PINX:BNXR Quarterly Report 10-Q Filing - 7/31/2012

Effective Date 7/31/2012

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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 July 31, 2012

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

For the transition period from ________________ to _______________

333-102441
 (Commission file number)

BRINX RESOURCES LTD.
(Exact name of registrant as specified in its charter)

Nevada
(State or other jurisdiction
of incorporation or organization)
 
98-0388682
(IRS Employer
Identification No.)

c/o Dill Dill Carr Stonbraker & Hutchings, P.C., 455 Sherman Street, Suite 300, Denver, Colorado 80203
(Address of principal executive offices)                                (Zip Code)

(505) 250-9992
(Registrant’s telephone number, including area code)

820 Piedra Vista Road NE, Albuquerque, NM 87123
 (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.
[x] 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
[x] 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 [  ]
Smaller reporting company [x]

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:  24,629,832 shares of Common Stock, $0.001 par value, as of September 14, 2012

 
 

 


BRINX RESOURCES LTD.
INDEX

   
Page
PART I.
FINANCIAL INFORMATION
 
     
Item 1.
Financial Statements
3
     
 
Balance Sheets
July 31, 2012 (unaudited) and October 31, 2011
4
     
 
Statements of Operations and Comprehensive Income (unaudited)
Three and Nine months Ended July 31, 2012 and 2011
5
     
 
Statements of Cash Flows (unaudited)
Nine months Ended July 31, 2012 and 2011
6
     
 
Notes to Financial Statements (unaudited)
7
     
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
18
     
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 2.
Unregistered Sales of Equity Securities and Use of Proceeds
27
     
Item 3.
Defaults Upon Senior Securities
27
     
Item 4.
Mine Safety Disclosures
27
     
Item 5.
Other Information
27
     
Item 6.
Exhibits
27
     
Signatures
 
29


 
2

 

Part I.      FINANCIAL INFORMATION

Item 1.            Financial Statements

 
3

 

 BRINX RESOURCES LTD.
 
 BALANCE SHEETS
 
             
   
JULY 31,
   
OCTOBER 31,
 
   
2012
   
2011
 
 ASSETS
 
(Unaudited)
   
(Audited)
 
             
 Current assets
           
 Cash and cash equivalents
  $ 344,551     $ 401,047  
 Investment - Certificate of deposit
    400,000       400,000  
 Marketable securities
    88,000       208,000  
 Accounts receivable
    53,999       329,748  
 Prepaid expenses and deposit
    40,810       37,254  
                 
 Total current assets
    927,360       1,376,049  
                 
 Undeveloped mineral interests, at cost
    1,981       1,981  
                 
 Oil and gas interests, full cost method of accounting,
               
net of accumulated depletion
    2,175,592       2,074,900  
                 
 Total assets
  $ 3,104,933     $ 3,452,930  
                 
 LIABILITIES AND STOCKHOLDERS' EQUITY
               
                 
 Current liabilities
               
 Accounts payable and accrued liabilities
  $ 19,340     $ 10,971  
                 
 Total current liabilities
    19,340       10,971  
                 
 Asset retirement obligations
    28,705       26,335  
                 
 Total liabilities
    48,045       37,306  
                 
                 
 Stockholders' equity
               
Preferred stock - $0.001 par value; authorized - 1,000,000 shares
         
 Issued and outstanding - 500,001 shares
    500       -  
                 
Common stock - $0.001 par value; authorized - 100,000,000 shares
         
 Issued and outstanding - 24,629,832 shares
    24,630       24,630  
                 
 Capital in excess of par value
    2,868,057       2,868,057  
                 
 Accumulative other comprehensive loss
    (184,000 )     (64,000 )
                 
 Retained earnings
    347,701       586,937  
                 
 Total stockholders' equity
    3,056,888       3,415,624  
                 
 Total liabilities and stockholders' equity
  $ 3,104,933     $ 3,452,930  
 
The accompanying notes are an integral part of these financial statements.

 
4

 

 BRINX RESOURCES LTD.
 
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME/(LOSS)
 
 (UNAUDITED)
 
                         
   
FOR THE THREE MONTHS
   
FOR THE NINE MONTHS
 
   
PERIOD ENDED
   
PERIOD ENDED
 
   
JULY 31,
   
JULY 31,
 
   
2012
   
2011
   
2012
   
2011
 
                         
 REVENUES
                       
Natural gas and oil sales
  $ 75,811     $ 291,527     $ 422,570     $ 1,062,679  
                                 
 DIRECT COSTS
                               
 Production costs
    33,848       40,385       87,023       162,262  
 Depletion and accretion
    36,710       79,388       142,795       285,481  
 General and administrative
    131,611       223,766       451,999       595,677  
 Total Expenses
    (202,169 )     (343,539 )     (681,817 )     (1,043,420 )
                                 
 OPERATING INCOME/(LOSS)
    (126,358 )     (52,012 )     (259,247 )     19,259  
                                 
 OTHER INCOME
                               
 Interest income
    202       350       11       900  
 Other Income
    -       -       20,000       -  
                                 
 NET INCOME/(LOSS) BEFORE COMPREHENSIVE LOSS
    (126,156 )     (51,662 )     (239,236 )     20,159  
                                 
 COMPREHENSIVE INCOME/(LOSS)
                               
 Unrealized (loss) on held for sale marketable security
    (20,000 )     -       (120,000 )     -  
                                 
 COMPREHENSIVE INCOME/(LOSS) FOR THE PERIODS
  $ (146,156 )   $ (51,662 )   $ (359,236 )   $ 20,159  
                                 
 Net Income/(Loss) Per Common Share
                               
                                 
  - Basic
  $ (0.005 )   $ (0.002 )   $ (0.010 )   $ 0.001  
  - Diluted
  $ (0.005 )   $ (0.002 )   $ (0.010 )   $ 0.001  
                                 
 Weighted average number of common shares outstanding
                               
                                 
  - Basic
    24,629,832       24,629,832       24,629,832       24,629,832  
  - Diluted
    24,629,832       24,629,832       24,629,832       24,749,314  
 
The accompanying notes are an integral part of these financial statements.

 
5

 

 
 BRINX RESOURCES LTD.
           
 STATEMENTS OF CASH FLOWS
           
 (UNAUDITED)
           
             
    FOR THE NINE MONTHS  
   
PERIOD ENDED
 
   
JULY 31,
 
   
2012
   
2011
 
             
 CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES
           
             
 Net Income / (loss)
  $ (239,236 )   $ 20,159  
                 
 Adjustments to reconcile net income to net cash provided by
               
     operating activities:
               
 Depletion and accretion
    142,795       285,481  
 Changes in working capital:
               
 Decrease / (Increase) in accounts receivable
    76,249       (36,469 )
 Decrease / (Increase) in prepaid expenses and deposit
    (3,556 )     111,850  
 Increase / (Decrease) in accounts payable and accrued liabilities
    8,369       (1,199 )
                 
 Net cash provided by /(used in) operating activities
    (15,379 )     379,822  
                 
 CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES
               
                 
 Redemption of Certificate of deposit
    -       400,000  
 Sale proceeds of natural gas and oil working interests
    200,000       -  
 Payments on oil and gas interests
    (241,117 )     (486,668 )
                 
 Net cash (used in) investing activities
    (41,117 )     (86,668 )
                 
 CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES
               
                 
 Net cash (used in) financing activities
    -       -  
                 
 Net increase (decrease) in cash
    (56,496 )     293,154  
                 
 Cash and cash equivalents, beginning of periods
    401,047       21,029  
                 
 Cash and cash equivalents, end of periods
  $ 344,551     $ 314,183  
                 
                 
 SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
               
                 
 Assets retirement costs incurred
  $ (2,370 )   $ (3,240 )
                 
Investment in natural oil and gas working interests included in
  $ -     $ 28,640  
 accounts payable
               
 
The accompanying notes are an integral part of these financial statements.

