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, 2011





[  ]
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 March 7, 2011








BRINX RESOURCES LTD.


INDEX





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

January 31, 2011 (unaudited) and October 31, 2010
4Statements of Operations (unaudited)

Three Months Ended January 31, 2011 and 2010
5Statements of Cash Flows (unaudited)

Three Months Ended January 31, 2011 and 2010
6Notes to Financial Statements (unaudited)
7Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
17Item 3.
Quantitative and Qualitative Disclosures About Market Risk
26Item 4.
Controls and Procedures
26PART II.
OTHER INFORMATIONItem 1.
Legal Proceedings
26Item 1A.
Risk Factors
26Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
26Item 3.
Defaults Upon Senior Securities
27Item 4.
Removed and Reserved
27Item 5.
Other Information
27Item 6.
Exhibits
27Signatures

28





2


Part I.         FINANCIAL INFORMATION





Item 1.              Financial Statements


3




BRINX RESOURCES LTD.BALANCE SHEETSJANUARY 31,


OCTOBER 31,2011


2010ASSETS

(Unaudited)


(Audited)Current assetsCash and cash equivalents

$
319,596


$
21,029Investment - Certificate of deposit


400,000



800,000Accounts receivable


240,447



148,924Prepaid expenses and deposit


87,920



128,055Total current assets


1,047,963



1,098,008Undeveloped mineral interests, at cost


811



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


2,737,585



2,577,519Total assets

$
3,786,359


$
3,676,338LIABILITIES AND STOCKHOLDERS' EQUITYCurrent liabilitiesAccounts payable and accrued liabilities

$
129,659


$
37,777Total current liabilities


129,659



37,777Asset retirement obligations


28,574



27,494Total liabilities


158,233



65,271Stockholders' 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



24,630Capital in excess of par value


2,868,057



2,868,057Retained earnings


735,439



718,380Total stockholders' equity


3,628,126



3,611,067Total liabilities and stockholders' equity

$
3,786,359


$
3,676,338


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







4





BRINX RESOURCES LTD.STATEMENTS OF OPERATIONS(UNAUDITED)FOR THE THREE MONTHSPERIOD ENDEDJANUARY 31,2011


2010REVENUESNatural gas and oil sales

$
373,759


$
121,025DIRECT COSTSProduction costs


58,824



17,578Depletion and accretion


95,159



37,539General and administrative


202,917



268,477Total Expenses


(356,900
)


(323,594
)OPERATING (LOSS)


16,859



(202,569
)OTHER INCOMEInterest income


200



-NET (LOSS) FOR THE PERIODS

$
17,059


$
(202,569
)Net Income Per Common Share- Basic

$
0.001


$
(0.008
)- Diluted

$
0.001


$
(0.008
)Weighted average number of common shares outstanding- Basic


24,629,832



24,529,832- Diluted


24,629,832



24,529,832









5





BRINX RESOURCES LTD.STATEMENTS OF CASH FLOWS(Unaudited)FOR THE THREE MONTHSPERIOD ENDEDJANUARY 31,2011


2010CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIESNet income (loss)

$
17,059


$
(202,569
)Adjustments to reconcile net income to net cash provided by(used in) operating activities:Stock based compensation (note 5)


-



15,558Depletion and accretion


95,159



37,539Changes in working capital:Decrease (Increase) in accounts receivable


(91,523
)


16,860Decrease (Increase) in prepaid expenses and deposit


40,135



(97,790
)Increase (Decrease) in accounts payable and accrued liabilities


91,882



(23,228
)Increase (Decrease) in income taxes receivable


-



(186
)Net cash provided by (used in) operating activities


152,712



(253,816
)CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIESInvestment - Certificate of deposit


400,000



-Payments on oil and gas interests


(254,145
)


(123,207
)Net cash provided by (used in) investing activities


145,855



(123,207
)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


298,567



(377,023
)Cash and cash equivalents, beginning of periods


21,029



1,947,950Cash and cash equivalents, end of periods

$
319,596


$
1,570,927SUPPLEMENTAL CASH FLOW INFORMATIONCash paid for taxes paid

$
-


$
1,386SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIESAssets retirement costs incurred

$
(1,080
)

$
(1,110
)Investment in natural oil and gas working interests included in

$
16,860


$
36,917accounts payable







6
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)





1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES





Brinx Resources Ltd. (the “Company”) was incorporated under the laws of the State of Nevada on December 23, 1998, and issued its initial common stock in February 2001.  The Company holds an undeveloped mineral interest located in New Mexico and holds oil and gas interests located in Oklahoma, 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 three-month period ended January 31, 2011 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, 2010.





