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 nine months ended November 30, 2015 and in our Annual Report on Form 10-K for the year ended February 28, 2015.  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 our Form 10-K for the year ended February 28, 2015; 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 28, 2015 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.

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 interests in our assets may be another source of cash flow.

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 28, 2015 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 7,300 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.  The lateral leg of each well is between 2,000 feet and 4,500 feet in length.  We have an approximate 25% working interest and an approximate net revenue interest (“NRI”) of 21.9% in all horizontal oil wells in this project.  The oil produced from our acreage in Kentucky is light crude oil measuring between 42 ° and 44 ° API gravity.  We are not the Operator of the Twin Bottoms Field project; instead we rely on the experience of the current Operator and its knowledge of this Field.

At November 30, 2015, we had 14 producing horizontal oil wells in the Twin Bottoms Field.  Our first well, the Grove H-1 was put on production in October 2013.  During the year ended February 28, 2014, three additional oil wells, the Grove #H-3, Grove #H-4 and Grove #H-5, were put on production.  Nine additional horizontal oil wells, the Dillon #H-6, Grove #H-7, Grove #H-8, Grove #H-9, Grove #H-10, Jackson #H-20, Lyons #H-23, Lyons #H-24 and the Dillon #H-22, were put on production during the year ended February 28, 2015.  The App Energy #H-33 well was drilled in October 2015 to a measured depth of 5,251 feet and encountered 3,913 feet of oil pay in the Berea Sandstone.  Our average working interest and NRI in these 14 producing horizontal oil wells is 22.6% and 19.7%, respectively.

In August 2015, we drilled the vertical leg portion of the Murray #H-34 well.  The well was logged and data was collected for use in the drilling of the App Energy #H-33 well.   The Company paid 12.5% of the drilling and completion cost for a 25% working interest in the App Energy H-33 and Murray #H-34 wells as part of the App Amendment.  The horizontal portion of the Murray #H-34 well will be drilled at a later date.

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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 begin until there is a sustained improvement in crude oil prices and additional financing is put in place.   We do not plan to make any capital investments in the Twin Bottoms Field project area during the remainder of the 2015-2016 fiscal year.

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.  We have been the Operator at the East Slopes Project since March 2009.

Our 20 oil wells in the East Slopes Project produce from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations.  The Sunday property has six producing wells, while the Bear property has nine producing wells.  The Black property is the smallest of all currently producing reservoirs, and currently has two producing wells at this property.  The Ball property also has two producing wells while the Dyer Creek property has one producing well.  Our average working interest and NRI in these 20 producing oil wells is 36.6% and 28.5%, respectively.  There are several other similar prospects on trend with the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic characteristics.  Some of these prospects, if successful, would utilize the Company’s existing production facilities.  In addition to the current field development, there are several other exploratory prospects that have been identified from the seismic data, which we plan to drill in the future.

Sunday Central Processing and Storage Facility

The oil produced from our acreage in California is considered heavy oil.  The oil ranges from 14 ° to 16 ° API (American Petroleum Institute) gravity.  All of the oil from our five producing properties is processed, stored and sold from the Sunday central processing and storage facility.  The oil must be heated to separate and remove water to prepare it to be sold.  We constructed these facilities during the summer and fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines.  In 2013, we completed an upgrade to this facility including the addition of a second oil storage tank to handle the additional oil production from the wells drilled in 2013.

By utilizing the Sunday centralized production facility our average operating costs have been reduced from over $40 per barrel in 2009 to a monthly average of approximately $12 per barrel of oil for the nine months ended November 30, 2015.  With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

Exploration Properties

Bull Run Prospect

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Etchegoin and Santa Margarita sands located between 800 and 1,200 feet deep.  Utilizing the data received from a previously drilled well that was not commercially successful, we expect to drill another exploratory well on this prospect in the future.  Future Bull Run wells will require a pilot steam flood and production facilities.  We estimate that the Bull Run prospect is 70 acres in size.  We have a 37.5% working interest in this prospect.

Sherman Prospect

This prospect is also located in the southern portion of our acreage position.  The drilling targets are the Olcese and Etchegoin sands between 1,000 and 2,000 feet deep.  We estimate that the Sherman Prospect is 100 acres in size.  The Company is currently seeking an extension of the leases in this prospect which expire in May 2016.  We have a 37.5% working interest in this prospect.

