10-Q 1 daybreakoilandgasform10-q.htm DAYBREAK OIL AND GAS. - QUARTERLY REPORT FOR AUGUST 31, 2011 daybreakoilandgasform10-q.htm - Generated by SEC Publisher for SEC Filing  

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

x  

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

For the quarterly period ended August 31, 2011

 

OR

 

¨  

TRANSITION REPORT PURSUANT TO SECTION 13 O 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to  

       

Commission File Number: 000-50107 

 

DAYBREAK OIL AND GAS, INC.

(Exact name of registrant as specified in its charter)

 

Washington

91-0626366

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

 

 

601 W. Main Ave., Suite 1012, Spokane, WA

99201

(Address of principal executive offices)

(Zip Code)

 

 

(509) 232-7674

(Registrant’s telephone number, including area code)

 

(Former name, former address and former fiscal year, if changed since last report)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  þ  Yes ¨  No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).                                        Yes ¨        No¨ 

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer ¨ 

 

Accelerated filer ¨ 

 

 

 

Non-accelerated filer ¨   

(Do not check if a smaller reporting company)

Smaller reporting company þ 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨Yes þNo  

 

At October 14, 2011 the registrant had 45,787,769 outstanding shares of $0.001 par value common stock.

 

 


 

 

 

TABLE OF CONTENTS

 

PART I - FINANCIAL INFORMATION

 
ITEM 1.     Financial Statements............................................................................................................................................................................................................................................ 3
 
Balance Sheets at August 31, 2011 and February 28, 2011 (Unaudited)................................................................................................................................................................... 3
 
Statements of Operations for the Three and Six Months Ended August 31, 2011 and August 31, 2010 (Unaudited)....................................................................................................
 
Statements of Cash Flows for the Six Months Ended August 31, 2011 and August 31, 2010 (Unaudited)................................................................................................................... 5
 
Notes to Unaudited Financial Statements............................................................................................................................................................................................................... 6
 
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations..................................................................................................................................... 13
 
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk................................................................................................................................................................................ 26
 
ITEM 4. Controls and Procedures..................................................................................................................................................................................................................................... 26
 

PART II - OTHER INFORMATION

 
ITEM 1. Legal Proceedings............................................................................................................................................................................................................................................... 27
 
ITEM 1A. Risk Factors....................................................................................................................................................................................................................................................... 27
 
ITEM 6.  EXHIBITS......................................................................................................................................................................................................................................................... 28
 
Signatures........................................................................................................................................................................................................................................................... 29
       

 

 

 

 

 

 

 


 
 

 

DAYBREAK OIL AND GAS, INC.

Balance Sheets - Unaudited

 

As of August 31,

As of February 28,

 

2011

 

2011

 

ASSETS

CURRENT ASSETS:

       
 

Cash and cash equivalents

$

18,441

$

57,380

 

Accounts receivable:

       
 

   Oil and gas sales

 

214,644

 

185,836

 

   Joint interest participants, net of allowance for doubtful

      accounts of $33,346

 

119,529

 

163,551

 

   Production revenue receivable

 

25,000

 

25,000

 

   Loan commitment refund and other receivables 

 

212,565

 

91,632

 

Prepaid expenses and other current assets

 

18,560

 

69,876

 

   Total current assets

 

608,739

 

593,275

 

OIL AND GAS PROPERTIES, net of accumulated depletion,

   depreciation, amortization, and impairment, net of $1,023,992

   and $871,666, respectively, successful efforts method

       
 

   Proved properties

 

1,709,865

 

1,837,431

 

   Unproved properties

 

449,251

 

452,570

 

VEHICLES AND EQUIPMENT, net of accumulated depreciation of $31,329

-

 

-

 

PRODUCTION REVENUE RECEIVABLE -LONG TERM

 

325,000

 

325,000

 

OTHER ASSETS

 

105,222

 

104,904

 

   Total assets

$

3,198,077

$

3,313,180

 

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)

CURRENT LIABILITIES:

       
 

Accounts payable and other accrued liabilities

$

1,658,804

$

1,790,382

 

Accounts payable - related parties

 

299,988

 

156,370

 

Accrued interest

 

6,064

 

5,477

 

Notes payable, net of discount of $-0- and $30,105, respectively

 

750,000

 

719,895

 

Notes payable- related party

 

200,000

 

-

 

   Total current liabilities

 

2,914,856

 

2,672,124

LONG TERM LIABILITIES:

       
 

Notes payable, net of discount of $90,208 and $99,106, respectively

 

504,792

 

495,894

 

Asset retirement obligation

 

57,090

 

55,122

 

   Total liabilities

 

3,476,738

 

3,223,140

COMMITMENTS

       

STOCKHOLDERS’ EQUITY (DEFICIT):

       
 

Preferred stock - 10,000,000 shares authorized, $0.001 par value

 

-

 

-

Series A Convertible Preferred stock - 2,400,000 shares authorized,

    $0.001 par value, 6% cumulative dividends, 906,565

    shares issued and outstanding

907

907

 

Common stock- 200,000,000 shares authorized, $0.001 par value,

    48,787,769 and 48,791,599 shares issued and outstanding, respectively

48,788

48,792

 

Additional paid-in capital

 

22,492,481

 

22,447,250

 

Accumulated deficit

 

(22,820,837)

 

(22,406,909)

 

Total stockholders’ equity (deficit)

 

(278,661)

 

90,040

 

    Total liabilities and stockholders' equity (deficit)

$

3,198,077

$

3,313,180

             

 

 

 

3


 
 

 

DAYBREAK OIL AND GAS, INC.

Statements of Operations - Unaudited

For the Three Months Ended
August 31,

For the Six Months Ended
August 31,

2011

 

2010

 

2011

 

2010

REVENUE:

               

   Oil and gas sales

$

331,684

$

307,006

$

712,041

$

500,057

               

OPERATING EXPENSES:

               

   Production expenses

 

59,071

 

12,988

 

99,843

 

48,931

   Exploration and drilling

 

29,986

 

71,463

 

55,788

 

144,283

   Depreciation, depletion, amortization, and impairment

 

75,337

 

121,770

 

154,908

 

237,057

   Gain on write-off of asset retirement obligation

 

-

 

-

 

-

 

(8,324)

   General and administrative

 

368,184

 

444,141

 

698,316

 

799,893

       Total operating expenses

 

532,578

 

650,362

 

1,008,855

 

1,221,840

OPERATING LOSS

 

(200,894)

 

(343,356)

 

(296,814)

 

(721,783)

                 

OTHER INCOME (EXPENSE):

               

   Interest income

 

159

 

493

 

328

 

1,680

   Interest expense

 

(58,747)

 

(23,420)

 

(117,442)

 

(46,661)

       Total other income (expense)

 

(58,588)

 

(22,927)

 

(117,114)

 

(44,981)

LOSS FROM CONTINUING OPERATIONS

 

(259,482)

 

(366,283)

 

(413,928)

 

(766,764)

DISCONTINUED OPERATIONS

               

   Income from discontinued operations

     (net of tax of $ -0-)

 

-

 

40

 

-

 

731

   Gain (loss) from sale of oil and gas properties

     (net of tax of $ -0-)

 

-

 

(3,868)

 

-

 

10,226

INCOME (LOSS) FROM DISCONTINUED

OPERATIONS

 

-

 

(3,828)

 

-

 

10,957

     

         

NET LOSS

 

(259,482)

 

(370,111)

 

(413,928)

 

(755,807)

Cumulative convertible preferred stock

   dividend requirement

 

(41,139)

 

(43,967)

 

(82,278)

 

(89,726)

NET LOSS AVAILABLE TO COMMON

   SHAREHOLDERS

$

(300,621)

$

(414,078)

$

(496,206)

$

(845,533)

NET LOSS PER COMMON SHARE

               

   Loss from continuing operations

$

(0.01)

