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EX-32.1 - EXH 32-1 CERTIFICATION - BRINX RESOURCES LTDexh32-1_certification.htm
EX-31.2 - EXH 31-2 CERTIFICATION - BRINX RESOURCES LTDexh31-2_certification.htm
EX-31.1 - EXH 31-1 CERTIFICATION - BRINX RESOURCES LTDexh31-1_certification.htm
EX-32.2 - EXH 32-2 CERTIFICATION - BRINX RESOURCES LTDexh32-2_certification.htm
 


 
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 January 31, 2013

[  ]
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)

Not applicable
 (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 March 11, 2013

 
 

 


BRINX RESOURCES LTD.
INDEX

   
Page
PART I.
FINANCIAL INFORMATION
 
     
Item 1.
Financial Statements
3
     
 
Balance Sheets
January 31, 2013 (unaudited) and October 31, 2012
4
     
 
Statements of Comprehensive Income/(Loss) (unaudited)
Three months Ended January 31, 2013 and 2012
5
     
 
Statements of Cash Flows (unaudited)
Three months Ended January 31, 2013 and 2012
 
6
     
 
Notes to Financial Statements (unaudited)
7
     
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
17
     
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
23
     
Item 4.
Controls and Procedures
23
     
PART II.
OTHER INFORMATION
 
     
Item 1.
Legal Proceedings
23
     
Item 1A.
Risk Factors
24
     
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
24
     
Item 3.
Defaults Upon Senior Securities
24
     
Item 4.
Mine Safety Disclosures
24
     
Item 5.
Other Information
24
     
Item 6.
Exhibits
24
     
Signatures
 
26


 
2

 

Part I.        FINANCIAL INFORMATION

Item 1.              Financial Statements

 
3

 

BRINX RESOURCES LTD.
 
BALANCE SHEETS
 
   
January 31,
   
OCTOBER 31,
 
   
2013
   
2012
 
   
(Unaudited)
   
(Audited)
 
 ASSETS
 
 
   
 
 
             
 Current assets
           
 Cash and cash equivalents
  $ 425,199     $ 540,512  
 Investment - Certificate of deposit
    400,000       400,000  
 Marketable securities
    40,000       96,000  
 Accounts receivable
    43,780       38,485  
 Prepaid expenses and deposit
    38,365       44,594  
                 
 Total current assets
    947,344       1,119,591  
                 
 Undeveloped mineral interests, at cost
    3,101       3,101  
                 
 Oil and gas interests, full cost method of accounting,
               
net of accumulated depletion
    1,444,056       1,450,330  
                 
 Total assets
  $ 2,394,501     $ 2,573,022  
                 
 LIABILITIES AND STOCKHOLDERS' EQUITY
               
                 
 Current liabilities
               
 Accounts payable and accrued liabilities
  $ 22,789     $ 6,332  
                 
 Total current liabilities
    22,789       6,332  
                 
 Asset retirement obligations
    28,381       27,554  
                 
 Total liabilities
    51,170       33,886  
                 
 Stockholders' equity
               
Preferred stock - $0.001 par value; authorized - 25,000,000 shares
               
        Series A Preferred stock - $0.001 par value; authorized - 1,000,000 shares
         
       Issued and outstanding - 500,001 shares
    500       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
    (232,000 )     (176,000 )
                 
 Retained earnings
    (317,856 )     (178,051 )
                 
 Total stockholders' equity
    2,343,331       2,539,136  
                 
 Total liabilities and stockholders' equity
  $ 2,394,501     $ 2,573,022  
 
The accompanying notes are an integral part of these financial statements.

 
4

 

 BRINX RESOURCES LTD.
 
 STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
 
 (UNAUDITED)
 
             
    FOR THE THREE MONTHS ENDED  
   
JANUARY 31,
 
   
2013
   
2012
 
             
 REVENUES
           
Natural gas and oil sales
  $ 64,376     $ 188,029  
                 
 DIRECT COSTS
               
 Production costs
    13,905       22,985  
 Depletion and accretion
    26,015       55,904  
 General and administrative
    162,419       154,876  
 Writedown of natural gas and oil properties
    2,039       -  
                 
 Total Expenses
    (204,378 )     (233,765 )
                 
 OPERATING INCOME/(LOSS)
    (140,002 )     (45,736 )
                 
