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EX-99 - EXHIBIT 99.1 - DAYBREAK OIL & GAS, INC.exhibit991.htm
EX-31 - EXHIBIT 31.1 - DAYBREAK OIL & GAS, INC.exhibit311.htm
EX-32 - EXHIBIT 32.1 - DAYBREAK OIL & GAS, INC.exhibit321.htm
EX-23 - EXHIBIT 23.2 - DAYBREAK OIL & GAS, INC.exhibit232.htm
EX-23 - EXHIBIT 23.1 - DAYBREAK OIL & GAS, INC.exhibit231.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


(Mark One)


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


For the fiscal year ended February 29, 2016


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)


Registrant’s telephone number, including area code:  (509) 232-7674


Securities registered pursuant to Section 12(b) of the Exchange Act:  None


Securities registered pursuant to Section 12(g) of the Exchange Act:  Common Stock, $.001 par value


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ¨  No þ


Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes ¨  No þ


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.  Yes þ  No ¨


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨


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 ¨

Smaller reporting company þ


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


The aggregate market value of the voting and non-voting stock held by non-affiliates of the registrant, based on the closing price of $0.04 on August 31, 2015, as reported by the Over-the-Counter Market was $1,970,295.


At May 26, 2016, the registrant had 51,487,373 outstanding shares of $0.001 par value common stock.


DOCUMENTS INCORPORATED BY REFERENCE:


None.






TABLE OF CONTENTS



 

 

PAGE

 

 

 

PART I

 

4

 

 

 

ITEM 1.

BUSINESS

4

ITEM 1A.

RISK FACTORS

9

ITEM 1B.

UNRESOLVED STAFF COMMENTS

19

ITEM 2.

PROPERTIES

20

ITEM 3.

LEGAL PROCEEDINGS

27

ITEM 4.

MINE SAFETY DISCLOSURES

27

 

 

 

PART II

 

28

 

 

 

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

28

ITEM 6.

SELECTED FINANCIAL DATA

36

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

37

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

53

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

54

 

Balance Sheets as of February 29, 2016 and February 28, 2015

55

 

Statements of Operations for the Years Ended February 29, 2016 and February 28, 2015

56

 

Statements of Changes in Stockholders’ Deficit for the Years Ended February 29, 2016 and February 28, 2015

57

 

Statements of Cash Flows for the Years Ended February 29, 2016 and February 28, 2015

58

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

80

ITEM 9A.

CONTROLS AND PROCEDURES

81

ITEM 9B.

OTHER INFORMATION

82

 

 

 

PART III

 

83

 

 

 

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

83

ITEM 11.

EXECUTIVE COMPENSATION

88

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

93

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

95

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

97

 

 

 

PART IV

 

98

 

 

 

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

98

 

 

 

GLOSSARY OF TERMS

100

SIGNATURES

102





2





CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS


This annual report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  Forward-looking statements include statements relating to future events or our future financial or operating performance, including statements regarding guidance, industry prospects or future results of operations or financial position, made in this Annual Report on Form 10-K.  These forward-looking statements are based on our current expectations, assumptions, estimates and projections for the future of our business and our industry and 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 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;

·

Changes to our reserve estimates or the recovery of oil and gas quantities that is less than our reserve estimates;

·

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-K; in our other public filings and press releases; and discussions with Company management.


Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  These risks and uncertainties, as well as other risks and uncertainties that could cause our actual results to differ significantly from management’s expectations, are described in greater detail in Item 1A of Part 1, “Risk Factors”.  We specifically undertake no obligation to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except as required by law.


All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.



3




PART I


ITEM 1.   BUSINESS


Historical Background


Daybreak Oil and Gas, Inc. (referred to herein as “we,” “our,” “us,” “Daybreak” or the “Company”) was originally incorporated in the State of Washington on March 11, 1955 as Daybreak Uranium, Inc.  The Company was organized to explore for, acquire and develop mineral properties throughout the Western United States.  In August 1955, we acquired the assets of Morning Sun Uranium, Inc.  By the late 1950’s, we ceased to be a producing mining company and thereafter engaged in mineral exploration only.  In May 1964, to reflect the diversity of our mineral holdings, we changed our name to Daybreak Mines, Inc.  By February 1967, we had ceased all exploration operations.  After that time, our activities were confined to annual assessment and maintenance work on our Idaho mineral properties and other general and administrative functions.  In November 2004, we sold our last remaining mineral rights covering approximately 340 acres in Shoshone County, Idaho.


Effective March 1, 2005, we undertook a new business direction for the Company; that of an exploration, development and production company in the oil and natural gas industry.  In October of 2005, to better reflect this new direction of the Company, our shareholders approved changing our name to Daybreak Oil and Gas, Inc.  Our Common Stock is quoted on the OTC Pink marketplace under the symbol DBRM.


Our corporate office is located at 1101 N. Argonne Road, Suite A 211, Spokane Valley, Washington 99212-2699.  Our telephone number is (509) 232-7674.  Additionally, we have a regional operations office located at 1414 S. Friendswood Dr., Suite 212, Friendswood, Texas 77546.  The telephone number of our office in Friendswood is (281) 996-4176.


Oil and Natural Gas 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 long-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 price 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, does have a material adverse effect on our results of operations and financial condition.


The Company’s focus is to pursue oil and natural gas drilling opportunities through joint ventures with industry partners as a means of limiting our drilling risk.  Prospects are generally brought to us by other oil and natural gas companies or individuals.  We identify and evaluate prospective oil and natural gas properties to determine both the degree of risk and the commercial potential of the project.  We seek projects that offer a mix of low risk with a potential of steady reliable revenue as well as projects with a higher risk, but that may also have a larger return.  Modern technology including 3-D seismic helps us identify potential oil and natural gas reservoirs and to mitigate our risk.  Currently, our core areas of activity are located in Lawrence County, Kentucky and Kern County, California although new opportunities may ultimately be secured in other areas.  We seek to maximize the value of our asset base by exploring and developing properties that have both production and reserve growth potential.


In some instances, such as with our California operations, we strive to be the operator of our oil and gas properties.  As the operator, we are more directly in control of the timing; costs of drilling and completion; and production operations on our projects.  In other instances, such as with our Kentucky properties, we may not serve as operator where we have concluded that the existing operator has existing operational knowledge, equipment and personnel in place, and operates competently and prudently and with the same operational goals that we would have if we served as operator.  However, we have our own personnel onsite during critical operations such as drillings, fracturing and completing operations.




4



Known Trends and Uncertainties


As we continue to pursue our exploratory and development drilling programs in our Kentucky and California properties the timing of these activities continues to be determined by current oil and natural gas prices; the availability of funds through our lending facility; and in California, the drilling permit approval process.  Additionally, our drilling programs are also very sensitive to drilling costs.  We attempt to control these costs through drilling efficiencies by working with service providers to receive acceptable unit costs.


In order to continue our drilling programs in Kentucky and California, we must be able to realize an acceptable margin between our expected cash flows from new production and the cost to drill and complete new wells.  If any combination of a decrease in oil and natural gas prices; the availability of drilling funds; and/or, the rising costs of drilling, completion and other field services occurs in future periods, we may be forced to modify or discontinue a planned drilling program.


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 and price of 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.


Because of the size of our Company, we are highly susceptible to downward changes in the price we receive for our hydrocarbon sales especially crude oil.  There has been a significant amount of volatility and dramatic decline in our realized sale price for both oil and natural gas since June of 2014.  The decline in the price of crude oil as shown below has had a substantial negative impact on our cash flow from both our Kentucky and California properties.

 

 

 

February 2016

 

June 2014

 

Percentage Decline

Average WTI crude oil price

 

$

30.32

 

$

105.79

 

71.3%

Average realized crude oil sales price (Bbl)

 

$

24.20

 

$

101.45

 

76.1%


Crude Oil and Natural Gas Prices and Revenue


Our realized crude oil and natural gas prices and revenues for the year ended February 29, 2016 have dramatically declined from the year ended February 28, 2015 as detailed in the table below:


 

 

Year Ended

February 29, 2016

 

Year Ended

February 28, 2015

 

Percentage

Decline

Annual realized price of crude oil (Bbl)

 

$

42.00

 

$

79.75

 

47.3%

Annual realized price of natural gas (Mcf)

 

$

1.51

 

$

2.97

 

49.2%

Annual realized price (BOE)

 

$

37.28

 

$

74.35

 

49.9%

Annual oil and natural gas revenue

 

$

1,253,686

 

$

3,083,797

 

59.3%


For the year ended February 29, 2016 crude oil and natural gas revenues declined $1,830,111 in aggregate to $1,253,686.  Of the $1,830,111 decline in revenue approximately 84.0% of the decline can be directly attributed to the sharp decline in hydrocarbon prices.  It is beyond our control and ability to accurately predict how long hydrocarbon prices will continue to decline; when or at what level they may begin to stabilize; or when they may start to rebound as there are many factors beyond our control that dictate the price we receive on our hydrocarbon sales.


The decline in hydrocarbon prices that we are currently experiencing has had a material adverse effect on our cash flows, reserves valuation and availability of funds in the financial markets.  As a result, we are currently unable to make the interest or principal payments required under the terms of our credit facility with our lender, Maximilian Resources, LLC.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not been made.  Due to the waivers granted by Maximilian, 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 assurances that this cooperation will continue.  Further, there can be no assurances that Maximilian will not declare the Company to be in default under the credit facility.




5



Competition


We compete with other independent oil and natural gas companies for exploration prospects, property acquisitions and for the equipment and labor required to operate and develop these properties.  Many of our competitors have substantially greater financial and other resources than we have.  These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can.


We conduct all of our drilling, exploration and production activities onshore in the United States.  All of our oil and natural gas assets are located in the United States and all of our revenues are from sales to customers within the United States.


Significant Customers


At our Twin Bottoms Field project located in Lawrence County, Kentucky, there is only one buyer available for the purchase of our oil production and only one buyer available for the purchase of our natural gas production.  Similarly, at our East Slopes Project, located in Kern County, California, there is only one buyer available for the purchase of our oil production.  At February 29, 2016, these three individual customers in aggregate represented 100% of crude oil and natural gas sales receivable.  If these local purchasers are unable to resell their products or if they lose a significant sales contract then we may incur difficulties in selling our oil and natural gas production.


The Company’s accounts receivable from Kentucky and California for oil and natural gas sales at February 29, 2016 and February 28, 2015 are set forth in the table below.


 

 

 

 

February 29, 2016

 

February 28, 2015

Project

 

Customer

 

Revenue

Receivable

 

Percentage

 

Revenue

Receivable

 

Percentage

Kentucky – Twin Bottoms Field (Oil)

 

Appalachian Oil

 

$

23,257

 

33.6%

 

$

90,906

 

44.9%

Kentucky – Twin Bottoms Field (Natural gas)

 

Jefferson Gas

 

 

6,767

 

9.8%

 

 

16,676

 

8.2%

California – East Slopes Project (Oil)

 

Plains Marketing

 

 

39,168

 

56.6%

 

 

95,150

 

46.9%

 

 

 

 

$

69,192

 

100.0%

 

$

202,732

 

100.0%


Title to Properties


As is customary in the oil and natural gas industry, we make only a cursory review of title to undeveloped oil and natural gas leases at the time we acquire them.  However, before drilling operations commence, we search the title, and remedy material defects, if any, before we actually begin drilling the well.  To the extent title opinions or other investigations reflect title defects, we (rather than the seller or lessor of the undeveloped property) typically are obligated to cure any such title defects at our expense.  If we are unable to remedy or cure any title defects, so that it would not be prudent for us to commence drilling operations on the property, we could suffer a loss of our entire investment in the property.  Except for encumbrances we have granted as described below under “Encumbrances,” we believe that we have good title to our oil and natural gas properties, some of which are subject to immaterial easements, and restrictions.


Encumbrances


The Company’s debt obligations, pursuant to a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC, a Delaware limited liability company, as lender, (either party, as appropriate, is referred to in this annual report on Form 10-K as “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 refer to the discussion under the caption “Non-current debt (long-term borrowings)” found in the MD&A section of this Form 10-K.


Regulation


The exploration and development of oil and natural gas properties are subject to various types of federal, state and local laws and regulations.  These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, hydraulic fracturing operations, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and specific requirements for the operation of wells.  Failure to comply with such laws and regulations can result in substantial penalties.



6




Laws and regulations relating to our business frequently change so we are unable to predict the future cost or impact of complying with such laws.  Future laws and regulations, including changes to existing laws and regulations, could adversely affect our business.  These regulatory burdens generally do not affect us any differently than they affect other companies in our industry with similar types, quantities and locations of production.


All of the states in which we operate generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas.  Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring of natural gas and requirements regarding the ratability of production.


These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill.  Moreover, many states impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction.  States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.


In the event we conduct operations on federal, state or American Indian oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements and on-site security regulations, and other appropriate permits issued by the Bureau of Land Management or other relevant federal or state agencies.


The sales prices of oil and natural gas are not presently regulated but rather are set by the market.  We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on the operations of the underlying properties.


Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  We commonly use hydraulic fracturing as part of our operations in Kentucky.  Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuel.  At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities.  If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.


Operational Hazards and Insurance


Our operations are subject to the usual hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks.  These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation.  In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.


We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry.  We believe the coverage and types of insurance we maintain are adequate.  The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations.  We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.




7



Employees and Consultants


At February 29, 2016, we had six full-time employees.  Additionally, we regularly use the services of four consultants on an as-needed basis for accounting, technical, oil field, geological, investor relations and administrative services.  None of our employees are subject to a collective bargaining agreement.  In our opinion, relations with our employees are good.  We may hire more employees in the future as needed.  All other services are currently contracted for with independent contractors.  We have not obtained “key person” life insurance on any of our officers or directors.


Long-Term Success


Our long-term success depends on the successful acquisition, exploration and development of commercial grade oil and natural gas properties as well as the prevailing prices for oil and natural gas to generate future revenues and operating cash flow.  Oil and natural gas prices have been extremely volatile and have decreased significantly since June of 2014 and are affected by many factors outside of our control.  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, has had and will likely continue to have a material adverse effect on our results of operations and financial condition.  Such pricing factors are beyond our control, and have resulted and will result in negative fluctuations of our earnings. We believe; however, that even in this volatile pricing environment there are significant opportunities available to us in the oil and natural gas exploration and development industry.


Availability of SEC Filings


You may read and copy any materials we file with the U.S. Securities and Exchange Commission (the “SEC”) at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549, on official business days during the hours of 10:00 am to 3:00 pm.  You can obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.  The address of that site is http://www.sec.gov.


Website / Available Information


Our website can be found at www.daybreakoilandgas.com.  Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed with or furnished to the SEC, pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (“the Exchange Act”) can be accessed free of charge on our website at www.daybreakoilandgas.com under the “Shareholder/Financial” section of our website within the “SEC Filings” subsection as soon as is reasonably practicable after we electronically file such material with, or otherwise furnish it to, the SEC.


We have adopted an Ethical Business Conduct Policy Statement to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures.  We also have adopted a Code of Ethics for Senior Financial Officers that applies to our principal executive officer, principal financial officer, principal accounting officer and controller.  Copies of our Ethical Business Conduct Policy Statement and Code of Ethics for Senior Financial Officers are available under the “Shareholder/Financial” section of our website at www.daybreakoilandgas.com within the heading “Corporate Governance.”  We intend to promptly disclose via a Current Report on Form 8-K or via an update to our website, information on any amendment to or waiver of these codes with respect to our executive officers and directors.  Waiver information disclosed via the website will remain on the website for at least 12 months after the initial disclosure of a waiver.


Our Corporate Governance Guidelines and the charters of our Audit Committee, Nominating and Corporate Governance Committee, and Compensation Committee are also available in the “Shareholder/Financial” section of our website at www.daybreakoilandgas.com within the heading “Corporate Governance.”  In addition, copies of our Ethical Business Conduct Policy Statement, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines and the charters of the Committees referenced above are available at no cost to any shareholder who requests them by writing or telephoning us at the following address or telephone number:


 

Daybreak Oil and Gas, Inc.

 

1101 N. Argonne Road, Suite A 211

 

Spokane Valley, WA 99212-2699

 

Attention: Corporate Secretary

 

Telephone: (509) 232-7674


Information contained on or connected to our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.



8




ITEM 1A.   RISK FACTORS


The following risk factors together with other information set forth in this Annual Report on Form 10-K, should be carefully considered by current and future investors in our securities.  An investment in our securities involves substantial risks.  There are many factors that affect our business, a number of which are beyond our control.  Our business, financial condition and results of operations could be materially adversely affected by any of these factors.  The nature of our business activities further subjects us to certain hazards and risks.  The risks described below are a summary of the known material risks relating to our business.  Additional risks and uncertainties not presently known to us or that we currently deem to be immaterial individually or in aggregate may also impair our business operations.  If any of these risks actually occur, it could harm our business, financial condition or results of operations and impair our ability to implement our business plan or complete development projects as scheduled.  In any such case, the trading price of our Common Stock could decline, and you could lose all, or a part, of your investment.


Oil and natural gas prices are volatile.  Declines in commodity prices have currently adversely affected, and in the future may continue to adversely affect, our financial condition, liquidity, results of operations, cash flows, access to capital markets, and ability to grow.


Our revenues, operating results, liquidity, cash flows, profitability and valuation of proved reserves depend substantially upon the market prices of oil and natural gas.  Product prices affect our cash flow available for capital expenditures and our ability to access funds through the capital markets.  Declines in commodity prices have historically adversely affected the estimated value of our proved reserves and our cash flows.  The decline in hydrocarbon prices that we are currently experiencing has had a material adverse effect on our cash flows, reserves valuation and availability of funds in the financial markets.


The commodity prices we receive for our oil and natural gas depend upon factors beyond our control, including among others:

·

changes in the supply of and demand for oil and natural gas;

·

market uncertainty;

·

the level of consumer product demands;

·

hurricanes and other weather conditions;

·

domestic governmental regulations and taxes;

·

the foreign supply of oil and natural gas

·

the price of oil and natural gas imports; and

·

overall domestic and foreign economic conditions.


These factors make it very difficult to predict future hydrocarbon commodity price movements with any certainty.  It is beyond our control and ability to accurately predict when there will be a sustained improvement in hydrocarbon prices.  All of our oil and natural gas sales are made pursuant to contracts based on spot market prices and are not based on long-term fixed price contracts.  Oil and natural gas prices do not necessarily fluctuate in direct relation to each other.


We have experienced significant operating losses in the past and there can be no assurance that we will become profitable in the future.


We have reported a net loss of approximately $4.2 million for the year ended February 29, 2016, and we have an accumulated deficit through February 29, 2016 of approximately $32.4 million.  Without successful exploration and development of our properties and a significant sustained increase in hydrocarbon prices any investment in Daybreak could become devalued or worthless.




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We have substantial indebtedness.  The amount of our outstanding indebtedness continues to increase and our current inability to make payments towards such indebtedness could have adverse consequences on future operations.


Our outstanding indebtedness at February 29, 2016 was approximately $18.9 million, which was comprised of a variety of short-term and long-term borrowings; related party notes and payables; a line of credit; trade payables; and 12% Subordinated Notes.  The level of indebtedness we have affects our operations in a number of ways.  We will need to use a portion of our cash flow to pay principal and interest and meet payables commitments, which reduces the amount of funds we will have available to finance our operations.  This lack of funds limits planning for or reacting to changes in our business and the industry in which we operate and could limit our ability to make funds available for other purposes, such as future exploration, development or acquisition activities.  As a result of the decline in hydrocarbon prices, we are currently unable to make the interest or principal payments required under the terms of our credit facility with our lender, Maximilian.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not been made.  Due to the waivers granted by Maximilian, 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 assurances that this cooperation will continue.  Further, there can be no assurances that Maximilian will not declare the Company to be in default under the credit facility.  Our ability to meet our debt service obligations and reduce our total indebtedness will depend upon our future performance.  Our future performance, in turn, is dependent upon many factors that are beyond our control such as the level of hydrocarbon prices and general economic, financial and business conditions.  We cannot guarantee that our future performance will not be adversely affected by such economic conditions and financial, business and other factors.


To execute our business plan we will need to develop current projects and expand our operations requiring significant capital expenditures, which we may be unable to fund.


Our business plan contemplates the execution of our current exploration and development projects and the expansion of our business by identifying, acquiring, and developing additional oil and natural gas properties.  We plan to rely on external sources of financing to meet the capital requirements associated with these activities.  We will have to obtain any additional funding we need through debt and equity markets or the sale of producing or non-producing assets.  There is no assurance that we will be able to obtain additional funding when it is required or that it will be available to us on commercially acceptable terms.


Low hydrocarbon price environments such as the downturn in prices that we are currently experiencing, as well as operating difficulties and other factors, many of which are beyond our control, are causing our revenues and cash flows from operating activities to decrease and may limit our ability to internally fund our exploration and development activities.


We may make offers to acquire oil and natural gas properties in the ordinary course of our business.  If these offers are accepted, our capital needs will increase substantially.  If we fail to obtain the funding that we need when it is required, we may have to forego or delay potentially valuable opportunities to acquire new oil and natural gas properties.  In addition, without the necessary funding, we may default on existing funding commitments to third parties and forfeit or dilute our rights in existing oil and natural gas property interests.


Hydrocarbon price declines may result in impairments of our asset carrying values.


Commodity prices have a significant impact on the present value of our proved reserves.  Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties in certain situations.  We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets.  To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required.  Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred.  For the year ended February 29, 2016, we recorded an impairment expense of $1.1 million on our California properties.


The oil and natural gas business is highly competitive, placing us at an operating disadvantage.


We expect to be at a competitive disadvantage in (a) seeking to acquire suitable oil and or natural gas drilling prospects; (b) undertaking exploration and development; and (c) seeking additional financing.  We base our preliminary decisions regarding the acquisition of oil and or natural gas prospects and undertaking of drilling ventures upon general and inferred geology and economic assumptions.  This public information is also available to our competitors.



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In addition, we compete with larger oil and natural gas companies with longer operating histories and greater financial resources than us.  These larger competitors, by reason of their size and greater financial strength, can more easily:

·

access capital markets;

·

recruit more qualified personnel;

·

absorb the burden of any changes in laws and regulation in applicable jurisdictions;

·

handle longer periods of reduced prices of natural gas and oil;

·

acquire and evaluate larger volumes of critical information; and

·

compete for industry-offered business ventures.


These disadvantages could create negative results for our business plan and future operations.


Our ability to reach and maintain profitable operating results is dependent on our ability to find, acquire, and develop oil and natural gas properties.


Our future performance depends upon our ability to find, acquire, and develop oil and natural gas reserves that are economically recoverable.  Without successful exploration and acquisition activities, we will not be able to develop reserves or generate production revenues to achieve and maintain profitable operating results.  No assurance can be given that we will be able to find, acquire or develop these reserves on acceptable terms.  We also cannot assure that commercial quantities of oil and natural gas deposits will be discovered that are sufficient to enable us to recover our exploration and development costs.


We have a limited operating history on which to base an investment decision.


To date, while we have positive cash flow from our continuing operations in Kentucky and California, we have not yet generated sustainable positive cash flow or earnings on a company-wide basis.  We cannot provide any assurances that we will ever operate profitably especially in the current low-priced hydrocarbon environment.  As a result of our limited operating history, we are more susceptible to business risks.  These risks include unforeseen capital requirements, failure to establish business relationships, and competitive disadvantages against larger and more established companies.


Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of proposed legislation.


Legislation has been proposed that would, if enacted into law, make significant changes to United States federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies.  These changes include, but are not limited to:  (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures.  It is unclear whether any such changes will be enacted and, if enacted, how soon any such changes could become effective.  The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our Common Stock as well as affect our financial condition and results of operations.


Our oil and natural gas exploration and production, and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.


Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances.  Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated, and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate.  Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws.  Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share.  Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.



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We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future.  Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs.  Some of our properties may be affected by environmental contamination that may require investigation or remediation.  In addition, claims are sometimes made or threatened against companies engaged in oil and natural gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation.  Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.


The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.


In December 2009, the Environmental Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States including petroleum refineries, as well as certain onshore oil and natural gas production facilities, on an annual basis.  More recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule.  These new sources include gathering and boosting facilities as well as completions and requirements for certain facilities.  These changes to the EPA’s greenhouse gases emissions reporting rule could result in increased compliance costs.


Moreover, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions to acquire and surrender emission allowances.  The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.  Although our current facilities are not subject to the EPA’s greenhouse gases reporting rules, the EPA has indicated that it is evaluating whether the rule should be applied to oil and natural gas production activities, perhaps on a field-wide basis.


The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements.  Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.  Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.


Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.


Recently approved final rules regulating air emissions from natural gas production operations could cause us to incur increased capital expenditures, and operating costs which could be significant.


On April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities.  The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015.  For well completion operations occurring at such well sites before January 1, 2015, the final regulation allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions.  These regulations also establish specific new requirements regarding emissions from hydrators, storage tanks and other production equipment.  This new rule and compliance with its requirements could increase our costs of



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development and productions, though we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.


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


Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  We commonly use hydraulic fracturing as part of our operations in Kentucky.  Hydraulic fracturing typically is regulated by state oil and gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuel, and, in February 2014, issued guidance for such activities.


At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities.  If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.


The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.  In June 2015 the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources.  The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board.  These ongoing or any future studies could spur initiatives further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their findings, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.  If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.


Our proved reserves are estimates and depend on many assumptions.  Any material inaccuracies in these assumptions could cause the quantity and value of our oil and natural gas reserves, and our revenues, profitability and cash flows to be materially different from our estimates.


The accuracy of estimated proved reserves and estimated future net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses and other matters.  Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves.  Any significant variance could materially affect the estimated quantities and value of our oil and natural gas reserves, which in turn could adversely affect our cash flows, results of operations, financial condition and the availability of capital resources.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.  Downward adjustments to our estimated proved reserves could require us to impair the carrying value of our oil and natural gas properties, which would reduce our earnings and our stockholders’ equity.


The present value of proved reserves will not necessarily equal the current fair market value of our estimated oil and natural gas reserves.  In accordance with reserve reporting requirements of the SEC, we are required to establish economic production for reserves on an average historical price.  Actual future prices and costs may be materially higher or lower than those required by the SEC.  The timing of both the production and expenses with respect to the development and production of oil and natural gas properties will affect the timing of future net cash flows from proved reserves and their present value.



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The estimated proved reserve information is based upon reserve reports prepared by an independent engineer.  From time to time, estimates of our reserves are also made by our company engineer for use in developing business plans and making various decisions.  Such estimates may vary significantly from those of the independent engineers and may have a material effect upon our business decisions and available capital resources.