Tobias Prospect

This prospect is also located in the central portion of our acreage position.  The drilling targets are the Vedder and Eocene sands between 2,000 and 4,500 feet deep.  This prospect be drilled in the future.  We estimate that the Tobias prospect is 60 acres in size.  We have a 37.5% working interest in this prospect.

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California Drilling Plans

Future drilling plans include a combination of both exploratory drilling and development well drilling.  Planned drilling activity and implementation of our full development plan will not begin until there is a sustained improvement in crude oil prices and additional financing is put in place.  We do not plan to make any capital investments in the East Slopes Project during the rest of the 2015-2016 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 “Non-current Borrowings” in this MD&A.

Results of Operations – Nine Months Ended November 30, 2015 compared to the Nine Months Ended November 30, 2014

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 76% 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.

Kentucky Oil Prices

For the nine months ended November 30, 2015, our average realized oil sale price was $49.38 in comparison to the average WTI price of $49.94 representing a discount of $0.56 per barrel or 1.1% lower than the average WTI price.  In comparison, for the nine months ended November 30, 2014, the average WTI price was $96.04 and our average realized sale price was $95.48 representing a discount of $0.56 per barrel or 0.6% lower than the average WTI price.

Kentucky Natural Gas Prices

For the nine months ended November 30, 2015, our average realized natural gas sale price was $1.62 per Mcf (thousand cubic feet) in comparison to the average Henry Hub price of $2.64 per million BTU representing a discount of $1.02 per Mcf or 38.6% lower than the average Henry Hub price.  In comparison, for the nine months ended November 30, 2014, the average realized sale price was $3.01 per Mcf in comparison to the average Henry Hub price of $4.28 per million BTU representing a discount of $1.27 or 29.7% lower than the average Henry Hub price.

California Oil Prices

For the nine months ended November 30, 2015, the average WTI price was $49.94 and our average realized oil sale price was $41.89, representing a discount of $8.05 per barrel or 16.1% lower than the average WTI price.  In comparison, for the nine months ended November 30, 2014, the average WTI price was $96.04 and our average realized sale price was $89.10 representing a discount of $6.94 per barrel or 7.2% 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.

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Total Oil and Natural Gas Revenue and Production

Our revenues are derived entirely from the sale of our share of oil production in Kentucky and California and natural gas sales in Kentucky. Oil and natural gas revenues for the nine months ended November 30, 2015 in aggregate decreased $1,430,925 or 56.8%, to $1,087,450 in comparison to revenues of $2,518,375 for the nine months ended November 30, 2014.  Oil and natural gas sales volume decreased 2,520 BOE (barrels of oil equivalent) or 8.6% to 26,528 (BOE) in comparison to 29,048 (BOE) for the nine months ended November 30, 2014.  The decrease in volume was due to the natural decline in oil producing reservoir pressure.  Our average realized sale price on a BOE basis for the nine months ended November 30, 2015 was $40.99 in comparison to $86.75 for the nine months ended November 30, 2014, representing a decline of $45.76 or 52.8% per barrel.

Kentucky Oil Revenue and Production

Production in Kentucky is from horizontal oil wells in consolidated shale sands that are characterized by large initial production volumes that decline quite rapidly to a much lower and more stable long-term production volume.  Fluctuations in revenue are closely linked to both production volumes and crude oil prices.  Our first oil sales in Kentucky occurred in October 2013.  Oil revenue in Kentucky for the nine months ended November 30, 2015 decreased $754,841 or 55.7% to $601,339 in comparison to revenue of $1,356,180 for the nine months ended November 30, 2014.  The average realized sale price of a barrel of oil for the nine months ended November 30, 2015 was $49.38 in comparison to $95.48 for the nine months ended November 30, 2014.  The decrease of $46.11 or 48.3% in the average sale price of a barrel of oil was responsible for 86.8% of the decline in Kentucky oil revenue for the nine months ended November 30, 2015.

