current liabilities section of the balance sheets.  In accordance with the guidance found ASC 835-35 the net amount of the deferred finance costs are included with the debt discount as a reduction of the loan balance shown on the Balance Sheets as of August 31, 2016 and February 29, 2016, respectively.

The Maximilian loan balances at August 31, 2016 and February 29, 2016 are set forth in the table below:

	August 31, 2016			February 29, 2016
Principal amount	$	16,305,954		$	14,381,131
Less unamortized discount and debt issuance costs		(442,067)			(713,026)
Net Maximilian loan balance	$	15,863,887		$	13,668,105

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App Loan Agreement

In connection with amending and restating its loan agreement with Maximilian, on August 28, 2013 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 natural gas field in Lawrence County, Kentucky pursuant to a Loan and Security Agreement between the Company as lender and App as borrower (the “App Loan Agreement”).

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 Maximilian.  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 App leases in Lawrence County, Kentucky.

The proceeds of the initial borrowing by App of $2.65 million under the App Loan Agreement 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 Twin Bottoms Field in Lawrence County, Kentucky in which the Company has a 25% working interest.  Future advances under the facility would primarily be used for oil and natural 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 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.

On August 21, 2014, a First Amendment to the Loan and Security Agreement by and between the Company and App was executed whereby Section 1.5 (f) of the original Loan and Security Agreement was deleted and intentionally left blank.  The affected section removed App’s ability to have the Required Monthly Payment be equal to zero for a maximum of three payments.  All other terms of the original agreement remained unchanged.

On May 20, 2015, a Second Amendment to the Loan and Security Agreement by and between Daybreak and App was executed whereby the Required Monthly Payment definition was modified for the months of March, April, May and June of 2015.  All other terms of the original agreement remained unchanged.

In connection with entering into the Third Amendment with Maximilian, the Company concurrently entered into a Third Amendment to Loan and Security Agreement with App (the “App Amendment”), which amended the Company’s loan agreement with App in which the Company, as lender, lends to App, as borrower, a portion of the advances it receives pursuant to its loan agreement with Maximilian.  The App Amendment provided for a reduction in interest rate and a reduction in monthly payments to be made by App to the Company for the same payment cycles as the reduced payment to be made by the Company under the Maximilian Amendment.  The reduction in monthly payments by App would allow App to fund its share of drilling and completing additional wells in Kentucky with the Company.  As consideration for the reduction in the monthly payment amount, App agreed that certain amounts would be treated as additional advances under the App Energy loan agreement, and that it would fund a portion of the Company’s drilling and development expenses with respect to two wells.  App also agreed to grant to Maximilian an overriding royalty interest on the same terms as the overriding royalty interest agreed to by the Company.

Due to a decline in crude oil and natural gas revenues, App has been unable to make the interest or principal payments required under the terms of the credit facility with the Company since November 2015.  Unpaid monthly interest and fees have been added to the principal balance of the loan.  A series of waivers have been granted by the Company to App for the principal and interest payments that App has been unable to make.  During the six months ended August 31, 2016, an additional $538,794 in interest and fees has been added to the App outstanding loan balance.

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Due to the waivers granted by the Company to App for the missed principal and interest payments, App is currently not considered to be in default under terms of the credit facility.  The Company is continuing to work with App in modifying the credit facility terms during this period of lower hydrocarbon prices.  As a consequence of App’s inability to make interest and principal payments to the Company, the entire balance of the App loan is presented as a non-current item on the balance sheet at August 31, 2016.

Note receivable balances at August 31, 2016 and February 29, 2016 are set forth in the table below:

	August 31, 2016			February 29, 2016
Note receivable – current	$	-		$	420,901
Note receivable – non-current		5,194,307			4,234,612
	$	5,194,307		$	4,655,513

Capital Commitments

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 current economic downturn in the energy sector, may restrict our ability to obtain needed capital.

Encumbrances

The Company’s debt obligations, pursuant to the loan agreement entered into by and among Maximilian 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 with Maximilian refer to the discussion above under the caption “Current Debt (Short-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.  We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.  Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.

At August 31, 2016, a total of 3,000,000 shares of restricted stock had been awarded under the 2009 Plan, with 2,986,220 shares outstanding and fully vested.  A total of 1,013,780 common stock shares remained available at August 31, 2016 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		417,090		7,910		-
		3,000,000				2,986,220(1)		13,780(2)		-

⁽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.

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For the six months ended August 31, 2016, the Company did not recognize any stock compensation expense related to the above restricted stock grants since all issuances have been fully amortized.

Management Plans to Continue as a Going Concern

The Company 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 36.6% with an average net revenue interest of 28.5%.

Additionally, Daybreak currently has a net revenue interest in 14 producing horizontal oil wells in the Twin Bottoms Field in Lawrence County, Kentucky, with associated natural gas production.  Our average working interest in these 14 oil wells is 22.6% with an average net revenue interest of 19.7%.

We anticipate revenues will continue to increase as the Company participates in the drilling of more wells in the Twin Bottoms Field in Kentucky and the East Slopes Project in California.  However given the current decline and instability in hydrocarbon prices, the timing of any drilling activity in Kentucky and California will be dependent on a sustained improvement in hydrocarbon prices and a successful refinancing or restructuring of our credit facility.

We believe that our liquidity will improve when there is a sustained improvement in hydrocarbon prices.  Our sources of funds in the past have included the debt or equity markets and the sale of assets.  While the Company does have positive cash flow from its oil and natural gas 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, we cannot offer any assurance that we will be successful in executing the aforementioned plans to continue as a going concern.

Our financial statements as of August 31, 2016 do not include any adjustments that might result from the inability to implement or execute Daybreak’s plans to improve our ability 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 29, 2016.

Off-Balance Sheet Arrangements

As of August 31, 2016, 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, August 31, 2016, 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 August 31, 2016.

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 August 31, 2016 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 Form 10-Q Report, you should carefully consider the various factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended February 29, 2016, which could materially affect our business, financial condition or future results.  Our Annual Report is available from the SEC at www.sec.gov.  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 or future results of operations.

ITEM 5.  OTHER INFORMATION

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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

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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.

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