We may reclassify proved undeveloped reserves to unproved due to our inability to commit sufficient capital within the required five-year development window, which could adversely affect the value of our properties.


The SEC generally requires that any undrilled location can be classified as a proved undeveloped reserve only if a development plan has been adopted indicating that the location is scheduled to be drilled within five years.  Our recent reduction of our drilling program in response to depressed oil and natural gas process is likely to impact our ability to develop proved undeveloped reserves within such five-year period.  If we continue our limited drilling plan over a significant period of time our future access to capital resources is limited, we will also likely further delay our development of our proved undeveloped reserves or ultimately suspend such development which could result in the reclassification of a significant amount of our proved undeveloped reserves as probable or possible reserves.  A significant reclassification of proved undeveloped reserves could adversely affect the value of our properties.  


When we make the determination to invest in oil or natural gas properties we rely upon geological and engineering estimates, which involve a high level of uncertainty.


Geologic and engineering data are used to determine the probability that a reservoir of oil or natural gas exists at a particular location.  This data is also used to determine whether oil and natural gas are recoverable from a reservoir.  Recoverability is ultimately subject to the accuracy of data including, but not limited to, geological characteristics of the reservoir, structure, reservoir fluid properties, the size and boundaries of the drainage area, reservoir pressure, and the anticipated rate of pressure depletion.  Also, an increase in the costs of production operations may render some deposits uneconomic to extract.


The evaluation of these and other factors is based upon available seismic data, computer modeling, well tests and information obtained from production of oil and natural gas from adjacent or similar properties.  There is a high degree of risk in proving the existence and recoverability of reserves.  Actual recoveries of proved reserves can differ materially from original estimates.  Accordingly, reserve estimates may be subject to downward adjustment.  Actual production, revenue and expenditures will likely vary from estimates, and such variances may be material.


Drilling is a high risk activity and, as a result, we may not be able to adhere to our proposed drilling schedule, or our drilling program may not result in commercially productive reserves.


Our future success will partly depend on the success of our drilling programs. The future cost or timing of drilling, completing, and producing wells is inherently uncertain.  Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including:

·

unexpected drilling conditions;

·

well integrity issues and surface expressions;

·

pressure or irregularities in formations;

·

equipment failures or accidents;

·

compliance with landowner requirements;

·

current oil and natural gas prices and estimates of future oil and natural gas prices;

·

availability, costs and terms of contractual arrangements with respect to pipelines and related facilities to gather, process, transport and market oil and natural gas; and

·

shortages or delays in the availability of drilling rigs and the delivery of equipment and/or services, including experienced labor.






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Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.


The demand for qualified and experienced field personnel to drill wells and conduct field operations in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages.  Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled.  These factors also cause significant increases in costs for equipment, services and personnel.  Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews, and associated supplies, equipment and services.  It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be.


Our financial condition will deteriorate if we are unable to retain our interests in our leased oil and natural gas properties.


All of our properties are held under interests in oil and natural gas mineral leases.  If we fail to meet the specific requirements of any lease, such lease may be terminated or otherwise expire.  We cannot be assured that we will be able to meet our obligations under each lease.  The termination or expiration of our “working interests” (interests created by the execution of an oil and natural gas lease) relating to these leases would impair our financial condition and results of operations.


We will need significant additional funds to meet capital calls, drilling and other production costs in our effort to explore, produce, develop and sell the crude oil and natural gas produced by our leases.  We may not be able to obtain any such additional funds on acceptable terms.


Title deficiencies could render our oil and natural gas leases worthless; thus damaging the financial condition of our business.


The existence of a material title deficiency can render a lease worthless, resulting in a large expense to our business.  We rely upon the judgment of oil and natural gas lease brokers who perform the fieldwork and examine records in the appropriate governmental office before attempting to place a specific mineral interest under lease.  This is a customary practice in the oil and natural gas industry.


We anticipate that we, or the person or company acting as operator on the properties that we lease, will examine title prior to any well being drilled.  Even after taking these precautions, deficiencies in the marketability of the title to the leases may still arise.  Such deficiencies may render some leases worthless, negatively impacting our financial condition.


If we as operators, or the operator of our oil and natural gas projects fail to maintain adequate insurance, our business could be exposed to significant losses.


Our oil and natural gas projects are subject to risks inherent in the oil and natural gas industry.  These risks involve explosions, uncontrollable flows of oil, natural gas or well fluids, pollution, fires, earthquakes and other environmental issues.  These risks could result in substantial losses due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage.  As protection against these operating hazards we maintain insurance coverage to include physical damage and comprehensive general liability.  However, we are not fully insured in all aspects of our business.  The occurrence of a significant event on any project against which we are not adequately covered by insurance could have a material adverse effect on our financial position.


In the projects in which we are not the operator, we require the operator to maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry.  The occurrence of a significant adverse event on any of these projects if they are not fully covered by insurance could result in the loss of all or part of our investment.  The loss of any such project investment could have a material adverse effect on our financial condition and results of operations.




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We may lose key management personnel which could endanger the future success of our oil and natural gas operations.


Our President and Chief Executive Officer, who is also acting as our interim principal finance and accounting officer, our Director of Field Operations, and two of our directors each have substantial experience in the oil and natural gas business. The loss of any of these individuals could adversely affect our business.  If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that a suitable or comparable substitute will be found.


We may be unable to continue as a going concern in which case our securities will have little or no value.


Our financial statements for the year ended February 29, 2016 were prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  We have incurred net losses since inception, which raises substantial doubt about our ability to continue as a going concern.  In the event we are not able to continue operations, an investor will likely suffer a complete loss of their investment in our securities.


We have not held an annual meeting of our shareholders since 2010; as such, our shareholders have not had the opportunity to elect directors since 2010.


Our bylaws and the Washington Business Corporation Act state that we must hold an annual meeting of our shareholders for the election of directors and other business as may be properly brought before the meeting.  However, because we have had limited financial resources, and as a part of our efforts to minimize our general and administrative costs, we have not held an annual meeting of our shareholders since 2010.  As such, our shareholders have not had the opportunity to vote in an election of our directors since 2010.  We plan to hold an annual shareholders’ meeting in the next year; however, if we do not, or if we otherwise fail to hold annual shareholders’ meetings in the future, our shareholders will likely not have the opportunity to vote on the election of our directors.


The market price of our Common Stock has been volatile, which may cause the investment value of our stock to decline.


Daybreak’s Common Stock (OTC Pink: DBRM) trades on the OTC Pink marketplace.  Prior to May 1, 2016, our stock had traded on the OTCQB Venture Marketplace.  Our transition to the OTC Pink marketplace resulted in a cost-savings to the company related to listing fees.


Because of the limited liquidity of our stock, shareholders may be unable to sell their shares at or above the cost of their purchase prices.  The trading price of our shares has experienced wide fluctuations and these shares may be subject to similar fluctuations in the future.


The trading price of our Common Stock may be affected by a number of factors including events described in these risk factors, as well as our operating results, financial condition, announcements of drilling activities, general conditions in the oil and natural gas exploration and development industry including volatility in oil and natural gas prices, and other events or factors.  The decline in hydrocarbon prices, that we have been experiencing since June 2014, has had a corresponding material adverse impact on our revenues and a similar direct material adverse impact on the trading price of our Common Stock.


In recent years, broad stock market indices, in general, and smaller capitalization companies, in particular, have experienced substantial price fluctuations.  In a volatile market, we do experience wide fluctuations in the market price of our Common Stock.  These fluctuations may have a negative effect on the market price of our Common Stock.


Pursuant to SEC rules our Common Stock is classified as a “penny stock” increasing the risk of investment in these shares.


Our Common Stock is designated as a “penny stock” and thus may be more illiquid than shares traded on an exchange or on NASDAQ.  Penny stocks generally are any non-NASDAQ or non-exchange listed equity securities with a price of less than $5.00, subject to certain exceptions.


The “penny stock” reporting and disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for a stock that is subject to these rules.  The market liquidity for the shares could be severely and adversely affected by limiting the ability of broker-dealers to sell these shares.




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The resale of shares offered in private placements could depress the value of the shares.


In the past shares of our Common Stock have been offered and sold in private placements at significant discounts to the trading price of the Common Stock at the time of the offering.  Sales of substantial amounts of Common Stock eligible for future sale in the public market, or the availability of shares for sale, including shares issued upon exercise of outstanding warrants, could adversely affect the prevailing market price of our Common Stock and our ability to raise capital by an offering of equity securities.


Privately placed issuances of our Common Stock, Preferred Stock and warrants have and may continue to dilute ownership interests which could have an adverse effect on our stock prices.


Our authorized capital stock consists of 200,000,000 shares of Common Stock and 10,000,000 shares of preferred stock.  As of February 29, 2016, there were 51,487,373 shares of Common Stock and 724,565 shares of Series A Convertible Preferred stock outstanding.


Historically we have issued, and likely will continue to issue, additional shares of our Common Stock in connection with the compensation of personnel, future acquisitions, private placements, possible equity swaps for debt or for other business purposes.  Future issuances of substantial amounts of these equity securities could have a material adverse effect on the market price of our Common Stock, and would result in further dilution of the ownership interests of our existing shareholders.


Preferred Stock has been issued with greater rights than the Common Stock issued which may dilute and depress the investment value of the Common Stock investments.


The rights of the holders of Common Stock are subject to and may be adversely affected by the rights and preferences afforded to the holders of our Series A Convertible Preferred Shares.  The rights and preferences of these issued preferred shares include:

·

conversion into Common Stock of the Company anytime the preferred shareholder may wish;

·

cumulative dividends in the amount of 6% of the original purchase price per annum, payable upon declaration by the board of directors;

·

the ability to vote together with the Common Stock with a number of votes equal to the number of shares of Common Stock to be issued upon conversion of the Preferred Stock; and

·

a preference upon any actual or “deemed” liquidation, dissolution or winding up of the Company.


The issuance of these preferred shares could make it less likely that shareholders would receive a premium for their shares of Common Stock as a result of any attempt to acquire the Company.  Further, this issuance could adversely affect the market price of, and the voting and other rights, of the holders of outstanding shares of Common Stock.


Further, the Board of Directors has the power to issue more shares of Preferred Stock without shareholder approval, and such shares can be issued with such rights, preferences, and limitations as may be determined by our Board of Directors.


We may seek to raise additional funds in the future through debt financing, which may impose operational restrictions and may further dilute existing ownership interests.


We expect to seek to raise additional capital in the future to help fund our acquisition, development, and production of oil and natural gas reserves.  We have obtained debt financing through our revolving credit facility with Maximilian, as described in the MD&A section under the caption “Non-current debt – Maximilian Loan”  Subsequent debt financing, if available, may require restrictive covenants in addition to those to which we are already subject under the Maximilian loan, which may limit our operating flexibility.  Future debt financing may also involve debt instruments that are convertible into or exercisable for Common Stock.  The conversion of the debt to equity financing may dilute the equity position of our existing shareholders.






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We do not anticipate paying dividends on our Common Stock, which could devalue the market value of these securities.


We have not paid any cash dividends on our Common Stock since the Company’s inception in 1955.  We do not anticipate paying cash dividends in the foreseeable future.  Any dividends paid in the future will be at the complete discretion of our Board of Directors.  For the foreseeable future, we anticipate that we will retain any revenues that we may generate from our operations.  These retained revenues will be used to finance and develop the growth of the Company.  Prospective investors should be aware that the absence of dividend payments could negatively affect the market value of our Common Stock.  Investors must rely on sales of their Common Stock after price appreciation, which may never occur, as the only way to realize a return on their investment.  Investors seeking cash dividends should not purchase our Common Stock.


A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.


A terrorist attack, anti-terrorist efforts or other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations.  If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues.  Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged.  Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.





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ITEM 1B.   UNRESOLVED STAFF COMMENTS


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






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ITEM 2.   PROPERTIES


We conduct all of our drilling, exploration and production activities in the United States.  All of our oil and natural gas assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.  During the year ended February 29, 2016, we were involved in oilfield projects in Lawrence County, Kentucky and Kern County, California.  We have not filed any estimates of total, proved net oil or natural gas reserves with any federal agency other than this report to the SEC for the fiscal year ended February 29, 2016.  Throughout this Annual Report on Form 10-K, oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).


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.  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 (“American Petroleum Institute”) 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.  However, we have our own personnel onsite during critical operations such as drilling, fracturing and completing operations.


At February 29, 2016, 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.


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 plan to spend approximately $1.0 million in new capital investments in the Twin Bottoms Field Project area in the 2016 - 2017 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 that 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 vertical 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.



20




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 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 an average of approximately $12 per barrel of oil for the year ended February 29, 2016.  With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.


California Producing Properties


Sunday Property


In November 2008, we made our initial oil discovery drilling the Sunday #1 well.  The well was put on production in January 2009.  Production is from the Vedder Sand at approximately 2,000 feet.  During 2009, we drilled three development wells including one horizontal well: the Sunday #2, Sunday #3 and Sunday #4H wells, respectively.  During May and June 2013, we drilled two additional development wells: the Sunday #5 and Sunday #6.  We have a 37.5% working interest with a 26.1% net revenue interest (“NRI”) in the Sunday #1 well.  For the Sunday #2 and Sunday #3 wells, we have a 33.8% working interest with a 24.3% NRI.  In the Sunday #4H well, we have a 33.8% working interest with a 27.1% NRI.  In both the Sunday #5 and Sunday #6 wells we have a 37.5% working interest and a NRI of 30.1%.  Our average working interest and NRI for the Sunday property in aggregate is 35.6% and 27.0%, respectively.  The Sunday reservoir is estimated to be approximately 35 acres in size with the potential for at least five more development wells to be drilled in the future.


Bear Property


In February 2009, we made our second oil discovery drilling the Bear #1 well, which is approximately one mile northwest of our Sunday discovery.  The well was put on production in May 2009.  Production is from the Vedder Sand at approximately 2,200 feet.  In December 2009, we began a development program on this property by drilling and completing the Bear #2 well.  In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells.  In May and June 2013, we drilled three additional development wells, the Bear #5, Bear #6 and Bear #7, on this property.  In November 2013, we drilled and put on production two additional development wells: the Bear #8 and Bear #9.  We have a 37.5% working interest in all wells on the Bear property.  Our NRI in the Bear #1, Bear #2, Bear #3 and Bear #4 wells is 26.1%.  For the Bear #5, Bear #6 and Bear #7 wells our NRI is 30.1%.  Our NRI in the Bear #8 and Bear #9 wells is 31.7%.  The average working interest and NRI for the Bear property in aggregate is 37.5% and 28.7%, respectively.  The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least ten more development wells to be drilled in the future.


Black Property


The Black property was acquired through a farm-in arrangement with a local operator.  The Black property is just south of the Bear property on the same fault system.  The Black #1 well was completed and put on production in January 2010.  Production is from the Vedder Sand at approximately 2,200 feet.  In May 2013, we drilled a development well, the Black #2, on this property.  We have a 33.8% working interest with a 26.8% NRI in all wells on this property.  The Black reservoir is estimated to be approximately 13 acres in size with the potential for at least three more development wells to be drilled in the future.


Ball Property


The Ball #1-11 well was put on production in late October 2010.  In June 2013 we drilled a development well, the Ball #2-11, on this property.  Production on this property is from the Vedder Sand at approximately 2,500 feet.  We have a 37.5% working interest with a 31.2% NRI in all wells on this property.  Our 3-D seismic data indicates a reservoir of approximately 38 acres in size with the potential for at least three more development wells to be drilled in the future.




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Dyer Creek Property


The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010.  This well is producing from the Vedder Sand and is located to the north of the Bear property on the same trapping fault.  We have a 37.5% working interest with a 31.2% NRI in all wells on this property.  The Dyer Creek property has the potential for at least one development well in the future.


California Drilling Plans


Planned drilling activity and implementation of our oilfield development plan will not begin until there is a sustained improvement in crude oil prices and additional financing is put in place.  We plan to spend approximately $-0- in new capital investments within the East Slopes Project area in the 2016 – 2017 fiscal year.


Encumbrances


The Company’s debt obligations, pursuant to a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC, a Delaware limited liability company, as lender, (either party, as appropriate, is referred to in this Annual Report on Form 10-K as “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 refer to the discussion under the caption “Non-current debt (long-term borrowings)” in the MD&A portion of this Annual Report on Form 10-K.


Reserves


The following table sets forth our estimated net quantities of proved reserves as of February 29, 2016.


 

 

Proved Reserves

Reserve Category

 

Oil (Barrels)

 

Natural Gas

(Mcf)

 

Total Oil

Equivalents (BOE)

 

Percent of Oil

Equivalents (BOE) (1)

Developed

 

203,131

 

171,880

 

231,778

 

25.7%

Undeveloped

 

569,979

 

606,140

 

671,002

 

74.3%

Total Proved

 

773,110

 

778,020

 

902,780

 

100.0%


(1)

Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil


The following table summarizes changes in our estimated net proved reserves for the year ended February 29, 2016.


 

 

Proved Reserves

(BOE)

Balance as of February 28, 2015

 

 

888,136 

Revisions

 

 

(54,886)

Discoveries and extensions

 

 

103,157 

Production

 

 

(33,627)

Balance as of February 29, 2016

 

 

902,780 


Revisions. Net downward revisions of 54,886 BOE in aggregate were due to lower realized hydrocarbons prices during the year ended February 29, 2016 decreasing the economic life of our proved reserves.


Discoveries and extensions. For the year ended February 29, 2016, extensions of 103,157 BOE were a result of our drilling activity in the Twin Bottoms Field in eastern Kentucky.  There were no extensions for the year ended February 29, 2016 in California.


Production. Production in Kentucky was 19,482 BOE and 14,145 BOE in California representing 33,627 BOE in aggregate of proved reserves for the year ended February 29, 2016.




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The following table summarizes changes in our estimated net proved undeveloped reserves for the year ended February 29, 2016.


 

 

Proved Undeveloped Reserves

(BOE)

Balance as of February 28, 2015

 

593,551 

Revisions

 

(17,569)

Discoveries and extensions

 

95,020 

Reclassified to proved developed

 

Balance as of February 29,2016

 

671,002 


Revisions. There were net downward revisions of 17,569 BOE in aggregate due to lower realized hydrocarbons prices during the year ended February 29, 2016 decreasing the economic life of our proved reserves.


Discoveries and extensions. For the year ended February 29, 2016, extensions of 95,020 BOE were a result of our drilling activity in the Twin Bottoms Field in eastern Kentucky.  There were no extensions for the year ended February 29, 2016 in California.


The following table sets forth our estimated net proved developed reserves as of February 29, 2016 by project location.


 

 

Proved Developed Reserves

 

 

 

 

Natural

 

Total Oil

 

Percent of Oil

Location

 

Oil (Barrels)

 

Gas (Mcf)

 

Equivalents (BOE)

 

Equivalents (BOE)

Kentucky

 

89,925

 

171,880

 

118,572

 

51.2%

California

 

113,206

 

-

 

113,206

 

48.8%

Total

 

203,131

 

171,880

 

231,778

 

100.0%


The following table sets forth our estimated net proved undeveloped reserves as of February 29, 2016 by project location.


 

 

Proved Undeveloped Reserves

 

 

 

 

Natural

 

Total Oil

 

Percent of Oil

Location

 

Oil (Barrels)

 

Gas (Mcf)

 

Equivalents (BOE)

 

Equivalents (BOE)

Kentucky

 

275,556

 

606,140

 

376,579

 

56.1%

California

 

294,423

 

-

 

294,423

 

43.9%

Total

 

569,979

 

606,140

 

671,002

 

100.0%


The Company has no proved undeveloped reserves that have remained undeveloped for a period greater than five years.  Under our current drilling plans, we intend to convert all 671,002 BOE or 100.0% of the proved undeveloped reserves disclosed as of February 29, 2016 to proved developed reserves within five years of the date they were initially first disclosed as proved undeveloped reserves.


The following table sets forth our estimated proved reserves (BOE) and PV-10 valuation by project area.


 

 

Proved Reserves

 

 

 

 

 

 

PV-10 as a

 

 

Total Oil

 

PV-10 of

 

Percentage of

Location

 

Equivalents (BOE)

 

Proved Reserves

 

Proved Reserves

Kentucky

 

495,151

 

$

2,052,140

 

51.7%

California

 

407,629

 

 

1,920,790

 

48.3%

Total

 

902,780

 

$

3,972,930

 

100.0%


The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10”), was approximately $4.0 million at February 29, 2016 a decline of approximately $13.5 million or 77.3% from the year ended February 28, 2015.  This decline is primarily due to the decline in hydrocarbon prices since June of 2014.  The commodity prices used to estimate proved reserves and their related PV-10 at February 29, 2016 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from March 2015 through February 2016.  The benchmark average price for the year ended February 29, 2016 was $47.45 per barrel of oil and $2.51 per Mcf for natural gas.




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These benchmark average prices were further adjusted for quality, transportation fees and other price differentials resulting in an average realized price in Kentucky for crude oil of $46.41 per barrel and $1.51 per Mcf for natural gas.  In California the average realized price was $39.10 per barrel of crude oil.  Adverse changes in any price differential could reduce our cash flow from operations and the PV-10 of our proved reserves.  Operating costs were not escalated.


PV-10 is not a generally accepted accounting principal (“GAAP”) financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our financial statements.  The PV-10 of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a comparable basis.


Reserve Estimation


All of our estimated proved reserves of 902,780 BOE for the year ended February 29, 2016 were derived from engineering reports prepared by PGH Petroleum and Environmental Engineers, LLC (“PGH”) of Austin, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.


PGH is an independent petroleum engineering consulting firm registered in the State of Texas, and Frank J. Muser, a Petroleum Engineer, is the technical person at PGH primarily responsible for evaluating the proved reserves covered by their report.  Mr. Muser graduated from the University of Texas at Austin with a Bachelor of Science degree in Chemical Engineering.  He is a licensed Professional Engineer in the states of Texas, Alabama, Kansas, North Dakota and West Virginia and has been employed by PGH as a staff engineer since 2012.  Mr. Muser has over 20 years of extensive oil and natural gas experience working in both private industry and for the State of Texas.  The services provided by PGH are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties.  For more information about the evaluations performed by PGH, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K.


Our internal controls over the reserve reporting process are designed to result in accurate and reliable estimates in compliance with applicable regulations and guidance.  Internal reserve preparation is performed by Bobby Ray Greer, Director of Field Operations.  Mr. Greer is a 1984 graduate of University of Southern Mississippi in Hattiesburg, Mississippi with a Bachelor of Science Degree in Geology and is a certified Petroleum Geologist and a member, in good standing, of the American Association of Professional Geologists.  Mr. Greer has over 30 years of experience in petroleum exploration, reservoir analysis, drilling rig construction, oilfield operations and management.


Although we believe that the estimates of reserves prepared by Mr. Greer have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage an independent petroleum engineering consultant to prepare an annual evaluation of our estimated proved reserves.  We provide to PGH for their analysis all pertinent data needed to properly evaluate our reserves.  We consult regularly with PGH during the reserve estimation process to review properties, assumptions, and any new data available.  Additionally, the Company’s senior management reviewed and approved all Daybreak reserve report information contained in this Annual Report on Form 10-K.


Under current SEC standards, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate.  Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.  Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.


In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability.  The technical data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.  Generally, oil and natural gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations.  Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships.  Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technical data to assess the reservoir continuity.  In some instances, particularly in



24



connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities.  Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data.  When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of oil and natural gas derived through volumetric calculations.


The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment.  The estimates of reserves and future cash flows are based on various assumptions and are inherently imprecise.  Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.  Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.


Delivery Commitments


As of February 29, 2016, we had no commitments to provide any fixed or determinable quantities of oil or natural gas in the near future under contracts or agreements, other than through customary marketing arrangements that require us to nominate estimated volumes of natural gas production for sale during periods of one month or less.


Summary Operating Data


The following table sets forth our net share of annual production in each project for the periods shown.  One barrel of oil equivalent (“BOE”) is roughly equivalent to 6,000 cubic feet or 6 Mcf of gas.


 

 

For the Year Ended February 28/29,

 

 

2016

 

2015

 

2014

Oil and Natural Gas Production Data:

 

 

 

 

 

 

Kentucky Oil

 

14,673

 

21,460

 

3,162

Kentucky Gas (Mcf)

 

28,853

 

22,134

 

1,717

Kentucky Gas (BOE)

 

4,809

 

3,689

 

286

 

 

 

 

 

 

 

Kentucky Oil and Natural Gas (BOE)

 

19,482

 

25,149

 

3,448

California Oil

 

14,145

 

16,402

 

15,586

Total (BOE)

 

33,627

 

41,551

 

19,034


The following table sets forth our net share of oil and natural gas revenue by project area for the periods shown.


 

 

For the Year Ended February 28/29,

 

 

2016

 

2015

 

2014

Oil and Gas Revenue:

 

 

 

 

 

 

 

 

 

Kentucky (Oil)

 

$

680,869

 

$

1,734,400

 

$

304,858

Kentucky (Gas)

 

 

43,457

 

 

64,486

 

 

4,196

California (Oil only)

 

 

529,360

 

 

1,284,911

 

 

1,493,737

Total

 

$

1,253,686

 

$

3,083,797

 

$

1,802,791


The following table sets forth the average realized sales price from each project area for the periods shown.


 

 

For the Year Ended February 28/29,

 

 

2016

 

2015

 

2014

Average Realized Price:

 

 

 

 

 

 

 

 

 

Oil – Kentucky (Bbl)

 

$

46.40

 

$

80.82

 

$

96.43

Gas – Kentucky (Mcf)

 

$

1.51

 

$

2.93

 

$

2.44

Gas – Kentucky (BOE)

 

$

9.04

 

$

17.59

 

$

14.66

 

 

 

 

 

 

 

 

 

 

Kentucky Aggregate (BOE)

 

$

37.18

 

$

71.74

 

$

89.63

Oil – California (Bbl)

 

$

37.43

 

$

78.34

 

$

95.84

     Average realized price (BOE)

 

$

37.28

 

$

74.35

 

$

94.71




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The following table sets forth the average production expense (BOE) for the periods shown.


 

 

For the Year Ended February 28/29,

 

 

2016

 

2015

 

2014

Average Production Expense (BOE):

 

 

 

 

 

 

 

 

 

Kentucky (BOE)

 

$

5.52

 

$

5.96

 

$

6.32

California

 

$

11.37

 

$

10.99

 

$

12.51

Average production cost (BOE)

 

$

7.98

 

$

7.94

 

$

11.39


The following table sets forth the developed and undeveloped oil and natural gas lease acreage held by us as of February 29, 2016.  Undeveloped acres are on lease acreage that wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas.  Gross acres are the total number of acres in which we have an interest.  Net acres are the sum of our fractional working interests owned in the gross acres.