 OTHER INCOME
               
 Interest income
    197       350  
 Other Income
    -       20,000  
                 
 NET INCOME/(LOSS)
    (139,805 )     (25,386 )
                 
 OTHER COMPREHENSIVE INCOME/(LOSS), NET OF TAX
               
 Unrealized gain/(loss) on held for sale marketable security
    (56,000 )     16,000  
                 
 COMPREHENSIVE LOSS FOR THE PERIODS
  $ (195,805 )   $ (9,386 )
                 
 Net Income/(Loss) Per Common Share
               
                 
  - Basic
  $ (0.01 )   $ (0.00 )
  - Diluted
  $ (0.01 )   $ (0.00 )
                 
 Weighted average number of common shares outstanding
               
                 
  - Basic
    24,629,832       24,629,832  
  - Diluted
    24,629,832       24,629,832  
 
 The accompanying notes are an integral part of these financial statements.

 
5

 

 BRINX RESOURCES LTD.
 
 STATEMENTS OF CASH FLOWS
 
 (UNAUDITED)
 
             
  FOR THE THREE MONTHS ENDED  
  JANUARY 31,  
   
2013
   
2012
 
             
 CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES
           
             
 Net (loss)
  $ (139,805 )   $ (25,386 )
                 
 Adjustments to reconcile net income to net cash provided by
               
     operating activities:
               
 Depletion and accretion
    26,015       55,904  
 Writedown of natural gas and oil properties
    2,039       -  
 Changes in working capital:
               
 Decrease in accounts receivable
    (5,295 )     (10,672 )
 Decrease in prepaid expenses and deposit
    6,229       6,549  
 Increase in accounts payable and accrued liabilities
    10,173       11,874  
                 
 Net cash provided by /(used in) operating activities
    (100,644 )     38,269  
                 
 CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES
               
                 
 Sale proceeds of natural gas and oil working interests
    -       200,000  
 Payments on oil and gas interests
    (14,669 )     (88,023 )
                 
 Net cash provided by /(used in) investing activities
    (14,669 )     111,977  
                 
 CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES
               
                 
 Net cash provided by /(used in) financing activities
    -       -  
                 
 Net increase/(decrease) in cash
    (115,313 )     150,246  
                 
 Cash and cash equivalents, beginning of periods
    540,512       401,047  
                 
 Cash and cash equivalents, end of periods
  $ 425,199     $ 551,293  
                 
                 
 SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
               
                 
 Assets retirement costs incurred
  $ (827 )   $ (790 )
                 
Investment in natural oil and gas working interests included in
  $ 6,283     $ -  
 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 in New Mexico and oil and gas interests 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 three-month period ended January 31, 2013 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, 2012.

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 average oil and gas prices and estimated reserves.  Price declines reduce the estimated value 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.  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 customers.  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 January 31, 2013 and 2012, 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," which 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 year.  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 the dilutive effect on income/(loss) per share.  The dilutive effect of outstanding options was nil as of January 31, 2013 and 2012.

 
8

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)


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

INCOME / (LOSS) PER SHARE (continued)

The table below presents the computation of basic and diluted earnings per share for the three-month periods ended January 31, 2013 and 2012:

      January 31, 2013        January 31, 2012   
Basic earnings per share computation:                
(Loss) from continuing operations
  $ (139,805 )   $ (25,386 )
Basic shares outstanding
    24,629,832       24,629,832  
Basic loss per share
  $ (0.01 )   $ (0.00 )
 
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 currently 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 the investments is based on the quoted market price on the closing date of the period.

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.
 
 
9

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
 
1.           ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

FAIR VALUE (continued)

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 the cash and cash equivalents, investments in certificates of deposits, 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 the business operations.  Management periodically evaluates the collectability of the 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.”
 
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 January 31, 2013 was $0.05 per share, as compared to $0.12 per share at October 31, 2012, giving rise to an unrealized loss of $56,000 for the three-month period ended January 31, 2013 (2012 – unrealized gain of $16,000).  The Company evaluated the prospects of Lexaria in relation to the severity and duration of the impairment.  Based on the evaluation and the Company’s ability and intent to hold the shares for a reasonable period of time sufficient for a recovery, the Company does not consider the shares to be other-than-temporarily impaired at January 31, 2013.
 