$

(0.01)

$

(0.01)

$

(0.02)

   Income (loss) from discontinued operations

 

-

 

-

 

-

 

-

NET LOSS PER COMMON SHARE - Basic and diluted

$

(0.01)

$

(0.01)

$

(0.01)

$

(0.02)

WEIGHTED AVERAGE NUMBER OF

   COMMON SHARES OUTSTANDING -

               

     Basic and diluted

 

48,791,516

 

48,070,962

 

48,791,557

 

47,927,501

 

 

4


 
 

 

 

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows - Unaudited

           

 

Six Months Ended
August 31,

2011

2010

     

         

CASH FLOWS FROM OPERATING ACTIVITIES

         
 

Net loss

 

$

(413,928)

$

(755,807)

 

Adjustments to reconcile net loss to net cash used in operating activities:

         
   

Stock compensation

   

45,610

 

42,898

   

Gain on write-off of asset retirement obligation

   

-

 

(8,324)

   

Gain on sale of oil and gas properties

   

-

 

(10,226)

   

Depreciation, depletion, and impairment expense

   

154,908

 

237,057

   

Amortization of debt discount

   

39,003

 

7,553

   

Amortization of loan origination fees

   

11,875

 

-

   

Bad debt expense (recovery)

   

-

 

(5,047)

   

Non-cash interest income

   

(318)

 

(1,680)

   

Warrant expense for services

   

-

 

14,600

 

Changes in assets and liabilities:

         
   

Accounts receivable - oil and gas sales

   

(28,808)

 

79,378

   

Accounts receivable - joint interest participants

   

44,022

 

(224,541)

   

Receivables associated with assets held for sale

   

-

 

303,097

   

Accounts receivable - other

   

79,067

 

-

   

Prepaid expenses and other current assets

   

39,441

 

2,485

   

Other assets

   

-

 

299,421

   

Accounts payable and other accrued liabilities

   

(25,758)

 

162,622

   

Accounts payable - related parties

   

143,618

 

12,546

   

Accrued interest

   

587

 

1,060

     

Net cash provided by operating activities

   

89,319

 

157,092

     

         

CASH FLOWS FROM INVESTING ACTIVITIES:

         
 

Additions to oil and gas properties

   

(128,258)

 

(417,664)

     

         

CASH FLOWS FROM FINANCING ACTIVITIES:

         
 

Proceeds from issuance of notes payable

   

-

 

30,000

   

Proceeds from issuance of notes payable – related parties

   

200,000

 

-

 

 

Payment to escrow for loan commitment

 

 

(200,000)

 

-

 

 

 

Net cash provided by financing activities

 

 

-

 

30,000

     

NET DECREASE IN CASH AND CASH EQUIVALENTS

   

(38,939)

 

(230,572)

     

         
     

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

 

57,380

 

247,951

     

         
     

CASH AND CASH EQUIVALENTS AT END OF PERIOD

 

$

18,441

$

17,379

CASH PAID FOR:

         
 

Interest

 

$

40,353

$

38,048

 

Income taxes

 

-

 

-

             

 

 

SUPPLEMENTAL CASH FLOW INFORMATION:

 

 

 

 

 
 

Unpaid additions to oil and gas properties

 

$

5,314

$

93,086

 

Addition to asset retirement obligation

 

$

605

$

7,584

 

Discount on notes payable - Long term

 

$

8,897

$

5,284

 

Conversion of preferred stock to common stock

 

$

-

$

96

                   
 
 

5


 
 

DAYBREAK OIL AND GAS, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

 

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

Organization

 

Originally incorporated on March 11, 1955, as Daybreak Uranium, Inc. under the laws of the State of Washington, the Company was organized to explore for, acquire, and develop mineral properties in the Western United States.  In March 2005, the Company decided to enter the oil and gas exploration industry, and on October 25, 2005, the shareholders approved a name change from Daybreak Mines, Inc. to Daybreak Oil and Gas, Inc. (the “Company” or “Daybreak”) to better reflect the business of the Company.

 

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

 

Basis of Presentation

 

The accompanying unaudited interim financial statements and notes for the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q for quarterly reports under Section 13 or 15 (d) of the Securities Exchange Act of 1934 (the “Exchange Act”).  Accordingly, they do not include all of the information and footnote disclosures normally required by accounting principles generally accepted in the United States of America for complete financial statements. 

 

In the opinion of management, all adjustments considered necessary for a fair presentation have been included and such adjustments are of a normal recurring nature.  Operating results for the six months ended August 31, 2011 are not necessarily indicative of the results that may be expected for the fiscal year ending February 29, 2012.

 

These financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended February 28, 2011.

 

Use of Estimates

 

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions.  These estimates and assumptions may affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and revenues and expenses during the reporting period.  Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows:

 

·         The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any impairment of

      proved properties;

·         The valuation of unproved acreage and proved oil and gas properties to determine the amount of any impairment of oil and gas properties;

·         Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment; and

·         Estimates regarding abandonment obligations.

 

6


 
 

NOTE 2 — GOING CONCERN

 

Financial Condition  

 

The Company’s financial statements for the six months ended August 31, 2011 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  The Company has incurred net losses since entering the oil and gas exploration industry and as of August 31, 2011 has an accumulated deficit of $22,820,837 and a working capital deficit of $2,306,117 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 11 producing wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”).  The revenue from these wells has created a steady and reliable source of revenue for the Company.  Daybreak’s average net revenue interest in these wells is 29.85%.  The Company’s average working interest is 40.15% for these same wells. 

 

The Company anticipates revenues will continue to increase as it participates in the drilling of more wells in California.  Daybreak plans to continue its development drilling program at a rate that is compatible with its cash flow and funding opportunities. 

 

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company does have positive cash flow from its oil and gas properties, it has not yet established a positive cash flow on a company-wide basis.  It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future.   

 

The Company’s financial statements as of August 31, 2011 do not include any adjustments that might result from the inability to implement or execute the plans to improve its ability to continue as a going concern.

 

NOTE 3 RECENT ACCOUNTING PRONOUNCEMENTS

 

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements).  The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact the Company’s operating results, financial position or cash flows and related disclosures.

 

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

 

 

 

 

7


 
 

NOTE 4 CONCENTRATION OF CREDIT RISK

 

Substantially all of the Company’s accounts receivable result from crude oil sales or joint interest billings to its working interest partners.  This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors.  Accounts receivable are generally not collateralized.  Allowances for doubtful accounts at August 31, 2011 and February 28, 2011 relate to amounts due from joint interest owners of projects in which the Company no longer participates. 

 

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

 

NOTE 5OIL AND GAS PROPERTIES

 

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

 

 

 

August 31, 2011

 

February 28, 2011

Proved leasehold costs

$

8,975 

$

8,975 

Unproved leasehold costs

 

449,251 

 

452,570 

Costs of wells and development

 

443,305 

 

422,702 

Capitalized exploratory well costs

 

2,234,273 

 

2,229,511 

Capitalized asset retirement costs

 

47,304 

 

47,909 

Total cost of oil and gas properties

 

3,183,108 

 

3,161,667 

Accumulated depletion, depreciation,

 

(1,023,992)

 

(871,666)

amortization and impairment

Net Oil and Gas Properties

$

2,159,116 

$

2,290,001 

 

NOTE 6 —  ACCOUNTS PAYABLE

 

On March 1, 2009, the Company became the operator for its East Slopes Project.  Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project’s four earning wells.  The Company subsequently sold the same 25% working interest on June 11, 2009.  Approximately $317,034 of the $1.5 million default remains unpaid and is included in the August 31, 2011 accounts payable balance.

 

NOTE 7NOTES PAYABLE

 

Short-Term

 

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest in its East Slopes Project from another working interest owner.  The Company financed the additional working interest purchase by issuing, to a third party, a one-year convertible secured promissory note for the principal amount of $750,000 (the “Wells Works Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing.  Interest expense related to the Well Works Loan for the six months ended August 31, 2011 was $37,500.