 

 

Developed

 

Undeveloped

 

Total

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Kentucky

 

560

 

127

 

6,660

 

1,557

 

7,220

 

1,684

California

 

800

 

292

 

4,261

 

1,575

 

5,061

 

1,867

Total

 

1,360

 

419

 

10,921

 

3,132

 

12,281

 

3,551


The following table sets forth expiration dates of the leases of our gross and net undeveloped acres for the years shown.


 

 

Year Ended

February 28, 2017

 

Year Ended

February 28, 2018

 

Year Ended

February 28, 2019

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Kentucky

 

957

 

224

 

322

 

75

 

305

 

71

California

 

2,963

 

1,095

 

1,204

 

445

 

40

 

15

Total

 

3,920

 

1,319

 

1,526

 

520

 

345

 

86


Acres expiring are based on contractual lease maturities.  We may extend the leases prior to their expiration based upon planned activities or for other business activities.  In California, we have previously determined that there is no likely benefit to pursuing any drilling opportunities on the majority of the expiring leases, so the expiration of these leases is expected to be immaterial to our operations.  Further, none of our proved undeveloped reserves have been assigned to locations that are scheduled to be drilled after the expiration of the current leases.  All of our proved undeveloped reserves are assigned to leases that are currently held by production (“HBP”).


The following table sets forth our productive oil and gas wells by the property and in aggregate as of February 29, 2016.  Productive wells are producing wells and wells capable of production.  Gross wells are the total number of wells in which we have an interest.  Net wells are the sum of our fractional working interests owned in the gross wells.


Property Location

 

Gross

 

Net

Kentucky

 

14

 

3.2

California

 

20

 

7.3

Total

 

34

 

10.5


The following table sets forth our exploratory and development well drilling activity for the periods shown.


 

 

For the Year Ended

 

For the Year Ended

 

For the Year Ended

 

 

February 29, 2016

 

February 28, 2015

 

February 28, 2014

Property Location

 

Productive

 

Dry

 

Productive

 

Dry

 

Productive

 

Dry

Kentucky

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory

 

-

 

-

 

-

 

-

 

1

 

-

Developmental

 

1

 

-

 

8

 

-

 

4

 

-

Subtotal

 

1

 

-

 

8

 

-

 

5

 

-

California

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory

 

-

 

-

 

-

 

-

 

-

 

1

Developmental

 

-

 

-

 

-

 

-

 

9

 

1

Subtotal

 

-

 

-

 

-

 

-

 

9

 

2

Total

 

1

 

-

 

8

 

-

 

14

 

2



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ITEM 3.   LEGAL PROCEEDINGS


Neither the Company, nor any of our officers or directors is a party to any material legal proceeding or litigation, and such persons know of no material legal proceeding or contemplated or threatened litigation.  There are no judgments against us or our officers or directors.  None of our officers or directors has been convicted of a felony or misdemeanor relating to securities or performance in corporate office.



ITEM 4.   MINE SAFETY DISCLOSURES


Not applicable.






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PART II


ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES


Our Common Stock is quoted on the OTC Pink marketplace under the symbol “DBRM”.  Prior to May 1, 2016, our stock had traded on the OTCQB Venture Marketplace.  Our transition to the OTC Pink marketplace resulted in a cost-savings to the company related to listing fees.  The following table sets forth the high and low closing sales prices for our Common Stock for the two most recent periods shown.  The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.  The information is derived from information received from online stock quotation services.


 

 

Year Ended February 29, 2016

 

Year Ended February 28, 2015

 

 

High

 

Low

 

High

 

Low

First Quarter

 

0.10

 

0.06

 

0.40

 

0.29

Second Quarter

 

0.07

 

0.04

 

0.35

 

0.17

Third Quarter

 

0.05

 

0.03

 

0.23

 

0.11

Fourth Quarter

 

0.04

 

0.01

 

0.16

 

0.05


We feel the dramatic decline in the trading price of our stock can be directly linked to the similar dramatic decline in crude oil and natural gas prices since June of 2014.


As of May 26, 2016, the Company had 1,920 shareholders of record of its Common Stock.  This number does not include an indeterminate number of shareholders whose shares are held by brokers in street name.


Transfer Agent


The transfer agent for our Common Stock is Computershare Trust Company, N.A., 250 Royall Street, Canton, MA 02021.  Their website address is: www.computershare.com.


Dividend Policy


The Company has not declared or paid cash dividends or made distributions since its inception in 1955, and the Company does not anticipate that it will pay cash dividends or make distributions in the foreseeable future.


Sales of Unregistered Securities


Series A Convertible Preferred Stock Conversions


Daybreak Series A Convertible Preferred Stock (“Series A Preferred”) was issued to 100 accredited investors pursuant to the terms of a Daybreak private placement offering held in July 2006.  For the year ended February 29, 2016, the company issued 30,000 shares of Common Stock to one accredited investor from the conversion of 10,000 shares of Series A Preferred stock.  The terms of the Series A Preferred are disclosed in the Company’s Amended and Restated Articles of Incorporation.  The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s Common Stock.  Conversion of Series A Preferred to the Company’s Common Stock by the accredited investors relies upon an exemption from registration provided by Section 3(a)(9) of the Securities Act of 1933 relating to securities exchanged by the issuer with its existing security holders exclusively where no commission or other remuneration is paid or given directly or indirectly for soliciting such exchange.





28



As of February 29, 2016, 43 accredited investors have converted 675,200 Series A Preferred shares into 2,025,600 shares of Daybreak Common Stock.  Conversions of the Series A Preferred that have occurred since being issued in July 2006 are 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

Totals

 

675,200

 

2,025,600

 

43


Common Stock Issuances


During the year ended February 28, 2011, the Company closed on a private placement of 12% Subordinated Notes (“Notes”) to 13 accredited investors.  In conjunction with the Notes private placement, a total of 1,190,000 Common Stock purchase warrants were issued at the rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.14 and were initially set to expire on January 29, 2015.  On January 29, 2015, the Company entered into agreements with the holders of all but one of the 12% Subordinated Notes and associated warrants to extend the maturity date of such holders’ notes and warrants to January 29, 2017.  During the years ended February 28, 2015 and 2014, two 12% Notes holders in aggregate exercised the warrants associated with the Notes, resulting in 50,000 and 100,000 Common Stock shares, respectively being issued to the Note holders.


Securities Authorized for Issuance under Equity Compensation Plan


The table below sets forth information regarding outstanding restricted stock awards for the year ended February 29, 2016.  All shares awarded under the 2009 Restricted Stock and Restricted Stock Plan (“2009 Plan”) have either fully vested or been returned to the 2009 Plan for future awards.  The Company has not awarded any restricted stock units.  The Company has no qualified or nonqualified stock option plans and has no outstanding stock options.


Equity Compensation Plan Information


Plan Category

 

Number of securities to

be issued upon exercise

of outstanding options,

warrants and rights

 

Weighted-average

exercise price of

outstanding

options, warrants

and rights

 

Number of securities

remaining available for

future issuance under equity

compensation plans

Equity compensation plans approved by security holders

 

-

 

-

 

- 

Equity compensation plans not approved by security holders(1)

 

-

 

-

 

1,013,780(2)

Total

 

-

 

-

 

1,013,780(2)


(1)

On April 6, 2009, the Board of Directors approved the 2009 Restricted Stock and Restricted Stock Unit Plan, as described in detail under Item 11. Executive Compensation – Equity Compensation Plan Information.

(2)

Reflects the initial 4,000,000 shares in the 2009 Plan, reduced by (i) 900,000 shares of restricted stock awarded to the Company’s non-employee directors in recognition of their leadership and contribution during the restructuring and transformation of the Company during the fiscal year ended February 28, 2009, (ii) 1,000,000 shares of restricted stock awarded to our current President and Chief Executive Officer and our former interim President and Chief Executive Officer in recognition of past service as executive officers (iii) 425,000 and 625,000 shares of restricted stock awarded to employees during the fiscal years ended February 28, 2011 and 2010 respectively; and (iv) 25,000 shares of restricted stock awarded to non-employee directors in accordance with the director compensation policy for the fiscal years ended February 28, 2011 and 2010 respectively, as described in detail under Item 11 – Executive Compensation, subheading “Director Compensation”.  Also reflects 2,040 shares that were returned to the 2009 Plan during the year ended February 28, 2015, 4,080 shares that were returned to the 2009 Plan during the year ended February 28, 2014, and 3,830 shares that were returned to the 2009 Plan during each year ended February 28, 2013 and February 29, 2012, respectively.




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2009 Restricted Stock and Restricted Stock Unit Plan


On April 6, 2009, the Board of Directors approved the 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”), allowing the executive officers, directors, consultants and employees of the Company and its affiliates (“Plan Participants”) to be eligible to receive restricted stock and restricted stock units awards, as a means of providing Plan Participants with a continuing proprietary interest in the Company.  There are no predeterminations established for restricted stock or restricted stock units to be awarded to our named executive officers or employees.


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.


Under the 2009 Plan, we may grant up to 4,000,000 shares.  The Board delegated the administration of the 2009 Plan to the Compensation Committee.  The Compensation Committee has the power and authority to select Plan Participants and grant awards of restricted stock and restricted stock units (“Awards”) to such Plan Participants pursuant to the terms of the 2009 Plan.  Awards may be in the form of actual shares of restricted Common Stock or hypothetical restricted Common Stock Units having a value equal to the fair market value of an identical number of shares of Common Stock.  Unless otherwise provided by the Compensation Committee in an individual Award agreement, Awards under the 2009 Plan vest 25% on each of the first four anniversaries of the date of grant and the unvested portion of any Award will terminate and be forfeited upon termination of the Plan Participant’s employment or service.  To date, the Compensation Committee has approved a vesting period of three years (vesting 331/3% per year), as opposed to a four-year vesting period, for Awards granted to non-employee directors.


Subject to the terms of the 2009 Plan and the applicable Award agreement, the recipients of restricted stock generally will have the rights and privileges of a shareholder with respect to the restricted stock, including the right to vote the shares and to receive dividends, if applicable.  The recipients of restricted stock units will not have the rights and privileges of a shareholder with respect to the shares underlying the restricted stock unit award until the award vests and the shares are received.  The Compensation Committee may, at its discretion, withhold dividends attributed to any particular share of restricted stock, and any dividends so withheld will be distributed to the Plan Participant upon the release of restrictions on such shares in cash, or at the sole discretion of the Compensation Committee, in shares of Common Stock having a fair market value equal to the amount of such dividends.  Awards under the 2009 Plan may not be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by a Plan Participant other than by will or by the laws of descent and distribution.


Change in Control


Unless otherwise provided in an Award agreement, in the event of a Change in Control (as defined in the 2009 Plan) of the Company, the Compensation Committee may provide that the restrictions pertaining to all or any portion of a particular outstanding Award will expire at a time prior to the change in control.  To the extent practicable, any actions taken by the Compensation Committee to accelerate vesting will occur in a manner and at a time that will allow affected Plan Participants to participate in the change in control transaction with respect to the Common Stock subject to their Awards.


Amendment and Termination


The Board at any time, and from time to time, may amend or terminate the 2009 Plan; provided, however, that such amendment or termination shall not be effective unless approved by the Company’s shareholders to the extent shareholder approval is necessary to comply with any applicable tax or regulatory requirements.  In addition, any such amendment or termination that would materially and adversely affect the rights of any Plan Participant shall not to that extent be effective without the consent of the affected Plan Participant.  The Compensation Committee at any time, and from time to time, may amend the terms of any one or more Awards; provided, however, that the Compensation Committee may not effect any amendment that would materially and adversely affect the rights of any Plan Participant under any Award without the consent of such Plan Participant.




30



At February 29, 2016, a total of 3,000,000 shares of restricted stock had been awarded and 2,986,220 of those were fully vested and remained outstanding under the 2009 Plan.  A total of 1,013,780 common stock shares remained available at February 29, 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(3)

 

5,870

 

-

7/22/2010

 

25,000

 

3 Years

 

25,000(4)

 

-

 

-

7/22/2010

 

425,000

 

4 Years

 

417,090(5)

 

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.

(3)

In accordance with the award, on July 16, 2013, 156,250 shares were vested with 2,040 shares being returned to the 2009 Plan.

(4)

In accordance with the award, on July 22, 2013, 8,335 shares were vested.

(5)

In accordance with the award, on of July 22, 2014, 106,250 shares were vested, with 2,040 shares being returned to the 2009 Plan.


For the year ended February 29, 2016, the Company recognized compensation expense related to the above restricted stock grants of $-0-.  There was no unamortized stock compensation expense remaining as of as of February 29, 2016.


Preferred Stock


The Company is authorized to issue up to 10,000,000 shares of Preferred Stock with a par value of $0.001.  Our 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.  In July 2006, we completed a private placement of the Series A Preferred that resulted in the issuance of 1,399,765 Series A Preferred shares to 100 accredited investors.


The following is a summary of the rights and preferences of the Series A Preferred.


Voluntary Conversion:


The Series A Preferred that is currently issued and outstanding is eligible to be converted by the shareholder at any time into three shares of the Company’s Common Stock.  During the year ended February 29, 2016, one conversion of 10,000 shares of Series A Preferred occurred resulting in 30,000 shares of our Common Stock being issued.




31



At February 29, 2016, there were 724,565 shares issued and outstanding that had not been converted into our Common Stock.  As of February 29, 2016, there were 43 accredited investors who had 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 are 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

Totals

 

675,200

 

2,025,600

 

43


Automatic Conversion:


The Series A Preferred shall be automatically converted into Common Stock if the Common Stock into which the Series A Preferred are convertible is registered with the SEC and at any time after the effective date of the registration statement the Company’s Common Stock closes at or above $3.00 per share for 20 out of 30 trading days.


Dividend:


Holders of Series A Preferred shall be paid dividends, in the amount of 6% of the original purchase price per annum. Dividends may be paid in cash or Common Stock at the discretion of the Company. 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.  Accumulations of dividends on shares of Series A Preferred do not bear interest.  Dividends are payable upon declaration by the Board of Directors.  There have been no cash or common stock dividends declared by the Board of Directors to date.


Cumulative dividends earned for each fiscal year since issuance are set forth in the table below:


Fiscal Year Ended

 

Shareholders at

Period End

 

Accumulated

Dividends

February 28, 2007

 

100

 

$

155,311

February 29, 2008

 

90

 

 

242,126

February 28, 2009

 

78

 

 

209,973

February 28, 2010

 

74

 

 

189,973

February 28, 2011

 

70

 

 

173,707

February 29, 2012

 

70

 

 

163,624

February 28, 2013

 

68

 

 

161,906

February 28, 2014

 

59

 

 

151,323

February 28, 2015

 

58

 

 

132,634

February 29, 2016

 

57

 

 

130,925

 

 

 

 

$

1,711,502


Liquidation Preference:


In the event of any liquidation, dissolution or winding up of the Company, either voluntary or involuntary, the holders of the Series A Preferred shall be entitled to receive, prior and in preference to any distribution of any of the assets or surplus funds of the Company to the holders of Common Stock by reason of their ownership thereof, and subject to the rights of any series of preferred stock that may rank on liquidation prior to the Series A Preferred, an amount equal to all accrued or declared but unpaid dividends on such shares, for each share of Series A Preferred then held by them.  The remaining assets shall be distributed ratably to the holders of Common Stock and Series A Preferred on a common equivalent basis.  Certain other events, as described in our Amended and Restated Articles of Incorporation, including a consolidation or merger of the Company or the disposition of the Company’s assets, may trigger the payment of the liquidation preference to the holders of Series A Preferred.



32




Voting Rights:


The holders of the Series A Preferred will vote together with the Common Stock and not as a separate class except as specifically provided or as otherwise required by law.  Each share of the Series A Preferred shall have a number of votes equal to the number of shares of Common Stock then issuable upon conversion of such shares of Series A Preferred.


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 February 29, 2016.  In comparison, at February 28, 2015, a total of 51,457,373 shares were issued and outstanding.  This change of 30,000 shares was attributable as shown in the table below:


 

Common Stock

Balance

 

Par Value

Common stock, Issued and Outstanding, February 28, 2014

55,509,411 

 

 

 

Conversion of Series A Convertible Preferred Stock to common stock

9,000 

 

$

Exercise of warrants issued with 12% Subordinated Notes

50,000 

 

$

50 

Cashless exercise of warrants

1,873,554 

 

$

1,874 

Common stock-for-warrant exchange (Maximilian)

(427,729)

 

$

(428)

Transfer agent balancing adjustment

140,000 

 

$

140 

Share purchase and cancellation (Maximilian)

(5,694,823)

 

$

(5,695)

Common stock returned to 2009 Stock Plan (tax withholding liability)

(2,040)

 

$

(2)

Common stock, Issued and Outstanding, February 28, 2015

51,457,373 

 

 

 

Conversion of Series A Convertible Preferred Stock to Common Stock

30,000 

 

$

30 

Common stock, Issued and Outstanding, February 29, 2016

51,487,373 

 

 

 


All shares of Common Stock are equal to each other with respect to voting, liquidation, dividend and other rights.  Owners of shares of Common Stock are entitled to one vote for each share of Common Stock owned at any shareholders’ meeting.  Holders of shares of Common Stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefore; and upon liquidation, are entitled to participate pro rata in a distribution of assets available for such a distribution to shareholders.


There are no conversion, preemptive, or other subscription rights or privileges with respect to any shares of our Common Stock.  Our stock does not have cumulative voting rights, which means that the holders of more than 50% of the shares voting in an election of directors may elect all of the directors if they choose to do so.  In such event, the holders of the remaining shares aggregating less than 50% would not be able to elect any directors.


Warrants


Maximilian Financing and Credit Facility


On October 31, 2012, the Company entered into a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment from Maximilian Investors LLC (either party, as appropriate, is referred to as “Maximilian”).  In connection with this loan, 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.  On March 10, 2014, one of the third parties who assisted in this financing transaction exercised 2,118,900 warrants resulting in the issuance of 1,873,554 shares of Common Stock.


In connection with the Company’s acquisition of a working interest from App Energy, LLC, a Kentucky limited liability company (“App”), in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013.  As consideration for Maximilian facilitating the Company’s transactions with App and entering into the amended loan agreement, the Company issued to Maximilian 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.




33



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


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


The fair value of the above warrant issuances that were recognized as a deferred financing cost are being amortized over the term of the loan.  Amortization expense was $127,513 for the years ended February 29, 2016 and February 28, 2015.  Unamortized deferred financing costs amounted to $191,270 as of February 29, 2016.


On February 14, 2014, the Company at the request of Maximilian, amended the warrant agreement related to the above issuance of approximately 6.1 million warrants to include a warrant exercise blocker provision that would effectively prevent 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 currently issued and outstanding shares at the time of the exercise.  All other terms of the original warrant agreement remained unchanged.


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 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 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 modification did not result to any accounting since these warrants were deemed to be investor warrants.


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”).  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.


12% Subordinated Notes – Warrant Expiration Extension


On January 29, 2015, the expiration date of the warrants that were issued in conjunction with the 12% Subordinated Notes from a January 2010 private placement offering to accredited investors was extended for an additional two years.  The warrant expiration extension applied to noteholders who chose to extend the maturity date of the 12% Subordinated Notes for an additional two years and had not already exercised the associated warrants.  Ten of the original 13 noteholders had the expiration date of their warrants extended to January 29, 2017.  The fair value of the warrant extension, as determined by the Black-Scholes option pricing model, was $56,519 using the following weighted average assumptions: a risk free interest rate of 0.51%; volatility of 153.4%; and dividend yield of 0.0%.  The fair value of the warrants was recognized as a loss on settlement of debt.




34



Warrants outstanding and exercisable as of February 29, 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

 

0.92

 

980,000

Warrants issued in 2012 for debt financing

 

2,435,517

 

$0.044

 

1.67

 

316,617

Warrants issued for Kentucky oil project

 

3,498,601

 

$0.04

 

2.50

 

3,498,601

Warrants issued for Kentucky debt financing

 

2,623,951

 

$0.04

 

2.50

 

2,623,951

Warrants issued for Kentucky debt financing

 

309,503

 

$0.214

 

2.50

 

309,503

Warrants issued in share-for-warrant exchange

 

427,729

 

$0.04

 

2.50

 

427,729

 

 

10,485,301

 

 

 

 

 

8,156,401


During the years ended February 29, 2016 and February 28, 2015, a total of 150,000 and 60,000 warrants expired, respectively.  All of the expired warrants were associated with the 12% Subordinated Note offering and had been issued to investors or were for services associated with the offering.  There were no warrants issued during the year ended February 29, 2016.  During the year ended February 28, 2015 there were 427,729 warrants issued in connection with the share-for-warrant exchange agreement with Maximilian as described in Note 11 - Short-Term and Long-Term Borrowings.  The 2,168,900 warrants exercised in the year ended February 28, 2015 were issued (a) to a third party who assisted in the Maximilian financing (2,118,900) and (b) in conjunction with the 12% Subordinated Notes (50,000).  The outstanding warrants as of February 29, 2016 and February 28, 2015 have a weighted average exercise price of $0.06 and $0.11; a weighted average remaining life of 2.28 and 1.65 years; and an intrinsic value of $-0- and $14,564, respectively.





35



ITEM 6.   SELECTED FINANCIAL DATA


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





36



ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The following management’s discussion and analysis (“MD&A”) is management’s assessment of the financial condition, changes in our financial condition and our results of operations and cash flows for the twelve months ended February 29, 2016 and February 28, 2015.  This MD&A should be read in conjunction with the audited financial statements and the related notes and other information included elsewhere in this Annual Report on Form 10-K.


Safe Harbor Provision


Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations 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 facts contained in this MD&A report, including statements regarding our current expectations and projections about future results, intentions, plans and beliefs, business strategy, performance, prospects and opportunities, are inherently uncertain and are forward-looking statements.  For more information about forward-looking statements, please refer to the section labeled “Cautionary Statement About Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.


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 long-term success depends on, among many other factors, the successful acquisition and drilling of commercial grade oil and natural gas properties as well as 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, will 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.  We are currently 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.  While we have positive cash flow from our continuing crude oil and natural gas operations in Kentucky and California, we have not yet generated sustainable positive cash flow or 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 more fully described in Item 1A. Risk Factors of this Annual Report on Form 10-K for the fiscal year ended February 29, 2016.


Throughout this Annual Report on Form 10-K, oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) or British Thermal Units (“BTU”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).


Year-to-Date Results


This was a period of time that was full of challenges, primarily managing our dwindling cash flow in the face of declining hydrocarbon prices.  During the twelve months ended February 29, 2016, we were successful in accomplishing the following objectives:


·

Kentucky development program – We drilled and put on production one development well.  We also obtained a core from our development well while it was being drilled.  The core was analyzed and the results were factored into our fracturing program for this and future wells.



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·

Increasing our proven reserves – Our total proved reserves increased 1.6% or 14,644 BOE to 902,780 BOE.  Our proved undeveloped reserves (PUD) increased by 13% or 77,451 barrels to 671,002 (BOE) primarily due to the drilling of the one development well during the twelve months ended February 29, 2016.


Below is brief summary of our oil and natural gas projects in Kentucky and California.  Refer to our discussion in Item 2. Properties, in this Annual Report on Form 10-K for more information on both the Twin Bottoms Field in Lawrence County, Kentucky and our East Slopes Project in Kern County, 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 Oil Sand, 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 crude oil measuring between 42° and 44° API (American Petroleum Institute) gravity.  During the year ended February 29, 2016, we had production from 14 wells.  Our average working interest 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.


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 that 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 from our acreage in 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 twelve months ended February 29, 2016 we had production from 20 vertical oil wells.  Our average working interest 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.


Results of Operations – For the years ended February 29, 2016 and February 28, 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 76% of the TCO Appalachia price per dekatherm (DTH) less $0.25 compression cost for each Mcf of 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 correspondently 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.


 

 

February 2016

 

June 2014

 

Percentage

Decline

Monthly average WTI crude oil price

 

$

30.32

 

$

105.79

 

71.3%

Monthly average realized crude oil sales price (Bbl)

 

$

24.20

 

$

101.45

 

76.1%


Crude Oil and Natural Gas Revenue, Production and Realize 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 twelve months ended February 29, 2016 in aggregate decreased $1,830,111 or 59.4%, to $1,253,686 in comparison to revenues of $3,083,797 for the twelve months ended February 28, 2015.  Oil and natural gas sales volume decreased 7,849 BOE (barrels of oil equivalent) or 18.9% to 33,626 (BOE) in comparison to 41,476 (BOE) for the twelve months ended February 28, 2015.  The decrease in volume was primarily due to the natural decline in oil producing reservoir pressure.  Our average realized sale price on a BOE basis for the twelve months ended February 29, 2016 was $37.28 in comparison to $74.35 for the twelve months ended February 28, 2015, representing a decline of $37.07 or 49.9% per barrel.  Approximately $1.5 million or 84.0% of the decline in revenue can be directly attributed to the decline in hydrocarbon prices for the twelve months ended February 29, 2016.



38




Kentucky Oil Prices


For the twelve months ended February 29, 2016, our average realized oil sale price was $46.40 in comparison to the average WTI price of $45.72 representing a premium of $0.68 per barrel or 1.5% higher than the average WTI price.  In comparison, for the twelve months ended February 28, 2015, the average WTI price was $85.12 and our average realized sale price was $80.82 representing a discount of $4.30 per barrel or 5.1% lower than the average WTI price.


Kentucky Oil Revenue and Production


Oil revenue in Kentucky for the twelve months ended February 29, 2016 decreased $1,053,531 or 60.7% to $680,869 in comparison to revenue of $1,734,400 for the twelve months ended February 28, 2015.  The average sale price of a barrel of oil for the twelve months ended February 29, 2016 was $46.40 in comparison to $80.82 for the twelve months ended February 28, 2015.  The decrease of $34.42 or 42.6% in the average realized price of a barrel of oil accounted for $738,600 or 70.1% of the decline in oil revenue while a decrease of $314,930 or 29.9% can be attributed to a decline in production for the twelve months ended February 29, 2016.


Our net sales volume for the twelve months ended February 29, 2016 was 14,673 barrels of oil in comparison to 21,460 barrels sold for the twelve months ended February 28, 2015.  This decrease in oil sales volume of 6,787 barrels or 31.6% was due to the natural decline in reservoir pressure partially offset by the addition of one new development well being put on production during the twelve months ended February 29, 2016.


The gravity of our produced oil in Kentucky ranges between 42° API and 44° API.  Production for the twelve months ended February 29, 2016 was from 14 wells resulting in 4,241 well days of production in comparison to 2,634 well days of production from 13 wells for the twelve months ended February 28, 2015.  The increase of 1,607 well days or 61.0% of production was due to gas pipeline infrastructure improvements within the Twin Bottoms Field and a full year of production time for 13 horizontal oil wells.