3.         ACCOUNTS RECEIVABLE

Accounts receivable consists of revenues receivable, interest receivable and other receivable.  The revenue receivable are 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 January 31, 2013 and October 31, 2012.  Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.

 
10

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

 
   
January 31, 2013
   
October 31, 2012
 
Accounts receivable
  $ 43,780     $ 38,485  
Less: allowance for doubtful account
    -       -  
    $ 43,780     $ 38,485  

4.  
OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:
 
      January 31, 2013        October 31, 2012   
2008-3 Drilling Program, Oklahoma
  $ 309,152     $ 309,152  
2009-2 Drilling Program, Oklahoma
    114,420       114,420  
2009-3 Drilling Program, Oklahoma
    338,470       337,749  
2009-4 Drilling Program, Oklahoma
    190,182       190,182  
2010-1 Drilling Program, Oklahoma
    255,985       254,817  
Washita Bend 3D, Oklahoma
    549,868       537,361  
Double T Ranch #1 SWDW, Oklahoma
    49,635       43,078  
Kings City Prospect, California
    404,121       404,121  
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 )
    Three Sands Project, Oklahoma
    555,715       555,715  
Asset retirement cost
    2,593       2,593  
Less:  Accumulated depletion and impairment
    (1,165,047 )     (1,137,820 )
    $ 1,444,056     $ 1,450,330  
 
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.  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”) is 6.25% and the After Casing Point Interest (“ACP”) is 5.00%.  At January 31, 2013, the total cost of the 2008-3 Drilling Program 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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At January 31, 2013, 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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP is 5.00%.  At January 31, 2013, the total cost of the 2009-3 Drilling Program was $338,470.  The interests are located in Garvin County, Oklahoma.

 
11

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)


4.        OIL AND GAS INTERESTS (continued)

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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At January 31, 2013, the total cost of the 2009-4 Drilling Program was $190,182.  The interests are located in Garvin County, Oklahoma.

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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At January 31, 2013, the total cost of the 2010-1 Drilling Program was $255,985.  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.  The BCP Interest is 5.625% and the ACP Interest is 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  At January 31, 2013, the total costs, including seismic costs, was $549,868.

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.  At January 31, 2013, the cost of the Double T Ranch#1 SWDW was $49,635.

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 to 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 party’s working interest.  The total cost of the King City prospect as at January 31, 2013 was $404,121.

Three Sands Project, Oklahoma

On October 6, 2005, the Company acquired a 40% working interest in Vector Exploration Inc’s Three Sands Project.

On September 10, 2012, the Company signed an asset purchase agreement with GLM Energy Inc., to sell the oil and gas assets effective June 1, 2012 for a total of $352,144.  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 Statements of Comprehensive Income in the amount of $96,491 for the year ended October 31, 2012.


 
12

 
 
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 is 6.25% and the ACP Interest is 5.00%.  The interests are located in McClain County, Oklahoma.  The total cost of the South Wayne prospect as at January 31, 2013 was $61,085.

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 three-month periods ended January 31, 2013 and 2012, respectively.

Depletion

Under the full cost method, depletion is computed on the units of production method based on proved reserves.  Depletion expense recognized was $25,188 and $55,114 for the three-month periods ended January 31, 2013 and 2012, respectively.

Capitalized Costs
   
January 31, 2013
   
October 31, 2012
 
Proved properties
  $ 1,605,478     $ 1,603,590  
Unproved properties
    1,003,624       984,560  
Total Proved and Unproved properties
    2,609,102       2,588,150  
Accumulated depletion expense
    (759,886 )     (734,698 )
Impairment
    (405,160 )     (403,122 )
Net capitalized cost
  $ 1,444,056     $ 1,450,330  

Results of Operations

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

   
January 31, 2013
   
January 31, 2012
  Revenues
  $ 64,376     $ 188,029  
  Production costs
    (13,905 )     (22,985 )
  Depletion and accretion
    (26,015 )     (55,904 )
  Results of operations (excluding corporate overhead)
  $ 24,456     $ 109,140  
 
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 January 31, 2013 and October 31, 2012, 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

 
13

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
 
5.           ASSET RETIREMENT OBLIGATIONS (continued)

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 discounted 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 three-month period ended January 31, 2013 and the year ended October 31, 2012:

   
January 31, 2013
   
October 31, 2012
 
Balance, beginning of periods
  $ 27,554     $ 26,335  
Liabilities assumed
    -       -  
    Revisions     -       (1,941
Accretion expense
     827        3,160  
Balance, end of periods
  $ 28,381     $ 27,554  

The reclamation obligation relates to the Bagwell#1-20, Bagwell#2-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24 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.