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, 2010.





USE OF ESTIMATES





The preparation of financial statement 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)





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 ends, 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 January 31, 2011 and 2010, 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 (prior authoritative literature: SFAS No.  144) "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 (prior authoritative literature: SFAS No. 143) "Accounting for Asset Retirement Obligations," that addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.





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





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




8
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)
  
 1.
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)





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 three months period ended January 31, 2011, since they out of the money.  The table below presents the computation of basic and diluted earnings per share for the three months periods ended January 31, 2011 and 2010:





January 31, 2011


January 31, 2010Basic earnings per share computation:(Loss) from continuing operations and net income

$
17,059


$
(202,569
)Basic shares outstanding


24,629,832



24,529,832Basic earnings per share

$
0.00


$
(0.01
)Diluted earnings per share computation:(Loss) from continuing operations

$
17,059


$
(202,569
)Basic shares outstanding


24,629,832



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


-



-Warrants


-



-Diluted shares outstanding


24,629,832



24,529,832Diluted earnings per share

$
0.00


$
(0.01
)





The calculation for earnings per share excluded 500,000 stock options and 400,000 stock options as these were not in the money as at January 31, 2011 and 2010, respectively.





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.





FAIR VALUE





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





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





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





Level 3 inputs to valuation methodology are unobservable and significant to the fair measurement.





9
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)
  
 1.
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)





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.





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 (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:




Three months periods endedJanuary 31, 2011
January 31, 2010Expected volatility
-
219%Risk-free interest rate
-
0.92%Expected life
-
2 yearsDividend yield
-
0.00%





RECENT ACCOUNTING PRONOUNCEMENTS





In January 2010, the FASB issued Accounting Standards Update 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. The ASU amends Subtopic 820-10 with new disclosure requirements and clarification of existing disclosure requirements. New disclosures required include the amount of significant transfers in and out of levels 1 and 2 fair value measurements and the reasons for the transfers. In addition, the reconciliation for level 3 activity will be required on a gross rather than net basis. The ASU provides additional guidance related to the level of disaggregation in determining classes of assets and liabilities and disclosures about inputs and valuation techniques. The amendments are effective for annual or interim reporting periods beginning after December 15, 2009, except for the requirement to provide the reconciliation for level 3 activities on a gross basis, which will be effective for fiscal years beginning after December 15, 2010. The Company is currently assessing the impact of ASU 2010-06 and does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.





10
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)
  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 their 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, 2011 and October 31, 2010.  Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.


January 31, 2011


October 31, 2010Accounts receivable

$
240,447


$
148,924Less: allowance for doubtful account


-



-$
240,447


$
148,924








3.
OIL AND GAS INTERESTS




The Company holds the following oil and natural gas interests:


January 31, 2011


October 31, 20102008-3 Drilling Program, Oklahoma

$
262,389


$
257,5642009-2 Drilling Program, Oklahoma


115,582



115,5822009-3 Drilling Program, Oklahoma


296,110



294,1642009-4 Drilling Program, Oklahoma


192,771



172,5302010-1 Drilling Program, Oklahoma


259,575



232,212Washita Bend 3D, Oklahoma


357,517



337,398Kings City Prospect, California


106,091



106,091Three Sands Project, Oklahoma


1,409,115



1,279,633South Wayne Prospect, Oklahoma


61,113



60,914Palmetto 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


362,600



312,630Asset retirement cost


8,992



8,992Less: Accumulated depletion and impairment


(1,514,270
)


(1,420,191
)$
2,737,585


$
2,577,519


2008-3 Drilling Program, Oklahoma




On January 12, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The Before Casing Point Interest “BCP” shall be 6.25% and the After Casing Point Interest “ACP” shall be 5.00%.  During January to July 2009, the Company expended a $213,925 in addition to $18,850 that was spent in previous periods.  The well, Wigley#1-11, was abandoned during March 2009.  The cost and its buy-in cost total of $33,423 were moved to the proved properties.  Selman#1-21 and Bagwell#1-20 started producing during May 2009, 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 was moved to the proved properties.  Selman#2-21 started producing during July 2009 and was abandoned on April 20, 2010; the cost and its buy-in cost total of $57,483 were moved to the proved properties pool.  The total cost of the 2008-3 Drilling Program as at January 31, 2011 was $262,389.  The interests are located in Garvin County, Oklahoma.