Kentucky Natural Gas Prices


For the twelve months ended February 29, 2016, our average realized natural gas sale price was $1.51 per Mcf (thousand cubic feet) in comparison to the average Henry Hub price of $2.64 per million BTU representing a discount of $1.13 per Mcf or 43.0% lower than the average Henry Hub price.  In comparison, for the twelve months ended February 28, 2015, the average realized sale price was $2.97 per Mcf in comparison to the average Henry Hub price of $3.99 per million BTU representing a discount of $1.02 or 25.5% lower than the average Henry Hub price.


Kentucky Natural Gas Revenue and Production


Natural gas revenue for the twelve months ended February 29, 2016 decreased $21,029 or 32.6% to $43,457 in comparison to revenue of $64,486 for the twelve months ended February 28, 2015.  The average sale price per Mcf for the twelve months ended February 29, 2016 was $1.51 in comparison to $2.97 for the twelve months ended February 28, 2015.


Our net sales volume for the twelve months ended February 29, 2016 was 28,853 Mcf or 4,809 BOE in comparison to 21,687 Mcf or 3,614 BOE for the twelve months ended February 28, 2015.  The increase in natural gas volume was due to having 13 horizontal wells on production during the twelve months ended February 29, 2016 and the resolution of infrastructure issues that had previously inhibited natural gas production from existing wells.


California Oil Prices


For the twelve months ended February 29, 2016, the average WTI price was $45.72 and our average realized oil sale price was $37.43, representing a discount of $8.29 per barrel or 18.1% lower than the average WTI price.  In comparison, for the twelve months ended February 28, 2015, the average WTI price was $85.12 and our average realized sale price was $78.34 representing a discount of $6.78 per barrel or 8.0% 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 the API gravity of WTI oil.





39



California Oil Revenue and Production


Oil revenue in California for the twelve months ended February 29, 2016 decreased $755,551 or 58.8% to $529,360 in comparison to revenue of $1,284,912 for the twelve months ended February 28, 2015.  The average sale price of a barrel of crude oil for the twelve months ended February 29, 2016 was $37.43 in comparison to $78.34 for the twelve months ended February 28, 2015.  The decrease of $40.92 or 52.2% in the average realized price of a barrel of oil accounted for $671,083 or 88.8% of the decline in oil revenue while a decrease of $84,469 or 11.2% can be attributed to a decline in production for the twelve months ended February 29, 2016.


Our net sales volume for the twelve months ended February 29, 2016 was 14,144 barrels of oil in comparison to 16,402 barrels sold for the twelve months ended February 28, 2015.  This decrease in oil sales volume of 2,258 barrels or 13.8% was primarily due to the natural decline in reservoir pressure during the twelve months ended February 29, 2016.


The gravity of our produced oil in California ranges between 14° API and 16° API.  Production for the twelve months ended February 29, 2016 was from 20 wells resulting in 7,210 well days of production in comparison to 7,225 well days of production for the twelve months ended February 28, 2015.


Our oil and natural gas revenues from Kentucky and California are set forth in the table below:


 

 

Twelve Months Ended

February 29, 2016

 

Twelve Months Ended

February 28, 2015

Project

 

Revenue

 

Percentage

 

Revenue

 

Percentage

Kentucky – Twin Bottoms Field (Oil)

 

$

680,869

 

54.3%

 

$

1,734,400

 

56.2%

Kentucky – Twin Bottoms Field (Gas)

 

 

43,457

 

3.5%

 

 

64,486

 

2.1%

California – East Slopes Project (Oil only)

 

 

529,360

 

42.2%

 

 

1,284,911

 

41.7%

Total oil and natural gas revenues*

 

$

1,253,686

 

100.0%

 

$

3,083,797

 

100.0%


*Our average realized sale price on a BOE basis for the twelve months ended February 29, 2016 was $37.28 in comparison to $74.35 for the twelve months ended February 28, 2015, representing a decrease of $37.07 or 49.9% per barrel.


Of the $1,830,111 or 59.4% decline in revenue for twelve months ended February 29, 2016, approximately $1.5 million or 84.0% can be directly attributed to the decline in the price of crude oil and natural gas.


Operating Expenses


Total operating expenses increased $933,985 or 45.6% to $2,980,051 for the twelve months ended February 29, 2016 in comparison to $2,046,066 for the twelve months ended February 28, 2015.  As shown below, this increase in expenses was due to impairment recognition of oil and gas properties for $1,108,683.  Our operating expenses are set forth in the table below:


 

 

Twelve Months Ended

February 29, 2016

 

Twelve Months Ended

February 28, 2015

 

 

Expenses

 

Percentage

 

BOE

Basis

 

Expenses

 

Percentage

 

BOE

Basis

Production expenses

 

$

268,448

 

8.5%

 

 

 

 

$

329,917

 

16.1%

 

 

 

Exploration and drilling expenses

 

 

76,053

 

2.4%

 

 

 

 

 

42,997

 

2.1%

 

 

 

Depreciation, Depletion, Amortization (“DD&A”)

 

 

517,870

 

16.5%

 

 

 

 

 

570,110

 

27.9%

 

 

 

Impairment of oil and gas properties

 

 

1,108,683

 

35.3%

 

 

 

 

 

-

 

-

 

 

 

General and Administrative (“G&A”) expenses

 

 

1,172,206

 

37.3%

 

 

 

 

 

1,103,042

 

53.9%

 

 

 

Total operating expenses

 

$

3,143,260

 

100.0%

 

$

93.48

 

$

2,046,066

 

100.0%

 

$

49.24


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 maintenance and workover expenses; and, relate directly to the number of wells that are on production.  For the twelve months ended February 29, 2016, these expenses decreased $61,469, or 18.6% to $268,448 in comparison to $329,917 for the twelve months ended February 28, 2015.  For the twelve months ended February 29, 2016, we had 14 wells on production in Kentucky and 20 wells on production in California in comparison to 13 wells on production in Kentucky and 20 wells on production in California for the twelve months ended February 28, 2015.  Production expenses represented 8.5% of total operating expenses in comparison to 16.1% for the year ended February 28, 2015.




40



Production expenses in Kentucky and California for the twelve months ended February 29, 2016 and February 28, 2015 are set forth in the table below:


 

 

Twelve Months Ended

February 29, 2016

 

Twelve Months Ended

February 28, 2015

 

 

Expenses

 

Percentage

 

Expenses

 

Percentage

Kentucky – Twin Bottoms Field  

 

$

107,608

 

40.1%

 

$

150,233

 

45.5%

California – East Slopes Project

 

 

160,840

 

59.9%

 

 

179,684

 

54.5%

Total production expenses

 

$

268,448

 

100.0%

 

$

329,917

 

100.0%


Production expenses on a BOE basis in Kentucky and California for the twelve months ended February 29, 2016 and February 28, 2015 are set forth in the table below:


 

 

Twelve Months Ended

 

 

February 29, 2016

 

February 28, 2015

Kentucky – Twin Bottoms Field (BOE)  

 

$

5.52

 

$

5.99

California – East Slopes Project (BOE)

 

$

11.37

 

$

10.96

Aggregate production expenses (BOE)

 

$

7.98

 

$

7.95


Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses increased $33,056 or 76.9% to $76,053 for the twelve months ended February 29, 2016 in comparison to $42,297 for the twelve months ended February 28, 2015.  Exploration and drilling expenses represented 2.4% of total operating expenses in comparison to 2.1% for the twelve months ended February 28, 2015.


Depreciation, Depletion, Amortization (“DD&A”) expense relates to equipment, proven reserves and property costs, along with impairment and is another component of operating expenses.  These expenses decreased $52,240 or 9.2% to $517,870 for the twelve months ended February 29, 2016 in comparison to $570,110 for the year ended February 28, 2015.  This decrease is directly related to lower hydrocarbon prices and reduced production during the twelve months ended February 29, 2016.  On a BOE basis, DD&A in Kentucky was 14.21 and $17.04 in California.  In aggregate, DD&A for the twelve months ended February 29, 2016 was $15.40.  DD&A expenses represented 16.5% of total operating expenses in comparison to 27.9% for the twelve months ended February 28, 2015.


Impairment of proved and unproved oil properties in California for the twelve months ended February 29, 2016 was $1,108,683 for the twelve months ended February 29, 2016 in comparison to $-0- for the twelve months ended February 28, 2015.  On a BOE basis in aggregate, impairment of oil properties in California represented $32.97.  This impairment was caused by lower hydrocarbon prices resulting in lower economic reserve valuation and a reduction in our cash flows in California.  Impairment of oil properties represented 35.3% of total operating expenses.


General and administrative (“G&A”) expenses include the salaries of six employees, including management.  Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as for running a public company.  These expenses increased $69,163 or 6.3% to $1,172,206 for the twelve months ended February 29, 2016 in comparison to $1,103,042 for the twelve months ended February 28, 2015.  Accounting, reserve reporting and legal expenses decreased by $57,255 in aggregate during the twelve months ended February 29, 2016.  Director fees decreased $12,125 due to fewer Board of Directors meetings.  Advertising, marketing and press release expense decreased by $8,590.  Rent, office supplies and postage decreased by $5,675.  These decreases were offset by the recognition of $169,340 in expenses associated with our refinancing efforts.  For the year ended February 29, 2016, we received, as Operator of the East Slopes project in California, administrative overhead reimbursement of $66,487, 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 approximately 37.3% of total operating expenses in comparison to 53.9% for the twelve months ended February 28, 2015.


Interest income decreased $41,352 or 3.8% to $1,039,862 for the twelve months ended February 29, 2016 in comparison to $1,081,214 for the twelve months ended February 28, 2015 primarily due to a lower loan balance and interest rate on the Note Receivable from App Energy, LLC.  For further discussion on this Note refer to the App Loan Agreement under the caption “Non-current Borrowings” in this MD&A.




41



Interest expense increased $560,407 or 20.0% to 3,355,776 for the twelve months ended February 29, 2016 in comparison to $2,795,369 for the twelve months ended February 28, 2015 due to higher balances on our credit facility with Maximilian.  This financing transaction is discussed further in the MD&A section of this 10-K report under the caption “Non-current debt – Maximilian Loan.”


Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially quarter-to-quarter and year-to-year.  The material adverse impact of lower crude oil prices on our revenues cannot be understated.  For the twelve months ended February 29, 2016 our sales volume on a BOE basis decreased by 18.9% while our revenues decreased 59.4% during the same time period.  Production costs will fluctuate according to the number and percentage ownership of producing wells, as well as the amount of revenues being contributed by such wells.  Exploration and drilling expenses will be dependent upon the amount of capital that we have to invest in future development projects, as well as the success or failure of such projects.  Likewise, the amount of DD&A expense will depend upon the factors cited above, plus the size of our reserve base and the market price of energy products.  G&A costs will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.  An ongoing goal throughout the Company is to improve cash flow to cover the current level of G&A expenses and to fund our development drilling in California and Kentucky.


Capital Resources and Liquidity


Our primary financial resource is our base of oil reserves. Our ability to fund our capital expenditure program is dependent upon the prices we receive from our oil and natural gas sales; the success of our development program in Kentucky; and the availability of capital resource financing.  In the next fiscal year, we plan on investing approximately $1.0 million in new capital expenditures; however our actual expenditures may vary significantly from this estimate if our plans for exploration and development activities change during the year.  Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.


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


 

February 29, 2016

 

February 28, 2015

 

Increase

(Decrease)

 

Percentage

Change

Cash

$

6,995 

 

$

496,772 

 

$

(489,777)

 

(98.6%)

Current Assets

$

1,475,555 

 

$

2,554,519 

 

$

(1,078,964)

 

(42.2%)

Total Assets

$

9,601,079 

 

$

12,313,061 

 

$

(2,711,982)

 

(22.0%)

Current Liabilities

$

(18,911,089)

 

$

(8,311,541)

 

$

10,599,548 

 

127.5%

Total Liabilities

$

(18,991,068)

 

$

(17,497,651)

 

$

1,493,417 

 

8.5%

Working Capital

$

(17,435,534)

 

$

(5,757,022)

 

$

(11,678,512)

 

(202.9%)


Our working capital deficit increased by $11,678,512 or 202.9% from a deficit of $5,757,022 at February 28, 2015 to a deficit of $17,435,534 at February 29, 2016.  The increase in the working capital deficit is primarily related to the classification of the entire Maximilian credit facility balance of $14,309,180 as a current liability in accordance with guidance from ASC 470-10-45 as compared to $4,691,211 in current liabilities at February 28, 2015.  Partially offsetting this balance sheet presentation was the classification of $641,075 in net deferred financing costs being presented as a current asset.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not been made by us since December 2015.  Due to the waivers granted by Maximilian, we are currently not considered to be in default under terms of the credit facility.  Maximilian is continuing to work with us in modifying the credit facility terms during this period of lower hydrocarbon prices, but there can be no assurances that this cooperation will continue.  Further, there can be no assurances that in the future Maximilian will not declare us to be in default under the credit facility.  While we continue to have ongoing positive cash flow from our oil and gas operations in Kentucky and California during this period of low hydrocarbon prices, we are unable to generate sufficient cash flow to cover all of our general and administrative (“G&A”) and interest expense requirements.  We cannot forecast when there will be a sustained improvement in crude oil and natural gas prices allowing us to implement a more aggressive drilling program in the Twin Bottoms Field in Lawrence County, Kentucky and our East Slope operations in Kern County, California.


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.




42



Major sources of funds in the past for us have included the debt or equity markets.  While we have achieved positive cash flow from our 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 gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources.


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


For the current fiscal year, we may 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.  No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all.  Sales of interests in our assets may be another source of cash flow.


Cash Flows


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


 

Twelve Months Ended

February 29, 2016

 

Twelve Months Ended

February 28, 2015

 

Increase

(Decrease)

 

Percentage

Change

Net cash provided by (used in) operating activities

$

(496,667)

 

$

312,700 

 

$

(809,367)

 

(258.8)%

Net cash provided by (used in) investing activities

$

636,034 

 

$

(2,717,083)

 

$

3,353,117 

 

123.4% 

Net cash provided by (used in) financing activities

$

(629,144)

 

$

2,400,724 

 

$

(3,029,868)

 

 (126.2%)


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 year ended February 29, 2016, cash used in our operating activities was $496,667 in comparison to cash flow provided by operating activities of $312,700 for the twelve months ended February 28, 2015.  This decrease in cash provided by operating activities of $809,367 was due to a decline in operating revenue of $1.8 million; a decrease in receivables and prepaids and the net loss offset by an increases in accounts payable.  Non-cash expenses increased by $965,726 in comparison to the twelve months ended February 28, 2015.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.


Our expenditures in operating activities consist primarily of exploration and drilling costs; production costs; geological, geophysical and engineering services and acquisition of mineral leases.  Our expenses also consist of consulting and professional services, employee compensation, legal, accounting, travel and other G&A expenses that we have incurred in order to address normal and necessary business activities.


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, LLC (“App”) loan.  Cash flow provided by investing activities for the twelve months ended February 29, 2016 was $636,034 in comparison to $2,717,083 used in investing activities for the twelve months ended February 28, 2015.  We invested approximately $171,000 million in our multi-well drilling program in Kentucky and collected $775,500 from App in payments on their advances in Kentucky.  Refer to the caption “Non-current debt – App Loan Agreement” for further discussion of the App loan.





43



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 flow used in our financing activities was $629,144 for the twelve months ended February 29, 2016 in comparison to $2,400,724 provided by our financing activities for the year ended February 28, 2015.  For the twelve months ended February 29, 2016 we received advances of $25,000 on our credit facility and we made principal payments of $618,431 against the outstanding balance.  We anticipate it will continue to be necessary to rely on additional funding from the capital markets in the current fiscal year to maintain our current drilling program.  The following is a summary of cash flows provided by, and used in, the Company’s financing activities for the twelve months ended February 29, 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 has been used for a variety of corporate purposes including an escrow requirement on a loan commitment; extension fees on third party loans; and a reduction of principal on the Company’s credit line with UBS Bank.  These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.


Line of Credit


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 February 29, 2016 and February 28, 2015, the Line of Credit had an outstanding balance of $843,807 and $869,865, respectively.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $31,442 and  $31,498 for the years ended February 29, 2016 and February 28, 2015, respectively.  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 January 2010 private placement, resulted in $595,000 in gross proceeds (of which $250,000 was from a related party) to the Company 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 Notes principal of $565,000 is payable in full at the amended maturity date 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.  The 12% Notes balances at February 29, 2016 and February 28, 2015 are set forth in the table below.


 

February 29, 2016

 

February 28, 2015

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

 

-

 

-

 

-

Totals

 

150,000

 

150,000

 

2




44




Maximilian Loan


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 gas leases in Kern County, California. The relative fair value of this 10% working interest amounting to $515,638 was recognized as a debt discount and is being amortized over the term of the loan. Amortization expense for the year ended February 29, 2016 amounted to $132,114.  Unamortized debt discount amounted to $71,951 as of February 29, 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.  Amortization expense for the year ended February 29, 2016 amounted to $127,513.  Unamortized deferred financing cost of these warrants was $191,270 as of February 29, 2016.  There were 316,617 of these warrants that remained unexercised as of February 29, 2016.


Maximilian Loan - Amended and Restated Loan Agreement


In connection with the Company’s acquisition of a working interest from App Energy, LLC (“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 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 the caption “App Loan Agreement” in the discussion below for further information).


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; contain a cash exercise provision; were exercisable for a period of three years expiring on August 28, 2016; and contain an exercise provision 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 properties, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.




45



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


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 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 our 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.  We 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 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 modification did not result to any accounting since these warrants were deemed to be investor warrants.


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 (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 20% fee is being recognized as additional interest expense.  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 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.


As a result of the decline in hydrocarbon prices, we are currently unable to make the interest or principal payments required under the terms of our credit facility with our lender, Maximilian.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not been made.  Due to the waivers granted by Maximilian, 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 assurances that this cooperation will continue.  Further, there can be no assurances that Maximilian will not declare the Company to be in default under the credit facility.  In accordance with guidance from ASC 470-10-45, since we have been unable to make the above referenced payments the entire balance of the Maximilian credit facility is presented under the current liabilities section of the financial statements.




46



Current debt balances at February 29, 2016 and February 28, 2015 are set forth in the table below:


 

February 29, 2016

 

February 28, 2015

Maximilian Note

$

14,381,131 

 

$

4,823,325 

Maximilian Note Discount

 

(71,951)

 

 

(132,114)

 

$

14,309,180 

 

$

4,691,211 


Non-current debt balances at February 29, 2016 and February 28, 2015 are set forth in the table below:


 

February 29, 2016

 

February 28, 2015

Maximilian Note

$

 

$

8,663,458 

Maximilian Note Discount

 

 

 

(71,951)

 

$

 

$

8,591,507 


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 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 Company’s leases in Lawrence County, Kentucky.


The proceeds of the initial borrowing by App of $2.65 million under the App facility were primarily used to (a) pay loan fees and closing costs, (b) repay indebtedness and (c) finance the drilling of three wells by App in the 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 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 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.




47



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.


For the twelve months ended February 29, 2016, we received principal payments of $777,500 from App Energy.  Since November 2015, App Energy has been unable to make any required interest or principal payments under terms of the amended loan agreements, but is not considered to be in default under the terms of the amended agreements because Daybreak has granted a series of waivers for the required payments as App Energy seeks to refinance their loan with alternative lenders.  The Company retains all of its rights under the loan agreements to declare App Energy in default on the loan in the future.  The App Energy loan is secured by a perfected first priority security interest in substantially all of the assets of App Energy, including its leases in Lawrence County, Kentucky.


Note receivable balances at February 29, 2016 and February 28, 2015 are set forth in the table below:


 

February 29, 2016

 

February 28, 2015

Note receivable – current

$

420,901

 

$

1,320,944

Note receivable – non-current

 

4,234,612

 

 

3,429,056

 

$

4,655,513

 

$

4,750,000


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.


Encumbrances


The Company’s debt obligations, pursuant to a 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.  This includes mortgages on the Sunday, Bear, Black, Ball and Dyer Creek Properties in California.  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 stock and restricted stock unit awards.  Subject to adjustment, the total number of shares of Daybreak’s common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.  We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.  Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.





48



At February 29, 2016, a total of 3,000,000 shares of restricted common stock had been awarded and 2,986,220 shares of the 2009 Plan had fully vested.  A total of 1,013,780 common stock shares remained available for issuance pursuant to the 2009 Plan at February 29, 2016.  For the years ended February 29, 2016 and February 28, 2015, an aggregate of -0- and 106,250 shares vested, respectively.  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 the number of common 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 years ended February 29, 2016 and February 28, 2015, the Company recognized compensation expense related to the above-restricted stock grants of $-0- and $2,515, respectively.  There was no unamortized stock compensation expense remaining as of as of February 29, 2016.


Oil and Natural Gas Reserves


Daybreak’s total net proved developed and undeveloped oil and natural gas reserves on a barrel of oil equivalent (“BOE”) basis increased by 14,644 barrels, or 1.6%, to 902,780 barrels at February 29, 2016 compared to 888,136 BOE at February 28, 2015.  Our Kentucky, Twin Bottoms Field, project added 43,186 net barrels of oil and 523,160 net Mcf of natural gas or an additional 130,379 net BOE in aggregate to our proved reserve base after adjusting for extensions, revisions and production.  The proved reserve base in California declined by 115,735 barrels of oil due to reserve revisions and production.  Net proved developed reserves in aggregate decreased by 62,807 BOE or 21.3%, to 231,778 BOE at February 29, 2016 compared to 294,585 BOE at February 28, 2015.  This net decrease was caused by 33,627 BOE of production and 37,317 BOE of downward revisions from lower hydrocarbon prices offset by 8,137 BOE of extensions in Kentucky.  Net proved undeveloped reserves increased by 77,451 BOE or 13.0% to 671,002 BOE at February 29, 2016 in comparison to 593,551 at February 28, 2015. This net increase in proved undeveloped reserves was from 95,020 BOE in extensions in Kentucky offset by downward revisions of 17,569 in aggregate.  Our reserves were fully engineered by PGH Petroleum and Environmental Engineers, LLC of Austin, Texas in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.  For further information on our reserve report, refer to exhibit 99.1 of this Annual Report on Form 10-K.


Changes in Financial Condition


During the year ended February 29, 2016, we received crude oil and natural gas sales revenue from 14 wells in Lawrence County, Kentucky and crude oil sales revenue from 20 wells in our East Slopes Project in Kern County, California.  Our commitment to improving corporate profitability remains unchanged.  Since June 2014, there has been a significant decline in the WTI price of crude oil and correspondently 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.  During the year ended February 29, 2016, oil and natural gas revenues in aggregate decreased $1,830,111 or 59.4%, to $1,253,686.  Approximately $1.5 million or 84.0% of the decline in revenue can be directly attributed to the decline in hydrocarbon prices for the twelve months ended February 29, 2016.  An additional consequence of lower hydrocarbon prices was the recognition of $1,108,683 in impairment of proved and unproved oil properties in California.  These two factors were the primary reasons why we incurred an operating loss of $1,889,574 for the twelve months ended February 29, 2016 in comparison to an operating profit of $1,037,731 for the twelve months ended February 28, 2015.


Our balance sheet at February 29, 2016 reflects total assets of $9,601,079 a decrease of $2,711,982 or 22.0% in comparison to $12,313,061 at February 28, 2015.  This decrease in total assets is comprised primarily of a $1.3 million decrease in oil and gas properties due to DD&A and impairment; a $0.5 million decrease in cash and an approximate $318,000 decrease in accounts receivable and prepaid expenses in aggregate.



49




At February 29, 2016, total liabilities were $18,991,068, an increase of approximately $1.5 million or 8.5% in comparison to $17,497,651 at February 28, 2015.  This increase was primarily comprised of a $1.0 million increase in our credit line facility balance and approximate $420,000 increase in our accounts payable.


Our common stock issued and outstanding increased by 30,000 shares to 51,487,373 for the year ended February 29, 2016 in comparison to 51,457,373 for the year ended February 28, 2015.  This increase in shares outstanding was due to the conversion of 10,000 shares of our Series A Convertible Preferred stock to common stock.


Accumulated Deficit


Our financial statements for the year ended February 29, 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.  Our financial statements show that the Company has incurred significant operating losses that raise substantial doubt about our ability to continue as a going concern.  The accompanying financial statements do not include any adjustments that might result from this uncertainty.


The increase in the accumulated deficit from $28,205,516 as of February 28, 2015 to $32,410,915 as of February 29, 2016 was due to the $4,205,399 net loss for the year.  Approximately $2.3 million of the loss can be attributed to net interest expense while another $1.1 million can be attributed to impairment of proved and unproved oil properties in California due to lower hydrocarbon prices during the year ended February 29,2016.  For the year ended February 29, 2016 we had a net operating loss of $1,889,574 in comparison to a net operating income of $1,037,731 for the year ended February 28, 2015.


Cash Balance


We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations, investments and capital resource funding.  Our cash balances were $6,995 and $496,772 at February 29, 2016 and February 28, 2015, respectively.


Crude oil and natural gas revenues


Crude oil and natural gas revenues decreased $1,830,111 or 59.4% to $1,253,686 for the twelve months ended February 29, 2016 in comparison to $3,083,797 for the twelve months ended February 28, 2015.  Approximately 84.0% or $1.5 million of this decrease was due to the continuing decline in crude oil and natural gas prices during the twelve months ended February 29, 2016.


Operating Expenses


Operating expenses increased by $1,097,195 or 53.6% to $3,143,260 in comparison to $2,046,066 for the twelve months ended February 28, 2015.  This increase in expenses was due to the recognition of $1.1 million in impairment of proved and unproved oil properties in California for the twelve months ended February 29, 2016.


Operating (Loss) Income


For the year ended February 29, 2016, we reported an operating loss of $1.9 million in comparison to an operating income of $1.0 million for the twelve months ended February 28, 2015.  This decrease in operating income of $2.9 million was due to lower crude oil and natural gas revenues and increased operating expenses as explained immediately above.


Net Loss


Since entering the oil and gas exploration industry, we have incurred net losses with periodic negative cash flow and have depended on external financing and the sale of oil and gas assets to sustain our operations.  A net loss of $4.2 million was reported for the twelve months ended February 29, 2016 in comparison to a net loss of $0.7 million for the twelve months ended February 28, 2015.  The increase in the net loss of $3.5 million for the twelve months ended February 29, 2016 was due to a decrease in crude oil and natural gas revenues ($1.8 million); an increase in operating expenses ($1.1 million); and, an increase in net interest expense of $0.5 million.




50



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 oil wells in our East Slopes Project located in Kern County, California.  The revenue from these wells has created a steady and reliable source of revenue for the Company.  Our average working interest in these wells is 36.6% and the average net revenue interest is 28.5%.