 
6

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

 

1.  
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Brinx Resources Ltd. (the “Company”) was incorporated under the laws of the State of Nevada on December 23, 1998, and issued its initial common stock in February 2001.  The Company holds an undeveloped mineral interest located in New Mexico and holds oil and gas interests located in Oklahoma and California.  In 2006, the Company commenced oil and gas production and started earning revenues.

The accompanying financial statements of the Company are unaudited.  In the opinion of management, the financial statements include all adjustments, consisting only of normal recurring adjustments, necessary for fair presentation.  The results of operations for the nine-month period ended July 31, 2012 are not necessarily indicative of the operating results for the entire year.  These financial statements should be read in conjunction with the financial statements and notes included in the Company’s Form 10-K for the year ended October 31, 2011.

USE OF ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs.  At this time, management knows of no substantial costs from environmental accidents or events for which the Company may be currently liable.  In addition, the Company’s oil and gas business makes it vulnerable to changes in prices of crude oil and natural gas.  Such prices have been volatile in the past and can be expected to be volatile in the future.  By definition, proved reserves are based on current oil and gas prices and estimated reserves.  Price declines reduce the estimated quantity of proved reserves and increase annual depletion expense (which is based on proved reserves).

OIL AND GAS INTERESTS

The Company utilizes the full cost method of accounting for oil and gas activities.  Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration; are capitalized within a cost center.  No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas interests unless the sale represents a significant portion of oil and gas interests and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center.  Depreciation, depletion and amortization of oil and gas interests is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production.  Amortizable costs include estimates of future development costs of proved undeveloped reserves.

Capitalized costs of oil and gas interests may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved interests.  Should capitalized costs exceed this ceiling, an impairment is recognized.  The present value of estimated future net cash flows is computed by applying average prices, in the preceding twelve months, of oil and gas to estimated future production of proved oil and gas reserves as of year end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.

 
7

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)



1.  
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

REVENUE RECOGNITION

Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer.  Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred.  Revenues from the production of oil and natural gas properties in which the Company shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period.  Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests.  The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field.  At July 31, 2012 and 2011, the Company had no overproduced imbalances.

ACCOUNTS RECEIVABLE

Accounts receivable are carried at net receivable amounts less an estimate for doubtful accounts.  Management determines the allowance for doubtful accounts by regularly evaluating individual customer receivables and considering a customer’s financial condition, credit history, and current economic conditions.  Trade receivables are written off when deemed uncollectible.  Recoveries of receivables previously written off are recorded when received.

IMPAIRMENT OF LONG-LIVED ASSETS

The Company has adopted FASB ASC 360 “Accounting  for the  Impairment  or Disposal of Long-Lived  Assets,” which requires that long-lived  assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Oil and gas interests accounted for under the full cost method are subject to a ceiling test, described above, and are excluded from this requirement.

ASSET RETIREMENT OBLIGATIONS

The Company follows FASB ASC 410-20 "Accounting for Asset Retirement Obligations," that addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.

FASB ASC 410-20 requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset's carrying amount.

Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset.  The Company's asset retirement obligations are related to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and gas exploration activities.

INCOME / (LOSS) PER SHARE

Basic income/(loss) per share is computed based on the weighted average number of common shares outstanding during each period.  The computation of diluted earnings per share assumes the conversion, exercise or contingent issuance of securities only when such conversion, exercise or issuance would have a dilutive effect on income/(loss) per share.  The dilutive effect of outstanding options was nil as of July 31, 2012 and 2011.  500,000 options were included in the earnings per share calculation for the nine-month period ended July 31, 2011.  The table below presents the computation of basic and diluted earnings per share for the nine-month periods ended July 31, 2012 and 2011:
 

 
8

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

 
1.  
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

INCOME / (LOSS) PER SHARE (continued)

    July 31, 2012   July 31, 2011   
Basic earnings per share computation:          
 
Income/(Loss) from continuing operations
  $ (239,236 )   $ 20,159  
Basic shares outstanding
    24,629,832       24,629,832  
Basic earnings per share
  $ (0.010 )   $ 0.001  
Diluted earnings per share computation:                
Income (Loss) from continuing operations
  $ (239,236 )   $ 20,159  
Basic shares outstanding
    24,629,832       24,629,832  
Incremental shares from assumed conversions:
               
    Stock options
    -       119,482  
    Warrants
    -       -  
Diluted shares outstanding
    24,629,832       24,749,314  
Diluted earnings per share   $ (0.010 )   $ 0.001  


INCOME TAXES

Deferred tax assets and liabilities are recognized for temporary differences between the financial reporting and tax bases of the firm’s assets and liabilities. Valuation allowances are established to reduce deferred tax assets to the amount that more likely than not will be realized. The firm’s tax assets and liabilities, if any, are presented as a component of “Other assets” and “Other liabilities and accrued expenses,” respectively, in the balance sheet.  Tax provisions are computed in accordance with FASB ASC 740, “Accounting for Income Taxes.”

The Company applies the provisions of FASB ASC 740-10 “Accounting for Uncertainty in Income Taxes — an Interpretation.” A tax position can be recognized in the financial statements only when it is more likely than not that the position will be sustained upon examination by the relevant taxing authority based on the technical merits of the position. A position that meets this standard is measured at the largest amount of benefit that will more likely than not be realized upon settlement. A liability is established for differences between positions taken in a tax return and amounts recognized in the financial statements. FASB ASC 740-10 also provides guidance on de-recognition, classification, interim period accounting and accounting for interest and penalties.

CASH EQUIVALENTS
 
For purposes of reporting cash flows, the Company considers as cash equivalents all highly liquid investments with a maturity of three months or less at the time of purchase.  On occasion, the Company may have cash balances in excess of federally insured amounts.

MARKETABLE SECURITIES AND INVESTMENTS
 
All equity investments are classified as available for sale and any subsequent changes in the fair value are recorded in comprehensive income. If in the opinion of management there has been a decline in the value of the investment below the carrying value that is considered to be other than temporary, the valuation adjustment is recorded in net earnings in the period of determination.  The fair value of investments is based on the quoted market price on the closing date of the period.


 
9

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)



1.  
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

FAIR VALUE

The Company adopted FASB ASC 820-10-50, “Fair Value Measurements.” This guidance defines fair value, establishes a three-level valuation hierarchy for disclosures of fair value measurement and enhances disclosure requirements for fair value measures.  The three levels are defined as follows:

Level 1 inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
 
Level 3 inputs to valuation methodology are unobservable and significant to the fair measurement.

The carrying amounts reported in the balance sheets for cash and cash equivalents, investments in certificates of deposit, receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of fair value because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest. Marketable securities are valued using Level 1 inputs.

CONCENTRATION OF CREDIT RISK

Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents, investments in certificates of deposit and accounts receivable.  The Company maintains cash at one financial institution.  The Company periodically evaluates the credit worthiness of financial institutions, and maintains cash accounts only in large high quality financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts.  The Company believes credit risk associated with cash and cash equivalents to be minimal.

The Company has recorded trade accounts receivable from business operations. Management periodically evaluates the collectability of trade receivables and believes that the Company’s receivables are fully collectable and that the risk of loss is minimal.

EQUITY BASED COMPENSATION

The Company adopted the fair value recognition provisions of FASB ASC 718 “Share Based Payment.”

