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, 2010





[  ]
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.)





820 Piedra Vista Road NE, Albuquerque, New Mexico 87123


(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).


[  ] Yes                      [  ] No (Not Required)





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, 2010








BRINX RESOURCES LTD.


INDEX





PagePART I.
FINANCIAL INFORMATIONItem 1.
Financial Statements
3Balance Sheets

July 31, 2010 (unaudited) and October 31, 2009
4Statements of Operations (unaudited)

Three Months and Nine Months Ended July 31, 2010 and 2009
5Statements of Cash Flows (unaudited)

Nine Months Ended July 31, 2010 and 2009
6Notes to Financial Statements (unaudited)
7Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
16Item 3.
Quantitative and Qualitative Disclosures About Market Risk
24Item 4.
Controls and Procedures
24PART II.
OTHER INFORMATIONItem 1.
Legal Proceedings
24Item 1A.
Risk Factors
24Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
24Item 3.
Defaults Upon Senior Securities
25Item 4.
Removed and Reserved
25Item 5.
Other Information
25Item 6.
Exhibits
25Signatures

26





2


Part I.        FINANCIAL INFORMATION





Item 1.              Financial Statements


3





BRINX RESOURCES LTD.BALANCE SHEETSJULY 31,


OCTOBER 31,2010


2009ASSETS

(UNAUDITED)


(AUDITED)Current assetsCash and cash equivalents

$
1,328,452


$
1,947,950Accounts receivable


147,456



97,198Income taxes receivable


-



253,814Prepaid expenses and deposit


203,006



270,610Total current assets


1,678,914



2,569,572Undeveloped mineral interests, at cost


811



811Oil and gas interests, full cost method of accounting,net of accumulated depletion


2,175,985



1,637,010Total assets

$
3,855,710


$
4,207,393LIABILITIES AND STOCKHOLDERS' EQUITYCurrent liabilitiesAccounts payable and accrued liabilities

$
95,242


$
75,185Total current liabilities


95,242



75,185Asset retirement obligations


40,341



37,011Total liabilities


135,583



112,196Stockholders' equityPreferred stock - $0.001 par value; authorized - 1,000,000 sharesIssued - none


-



-Common stock - $0.001 par value; authorized - 100,000,000 sharesIssued and outstanding - 24,629,832 shares


24,630



24,530Capital in excess of par value


2,859,906



2,801,991Retained earnings


835,591



1,268,676Total stockholders' equity


3,720,127



4,095,197Total liabilities and stockholders' equity

$
3,855,710


$
4,207,393




The accompanying notes are an integral part of these financial statements.







4





BRINX RESOURCES LTD.STATEMENTS OF OPERATIONS(UNAUDITED)FOR THE THREE MONTHS


FOR THE NINE MONTHSPERIOD ENDED


PERIOD ENDEDJULY 31,


JULY 31,2010


2009


2010


2009REVENUESNatural gas and oil sales

$
254,173


$
135,126


$
482,229


$
245,405DIRECT COSTSProduction costs


20,119



23,156



62,807



75,612Depletion and accretion


106,446



59,512



175,458



131,790General and administrative


200,208



163,506



679,671



435,569Total Expenses


(326,773
)


(246,174
)


(917,936
)


(642,971
)OPERATING INCOME (LOSS)


(72,600
)


(111,048
)


(435,707
)


(397,566
)OTHER INCOME AND EXPENSEInterest income


1,701



-



2,622



1,291NET (LOSS) BEFORE INCOME TAXES


(70,899
)


(111,048
)


(433,085
)


(396,275
)Income taxes


-



6,940







6,940NET (LOSS) FOR THE PERIODS

$
(70,899
)

$
(117,988
)

$
(433,085
)

$
(403,215
)Net Income Per Common Share- Basic

$
(0.003
)

$
(0.005
)

$
(0.018
)

$
(0.016
)- Diluted

$
(0.003
)

$
(0.005
)

$
(0.018
)

$
(0.016
)Weighted average number of common shares outstanding- Basic


24,629,832



24,529,832



24,596,132



24,529,832- Diluted


24,629,832



24,529,832



24,596,132



24,529,832




The accompanying notes are an integral part of these financial statements.