Additionally, we have a working interest in a shallow oil play in an existing gas field in Lawrence County, Kentucky, through our acquisition of a 25% working interest in approximately 7,300 acres in two large contiguous acreage blocks in the Twin Bottoms Field in Lawrence County, Kentucky.  We currently have a net revenue interest in 13 producing horizontal oil wells with associated natural gas production.  Our average working interest in these wells is 22.4% and the average net revenue interest is 19.6%.


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 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.


Critical Accounting Policies


Critical accounting policies are policies that are both most important to the portrayal of the Company’s financial condition and results, and that require management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.  Management’s discussion and analysis of our financial condition and results of operations are based on our financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America.  The preparation of these financial statements requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.


On an ongoing basis, we evaluate our estimates, including those related to revenue recognition, bad debts, cancellation costs associated with long term commitments, investments, intangible assets, assets subject to disposal, income taxes, service contracts, contingencies and litigation.  We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making estimates and judgments about the carrying value of assets and liabilities that are not readily apparent from other sources.  Estimates, by their nature, are based on judgment and available information.  These judgments and uncertainties do affect the application of these critical accounting policies.  There is a strong likelihood that materially different amounts could be reported under different conditions or using different assumptions.  Therefore, actual results could differ from those estimates and could have a material impact on our financial statements, and it is possible that such changes could occur in the near term.


Oil and Natural Gas Properties


We use the successful efforts method of accounting for oil and natural gas property acquisition, exploration, development, and production activities.  Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred.  Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred.  In addition, the geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred.  Costs to operate and maintain wells and field equipment are expensed as incurred.


Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on proved reserves.  Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their proved developed reserves.  Support equipment and other property and equipment are depreciated over their estimated useful lives.



51




Pursuant to Financial Accounting Standards Board Codification (“ASC”) Topic 360, “Property, Plant and Equipment,” we review proved oil and natural gas properties and other long-lived assets for impairment.  These reviews are predicated by events and circumstances, such as downward revision of the reserve estimates or commodity prices that indicate a decline in the recoverability of the carrying value of such properties.  We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable.  When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amounts of the properties are reduced to their estimated fair value.  The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production, future capital expenditures and a risk-adjusted discount rate.  The charge is included in DD&A.


Unproved oil and natural gas properties that are individually significant are also periodically assessed for impairment of value.  An impairment loss for unproved oil and natural gas properties is recognized at the time of impairment by providing an impairment allowance.


On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income.


Deposits and advances for services expected to be provided for exploration and development or for the acquisition of oil and gas properties are classified as long term other assets.


Revenue Recognition


We use the sales method to account for sales of crude oil and natural gas.  Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers.  The volumes sold may differ from the volumes to which we are entitled based on our interests in the properties.  These differences create imbalances, which are recognized as a liability only when the imbalance exceeds the estimate of remaining reserves.  We had no significant imbalances as of February 29, 2016 and February 28, 2015.


Suspended Well Costs


We account for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities – Oil and Gas” (“ASC 932”).  ASC 932 states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the economic and operating feasibility of the well.  If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value.  Additional annual disclosures are required to provide information about management's evaluation of capitalized exploratory well costs.


In addition, ASC 932 requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year, designating the number of wells the aging is related to.  Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation.


Share Based Payments


Share based awards are accounted for under FASB Topic ASC 718, “Compensation-Stock Compensation” (“ASC 718”).  ASC 718 requires compensation costs for all share-based payments granted to be based on the grant date fair value.  The value of the portion of the award that is ultimately expected to vest is recognized as expense ratably over the requisite service periods.


Off-Balance Sheet Arrangements


As of February 29, 2016, we did not have any relationships with unconsolidated entities or financial partners, such as entities often referred to as structured finance or special purpose entities, which have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.  As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.




52



ITEM 7A.   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.





53



ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




To the Board of Directors and Shareholders of

Daybreak Oil and Gas, Inc.

Spokane Valley, Washington



We have audited the accompanying balance sheets of Daybreak Oil and Gas, Inc. (the “Company”) as of February 29, 2016 and February 28, 2015 and the related statements of operations, changes in stockholders’ deficit and cash flows for the years then ended.  These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.


In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Daybreak Oil and Gas, Inc. as of February 29, 2016 and February 28, 2015 and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.


The accompanying financial statements have been prepared assuming that Daybreak Oil and Gas, Inc. will continue as a going concern.  As discussed in Note 2 to the financial statements, Daybreak Oil and Gas, Inc. suffered losses from operations and has negative operating cash flows, which raises substantial doubt about its ability to continue as a going concern.  Management’s plans regarding those matters are also described in Note 2.  The financial statements do not include any adjustments that might result from the outcome of this uncertainty.



/s/ MaloneBailey, LLP

www.malonebailey.com

Houston, Texas


May 27, 2016






54



DAYBREAK OIL AND GAS, INC.

Balance Sheets

As of February 29, 2016 and February 28, 2015

 

As of February 29,

 

As of February 28,

 

2016

 

2015

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

$

6,995 

 

$

496,772 

Accounts receivable:

 

 

 

 

 

Oil and natural gas sales

 

69,192 

 

 

202,732 

Joint interest participants

 

106,694 

 

 

51,382 

Other receivables, net

 

71,237 

 

 

160,996 

Production revenue receivable - current

 

45,000 

 

 

120,000 

Prepaid expenses and other current assets

 

114,461 

 

 

201,693 

Deferred financing costs, net

 

641,075 

 

 

Note receivable - current

 

420,901 

 

 

1,320,944 

Total current assets

 

1,475,555 

 

 

2,554,519 

OIL AND GAS PROPERTIES, successful efforts method, net

 

 

 

 

 

Proved properties

 

3,180,002 

 

 

4,379,606 

Unproved properties

 

585,826 

 

 

733,478 

PREPAID DRILLING COSTS

 

18,802 

 

 

16,452 

PRODUCTION REVENUE RECEIVABLE – NON-CURRENT

 

 

 

35,000 

DEFERRED FINANCING COSTS, NET

 

 

 

1,058,751 

NOTE RECEIVABLE – NON-CURRENT

 

4,234,612 

 

 

3,429,056 

OTHER ASSETS

 

106,282 

 

 

106,199 

Total assets

$

9,601,079 

 

$

12,313,061 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ DEFICIT

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable and other accrued liabilities

$

1,777,236 

 

$

1,435,677 

Accounts payable - related parties

 

990,483 

 

 

905,891 

Accrued interest

 

175,283 

 

 

158,797 

Notes payable, related party

 

250,100 

 

 

250,100 

12% Notes payable

 

315,000 

 

 

12% Note payable - related party

 

250,000 

 

 

Debt - current portion, net

 

14,309,180 

 

 

4,691,211 

Line of credit

 

843,807 

 

 

869,865 

Total current liabilities

 

18,911,089 

 

 

8,311,541 

LONG TERM LIABILITIES:

 

 

 

 

 

Debt - non-current, net

 

 

 

8,591,507 

12% Notes payable

 

 

 

315,000 

12% Note payable - related party

 

 

 

250,000 

Asset retirement obligation

 

79,979 

 

 

29,603 

Total liabilities

 

18,991,068 

 

 

17,497,651 

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 734,565 shares issued and outstanding, respectively

 

725 

 

 

735 

Common stock- 200,000,000 shares authorized; $0.001 par value, 51,487,373 and 51,457,373 shares issued and outstanding, respectively

 

51,487 

 

 

51,457 

Additional paid-in capital

 

22,968,714 

 

 

22,968,734 

Accumulated deficit

 

(32,410,915)

 

 

(28,205,516)

Total stockholders’ deficit

 

(9,389,989)

 

 

(5,184,590)

Total liabilities and stockholders' deficit

$

9,601,079 

 

$

12,313,061 


The accompanying notes are an integral part of these financial statements




55



DAYBREAK OIL AND GAS, INC.

Statements of Operations

For the Years Ended February 29, 2016 and February 28, 2015

 

Year Ended

February 29, 2016

 

Year Ended

February 28, 2015

REVENUE:

 

 

 

 

 

Crude oil and natural gas sales

$

1,253,686 

 

$

3,083,797 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

Production

 

268,448 

 

 

329,917 

Exploration and drilling

 

76,053 

 

 

42,997 

Depreciation, depletion and amortization

 

517,870 

 

 

570,110 

Impairment of oil and gas properties

 

1,108,683 

 

 

General and administrative

 

1,172,206 

 

 

1,103,042 

Total operating expenses

 

3,143,260 

 

 

2,046,066 

OPERATING INCOME (LOSS)

 

(1,889,574)

 

 

1,037,731 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

Interest income

 

1,039,951 

 

 

1,081,214 

Interest expense

 

(3,355,776)

 

 

(2,795,369)

Loss on debt extinguishment

 

 

 

(56,519)

Total other income (expense)

 

(2,315,825)

 

 

(1,770,674)

 

 

 

 

 

 

NET LOSS

 

(4,205,399)

 

 

(732,943)

 

 

 

 

 

 

Cumulative convertible preferred stock dividend requirement

 

(130,925)

 

 

(132,634)

 

 

 

 

 

 

NET LOSS AVAILABLE TO COMMON SHAREHOLDERS

$

(4,336,324)

 

$

(865,577)

 

 

 

 

 

 

NET LOSS PER COMMON SHARE – Basic and diluted

$

(0.08)

 

$

(0.02)

 

 

 

 

 

 

WEIGHTED AVERAGE NUMBER OF

COMMON SHARES OUTSTANDING – Basic and diluted

 

51,484,673 

 

 

54,126,721 


The accompanying notes are an integral part of these financial statements









56





DAYBREAK OIL AND GAS, INC.

Statements of Changes in Stockholders' Deficit

For the Years Ended February 29, 2016 and February 28, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Series A Convertible

 

 

 

 

 

 

Additional

 

 

 

 

 

 

 

Preferred Stock

 

Common Stock

 

Paid-In

 

Accumulated

 

 

 

 

Shares

 

Amount

 

Shares

 

Amount

 

Capital

 

Deficit

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, FEBRUARY 28, 2014

737,565 

 

$

738 

 

55,509,411 

 

$

55,509 

 

$

24,607,582 

 

$

(27,472,573)

 

$

(2,808,744)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of common stock for:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Warrant exercise – 12% Notes

 

 

 

50,000 

 

 

50 

 

 

6,950 

 

 

 

 

7,000 

Warrant cashless exercise

 

 

 

 

 

1,873,554 

 

 

1,874 

 

 

(1,874)

 

 

 

 

 

Company stock plan

 

 

 

 

 

 

 

2,515 

 

 

 

 

2,515 

Cancellation of stock plan issuances

 

 

 

(2,040)

 

 

(2)

 

 

(488)

 

 

 

 

(490)

Conversion of preferred stock

(3,000)

 

 

(3)

 

9,000 

 

 

 

 

(6)

 

 

 

 

Transfer agent balancing adjustment

 

 

 

140,000 

 

 

140 

 

 

(140)

 

 

 

 

Share purchase and cancellation

 

 

 

(5,694,823)

 

 

(5,695)

 

 

(1,702,752)

 

 

 

 

(1,708,447)

Share-for-warrant exchange

 

 

 

(427,729)

 

 

(428)

 

 

428 

 

 

 

 

Extension of 12% Note warrants

 

 

 

 

 

 

 

56,519 

 

 

 

 

56,519 

Net loss

 

 

 

 

 

 

 

 

 

(732,943)

 

 

(732,943)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, FEBRUARY 28, 2015

734,565 

 

$

735 

 

51,457,373 

 

$

51,457 

 

$

22,968,734 

 

$

(28,205,516)

 

$

(5,184,590)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of common stock for:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conversion of preferred stock

(10,000)

 

 

(10)

 

30,000 

 

 

30 

 

 

(20)

 

 

 

 

Net loss

 

 

 

 

 

 

 

 

 

(4,205,399)

 

 

(4,205,399)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, FEBRUARY 29, 2016

724,565 

 

$

725 

 

51,487,373 

 

$

51,487 

 

$

22,968,714 

 

$

(32,410,915)

 

$

(9,389,989)


The accompanying notes are an integral part of these financial statements










57





DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows

For the Years Ended February 29, 2016 and February 28, 2015

 

Years Ended

 

February 29,

2016

 

February 28,

2015

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net loss

$

(4,205,399)

 

$

(732,943)

Adjustments to reconcile net loss to net cash (used in) provided by operating activities:

 

 

 

 

 

Stock compensation

 

 

 

2,515 

Depreciation, depletion and ARO expense

 

517,870 

 

 

570,110 

Impairment of oil and gas properties

 

1,108,683 

 

 

Amortization of debt discount

 

132,114 

 

 

168,722 

Amortization of deferred financing costs

 

427,331 

 

 

422,408 

Loss on debt extinguishment

 

 

 

56,519 

Non-cash interest income

 

(83)

 

 

(85)

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable - oil and gas sales

 

133,540 

 

 

127,611 

Accounts receivable - joint interest participants

 

(55,312)

 

 

287,568 

Accounts receivable - other

 

(483,255)

 

 

(11,447)

Prepaid expenses and other current assets

 

87,232 

 

 

(172,296)

Accounts payable and other accrued liabilities

 

251,755 

 

 

(515,776)

Accounts payable - related parties

 

84,592 

 

 

(46,761)

Accrued interest

 

1,504,265 

 

 

156,555 

Net cash provided by (used in) operating activities

 

(496,667)

 

 

312,700 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Prepaid drilling costs

 

(2,350)

 

 

(1,537)

Additions to oil and gas properties

 

(170,697)

 

 

(1,516,201)

Proceeds from the sale of O&G properties

 

31,581 

 

 

Additions to note receivable

 

 

 

(4,762,500)

Collections of note receivable

 

777,500 

 

 

3,562,500 

Deferred Interest

 

 

 

655 

Net cash provided by (used in) investing activities

 

636,034 

 

 

(2,717,083)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Proceeds from non-current debt

 

25,000 

 

 

5,700,000 

Principal payments on non-current debt

 

(618,431)

 

 

(2,948,772)

Proceeds from warrant conversion

 

 

 

7,000 

Payment of deferred financing fees

 

(9,655)

 

 

(345,000)

Payments to line of credit

 

(26,058)

 

 

(12,504)

Net cash provided by (used in) financing activities

 

(629,144)

 

 

2,400,724 

 

 

 

 

 

 

NET DECREASE  IN CASH AND CASH EQUIVALENTS

 

(489,777)

 

 

(3,659)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

 

496,772 

 

 

500,431 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

$

6,995 

 

$

496,772 

 

 

 

 

 

 

CASH PAID FOR:

 

 

 

 

 

Interest

$

1,292,066 

 

$

2,077,418 

Income taxes

$

 

$




58





DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows (continued)

For the Years Ended February 26, 2016 and February 28, 2015

 

Years Ended

 

February 29,

2016

 

February 28,

2015

SUPPLEMENTAL CASH FLOW INFORMATION:

 

 

 

 

 

Unpaid additions to oil and gas properties

$

89,804 

 

$

16,552 

Interest and fees converted to principal

$

1,487,779 

 

$

Increase in note receivable for deferred interest and fees

$

683,013 

 

$

Increase in note payable for stock acquisition and subsequent retirement

$

 

$

1,708,447 

ARO asset and liability increase due to timing differences

$

47,362 

 

$

5,337 

Share-to-warrant exchange

$

 

$

428 

Conversion of warrants

$

 

$

1,874 

Repurchase of stock through payment of payroll taxes

$

 

$

490 

Conversion of preferred stock to common stock

$

30 

 

$


The accompanying notes are an integral part of these financial statements









59





NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION:


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’s 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 that are market-sensitive.  Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.



NOTE 2 — GOING CONCERN:


Financial Condition


Daybreak’s financial statements for the year ended February 29, 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. Daybreak has incurred net losses since inception and has accumulated a deficit of $32,410,915 and a working capital deficit of $17,435,534, which raises substantial doubt about the Company’s ability to continue as a going concern.


Management Plans to Continue as a Going Concern


The Company continues to implement plans to enhance its ability to continue as a going concern.  Daybreak currently has a net revenue interest in 20 producing wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”).  The revenue from these wells has created a steady and reliable source of revenue.  The Company’s average working interest in these wells is 36.6% and the average net revenue interest is 28.4% for these same wells.


Additionally, the Company has a working interest in a shallow oil play in an existing natural gas field in Lawrence County, Kentucky, through its acquisition of a 25% working interest in approximately 7,300 acres in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky.  Daybreak currently has a net revenue interest in 14 producing horizontal oil wells in the Twin Bottoms Field.  The Company’s average working interest in these 14 horizontal oil wells is 22.6% and the average net revenue interest is 19.7% in these same wells.


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.  The Company’s sources of funds in the past have included the debt or equity markets and the sale of assets.  While the Company has experienced revenue growth, which has resulted in 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, 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 February 29, 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.




60





NOTE 3 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:


Cash and Cash Equivalents


Cash equivalents include demand deposits with banks and all highly liquid investments with original maturities of three months or less.  The Company has historically maintained balances in financial institutions where deposits may exceed the Federally insured deposit limit of $250,000.  The Company has not experienced any losses from such accounts and does not believe it is exposed to any significant credit risk on cash.


Accounts Receivable


The Company routinely assesses the recoverability of all material trade and other receivables.  The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated.  Actual write-offs may exceed the recorded allowance.  Substantially all of the Company’s trade accounts receivable result from crude oil and natural gas sales in Kentucky and California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors.  Trade accounts receivable are generally not collateralized.  There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 29, 2016 and February 28, 2015.


Oil and Gas Properties


The Company uses the successful efforts method of accounting for oil and natural gas property acquisition, exploration, development, and production activities.  Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred.  Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred.  In addition, the geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred.  Costs to operate and maintain wells and field equipment are expensed as incurred.


Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on estimated proved reserves.  Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their estimated proved developed reserves.  Support equipment and other property and equipment are depreciated over their estimated useful lives.


Pursuant to the provisions of Financial Accounting Standards Codification (“ASC”) Topic 360, “Property, Plant and Equipment” the Company reviews proved oil and natural gas properties and other long-lived assets for impairment. These reviews are predicated by events and circumstances, such as downward revision of the reserve estimates or commodity prices that indicate a decline in the recoverability of the carrying value of such properties.  The Company estimates the future cash flows expected in connection with the properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable.  When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amounts of the properties are reduced to their estimated fair value.  The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production, future capital expenditures and a risk-adjusted discount rate.  These estimates of future product prices may differ from current market prices of oil and natural gas.  Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s oil and natural gas properties in subsequent periods.  Unproved oil and natural gas properties that are individually significant are also periodically assessed for impairment of value.  An impairment loss for unproved oil and natural gas properties is recognized at the time of impairment by providing an impairment allowance.


The Company recognized asset impairments of $1,108,683 and $-0- for the years ended February 29, 2016 and February 28, 2015, respectively.


On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income.



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Property and Equipment


Fixed assets are stated at cost. Depreciation on vehicles is provided using the straight-line method over expected useful lives of three years.  Depreciation on machinery and equipment is provided using the straight-line method over expected useful life of three years.  Depreciation of production facilities and natural gas pipelines are recorded using the unit-of-production method based on estimated reserves.


Long Lived Assets


The Company reviews long-lived assets and identifiable intangibles whenever events or circumstances indicate that the carrying amounts of such assets may not be fully recoverable. The Company evaluates the recoverability of long-lived assets by measuring the carrying amounts of the assets against the estimated undiscounted cash flows associated with these assets.  If this evaluation indicates that the future undiscounted cash flows of certain long-lived assets are not sufficient to recover the assets' carrying value, the assets are adjusted to their fair values (based upon discounted cash flows).


Fair Value of Financial Instruments


The carrying value of short-term financial instruments including cash, receivables, prepaid expenses, accounts payable, and other accrued liabilities, short-term liabilities and the line of credit approximated their fair values due to the relatively short period to maturity for these instruments.  The long-term notes payable approximates fair value since the related rates of interest approximate current market rates.


Share Based Payments


Stock awards are accounted for under FASB ASC Topic 718, “Compensation-Stock Compensation” (“ASC 718”).  Under ASC 718, compensation for all share-based payment awards is based on estimated fair value at the grant date. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.


The Company estimates the fair value of stock purchase warrants on the grant date using the Black-Scholes option pricing model (“Black-Scholes Model”) as its method of valuation for warrant awards granted during the year.  The Company’s determination of fair value of warrant awards on the date of grant using an option-pricing model is affected by the Company’s stock price, as well as assumptions regarding a number of subjective variables.  These variables include, but are not limited to, the Company’s expected price volatility over the term of the awards and discount rates assumed.


Loss per Share of Common Stock


Basic loss per share of Common Stock is calculated by dividing net loss available to common stockholders by the weighted average number of common shares issued and outstanding during the year.  Diluted net loss per share is computed based on the weighted average number of common shares outstanding, increased by dilutive Common Stock equivalents.  Common Stock equivalents are excluded from the calculations when their effect is anti-dilutive.


Concentration of Credit Risk


Substantially all of the Company’s accounts receivable result from crude oil and natural gas sales in Kentucky and California or joint interest billings to its working interest partners in California.  This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors.


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 one buyer 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 February 29, 2016 and February 28, 2015 these three individual customers represented 100.0% of crude oil and natural gas sales receivable.  If these buyers are unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its oil and natural gas production.



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The Company’s accounts receivable from Kentucky and California oil and natural gas sales at February 29, 2016 and February 28, 2015 are set forth in the table below.


 

 

 

 

February 29, 2016

 

February 28, 2015

Project

 

Customer

 

Revenue

Receivable

 

Percentage

 

Revenue

Receivable

 

Percentage

Kentucky – Twin Bottoms Field (Oil)

 

Appalachian Oil

 

$

23,257

 

33.6%

 

$

90,906

 

44.9%

Kentucky – Twin Bottoms Field (Natural gas)

 

Jefferson Gas

 

 

6,767

 

9.8%

 

 

16,676

 

8.2%

California – East Slopes Project (Oil)

 

Plains Marketing

 

 

39,168

 

56.6%

 

 

95,150

 

46.9%

 

 

 

 

$

69,192

 

100.0%

 

$

202,732

 

100.0%


Revenue Recognition


The Company uses the sales method to account for sales of crude oil and natural gas.  Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers.  The volumes sold may differ from the volumes to which the Company is entitled based on its interests in the properties.  These differences create imbalances that are recognized as a liability only when the imbalance exceeds the estimate of remaining reserves.  The Company had no significant imbalances as of February 29, 2016 and February 28, 2015.


Reclamation Bonds


Included in other assets as of February 29, 2016, are funds that have been pledged as collateral in connection with asset retirement obligations for future plugging, abandonment and site remediation.  The amount pledged for an operator bond in California is approximately $100,000 plus accrued interest.  The pledging of these funds is required by any state in which the Company operates as the project Operator.


Asset Retirement Obligation (“ARO”)


The Company follows the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“ASC 410”), which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  This standard requires that the Company recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred.  The ARO is capitalized as part of the carrying value of the assets to which it is associated, and depreciated over the useful life of the asset.  The ARO and the related asset retirement cost are recorded when an asset is first drilled, constructed or purchased.  The asset retirement cost is determined and discounted to present value using a credit-adjusted risk-free rate.  After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in the statements of operations.  Subsequent adjustments in the cost estimate are reflected in the ARO liability and the amounts continue to be amortized over the useful life of the related long-lived assets.


Suspended Well Costs


The Company accounts for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities – Oil and Gas” (“ASC 932”).  ASC 932 states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the economic and operating feasibility of the well.  If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value.  Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs.


In addition, ASC 932 requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year, designating the number of wells the aging is related to.  Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation.




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Income Taxes


The Company follows the provisions of FASB ASC Topic 740, “Income Taxes” (“ASC 740”).  As required under ASC 740, the Company accounts for income taxes using an asset and liability approach, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial statements and tax bases of assets and liabilities at the applicable tax rates.  A valuation allowance is utilized when it is more likely than not, that some portion of, or all of the deferred tax assets will not be realized.  Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.


ASC 740 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  Under ASC 740, the Company recognizes tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities.  The amount recognized is measured as the largest amount of benefit that is greater than 50% (percent) likely to be realized upon settlement.  A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards.


Use of Estimates and Assumptions


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 reported amounts of revenues and expenses during the reporting periods.  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 the timing and cost of future abandonment obligations.


Recent Accounting Pronouncements


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


Reclassifications


Certain reclassifications have been made to conform the prior period’s financial information to the current period’s presentation.  These reclassifications had no effect on previously reported net loss or accumulated deficit.



NOTE 4 — ACCOUNTS RECEIVABLE:


Accounts receivable consists primarily of receivables from the sale of crude oil and natural gas production by the Company and receivables from the Company’s working interest partners in oil and natural gas projects in which the Company acts as Operator of the project.


Crude oil and natural gas sales receivables balances of $69,192 and $202,732 at February 29, 2016 and February 28, 2015 represent crude oil sales that occurred in February 2016 and 2015, respectively.  Natural gas sales balances represent sales that occurred during the months of January and February 2016 and 2015, respectively.


Joint interest participant receivables balances of $106,694 and $51,382 at February 29, 2016 and February 28, 2015, 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 February 29, 2016 and February 28, 2015.




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Other receivables balances primarily include the monthly interest due on the App Energy loan and amounts advanced to certain minority working interest partners in Kentucky.



NOTE 5 PRODUCTION REVENUE RECEIVABLE:


The production revenue receivable balance of $45,000 represents amounts due the Company from a portion of the sale price of a 25% working interest in East Slopes Project in Kern County, California that was acquired through the default of certain original working interest partners in the project.  Production revenue receivable balances at February 29, 2016 and February 28, 2015 are set forth in the table below:


 

February 29, 2016

 

February 28, 2015

Production revenue receivable – current

$

45,000

 

$

120,000

Production revenue receivable – non-current

 

-

 

 

35,000

 

$

45,000

 

$

155,000



NOTE 6 — DEFERRED FINANCING COSTS:


Deferred financing costs at February 29, 2016 and February 28, 2015 relating to the original and the amended credit facility with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in these notes to the financial statements as “Maximilian”), are set forth in the table below:


 

February 29, 2016

 

February 28, 2015

Deferred financing costs – loan fees

$

160,794 

 

$

151,139 

Deferred financing costs – loan commissions

 

630,662 

 

 

630,662 

Deferred financing costs – fair value of warrants

 

530,488 

 

 

530,488 

Deferred financing costs – fair value of common stock

 

419,832 

 

 

419,832 

 

 

1,741,776 

 

 

1,732,121 

Accumulated amortization

 

(1,100,701)

 

 

(673,370)

 

$

641,075 

 

$

1,058,751 


Amortization expense of deferred financing costs was $427,331 and $422,408 for the years ended February 29, 2016 and February 28, 2015, respectively.  Deferred financing costs of $950,320 at February 29, 2016 include the fair value of common shares and warrants issued to Maximilian and to a third party that assisted in both the original and the amended financing transactions.  Refer to the discussion in Note 11 - Short-Term and Long-Term Borrowings for further information on the deferred financing costs.