RECENT ACCOUNTING PRONOUNCEMENTS

In June 2011, authoritative guidance was issued on the presentation of comprehensive income.  Specifically, the guidance allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. The new guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This guidance has been applied retrospectively and will be effective for our interim and annual reporting periods beginning after December 15, 2011.

The changes in presentation of comprehensive income had no effect on the calculation of net income, comprehensive income or earnings per share.

 
10

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

 

2.  
MARKETABLE SECURITIES

In August 2011, the Company received 800,000 common shares in Lexaria Corp. on the sale of its oil and natural gas interests in Mississippi, with a value of $0.34 per share.  The value of the shares at July 31, 2012 was $0.11 per share, as compared to $0.26 per share as at October 31, 2011, giving rise to an unrealized loss of $120,000 for the nine-month period ended July 31, 2012.
 

3.  
ACCOUNTS RECEIVABLE

Accounts receivable consists of revenues receivable from the operators of the oil and gas projects for the sale of oil and gas by the operators on the Company’s behalf and are carried at net receivable amounts less an estimate for doubtful accounts.  Management considers all accounts receivable to be fully collectible at July 31, 2012 and October 31, 2011.  Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.
 
 
   
July 31, 2012
   
October 31, 2011
 
Accounts receivable
  $ 53,999     $ 329,748  
Less: allowance for doubtful account
    -       -  
    $ 53,999     $ 329,748  

4.  
OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:
 
      July 31, 2012       October 31, 2011  
2008-3 Drilling Program, Oklahoma
  $ 309,152     $ 302,361  
2009-2 Drilling Program, Oklahoma
    114,420       114,420  
2009-3 Drilling Program, Oklahoma
    335,612       300,080  
2009-4 Drilling Program, Oklahoma
    190,182       190,146  
2010-1 Drilling Program, Oklahoma
    253,967       253,855  
Washita Bend 3D, Oklahoma
    526,926       482,882  
Double T Ranch #1 SWDW, Oklahoma
    29,312       --  
Kings City Prospect, California
    388,837       263,561  
Three Sands Project, Oklahoma
    1,451,557       1,451,543  
South Wayne Prospect, Oklahoma
    61,085       61,085  
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi
    (222,123 )     (222,123 )
Asset retirement cost
    4,534       4,534  
Less:  Accumulated depletion and impairment
    (1,267,869 )     (1,127,444 )
    $ 2,175,592     $ 2,074,900  
 
2008-3 Drilling Program, Oklahoma
 
On January 12, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The Before Casing Point Interest (“BCP”) shall be 6.25% and the After Casing Point Interest (“ACP”) shall be 5.00%.  During January to July 2009, the Company expended a $213,925 in addition to $18,850 that was spent in previous periods.  The well, Wigley#1-11, was abandoned during March 2009.  The cost and its buy-in cost total of $33,423 were moved to the proved properties.  Selman#1-21 and Bagwell#1-20 started producing during May 2009,
 

 
11

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

 
4.  
OIL AND GAS INTERESTS (continued)

2008-3 Drilling Program, Oklahoma (continued)

the cost and its buy-in cost total of $67,632 for Selman#1-21 and $65,209 for Bagwell#1-20 were moved to the proved properties. Ard#1-36 started producing during June 2009 and the cost and its buy-in cost total of $42,647 was moved to the proved properties.  Selman#2-21 started producing during July 2009 and was abandoned on April 20, 2010; the cost and its buy-in cost total of $55,940 were moved to the proved properties pool.  The total cost of the 2008-3 Drilling Program as at July 31, 2012 was $309,152.  The interests are located in Garvin County, Oklahoma.

2009-2 Drilling Program, Oklahoma

On June 19, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,562.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The well,  James#1-18, was abandoned on September 21, 2009.  The cost and its buy-in cost total of $41,934 were moved to the proved properties.  Little Chief#1-3 was abandoned on November 17, 2009; the cost and its buy-in cost total of $35,528 were moved to the proved properties.  J.C. Carlton#1-31 was abandoned on April 30, 2010; the cost and its buy-in cost total of $36,957 were moved to the proved properties.  As at July 31, 2012, the total cost of the 2009-2 Drilling Program was $114,420.  The interests are located in Garvin County, Oklahoma.

2009-3 Drilling Program, Oklahoma

On August 12, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  Jackson#1-18 started producing during January 2010; an amount of $66,106 which included the buy-in cost was moved to the proved property pool.  Miss Gracie#1-18 started producing during March 2010; an amount of $69,056 which included its buy-in cost was moved to the proved property pool.  Brewer#1-20 was abandoned on June 2, 2010; the cost and its buy-in cost total of $65,984 were moved to the proved properties.  Waunice#1-36 started producing during June 2010 and was abandoned on September 23, 2010; an amount of $42,838 which included its buy-in cost was moved to the proved property pool.

As at July 31, 2012, the total cost of the 2009-3 Drilling Program was $335,612.  The interests are located in Garvin County, Oklahoma.

2009-4 Drilling Program, Oklahoma

On December 19, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-4 Drilling Program for a total buy-in cost of $13,482.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  Dennis#1-8 started producing during May 2010; an amount of $89,726 which included the buy-in cost was moved to the proved property pool, it was abandoned on September 27, 2010.  Dennis#2-8 was abandoned on November 17, 2010; an amount of $34,341 which included the buy-in cost was moved to the proved property pool.  Murray Trust#3-19 was abandoned on December 13, 2010; an amount of $13,168 which included the buy-in cost was moved to the proved property pool.  Murray Trust#2-19 started producing during November 2010; an amount of $52,910 which included the buy-in cost was moved to the proved property pool.   As at July 31, 2012, the total cost of the 2009-4 Drilling Program was $190,182.  The interests are located in Garvin County, Oklahoma.

 
12

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)


 
4.  
OIL AND GAS INTERESTS (continued)

2010-1 Drilling Program, Oklahoma

On April 23, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,163.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  Julie#1-14 was abandoned on October 2, 2010; the cost and its buy-in cost total of $48,938 were moved to the proved properties.  Jack#1-13 started producing during November 2010; an amount of $74,144 which included the buy-in cost was moved to the proved property pool.  Miss Jenny started producing during December 2010; an amount of $68,620 which included the buy-in cost was moved to the proved property pool.  As at July 31, 2012, the total cost of the 2010-1 Drilling Program was $253,967.  The interests are located in Garvin County, Oklahoma.

Washita Bend 3D Exploration Project, Oklahoma

On March 1, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s Washita Bend 3D Exploration Project for a buy-in cost of $46,250.  The BCP Interest shall be 5.625% and the ACP Interest shall be 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  As at July 31, 2012, the total costs, including seismic costs was $526,926.

Double T Ranch#1 SWDW, Oklahoma

On July 17, 2012, the Company acquired a 3.00% working interest in the drilling, completion and operations of the Double T Ranch#1 SWDW located in Garvin County from Ranken Energy Corporation. As at July 31, 2012, the cost of the Double T Ranch#1 SWDW was $29,312.

Kings City Prospect, California

A Farmout agreement was made effective on May 25, 2009 between the Company and Sunset Exploration, Inc., to explore for oil and natural gas on 10,000 acres located in west central California.  The Company paid $100,000 (50% pro rata share of $200,000)  to earn a 20% working interest in project by funding a maximum of 50% of a $200,000 in a geophysical survey composed of gravity and seismic surveys and carry Sunset exploration for 33.33% of dry hole cost of the first well.  Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each parties working interest.  The total cost of the King City prospect as at July 31, 2012 was $388,837.