 

The third party may convert up to 50% of the unpaid principal balance into the Company’s Common Stock at a conversion price of $0.16 per share at any time prior to the Well Works Loan being paid in full. 

 

The Well Works Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in the Company’s East Slopes Project Furthermore, as a condition precedent to the Well Works Loan, the Company entered into a Technical and Consulting Services Agreement with the third party, whereby the Company will provide operating, engineering and technical consulting to the third party for a one-year period for the purpose of evaluating 22 wells in Hutchinson County, Texas for the third party. 

 

8


 
     

The Company also issued 250,000 shares of the Company’s Common Stock to the third party as a loan origination fee.  The fair value of these shares amounted to $23,750 which was deferred and fully amortized over the term of the Wells Works Loan.  Amortization expense for the six months ended August 31, 2011 amounted to $11,875. The loan origination fees were fully amortized as of August 31, 2011. 

 

As additional consideration for the Wells Works Loan, the Company executed an Assignment of Net Profits Interest in favor of the third party, whereby the Company assigned two percent of the net profits realized by the Company on its leases in the East Slopes Project.  The fair value of the two percent net profits interest was determined to be $60,210 and has been recognized as a discount to the debt.  The debt discount was deferred and fully amortized over the term of the Wells Works Loan.  Amortization expense for the six months ended August 31, 2011 amounted to $30,105. The debt discount was fully amortized as of August 31, 2011.

 

The Company analyzed the Wells Works Loan for derivative accounting consideration and determined that derivative accounting does not apply to this instrument.

 

Short-Term (Related Party)

 

On June 20, 2011, the Company issued a $200,000 non-interest bearing note from the Company’s President and Chief Executive Officer.  The term of the note provided for repayment on or before June 30, 2011, or such other date as may be agreed to by the Company its President.  The Company and its President have agreed that repayment will be made upon the successful completion of financing.

 

Proceeds from the note were used to meet the escrow requirement on a loan commitment.  The escrow requirement amount is reflected as an account receivable on the Balance Sheet and will be refunded to the Company upon closing. 

 

Long-Term

 

On March 16, 2010, the Company closed its private placement of 12% Subordinated Notes (the “Notes”) to 13 accredited investors resulting in total gross proceeds of $595,000.  The note principal is payable in full at the expiration of the term of the Notes, which is January 29, 2015.  The Notes are subject to an annual interest rate of 12%, payable semi-annually.  On the maturity date, the Company may elect a mandatory conversion of the unpaid principal and interest into the Company’s Common Stock at a conversion rate equal to 75% of the average closing price of the Company’s Common Stock over the 20 consecutive trading days preceding December 31, 2014.  A $250,000 Note was sold to a related party, the Company’s President and Chief Executive Officer.  The terms and conditions of the related party Note were identical to the terms and conditions of the other accredited investors’ Notes.  

 

Two Common Stock purchase warrants were issued for every dollar raised through the private placement resulting in 1,190,000 warrants being issued. The warrants have an exercise price of $0.14 and expire on January 29, 2015. The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $116,557 using the following weighted-average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%.  The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method.  Amortization expense for the six months ended August 31, 2011 was $8,898.  Unamortized debt discount amounted to $90,209 as of August 31, 2011.

 

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

 

9


 
 

NOTE 8 — STOCKHOLDERS EQUITY DEFICIT

 

Series A Convertible Preferred Stock

 

The Company is authorized to issue up to 10,000,000 shares of $0.001 par value preferred stock.  The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as “Series A Convertible Preferred Stock” (“Series A Preferred”), with a $0.001 par value, of which 906,565 shares were issued and outstanding as of August 31, 2011.  The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s Common Stock.  

 

During the three and six months ended August 31, 2011, there were no conversions of Series A Preferred to the Company’s Common Stock.

  

Holders of Series A Preferred earn a 6% annual cumulative dividend based on the original purchase price of the shares.  Accumulated dividends do not bear interest and as of August 31, 2011, accumulated and unpaid dividends amounted to $1,053,950.  Dividends may be paid in cash or Common Stock at the discretion of the Company and are payable upon declaration by the Board of Directors.  Dividends are earned until the Series A Preferred is converted to Common Stock.  No payment of dividends has been declared as of August 31, 2011.

 

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

Fiscal Year Ended

 

Shareholders at
Period End

 

Accumulated

Dividends

 

 

 

 

 

February 28, 2007

 

100

$

 155,333

February 29, 2008

 

90

 

242,165

February 28, 2009

 

78

 

209,974

February 28, 2010

 

74

 

190,460

February 28, 2011

 

70

 

173,740

Six Months Ended August 31, 2011

 

70

 

82,278

Total Accumulated Dividends

 

 

$

1,053,950

 

Common Stock

 

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock, of which 48,787,769 shares were issued and outstanding as of August 31, 2011. For the three and six months ended August 31, 2011, no shares of the Company’s Common Stock were issued.  However, 3,830 shares of the Company’s Common Stock relating to the 2009 Stock Plan were returned to the Company during the three months ended August 31, 2011 as discussed in Note 10 below.

 

NOTE 9 —  WARRANTS

 

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

 

 

 

Warrants

Exercise
Price

Remaining
Life
(Years)

Exercisable
Warrants
Remaining

 

 

 

 

 

 

Placement agent warrants - Spring 2006 PP

 

802,721

$0.75

1.75

802,721

Placement agent warrants - Spring 2006 PP

 

401,361

$2.00

1.75

401,361

Placement agent warrants - July 2006 PP

 

419,930

$1.00

2.00

419,930

Convertible debenture term extension

 

150,001

$2.00

0.25

150,001

12% Subordinated Note warrants

 

1,190,000

$0.14

3.25

1,190,000

Warrants issued in 2010 for services

 

150,000

$0.14

3.75

150,000

 

 

3,114,013

 

 

3,114,013

 

10


 
 

There were no warrants issued or exercised during the three and six months ended August 31, 2011.  For the six months ended August 31, 2011, a total of 6,813,132 warrants expired.  These warrants were issued to accredited investors in private placements of the Company’s Common Stock Series A Preferred that occurred in the Spring of 2006 and July of 2006, respectively. 

 

The outstanding warrants as of August 31, 2011, have a weighted average exercise price of $0.74, a weighted average remaining life of 2.38 years, and an intrinsic value of $-0-.

 

NOTE 10 —  RESTRICTED STOCK and RESTRICTED STOCK UNIT PLAN

 

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

 

For the six months ended August 31, 2011, an aggregate of 912,499 shares vested and 3,830 shares were returned to the 2009 Plan.  At August 31, 2011, a total of 1,003,830 Common Stock shares remained available for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan activity is set forth in the table below:

 

Grant

Date

 

Shares
Awarded

 

Vesting
Period

 

Shares
Vested

 

Shares
Returned

 

Shares
Outstanding
(Unvested)

4/7/2009

 

1,900,000

 

3 Years

 

1,266,665

 

-0-

 

633,335

7/16/2009

 

25,000

 

3 Years

 

16,665

 

-0-

 

8,335

7/16/2009

 

625,000

 

4 Years

 

312,500

 

1,915 

 

312,500

7/22/2010

 

25,000

 

3 Years

 

8,330

 

-0-

 

16,670

7/22/2010

 

425,000

 

4 Years

 

106,250

 

1,915 

 

318,750

 

 

3,000,000

 

 

 

1,710,410

 

3,830 

 

1,289,590

 

For the six months ended August 31, 2011, the Company recognized compensation expense related to the above restricted stock grants of $45,609.  Unamortized compensation expense amounted to $87,688 as of August 31, 2011.