NOTE 7 — OIL AND GAS PROPERTIES:


Oil and gas property balances at February 29, 2016 and February 28, 2015 are set forth in the table below:


 

February 29, 2016

 

February 28, 2015

Proved leasehold costs

$

654.445 

 

$

695,231 

Unproved leasehold costs

 

585,826 

 

 

733,478 

Costs of wells and development

 

604,684 

 

 

542,563 

Capitalized exploratory well costs

 

5,461,677 

 

 

5,308,876 

Capitalized asset retirement costs

 

28,901 

 

 

Total cost of oil and gas properties

 

7,335,533 

 

 

7,280,148 

Accumulated depletion, depreciation amortization and impairment

 

(3,569,705)

 

 

(2,167,064)

Oil and gas properties, net

$

3,765,828 

 

$

5,113,084 


For the twelve months ended February 29, 2016, the Company received $31,581 from a third party for the sale of the deep rights on certain mineral leases in Kentucky.




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Asset Retirement Obligation (“ARO”)


The Company’s financial statements reflect the provisions of ASC 410.  The ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws.  The Company determines the ARO on its oil and natural gas properties by calculating the present value of estimated cash flows related to the liability.  As of February 29, 2016 and February 28, 2015, ARO obligations were considered to be long-term based on the estimated timing of the anticipated cash flows.  For the years ended February 29, 2016 and February 28, 2015, the Company recognized accretion expense of $3,014 and $2,187, respectively which is included in DD&A in the statement of operations.


Changes in the asset retirement obligations for the years ended February 29, 2016 and February 28, 2015 are set forth in the table below.


 

February 29, 2016

 

February 28, 2015

Asset retirement obligation, beginning of period

$

29,603

 

$

22,079

Accretion expense

 

3,014

 

 

2,187

Change in asset retirement estimates

 

47,362

 

 

5,337

Asset retirement obligation, end of period

$

79,979

 

$

29,603



NOTE 8 NOTE RECEIVABLE:


On August 28, 2013, the Company amended its credit facility with Maximilian as a part of a financing transaction in which the Company extended to App Energy, LLC, a Kentucky limited liability company (“App”) a credit facility for the development of a shallow oil project in an existing gas field, the Twin Bottoms Field, in Lawrence County, Kentucky (see Note 11 –Short-Term and Long-Term Borrowings).


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


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


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 an average 25% working interest in the Kentucky Acreage, as described above.  The fair value of the 25% working interest was determined to be $1,073,091 and was recorded as unproved oil and gas properties (see Note 11 –Short-Term and Long-Term Borrowings).


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.



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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 on October 14, 2015, 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 from 19.2% to 17.0% 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.


For the twelve months ended February 29, 2016, the Company received principal payments of $777,500 from App Energy.  Since November 2015, App Energy has been unable to make any required interest or principal payments under terms of the amended loan agreements, but is not considered to be in default under the terms of the amended agreements because Daybreak has granted a series of waivers for the required payments as App Energy seeks to refinance their loan with alternative lenders.  The Company retains all of its rights under the loan agreements to declare App Energy in default on the loan in the future.  The App Energy loan is secured by a perfected first priority security interest in substantially all of the assets of App Energy, including its leases in Lawrence County, Kentucky.


Note receivable balances at February 29. 2016 and February 28, 2015 are set forth in the table below:


 

February 29, 2016

 

February 28, 2015

Note receivable – current

$

420,901

 

$

1,320,944

Note receivable – non-current

 

4,234,612

 

 

3,429,056

 

$

4,655,513

 

$

4,750,000



NOTE 9ACCOUNTS PAYABLE:


On March 1, 2009, the Company became the operator for the East Slopes Project located in Kern County, California.  Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning wells program.  The Company subsequently sold the 25% working interest on June 11, 2009.  Approximately $244,849 of the $1.5 million default remains unpaid and is included in the February 29, 2016 accounts payable balance.



NOTE 10ACCOUNTS PAYABLE- RELATED PARTIES:


The February 29, 2016 and February 28, 2015 accounts payable – related parties balances of $990,483 and $905,891, respectively, were comprised primarily of deferred salaries of the Company’s Executive Officers and certain employees; deferred directors’ fees; expense reimbursements; related party consulting fees; and deferred interest payments on the 12% Subordinated Note to the Company’s Chairman, President and Chief Executive Officer.  Payment of these deferred items has been delayed until the Company’s cash flow situation improves.






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NOTE 11 — SHORT-TERM AND LONG-TERM BORROWINGS:


Current Debt


Note Payable – Related Party


At February 29, 2016 and February 28, 2015, the Company’s Chairman, President and Chief Executive Officer had loaned the Company an aggregate $250,100 during the years ended February 29, 2012 and February 28, 2013, 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 the Company’s Chairman, President and Chief Executive Officer.  At February 29, 2016 and February 28, 2015, the Line of Credit had an outstanding balance of $843,807 and $869,865, respectively.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $31,442 and $31,498 for the years ended February 29, 2016 and February 28, 2015, respectively.  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.  The Notes consist of the following:


 

February 29, 2016

 

February 28, 2015

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

 

-

 

-

 

-

Totals

 

150,000

 

150,000

 

2





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Maximilian Loan


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 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 $132,114 and $138,988 for the years ended February 29, 2016 and February 28, 2015, respectively.  Unamortized debt discount amounted to $71,951 as of February 29, 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.  Amortization expense for the year ended February 29, 2016 amounted to $127,513.  Unamortized deferred financing cost of these warrants was $191,270 as of February 29, 2016.  There were 316,617 of these warrants that remained unexercised as of February 29, 2016.


Maximilian Loan - 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 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 shares and warrants as described in the paragraph below.  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.




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The fair value of the 6.1 million shares was determined to be $979,609 based on the Company’s stock price on the grant date of $0.16.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $898,299 and included the following assumptions: a risk free interest rate of 2.48%; stock price of $0.16, volatility of 184.53%; and a dividend yield of 0.0%.  The Company determined that the common shares and warrants were issued in connection with the increase in Company’s borrowing limit and App’s $40 million revolving credit facility for which the Company was granted a 25% working interest.  Consequently, the fair value of the common shares and warrants totaling $1,877,907 was allocated to deferred financing costs ($804,816) and unproved oil and gas properties ($1,073,091) based on the amount of the increase in the revolving credit facility that is attributable to Daybreak and App.


On February 14, 2014, the Company at the request of Maximilian, amended the warrant agreement related to the above issuance of approximately 6.1 million warrants to include a warrant exercise blocker provision that would effectively prevent 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 currently issued and outstanding shares at the time of the exercise.  All other terms of the original warrant agreement remained unchanged.


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


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


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 has paid $1,000,000 less than principal payments required by the previous agreement.  As of February 28, 2015, the Company had recognized $700,000 of the reduced monthly principal payments program.  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 “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 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 modification did not result to any accounting since these warrants were deemed to be investor warrants.




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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 (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 20% fee is being recognized as additional interest expense.  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 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.  As a result of the decline in hydrocarbon prices, we are currently unable to make the interest or principal payments required under the terms of our credit facility with our lender, Maximilian.  A series of waivers have been granted by Maximilian for the principal and interest payments that have not been made since December 2015.  Due to the waivers granted by Maximilian, 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 assurances that this cooperation will continue.  Further, there can be no assurances that Maximilian will not declare the Company to be in default under the credit facility.  In accordance with guidance from ASC-470-10-45, since the Company has been unable to make the above referenced payments the entire balance of the Maximilian credit facility is presented under the current liabilities section of the financial statements.


Current debt balances at February 29, 2016 and February 28, 2015 are set forth in the table below:


 

February 29, 2016

 

February 28, 2015

Maximilian Note

$

14,381,131 

 

$

4,823,325 

Maximilian Note Discount

 

(71,951)

 

 

(132,114)

 

$

14,309,180 

 

$

4,691,211 


Non-current debt balances at February 29, 2016 and February 28, 2015 are set forth in the table below:


 

February 29, 2016

 

February 28, 2015

Maximilian Note

$

 

$

8,663,458 

Maximilian Note Discount

 

 

 

(71,951)

 

$

 

$

8,591,507 



NOTE 12 — 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.




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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.  In July 2006, we completed a private placement of the Series A Preferred that resulted in the issuance of 1,399,765 shares to 100 accredited investors.


The following is a summary of the rights and preferences of the Series A Preferred.


Voluntary Conversion:


The Series A Preferred that is currently issued and outstanding is eligible to be converted by the shareholder at any time into three shares of the Company’s common stock.  During the years ended February 29, 2016 and February 28, 2015, there was one conversion each year of 10,000 and 3,000 shares of Series A Preferred that resulted in 30,000 and 9,000 shares of our common stock being issued, respectively.


At February 29, 2016 there were 724,565 shares issued and outstanding that had not been converted into our common stock.  As of February 29, 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

Totals

 

675,200

 

2,025,600

 

43


Automatic Conversion:


The Series A Preferred shall be automatically converted into the Company’s common stock if the common stock into which the Series A Preferred are convertible the Company’s common stock closes at or above $3.00 per share for 20 out of 30 trading days.


Dividend:


Holders of Series A Preferred shall be paid dividends, in the amount of 6% of the original purchase price per annum. Dividends may be paid in cash or common stock at the discretion of the Company. 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.  Accumulations of dividends on shares of Series A Preferred do not bear interest.  Dividends are payable upon declaration by the Board of Directors.






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Cumulative dividends earned for each fiscal year since issuance are set forth in the table below:


Fiscal Year Ended

 

Shareholders at

Period End

 

Accumulated

Dividends

February 28, 2007

 

100

 

$

155,311

February 29, 2008

 

90

 

 

242,126

February 28, 2009

 

78

 

 

209,973

February 28, 2010

 

74

 

 

189,973

February 28, 2011

 

70

 

 

173,707

February 29, 2012

 

70

 

 

163,624

February 28, 2013

 

68

 

 

161,906

February 28, 2014

 

59

 

 

151,323

February 28, 2015

 

58

 

 

132,634

February 29, 2016

 

57

 

 

130,925

 

 

 

 

$

1,711,502


Liquidation Preference:


In the event of any liquidation, dissolution or winding up of the Company, either voluntary or involuntary, the holders of the Series A Preferred shall be entitled to receive, prior and in preference to any distribution of any of the assets or surplus funds of the Company to the holders of common stock by reason of their ownership thereof, and subject to the rights of any series of preferred stock that may rank on liquidation prior to the Series A Preferred, an amount equal to all accrued or declared but unpaid dividends on such shares, for each share of Series A Preferred then held by them.  The remaining assets shall be distributed ratably to the holders of common stock and Series A Preferred on a common equivalent basis.  Certain other events, as described in our Amended and Restated Articles of Incorporation, including a consolidation or merger of the Company or the disposition of the Company’s assets, may trigger the payment of the liquidation preference to the holders of Series A Preferred.


Voting Rights:


The holders of the Series A Preferred will vote together with the common stock and not as a separate class except as specifically provided or as otherwise required by law.  Each share of the Series A Preferred shall have a number of votes equal to the number of shares of common stock then issuable upon conversion of such shares of Series A Preferred.


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 February 29, 2016.  In comparison, at February 28, 2015, a total of 51,457,373 shares were issued and outstanding.  This change of 30,000 shares was attributable as shown in the table below:


 

Common Stock

Balance

 

Par Value

Common stock, Issued and Outstanding, February 28, 2014

55,509,411 

 

 

 

Conversion of Series A Convertible Preferred Stock to common stock

9,000 

 

$

9 

Exercise of warrants issued with 12% Subordinated Notes

50,000 

 

$

50 

Cashless exercise of warrants

1,873,554 

 

$

1,874 

Common stock-for-warrant exchange (Maximilian)

(427,729)

 

$

(428)

Transfer agent balancing adjustment

140,000 

 

$

140 

Share purchase and cancellation (Maximilian)

(5,694,823)

 

$

(5,695)

Common stock returned to 2009 Stock Plan (tax withholding liability)

(2,040)

 

$

(2)

Common stock, Issued and Outstanding, February 28, 2015

51,457,373 

 

 

 

Conversion of Series A Convertible Preferred Stock to Common Stock

30,000 

 

$

30 

Common stock, Issued and Outstanding, February 29, 2016

51,487,373 

 

 

 


All shares of common stock are equal to each other with respect to voting, liquidation, dividend and other rights.  Owners of shares of common stock are entitled to one vote for each share of common stock owned at any shareholders’ meeting.  Holders of shares of common stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefore; and upon liquidation, are entitled to participate pro rata in a distribution of assets available for such a distribution to shareholders.



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There are no conversion, preemptive, or other subscription rights or privileges with respect to any shares of our common stock.  Our stock does not have cumulative voting rights, which means that the holders of more than 50% of the shares voting in an election of directors may elect all of the directors if they choose to do so.  In such event, the holders of the remaining shares aggregating less than 50% would not be able to elect any directors.


Common Stock Issued through Restricted Stock and Restricted Stock Unit Plan


On April 6, 2009, the Board approved the 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of the Company and its affiliates to be eligible to receive restricted stock and restricted stock unit awards.  Refer to the discussion in Note 14 for the issuances made under the 2009 Plan.



NOTE 13 — WARRANTS:


Warrants outstanding and exercisable as of February 29, 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

 

0.92

 

980,000

Warrants issued in 2012 for debt financing

 

2,435,517

 

$0.044

 

1.67

 

316,617

Warrants issued for Kentucky oil project

 

3,498,601

 

$0.04

 

2.50

 

3,498,601

Warrants issued for Kentucky debt financing

 

2,623,951

 

$0.04

 

2.50

 

2,623,951

Warrants issued for Kentucky debt financing

 

309,503

 

$0.214

 

2.50

 

309,503

Warrants issued in share-for-warrant exchange

 

427,729

 

$0.04

 

2.50

 

427,729

 

 

10,485,301

 

 

 

 

 

8,156,401


For the years ended February 29, 2016 and February 28, 2015, a total of 150,000 and 60,000 warrants expired, respectively.  The 150,000 warrants that expired during the year ended February 29, 2016 had been issued for services in conjunction with the 12% Subordinated Note offering in 2010.  During the years ended February 29, 2016 and February 28, 2015, there were -0- and 2,168,900 warrants exercised, respectively.  For the years ended February 29, 2016 and February 28, 2015, there were -0- and 427,729 warrants issued, respectively.  The outstanding warrants as of February 29, 2016 and February 28, 2015, had a weighted average exercise price of $0.06 and $0.11; a weighted average remaining life of 2.28 and 1.64 years; and an intrinsic value of $-0- and $14,564, respectively.



NOTE 14 RESTRICTED STOCK and RESTRICTED STOCK UNIT PLAN:


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


The Company believes that awards of this type further align the interests of its employees and its shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.  Restricted stock and restricted stock units also enhance the Company’s ability to attract and retain the services of qualified individuals.


During the year ended February 28, 2009, the Compensation Committee of the Board awarded a total of 2,550,000 restricted shares of the Company’s common stock to members of the Board of Directors, officers and employees of the Company.  These shares were granted pursuant to the 2009 Plan and fully vest equally over a period ranging from three to four years.




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On July 22, 2010, the Compensation Committee of the Board awarded 25,000 restricted shares of its common stock to the five non-employee Directors as a part of the director compensation policy.  These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of three years.


On July 22, 2010, the Compensation Committee of the Board awarded 425,000 restricted shares of its common stock to five employees of Daybreak.  These shares were granted pursuant to the 2009 Plan and fully vest equally over a period of four years.


For the years ended February 29, 2016 and February 28, 2015, an aggregate of -0- and 106,250 shares vested, respectively.  At February 29, 2016, all issued and outstanding shares in the 2009 stock plan had fully vested.  For the years ended February 29, 2016 and February 28, 2015, the number of common shares available for issuance under the Plan increased by -0- and 2,040 shares, respectively.  This increase was attributable to the return 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.


At February 29, 2016, a total of 3,000,000 shares of restricted stock had been awarded and 2,986,220 shares of the 2009 Plan had fully vested.  A total of 1,013,780 common stock shares remained available for issuance pursuant to the 2009 Plan at February 29, 2016.  For the years ended February 29, 2016 and February 28, 2015, an aggregate of -0- and 106,250 shares vested, respectively.  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

 


(1)

Does not include the number of common 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 years ended February 29, 2016 and February 28, 2015, the Company recognized compensation expense related to the above restricted stock grants of $-0- and $2,515, respectively.  There was no unamortized stock compensation expense remaining as of February 29, 2016.



NOTE 15 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 rate to income from continuing operations before income taxes is as follows:


 

February 29, 2016

 

February 28, 2015

Computed at U.S. and state statutory rates (40%)

$

(1,616,023)

 

$

(293,176)

Permanent differences

 

143,946 

 

 

142,925 

Changes in valuation allowance

 

1,472,077 

 

 

150,251 

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 presented below:


 

February 29, 2016

 

February 28, 2015

Deferred tax assets:

 

 

 

 

 

Net operating loss carryforwards

$

10,217,121 

 

$

9,188,905 

Oil and gas properties

 

(944,342)

 

 

(1,436,249)

Stock based compensation

 

88,723 

 

 

88,723 

Other

 

(150,945)

 

 

(102,899)

Less valuation allowance

 

(9,210,557)

 

 

(7,738,480)

Total

$

 

$


At February 29, 2016, the Company had a net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $25,542,800, which will begin to expire, if unused, beginning in 2024.  The valuation allowances increased by $1,472,077 and $150,251 for the years ended February 29, 2016 and February 28, 2015, respectively.  Section 382 Rule of the Internal Revenue Code will place annual limitations on the Company’s NOL carryforward.


The above estimates are based upon management’s decisions concerning certain elections that could change the relationship between net income and taxable income.  Management decisions are made annually and could cause the estimates to vary significantly.



NOTE 16 — 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 the aforementioned contingencies are not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company.


The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment.  These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup 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 February 29, 2016.  There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.





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NOTE 17 SUPPLEMENTARY INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)


All of the Company’s continuing operations are directly related to oil and natural gas producing activities located in Kern County, California and Lawrence County, Kentucky.


Capitalized Costs Relating to Oil and Gas Producing Activities


 

As of

February 29, 2016

 

As of

February 28, 2015

Proved leasehold costs

 

 

 

 

 

Mineral Interests

$

654,445 

 

$

695,231 

Wells, equipment and facilities

 

6,095,262 

 

 

5,851,439 

Total Proved Properties

 

6,749,707 

 

 

6,546,670 

 

 

 

 

 

 

Unproved properties

 

 

 

 

 

Mineral Interests

 

585,826 

 

 

733,478 

Uncompleted wells, equipment and facilities

 

 

 

Total unproved properties

 

585,826 

 

 

733,478 

 

 

 

 

 

 

Less accumulated depreciation, depletion amortization and impairment

 

(3,569,705)

 

 

(2,167,064)

Net capitalized costs

$

3,765,828 

 

$

5,113,084 


Costs Incurred in Oil and Gas Producing Activities


 

12 Months Ended

 

12 Months Ended

 

February 29, 2016

 

February 28, 2015

Acquisition of proved properties

$

 

$

165,317

Acquisition of unproved properties

 

 

 

-

Development costs

 

243,823 

 

 

1,339,570

Exploration costs

 

76,053 

 

 

42,997

Total costs incurred

$

319,876 

 

$

1,547,884


Results of Operations from Oil and Gas Producing Activities


 

12 Months Ended

 

12 Months Ended

 

February 29, 2016

 

February 28, 2015

Oil and gas revenues

$

1,253,686 

 

$

3,083,797 

Production costs

 

(268,448)

 

 

(329,917)

Exploration expenses

 

(76,053)

 

 

(42,997)

Depletion, depreciation and amortization

 

(517,870)

 

 

(570,110)

Impairment of oil properties

 

(1,108,683)

 

 

Result of oil and gas producing operations before income taxes

 

(717,368)

 

 

2,140,773 

Provision for income taxes

 

 

 

Results of oil and gas producing activities

$

(717,368)

 

$

2,140,773 





77





Proved Reserves


The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, PGH Petroleum and Environmental Engineers, LLC.  Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods when the estimates were made.  Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available.  The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate.  Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors.  Our proved reserves are summarized in the table below:


 

 

Oil (Barrels)

 

Natural Gas (Mcf)

 

BOE (Barrels)

Proved reserves:

 

 

 

 

 

 

February 28,  2014

 

745,830 

 

26,090 

 

750,178 

Revisions(1)

 

49,103 

 

192,589 

 

88,882 

Discoveries and extensions

 

88,611 

 

58,180 

 

90,627 

Production

 

(37,885)

 

(21,999)

 

(41,551)

February 28, 2015

 

845,659 

 

254,860 

 

888,136 

Revisions(1)

 

(120,001)

 

390,693 

 

(54,886)

Discoveries and extensions

 

76,270 

 

161,320 

 

103,157 

Production

 

(28,818)

 

(28,853)

 

(33,627)

February 29, 2016

 

773,110 

 

778,020 

 

902,780 


(1)

The revisions of previous estimates resulted from a decline in the estimated economic life of the reserves due to lower hydrocarbon prices in the energy markets.


The Company’s proved reserves are set forth in the table below.


 

 

Developed

 

Undeveloped

 

Total Reserves

 

 

Oil (Bbls)

 

BOE (Bbls)

 

Oil (Bbls)

 

BOE (Bbls)

 

Oil (Bbls)

 

BOE (Bbls)

February 29, 2016

 

203,131

 

231,778

 

569,979

 

671,002

 

773,110

 

902,780

February 28, 2015

 

278,233

 

294,585

 

567,426

 

593,551

 

845,659

 

888,136

February 28, 2014

 

263,010

 

264,062

 

482,820

 

486,116

 

745,830

 

750,178


Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves


The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of February 29, 2016 and February 28, 2015 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate.  This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.


Future cash inflows for the years ended February 29, 2016 and February 28, 2015 were estimated as specified by the SEC through calculation of an average price based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from March through February during each respective fiscal year.  The resulting net cash flows are reduced to present value by applying a 10% discount factor.


 

12 Months Ended

 

February 29, 2016

 

February 28, 2015

Future cash inflows

$

34,077,610 

 

$

73,348,130 

Future production costs(1)

 

(16,255,030)

 

 

(25,378,830)

Future development costs

 

(7,278,930)

 

 

(6,789,770)

Future income tax expenses(2)

 

 

 

Future net cash flows

 

10,543,650 

 

 

41,179,530 

10% annual discount for estimated timing of cash flows

 

(6,570,720)

 

 

(23,674,830)

Standardized measure of discounted future net cash flows at the end of the fiscal year

$

3,972,930 

 

$

17,504,700 


(1)

Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s oil and gas operations.

(2)

The Company has sufficient tax deductions and allowances related to proved oil and gas reserves to offset future net revenues.



78






Average hydrocarbon prices are set forth in the table below.


 

Average Price

 

Natural

 

Crude Oil (Bbl)

 

Gas (Mcf)

Year ended February 29, 2016(1)

$

47.45

 

$

2.51

Year ended February 28, 2015(1)

$

85.53

 

$

2.99

Year ended February 29, 2014(1)

$

95.94

 

$

2.44


(1)

Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year.


Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.


Sources of Changes in Discounted Future Net Cash Flows


Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by ASC 932, at fiscal year-end are set forth in the table below.


 

12 Months Ended

 

February 29, 2016

 

February 28, 2015

Standardized measure of discounted future net cash flows at the beginning of the year

$

17,504,700 

 

$

21,424,440 

Extensions, discoveries and improved recovery, less related costs

 

271,190 

 

 

1,565,310 

Revisions of previous quantity estimates

 

(408,300)

 

 

2,040,090 

Net changes in prices and production costs

 

(10,040,886)

 

 

(3,214,934)

Accretion of discount

 

1,750,470 

 

 

2,142,444 

Sales of oil produced, net of production costs

 

(985,238)

 

 

(2,753,880)

Development costs incurred during the period

 

213,576 

 

 

1,516,201 

Changes in future development costs

 

526,413 

 

 

(1,385,033)

Changes in timing of future production

 

(4,858,995)

 

 

(3,829,938)

Net changes in income taxes

 

 

 

Standardized measure of discounted future net cash flows at the end of the year

$

3,972,930 

 

$

17,504,700 







79






ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE


None.






80





ITEM 9A.   CONTROLS AND PROCEDURES


Management’s Evaluation of Disclosure Controls and Procedures


As of the end of the reporting period, February 29, 2016, an evaluation was conducted by Daybreak’s management, including our President and Chief Executive Officer, 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 February 29, 2016.


Internal Control Over Financial Reporting


The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.


Our internal controls over financial reporting include those policies and procedures that:

1)

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

2)

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made in accordance with authorizations of management and our Board of Directors; and

3)

provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.


Because of the inherent limitations due to, for example, the potential for human error or circumvention of controls, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.


Management’s Report on Internal Control Over Financial Reporting


Daybreak’s management, including our President and Chief Executive Officer, also serving as our interim principal finance and accounting officer is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act.  Our management assessed the effectiveness of our internal control over financial reporting as of February 29, 2016.  In making this assessment, management used certain criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.  Based on such assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of February 29, 2016.


This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to SEC rules that permit the company to provide only management’s report in this annual report.


Changes in Internal Control over Financial Reporting


There have not been any changes in the Company’s internal control over financial reporting during the quarter ended February 29, 2016 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.





81





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.



ITEM 9B.  OTHER INFORMATION


None.





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PART III


ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE


Directors of Daybreak Oil and Gas, Inc.


The following information reflects the business experience of each individual serving on the Board of Directors (the “Board”) of Daybreak Oil and Gas, Inc.