Three Sands Project, Oklahoma

On October 6, 2005, the Company acquired a 40% working interest in Vector Exploration Inc’s Three Sands Project for a total buy-in cost of $88,000 plus dry hole costs.  For the year ended October 31, 2006, the Company expended $530,081 in exploration costs.  In June 2007, the Company acquired a 40% working interest in William #4-10 well for a total cost of $285,196 and paid a further $17,000 in costs relating to the well.  On March 19, 2008, the Company participated in the KC 80#1-11 well and paid $75,000 for the prepaid drilling costs.  During March and April 2008, the Company expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 during May to July 2008 for the KC 80#1-11 well.  The total cost of the Three Sands Project as at July 31, 2012 was $1,451,557.  The interests are located in Oklahoma.


 
13

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)


 
4.  
OIL AND GAS INTERESTS (continued)

South Wayne Prospect, Oklahoma

On March 14, 2010, the Company acquired a 5.00% working interest in McPherson#1-1 well for a payment for leasehold, prospect and geophysical fees of $5,000, and dry hole costs of $32,370.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The interests are located in McClain County, Oklahoma.  The total cost of the South Wayne prospect as at July 31, 2012 was $61,085.

Palmetto Point Project, Mississippi

On August 12, 2011, the Company signed an asset purchase agreement to sell its oil and gas assets in Mississippi for a total of $400,000 and received 800,000 shares of restricted common stock in Lexaria Corp.  These properties consist principally of the Belmont Lake Oil Field and all undeveloped acreage in the Palmetto Point Project.  $200,000 was received on August 12, 2011.  $10,000 per month was paid in November and December 2011 and the balance of $200,000 was paid on January 13, 2012. The disposed reserves represented more than 25% of the total reserves which the Company considered to represent a significant alteration between capitalized costs and proved reserves and hence a loss on the sale was recognized in the Statement of Operations in the amount of $109,299 for the period ended October 31, 2011.

Impairment

Under the full cost method, the Company is subject to a ceiling test.  This ceiling test determines whether there is an impairment to the proved properties.  The impairment amount represents the excess of capitalized costs over the present value, discounted at 10%, of the estimated future net cash flows from the proven oil and gas reserves plus the cost, or estimated fair market value.  There was no impairment cost for the nine-month periods ended July 31, 2012 and 2011, respectively.

Depletion

Under the full cost method, depletion is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production.  Depletion expense recognized was $140,425 and $282,241 for the nine-month periods ended July 31, 2012 and 2011, respectively.

Capitalized Costs

   
July 31, 2012
   
October 31, 2011
 
Proved properties
  $ 2,438,387     $ 2,395,902  
Unproved properties
    1,005,075       806,443  
Total Proved and Unproved properties
    3,443,462       3,202,345  
Accumulated depletion expense
    (1,130,138 )     (989,713 )
Impairment
    (137,732 )     (137,732 )
Net capitalized cost
  $ 2,175,592     $ 2,074,900  


 
14

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)


 
4.  
OIL AND GAS INTERESTS (continued)

Results of Operations

Results of operations for oil and gas producing activities during the nine-month periods ended are as follows:

   
July 31, 2012
   
July 31, 2011
  Revenues
  $ 422,570     $ 1,062,679  
  Production costs
    (87,023 )     (162,262 )
  Depletion and accretion
    (142,795 )     (285,481 )
  Results of operations (excluding corporate overhead)
  $ 192,752     $ 614,936  
 
 
5.  
ASSET RETIREMENT OBLIGATIONS

The Company follows FASB ASC 410-20 “Accounting for Asset Retirement Obligations”  which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  This policy requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred.  As of July 31, 2012 and October 31, 2011, the Company recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with “Accounting for Asset Retirement Obligations.”  The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production.  The Company amortizes the amount added to the oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining life of the respective well.  The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements.  The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.  Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.

The Company amortizes the amount added to oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining useful lives of the respective wells.

The information below reflects the change in the asset retirement obligations during the nine-month period ended July 31, 2012 and the year ended October 31, 2011:

   
July 31, 2012
   
October 31, 2011
 
Balance, beginning of period
  $ 26,335     $ 27,494  
Liabilities assumed
    -       774  
    Revisions     -       (5,232
Accretion expense
    2,370        3,299  
Balance, end of period
  $ 28,705     $ 26,335  


The reclamation obligation relates to the Kodesh, Dye Estate, KC 80, Taylor and William wells at the Three Sands Property; ARD#1-36, Bagwell#1-20, Bagwell#2-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24, Jack#1-13 and Miss Jenny#1-8 wells at Oklahoma Properties, and McPherson#1-1 well at South Wayne Prospect.  The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes in applicable laws and regulations.  Such changes will be recorded in the accounts of the Company as they occur.


 
15

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

 
 
6.
COMMON STOCK

PREFERRED STOCK

On February 10, 2012, the Company issued 500,001 Series A preferred stock at par value.

               STOCK OPTIONS

Although the Company does not have a formal stock option plan, all options granted in the past have been approved by the Board of Directors.
 
 
A summary of the changes in stock options for the nine-month period ended July 31, 2012 is presented below:
   
Options Outstanding
 
         
Weighted Average
 
   
Number of Shares
   
Exercise Price
 
Balance, October 31, 2011
    300,000     $ 0.10  
Expired on November 2, 2011
    (300,000 )     0.10  
 
Balance, July 31, 2012
     -     $ -  


7.
RELATED PARTY TRANSACTIONS

During the nine-month periods ended July 31, 2012 and 2011, the Company entered into the following transactions with related parties:

a)    
The Company paid $30,000 (2011 - $54,000) in management fees and reimbursement of office space of $nil (2011 - $3,600) to the then President of the Company.

b)    
The Company paid $54,000 (2011 - $53,000) to a related entity, for administration services.

c)    
The Company paid $81,500 (2011 - $75,500) in management fees to the director and current President of the Company.

d)    
The Company paid $58,673 (2011 - $57,628) in consulting and accounting fees to the Chief Financial Officer of the Company.
 
 
8.  
MAJOR CUSTOMERS

We collected $318,909 (2011: $654,172) or 75% (2011: 62%) of our revenues from one of our operators during the nine-month period ended July 31, 2012. As of July 31, 2012, $24,567 was due from this operator.
 
9.  
CONTINGENCIES
 
In September 2010, two lawsuits were filed in the District Court of Garvin County in the State of Oklahoma by Harold Hamm (“Hamm”) against certain defendants (“Defendants”) and consolidated together alleging, among other things, that Hamm owns an interest in two oil and gas leases in Garvin County and is entitled to a 50% participatory interest.  The Company was not named as a party in these legal proceedings, but Hamm’s allegations include that he is entitled to a 50% participatory interest in the Joe Murray Farms well drilled as part of the 2009-3 Drilling Program, in which the Company purchased a 6.25% working interest

 
16

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)



9.
CONTINGENCIES (continued)

before casing point and 5.0% working interest after casing point.  The Defendants and the Company believe that there is no merit to Hamm’s allegations.  In connection with these proceedings, the Defendants were ordered in January 2011 to escrow fifty percent (50%) of the revenues generated within the subject area pending the outcome of these proceedings.  For this reason, fifty percent (50%) of the revenues the Company is entitled to that have been generated by production from the Joe Murray Farms well is being escrowed and there is no assurance that the Company will be able to recover these proceeds.  The Company recognized $43,989 in revenue during the nine months ended July 31, 2012 and $119,295 in revenue during the year ended October 31, 2011 from the Joe Murray Farms well and a total of $163,284 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.



 
17

 

Item 2.        Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Overview

We are an independent oil and gas company engaged in exploration, development and production of oil and natural gas. As production of these products continues, they will be sold to purchasers in the immediate area where the products are extracted.