Our net sales volume in the nine months ended November 30, 2015 was 12,179 barrels of oil in comparison to 14,221 barrels sold during the nine months ended November 30, 2014.  This decrease in oil sales volume of 2,042 barrels or 14.4% was responsible for 13.2% of the decline in Kentucky oil revenue for the nine months ended November 30, 2015.

The API gravity of our produced oil in Kentucky ranges between 42° API and 44° API.  Production for the nine months ended November 30, 2015 was from 14 wells resulting in 3,274 well days of production in comparison to 1,709 well days from 10 horizontal oil wells during the nine months ended November 30, 2014.

Kentucky Natural Gas Revenue and Production

Natural gas production is a by-product from our horizontal oil wells and the volume varies on a well-to-well basis.   Our first natural gas sales in Kentucky also occurred in October 2013.  Natural gas revenue for the nine months ended November 30, 2015 decreased $4,583 to $34,752 in comparison to revenue of $39,335 for the nine months ended November 30, 2014.  The average realized sale price per Mcf for the nine months ended November 30, 2015 was $1.62 in comparison to $3.01 for the nine months ended November 30, 2014.

Our net sales volume in the nine months ended November 30, 2015 was 21,443 Mcf or 3,574 BOE in comparison to 13,350 Mcf or 2,225 BOE during the nine months ended November 30, 2014.  The increase of 8,093 MCF or 1,349 BOE representing a 60.6% increase was due to infrastructure improvements that had previously inhibited natural gas production from existing wells.

California Revenue and Production

Production in California is from vertical oil wells that historically produce at relatively stable levels over time.  Fluctuations in revenue are generally more dependent on the price of crude oil and the timing of oil sales rather than oil production volumes.  Oil revenue in California for the nine months ended November 30, 2015 decreased $671,501 or 59.8% to $451,359 in comparison to revenue of $1,122,860 for the nine months ended November 30, 2014.  The average realized sale price of a barrel of oil for the nine months ended November 30, 2015 was $41.89 in comparison to $89.10 for the nine months ended November 30, 2014.  The decrease of $47.22 or 53.0% in the average realized sale price of a barrel of oil accounted for 88.6% of the decrease in California oil revenue for the nine months ended November 30, 2015.

Our net sales volume in the nine months ended November 30, 2015 was 10,775 barrels of oil in comparison to 12,602 barrels sold during the nine months ended August 31, 2014.  This decrease in oil sales volume of 1,827 barrels or 14.5% accounted for 11.4% of the decrease in California oil revenue for the nine months ended November 30, 2015.  The decrease in volume was due to natural decline in the oil producing reservoirs.

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The gravity of our produced oil in California ranges between 14° API and 16° API.  Production for the nine months ended November 30, 2015 was from 20 wells resulting in 5,410 well days of production in comparison to 5,482 of production from 20 wells for the nine months ended November 30, 2014.

Oil and natural gas revenues for the nine months ended November 30, 2015 and 2014 are set forth in the table below:

*Our average realized sale price on a BOE basis for the nine months ended November 30, 2015 was $40.99 in comparison to $86.75 for the nine months ended November 30, 2014, representing a decline of $45.76 or 52.8% per barrel.

Operating Expenses .  Total operating expenses for the nine months ended November 30, 2015 decreased by $127,503 or 8.2% to $1,420,624 in comparison to $1,548,127 for the nine months ended November 30, 2014.

Operating expenses for the nine months ended November 30, 2015 and November 30, 2014 are set forth in the table below:

Production expenses include expenses associated with the production of oil and natural gas.  These expenses include pumper salaries, 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 nine months ended November 30, 2015, these expenses decreased by $43,382 or 17.2% to $208,243 in comparison to $251,625 for the nine months ended November 30, 2014.  For the nine months ended November 30, 2015 we had 20 wells on production in California and 14 wells on production in Kentucky in comparison to 20 wells in California and 10 wells in Kentucky for the nine months ended November 30, 2014.  Production expenses represented 14.7% of total operating expenses.

Production expenses in Kentucky and California for the nine months ended November 30, 2015 and November 30, 2014 are set forth in the table below:

Production expenses on a BOE basis in Kentucky and California for the nine months ended November 30, 2015 and November 30, 2014 are set forth in the table below:

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Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses increased $9,651 or 47.8% to $29,823 for the nine months ended November 30, 2015 in comparison to $20,172 the nine months ended November 30, 2014 primarily due to additional G&G work in Kentucky.  Exploration and drilling expenses represented 2.1% of total operating expenses.