 

NOTE 11 —  INCOME TAXES

 

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

 

 

August 31, 2011

August 31, 2010

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

$                           (165,571)

$                         (302,323)

Permanent differences

                                31,891

                              20,323

Changes in valuation allowance

                              133,680 

                            282,000

Total

$                                      -0-

$                                    -0-

 

 

 

11


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

 

 

August 31, 2011

 

February 28, 2011

Deferred tax assets:

 

 

 

Net operating loss carryforwards

$                              5,980,285

 

$                             5,900,491

Oil and gas properties

                                 (182,230)

 

                                (226,994)

Stock based compensation

                                    44,525

 

                                   35,403

Less valuation allowance

                              (5,842,580)

 

                             (5,708,900)

Total

$                                          -0-

 

$                                         -0-

 

At August 31, 2011, the Company had estimated net operating loss carryforwards for federal and state income tax purposes of approximately $14,950,712, which will begin to expire, if unused, beginning in 2024.  The valuation allowance increased approximately $133,680 for the six months ended August 31, 2011 and increased $471,569 for the year ended February 28, 2011. Section 382 of the Internal Revenue Code places annual limitations on the Company’s net operating loss (“NOL”) carryforward.

 

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

 

NOTE 12 — COMMITMENTS AND CONTINGENCIES

 

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

 

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

 

The Company is not aware of any environmental claims existing as of August 31, 2011.  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.

 

 

 

 

 

 

 

 

 

12


 
 

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

 

Cautionary Statement Regarding Forward-Looking Statements

 

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

 

Some statements contained in this Form 10-Q report relate to results or developments that we anticipate will or may occur in the future and are not statements of historical fact.  All statements other than statements of historical fact contained in this MD&A report are inherently uncertain and are forward-looking statements.  Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will” and similar expressions identify forward-looking statements.  Examples of forward-looking statements include statements about the following:

·         Our future operating results;

·         Our future capital expenditures;

·         Our future financing;

·         Our expansion and growth of operations; and

·         Our future investments in and acquisitions of oil and natural gas properties.

 

We have based these forward-looking statements on assumptions and analyses made in light of our experience and our perception of historical trends, current conditions, and expected future developments.  However, you should be aware that these forward-looking statements are only our predictions and we cannot guarantee any such outcomes.  Future events and actual results may differ materially from the results set forth in or implied in the forward-looking statements.  Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

·         General economic and business conditions;

·         Exposure to market risks in our financial instruments;

·         Fluctuations in worldwide prices and demand for oil and natural gas;

·         Our ability to find, acquire and develop oil and gas properties;

·         Fluctuations in the levels of our oil and natural gas exploration and development activities;

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

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

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

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

·         Our ability to continue as a going concern;

·         Our ability to secure financing under any commitments as well as additional capital to fund operations; and

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

 

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  We specifically undertake no obligation to publicly update or revise any information contained in any forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except as required by law. 

 

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

 

13


 
 

Introduction and Overview

 

The following MD&A is management’s assessment of the historical financial and operating results of the Company for the three and six month periods ended August 31, 2011 and August 31, 2010 and of our financial condition as of August 31, 2011, and is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes included elsewhere in this Form 10-Q and in our audited financial statements and notes included in our Annual Report on Form 10-K for the fiscal year ended February 28, 2011.  Unless otherwise noted, all of our discussion refers to continuing operations in Kern County, California. 

 

We are an independent oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities and selling the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.

 

Plan of Operation

 

Our longer-term success depends on, among many other factors, the acquisition and drilling of commercial grade oil and gas properties and on the prevailing sales prices for oil and natural gas along with associated operating expenses.  The volatile nature of the energy markets makes it difficult to estimate future prices of oil and natural gas; however, any prolonged period of depressed prices would have a material adverse effect on our results of operations and financial condition. Our operations are focused on identifying and evaluating prospective oil and gas properties and funding projects that we believe have the potential to produce oil or gas in commercial quantities.  We are in the process of developing a multi-well oilfield project in Kern County, California and have participated in the drilling of 11 oil wells that have achieved commercial production.   

 

Kern County, California (East Slopes Project)

 

We believe the Company is now well positioned to expand its operations in the East Slopes Project.  We currently have production from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek properties.  The Sunday and Bear properties each have four producing wells.  The Black property is the smallest of all currently producing reservoirs, and we will most likely drill only one or two more development wells at this property.  The Ball and Dyer Creek properties were put on production in late October 2010.  There are several other similar prospects on trend with the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic characteristics.  Some of these prospects, if successful, would utilize the Company’s existing production facilities.  In addition to the current field development, there are several other exploratory prospects that have been identified from seismic data, which we plan to drill in the future.

 

Sunday Property

 

In November 2008, we made our initial oil discovery drilling the Sunday #1 well.  The well was put on production in January 2009.  Production is from the Vedder sand at approximately 2,000 feet.  During 2009, we drilled three development wells including one horizontal well.  The Sunday reservoir is estimated to be approximately 34.6 acres in size with the potential for at least three more development wells to be drilled in the future.  With the acquisition of an additional 16.67% working interest in the East Slopes Project in September 2010, we have a 41.67% working interest with a 29.0% net revenue interest in the Sunday #1 well.  We continue to have a 37.5% working interest with a 27% net revenue interest in each of the Sunday #2 and #3 wells.  We also have a 37.5% working interest with a 30.1% net revenue interest in the Sunday #4H well.

 

14


 
 

Bear Property

 

In February 2009, we made our second oil discovery drilling the Bear #1 well, which is approximately one mile northwest of our Sunday discovery.  The well was put on production in May 2009.  Production is from the Vedder sand at approximately 2,200 feet.  In December 2009, we began a development program by drilling and completing the Bear #2 well.  In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells.  The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least three more development wells to be drilled in the future, including one planned for the fall of 2011.  With the acquisition of an additional 16.67% working interest in the East Slopes Project in September 2010, we have a 41.67% working interest with a 29.0% net revenue interest in each of the Bear wells in this property.

 

Black Property

  

The Black property was acquired through a farm-in arrangement with a local operator.  The Black property is just south of the Bear property on the same fault system.  The Black #1 well was completed and put on production in January 2010.  Production is from the Vedder sand at 2,150 feet.  The Black reservoir is estimated to be approximately 13.4 acres in size with the potential for up to two more development wells to be drilled in the future.  We have a 37.5% working interest with a 29.8% net revenue interest in this property.

 

Sunday Central Processing and Storage Facility

 

The oil produced from our acreage is considered heavy oil.  The oil ranges from 14°  to 16°  API gravity.  All of our oil from the Sunday, Bear and Black properties is processed, stored and sold from the Sunday Central Processing and Storage Facility.  The oil must be heated to separate and remove water to prepare it to be sold.  We constructed these facilities during the summer and fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines.  As a result, our average operating costs have been reduced from over $40 per barrel to approximately $18 per barrel of oil after accounting for the loss of certain oil processing credits that ceased with our purchase of an additional 16.67% working interest in September 2010.  By having this central facility and permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

 

Ball Property

 

The Ball #1-11 well was put on production in late October 2010.  Our 3-D seismic data indicates a reservoir approximately 37.5 acres in size with the potential for at least two development wells to be drilled in the future.  Production from the Ball #1-11 well is being processed at the Dyer Creek production facility.  We have a 41.67% working interest with a 34.69% net revenue interest in this property.  We expect to drill at least one development well at this property during the fall of 2011.  

 

Dyer Creek Property

 

The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010.  This well is producing from the Vedder sand and is located to the north of the Bear property on the same trapping fault. The Dyer Creek property has the potential for at least one development well in the future.  Production from the DC67X well is also being processed at the Dyer Creek production facility.  We have a 41.67% working interest with a 34.69% net revenue interest in this property.