Our original business plan was to proceed with the exploration of the Antelope Pass Project to determine whether there were commercially exploitable reserves of gold located on the property comprising the mineral claims.  Based on the geological report and recommendation prepared by our geological consultant at that time, we completed geological mapping, sampling and assaying in connection with the first phase of a staged exploration program during the fiscal year ended October 31, 2004.  In 2005, we suspended our activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on the Antelope Pass Project during the fiscal years ended October 31, 2011 or 2010 or the nine months ended July 31, 2012.  At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project.
 
Our plan of operations is to continue to participate in drilling programs that produce commercial quantities of oil and gas and drill new exploratory and development wells and re-entries to test the oil and gas productive capabilities of our oil and gas properties.  In addition to the drilling and producing of oil and gas wells, we have expanded and plan to continue to expand into exploration and project acquisition through the participation in new 3-D geophysical surveys and related project acquisitions.
 
Oil and Gas Properties

“Bbl” is defined herein to mean one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

“Mcf” is defined herein to mean one thousand cubic feet of natural gas at standard atmospheric conditions.

“Working interest” is defined herein to mean an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.  The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of mineral royalties.

Note that all daily production amounts disclosed for the individual properties below are gross amounts for such properties and not net to our working interest.  Production totals for each property are presented net to our working interest.

2008-3 Drilling Program, Oklahoma.  On January 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581.  We agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.   From January 2009 to July 2009, we expended $213,925 in addition to $18,850 that was spent in previous periods.  The total cost of the 2008-3 Drilling Program as of July 31, 2012 was $309,152. The interests are located in Garvin County, South Central Oklahoma.

This program is composed of four 3-D seismically defined separate prospects with one exploratory well in three of the prospects and two in the fourth prospect.  Targeted pay zones include the prolific Bromide Sands, Viola Limestone, Deese Sandstone and Layton Sandstone.  One of the wells has very similar geology and structure to the Bromide sands in the Owl Creek field.

Five wells were drilled during 2009.  Production casing was set on four of the five wells and the fifth well was deemed non-commercial and was plugged and abandoned.   Two of the four completed wells are still producing commercial quantities of oil and gas, with one of the wells still flowing naturally and producing most of the oil.  One
 
 
18

 
 
development well was drilled in August of 2011 near the highest producing well in the program.  As of July 31, 2012, the three producing wells in this program have produced a total net production of 782 Bbls of oil and 266 Mcf of natural gas, representing our working interest.

2009-2 Drilling Program, Oklahoma.  On June 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,562.  We agreed to participate in the drilling operations to casing point in the initial test well of each of three prospects.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The interests are located in Garvin County, Oklahoma.  A total of three wells were drilled in this program and targeted pay zones that were the same as in the 2008-3 program.  The zones included the prolific Oil Creek, Bromide Sands, Viola, Deese and Layton Sandstone.  This program is composed of three 3-D seismically defined separate prospects.   All wells were drilled in the last fiscal quarter of 2009.  Two of the wells were deemed non-commercial and were plugged and abandoned.  Production casing was set on one of the three wells and completion efforts have taken place on the third well; however, after testing it was also deemed non-commercial and plugged.  As of July 31, 2012, the total cost of the 2009-2 Drilling Program was $114,420.

2009-3 Drilling Program, Oklahoma. On August 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775.  We agreed to participate in the drilling operations to casing point in the initial test well on each of four prospects.   The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total costs incurred, including drilling costs, as of July 31, 2012 was $335,612.  The interests are located in Garvin County, Oklahoma.  Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands.  This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the four prospects.  All four of the wells have been drilled and production casing has been set on all four.  Two of the wells had successful drill stem tests that flowed oil and gas to the surface.  Electric and radiation logs indicate multiple pay zones in all four wells.

One of the four wells in this program was completed in late January 2010 as a flowing oil and gas well.  The well was flowing naturally at rates between 400 and 500 Bbls of fluid per day with an oil cut of between 50% and 70% oil.  Natural gas was being produced at a rate of over 400 Mcf per day.  The well only produced for a few days before snow and ice storms forced shutting the well in because the produced oil and water could not be hauled away from the location and the storage tanks for these liquids were full.  After conditions improved, the well produced oil and gas until late 2011 and has been plugged and abandoned. During its short production history, the well had cumulative production of over 13,000 Bbls of oil and 21,000 Mcf of natural gas.  The second well that also had a flowing drill stem test was completed in late March 2010 and that well is currently producing oil and natural gas with the use of a pumping unit.  Total net production from the producing well as of July 31, 2012 totaled 582 Bbls of oil and 46 Mcf of natural gas, representing our working interest.

In late June 2010, a successful development well was drilled as an offset to the naturally flowing well that is still producing at a rate of 60 Bbls oil and 7 Mcf of natural gas per day with the aid of a pumping unit.  This development well was completed in early August 2010 and is still producing with the aid of a pumping unit at a rate of 90 Bbls of oil and 12 Mcf of natural gas per day and should add significantly to this program’s future oil and gas production.  Total net production from this producing well as of July 31, 2012 was 167 Bbls of oil and 138 Mcf of natural gas, representing our working interest.

The two remaining wells were completed in late May 2010.  After testing, both wells were deemed to be non-commercial and have been plugged and abandoned.

2009-4 Drilling Program, Oklahoma.  On December 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-4 Drilling Program for a total buy-in cost of $13,482.  We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total costs incurred, including drilling costs, as of July 31, 2012 was $190,182.  The interests are located in Garvin County, Oklahoma. Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands.  This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the two prospects.

Drilling of the first well started in early February 2010 and reached total depth on February 20, 2010.  The second well drilling started in late February 2010 and reached total depth on April 8, 2010.  Both of the wells
 
 
19

 
 
intercepted multiple potential productive horizons and production casing was set.  The lowest horizon in the first well flowed oil and gas on a drill stem test.  Weather was initially a problem with heavy rain causing flooding and other delays but both wells have now been completed.  Both wells were treated for a poor cement bond and only one remained in production.  The one well that could not be successfully treated for the poor cement bond was plugged and abandoned.  Another well is being drilled as a twin to this well.  If it is not successful it will be left unplugged as a possible salt water disposal well.  In early 2012, both wells were plugged and abandoned after producing a few thousand Bbls of oil.

2010-1 Program, Oklahoma. On April 23, 2010, we acquired a 5% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,163.  We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects.   The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total cost incurred, including drilling costs, as of July 31, 2012 was $253,967. The interests are located in Garvin County, Oklahoma.  Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands.  This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the two prospects.

As of late October 2010, all four wells of the four-well program had been drilled.  Three of the wells had production casing set and one well was plugged and abandoned.  The three successful wells intercepted multiple pay zones including the prolific lowest zone.  One well had a flowing drill stem test but the other two wells were not drill stem tested.  All three wells show excellent porosity, permeability, and hydrocarbon shows.  Completion of these wells started in mid-September 2010.  As of July 31, 2012, all three of the wells have been completed in the deepest pay zone with one well producing at a rate of 6 Bbls of oil per day, a second producing at a rate of 11 Bbls of oil and the third was producing at a rate of 190 Bbls of oil per day.  Total net production from these wells as of July 31, 2012 was 1,496 Bbls of oil and 454 Mcf of natural gas, representing our working interest.  As of July 31, 2012, the wells were producing at a combined rate of gross 151 Bbls of oil and gross 46 Mcf of natural gas per day.