DD&A expenses relate to equipment, proven reserves and property costs, along with impairment and is another component of operating expenses.  For the nine months ended November 30, 2015, DD&A expenses decreased $26,668 or 6.3% to $399,698 in comparison to $426,366 for the nine months ended November 30, 2014.  The decrease in DD&A is directly related to the level of our hydrocarbon production in both Kentucky and California offset by additional impairment in California of $34,744.  On a BOE basis, DD&A and impairment represented $15.07 and $14.68 per barrel for the nine months ended November 30, 2015 and 2014, respectively.  DD&A expenses represented 28.1% of total operating expenses.

G&A expenses include the salaries of six full-time employees, including management.  Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and natural gas properties as well as for running a public company.  For the nine months ended November 30, 2015, G&A expenses decreased $67,104 or 7.9% to $782,860 in comparison to $849,964 for the nine months ended November 30, 2014.  We received, as Operator in California, administrative overhead reimbursement of $39,965 during the nine months ended November 30, 2015 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 55.1% of total operating expenses.

Interest income for the nine months ended November 30, 2015 decreased $70,078 or 8.4% to $763,700 in comparison to $833,778 for the nine months ended November 30, 2014 due to reduced interest rates and modification of the Note receivable from App Energy. For further discussion on the App Energy Note refer to the discussion of the App Loan Agreement under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-term Borrowings) in this MD&A.

Interest expense for the nine months ended November 30, 2015 increased $231,151 or 11.1% to $2,312,741 in comparison to $2,081,590 for the nine months ended November 30, 2014.  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 in the  MD&A section of this 10-Q report under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-term Borrowings) in this MD&A.

Results of Operations – Three Months Ended November 30, 2015 compared to the Three Months Ended November 30, 2014

Kentucky Oil Prices

For the three months ended November 30, 2015, our average realized oil sale price was $43.66 in comparison to the average WTI price of $44.70 representing a discount of $1.04 per barrel or 2.3% from the average WTI price.  In comparison, for the three months ended November 30, 2014 the average WTI price was $84.47 and our average realized sale price was $84.11, representing a discount of $0.36 per barrel or 0.4% lower than the average WTI prices.

Kentucky Natural Gas Prices

For the three months ended November 30, 2015, our average realized natural gas sale price was $1.33 per Mcf in comparison to the average Henry Hub price of $2.36 per million BTU representing a discount of $1.03 per Mcf or 43.5% lower than the average Henry Hub price.  In comparison, for the three months ended November 30, 2014, the average realized sale price was $3.15 per Mcf while the average Henry Hub price was $3.94 per million BTU representing a discount of $0.79 or 20.0% lower than the average Henry Hub price.

California Oil Prices

For the three months ended November 30, 2015, the average WTI price was $44.70 and our average realized oil sale price was $35.88 representing a discount of $8.82 per barrel or 19.7% lower than the average WTI price.  In comparison, for the three months ended November 30, 2014, the average WTI price was $84.47 and our average realized sale price was $75.80, representing a discount of $8.67 per barrel or 10.3% lower than the average WTI price.

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Total Oil and Natural Gas Revenue and Production

Oil and natural gas revenues for the three months ended November 30, 2015 in aggregate decreased $387,318 or 58.4%, to $276,332 in comparison to revenues of $663,650 for the three months ended November 30, 2014.  Oil and natural gas sales volume decreased 1,272 BOE (barrels of oil equivalent) or 13.9% to 7,891 (BOE) in comparison to 9,163 (BOE) for the three months ended November 30, 2014.  Our average realized sale price on a BOE basis for the three months ended November 30, 2015 was $35.02 in comparison to $72.43 for the three months ended November 30, 2014, representing a decline of $37.41 or 51.6% per barrel.