6.
COMMON STOCK

PREFERRED STOCK

The Company has authorized 25,000,000 shares of preferred stock. On February 10, 2012, the Company issued 500,001 Series A preferred stock at par value. The rights attached to these Series A preferred stock include:

·      
The holders of the Series A preferred stock can redeem their stock at a predetermined redemption price.

·      
The holders of the Series A Preferred Stock shall be entitled to elect one director of the Company in connection with each annual election of directors who shall be the designated “Series A Director”. With respect to any other matter submitted for a vote (or a written consent in lieu thereof) by the stockholders of the Company (except as to which the Series A Preferred Stock will be entitled to vote separately as a class), the holders of Series A Preferred Stock and the holders of the common stock, $0.001 par value of the Company (“Common Stock”) shall vote together as a single class and not as separate series.


 
14

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)


6.        COMMON STOCK (continued)

·      
The Company shall not without first obtaining the approval (by vote or written consent, as provided by law) of the holders of a majority of the Series A Preferred Stock do any of the following:

(a) amend, alter, or repeal any provision of the Articles of Incorporation or the Bylaws of the Company (including any filing of a Certificate of Designation) that alters or changes the voting powers, preferences, or other special rights or privileges, or restrictions of the Series A Preferred Stock;

(b) increase or decrease the total number of authorized shares of Series A Preferred Stock;

(c) authorize or issue, or obligate itself to issue, any other equity security, including any other security convertible into or exercisable for any other equity security, which has a preference over the Series A Preferred Stock with respect to voting, or authorize any increase in the authorized or designated number of any such security;

(d) purchase or otherwise acquire any share or shares of Preferred Stock or Common Stock (or pay into or set aside for a sinking fund for such purpose); provided, however, that this restriction shall not apply to the repurchase of shares of Common Stock from employees, officers, directors, consultants or other persons performing services for the Company or any subsidiary pursuant to agreements under which the Company has the option to repurchase such shares at cost or at cost upon the occurrence of certain events, such as the termination of employment;

(e) authorize the voluntary or involuntary dissolution, liquidation or winding-up of the Company;

(f) pay any dividend or other distribution other than (i) in the case of the Common Stock, a dividend or distribution payable solely in Common Stock and (ii) any dividend or distribution the fair market value of which does not exceed 10% of the Company's aggregate net profits for the fiscal year of the Company in which such dividend is declared and the immediately preceding fiscal year;

(g) cause the Company to enter into or engage, directly or indirectly, in any material respect any line of business other than the other than the business anticipated to be conducted by the Company as of the date of the first issuance of the Series A Preferred Stock; or

(h) enter into any transaction with any officer, director or stockholder of the Company or any "affiliate" or "associate" (as such terms are defined in the regulations promulgated by the Securities and Exchange Commission under the Securities Exchange Act of 1940) of any such person or entity, other than normal employment arrangements and benefit programs on reasonable terms and other than any transaction (or series of related transactions) involving not more than $100,000 in the aggregate that has been approved by a majority of the Board of Directors (excluding any director who is interested in such transaction, either directly or through one of his affiliates or associates) after full disclosure of the terms thereof to the Board of Directors and after the determination by such majority of the Board of Directors.


7.         RELATED PARTY TRANSACTIONS

During the three-month periods ended January 31, 2013 and 2012, the Company entered into the following transactions with related parties:

a)    
  The Company paid $21,000 (2012 - $18,000) to a related entity, for administration services.

 
15

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
(Unaudited)


7.         RELATED PARTY TRANSACTIONS (continued)

b)      
The Company paid $40,500 (2012 - $25,500) in management fees to the director and current President of the Company.

c)      
The Company paid $20,235 (2012 - $19,527) in consulting and accounting fees to the Chief Financial Officer of the Company.

d)      
The Company paid $1,500 (2012 - $ nil) in consulting fee to the director of the Company.