5





BRINX RESOURCES LTD.STATEMENTS OF CASH FLOWS(UNAUDITED)FOR THE NINE MONTHSPERIOD ENDEDJULY 31,2010


2009CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIESNet (loss)

$
(433,085
)

$
(403,215
)Adjustments to reconcile net income to net cash provided by(used in) operating activities:Stock based compensation (note 5)


31,015



-Depletion and accretion


175,458



131,790Shares issued to Investor Relations Services Inc. for services rendered


27,000



-Changes in working capital:Decrease (Increase) in accounts receivable


(50,258
)


(27,100
)Decrease (Increase) in prepaid expenses and deposit


67,604



2,808Increase (Decrease) in accounts payable and accrued liabilities


20,057



34,076Increase (Decrease) in income taxes receivable


253,814



-Increase (Decrease) in income taxes payable


-



(580,000
)Net cash provided by (used in) operating activities


91,605



(841,641
)CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIESPayments on oil and gas interests


(711,103
)


(414,667
)Net cash provided by (used in) investing activities


(711,103
)


(414,667
)CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIESNet cash provided by (used in) financing activities


-



-Net cash (used in) financing activities


-



-Net increase (decrease) in cash


(619,498
)


(1,256,308
)Cash and cash equivalents, beginning of periods


1,947,950



3,617,109Cash and cash equivalents, end of periods

$
1,328,452


$
2,360,801SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIESAssets retirement costs incurred

$
(3,330
)

$
(2,769
)Assets retirement obligation incurred

$
3,330


$
2,769Investment in natural oil and gas working interests included in accounts payable

$
93,208


$
-







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 undeveloped mineral interests located in New Mexico and holds oil and gas interests located in Oklahoma, California, Mississippi and Louisiana.  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, 2010 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, 2009.





Except for the historical information contained in this Form 10-Q, this Form contains forward-looking statements that involve risks and uncertainties.  The Company’s actual results could differ materially from those discussed in this Report.  Factors that could cause or contribute to such differences include, but are not limited to, those discussed in this Report and any documents incorporated herein by reference, as well as the Annual Report on Form 10-K for the year ended October 31, 2009.





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.









7
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)


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





OIL AND GAS INTERESTS (continued)





less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.





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 July 31, 2010 and 2009, the Company had no overproduced imbalances.





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 the dilutive effect on income/(loss) per share.  The dilutive effect of convertible securities is reflected in diluted earnings per share by application of the "as if converted method." The dilutive effect of outstanding options and warrants and their equivalents is reflected in diluted earnings per share by application of the treasury stock method.  Hence 500,000 options were excluded from the earnings per share calculation for the nine-month period ended July 31, 2010, since they were considered to be anti-dilutive.  The table below presents the computation of basic and diluted earnings per share for the nine-month periods ended July 31, 2010 and 2009:





July 31, 2010


July 31, 2009Basic earnings per share computation:Income (Loss) from continuing operations

$
(433,085
)

$
(403,215
)Basic shares outstanding


24,596,132



24,529,832Basic earnings per share

$
(0.018
)

$
(0.016
)Diluted earnings per share computation:Income (Loss) from continuing operations

$
(433,085
)

$
(403,215
)Basic shares outstanding


24,596,132



24,529,832Incremental shares from assumed conversions:Stock options


-



-Warrants


-



-Diluted shares outstanding


24,596,132



24,529,832Diluted earnings per share

$
(0.018
)

$
(0.016
)




The calculation for earnings per share excluded stock options as these were not in the money as at July 31, 2010 and 2009, respectively and have an anti-dilutive effect.






8
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)


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




CONCENTRATION OF CREDIT RISK





Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents 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, however, the at risk amounts were $1,078,452 for the nine-month period ended July 31, 2010 and $1,697,950 for the year ended October 31, 2009.





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





Effective November 1 2006, the Company adopted the fair value recognition provisions of FASB ASC 718 (prior authoritative literature: SFAS No. 123R) “Share Based Payment” using the modified prospective method as described in “Accounting for Stock-Based Compensation – Transition and Disclosure”, as prescribed by the United States Securities and Exchange Commission (“SEC”).





The fair value of each option granted has been estimated as of the date of the grant using the Black-Scholes option pricing model with the following assumptions:




Nine-month periods endedJuly 31, 2010
July 31, 2009Expected volatility
149%
0.00%Risk-free interest rate
0.11%
0.00%Expected life
2 years
0 yearsDividend yield
0.00%
0.00%




2.         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 our 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, 2010 and October 31, 2009.  Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.
  July 31, 2010


October 31, 2009Accounts receivable

$
147,456


$
97,198Less: allowance for doubtful account


-



-$
147,456


$
97,198


9
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)








3.
OIL AND GAS INTERESTS





The Company holds the following oil and natural gas interests:





July 31, 2010


October 31, 20092008-3 Drilling Program, Oklahoma

$
259,181


$
258,9802009-2 Drilling Program, Oklahoma


116,093



82,9352009-3 Drilling Program, Oklahoma


278,194



137,3562009-4 Drilling Program, Oklahoma


133,889



-2010-1 Drilling Program, Oklahoma


138,773



-Washita Bend 3D, Oklahoma


203,109



-Kings City Prospect, California


100,000



100,000Three Sands Project, Oklahoma


1,197,523



1,197,523South Wayne Prospect, Oklahoma


61,135



-Palmetto Point Project, Mississippi


420,000



420,000Frio-Wilcox Prospect, Mississippi


400,000



400,000PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi


221,820



221,820Asset retirement cost


22,949



22,949Less: Accumulated depletion and impairment


(1,376,681
)


(1,204,553
)$
2,175,985


$
1,637,010





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 $213,925 in addition to $18,850 that was spent in previous periods.  The total cost of the 2008-3 Drilling Program at July 31, 2010 was $259,181.  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, the cost and its buy-in cost total of $67,707 for Selman#1-21 and $57,921 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 were 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 $57,483 were moved to the proved properties.  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 $38,630 were moved to the proved properties.  As at July 31, 2010, the total cost of the 2009-2 Drilling Program was $116,093.  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%


10
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)


3.         OIL AND GAS INTERESTS (continued)





and the ACP Interest shall be 5.00%.  Jackson#1-18 started producing during January 2010; an amount of $63,725 which included the buy-in cost was moved to the proved properties.  Miss Gracie#1-18 started producing during March 2010; an amount of $62,268 which included its buy-in cost was moved to the proved properties.  Brewer#1-20 was abandoned on June 2, 2010; the cost and its buy-in cost total of $64,936 were moved to the proved properties.  Waunice#1-36 started producing during June 2010; an amount of $43,848 which included its buy-in cost was moved to the proved properties.   As at July 31, 2010, the total cost of the 2009-3 Drilling Program was $278,194.  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 $79,892 which included the buy-in cost was moved to the proved properties.  The total costs, including drilling costs, for the nine-month period ended July 31, 2010 was $133,889.





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%.  The total costs, including drilling costs, for the nine-month period ended July 31, 2010 was $138,773.





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 total costs, including seismic costs, for the nine-month period ended July 31, 2010 was $203,109.




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 agreeing to carry Sunset Exploration for 40% 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.
 
 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 from May to July 2008 for the KC 80#1-11 well.  The total cost of the Three Sands Project as at July 31, 2010 was $1,197,523.  The interests are located in Oklahoma.


11
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)


3.         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 total costs, including drilling costs, for the nine-month period ended July 31, 2010 was $61,135.  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.





Palmetto Point Project, Mississippi





On February 28, 2006, the Company acquired a 10% working interest before production and 8.5% revenue interest after production in a 10-well program at Griffin & Griffin Exploration Inc.’s Palmetto Point Project for a total buy-in cost of $350,000.  On September 26, 2006, the Company acquired an additional two wells within this program for $70,000.  On October 1, 2007, the Company acquired a 10% working interest and participated in drilling two more wells within the Palmetto Point Project, the (PP F-12-2 and PP F-12-3 wells), at a cost of $69,862. On October 25, 2007, the Company paid $17,000 for a sidetrack, a deviation of the existing PP-F-12-3 well at an angle to reach additional targeted oil sands.





On January 30, 2008, the Company incurred $36,498 for work-overs to install submersible pumps.  From November 2008 to July 2009, the Company incurred $44,623 for Belmont Lake Project.  The total cost of the Palmetto Point Project, which included costs for the PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52 wells, is $641,820 as of July 31, 2010.  The interests are located in Mississippi.




Frio-Wilcox Project, Mississippi
 
 On August 2, 2006, the Company signed a memorandum agreement with Griffin & Griffin LLC (the “Operator”) to participate in two proposed drilling programs located in Mississippi and Louisiana.  The Company acquired a 10% working interest in this project before production and a prorated reduced working interest after production based on the Operator’s interest portion.  The Company paid $400,000 for the interest.
 
 On June 21, 2007, the Company assigned all future development obligations for any new well at its Frio-Wilcox Prospect to a third party.  The Company maintained its original interest, rights, title and benefits to all seven wells drilled with the Company’s participation at the Frio-Wilcox Prospect property between August 3, 2006 and June 19, 2007, specifically wells CMR-USA-39-14, Dixon #1, Faust #1 TEC F-1, CMR/BR F-14, RB F-1 Red Bug #2, BR F-33, and Randall #1 F-4, and any offset wells that could be drilled to any of these specified wells.
 