Kentucky Oil Revenue and Production

Oil revenue in Kentucky for the three months ended November 30, 2015 decreased $197,255 or 59.0% to $136,901 in comparison to revenue of $334,156 for the three months ended November 30, 2014.  The average realized sale price of a barrel of oil for the three months ended November 30, 2015 was $43.66 in comparison to $84.11 for the three months ended November 30, 2014.  The decrease of $40.46 or 48.1% in the average sale price of a barrel of oil accounted for 81.5% of the decline in Kentucky oil revenue for the three months ended November 30, 2015.

Our net sales volume for the three months ended November 30, 2015 was 3,136 barrels of oil in comparison to 3,991 barrels sold for the three months ended August 31, 2014.  This decrease in oil sales volume of 855 barrels or 21.4% accounted for 18.5% of the decline in Kentucky oil revenue for the three months ended November 30, 2015.

Production for the three months ended November 30, 2015 was from 14 wells resulting in 1,102 well days of production in comparison to 776 well days from 10 horizontal oil wells during for the three months ended November 30, 2014.

Kentucky Natural Gas Revenue and Production

Natural gas revenue for the three months ended November 30, 2015 decreased $11,858 to $8,948 in comparison to revenue of $20,806 for the three months ended November 30, 2014.  The average realized sale price per Mcf for the three months ended November 30, 2015 was $1.33 in comparison to $3.15 for the three months ended November 30, 2014.  Our net sales volume for the three months ended November 30, 2015 was 6,710 Mcf or 1,118 BOE in comparison to 6,599 Mcf or 1,100 BOE for the three months ended November 30, 2014.  The increase in natural gas volume of 112 or 19 BOE representing a 1.7% increase was due to infrastructure improvements that had previously inhibited natural gas production from existing wells.

California Revenue and Production

Oil revenue in California for the three months ended November 30, 2015 decreased $178,205 or 57.7% to $130,483 in comparison to revenue of $308,688 for the three months ended November 30, 2014.  The average realized sale price of a barrel of oil for the three months ended November 30, 2015 was $35.88 in comparison to $75.80 for the three months ended November 30, 2014.  The decrease of $39.92 or 52.7% in the average realized sale price of a barrel of oil accounted for 91.2% of the decrease in California oil revenue for the three months ended November 30, 2015.

Our net sales volume for the three months ended November 30, 2015 was 3,637 barrels of oil in comparison to 4,072 barrels sold for the three months ended November 30, 2014.  This decrease in oil sales volume of 435 barrels or 10.7% accounted for 8.8% of the decrease in revenue for the three months ended November 30, 2015.  Production for the three months ended November 30, 2015 was from 20 wells resulting in 1,748 well days of production in comparison to 1,816 of production from 20 wells for the three months ended November 30, 2014.

Oil and natural gas revenues for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:

*Our average realized sale price on a BOE basis for the three months ended November 30, 2015 was $35.02 in comparison to $72.43 for the three months ended November 30, 2014, representing a decline of $37.41 or 51.6% per barrel.

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Operating Expenses .  Total operating expenses for the three months ended November 30, 2015 increased by $4,304 or 0.9% to $462,719 in comparison to $458,415 for the three months ended November 30, 2014.

Operating expenses for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:

For the three months ended November 30, 2015, production expenses decreased by $23,503 or 27.3% to $62,637 in comparison to $86,140 for the three months ended November 30, 2014.  For the three months ended November 30, 2014 we had 20 wells on production in California and 14 wells on production in Kentucky in comparison to 20 wells in California and 10 wells in Kentucky for the three months ended November 30, 2014.  Production expenses represented 13.5% of total operating expenses for the three months ended November 30, 2015.

Production expenses in Kentucky and California for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:

Production expenses on a BOE basis in Kentucky and California for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:

For the three months ended November 30, 2015, exploration and drilling expenses increased $2,394 or 32.5% to $9,756 in comparison to $7,362 for the three months ended November 30, 2014.  Exploration and drilling expenses represented 2.1% of total operating expenses for the three months ended November 30, 2015.

For the three months ended November 30, 2015, DD&A expenses increased $7,096 or 5.3% to $141,969 in comparison to $134,873 for the three months ended November 30, 2014.  The increase in DD&A is directly related to the recognition of $34,744 in property impairment in California offset by lower hydrocarbon production volumes in both Kentucky and California.  On a BOE basis, DD&A and impairment represented $17.99 and $14.75 per barrel for the three months ended November 30, 2015 and 2014, respectively.  DD&A expenses represented 30.7% of total operating expenses for the three months ended November 30, 2015.