 

Dyer Creek Processing and Storage Facility

 

The Dyer Creek Processing and Storage Facility serves the Ball and Dyer Creek properties and includes previously abandoned infrastructure that we have refurbished.  We have completed the installation of

 

15


 
 

electrical service to this location, thereby reducing operating costs through the elimination of rental equipment for power generation.  The oil produced into this facility has a similar API gravity to the oil at the Sunday production facility and the oil must also be heated to separate and remove water in preparation for sale.

   

Bull Run Prospect

 

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Etchegoin and Santa Margarita sands located between 800 and 1,200 feet deep.  We plan to drill an exploratory well on this prospect during the fall of 2011.  The Bull Run wells will require a pilot steam flood and additional production facilities.  We have a 41.67% working interest in this prospect.

 

Glide-Kendall Prospect

 

This prospect is also located in the southern portion of our acreage position.  The drilling targets are the Olcese and Eocene sands between 1,000 and 2,000 feet deep.  We plan to drill an exploratory well in the fall of 2011.  We have a 41.67% working interest in this prospect.

 

Sherman Prospect

 

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Olcese and Etchegoin sands between 1,000 and 2,000 feet deep.  We plan to drill an exploratory well in early 2012.  We have a 41.67% working interest in this prospect.

 

Baker Prospect

 

This prospect is located in the northern portion of our acreage position approximately one mile south of our Sunday property.  The drilling target is the Vedder sand at approximately 2,000 feet deep.  We plan to drill an exploratory well in early 2012.  We have a 41.67% working interest in this prospect.

 

Breckenridge-Chimney Prospect

 

This prospect is located in the central portion of our acreage position. The drilling targets are the Vedder and Eocene sands between 2,000 and 2,500 feet deep.  We plan to drill an exploratory well in 2012.  We have a 41.67% working interest in this prospect.

 

Tobias Prospect

 

This prospect is also located in the central portion of our acreage position.  The drilling targets are the Vedder and Eocene sands between 2,000 and 2,500 feet deep.  We plan to drill an exploratory well in 2012.  We have a 41.67% working interest in this prospect.

 

Production, Revenue and LOE

 

Our net sales volume, revenue and lease operating expenses (“LOE”) at the East Slopes Project for the last five quarters ended August 31, 2011 are set forth in the following table:

 

 

 

Three Months

Ended

August 31, 2011

 

Three Months
Ended

May 31, 2011

 

Three Months
Ended

February 28, 2011

 

Three Months
Ended

November 30, 2010

 

Three Months
Ended

August 31, 2010

Sales (Bbls)

 

3,362

 

3,502

 

3,805

 

3,508

 

2,976

Revenue

$

331,684

$

 380,357

$

320,375

$

 259,064

$

 202,989

LOE

$

59,071

$

 40,772

$

 62,524

$

 56,778

$

19,514

 

 

 

 

 

 

 

 

 

 

 

Average Sales Price (Bbls)

$

 98.66

$

 108.61

$

 84.20

$

 73.85

$

 68.21

 

 

 

 

 

 

 

 

 

 

 

Average LOE (Bbls)

$

 17.57

$

11.64

$

16.43

$

 16.18

$

6.56

 

16


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

 

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

 

Revenues.  Revenues are derived entirely from the sale of our share of oil production.  We realized the first revenues from producing wells in our East Slopes Project during February 2009.  The price we receive for oil sales is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) contracts, less deductions that vary by grade of crude oil sold.  Historically, the sales price we receive for California oil sales has been less than the quoted WTI price.  For the three months ended August 31, 2010, the average discount from WTI pricing on oil sales in California was 10.4%. For the three months ended August 31, 2011, the average monthly sales price was a premium of 5.8% higher than the average WTI pricing. 

 

Revenues at our East Slopes Project for the three months ended August 31, 2011 increased $128,695 or 63.4% to $331,684 in comparison to revenues of $202,989 for the three months ended August 31, 2010.  The average sales price of a barrel of oil for the three months ended August 31, 2011 was $98.66 in comparison to $68.21 for the three months ended August 31, 2010.  The increase of $30.45 or 44.7% in the average sales price of a barrel of oil accounted for $90,648 or 70.4% of the revenue increase from the comparative three month period ended August 31, 2010.  The balance of the revenue for the three months ended August 31, 2010 was comprised of gas revenue of approximately $104,017 from the Krotz Springs project in Louisiana.

 

At our East Slopes Project, production for the three months ended August 31, 2011 was from 11 wells with a total of 1,007 well days in comparison to production from nine wells with a total of 818 well days for the three months ended August 31, 2010.  Our net share of production for the three months ended August 31, 2011 was 3,362 barrels in comparison to 2,976 barrels for the three months ended August 31, 2010.  The increase in production of 386 barrels or 13.0% accounted for $38,047 or 29.6% of the revenue increase from the comparative three month period ended August 31, 2010.  A table of our revenues is set forth below:

 

 

 

Three Months Ended

August 31, 2011

 

Three Months Ended

August 31, 2010

California - East Slopes Project

$

 331,684 

$

 202,989

Louisiana - Krotz Springs** 

 

-0-

 

104,017

Total Revenues

$

331,684  

$

 307,006

 

**During three months ended August 31, 2010, the Company received approximately $104,017 in revenue related to the Krotz Springs Field in Louisiana as a one-time adjustment to gas revenue earned in calendar years 2007, 2008 and 2009 due to well production revenue misallocation by the unitized field operator.

 

Operating Expenses.  Total  operating expenses for the three months ended August 31, 2011 decreased by $117,784 or 18.1% in comparison to the three months ended August 31, 2010.  Significant decreases of $163,867 or 25.7% in aggregate occurred in exploration and drilling and depreciation, depletion and amortization (“DD&A”) expenses and general and administrative (“G&A”) expenses. However these decreases were partially offset by an increase of $46,083 in production expenses.  

 

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

 

 

August 31, 2011

 

August 31, 2010

Production expenses

$

 59,071

$

 12,988

Exploration and drilling

29,986

 

71,463

DD&A

75,337

 

121,770

G&A

368,184

 

444,141

Total operating expenses

$

532,578

$

650,362

 

17


 
 

Production expenses include expenses directly associated with the generation of oil and gas revenues, road maintenance and well workover expenses.  For the three months ended August 31, 2011, these expenses increased by $46,083 in comparison to the three months ended August 31, 2010.  The increase in production expenses is directly related to the 11 wells and nine wells that were producing during the three months ended August 31, 2011 and 2010, respectively, and our percentage of working interest ownership in those wells.  Additionally, for the three months ended August 31, 2010 we received oil processing credits of approximately $14,840 from a third party that were applied against production expenses.  The oil processing credits related to five wells producing into the Sunday Central Processing and Storage Facility.  Production expenses represented approximately 11.1% of total operating expenses.

 

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  For the three months ended August 31, 2011 these expenses decreased $41,477 or 58.0%, in comparison to the three months ended August 31, 2010.  Exploration expenses decreased primarily because of fewer lease rental expenses due to the expiration of certain leases.  For the three months ended August 31, 2011, we did not drill any dry hole or non-commercial wells.  Exploration and drilling expenses represented approximately 5.6% of total operating expenses.

 

DD&A expenses relating to equipment, proven reserves and property costs, along with impairment are another component of operating expenses.  DD&A expenses decreased $46,433 or 38.1% for the three months ended August 31, 2011 in comparison to the three months ended August 31, 2010 primarily due to a larger proven reserve base.  DD&A expenses represented approximately 14.2% of total operating expenses.    

 

G&A expenses include the salaries of seven employees, including management. Other items included in our G&A 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 with being an operator of oil and gas properties; as well as running a public company.  For the three months ended August 31, 2011, G&A expenses decreased 75,957 or 17.1%, compared to the three months ended August 31, 2010.  Significant decreases were realized in the following areas: consulting and fundraising ($32,063), shareholder services and meetings ($29,240), travel ($13,785), and advertising and marketing ($9,278).  Management and employee salaries, which were 44.1% of our G&A expense, director fees and stock compensation remained relatively unchanged for the three months ended August 31, 2011 in comparison to the three months ended August 31, 2010.  For the three months ended August 31, 2011 and 2010, we received, as Operator, administrative overhead reimbursement of approximately $16,400 and $20,700, respectively, for the East Slopes Project, which was used to directly offset certain employee salaries.  We are continuing a program of reducing all of our G&A costs wherever possible.  G&A costs represented approximately 69.1% of total operating expenses.