 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, 2010 or 2009, 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





12
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)


3.         OIL AND GAS INTERESTS (continued)





recent commencement of production.  Depletion expense recognized was $172,128 and $129,021 for the nine-month periods ended July 31, 2010 and 2009, respectively.





Capitalized Costs


July 31, 2010


October 31, 2009Proved properties

$
2,993,972


$
2,571,104Unproved properties


558,694



270,459Total Proved and Unproved properties


3,552,666



2,841,563Accumulated depletion expense


(1,157,142
)


(985,014
)Impairment


(219,539
)


(219,539
)Net capitalized cost

$
2,175,985


$
1,637,010




Results of Operations





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


July 31, 2010


July 31, 2009Revenues

$
482,229


$
245,405Production costs


(62,807
)


(75,612
)Depletion and accretion


(175,458
)


(131,790
)Results of operations (excluding corporate overhead)

$
243,964


$
38,003




4.           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, 2010 and October 31, 2009, 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.  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, 2010 and the year ended October 31, 2009:


13
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)




4.           ASSET RETIREMENT OBLIGATIONS (continued)





July 31, 2010


October 31, 2009Balance, beginning of period

$
37,011


$
30,766Liabilities assumed


-



9,206Revisions


-



(6,653
)Accretion expense


3,330



3,692Balance, end of period

$
40,341


$
37,011





The reclamation obligation relates to the Kodesh, Dye Estate, KC 80 and William wells at the Three Sands Property; the Palmetto Point Project well at the Frio-Wilcox Project; and ARD#1-36, Bagwell#1-20, Selman#1-21, Selman#2-21, Jackson#1-18, Miss Gracie#1-18, Waunice#1-36 and Dennis#1-8 wells at Oklahoma Properties.  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.





5.
COMMON STOCK





The Company entered into the agreement for corporate development services for consideration of 100,000 restricted common shares of the Company and two payments of $4,000 which were paid during the three months ended January 31, 2010.  The shares were issued on February 1, 2010 with a cost of $27,000.





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.





On November 2, 2007, the Company granted a non-qualified stock option with respect to 200,000 shares to the President.  The exercise price is $0.24 per share.  The Option expired on November 2, 2009.




On October 30, 2009, the Company granted a non-qualified stock option with respect to 200,000 shares to the CFO.  The exercise price is $0.10 per share.  The options will fully vest in six months and expire in two years from the Grant Date.  The Company recorded a total of $12,322 and $136 and for stock compensation expenses for the nine months ended July 31, 2010 and the year ended October 31, 2009.
 
 On November 2, 2009, the Company granted a non-qualified stock option with respect to 300,000 shares to the President.  The exercise price is $0.10 per share.  The options will fully vest in six months and expire in two years from the Grant Date.  The Company recorded a total of $18,693 for stock compensation expenses for the nine months ended July 31, 2010.
 
 A summary of the changes in stock options for the nine months ended July 31, 2010 is presented below:
 
 Options OutstandingWeighted AverageNumber of Shares


Exercise PriceBalance, October 31, 2008


200,000


$
0.24Grant on October 30, 2009


200,000



0.10Exercised


-



-Balance, October 31, 2009


400,000


$
0.17Granted on November 2, 2009


300,000



0.10Expired on November 2, 2009


(200,000
)


0.24Exercised


-



-Balance, July 31, 2010


500,000


$
0.10


14
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)


5.        COMMON STOCK (continued)





The Company has the following options outstanding and exercisable.





July 31, 2010
Options outstanding and exercisableRange of

exercise prices
Number of

shares
Weighted average remaining contractual life
Weighted Average

Exercise Price$0.10

$0.10
200,000

300,000
1.24 years

1.25 years
0.10

0.10





6.         RELATED PARTY TRANSACTIONS





During the nine-month periods ended July 31, 2010 and 2009, the Company entered into the following transactions with related parties:





a)
The Company paid $45,000 (2009 - $45,000) in management fees and reimbursement of office space of $3,600 (2009 - $3,600) to the President of the Company.





b)
The Company paid $45,000 (2009 - $45,000) to a related entity, for administration services, and $nil (2009 - $ 96,500) for consulting.





c)
The Company paid $67,500 (2009 - $79,500) in management fees to the director of the Company.