For the three months ended November 30, 2015, G&A expenses increased $18,317 or 8.0% to $248,357 in comparison to $230,040 for the three months ended November 30, 2014.  We received, as Operator in California, administrative overhead reimbursement of $13,322 during the three months ended November 30, 2015 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 53.7% of total operating expenses for the three months ended November 30, 2015.

Interest income for the three months ended November 30, 2015 decreased $39,836 or 10.5% to $339,096 in comparison to $378,932 for the three months ended November 30, 2014 due to reduced loan balances on the Note receivable from App Energy.

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Interest expense for the three months ended November 30, 2015 increased $263,684 or 36.7% to $982,270 in comparison to $718,586 for the three months ended November 30, 2014.  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 in the MD&A section of this 10-Q report under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-term Borrowings).

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 reserves base.  Our ability to fund any future capital expenditure programs is dependent upon the prices we receive from oil sales, the success of our exploration and development program in Lawrence County, Kentucky and Kern County, California and the availability of capital resource financing.

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.

Changes in our capital resources at November 30, 2015 in comparison to February 28, 2015 are set forth in the table below:

Our working capital deficit decreased $94,130 or 1.6% to $5,851,152 at November 30, 2015 in comparison to $5,757,022 at February 28, 2015.  This decrease in the working capital deficit was due to reclassification of part of the current portion of the Maximilian credit facility debt to non-current debt due to a loan modification with Maximilian during the nine months ended November 30, 2015.  While we have ongoing positive cash flow from our operations in California and Kentucky we have not yet been able to generate sufficient cash flow to cover all of our G&A and interest expense requirements on a consistent basis.

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 and equity markets, as well as select asset sales.  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.

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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 decline of hydrocarbon prices, may restrict our ability to obtain needed capital.

The Company’s financial statements for the nine months ended November 30, 2015 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 November 30, 2015, we have an accumulated deficit of $30,087,731 and a working capital deficit of $5,851,152 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 interests in our assets may be another source of cash flow.

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 nine months ended November 30, 2015, we had a cash flow deficit in operating activities of $438,547 in comparison to cash flow provided by operating activities of $254,645 for the nine months ended November 30, 2014.  This decline in operating cash flow of 693,192 or 272.2% is directly related to lower realized hydrocarbon revenues from the sharp decline of approximately 64% in crude oil prices since June of 2014.  Non-cash account balances relating to DD&A; amortization of debt discount and deferred financing costs accounted for a represented $820,338 in aggregate for the nine months ended November 30, 2015.  Changes in our receivables, prepaids and payables balances accounted for a net increase of approximately $623,330 in our cash flow, but were offset by the increase in the net loss of approximately $1.9 million for the nine months ended November 30, 2015.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash Flow Provided by (Used in) Investing Activities

Cash flow from investing activities is derived from changes in oil and gas property balances and our lending activities associated with the App Energy loan. Cash flow provided by investing activities for the nine months ended November 30, 2015 was $670,237, a change of $4,057,956 from the $3,387,719 used in investing activities for the nine months ended November 30, 2014.   This change of $4,057,956 was due to less drilling activity because of lower hydrocarbon prices and reduced lending to App Energy for the nine months ended November 30, 2015.  The credit facility and our lending activity to App Energy is discussed further in the MD&A section of this 10-Q report under the caption “Long-Term Borrowings – Maximilian Credit Facility.”

Cash Flow Provided by (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 used in our financing activities was $619,816 for the nine months ended November 30, 2015 in comparison to cash flow provided by our financing activities of approximately $3.2 million for the nine months ended November 30, 2014.  This change of $3,773,485 was due to less drilling activity because of lower hydrocarbon prices for the nine months ended November 30, 2015 resulting in less borrowing through our credit facility with Maximilian.  The credit facility and our lending activity to App Energy is discussed further in the MD&A section of this 10-Q report discussed further in the discussion of the

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Maximilian Credit Facility – Amended and Restated Loan Agreement in the MD&A section of this 10-Q report under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-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 November 30, 2015.