11
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)
  3.            OIL AND GAS INTERESTS (continued)





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 January 31, 2011, the total cost of the 2009-2 Drilling Program was $115,582.  The interests are located in Garvin County, Oklahoma.





2009-3 Drilling Program, Oklahoma





On August 12, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  Jackson#1-18 started producing during January 2010; an amount of $63,725 which included the buy-in cost was moved to the proved property pool.  Miss Gracie#1-18 started producing during March 2010; an amount of $62,268 which included its buy-in cost was moved to the proved property pool.  Brewer#1-20 was abandoned on June 2, 2010; the cost and its buy-in cost total of $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 property pool, it was abandoned on September 23, 2010.   As at January 31, 2011, the total cost of the 2009-3 Drilling Program was $296,110.  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 property pool, it was abandoned on September 27, 2010.  Dennis#2-8 was abandoned on November 17, 2010; an amount of $34,068 which included the buy-in cost was moved to the proved property pool.  Murray Trust#3-19 was abandoned on December 13, 2010; an amount of $12,917 which included the buy-in cost was moved to the proved property pool.  Murray Trust#2-19 started producing during November 2010; an amount of $52,910 which included the buy-in cost was moved to the proved property pool.     As at January 31, 2011, the total cost of the 2009-4 Drilling Program was $192,771.  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 for a total buy-in cost of $39,163  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  Julie#1-14 was abandoned on October 2, 2010; the cost and its buy-in cost total of $47,035 were moved to the proved properties.  Jack#1-13 started producing during November 2010; an amount of $73,993 which included the buy-in cost was moved to the proved property pool.  Miss Jenny started producing during December 2010; an amount of $61,640 which included the buy-in cost was moved to the proved property pool.  The estimated completion cost of $16,860 for Jack 1-13 was accrued for the three months period ended.  As at January 31, 2011, the total cost of the 2010-1 Drilling Program was $259,575.  The interests are located in Garvin County, Oklahoma.


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


3.
OIL AND GAS INTERESTS (continued)





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.  As at January 31, 2011, the total costs, including seismic costs was $357,517.





Kings City Prospect, California





A Farmout agreement was made effective on May 25, 2009 between the Company and Sunset Exploration, Inc., to explore for oil and natural gas on 10,000 acres located in west central California.  The Company paid $100,000 (50% pro rata share of $200,000)  to earn a 20% working interest in project by funding a maximum of 50% of a $200,000 in a geophysical survey composed of gravity and seismic surveys and carry Sunset exploration for 33.33% of dry hole cost of the first well.  Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each parties working interest.  The total cost of the King City prospect as at January 31, 2011 was $106,091.





Three Sands Project, Oklahoma





On October 6, 2005, the Company acquired a 40% working interest in Vector Exploration Inc’s Three Sands Project for a total buy-in cost of $88,000 plus dry hole costs.  For the year ended October 31, 2006, the Company expended $530,081 in exploration costs.  In June 2007, the Company acquired a 40% working interest in William #4-10 well for a total cost of $285,196 and paid a further $17,000 in costs relating to the well.  On March 19, 2008, the Company participated in the KC 80#1-11 well and paid $75,000 for the prepaid drilling costs.  During March and April 2008, the Company expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 during May to July 2008 for the KC 80#1-11 well.  The total cost of the Three Sands Project as at January 31, 2011 was $1,409,115.  The interests are located in Oklahoma.





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 as at January 31, 2011 was $61,113.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The interests are located in McClain County, Oklahoma.  The total costs of the South Wayne prospect as at January 31, 2011 was $61,113.





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, were $782,600 as of January 31, 2011.  The interests are located in Mississippi.





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





3.           OIL AND GAS INTERESTS (continued)





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 three months periods ended January 31, 2011 and 2010, respectively.





Depletion





Under the full cost method, depletion is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production.  Depletion expense recognized was $94,079 and $36,429 for the three months periods ended January 31, 2011 and 2010, respectively.