7.         COMMITMENTS
  a)
The Company has a month to month rental agreement with its office in New Mexico.
 
 b)
The Company shall be responsible for 40% (i.e. $8,000) of additional expense on seismic survey for Kings City Farmout Modification Agreement.


15


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, 2009 or 2008 or the nine months ended July 31, 2010.  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.




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 100% of the production for such property and not the production amount relating only to 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 shall be 6.25% and the ACP Interest shall be 5.00%.  From January 2009 to July 2009, we expended an additional $213,925.  The total cost of the 2008-3 Drilling Program as of July 31, 2010 was $259,181.  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.  As of July 31, 2010, the two producing wells in this program have produced a total of 121,318 Bbls of oil and 21,288 Mcf of natural gas.





16


2009-2 Drilling Program, Oklahoma.  On June 15, 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 at July 31, 2010, the total cost of the 2009-2 Drilling Program was $116,093.





2009-3 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, at July 31, 2010 was $278,194.  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 test 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 as a flowing oil and gas well.  The well was flowing naturally at rates between 400 and 500 barrels 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. Conditions have improved and the well is now producing and selling oil and natural gas. The second well that also had a flowing drill stem test was completed in late March and that well is currently producing as a naturally flowing oil and gas well.  Total production from these two producing wells as of July 31, 2010 totaled 50,334 Bbls of oil and 18,531 Mcf of natural gas.





In late June, a successful development well was drilled as an offset to the naturally flowing well that is still producing at a rate of 230 Bbls oil and 28 Mcf of natural gas per day.  This development well was completed in early August and is flowing at a rate of 320 Bbls of oil and 40 Mcf of natural gas per day and should add significantly to this program’s future oil and gas production.





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





2009-4 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, for the nine-month period ended July 31, 2010 was $133,889.  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 and reached total depth on February 20, 2010. The second well drilling started in late February 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 are undergoing treatment for a poor cement bond and may be in production in the near future.  As of July 31, 2010, both wells have produced a total of 2,734 Bbls of oil and have not produced any natural gas.





17




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 costs incurred, including drilling costs, for the nine-month period ended July 31, 2010 was $138,773.  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 August, two wells of the four-well program had been drilled.  Both wells intercepted multiple pay zones including the prolific lowest zone in both of the wells.  One well had a flowing drill stem test but the other well was not drill stem tested due to hole conditions.  Both wells show excellent porosity, permeability, and hydrocarbon shows.  Completion of these wells is expected to start in mid-September.  The remaining two wells are expected to be drilled in September or early October.





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 costs incurred, including drilling costs, for the nine-month period ended July 31, 2010 was $61,135.  The well and related leasehold interests are located in McClain County, Oklahoma.  As of July 31, 2010, the well had been drilled and production casing has been set.  The well was perforated in July 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 and the well is now producing at a rate of 120 Bbls of oil and 35 Mcf of natural gas.  Total production during this short period as of July 31, 2010 was 1,748 Bbls of oil.




Washita Bend 3D Exploration Project, Oklahoma.On March 1, 2010, we agreed to participate with a 5% interest in a 3-D seismic program managed by an experienced local operator 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 costs, including seismic costs, for the nine-month period ended July 31, 2010 was $203,109.




Work has commenced on this project and, as of August 11, 2010, almost half of all the surface permits have been acquired.  Ownership reports are expected be completed in late August or early September. We expect the start date for the surveying to be early September with seismic data acquisition expected to start in October.





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.  For the year ended October 31, 2006, we expended $530,081 in exploration costs.  In June 2007, we acquired a 40% working interest in the 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, we participated in the KC 80 #1-11 well and paid $75,000 for the prepaid drilling costs.  From March and April 2008, we expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 during May to July 2008.  The total cost of the Three Sands Project as of July 31, 2010 was $1,197,523.  Our working interest in the Three Sands Project includes leasehold interests, one re-entry production well, and two drilling wells.  We also participate in drilling operations and related costs, in proportion to our working interest.





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 as a salt water disposal well.  The Kodesh #2 well no longer produces oil on a daily basis, but there is a small amount of natural gas being produced. As of July 31, 2010, it has produced 3,690 Bbls of oil and 7,762 Mcf of natural gas.  At the time of this report, the Kodesh #2 well is not producing oil because of a failure of the downhole pump which needs either to be repaired or








18
 
  replaced.  When natural gas prices have improved, we plan to replace the downhole pump and in addition to the reworking of the Kodesh #2, the operator is currently considering drilling a new well.