 

 

 

 

Director

Name

 

Age

 

Since

 

 

 

 

 

Wayne G. Dotson

 

81

 

2008

Timothy R. Lindsey

 

64

 

2007

James F. Meara

 

63

 

2008

James F. Westmoreland

 

60

 

2008


Wayne G. Dotson has served as a member of the Board of Directors since July 2008.  Mr. Dotson practiced oil and gas law, specializing in representation of various bank energy lending departments, including representing the banks in oil and gas company loans of up to $500 million, secured by oil and gas properties.  His experience includes review of title information on oil and gas leases, preparation of mortgage and other security documents, and preparation of complex credit agreements and other related documents.  From 1961 through 1984, Mr. Dotson was employed with the Texas law firm of Foreman, Dyess, Prewett, Rosenberg & Henderson, which later became Foreman & Dyess.  From 1984 through 1990, Mr. Dotson was employed with the law firm of Dotson, Babcock & Scofield.  In addition to legal practice at Dotson, Babcock and Scofield, Mr. Dotson served as Managing Partner and a member of the Compensation Committee.  After Dotson, Babcock & Scofield merged with Jackson Walker, LLP in 1990, Mr. Dotson continued his service until his retirement from the firm on January 1, 2008.  During his tenure with Jackson Walker, a law firm of 350 attorneys located in seven Texas cities, he also served on the Management Committee, Compensation Committee, and Business Development Committee.  Mr. Dotson received his Bachelor of Business Administration in 1957 and Juris Doctorate in 1961 from the University of Texas.


Timothy R. Lindsey has served as a member of the Board of Directors since January 2007.  He served as the Company’s Interim President and Chief Executive Officer from December 2007 until his resignation in October 2008.  Mr. Lindsey has over 35 years of energy and mineral exploration, technical and executive leadership in global exploration, production, technology, and business development.  From March 2005 to the present, Mr. Lindsey has been the Principal of Lindsey Energy and Natural Resources, an independent consulting firm specializing in energy and mining industry issues.  From May 2008 to the present, Mr. Lindsey has also been the President and a director of Canadian Sahara Energy Inc., a private company incorporated in Canada.  From September 2003 to March 2005, Mr. Lindsey held executive positions including Senior Vice-President, Exploration with The Houston Exploration Company, a Houston-based independent natural gas and oil company formerly engaged in the exploration, development, exploitation and acquisition of domestic natural gas and oil properties.  From October 1975 to February 2003, Mr. Lindsey was employed with Marathon Oil Corporation, a Houston-based company engaged in the worldwide exploration and production of crude oil and natural gas, as well as the domestic refining, marketing and transportation of petroleum products.  During his 27-year tenure with Marathon, Mr. Lindsey held a number of positions including senior management roles in both domestic and international exploration and business development.  Mr. Lindsey serves as a director and Chairman of the Board of Directors of Revett Mining Company., a publicly-listed company with mining activities in Montana from April 2009 until the merger of Revett Mining Company into Helca Mining in June 2015.  Mr. Lindsey obtained his Bachelor of Science degree in geology at Eastern Washington University in 1973, and completed graduate studies in economic geology from the University of Montana in 1975.  In addition, he completed the Advanced Executive Program from the Kellogg School of Management, Northwestern University, in 1990.  Mr. Lindsey is a member of the American Association of Petroleum Geologists, the Rocky Mountain Association of Geologists, the Montana Mining Association, and, the American Exploration and Mining Association.





83





James F. Meara has served as a member of the Board of Directors since March 2008.  From 1980 through December 2007, Mr. Meara was employed with Marathon Oil Corporation, a Houston-based company engaged in the worldwide exploration and production of crude oil and natural gas, as well as the domestic refining, marketing and transportation of petroleum products.  During his 27-year tenure with Marathon, Mr. Meara moved through a series of posts in the tax department, becoming manager of Tax Audit Systems and Planning in 1988, and in 1995 he was named Commercial Director of Sakhalin Energy in Moscow, Russia.  In 2000, Mr. Meara served as Controller and was appointed to Vice President of Tax in January 2002, serving until his retirement in December 2007.  He also serves as a director of Canadian Sahara Energy Inc., a private company incorporated in Canada.  Mr. Meara holds a bachelor’s degree in accounting from the University of Kentucky and a master’s degree in business administration from Bowling Green State University, and is a member of the American Institute of Certified Public Accountants.


James F. Westmoreland was elected Chairman of the Board of Directors in 2014, and appointed President and Chief Executive Officer and director in October 2008.  He also serves as interim principal finance and accounting officer.  Prior to that, he had been our Executive Vice President and Chief Financial Officer since April 2008.  He also served as the Company’s interim Chief Financial Officer from December 2007 to April 2008.  From August 2007 to December 2007, he consulted with the Company on various accounting and finance matters.  Prior to that time, Mr. Westmoreland was employed in various financial and accounting capacities for The Houston Exploration Company for 21 years, including Vice President, Controller and Corporate Secretary, serving as its Vice President and Chief Accounting Officer from October 1995 until its acquisition by Forest Oil Corporation in June 2007.  Mr. Westmoreland has almost 40 years of experience in oil and gas accounting, finance, corporate compliance and governance, both in the public and private sector.  He earned his Bachelor of Business Administration in accounting from the University of Houston.


When analyzing whether directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board of Directors to satisfy its oversight responsibilities effectively in light of the Company’s business and structure, the Governance Committee and the Board focus on the information as summarized in each of the Directors’ individual biographies set forth above.


In particular, the Governance Committee and the Board considered:


·

Mr. Dotson’s extensive legal career and knowledge of financing in the oil and gas industry.

·

Mr. Lindsey’s over 35 year career as a successful senior executive in the energy industry, his extensive knowledge of the industry and his active participation in energy related professional organizations are also valuable assets to the Board.  His knowledge and expertise in the energy business and management leadership regarding the issues affecting our business have been invaluable to the Board of Directors in overseeing the business affairs of our Company.  Further, the Committee believes that his extensive background and service with other public companies in the energy and mining sectors and his technical expertise provide the Board with superior leadership and decision-making skills.

·

Mr. Meara’s education, executive leadership roles and 27 year work experience in finance, tax and accounting in the oil and gas industry provide the knowledge and financial expertise needed to serve on the Board and the Company’s audit committee.

·

Mr. Westmoreland’s almost 40 year career in various financial and accounting capacities, including Vice President, Chief Accounting Officer, Controller and Corporate Secretary at a public oil and gas company along with his recent experience as President, Chief Executive Officer, Executive Vice President and Chief Financial Officer of the Company.  The Board also considered his role in reorganizing the Company and his day-to-day management of the Company.




84





Executive Officers of Daybreak Oil and Gas, Inc.


Executive officers are elected annually by our Board and serve at the discretion of the Board.  There are no arrangements or understandings between any of the directors, officers, and other persons pursuant to which such person was selected as an executive officer.


The following information concerns our executive officers, including the business experience of each during the past five years:


 

 

 

 

Executive

 

 

Name

 

Age

 

Since

 

Office

James F. Westmoreland

 

60

 

2007

 

Chairman of the Board, President and Chief Executive Officer

Bennett W. Anderson

 

55

 

2006

 

Chief Operating Officer


James F. Westmoreland was elected Chairman of the Board of Directors in 2014, and appointed President and Chief Executive Officer and director in October 2008.  He also serves as interim principal finance and accounting officer.  Prior to that, he had been our Executive Vice President and Chief Financial Officer since April 2008.  He also served as the Company’s interim Chief Financial Officer from December 2007 to April 2008.  From August 2007 to December 2007, he consulted with the Company on various accounting and finance matters.  Prior to that time, Mr. Westmoreland was employed in various financial and accounting capacities for The Houston Exploration Company for 21 years, including Vice President, Controller and Corporate Secretary, serving as its Vice President and Chief Accounting Officer from October 1995 until its acquisition by Forest Oil Corporation in June 2007.  Mr. Westmoreland has over 30 years of experience in oil and gas accounting, finance, corporate compliance and governance, both in the public and private sector.  He earned his Bachelor of Business Administration in accounting from the University of Houston.


Bennett W. Anderson was appointed Chief Operating Officer in 2006.  Prior to that time, he was a private investor from 2002 - 2006.  He served as a Senior Vice President with Novell, Inc. from 1998-2002.  Mr. Anderson’s duties included product direction, strategy and market direction, and training and support for the field sales staff.  From 1978 to 1982, Mr. Anderson worked as a rig hand and was involved in drilling over a dozen wells in North Dakota.  He holds a Bachelor of Science from Brigham Young University in Computer Science and graduated with University Honors of Distinction.


Legal Proceedings


On October 15, 2010, Canadian Sahara Energy Inc. (“Sahara”), a private Canadian oil and gas firm of which Mr. Lindsey is an executive officer and director, filed a Notice of Intention to File a Proposal under the Bankruptcy and Insolvency Act (Canada) (“BIA”) in order to obtain a stay of proceedings for a disputed oil and gas asset located in north Africa.  A Proposal was filed within 30 days as required under the BIA.  The sole creditor under the Proposal did not accept the Proposal, but was otherwise satisfied by the lifting of the stay.  Although no funds were owing, Sahara was deemed to be in bankruptcy, as a technical matter under the BIA.  A second Proposal will result in Sahara emerging from bankruptcy with a certification of full performance when accepted and approved by the Courts.  Sahara has advised that it anticipates that the second Proposal will be accepted.


As of the date hereof, it is the opinion of management that there is no other material proceeding to which any other director, officer or affiliate of the registrant, any owner of record or beneficially of more than five percent of any class of voting securities of the registrant, or any associate of any such director, officer, affiliate of the registrant, or security holder is a party adverse to the registrant or any of its subsidiaries or has a material interest adverse to the registrant or any of its subsidiaries.


None of Daybreak’s other current directors or Executive Officers has, during the past ten years:


a)

Had any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

b)

Been convicted in a criminal proceeding or been subject to a pending criminal proceeding;

c)

Been the subject of any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or

d)

Been found by a court of competent jurisdiction (in a civil action), the Securities and Exchange Commission or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated.



85





Section 16(a) Beneficial Ownership Reporting Compliance


Section 16(a) of the Securities Exchange Act of 1934 requires our directors, officers and beneficial owners of more than 10% of our common stock to file initial reports of ownership and reports of changes in ownership of common stock on Forms 3, 4 and 5 with the SEC.  Directors, officers and beneficial owners of more than 10% of our common stock are required by SEC regulations to furnish us with copies of any forms that they file.  We assist our directors and executive officers in complying with these requirements and are required to disclose in this Annual Report on Form 10-K the failure to file these reports on behalf of any reporting person when due.


With respect to our officers and directors, based solely on our review of such reports and written representations that no other reports were required, we believe that all such Section 16(a) reports for our officers and directors were timely filed during the fiscal year ended February 29, 2016.


Code of Ethics


Ethical Business Conduct Policy Statement and Code of Ethics for Senior Financial Officers


All of our employees, officers and directors are required to comply with our Ethical Business Conduct Policy Statement to help ensure that our business is conducted in accordance with the highest standards of moral and ethical behavior.  Our Ethical Business Conduct Policy covers all areas of professional conduct including:


·

Conflicts of interest;

·

Customer relationships;

·

Insider trading of our securities;

·

Financial disclosure;

·

Protection of confidential information; and

·

Strict legal and regulatory compliance.


Our employees, officers and directors are required to certify their compliance with our Ethical Business Conduct Policy Statement once each year.


In addition to the Ethical Business Conduct Policy Statement, all members of our senior financial management, including our President and Chief Executive Officer, have agreed in writing to our Code of Ethics for Senior Financial Officers, which prescribes additional ethical obligations pertinent to the integrity of our internal controls and financial reporting process, as well as the overall fairness of all financial disclosures.


The full text of our Ethical Business Conduct Policy Statement and the Code of Ethics for Senior Financial Officers are available under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com and are also available upon request, without charge, by contacting the Corporate Secretary at Daybreak Oil and Gas, Inc., 1101 N. Argonne Rd., Suite A 211, Spokane Valley, Washington 99212.


We intend to promptly disclose via a Current Report on Form 8-K or an update to our website information any amendment to, or waiver of, these codes with respect to our executive officers and directors.


Consideration of Nominees and Qualifications for Nominations to the Board of Directors


Our Corporate Governance Guidelines, which can be found under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com, contain Board membership criteria that apply to nominees recommended by the Nominating and Corporate Governance Committee (the “Governance Committee”) for a position on the Board.  The Corporate Governance Guidelines state that the Board’s Governance Committee is responsible for making recommendations to the Board concerning the appropriate size and composition of the Board, as well as for recommending to the Board nominees for election or re-election to the Board.  In formulating its recommendations for Board nominees, the Governance Committee will assess each proffered candidate’s independence and weigh his or her qualifications in accordance with the Governance Committee’s stated Qualifications for Nominations to the Board of Directors, which can be found under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com.




86





Audit Committee


The Audit Committee is responsible for monitoring the integrity of the Company’s financial reporting standards and practices and its financial statements, overseeing the Company’s compliance with ethics and legal and regulatory requirements, and selecting, compensating, overseeing and evaluating the Company’s independent registered public accountants.


During the fiscal year ended February 29, 2016, the Audit Committee met four times.  The Audit Committee operates under a charter that is available under the “Shareholder/Financial - Corporate Governance” section of our website at www.daybreakoilandgas.com and also upon request, without charge, by contacting the Corporate Secretary at Daybreak Oil and Gas, Inc., 1101 N. Argonne Road, Suite A 211, Spokane Valley, Washington 99212.


The Audit Committee’s purpose is to assist the Board in fulfilling its responsibility to oversee management activities related to accounting and financial reporting policies, internal controls, auditing practices and related legal and regulatory compliance.  In that connection, the Audit Committee is directly responsible for the appointment, compensation, retention and oversight of the work of our independent registered public accountants for the purposes of preparing or issuing an audit report or performing other audit, review or attest services.  The Audit Committee determines the independence of our independent registered public accountants, and our independent registered public accountants report directly to the Audit Committee, which also must review and pre-approve the current year’s audit and non-audit fees.  The Audit Committee has the authority to select, retain and/or replace consultants to provide independent advice to the Committee.


The Audit Committee charter prescribes the Committee’s functions, which include the following:


·

Maintaining our compliance with legal and regulatory requirements relating to financial reporting accounting and controls;

·

Overseeing our whistleblower procedures;

·

Overseeing the pre-approval of audit fees;

·

Appointing and overseeing our independent registered public accountants;

·

Overseeing our internal audit function;

·

Overseeing the integrity of our financial reporting processes, including the Company’s internal controls;

·

Assessing the effect of regulatory and accounting initiatives, as well as any off-balance sheet structures, on our financial statements;

·

Reviewing our earnings press releases, guidance and SEC filings;

·

Overseeing our risk analysis and risk management procedures;

·

Resolving any disagreements between management and the independent registered public accountants regarding financial reporting;

·

Overseeing our business practices and ethical standards;

·

Preparing an audit committee report to be included in our public filings pursuant to applicable rules and regulations of the SEC.


Wayne G. Dotson, Timothy R. Lindsey and James F. Meara serve on the Audit Committee.  All members of the Audit Committee satisfy all SEC criteria for independence and meet all financial literacy and other SEC and NYSE MKT LLC requirements for Audit Committee service.  The Board has determined that James F. Meara is an “audit committee financial expert” as defined by the rules of the SEC.





87





ITEM 11.   EXECUTIVE COMPENSATION


Executive Officers

Named Executive Officers


Named executive officers consist of any individual who served as our Chief Executive Officer during the fiscal year ended February 29, 2016, and up to two of our most highly compensated executive officers other than the Chief Executive Officer during the fiscal year ended February 29, 2016.  For the fiscal year ended February 29, 2016, under the smaller reporting company rules, our named executive officers are: James F. Westmoreland, President and Chief Executive Officer; and Bennett W. Anderson, our Chief Operating Officer (collectively, the “Named Executive Officers”).  Executive officers are elected annually by our Board and serve at the discretion of the Board.  There are no arrangements or understandings between any of the directors, officers, and other persons pursuant to which any such person was selected as an executive officer.


The following information concerns our Named Executive Officers for the fiscal year ended February 29, 2016.


 

 

 

 

Executive

 

 

Name

 

Age

 

Since

 

Office

James F. Westmoreland

 

60

 

2007

 

President and Chief Executive Officer

Bennett W. Anderson

 

55

 

2006

 

Chief Operating Officer


EXECUTIVE COMPENSATION


We currently qualify as a “smaller reporting company” as such term is defined in Rule 405 of the Securities Act and Item 10 of Regulation S-K.  Accordingly, and in accordance with relevant SEC rules and guidance, we have elected, with respect to the disclosures required by Item 402 (Executive Compensation) of Regulation S-K, to comply with the disclosure requirements applicable to smaller reporting companies.  The following Compensation Overview is not comparable to the “Compensation Discussion and Analysis” that is required of SEC reporting companies that are not smaller reporting companies.


Compensation Overview


This Compensation Overview discusses the material elements of the compensation awarded to, earned by or paid to our executive officers, and the Compensation Committee’s role in the design and administration of these programs and policies in making specific compensation decisions for our executive officers, including officers who are considered to be “Named Executive Officers” during the fiscal year ended February 29, 2016.


General Discussion of Executive Compensation


The Compensation Committee is responsible for establishing, implementing and continually monitoring adherence to our compensation philosophy.  In doing so, the Compensation Committee reviews and approves on an annual basis the evaluation process and compensation structure for the Company’s Named Executive Officers.  The Committee reviews and recommends to the Board the annual compensation, including salary, and any incentive and/or equity-based compensation for such officers.  The Committee also provides oversight of management’s decisions concerning the performance and compensation of other employees.


The current and future objectives of Daybreak’s compensation program are to keep compensation aligned with Daybreak’s cost structure, financial position, and strategic business and financial objectives.  Daybreak’s financial position and its plans going forward are integral to the design and implementation of officer and employee compensation.  Therefore, the Compensation Committee reviews the Company’s cash flow with the Chief Executive Officer at a minimum, on an annual basis, in order to evaluate the current compensation program and its effects on the financial position of the Company.  In deciding on the type and amount of compensation for each Named Executive Officer, the Compensation Committee focuses on the market value of the role and pay of the individual, along with the Company’s cost structure and financial position.


Larger companies such as NYSE or NASDAQ listed companies in the oil and gas industry have well pronounced trends in compensation, including cash and equity components.  Daybreak competes with larger oil and gas companies that have substantially greater resources.




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For the fiscal years ended February 29, 2016 and February 28, 2015, compensation to our Named Executive Officers consisted primarily of base salaries.  The Board, with the assistance of the Compensation Committee, has reviewed the compensation structure of the Company’s Named Executive Officers.  After taking into consideration the Company’s current cost structure, financial position, and current compensation structure (discussed under the heading “Narrative Disclosure to Summary Compensation Table, Base Salaries”), the Board approved continuation of the current compensation structure.  In addition, the full Board reviewed and discussed the performance and compensation of all of Daybreak’s employees.


In April 2009, the Company approved a 2009 Restricted Stock and Restricted Stock Unit Plan pursuant to which it may compensate executive officers, directors, consultants and employees.  These elements of compensation are described in more detail under “Narrative Disclosure to Summary Compensation Table”, beginning on page 89 of this Form 10-K.


Summary Compensation Table


The following table sets forth summary information concerning the compensation paid to or earned by our Named Executive Officers during the fiscal years ended February 29, 2016 and February 28, 2015.


Name and Principal Position

 

Fiscal Year

Ended

 

Salary

($)

 

Bonus

($)

 

Stock Awards

($)

 

All Other

Compensation

($)

 

Total

($)

James F. Westmoreland(1)

 

February 29, 2016

 

150,000(2)

 

-

 

-

 

-

 

150,000

President and Chief Executive Officer

 

February 28, 2015

 

150,000(3)

 

-

 

-

 

-

 

150,000

Bennett W. Anderson

 

February 29, 2016

 

89,400(4)

 

-

 

-

 

-

 

89,400

Chief Operating Officer

 

February 28, 2015

 

89,400(5)

 

-

 

-

 

-

 

89,400


(1)

Mr. Westmoreland commenced his employment on December 14, 2007 as the Company’s interim Chief Financial Officer and was appointed Executive Vice President and Chief Financial Officer in April 2008.  He was appointed to the position of President and Chief Executive Officer of the Company in October 2008 and also continues to serve as the interim principal finance and accounting officer of the Company.

(2)

As a result of the effect of declining oil prices on the Company’s cash flow, Mr. Westmoreland deferred partial salary payments during the year ended February 29, 2016.  For the fiscal year ended February 29, 2016, Mr. Westmoreland was paid $131,250; and $18,750 was accrued, but not paid.  The accrued liability is recorded on our balance sheet under accrued liabilities.

(3)

As a result of the Company’s limited available cash, Mr. Westmoreland postponed salary payment until cash flow improved.  For the fiscal year ended February 28, 2015, Mr. Westmoreland was paid $6,250; and $143,750 was accrued, but not paid.  This liability is recorded on our balance sheet under accrued liabilities.  Mr. Westmoreland began receiving regular salary payments on February 28, 2015.

(4)

As a result of the effect of declining oil prices on the Company’s cash flow, Mr. Anderson deferred partial salary payments during the year ended February 29, 2016.  For the year ended February 29, 2016, Mr. Anderson was paid $72,300; and $17,100 was accrued, but not paid.  The accrued liability is recorded on our balance sheet under accrued liabilities.  From April 1, 2009 until March 1, 2016, Mr. Anderson’s base salary was $63,000.  Additionally, if Mr. Anderson worked more than 11 days per month, he earned an additional amount equal to $200 per day, with such additional amount being capped at $2,200 per month, for an aggregate annual total of $89,400.  Mr. Anderson’s base salary is currently $89,400.

(5)

As a result of the Company’s limited available cash, Mr. Anderson deferred partial salary payments during the year ended February 28, 2015.  For the year ended February 28, 2014, Mr. Anderson was paid $79,750; and $9,650 was accrued, but not paid.  This liability is recorded on our balance sheet under accrued liabilities.  From April 1, 2009 until March 1, 2016, Mr. Anderson’s base salary was $63,000.  Additionally, if Mr. Anderson worked more than 11 days per month, he earned an additional amount equal to $200 per day, with such additional amount being capped at $2,200 per month, for an aggregate annual total of $89,400.  Mr. Anderson’s base salary is currently $89,400


Narrative Disclosure to Summary Compensation Table


Base Salaries


The Board, with the assistance of the Compensation Committee, has reviewed the compensation structure of the Company’s Named Executive Officers.  After taking into consideration the Company’s current cost structure, financial position, and the current compensation structure, the Board approved continuation of the current compensation structure, which was established on April 6, 2009.




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Equity Compensation Plan Information


Although no equity compensation was granted to our Named Executive Officers during the fiscal years ended February 29, 2016 and February 28, 2015, executive officers, directors, consultants and employees of the Company and its affiliates (“Plan Participants”) are eligible to receive restricted stock and restricted stock unit awards under our 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”), as a means of providing management with a continuing proprietary interest in the Company.  There are no predeterminations established for restricted stock or restricted stock units to be awarded to our named executive officers or employees.


We believe that awards of this type further the mutuality of interest between 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.


Under the 2009 Plan, we may grant up to 4,000,000 shares.  The Board delegated the administration of the 2009 Plan to the Compensation Committee.  The Compensation Committee will have the power and authority to select Plan Participants and grant awards of restricted stock and restricted stock units (“Awards”) to such Plan Participants pursuant to the terms of the 2009 Plan.  Awards may be in the form of actual shares of restricted common stock or hypothetical restricted common stock units having a value equal to the fair market value of an identical number of shares of common stock.  Unless otherwise provided by the Compensation Committee in an individual Award agreement, Awards under the 2009 Plan vest 25% on each of the first four anniversaries of the date of grant and the unvested portion of any Award will terminate and be forfeited upon termination of the Plan Participant’s employment or service.  To date, the Compensation Committee has approved a vesting period of three years (vesting 331/3% per year), as opposed to a four-year vesting period, for Awards granted to non-employee directors.


Subject to the terms of the 2009 Plan and the applicable Award agreement, the recipients of restricted stock generally will have the rights and privileges of a shareholder with respect to the restricted stock, including the right to vote the shares and to receive dividends, if applicable.  The recipients of restricted stock units will not have the rights and privileges of a shareholder with respect to the shares underlying the restricted stock unit award until the award vests and the shares are received.  The Compensation Committee may, at its discretion, withhold dividends attributed to any particular share of restricted stock, and any dividends so withheld will be distributed to the Plan Participant upon the release of restrictions on such shares in cash, or at the sole discretion of the Compensation Committee, in shares of common stock having a fair market value equal to the amount of such dividends.  Awards under the 2009 Plan may not be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by a Plan Participant other than by will or by the laws of descent and distribution.


Change in Control


Unless otherwise provided in an Award agreement, in the event of a Change in Control (as defined in the 2009 Plan) of the Company, the Compensation Committee may provide that the restrictions pertaining to all or any portion of a particular outstanding Award will expire at a time prior to the change in control.  To the extent practicable, any actions taken by the Compensation Committee to accelerate vesting will occur in a manner and at a time that will allow affected Plan Participants to participate in the change in control transaction with respect to the common stock subject to their Awards.


Amendment and Termination


The Board at any time, and from time to time, may amend or terminate the 2009 Plan; provided, however, that such amendment or termination shall not be effective unless approved by the Company’s shareholders to the extent shareholder approval is necessary to comply with any applicable tax or regulatory requirements.  In addition, any such amendment or termination that would materially and adversely affect the rights of any Plan Participant shall not to that extent be effective without the consent of the affected Plan Participant.  The Compensation Committee at any time, and from time to time, may amend the terms of any one or more Awards; provided, however, that the Compensation Committee may not effect any amendment that would materially and adversely affect the rights of any Plan Participant under any Award without the consent of such Plan Participant.




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Outstanding Equity Awards at Fiscal Year-End


The Company has no unvested outstanding restricted stock awards held by our Named Executive Officers at the end of the fiscal year ended February 29, 2016.  The Company has no qualified or nonqualified stock option plans and has no outstanding stock options.


Other: Securities Trading


We have a policy that executive officers and directors may not purchase or sell exchange traded options to sell or buy Daybreak stock (“puts” and “calls”), engage in short sales with respect to Daybreak stock or otherwise hedge equity positions in Daybreak (e.g., by buying or selling straddles, swaps or other derivatives).


Executive Employment Agreements


Our employees, including our named executive officers, are employed at will and do not have employment agreements.  Our Compensation Committee believes that employment agreements encourage a short-term rather than long-term focus, provide inappropriate security to the executives and employees and undermine the team spirit of the organization.


Payments Upon Termination or Change in Control


We do not have any agreements with any of our named executive officers that affect the amount paid or benefits provided following termination or a change in control.


Pension Plan Benefits


The Company does not have any pension plans that oblige the Company to make payments or provide benefits at, following or in connection with retirement of its Directors, Officers or employees.


Deductibility of Compensation


Section 162(m) of the Code places a $1 million per executive cap on the compensation paid to executives that can be deducted for tax purposes by publicly traded corporations each year.  Amounts that qualify as “performance based” compensation under Section 162(m)(4)(c) of the Code are exempt from the cap and do not count toward the $1 million limit if certain requirements are satisfied.  At our current named executive officer compensation levels, we do not presently anticipate that Section 162(m) of the Code will be applicable, and accordingly, our Compensation Committee did not consider its impact in determining compensation levels for our Named Executive Officers for the fiscal year ended February 29, 2016.