 

Interest income for the three months ended August 31, 2011 decreased $334 compared to the three months ended August 31, 2010, due to lower average cash balances.

 

Interest expense for the three months ended August 31, 2011 increased $35,327 compared to the three months ended August 31, 2010, due to amortization of the debt discount and interest on the 12% Subordinated Notes that were sold from January 2010 through March 2010 and amortization of loan origination fees and the fair value of the net profits interest associated with the Well Works Loan.

 

Due to the nature of our business, as well as the relative immaturity of the Company, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially on a quarter-to-quarter and year-to-year basis.  Production costs 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 and impairment costs will depend upon the factors cited above.  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.

 

18


 
 

Six Months Ended August 31, 2011 compared to the Six Months Ended August 31, 2010

 

The following discussion compares our results for the six month periods ended August 31, 2011 and August 31, 2010.  Unless otherwise referenced, these results only cover our continuing operations at the East Slopes Project.

 

Revenues.  Revenues are derived entirely from the sale of our share of oil production.  Historically, the sales price we receive for California oil sales has been less than the quoted West Texas Intermediate (“WTI”)  price.  For the six months ended August 31, 2010, the average discount from WTI pricing on oil sales in California was 10.8%. For the six months ended August 31, 2011, the average monthly sales price was a premium of 4.9% higher than the average WTI pricing.

 

Revenues at our East Slopes Project for the six months ended August 31, 2011 increased $316,001 or 79.8% to $712,041 in comparison to revenue of $396,040 for the six months ended August 31, 2010.  The average sales price of a barrel of oil for the six months ended August 31, 2011 was $103.74 in comparison to $69.53 for the six months ended August 31, 2010.  The increase of $34.21 or 49.2% in the average sales price of a barrel of oil accounted for $194,864 or 61.7% of the revenue increase from the comparative six month period ended August 31, 2010.  The revenue for the six months ended August 31, 2010 included a special one-time revenue adjustment of approximately $104,017 in regards to the Krotz Springs well in Louisiana. 

 

Production for the six months ended August 31, 2011 was from 11 producing wells from our East Slopes Project in comparison to nine producing wells for the six months ended August 31, 2010.  The Bear #3 and Bear #4 wells were on production for 41 and 34 days, respectively, for the three months ended May 31, 2010.  Our net share of production for the six months ended August 31, 2011 was 6,864 barrels in comparison to 5,696 barrels for the six months ended August 31, 2010.  The increase in production of 1,168 barrels or 20.5% accounted for $121,137 or 38.3% of the revenue increase from the comparative six month period ended August 31, 2010.  A table of our revenues is set forth below:

 

 

 

Six Months

 

Six Months

 

 

Ended

 

Ended

 

 

August 31, 2011

 

August 31, 2010

California - East Slopes Project

 

$                            712,041  

 

$                 396,040

Louisiana - Krotz Springs** 

 

-0- 

 

104,017

Total Revenues

 

$                           712,041   

 

$                500,057

 

**During the six months ended August 31, 2010, the Company received approximately $104,017 in revenue related to the Krotz Springs Field in Louisiana as a one-time adjustment to gas revenue earned in calendar years 2007, 2008 and 2009 due to well production revenue misallocation by the unitized field operator.

 

Operating Expenses.  Total operating expenses for the six months ended August 31, 2011 decreased by $212,985 or 17.4% in comparison to the six months ended August 31, 2010.  Significant decreases of $272,221 or 23.0% in aggregate occurred in exploration and drilling,  DD&A and G&A expenses. However these decreases were partially offset by an increase of $50,912 in production expenses.  The remaining difference in the comparative six month change in total operating expenses was due to a gain of $8,324 on the write-off of an asset retirement obligation for the six months ended August 31, 2010.

 

 

 

 

19


 

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

 

 

 

Six Months

 

Six Months

 

 

Ended

 

Ended

 

 

August 31, 2011

 

August 31, 2010

Production expenses

$

 99,843

$

48,931 

Exploration and drilling

 

55,788

 

144,283 

DD&A

 

154,908

 

237,057 

Gain on write-off of asset retirement obligation

 

-0- 

 

    (8,324)

G&A

 

698,316

 

799,893 

Total operating expenses

$

1,008,855

$

1,221,840 

 

Production expenses for the six months ended August 31, 2011 increased by $50,912 in comparison to the six months ended August 31, 2010.  The increase in production expenses is directly related to the number of wells that were producing during the three months ended August 31, 2011 and 2010 and our percentage of working interest ownership in those wells.  Additionally, for the six months ended August 31, 2010, we received oil processing credits of approximately $31,310 from a third party that were applied against production expenses.  Production costs represented approximately 9.9% of total operating expenses.

 

Exploration and drilling expenses decreased by $88,495 or 61.3% for the six months ended August 31, 2011 in comparison to the six months ended August 31, 2010.  For the six months ended August 31, 2011, we did not drill any dry hole or non-commercial wells.  Exploration and drilling costs represented approximately 5.5% of total operating expenses.

 

DD&A and impairment expenses for the six months ended August 31, 2011 decreased $82,149 or 34.7% in comparison to the six months ended August 31, 2010 primarily due to a larger proven reserve base.  DD&A costs represented approximately 15.4% of total operating expenses.

 

G&A expenses include the salaries of seven employees, including management. Other items included in our G&A 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 with being an operator of oil and gas properties; as well as running a public company.  G&A expense decreased $101,577, or 12.7%, for the six months ended August 31, 2011 in comparison to the six months ended August 31, 2010.  Significant decreases were realized in the following areas: consulting and fundraising ($37,075), shareholder services and meetings ($24,338), travel ($23,750), and advertising and marketing ($26,140).  Management and employee salaries, which were 46.5% of our G&A expense, director fees and stock compensation remained relatively unchanged for the six months ended August 31, 2011 in comparison to the six months ended August 31, 2010.  For the six months ended August 31, 2011 and 2010, we received, as Operator, administrative overhead reimbursement of approximately $32,490 and $54,200, respectively for the East Slopes Project which was used to directly offset certain employee salaries.  We are continuing a program of reducing all of our G&A costs wherever possible.  G&A costs represented approximately 69.2% of total operating expenses.

 

Interest income for the six months ended August 31, 2011 decreased $1,352 or 80.5% compared to the six months ended August 31, 2010 due to lower average cash balances.

 

Interest expense increased $70,781 for the six months ended August 31, 2011 compared to the six months ended August 31, 2010 due to amortization of debt discount and interest on the 12% Subordinated Notes that were sold from January 2010 through March 2010 and amortization of loan origination fees and the fair value of the net profit interest associated with the Well Works Loan.

 

 

 

20


 
 

Liquidity and Capital Resources


Our primary financial resource is our oil reserves base.  Our ability to fund a future capital expenditure program is dependent upon the level of prices we receive from oil sales, the success of our exploration and development program in Kern County, California, and the availability of capital resource financing.  Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the current fiscal year.

 

The Company’s financial statements for the six months ended August 31, 2011 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  We have incurred net losses since entering the oil and gas exploration industry and as of August 31, 2011 have an accumulated deficit of $22,820,837 and working capital deficit of $2,306,117, which raises substantial doubt about our ability to continue as a going concern.