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, 2010, the Dye Estate #1 well has produced 5,762 Mcf of natural gas and is currently averaging natural gas production at a rate of 4 Mcf per day. 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 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, 2010, the William #4-10 well has produced 2,384 Bbls oil and 57,799 Mcf of gas.




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, 2010, the KC 80 #1-11 well is producing at a rate of 5 Bbls of oil and 35 Mcf of natural gas daily.  As of July 31, 2010, the KC 80 #1-11 has produced 5,543 Bbls of oil and 29,373 Mcf of natural gas.





It should be noted that all wells in the Three Sands Project were shut-in for most of the month of January 2010 while the operator was changing natural gas purchasers.  As of July 31, 2010, all wells were back producing.  During the nine-month period ended July 31, 2010, 300 Bbls of oil and 12,473 Mcf of natural gas were produced at the Three Sands Project.




Palmetto Point Project.  On February 28, 2006, we acquired a 10% working interest before completion and an 8.5% revenue interest after completion, in a 10-well program at the Palmetto Point Project operated by Griffin & Griffin Exploration LLC (“Griffin & Griffin”) for a total buy-in cost of $350,000 (the “Palmetto Point Project”). The Palmetto Point Project is located in Mississippi. On September 26, 2006, we acquired two additional wells (the PP F-6B and PP F52-A wells) within the Palmetto Point Project for $70,000.  On October 1, 2007, we acquired and participated in drilling two more wells within the Palmetto Point Project (the PP F-12-2 and PP F-12-3 wells) at a cost of $69,862. On October 25, 2007, we paid $17,000 for a sidetrack, a deviation of the existing PP-F-12-3 well at an angle to reach additional targeted oil sands.  The well was successfully completed as a flowing oil well.





On January 30, 2008, we incurred $36,498 for workovers to install submersible pumps.  From November 2008 to July 2009, we incurred $44,623 for the Belmont Lake Project.  The total cost of the Palmetto Point Project, including costs for the PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52 wells, was $641,820 as of July 31, 2010.




As of October 31, 2007, Griffin & Griffin drilled all ten of the wells in the Palmetto Point Project.  Eight of the wells were successful and two were dry holes which were not completed.  Seven of the eight successful wells were completed and are currently producing.  One of the eight wells, the PP F-12, was completed as a flowing oil well in early October 2007.  The PP F-12 well flowed oil at rates of over 100 Bbls per day and in December 2007 was offset by two additional wells in the project, the PP F-12-2 and PP F-12-3.  The PP F-12-2 was a dry hole and the PP F-12-3 was completed as a flowing oil well.





Both the PP F-12 PP F-12-3 oil well locations and several of our gas well locations have been flooded at the Palmetto Point Project.  Prior to the flooding, we had partly completed work to install gas lift pumps at each well; however, the work could not be completed before the locations were flooded.  There has been virtually no








19
 
  damage to our surface equipment located at the well heads, as our batteries and other production facilities are located above the flood waters.  Thus far, the only damage has been to our lost production because the wells had to be shut-in.  We do not believe that the flooding will adversely affect future oil recovery from these wells.





In early September 2008, flood waters had receded sufficiently and work began on placing the PP F-12 and PP F12-3 back on line and producing oil.  Gas lift pumps were installed on both wells and other modification and additional equipment such as compressors were also installed.  In late April 2010, the PP F-12A well was shut-in as the result of a paraffin build-up and will be treated and placed back into production in early September.  At the end of July 2010, the PP F-12 well was producing oil at rates of between 99 and 102 Bbls of oil per day.





The flood waters have receded, we plan to service the two producing wells in the near future and starting in early September to drill up to three additional well to better drain the reservoir.  Depending upon the thickness of the pay zone intercepted in the new wells, one well may be converted to a horizontal well to increase production.





For the three-month period ending July 31, 2010, a total of 7,320 Bbls of oil and no natural gas were produced at the Palmetto Point Project.





Mississippi Frio-Wilcox Joint Venture.  On August 2, 2006, we executed a memorandum agreement with Griffin & Griffin (as operator of the project), Delta Oil and Gas, Inc., Turner Valley Oil and Gas Company, Lexaria Corp., a Nevada corporation (“Lexaria”), and the Stallion Group to participate in two proposed drilling programs located in Southwest Mississippi and Northeast Louisiana, comprised of up to 50 natural gas and/or oil wells, at a price of $400,000 (the “Mississippi Frio-Wilcox Joint Venture”).  We hold a 10% working interest in the Mississippi Frio-Wilcox Joint Venture project before production and a prorated reduced working interest after production based on the operator’s interest portion.