South Wayne Prospect, Oklahoma. On March 14, 2010, we acquired a 5% working interest in Okland Oil’s South Wayne prospect for a total buy-in cost of $5,000 and dry hole costs of $32,370.  We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total cost incurred, including drilling costs, as of July 31, 2012 was $61,085.  The well and related leasehold interests are located in McClain County, Oklahoma.  As of October 31, 2010, the well had been drilled and production casing has been set.  The well was perforated in July 2010 and immediately started flowing oil at a rate of 200 Bbls per day.  The flow of oil was slowed and stopped due to a buildup of paraffin.  A pumping unit was placed on the well in late August 2010 and the well is now producing water-free at a rate of 25 Bbls of oil and 19 Mcf of natural gas.  Total net production for the McPherson well as of July 31, 2012 was 178 Bbls of oil and 84 Mcf of natural gas, representing our working interest.  Additional pay zones are located above the currently producing horizon and it is anticipated that these zone will be perforated in the future adding additional production to the well.
 
Washita Bend 3D Exploration Project, Oklahoma.  On March 1, 2010, we agreed to participate with a 5% working interest in a 3-D seismic program managed by Ranken Energy Corporation for a buy-in cost of $46,250.  The Oklahoma 3-D seismic program will cover approximately 135 square miles in a known oil and gas producing area.   An earlier 2-D seismic program over the same area indicated a number of untested structures.  We expect the 3-D program will refine and better define the structures discovered during the earlier program and pinpoint drill locations.  We will participate in the seismic program and the related prospect generation and acquisition phase without any promotion.  The BCP Interest shall be 5.625% and the ACP Interest shall be 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  The total cost, including seismic costs, as of July 31, 2012 was $526,926.
 
Work has commenced on this project.  Shooting and data acquisition started on the Oklahoma 3-D project in late February 2011.  The project is slated to cover approximately 86,350 acres or 135 square miles of which approximately 83,043 acres or 130 square miles have now been permitted.  Weather related delays have intermittently forced postponement of the actual data gathering portion of the project which is now underway.

The project employs state of the art equipment and processing that will help pinpoint drill target and well locations.  Initial testing to determine what sweep frequencies to be used reinforced the fact that the data to be
 
 
20

 
 
acquired will be of high quality compared to surveys performed in the past.  This survey is taking place over an area that was originally shot with 2-D seismic that located a number of anomalies but the data was not of sufficient quality to pinpoint well locations.  In contrast, this 3-D survey is expected to pinpoint these locations, dramatically reducing the risk of drilling dry holes.  A total of 5,148 acres of leases have been acquired thus far and leasing of additional lands is now under way.

As of July 31, 2012, all of the permitted area had been shot and data acquired.  All initial or first run processing data has been completed and interpretation of the data and mapping as well as prospect delineation has started.  Regional structural and porosity mapping for the primary target formations has been completed and numerous prospective structural closure have been defined.  Over 10,000 acres have been targeted for title research with over half of the title search completed.  Leasing on a number of potential prospects is underway and it is anticipated that an up to 10-well exploration program on 10 separate prospects will start as soon as possible.

Three Sands Project

Location and Access.  The Three Sands Project is an oil and gas exploration project located in Noble County, Oklahoma. The property can be reached by Oklahoma State Highway 77 and then accessed by a secondary gravel and dirt road.

Previous Operations and History.  The Three Sands field was drilled on 10-acre spacing in the 1920s and 1930s and was very active in producing over 200 million Bbls of oil and an unknown amount of gas from a six-section (3,800 acres) area.  However, during this period, most wells were abandoned within twenty years as the wells became commercially unviable due to the lack of technology.  In particular, during this period, technology was not available, as it is today, to handle high volumes of water and its subsequent disposal, nor was it capable of drilling in areas where the tightness of rock limited flow.

The primary targets of the Three Sands Project are the Arbuckle, Wilcox and Viola Formations.  These were the deep pay zones first discovered in the field, and, in addition to the oil they produced, large amounts of water were eventually produced forcing the abandonment of the well.  Today the water problem has been overcome with down hole electrical high volume pumps and adequate disposal wells, allowing continued exploration.

Geology of the Three Sands Project.  Geologically, this field is a balded structure in which a combination of structure and erosion has aided in producing the field. Pay zones in the project vary from the Arbuckle to the Pennsylvanian and are productive over a 5,000-foot interval that starts at less than 1,000 feet from the surface.  In a 2004 drill test, more than two-dozen pay zones were encountered (some of which have not been produced).

Costs Including Previous Work.  As of July 31, 2012, we have expended $1,451,557 in connection with the Three Sands Project, including leasing, title, drilling, and casing.

Present Activities.  Drilling of the Kodesh #1 disposal well was completed on October 3, 2005 and drilling of the Kodesh #2 well was completed on October 23, 2005.  Completion and equipping of these wells took place during mid-December 2005 through early January 2006.  The Kodesh #1 is being used for salt water disposal well.  In January 2011, the pump was replaced on the Kodesh #2 well and a new pay zone was perforated and fracture treated, increasing production of oil and natural gas.  As of July 31, 2012, it has produced 979 Mcf of natural gas, representing our working interest.

During January 2007, we re-entered the Dye Estate #1 well.  Production of natural gas from the Dye Estate #1 well commenced in mid-August 2007.  As of July 31, 2012, the Dye Estate #1 well has produced 81 Mcf of natural gas representing our working interest.  As of January 31, 2012, the well has been shut-in as the result of low natural gas prices.  Water from the Dye Estate #1 well is being disposed in the Kodesh #1 disposal well.

We commenced drilling the William #4-10 well in early June 2007, reaching a total depth of 4,810 feet in mid-June 2007.  Electric and radiation logs indicated that the William #4-10 well contained four potential commercial pay zones, the Wilcox Sand, Mississippi Lime, Layton Sand and the Tonkawa Sand.  Completion of the lowest zone, the Wilcox Sand, occurred in mid-August 2007.  Production from the William #4-10 well started in mid-October 2007.  During the first quarter of 2008, we perforated, fracture treated and tested the Mississippi Lime
 
 
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and the lower Layton Sand to increase the production rate of both gas and oil from the William #4-10 well and provide data regarding the potential of these formations for the remainder of the leases on the Three Sands Project.  As of July 31, 2012, the William #4-10 well had produced 9,333 Mcf of gas, representing our working interest.  The well is currently producing natural gas at a rate of 115 Mcf with very little decline of the natural gas production rate over the past year.
 
Drilling commenced on the KC 80 #1-11 well in mid-February 2008 and reached total depth of 4,720 feet by the end of February 2008.  The KC 80 #1-11 has been surveyed with radiation and electrical logs.  The primary target for the well is the upper Mississippian Limestone and Chat Formation. The KC-80 well’s logs indicate significant thickness of Chat and upper Mississippi Limestone with good porosity, permeability, and hydrocarbon shows.

Completion of the KC 80 #1-11 well started in late April 2008.  The lowest pay zone, the Mississippian, was acidized and partially fracture treated.  In early August a similar treatment was given to the Chat zone or the horizon that lies above the lowest pay zone.  As of July 31, 2012, the KC 80 #1-11 well is producing at a rate of 2 Bbls of oil and 30 Mcf of natural gas daily.  As of July 31, 2012, the KC 80 #1-11 has produced 162 Bbls of oil and 2,428 Mcf of natural gas, representing our working interest.

Drilling commenced on the Taylor #1 well on October 7, 2010 and reached a total depth of 4,825 feet on October 14, 2010.  The primary target of the well was the Mississippian Limestone.  The well was fracture treated in mid-December 2010 and production testing will follow.  There was no production from this well prior to mid-December 2010.  The well is currently producing at a rate of 3 Bbls of oil per day and 63 Mcf of gas per day.  Production from this well as of July 31, 2012 totaled 59 Bbls of oil and 3,826 Mcf of natural gas, representing our working interest.