8.        MAJOR CUSTOMERS

We collected $59,418 (2012: $146,808) or 92% (2012: 78%) of our revenues from one of our operators during the three-month period ended January 31, 2013. As of January 31, 2013, $36,797 (2012: $77,680) 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 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 $5,875 in revenue during the three-month period ended January 31, 2013, and $51,276 in revenue during the year ended October 31, 2012.   As at January 31, 2013, revenue from the Joe Murray Farms well totaling $176,446 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

 
 

 
16

 

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 Leroy Halterman, who was 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, 2012 or 2011 or the three months ended January 31, 2013.  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 produce commercial quantities of oil and gas and to 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 mineral owners of royalties.

Note that all production amounts disclosed for the individual properties below are for the Company’s 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 is 6.25% and the ACP Interest is 5.00%.  The total cost of the 2008-3 Drilling Program as of January 31, 2013 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 development well was drilled in August of 2011 near the highest producing well in the program.  For the three
 
 
17

 
 
 
months ending  January 31, 2013, the three producing wells in this program have produced a total of 78 Bbls of oil and 39 Mcf of natural gas.

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 is 6.25% and the ACP Interest is 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 January 31, 2013, 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 is 6.25% and the ACP Interest is 5.00%.  The total costs incurred, including drilling costs, as of January 31, 2013 was $338,470.  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.  This 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.  The well is now producing oil and gas with the use of a pumping unit.  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 production from these two producing wells for the three months ending January 31, 2013 totaled 206 Bbls of oil and nil Mcf of natural gas.

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 is 6.25% and the ACP Interest is 5.00%.  The total costs incurred, including drilling costs, as of January 31, 2013 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 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 remains in production.  The one well that could not be successfully treated for the poor cement bond was plugged and abandoned.  The other well has been converted to a  salt water disposal well.  As of the three months ending January 31, 2013, there has been no production of hydrocarbons.

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 is 6.25% and the ACP
 
 
18

 
 
Interest is 5.00%.  The total cost incurred, including drilling costs, as of January 31, 2013 was $255,985. 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.  All three of the wells were completed in the deepest pay zone as of October 31, 2010.  The third well in this program is currently shut-in.  Total production from these wells for the three months ended January 31, 2013 was 407 Bbls of oil and 123 Mcf of natural gas.

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 is 6.25% and the ACP Interest is 5.00%.  The total cost incurred, including drilling costs, as of January 31, 2013 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 12 Bbls of oil and 4 Mcf of natural gas.  Total production for the McPherson well for the three months ending January 31, 2013 was 60 Bbls of oil and 18 Mcf of natural gas.  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 is 5.625% and the ACP Interest is 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 January 31, 2013 was $549,868.
 
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.

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 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 still under way.

As of January 31, 2013, 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.  Title research and leasing on a number of potential prospects is underway and it is anticipated that up to a 10-well exploration program on 10 separate prospects over the next twelve months will start in the near future.  Depending on the success of this program, additional wells may be drilled.
 
 
19

 

 
Double T Ranch#1 SWDW, Oklahoma.  On July 17, 2012, we 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.  At January 31, 2013, the cost of the Double T Ranch#1 SWDW was $49,635.

Three Sands Project

On October 6, 2005, we 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 (the “Three Sands Project”).  The Three Sands Project is located in Oklahoma.

On September 10, 2012, we signed an asset purchase agreement with GLM Energy Inc., to sell the oil and gas assets in the Three Sands Project effective June 1, 2012 for a total of $352,144.  The disposed reserves represented more than 25% of the total reserves which we considered to represent a significant alteration between capitalized costs and proved reserves and hence a loss on the sale was recognized in the Statements of Comprehensive Income in the amount of $96,491 for the year ended October 31, 2012.

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.  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 was completed in January 2012.  The operator is currently evaluating the well to determine if economic quantities of hydrocarbon can be produced.

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 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 three-month period ended January 31, 2013 or during the fiscal years ended October 31, 2012 and 2011.  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 January 31, 2013 compared to the three months ended January 31, 2012.  We realized revenues of $64,376 during the three months ended January 31, 2013, compared with $188,029 during the three months ended January 31, 2012, a decrease of $123,653, due to a decrease in our oil and gas production.  During the three-month period ended January 31, 2013, 752 Bbls of oil and 181Mcf of gas were produced at our oil and gas properties, as compared to 1,613 Bbls of oil and 6,128 Mcf of gas for the three months ended January 31, 2012.  The decrease in production was due primarily to a decrease in the number of producing wells.
 