Capitalized Costs


January 31, 2011


October 31, 2010Proved properties

$
3,649,177


$
3,188,673Unproved properties


602,678



809,037Total Proved and Unproved properties


4,251,855



3,997,710Accumulated depletion expense


(1,294,731
)


(1,200,652
)Impairment


(219,539
)


(219,539
)Net capitalized cost

$
2,737,585


$
2,577,519





Results of Operations





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


January 31, 2011


January 31, 2010Revenues

$
373,759


$
121,025Production costs


(58,824
)


(17,578
)Depletion and accretion


(95,159
)


(37,539
)Results of operations (excluding corporate overhead)

$
219,776


$
65,908




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





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 January 31, 2011 and October 31, 2010, 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 three months period ended January 31, 2011 and the year ended October 31, 2010:





January 31, 2011


October 31, 2010Balance, beginning of periods

$
27,494


$
37,011Liabilities assumed


-



2,700Revisions


-



(16,658
)Accretion expense


1,080



4,441Balance, end of years

$
28,574


$
27,494





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, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24, Jack#1-13 and Miss jenny#1-8 wells at Oklahoma Properties.  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.




15
 BRINX RESOURCES LTD.
 NOTES TO FINANCIAL STATEMENTS
 (Unaudited)





5.            COMMON STOCK (continued)





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 $15,585 and $136 and for stock compensation expenses for the years ended October 31, 2010 and 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 $23,581 for stock compensation expenses for the year ended October 31, 2010.





A summary of the changes in stock options for the three months ended January 31, 2011 is presented below:





Options OutstandingNumber of Shares


Weighted Average

Exercise PriceBalance, October 31, 2009


400,000


$
0.17Granted on November 2, 2009


300,000



0.10Expired on November 2, 2009


(200,000
)


0.24Exercised


-



-Balance, October 31, 2010


500,000


$
0.10Balance, January 31, 2011


500,000


$
0.10





The Company has the following options outstanding and exercisable.





January 31, 2011
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
0.74 years

0.75 years
0.10

0.10








6.                      RELATED PARTY TRANSACTIONS





During the three months periods ended January 31, 2011 and 2010, the Company entered into the following transactions with related parties:





a)
The Company paid $18,000 (2010 - $15,000) in management fees and reimbursement of office space of $1,200 (2010 - $1,200) to the President of the Company.





b)
The Company paid $17,000 (2010 - $15,000) to a related entity, for administration services.





c)
The Company paid $24,500 (2010 - $22,500) in management fees to the director of the Company.





d)
The Company paid $19,035 (2010 - $17,566) in consulting and accounting fees to the Chief Financial Officer of the Company.




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, 2010 or 2009 or the three months ended January 31, 2011.  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, the Company has expanded and will 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 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 $213,925 in addition to $18,850 that was spent in previous periods.  The total cost of the 2008-3 Drilling Program as of January 31, 2011 was $262,389.  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.





17
 
 During calendar year 2011 at least one development well is planned to be drilled.  As of January 31, 2011, the two producing wells in this program have produced a total of 143,435 Bbls of oil and 24,741 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 shall be 6.25% and the ACP Interest shall be 5.00%.  The interests are located in Garvin County, Oklahoma.  A total of three wells were drilled in this program and targeted pay zones that were the same as in the 2008-3 program.  The zones included the prolific Oil Creek, Bromide Sands, Viola, Deese and Layton Sandstone. This program is composed of three 3-D seismically defined separate prospects.   All wells were drilled in the last fiscal quarter of 2009. Two of the wells were deemed non-commercial and were plugged and abandoned.  Production casing was set on one of the three wells and completion efforts have taken place on the third well; however, after testing it was also deemed non-commercial and plugged.  As of January 31, 2011, the total cost of the 2009-2 Drilling Program was $115,582.





2009-3 Drilling Program, Oklahoma.On August 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775.  We agreed to participate in the drilling operations to casing point in the initial test well on each of four prospects.   The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total costs incurred, including drilling costs, as of January 31, 2011 was $296,110.  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 2010 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 2010 and that well is currently producing as a naturally flowing oil and gas well.  Total production from these two producing wells as of January 31, 2011 totaled 91,167 Bbls of oil and 27,041 Mcf of natural gas.





In late June 2010, a successful development well was drilled as an offset to the naturally flowing well that is still producing at a rate of 230 Bbls oil and 34 Mcf of natural gas per day.  This development well was completed in early August 2010 and is flowing at a rate of 330 Bbls of oil and 37 Mcf of natural gas per day and should add significantly to this program’s future oil and gas production.  Total production from this producing well as of January 31, 2011 was 50,068 Bbls of oil and 5,321 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 shall be 6.25% and the ACP Interest shall be 5.00%.  The total costs incurred, including drilling costs, as of January 31, 2011 was $192,771.  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





18
 
 and abandoned.  Another well is being drilled as a twin to this well.  If it is not successful it will be left unplugged as a possible salt water disposal well.  As of January 31, 2011, both wells have been plugged and abandoned after producing a few thousand barrels of oil and Mcf of natural gas.