 

For the last four years, we have been working to reposition Daybreak to better meet our corporate goals and objectives by selling our interest in projects that were not contributing to the strategic growth of the Company.  These projects included the Saxet Deep Field in Texas and the East Gilbertown Field in Alabama.  Additionally, we have discontinued participation in the KSU #59 well in the Krotz Springs Field in St. Landry Parish, Louisiana.  These actions have allowed us to improve cash flow and move forward with the current exploration and development program in Kern County, California.

 

We will continue to pursue funding alternatives in the future, including, but not limited to, debt or equity securities, to fund the development of the East Slopes Project.  However no assurance can be given that we will be able to obtain any additional financing on favorable terms, if at all.

 

Changes in our capital resources at August 31, 2011 in comparison to February 28, 2011 are set forth in the table below:

 

 

 

 

 

 

Increase

 

Percentage

 

 

August 31, 2011

 

February 28, 2011

 

(Decrease)

 

Change

Cash

$

 18,441 

$

 57,380 

$

 (38,939)

 

(67.9%)

Current Assets

$

608,739 

$

 593,275 

$

15,464 

 

2.6% 

Total Assets

$

3,198,077 

$

 3,313,180 

$

 (115,103)

 

(3.5%)

Current Liabilities

$

2,914,856 

$

 2,672,124 

$

 242,732 

 

9.1% 

Total Liabilities

$

3,476,738 

$

 3,223,140 

$

 253,598 

 

7.9% 

Working Capital

$

 (2,306,117)

$

 (2,078,849)

$

 (227,268)

 

10.9% 

 

Our working capital deficit increased $227,268 to ($2,306,117) at August 31, 2011 in comparison to ($2,078,849) at February 28, 2011.  The increase in the working capital deficit was principally due to meeting the ongoing financial commitments reflected in our G&A expenses and the continuing reduction of the $1.5 million debt we assumed when we acquired the additional 25% working interest in California in March 2009.  As of August 31, 2011, approximately $317,034 remained to be paid from the default of our original working interest partners in California and is included in the accounts payable balance.       

 

During the six months ended August 31, 2011, we reported an operating loss of approximately $296,814 in comparison to an operating loss of approximately $721,783 for the six months ended August 31, 2010.  This decrease in the operating loss of approximately $424,969 or 58.9% from the comparative six months ended August 31, 2010 was achieved by increasing revenue and lowering operating costs. 

 

Cash Flows


Our sources of funds in the past have included the debt or equity markets and, while we have positive cash flow from our oil and gas properties, we have not yet established positive cash flow on a company-wide basis.  We will need to rely on the debt or equity private or public markets, if available, to fund future operationsOur business model is focused on acquiring exploration and development properties and also

21


 
 

acquiring existing producing properties.  Our ability to generate future revenues and operating cash flow will depend on successful exploration and/or acquisition of oil and gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources, if available. 

 

Our expenditures consist primarily of exploration and drilling costs, production expenses, geological and engineering services and acquiring mineral leases.  Additionally, our expenses also consist of consulting and professional services, employee compensation, legal, accounting, travel and other G&A expenses which we have incurred in order to address necessary organizational activities.

 

The net funds provided by and (used in) each of our operating, investing and financing activities are summarized in the following table:

 

 

 

Six Months Ended
August 31, 2011

 

Six Months Ended
August 31, 2010

 

Increase
(Decrease)

 

Percentage
Change

Net cash provided by operating activities

$

89,319 

$

157,092 

$

(67,773)

 

(43.1%)

Net cash (used in) investing activities

$

(128,258)

$

(417,664)

$

289,406 

 

(69.3%)

Net cash provided by financing activities

$

-0-

$

30,000 

$

(30,000)

 

(100.0%)

 

Cash Flow Provided by Operating Activities

 

Cash flow from operating activities is derived from the production of our oil and gas reserves and changes in the balances of receivables, payables or other non-oil property asset account balances.  For the six months ended August 31, 2011, we had a positive cash flow from operating activities of $89,319, in comparison to a positive cash flow of $157,092 for the six months ended August 31, 2010.  This change of $67,773 was primarily the result of lower DD&A expense for the six months ended August 31, 2011 and the redemption of operator bonds for Alabama and Louisiana during the six months ended August 31, 2010.  Additionally, we increased our oil revenues and reduced our operating expenses during the six months ended August 31, 2011.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

 

Cash Flow (Used in) Investing Activities

 

Cash flow from investing activities is derived from changes in oil and gas property and other assets account balances.  Cash used in investing activities for the six months ended August 31, 2011 was ($128,258), a decrease of $289,406 from the ($417,664) used in investing activities for the six months ended August 31, 2010.  This change was primarily due to the lack of drilling activity that occurred during the six months ended August 31, 2011 in comparison to the six months ended August 31, 2010.

 

Cash Flow Provided by Financing Activities

 

Cash flow from financing activities is derived from changes in equity account balances excluding retained earnings or changes in long-term liability account balances. For the six months ended August 31, 2011 we had a zero balance in cash flow from financing activities in comparison to a cash flow of $30,000 from financing activities for the six months ended August 31, 2010 due to offsetting amounts in proceeds and payments for a loan commitment.  Financing activity for the six months ended August 31, 2010 consisted of funds received through the sale of the Notes. 


Daybreak has ongoing capital commitments to develop all of its oil and gas leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company. 
A major source of capital for Daybreak in the past has been through the sale of debt or equity securities in the private or public markets. The debt or equity markets, if available to us, will continue to be capital sources for Daybreak until sustained positive cash flow has been achieved.  The current uncertainty in the credit and capital markets may restrict our ability to obtain needed capital. 

 

22


 
 

12% Subordinated Notes

 

On March 16, 2010 we closed a private placement of 12% Subordinated Notes (the “Notes”) resulting in total gross proceeds of $595,000.  A total of $250,000 Notes were sold to a related party, the Company’s President and Chief Executive Officer.  The terms and conditions of the related party Note were identical to the terms and conditions of the other participants’ Notes.  The Notes are subject to an annual interest rate of 12%, payable semi-annually, and mature on January 29, 2015.  On the maturity date, the Company may elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days prior to December 31, 2014.  Proceeds from the sale of the notes were used to meet operating expenses and fund a portion of our development drilling program in Kern County, California.  This offering of securities was made pursuant to a private placement held under Regulation D promulgated under the Securities Act of 1933, as amended.

 

One-Year Note Payable

 

On September 17, 2010, we exercised a preferential right to acquire an additional 16.67% working interest in our East Slopes Project from another working interest owner.  We financed the additional working interest purchase by issuing, to a third party, a one-year convertible secured promissory note for the principal amount of $750,000 (the “Well Works Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing.  The Well Works Loan may be extended subject to closing the Three-Year Note.  However, there can be no assurance the third party will not demand payment of the full amount due.

 

We also issued 250,000 shares of the Company’s Common Stock to the third party as a loan origination fee.  The fair value of these shares amounted to $23,750 which was deferred and fully amortized over the term of the Loan.  Amortization expense for the six months ended August 31, 2011 amounted to $11,875. The loan origination fees were fully amortized as of August 31, 2011.

 

The Well Works Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in our East Slopes Project.  Furthermore, as a condition precedent to the September 2010 Loan, we entered into a Technical and Consulting Services Agreement with the third party, whereby we will provide operating, engineering and technical consulting to the third party for a one-year period for the purpose of evaluating 22 wells in Hutchinson County, Texas for the third party. 

 

As additional consideration for the Well Works Loan we executed an Assignment of Net Profits Interest in favor of the third party, whereby we assigned two percent of the net profits realized by us on our leases in the East Slopes Project.  The fair value of the two percent net profits interest was determined to be $60,210 and has been recognized as a discount to the debt. Amortization expense for the six months ended August 31, 2011 amounted to $30,105. The debt discount was fully amortized as of August 31, 2011.