The Three Sands Project lies in an area where there has been considerable recent leasing and drilling activity for horizontal development of the relatively shallow pay zones.  We, together with our partners, will consider farming out the non-producing well bore portions of this prospect for cash and overrides but plan to retain our current producing well bores.  We will continue to focus on our upcoming 3D seismic drilling program in southern Oklahoma.

Double T Ranch#1 SWDW, Oklahoma

On July 17, 2012, we entered into an agreement with Ranken Energy Corporation to acquire a 3.00% working interest in the drilling, completion and operations of the Double T Ranch#1 SWDW located in Garvin County. As at July 31, 2012, the cost of the Double T Ranch#1 SWDW was $29,312.

King City Oil Field

Effective May 25, 2009, we entered into an agreement with Sunset Exploration to explore for oil and gas on 10,000 acres located in west central California.  The agreement calls for us to earn a 20% working interest in the project by funding a maximum of 50% of a $200,000 geophysical survey composed of gravity and seismic surveys and agreeing to carry Sunset Exploration for 33.33% of dry hole cost of the first well.  The total cost of the King City Oil Field as at July 31, 2012 was $388,837.  Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each party’s working interest.  The geophysical surveys have been completed and most have been processed and interpreted.  The initial surveys indicated that several more short geophysical survey lines would improve the interpretation.  These additional lines have been completed and subsequently several stages of reprocessing have been applied to the original data.  In midsummer 2011, permitting of the first drill hole began and the well was started in mid-November 2011.  Production casing was set on November 28, 2011 and is expected to be completed in September 2012.

International Exploration Program

The Company is attempting to expand its property base by locating other resource properties internationally.  Accordingly, we have hired consultants to gather data on properties that may be of interest to us. The consultants on a best efforts basis will attempt to acquire option agreements, lease agreements and/or the
 
 
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outright purchase of oil and/or gas properties internationally.   As of the date of this filing, we have not found a suitable acquisition.

Mineral Interests

Antelope Pass.  In 2005, we suspended our activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on the Antelope Pass Project during the nine-month period ended July 31, 2012 or during the fiscal years ended October 31, 2011 and 2010.  At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project.   All Bureau of Land Management fees and filing have been paid and performed making the claim valid until August 31, 2013.

Results of Operations

Three months ended July 31, 2012 compared to the three months ended July 31, 2011.  We realized revenues of $75,811 during the three months ended July 31, 2012, compared with $291,527 during the three months ended July 31, 2011, a decrease of $215,716, due to a decrease in production and the sale of our Mississippi assets during year ending October 31, 2011, and a decrease in commodity prices.  During the three-month period ended July 31, 2012, 765 Bbls of oil and 5,822Mcf of gas were produced at our oil and gas properties, as compared to 2,655 Bbls of oil and 7,146 Mcf of gas for the three months ended July 31, 2011.  Both sets of amounts represented our working interest.
 
We incurred production costs of $33,848 during the three months ended July 31, 2012, compared with $40,385 during the three months ended July 31, 2011, a decrease of $6,537.  The decrease in our production costs is related to a decrease in production from our producing wells and the sale of our Mississippi assets.  Our production costs for the three months ended July 31, 2012 were 45% of our revenue for that same period, compared to production costs which were 14% of our revenue for the three months ended July 31, 2011.  This increase was due to the costs of reworking of some of our wells.

Our depletion and accretion costs were $36,710 during the three months ended July 31, 2012, compared with $79,388 during the three months ended July 31, 2011, a decrease of $42,678.  The decrease in our depletion costs is related to a decrease in production from our wells.

Our general and administrative costs decreased to $131,611 for the three months ended July 31, 2012, from $223,766 for the three months ended July 31, 2011, a decrease of $92,155.  The decrease is attributable to decreases in investor relations costs and consulting fees.

For the three months ended July 31, 2012, we incurred a net loss of $126,156, compared to a net loss of $51,662 for the three months ended July 31, 2011.  The increase in our net loss was largely attributable to a decrease in revenues for the quarter and the costs associated with re-working some of the wells as noted above.

As a result of our net loss for the quarter, we had retained earnings of $347,701 at July 31, 2012.

Nine months ended July 31, 2012 compared to the nine months ended July 31, 2011.  We realized revenues of $422,570 during the nine months ended July 31, 2012, compared with $1,062,679 during the nine months ended July 31, 2011, a decrease of $640,109, due to a decrease in our oil and gas production.  During the nine-month period ended July 31, 2012, 3,671 Bbls of oil and 17,543 Mcf of gas were produced at our oil and gas properties, as compared to 10,314 Bbls of oil and 17,464 Mcf of gas for the nine months ended July 31, 2011.  The decrease in production was caused by the disposal of our Mississippi assets and a reduction in the production from our producing wells.  Both sets of amounts represented our working interest.
 
We incurred production costs of $87,023 during the nine months ended July 31, 2012, compared with $162,262 during the nine months ended July 31, 2011, a decrease of $75,239.  The decrease in our production costs is related to a decrease in production from our producing wells, resulting from the disposal of our assets in Mississippi.

 
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Our depletion and accretion costs were $142,795 during the nine months ended July 31, 2012, compared with $285,481 during the nine months ended July 31, 2011, a decrease of $142,686.  The decrease in our depletion costs is related to a decrease in production from our wells and the disposal of our assets in Mississippi.

Our general and administrative costs decreased to $451,999 for the nine months ended July 31, 2012, from $595,677 for the nine months ended July 31, 2011.  The decrease of $143,678 is primarily attributable to decreases in costs of investor relations and consulting services.

We received $20,000 in other income during the nine months ended July 31, 2012, compared with $nil during the nine months ended July 31, 2011.  This other income was late payment fees received from Lexaria Corp. in conjunction with the sale of our Mississippi properties.

For the nine months ended July 31, 2012, we incurred a net loss of $239,236, compared to a net income of $20,159 for the nine months ended July 31, 2011.  The loss was largely attributable to the decrease in revenues.

As a result of our net loss for the quarter, we had retained earnings of $347,701 at July 31, 2012.

Liquidity and Capital Resources
 
As of July 31, 2012, we had cash and a certificate of deposit totaling $744,551 and working capital of $908,020, compared to cash and a certificate of deposit totaling $801,047 and working capital of $1,365,078 as of October 31, 2011.  The decrease in working capital is due to a decrease in accounts receivable and marketable securities.  Our accounts receivable decreased to $53,999 at July 31, 2012, compared with $329,748 at October 31, 2011, a decrease of $275,749.  Our marketable securities decreased to $88,000 at July 31, 2012, compared with $208,000 at October 31, 2011, a decrease of $120,000 due to a decrease in value.  Our current liabilities increased to $19,340 at July 31, 2012, compared with $10,971 at October 31, 2011.
 
During the nine months ended July 31, 2012, operating activities used cash of $15,379, as compared to net cash provided of $379,822 for the nine months ended July 31, 2011.  The principal reason for the change was due to the net loss for the period and the decrease in accounts receivable described above.

Investing activities used net cash of $41,117 during the nine months ended July 31, 2012, compared with $86,668 used during the nine months ended July 31, 2011.

Off-Balance Sheet Arrangements

As of July 31, 2012, we did not have any off-balance sheet arrangements.  

Critical Accounting Policies

Oil and Gas Interests. We utilize the full cost method of accounting for oil and gas activities.  Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center.  No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas interests unless the sale represents a significant portion of oil and gas interests and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center.  Depreciation, depletion and amortization of oil and gas interests are computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production.  Amortizable costs include estimates of future development costs of proved undeveloped reserves.
 