Stock Compensation Expense


Stock awards are accounted for under FASB ASC 718, “Stock Compensation.”  Under ASC 718, compensation for all share-based payment awards is based on estimated fair value at the grant date.  The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.




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DIRECTOR COMPENSATION


The Board has adopted a Non-Employee Director Compensation Policy (the “Director Compensation Policy”) under which it compensates directors who are not employees of the Company.


Each director who is not an employee or officer of the Company (“non-employee director”) receives an annual cash retainer of $9,000.  Each non-employee director also receives $500 per Board meeting attended and $500 per committee meeting attended.  Additionally, the chairman of the Audit Committee receives an additional annual retainer of $1,500 and all other committee chairmen receive an additional $750 annual retainer.  Director fees are paid in cash on a quarterly basis.  Additionally, directors are reimbursed for any out-of-pocket expenses incurred in attending board meetings.


In addition to cash fees, non-employee directors will receive automatic awards of 150,000 shares of restricted common stock of the Company (the “restricted shares”) upon initial election to the Board.  Additionally the Director Compensation Policy provides that each non-employee director may receive a discretionary grant of 5,000 restricted shares annually, which would typically be granted in conjunction with the Company’s Annual Meeting of Shareholders, and pursuant to the 2009 Plan.  No discretionary grants of restricted shares were made to the non-employee director for the fiscal years ended February 29, 2016 and February 28, 2015.  Shares granted to non-employee directors, under the 2009 Plan are restricted and fully vest equally over a period of three years, at a rate of 33 1/3% each year, or immediately upon termination by reason of death, disability or retirement from the Board.  The Board has discretion to remove any restrictions on restricted shares in the case of any other circumstance deemed appropriate by the Board.


The 2009 Plan is described under the heading “Equity Compensation Plan Information” beginning on page 90 of this Form 10-K.


The Compensation Committee periodically reviews our director compensation practices.  The Compensation Committee believes that our director compensation is fair and appropriate in light of the responsibilities and obligations of our directors.


Director Summary Compensation Table


Members of our board of directors are reimbursed for actual expenses incurred in attending Board meetings.  The table below provides information concerning compensation paid to, or earned by, directors for the fiscal year ended February 29, 2016(1).


Name

 

Fees Earned

Or

Paid in Cash(2)

($)

 

Stock

Awards(3)

($)

 

All other

compensation

($)

 

Total

($)

Wayne G. Dotson

 

13,250

 

-

 

-

 

13,250

Timothy R. Lindsey

 

13,750

 

-

 

-

 

13,750

James F. Meara

 

14,000

 

-

 

-

 

14,000


(1)

Mr. James F. Westmoreland did not receive any compensation for serving on the Board of Directors during the fiscal year ended February 29, 2016.  Only non-employee directors receive compensation for serving on the Board of Directors.

(2)

As a result of the Company’s limited available cash, the Board of Directors, beginning with the second quarter of the year ended February 28, 2011, postponed receiving payments of meeting fees and quarterly retainer fees until cash flow would allow.  For the year ended February 29, 2016, director fees were accrued, but not paid.  For the current year, all fees are still currently being accrued and will not be paid until cash flow would allow.  This liability is recorded on our balance sheet under accrued liabilities.

(3)

No discretionary grants of restricted shares were made to the non-employee directors for the fiscal year ended February 29, 2016.


REPORT OF THE COMPENSATION COMMITTEE


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


COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION


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





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ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS


Securities Authorized for Issuance Under Equity Compensation Plans


The following table provides information regarding outstanding restricted stock awards as of the fiscal year ended February 29, 2016.  The Company has not awarded any restricted stock units.  The Company has no qualified or nonqualified stock option plans and has no outstanding stock options.


Plan Category

 

Number of securities to

be issued upon exercise

of outstanding options,

warrants and rights

(a)

 

Weighted-average

exercise price of

outstanding

options, warrants

and rights

(b)

 

Number of securities

remaining available for

future issuance under

equity compensation plans

(excluding securities

reflected in column (a))

(c)

Equity compensation plans approved by security holders

 

-

 

-

 

-

Equity compensation plans not approved by security holders(1)

 

-

 

-

 

1,013,780

Total

 

-

 

-

 

1,013,780


(1)

Available to be issued pursuant our 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”), as described in detail under the heading “Equity Compensation Plan Information”, beginning on page 90.


Security Ownership of Certain Beneficial Owners and Management


Our largest principal beneficial shareholders, and five directors and officers of the Company, together own and control about 14% percent of our outstanding common stock.


Our shareholders do not have the right to cumulative voting in the election of our directors.  Cumulative voting could allow a minority group to elect at least one director to our Board.  Because there is no provision for cumulative voting, a minority group will not be able to elect any directors.  Conversely, if our principal beneficial shareholders and directors wish to act in concert, they would be able to vote to appoint directors of their choice, and otherwise directly or indirectly control the direction and operation of the Company.






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As of May 26, 2016, based on information available to the Company, the following table shows the beneficial ownership of the Company’s voting securities (Common Stock and Series A Convertible Preferred stock) by: (i) any persons or entities known by management to beneficially own more than 5% of the outstanding shares of the Company’s Common Stock; (ii) each current director of the Company; (iii) each current executive officer of the Company named in the Summary Compensation Table appearing on page 89; and (iv) all of the current directors and executive officers of Daybreak as a group.  The address of each of the beneficial owners, except where otherwise indicated, is the Company’s address.  Unless otherwise indicated, each person shown below has the sole power to vote and the sole power to dispose of the shares of voting stock listed as beneficially owned.


Class of Stock

Name of Beneficial Owner

Amount and

Nature of

Beneficial

Ownership(1,2)

Warrants

Currently

Exercisable or

Exercisable

Within 60 Days(3)

Total

Beneficial

Holdings

Percent of

Class(4)

(Less than 1%

not shown)

Common Stock

Maximilian Resources LLC

250 W. 55th Street, 14th Floor

New York NY 10019

5,657,433 

5,657,433

9.99 

 

Timothy R. Lindsey, Director

910,000 

- 

910,000

1.8 

 

 

 

 

 

 

 

Wayne G. Dotson, Director

160,000 

160,000

* 

 

 

 

 

 

 

 

James F. Meara, Director

160,000 

160,000

* 

 

 

 

 

 

 

 

James F. Westmoreland, President and Chief Executive Officer and Director

600,000 

500,000(6)

1,100,000

2.1 

 

 

 

 

 

 

 

Bennett W. Anderson, Chief Operating Officer

400,000 

400,000

* 

 

 

 

 

 

 

 

All (5) directors and executive officers as a group

2,230,000 

500,000(6)

2,730,000

5.3 

Series A

Convertible

Preferred Stock(7)

Tensas River Farms I,II,III

551 Lawrence 5470

Alicia, AR 72410

66,667 

66,667

9.2 

 

 

 

 

 

 

 

Summittcrest Capital Partners

50 California St., Suite 450

San Francisco, CA 94111

58,333 

58,333

8.0 


(1)

Includes shares believed to be held directly or indirectly by 5% or higher shareholders, directors and executive officers that have voting power and/or the power to dispose of such shares.  Unless otherwise noted, each individual or member of the group has the sole power to vote and the sole power to dispose of the shares listed as beneficially owned.

(2)

To reflect “beneficial ownership” as defined in Rule 13d-3 promulgated under the Securities Exchange Act of 1934, this column includes shares as to which each individual has (A) sole voting power, (B) shared voting power, (C) sole investment power, or (D) shared investment power and the right to acquire within sixty days (from May 26, 2016).

(3)

To reflect “beneficial ownership” as defined in Rule 13d-3 promulgated under the Securities Exchange Act of 1934, this column includes shares as to which each individual has the right to acquire within sixty days (from May 26, 2016).

(4)

Based upon 51,487,373 shares of common stock outstanding as of May 26, 2016 entitled to one vote per share, except for the percentage of beneficial ownership for Mr. Westmoreland, which includes the 500,000 shares underlying warrants held by him that are exercisable within 60 days of May 26, 2016.

(5)

Maximilian Resources LLC is the holder of the warrants, and the percentage of beneficial ownership for Maximilian Resources LLC, which includes the 5,657,433 shares underlying warrants held by it that are exercisable within 60 days of May 26, 2016.  Consists entirely of shares underlying warrants held by Maximilian Resources LLC that are exercisable within 60 days of May 26, 2016.  According to the Schedule 13D/A filed on August 26, 2014, Maximilian Resources LLC shares beneficial ownership, voting power and investment power with its affiliates, Maximilian Investors LLC, a Delaware limited liability company, Platinum Partners Credit Opportunities Master Fund LP, a Delaware limited partnership, Platinum Credit Holdings LLC, a Delaware limited liability company, Platinum Credit Management LP, a Delaware limited partnership (“Platinum Management”) and the investment manager of Maximilian, Mark Nordlicht, the Chief Investment Officer and principal owner of Platinum Management, and Uri Landesman, the President and Managing Member of Platinum Management.  All beneficial owners share the business address shown for Maximilian Resources LLC.

(6)

Reflects the Warrant to purchase shares of Daybreak’s Common Stock related to Mr. Westmoreland’s participation in the 12% Notes Offering by purchasing a $250,000 Note and receiving the related Warrant to purchase 500,000 shares of Daybreak’s Common Stock at an exercise price of $0.14.

(7)

The Series A Convertible Preferred (“Preferred”) stock has the ability to vote together with the common stock with a number of votes equal to the number of shares of common stock to be issued upon conversion of the Preferred shares.  Each share of Series A Convertible Preferred stock can be converted to three common stock shares at any time.  As of May 26, 2016, 724,565 shares of Daybreak Series A Convertible Preferred stock were outstanding.





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ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE


Transactions with Related Persons, Promoters and Certain Control Persons


The Board adopted a policy prescribing procedures for review, approval and monitoring of transactions involving Daybreak and “related persons” (directors and executive officers or their immediate family members, or shareholders owning five percent or greater of our outstanding stock).  The Policy Statement Regarding Related Party Transactions of Daybreak Oil and Gas, Inc. (“Related Party Transactions Policy”) supplements the conflict of interest provisions in our Ethical Business Policy Conduct Statement and Corporate Governance Guidelines.  The Board has determined that the Governance Committee is best suited to review and consider for approval related party transactions, although the Board may instead determine that a particular related party transaction be reviewed and considered for approval by a majority of disinterested directors.


The Related Party Transactions Policy covers any related person transaction that involves amounts exceeding $50,000 in which a related person has a direct or indirect material interest.  In addition, the new Related Party Transactions Policy applies specifically to transactions involving Daybreak and any of the following:


(1)

all officers;

(2)

directors and director nominees;

(3)

5% shareholders;

(4)

immediate family members of the foregoing individuals (broadly defined to include any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law);

(5)

any entity controlled by any of the individuals in (1), (2), (3) or (4) above (whether through ownership, management authority or otherwise); and

(6)

certain entities at which any of the individuals in (1), (2), (3) or (4) above is employed (generally, if the individual employed is directly involved in the negotiation of the transaction, has or shares responsibility at such entity for such transaction, or might receive compensation tied to such transaction).


During the fiscal years ended February 29, 2016, and February 28, 2015, the Company had no related party transactions.


Director Independence


Independence of Board Members


We seek individuals who are able to guide our operations based on their business experience, both past and present, or their education.  Our business model is not complex and our accounting issues are straightforward.


The Governance Committee is delegated with the responsibility to review the independence and qualifications of each member of the Board and its various Committees.  Directors are deemed independent only if the Board affirmatively determines that they have no material relationship with Daybreak, directly, or as an officer, shareowner or partner of an organization that has a relationship with us.


The Company has adopted the standards of NYSE MKT LLC for determining the independence of its directors.  The Company is not listed on NYSE MKT LLC and is not subject to the rules of NYSE MKT LLC but applies the rules established by NYSE MKT LLC to establish director independence.


These independence standards specify the relationships deemed sufficiently material to create the presumption that a director is not independent.  No director qualifies as independent unless the Company’s Board affirmatively determines that the director does not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.  In addition, Section 803A of the NYSE MKT LLC Company Guide (and related commentary) sets forth the following non-exclusive list of persons who shall not be considered independent:


(a)

a director who is, or during the past three years was, employed by the Company, other than prior employment as an interim executive officer (provided the interim employment did not last longer than one year);



95






(b)

a director who accepted or has an immediate family member who accepted any compensation from the Company in excess of $120,000 during any period of twelve consecutive months within the three years preceding the determination of independence, other than the following:

(i)

compensation for Board or Board committee service,

(ii)

compensation paid to an immediate family member who is an employee (other than an executive officer) of the Company,

(iii)

compensation received for former service as an interim executive officer (provided the interim employment did not last longer than one year), or

(iv)

benefits under a tax-qualified retirement plan, or non-discretionary compensation;


(c)

a director who is an immediate family member of an individual who is, or at any time during the past three years was, employed by the Company as an executive officer;

(d)

a director who is, or has an immediate family member who is, a partner in, or a controlling shareholder or an executive officer of, any organization to which the Company made, or from which the Company received, payments (other than those arising solely from investments in the Company’s securities or payments under non-discretionary charitable contribution matching programs) that exceed 5% of the organization’s consolidated gross revenues for that year, or $200,000, whichever is more, in any of the most recent three fiscal years;

(e)

a director who is, or has an immediate family member who is, employed as an executive officer of another entity where at any time during the most recent three fiscal years any of the issuer’s executive officers serve on the compensation committee of such other entity; or

(f)

a director who is, or has an immediate family member who is, a current partner of the Company’s outside auditor, or was a partner or employee of the Company’s outside auditor who worked on the Company’s audit at any time during any of the past three years.

Directors serving on the Company’s audit committee must also comply with the additional, more stringent requirements set forth in Section 803B of the NYSE MKT LLC Company Guide and Rule 10A-3 of the Securities Exchange Act of 1934, as amended.


Consistent with these considerations, after review of all relevant transactions and/or relationships between each director and any of his family members and Daybreak, its senior management and its independent registered public accountants, the Board affirmatively determined that three of the current directors, Messrs. Wayne G. Dotson, Timothy R. Lindsey, and James F. Meara are independent.  Mr. James F. Westmoreland, our President and Chief Executive Officer, is not independent.  Beginning July 1, 2013, directors serving on the Company’s compensation committee must also comply with the additional, more stringent requirements as set forth in Section 805(c) of the NYSE MKT LLL Company Guide.






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ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES


Fees Billed by Independent Registered Public Accountants


The following table provides a summary of fees for professional services performed by MaloneBailey, LLP (“MaloneBailey”) for the audit of our financial statements for the fiscal years ended February 29, 2016 and February 28, 2015:


Services Rendered

Fees Billed

FY 2016

 

Fees Billed

FY 2015

Audit fees

$

70,000

 

$

76,000

Audit-related fees

 

-

 

 

-

Tax fees

 

-

 

 

-

All other fees

 

-

 

 

-

Total

$

70,000

 

$

76,000


The Audit Committee has reviewed the nature and scope of the services provided by MaloneBailey and considers the services provided to have been compatible with the maintenance of MaloneBailey’s independence.


Pre-Approval Policies and Procedures


The Audit Committee has adopted guidelines for the pre-approval of audit and permitted non-audit services by our independent registered public accountants.  The Audit Committee considers annually and approves the provision of audit services by our independent registered public accountants and considers and pre-approves the provision of certain defined audit and non-audit services.  The Audit Committee also considers on a case-by-case basis and approves specific engagements that are not otherwise pre-approved.  Any proposed engagement that does not fit within the definition of a pre-approved service may be presented to the Chairman of the Audit Committee.  The Chairman of the Audit Committee reports any specific approval of services at the next regular Audit Committee meeting.  The Audit Committee reviews a summary report detailing all services being provided to Daybreak by its independent registered public accountants.  All of the fees and services described above under “audit fees,” “audit-related fees,” “tax fees” and “all other fees” were pre-approved in accordance with the Audit Fee Pre-Approval Policy and pursuant to Section 202 of the Sarbanes-Oxley Act of 2002.





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PART IV


ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES


The following Exhibits are filed as part of the report:


3.01

Amended and Restated Articles of Incorporation of Daybreak Oil and Gas, Inc. dated July 17, 2009 (15)

3.02

Amended and Restated Bylaws (1)

4.01

Specimen Stock Certificate (2)

4.02

Designations of Series A Convertible Preferred Stock (3)

4.03

Warrant for the purchase shares of Common Stock, March 2006 private placement (4)

4.04

Registration rights agreement, March 2006 private placement (4)

4.05

Warrant for the purchase shares of Common Stock, July 2006 private placement (5)

4.06

Registration rights agreement, July 2006 private placement (5)

4.07

Additional warrant to purchase shares of Common Stock associated with the Spring 2006 and the July 2006 private placement offerings (2)

4.08

2009 Restricted Stock and Restricted Stock Unit Plan (6)*

4.09

Form of Restricted Stock Award Agreement (6)*

4.10

Form of Restricted Stock Unit Award Agreement (6)*

4.11

Form of 12% Subordinated Note due 2015 (7)

4.12

Form of Warrant in connection with 12% Subordinated Notes (7)

4.13

Form of Amendment to 12% Subordinated Note due 2015 and Warrant to Purchase Shares of Common Stock (18)

4.14

Warrant Agreement dated as of August 28, 2013, by and between Daybreak Oil and Gas, Inc. and Maximilian Investors LLC. (14)

4.15

First Amendment to Warrant Agreement dated as of February 14, 2014, by and between Daybreak Oil and Gas, Inc. and Maximilian Investors LLC. (15)

10.01

Prospect review and non-competition agreement for California project (8)

10.02

Prospect review agreement for California project (8)

10.03

Form of Subscription Agreement for 12% Subordinated Note due 2015 (9)

10.04

Promissory Note, dated June 20, 2011, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland (10)

10.05

Promissory Note, dated January 31, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland. (11)

10.06

Credit Line Agreement, dated October 24, 2011, by and between Daybreak Oil and Gas, Inc. and UBS Bank USA. (11)

10.07

Loan and Security Agreement dated as of October 31, 2012, by and between Daybreak Oil and Gas, Inc., as borrower, and Maximilian Investors LLC, as lender (12)

10.08

Promissory Note dated as of October 31, 2012, by Daybreak Oil and Gas, Inc. in favor of Maximilian Investors LLC (12)

10.09

Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of October 31, 2012, executed by Daybreak Oil and Gas, Inc., in favor of Maximilian Investors LLC (12)

10.10

Assignment and Assumption Agreement dated as of October 31, 2012, by and between Daybreak Oil and Gas, Inc., as assignor, and Maximilian Investors LLC, as assignee (12)

10.11

Promissory Note, dated August 21, 2012, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland (13)

10.12

Amended and Restated Loan and Security Agreement dated as of August 28, 2013, by and between Daybreak Oil and Gas, Inc., as borrower, and Maximilian Investors LLC, as lender. (14)

10.13

Loan and Security Agreement dated as of August 28, 2013, by and between App Energy, LLC, as borrower, and Daybreak Oil and Gas, Inc., as lender. (14)

10.14

Partial Assignment of Interest in Oil and Gas Leases dated as of August 28, 2013, made by App Energy, LLC to Daybreak Oil and Gas, Inc. (14)

10.15

Assignment of Net Profits Interest dated as of August 28, 2013, made by Daybreak Oil and Gas, Inc. to Maximilian Investors LLC. (14)

10.16

Share Exchange Agreement dated as of May 19, 2014, by and between Daybreak Oil and Gas, Inc. and Maximilian Investors LLC. (16)

10.17

First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement, dated August 21, 2014, by and between Daybreak Oil and Gas, Inc. and Maximilian Resources LLC, a Delaware limited liability company. (17)




98





10.18

First Amendment to Loan and Security Agreement, dated August 21, 2014, by and between Daybreak Oil and Gas, Inc. and App Energy, LLC, a Kentucky limited liability company. (17)

10.19

Second Amendment to Amended and Restated Loan and Security Agreement and Warrant Amendment, dated May 20, 2015, by and between Daybreak Oil and Gas, Inc. and Maximilian Resources LLC, a Delaware limited liability company. (18)

10.20

Second Amendment to Loan and Security Agreement, dated May 20, 2015, by and between Daybreak Oil and Gas, Inc. and App Energy, LLC, a Kentucky limited liability company. (18)

10.21

Third Amendment to Amended and Restated Loan and Security Agreement and Second Warrant Amendment, dated October 14, 2015, by and between Daybreak Oil and Gas, Inc. and Maximilian Resources LLC, a Delaware limited liability company. (19)

10.22

Third Amendment to Loan and Security Agreement, dated October 14, 2015, by and between Daybreak Oil and Gas, Inc. and App Energy, LLC, a Kentucky limited liability company. (19)

23.1

Consent of PGH Petroleum and Environmental Engineers, LLC. (20)

23.2

Consent of MaloneBailey, LLP (20)

31.1

Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (20)

32.1

Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (20)

99.1

Reserve Report of PGH Petroleum and Environmental Engineers, LLC, independent petroleum engineering consulting firm, as of February 28m 2014. (20)


101.INS

XBRL Instance Document (21)


101.SCH

XBRL Taxonomy Schema (21)


101.CAL

XBRL Taxonomy Calculation Linkbase (21)


101.DEF

XBRL Taxonomy Definition Linkbase (21)


101.LAB

XBRL Taxonomy Label Linkbase (21)


101.PRE

XBRL Taxonomy Presentation Linkbase (21)


-----------------------


(1)

Previously filed as exhibit to Form 8-K on April 9, 2008, and incorporated by reference herein.

(2)

Previously filed as exhibits to Form 10-K on May 28, 2009, and incorporated by reference herein.

(3)

Previously filed as exhibit to Form SB-2 on July 18, 2006, and incorporated by reference herein. (filed as part of the Articles of Amendment to the Articles of Incorporation of Daybreak Oil & Gas, Inc. dated June 30, 2006.)

(4)

Previously filed as exhibits to Form SB-2 on July 18, 2006, and incorporated by reference herein.

(5)

Previously filed as exhibits to Form 10-KSB on September 21, 2007, and incorporated by reference herein.

(6)

Previously filed as exhibits to Form S-8 filed on April 7, 2009 and incorporated by reference herein.

(7)

Previously filed as exhibits to Form 8-K on February 3, 2010, and incorporated by reference herein.

(8)

Previously filed as exhibits to Form SB-2/A on December 28, 2006, and incorporated by reference herein.

(9)

Previously filed as exhibits to Form 8-K on February 3, 2010, and incorporated by reference herein.

(10)

Previously filed as exhibit to Form 10-Q on October 17, 2011, and incorporated by reference herein.

(11)

Previously filed as exhibit to Form 10-Q on January 13, 2012, and incorporated by reference herein.

(12)

Previously filed as exhibit to Form 8-K on November 5, 2012 and incorporated by reference herein.

(13)

Previously filed as exhibit to Form 10-Q dated January 10, 2013 and filed on January 11, 2013 and incorporated by reference herein.

(14)

Previously filed as exhibit to Form 8-K on September 3, 2013 and incorporated by reference herein.

(15)

Previously filed as exhibit to Form 10-K filed on May 28, 2010 and incorporated by reference herein

(16)

Previously filed as exhibit to Form 10-K filed on May 29, 2014 and incorporated by reference herein

(17)

Previously filed as exhibit to Form 10-Q filed on October 10, 2014 and incorporated by reference herein.

(18)

Previously filed as exhibit to Form 10-K dated May 21, 2015 and filed on May 22, 2015 and incorporated by reference herein

(19)

Previously filed as exhibit to Form 10-Q filed on January 13, 016 and incorporated by reference herein.

(20)

Filed herewith.

(21)

Furnished herewith.


* Contract or compensatory plan or arrangement in which directors and/or officers may participate.



99






GLOSSARY OF TERMS



The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this Form 10-K.


3-D seismic.  An advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.


API.  American Petroleum Institute, a petroleum induction association that sets standards for oil field equipment and operations.  Also see Oil Gravity.


BOE.  A barrel of oil equivalent (BOE) is the standard convention used to express oil and gas volumes on a comparable oil equivalent basis.  Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.


Bbl.  One barrel, or 42 U.S. gallons of liquid volume.


Completion.  The installation of permanent equipment for the production of oil or gas.


DD&A.  Refers to depreciation, depletion and amortization of the Company’s property and equipment.


Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.


Dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.


Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.


Gross acres or wells.  Refers to the total acres or wells in which the Company has a working interest.


Horizontal drilling.  A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.


Net acres or wells.  Refers to the gross sum of fractional working interest ownership in gross acres or wells.


Net production.  Oil and gas production that is owned by the Company, less royalties and production due others.


NYMEX.  New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded.


Oil.  Crude oil or condensate.


Oil Gravity.  The density of liquid hydrocarbons generally measured in degrees API.  The lighter the oil, the higher the API gravity.  Heavy oil has an API gravity of 20° API or less.  For example, motor lubricating oil is around 26° API; while gasoline is approximately 55° API.


Operator.  The individual or company responsible for the exploration, development and production of an oil or gas well or lease.


Productive wells. Producing wells and wells mechanically capable of production.




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Proved Developed Reserves.  Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.


Proved reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  (i) The area of the reservoir considered as proved includes:  (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities.


Proved undeveloped reserves (PUD).  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.


Royalty.  An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.  Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.


SEC.  The United States Securities and Exchange Commission.


Standardized measure of discounted future net cash flows.  Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes.


Undeveloped acreage.  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.


Working interest.  An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.  The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.


Workover.  Operations on a producing well to restore or increase production.




101






SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



 

 

 

DAYBREAK OIL AND GAS, INC.

 

 

 

 

 

 

 

 

By:

/s/ JAMES F. WESTMORELAND

 

 

 

 

James F. Westmoreland, its

 

 

 

 

President, Chief Executive Officer and

 

 

 

 

interim principal finance and

 

 

 

 

accounting officer

 

 

 

 

Date:  May 27, 2016




Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


By:

/s/ JAMES F. WESTMORELAND

 

By:

/s/ WAYNE G. DOTSON

 

James F. Westmoreland

 

 

Wayne G. Dotson

 

Director / President and Chief Executive Officer

 

 

Director

 

Date:  May 27, 2016

 

 

Date:  May 27, 2016

 

 

 

 

 

By:

/s/ TIMOTHY R. LINDSEY

 

By:

/s/ JAMES F. MEARA

 

Timothy R. Lindsey

 

 

James F. Meara

 

Director

 

 

Director

 

Date:  May 27, 2016

 

 

Date:  May 27, 2016

 

 

 

 

 





102