On June 21, 2007, we assigned our interests and all future development obligations for any new wells in the Mississippi Frio-Wilcox Joint Venture to Lexaria for the sum of $1. We believe the assigned interests to be of nominal value.   We have maintained our original interest, rights, title and benefits to all seven wells drilled with our participation at the Mississippi Frio-Wilcox Joint Venture between August 3, 2006 and June 19, 2007, specifically wells CMR-USA-39-14, Dixon #1, Faust #1 TEC F-1, CMR/BR F-14, RB F-1 Red Bug #2, BR F-33, and Randall #1 F-4, and any offset wells that could be drilled to any of these specified wells.  We do not anticipate expending additional exploration funds on the project.





As of July 31, 2010, we have expended $400,000 in connection with the Mississippi Frio-Wilcox Joint Venture, including leasing, title, drilling, and casing.





Nine wells were drilled on the Mississippi Frio-Wilcox Joint Venture, of which, five wells were initially deemed successful and four wells were dry holes and were not completed.  One of the five wells initially deemed to be successful was the BR F-24.  However, subsequent testing of the BR F-24 indicated that it was not commercially viable and the well was plugged and abandoned in 2007.  The four remaining successful wells were the Faust #1, USA 39-14, USA 1-37 and the BR F-33.  The USA 39-14 has been completed and is now producing natural gas.  As of July 31, 2010, these four wells were shut-in natural gas wells with no production.  No further exploration wells are currently planned for this project.





King City Oil Field.  We entered into an agreement with Sunset Exploration effective May 25, 2009, 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 40% of dry hole costs 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. However, one line in the new series of seismic profiles is still being processed.  Data acquired and processed thus far indicates several potential drill targets.








20


International Exploration and Acquisition 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 nine-month period ended July 31, 2010 or during the fiscal years ended October 31, 2009 and 2008.  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 at least September 1, 2011.





Results of Operations





Three months ended July 31, 2010 compared to the three months ended July 31, 2009.We realized revenues of $254,173 during the three months ended July 31, 2010, compared with $135,126 during the three months ended July 31, 2009, an increase of $119,047, due to additional wells producing and an increase in commodity prices.  During the three-month period ended July 31, 2010, 3,145 Bbls of oil and 5,321 Mcf of gas were produced at our oil and gas properties, as compared to 1,941 Bbls of oil and 764 Mcf of gas for the three months ended July 31, 2009.





We incurred production costs of $20,119 during the three months ended July 31, 2010, compared with $23,156 during the three months ended July 31, 2009, a decrease of $3,037.  The decrease in our production costs is related to a decrease in the costs of production from our producing wells.





Our depletion and accretion costs were $106,446 during the three months ended July 31, 2010, compared with $59,512 during the three months ended July 31, 2009, an increase of $46,934.  The increase in our depletion costs is related to a decrease in the reserves of the Company and an increase in production from our wells.





Our general and administrative costs increased to $200,208 for the three months ended July 31, 2010, from $163,506 for the three months ended July 31, 2009.  The increase is primarily attributable to increases in consulting fees of $73,410.  We are attempting to expand our property base by locating other resources properties.  Accordingly, we have hired consultants to gather data on properties that may be of interest to us.  As of the date of this filing, we have not found a suitable acquisition.





For the three months ended July 31, 2010, we incurred a net loss of $70,899, compared to a net loss of $117,988 for the three months ended July 31, 2009.  The loss was largely attributable to the increase in our depletion and accretion costs and general and administrative costs, which was partially offset by an increase in revenues for the quarter ended July 31, 2010.





As a result of our net loss for the quarter, we had retained earnings of $835,591 at July 31, 2010.





Nine months ended July 31, 2010 compared to the nine months ended July 31, 2009.We realized revenues of $482,229 during the nine months ended July 31, 2010, compared with $245,405 during the nine months ended July 31, 2009, an increase of $236,824, due to additional wells producing and an increase in commodity prices.  During the nine-month period ended July 31, 2010, 6,178 Bbls of oil and 13,302 Mcf of gas were produced at our oil and gas properties, as compared to 3,964 Bbls of oil and 2,113 Mcf of gas for the nine months ended July 31, 2009.





We incurred production costs of $62,807 during the nine months ended July 31, 2010, compared with $75,612 during the nine months ended July 31, 2009, a decrease of $12,805.  The decrease in our production costs is





21
 
  related to a decrease in maintenance costs on wells during the prior period and a decrease in production costs as new wells were brought to production.