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 November 30, 2015, the Line of Credit had an outstanding balance of $853,136.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $28,770 for the nine months ended November 30, 2015.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.

Non-current Debt (Long-Term Borrowings)

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 November 30, 2015 and February 28, 2015 are set forth in the table below:

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.

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Maximilian 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 $100,896 for the nine months ended November 30, 2015.  Unamortized debt discount amounted to $103,168 at November 30, 2015.

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 November 30, 2015, 316,617 of these warrants remain unexercised.

Maximilian Credit Facility - Amended and Restated Loan Agreement

In connection with the Company’s acquisition of a working interest from App 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, as borrower pursuant to a Loan and Security Agreement entered into between the Company and App on August 28, 2013 (See Note 8 – 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 have an exercise price of $0.10; contain a cash exercise provision and are exercisable for a period of three years expiring on August 28, 2016; 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 “First Amendment”) with Maximilian.  The First 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 has 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 “Second Amendment”) with Maximilian.  The Second 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, (the “Third Amendment”).  Pursuant to the Third 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 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 1.5% of its working interest in four wells in Kentucky.  As part of the Third 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 modification of the warrant expiration date did not result in any incremental fair value.

With the assistance 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.  Maximilian is continuing to work with the Company in modifying the credit facility terms during this period of lower hydrocarbon prices.

Current debt balances at November 30, 2015 and February 28, 2015 are set forth in the table below:

Non-current debt balances at November 30, 2015 and February 28, 2015 are set forth in the table below:

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 Energy”) 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 Energy as borrower (the “App Loan Agreement”).

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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 Energy, 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 Energy, including the App Energy leases in Lawrence County, Kentucky.

The proceeds of the initial borrowing by App Energy of $2.65 million under the App Energy facility were primarily used to (a) pay loan fees and closing costs, (b) repay indebtedness and (c) finance the drilling of three wells by App Energy in the Twin Bottoms Field in Lawrence County, Kentucky in which the Company has a 25% working interest.  Future advances under the facility will 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 Energy’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 Energy’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 Energy also granted to the Company a 25% working interest in approximately 6,400 acres (currently 7,300 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 Energy’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 Energy’s affiliates.

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 Energy (the “App Amendment”), which amended the Company’s loan agreement with App Energy in which the Company, as lender, lends to App Energy, as borrower, a portion of the advances it receives pursuant to its loan agreement with Maximilian.  The App Amendment provides for a reduction in interest rate and a reduction in monthly payments to be made by App Energy 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 Energy will allow App Energy 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 Energy agreed that certain amounts will 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 Energy also agreed to grant to Maximilian an overriding royalty interest on the same terms as the overriding royalty interest agreed to by the Company.  

Note receivable balances at November 30, 2015 and February 28, 2015 are set forth in the table below:

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 economic downturn, may restrict our ability to obtain needed capital.

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Encumbrances

The Company’s debt obligations, pursuant to the loan agreement with Maximilian, 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 of the Maximilian Credit Facility – Amended and Restated Loan Agreement in the  MD&A section of this 10-Q report under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-term Borrowings) in this MD&A.

Restricted Stock and Restricted Stock Unit Plan

On April 6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted common stock and restricted common stock unit awards.  Subject to adjustment, the total number of shares of Daybreak common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.  We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.  Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.

At November 30, 2015, a total of 3,000,000 shares of restricted stock had been awarded and remained outstanding under the 2009 Plan, with 2,986,220 shares having fully vested.  A total of 1,013,780 common stock shares remained available at August 31, 2015 for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan issuances is set forth in the table below:

⁽¹⁾

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

⁽²⁾

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

For the nine months ended November 30, 2015, 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

We continue to implement plans to enhance Daybreak’s ability 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% for these same wells.  Additionally, Daybreak currently has a net revenue interest in 14 producing horizontal oil wells in the Twin Bottoms Field in Lawrence County, Kentucky.  Our average working interest in these 14 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 Kentucky and California.  Daybreak plans to continue its development drilling program at a rate that is compatible with its cash flow, funding opportunities and hydrocarbon prices.

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

Critical Accounting Policies

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2015.

Off-Balance Sheet Arrangements

As of November 30, 2015, 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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