 
20

 
We incurred production costs of $13,905 during the three months ended January 31, 2013, compared with $22,985 during the three months ended January 31, 2012, a decrease of $9,080.  Our production costs decreased as a result of a decrease in our oil and gas production, but increased as a percentage of sales from 12% to 22% as a substantial portion of our production costs are fixed in nature.

Our depletion and accretion costs were $26,015 during the three months ended January 31, 2013, compared with $55,904 during the three months ended January 31, 2012, a decrease of $29,889.  The decrease in our depletion costs is related to a decrease in production from our wells.

Our general and administrative costs increased to $162,419 for the three months ended January 31, 2013, from $154,876 for the three months ended January 31, 2012.  The increase of $7,543 is primarily attributable to an increase in costs of consulting services.

We received $nil in other income during the three months ended January 31, 2013, compared with $20,000 during the three months ended January 31, 2012 for late payment fees received from Lexaria Corp. in conjunction with the sale of our Mississippi properties.

For the three months ended January 31, 2013, we incurred a net loss of $139,805, compared to a net loss of $25,386 for the three months ended January 31, 2012.  The increase in net loss was largely attributable to the decrease in revenues.

As a result of our net loss for the quarter, we had a retained loss of $317,856 at January 31, 2013.

Liquidity and Capital Resources
 
As of January 31, 2013, we had cash and a certificate of deposit totaling $825,199 and working capital of $924,555, compared to cash and a certificate of deposit totaling $940,512 and working capital of $1,113,529 as of October 31, 2012.  The decrease in working capital is due to primarily to a decrease in our marketable securities and an increase in our current liabilities.  Our marketable securities decreased to $40,000 at January 31, 2013, compared with $96,000 at October 31, 2012, a decrease of $56,000.  Our current liabilities increased to $22,789 at January 31, 2013, compared with $6,332 at October 31, 2012.
 
During the three months ended January 31, 2013, operating activities used cash of $100,644, as compared to net cash provided of $38,269 for the three months ended January 31, 2012.  The principal reason for the change was due to the net loss for the period.

Investing activities, which consisted of payments on our oil and gas interests, used net cash of $14,669 during the three months ended January 31, 2013, compared with $111,977 provided during the three months ended January 31, 2012.  We received $200,000 from the sale of our interest in the Palmetto Point Project in January 2012.

Off-Balance Sheet Arrangements

As of January 31, 2013, 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.  Amortizable costs include estimates of future development costs of proved undeveloped reserves.
 
 
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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 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 January 31, 2013 and October 31, 2012, 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 three-month period ended January 31, 2013 and the year ended October 31, 2012:

   
January 31, 2013
   
October 31, 2012
 
Balance, beginning of periods
  $ 27,554     $ 26,335  
Liabilities assumed
    -       -  
    Revisions     -       (1,941
Accretion expense
     827        3,160  
Balance, end of periods
  $ 28,381     $ 27,554  
 
The reclamation obligation relates to the Bagwell#1-20, Bagwell#2-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24 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
 
 
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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) 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 January 31, 2013, being the date of our most recently completed fiscal quarter.  This evaluation was conducted under the supervision and with the participation of our officers, Ken 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 because of
the following material weaknesses that existed at January 31, 2013:

·     
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 two members.  Therefore, there was an inherent lack of segregation of duties and a limited 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 January 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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
 
 
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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.  The Company recognized $5,875 in revenue during the three-month period ended January 31, 2013, and $51,276 in revenue during the year ended October 31, 2012.  As of January 31, 2013, revenue from the Joe Murray Farms well totalling $176,446 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

Not applicable.

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)
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
 
 
 
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Regulation
S-K Number
 
Exhibit
101*
Financial statements from the Quarterly Report on Form 10-Q of Brinx Resources Ltd. for the quarter ended January 31, 2013, 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.
________________________
(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.
 
*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)  
       
March 18, 2013
By:
/s/ Ken Cabianca  
    Ken Cabianca  
    Acting President  
    (principal executive officer)  
       
March 18, 2013 By:  /s/ Kulwant Sandher  
    Kulwant Sandher  
    Chief Financial Officer  
    (principal financial and accounting officer)  

 
 
 
 
 
 
 
 
 
 
 
 
 
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