Our depletion and accretion costs were $175,458 during the nine months ended July 31, 2010, compared with $131,790 during the nine months ended July 31, 2009, an increase of $43,668.  This increase was caused by an increase in production from our wells.





Our general and administrative costs increased to $679,671 for the nine months ended July 31, 2010, from $435,569 for the nine months ended July 31, 2009.  The increase is primarily attributable to increases in consulting fees of $327,160.  We are attempting to expand our property base by locating other resources properties.  Accordingly, we have hired consultants to gather data on properties that may be of interest to us.  As of the date of this filing, we have not found a suitable acquisition.  In addition, we incurred stock-based compensation expense of $31,015 in the 2010 period as a result of stock options granted to our officers.





For the nine months ended July 31, 2010, we incurred a net loss of $433,085, compared to a net loss of $403,215 for the nine months ended July 31, 2009.  The loss was largely attributable to the increase in our general and administrative costs which was partially offset by an increase in revenues for the nine months ended July 31, 2010.





Liquidity and Capital Resources





As of July 31, 2010, we had cash of $1,328,452 and working capital of $1,583,672, compared to cash of $1,947,950 and working capital of $2,494,387 as of October 31, 2009.  Our accounts receivable increased to $147,456 at July 31, 2010, compared with $97,198 at October 31, 2009, an increase of $50,258.  In addition, our current liabilities increased to $95,242 at July 31, 2010, compared with $75,185 at October 31, 2009.




During the nine months ended July 31, 2010, net cash provided by operating activities was $91,605, compared to net cash used of $841,641 during the nine months ended July 31, 2009.  The principal reason for the change was due to corporate taxes recoverable.





Net cash used in investing activities during the nine months ended July 31, 2010 was $711,103, compared with $414,667 used during the nine months ended July 31, 2009.  The increase in net cash used in investing activities is due to our investments in oil and gas prospects.





Off-Balance Sheet Arrangements





As of July 31, 2010, 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 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 year end prices of oil and gas to estimated future production of proved oil and gas reserves as of year end, less estimated future expenditures





22





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”.  FASB ASC 410-20 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.  As of October 31, 2009 and 2008, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with FASB ASC 410-20.  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 wells. 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 information below reflects the change in the asset retirement obligations during the nine-month period ended July 31, 2010 and the year ended October 31, 2009:





July 31, 2010


October 31, 2009Balance, beginning of period

$
37,011


$
30,766Liabilities assumed


-



9,206Revisions


-



(6,653
)Accretion expense


3,330



3,692Balance, end of period

$
40,341


$
37,011





The reclamation obligation relates to the Kodesh, Dye Estate, KC 80 and William wells at the Three Sands Property; the Palmetto Point Project well at the Frio-Wilcox Project; and ARD#1-36, Bagwell#1-20, Selman#1-21, Selman#2-21, Jackson#1-18, Miss Gracie#1-18, Waunice#1-36 and Dennis#1-8 wells at Oklahoma Properties.  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





23
 
  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





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, 2010, being the date of our most recently completed fiscal quarter.  This evaluation was conducted under the supervision and with the participation of our officers, Leroy Halterman and Kulwant Sandher.  Based on this evaluation, Messrs. Halterman and Sandher concluded that the design and operation of our disclosure controls and procedures are not effective since the following material weaknesses exist:





·
We rely on external consultants for the preparation of our financial statements and reports.  As a result, our officers may not be able to identify errors and irregularities in the financial statements and reports.




·
We have an officer who is also a director.  Our board of directors consists of only two members.  Therefore, there is an inherent lack of segregation of duties and a limited independent governing board.




·
We rely 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, 2010 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





None.





Item 1A.         Risk Factors





Not required for smaller reporting companies.





24


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





None.





Item 3.            Defaults Upon Senior Securities





None.





Item 4.            Removed and Reserved





Not applicable.





Item 5.            Other Information





Not applicable





Item 6.            Exhibits.





Regulation

S-K Number
Exhibit3.1
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)4.1
Certificate of Designation of Rights, Preferences, and Privileges for Series A Preferred Stock (4)31.1
Rule 15d-14(a) Certification of Principal Executive Officer31.2
Rule 15d-14(a) Certification of Principal Financial Officer32.1
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 Officer32.2
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




(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.







25


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, 2010
By:
/s/  Leroy HaltermanLeroy HaltermanPresident and Secretary(principal executive officer)
 September 14, 2010
By:
/s/  Kulwant SandherKulwant SandherChief Financial Officer(principal financial and accounting officer)