Capitalized costs of oil and gas interests may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved interests.  Should capitalized costs exceed this ceiling, an impairment is recognized.  The present value of estimated future net cash flows is computed by applying a twelve-month average of  month-end prices of oil and gas to estimated future production of proved oil and gas reserves as of year end, less
 
 
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estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.
 
Asset Retirement Obligations. We follow FASB ASC 410-20 “Accounting for Asset Retirement Obligations,”  which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  This policy requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred.  As of July 31, 2012 and October 31, 2011, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with “Accounting for Asset Retirement Obligations.”  The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production.  We amortize the amount added to the oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining life of the respective well.  The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements.  The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.  Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.

We amortize the amount added to oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining useful lives of the respective wells.

The information below reflects the change in the asset retirement obligations during the nine-month period ended July 31, 2012 and the year ended October 31, 2011:
 
   
July 31, 2012
   
October 31, 2011
 
Balance, beginning of period
  $ 26,335     $ 27,494  
Liabilities assumed
    -       774  
    Revisions     -       (5,232
Accretion expense
    2,370        3,299  
Balance, end of period
  $ 28,705     $ 26,335  
 
The reclamation obligation relates to the Kodesh, Dye Estate, KC 80, Taylor and William wells at the Three Sands Property; ARD#1-36, Bagwell#1-20, Bagwell#2-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24, Jack#1-13 and Miss Jenny#1-8 wells at Oklahoma Properties, and McPherson#1-1 well at South Wayne Prospect.  The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes in applicable laws and regulations.  Such changes will be recorded in our accounts as they occur.
 
Reserve Estimates.  Our estimates of oil and natural gas reserves are projections based on an interpretation of geological and engineering data.  There are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures.  Estimates of the economically   recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on the risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially.  Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Forward Looking Statements

Certain statements in this Quarterly Report on Form 10-Q as well as statements made by us in periodic press releases and oral statements made by our officials to analysts and shareholders in the course of presentations about the Company, constitute “forward-looking statements”.   Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward looking statements.  Such factors include, among other things, (1) general economic and business conditions; (2)
 
 
25

 
 
interest rate changes; (3) the relative stability of the debt and equity markets; (4) government regulations particularly those related to the natural resources industries; (5) required accounting changes; (6) disputes or claims regarding our property interests; and (7) other factors over which we have little or no control.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Not required for smaller reporting companies.

Item 4.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures
 
Disclosure controls and procedures, as defined in Rule 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”), are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Act is accumulated and communicated to our officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
 
Rule 15d-15 under the Exchange Act, requires us to carry out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of July 31, 2012, being the date of our most recently completed fiscal quarter.  This evaluation was conducted under the supervision and with the participation of our officers, Kenneth Cabianca and Kulwant Sandher.  Based on this evaluation, Messrs. Cabianca and Sandher concluded that the design and operation of our disclosure controls and procedures are not effective since the following material weaknesses exist:

As of July 31, 2012, the following material weaknesses existed:

·    
We relied on external consultants for the preparation of our financial statements and reports.  As a result, it was possible that our officers were not able to identify errors and irregularities in the financial statements and reports.
 
·    
We had an officer who was also a director.  Our board of directors consisted of only one member.  Therefore, there was an inherent lack of segregation of duties and no independent governing board.
 
·    
We relied on an external consultant for administration functions, some of which do not have standard procedures in place for formal review by our officers.

 Changes in Internal Controls Over Financial Reporting

In connection with the evaluation of our internal controls during our last fiscal quarter, our officers have concluded that there were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended July 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



 
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Part II.        OTHER INFORMATION

Item 1.              Legal Proceedings
 
In September 2010, two lawsuits were filed in the District Court of Garvin County in the State of Oklahoma by Harold Hamm (“Hamm”) against certain defendants (“Defendants”) and consolidated together alleging, among other things, that Hamm owns an interest in two oil and gas leases in Garvin County and is entitled to a 50% participatory interest.  We were not named as a party in these legal proceedings, but Hamm’s allegations include a claim that he is entitled to a 50% participatory interest in the Joe Murray Farms well drilled as part of the 2009-3 Drilling Program, in which we purchased a 6.25% working interest before casing point and 5.0% working interest after casing point.  We and the Defendants believe that there is no merit to Hamm’s allegations.  In connection with these proceedings, the Defendants were ordered in January 2011 to escrow fifty percent (50%) of the revenues generated within the subject area pending the outcome of these proceedings.  For this reason, fifty percent (50%) of the revenues we are entitled to that have been generated by production from the Joe Murray Farms well is being escrowed and there is no assurance that we will be able to recover these proceeds.  We recognized $43,989 in revenue during the nine months ended July 31, 2012 and $119,295 in revenue during the year ended October 31, 2011 from the Joe Murray Farms well and a total of $163,284 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

Item 1A.           Risk Factors

Not required for smaller reporting companies.

Item 2.              Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.              Defaults Upon Senior Securities

None.

Item 4.              Mine Safety Disclosures

Not applicable.

Item 5.              Other Information

In April 2012, our president at the time, Leroy Halterman, passed away and Kenneth Cabianca assumed the duties as president.  We agreed to pay Mr. Cabianca a salary of $5,000 per month, effective as of July 1, 2012, to compensate him for his additional responsibilities.  His total compensation is $12,500 per month.

Item 6.              Exhibits.

Regulation
S-K Number
 
Exhibit
3.1
Articles of Incorporation (1)
3.2
Certificate of Change Pursuant to NRS 78.209 (2)
3.3
Amendment to the Articles of Incorporation (3)
3.4
Amended and Restated Bylaws (4)
3.5
Amendment to Amended and Restated Bylaws (5)
4.1
Certificate of Designation of Rights, Preferences, and Privileges for Series A Preferred Stock (4)
 
 
27

 
 
Regulation
S-K Number
 
Exhibit
10.1
Management Consulting Agreement dated February 10, 2012 (5)
31.1
Rule 15d-14(a) Certification of Principal Executive Officer
31.2
Rule 15d-14(a) Certification of Principal Financial Officer
32.1
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer
32.2
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer
101*
Financial statements from the Quarterly Report on Form 10-Q of Brinx Resources Ltd. for the quarter ended July 31, 2012, formatted in XBRL: (i) the Balance Sheets; (ii) the Statements of Operations; (iii) the Statements of Cash Flows; and (iv) the Notes to Financial Statements. (6)
_________________
 
(1)
Incorporated by reference to the exhibits to the registrant’s registration statement on Form SB-1, file number 333-102441.
 
(2)
Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated September 26, 2004, filed September 27, 2004.
 
(3)
Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated December 3, 2008, filed January 13, 2009.
 
(4)
Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated December 11, 2009, filed December 15, 2009.
 
(5)
Incorporated by reference to the exhibits to the registrant’s annual report on Form 10-K dated October 31, 2011, filed February 14, 2012.
 
(6)
To be filed by amendment.
 
*In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.
 
 


 
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SIGNATURES

 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
  BRINX RESOURCES LTD.  
  (Registrant)  
       
September 14, 2012
By:
/s/ Kenneth Cabianca  
    Kenneth Cabianca  
    President  
    (principal executive officer)  
       
September 14, 2012 By: /s/ Kulwant Sandher   
    Kulwant Sandher  
    Chief Financial Officer  
    (principal financial and acounting officer)  


 
 
 
 
 
 
 
 
 
29
 
 
 


 

PINX:BNXR Quarterly Report 10-Q Filling

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PINX:BNXR Quarterly Report 10-Q Filing - 7/31/2012
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