 

Future Financing Commitment - Three-Year Note

 

On June 21, 2011, the Company announced that it had received a funding commitment for a Three-Year Note from a third party with  a term of three years and an interest rate of 6% per annum.  Also, in accordance with the terms of the commitment, the Company will make monthly payments of interest on the Three-Year Note, with the entire principal balance due at the end of the term.  The Three-Year Note will be secured by the Company’s leases at its East Slopes Project.  The Company has deposited $200,000 in escrow for purposes of facilitating the commitment.  While there can be no assurance, the Three-Year Note is expected to close after completion of definitive documentation, due diligence and customary closing conditions.  Proceeds of the Three-Year Note will be used to expand the development of the Company’s East Slopes Project as well as repay the $750,000 principal amount under its existing Well Works Loan as referenced above, and for other general corporate purposes.

 

23


 
 

Changes in Financial Condition and Results of Operations

 

Cash Balance

 

We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations, investments and capital resource funding.  Our cash balances were $18,441 and $57,380 as of August 31, 2011 and February 28, 2011, respectively.  The decrease of approximately $38,939 was due to meeting ongoing financial commitments as a part of our G&A expenses and continuing reduction of outstanding balances associated with the default of certain original partners default in our East Slopes Project.

 

Operating Loss

 

For the six months ended August 31, 2011, we reported an operating loss of approximately $296,814 in comparison to an operating loss of approximately $721,783 for the six months ended August 31, 2010.  This reduction in the operating loss of approximately $424,969 or 58.9% from the operating loss for the six months ended August 31, 2010 was achieved by increasing revenue and lowering operating costs.  Revenue increased due to both an increase in production and an increase in the sales price of oil.  We increased production by 1,168 barrels of oil or 20.5% through sales from 11 producing wells in comparison to sales from nine producing wells in the six months ended August 31, 2010.  The average price of oil increased by $34.21 or 49.2% to $103.74 per barrel for the six months ended August 31, 2011 in comparison to the six months ended August 31, 2010.

 

Operating expenses decreased by 17.4% or $212,985 to $1,008,855 for the six months ended August 31, 2011 in comparison to $1,221,840 for the six months ended August 31, 2010.  Exploration and drilling, DD&A and G&A expenses experienced the greatest reductions with a combined reduction of 23.0% or $272,221.  This reduction was offset by an increase of $50,912 in production expenses for the six months ended August 31, 2011.

 

Net Loss

 

Since entering the oil and gas exploration industry, we have incurred recurring losses with periodic negative cash flow and have depended on external financing and the sale of oil and gas assets to sustain our operations.  A net loss of $413,928 was reported for the six months ended August 31, 2011 in comparison to a net loss of $755,807 for the six months ended August 31, 2010.  The decrease in net loss of $341,879 or 45.2% for the six months ended August 31, 2011 was primarily due to an increase of $211,984 in revenue generated from oil sales; and a reduction of $212,985 in operating expenses in comparison to the six months ended August 31, 2010.

 

Restricted Stock and Restricted Stock Unit Plan

 

On April 6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted 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.

 

 

24


 
 

For the six months ended August 31, 2011 an aggregate 912,499 shares vested and 3,830 shares were returned to the 2009 Plan.  At August 31, 2011, a total of 1,003,830 Common Stock shares remained available for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan activity is set forth in the table below:

 

Grant

Date

 

Shares
Awarded

 

Vesting
Period

 

Shares
Vested

 

Shares
Returned

 

Shares
Outstanding
(Unvested)

4/7/2009

 

1,900,000

 

3 Years

 

1,266,665

 

-0-

 

633,335

7/16/2009

 

25,000

 

3 Years

 

16,665

 

-0-

 

8,335

7/16/2009

 

625,000

 

4 Years

 

312,500

 

1,915 

 

312,500

7/22/2010

 

25,000

 

3 Years

 

8,330

 

-0-

 

16,670

7/22/2010

 

425,000

 

4 Years

 

106,250

 

1,915 

 

318,750

 

 

3,000,000

 

 

 

1,710,410

 

3,830 

 

1,289,590

 

For the six months ended August 31, 2011, the Company recognized compensation expense related to the above restricted stock grants of $45,610.  Unamortized compensation expense amounted to $87,688 as of August 31, 2011.

 

Summary

 

We are continuing to execute the Company’s business plan of developing Daybreak’s acreage position in Kern County, California.  The Company will continue to focus our efforts on drilling development wells, as well as drilling several exploration wells over the next twelve months; which, coupled with the completion of our production and operating infrastructure will increase our net cash flow. 

 

We will need additional financing in the future for our planned exploration and development activities.  We may seek financing through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these instruments which could result in dilution to existing security holders and increased debt and leverage. 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.

 

Critical Accounting Policies

 

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2011.

 

Off-Balance Sheet Arrangements

 

As of August 31, 2011, we did not have any off-balance sheet arrangements or relationships with unconsolidated entities or financial partners that have been, or are reasonably likely to have, a material effect on our financial position or results of operations.

 

 

 

 

 

 

 

25


 
 
ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

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

 

 

ITEM 4.  CONTROLS AND PROCEDURES

 

Management’s Evaluation of Disclosure Controls and Procedures

 

As of the end of the reporting period, August 31, 2011, an evaluation was conducted by Daybreak management, including our President and Chief Executive Officer, who is also serving as our interim principal finance and accounting officer, as to the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Exchange Act.  Such disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods specified by the SEC rules and forms.  Additionally, it is vital that such information is accumulated and communicated to our management, including our President and Chief Executive Officer, in a manner to allow timely decisions regarding required disclosures.  Based on that evaluation, our management concluded that our disclosure controls were effective as of August 31, 2011.

 

Changes in Internal Control over Financial Reporting

 

There have not been any changes in the Company’s internal control over financial reporting during the six months ended August 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Limitations

 

Our management does not expect that our disclosure controls or internal controls over financial reporting will prevent all errors or all instances of fraud.  A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met.  Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.

 

Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected.  These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.  Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls.  The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and any design may not succeed in achieving its stated goals under all potential future conditions.

 

Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.  Because of the inherent limitation of a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

 

 

26


 
 

PART II

OTHER INFORMATION

 

ITEM 1.  LEGAL PROCEEDINGS

 

None.

 

 

ITEM 1A.  RISK FACTORS

 

The following risk factor updates the Risk Factors included in our Annual Report on Form 10-K for the fiscal year ended February 28, 2011. Except as set forth below, there have been no material changes to the risks previously disclosed in our “Risk Factors” described in Part 1, Item 1A, of the Annual report on Form 10-K for the year ended February 28, 2011.

 

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

 

Our outstanding indebtedness at August 31, 2011 was approximately $3,510,000, which was comprised of a $750,000 Secured Promissory Note due September 17, 2011 (“Wells Works Loan”), the $595,000 principal on the 12% Subordinated Notes (“Notes”) and $2,165,000 in accounts payable.  The level of indebtedness 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 will reduce the amount of funds we will have available to finance our operations.  This lack of funds could limit our flexibility in 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.  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 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.

 

The Well Works Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in the Company’s East Slopes Project.  If the Company were to default on this Loan, the Company would lose two of its primary leases.

 

 

 

 

 

 

 

 

 

27


 
 

 

ITEM 6.   EXHIBITS

 

The following Exhibits are filed as part of the report:

 

Exhibit

Number  Description

 

10.1(1)     Promissory Note, dated June 20, 2011, by and between Daybreak Oil and Gas, Inc. and James F. Westmoreland.

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

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

 

(1)     Filed herewith

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

28


 
 

SIGNATURES

 

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

 

                                                                                 DAYBREAK OIL AND GAS, INC.

 

                                                                                 By: /s/ JAMES F. WESTMORELAND

                                                                                            James F. Westmoreland, its

                                                                                            President, Chief Executive Officer and interim

                                                                                            principal finance and accounting officer

                                                                                            (Principal Executive Officer, Principal Financial        
                                                                                            Officer and Principal Accounting Officer)

 

                                                                     Date:  October 14, 2011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

29