2010-1 Program, Oklahoma.On April 23, 2010, we acquired a 5% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,163.  We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects.   The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total cost incurred, including drilling costs, as of January 31, 2011 was $259,575.  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.  Two of the wells have been completed in the deepest pay zone with one well producing between 90 to 110 barrels of oil water free and the second was producing at a rate of 360 to 400 barrels of oil per day in early December 2010.  An offset development well to the previously mentioned high flow rate well is planned for the second or third fiscal quarter.  Total production from these wells as of January 31, 2011 was 28,553 Bbls of oil and 508 Mcf of natural gas.  It should be noted that several of the wells produced for only one or two months prior to the end of the fiscal quarter.  The wells are now producing at a combined rate of 420 Bbls of oil and 9 Mcf of natural gas.  Two of the wells are waiting pipeline connection before they can start selling 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 shall be 6.25% and the ACP Interest shall be 5.00%.  The total cost incurred, including drilling costs, as of January 31, 2011 was $61,113.  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 at a rate of 33 Bbls of oil and 41 Mcf of natural gas and no water.  Total production for the McPherson well as of January 31, 2011 was 11,648 Bbls of oil and 4,964 Mcf of natural gas.




Washita Bend 3D Exploration Project, Oklahoma.On March 1, 2010, we agreed to participate with a 5% working interest in a 3-D seismic program managed by Ranken Energy Corporation for a buy-in cost of $46,250.  The Oklahoma 3-D seismic program will cover approximately 135 square miles in a known oil and gas producing area.   An earlier 2-D seismic program over the same area indicated a number of untested structures.  We expect the 3-D program will refine and better define the structures discovered during the earlier program and pinpoint drill locations.  We will participate in the seismic program and the related prospect generation and acquisition phase without any promotion.  The BCP Interest shall be 5.625% and the ACP Interest shall be 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  The total cost, including seismic costs, as of January 31, 2011 was $357,517.




Work has commenced on this project. Shooting and data acquisition started on the Oklahoma 3-D project in late February 2011. The project is slated to cover approximately 86,350 acres or 135 square miles of which approximately 83,043 acres or 130 square miles have now been permitted. Weather related delays have intermittently forced postponement of the actual data gathering portion of the project which is now underway.





The project will employ 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 will pinpoint these locations, dramatically reducing





19
 
 the risk of drilling dry holes. A total of 5,148 acres of leases have been acquired thus far and leasing of additional land may start in the next several months.  Drilling testing of these targets could begin in mid-summer.





Three Sands Project





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





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





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





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





Costs Including Previous Work.As of January 31, 2011, we have expended $1,409,115 in connection with the Three Sands Project, including leasing, title, drilling, and casing.





Present Activities.Drilling of the Kodesh #1 disposal well was completed on October 3, 2005 and drilling of the Kodesh #2 well was completed on October 23, 2005. Completion and equipping of these wells took place during mid-December 2005 through early January 2006.  The Kodesh #1 is being used for salt water disposal well.  In December 2010 and January 2011, the pump was replaced and new pay zones were perforated and fracture treated, thereby increasing production of oil and natural gas.  The Kodesh #2 is not producing oil and natural gas on a daily basis.  As of January 31, 2011, it has produced 3,762 Bbls of oil and 8,473 Mcf of natural gas.





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 January 31, 2011, the Dye Estate #1 well has produced 6,809 Mcf of natural gas and is currently averaging natural gas production at a rate of 6 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 January 31, 2011, the William #4-10 well has produced 2,526 Bbls oil and 77,774 Mcf of gas.  The well is currently producing at a rate of 1 barrel of oil per day and 117 Mcf of natural 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.





20


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 January 31, 2011, the KC 80 #1-11 well is producing at a rate of 3.5 Bbls of oil and 30 Mcf of natural gas daily.  As of January 31, 2011, the KC 80 #1-11 has produced 5,378 Bbls of oil and 35,568 Mcf of natural gas.





Drilling commenced on the Taylor #1 well on October 7, 2010 and reached a total depth of 4,825 feet on October 14, 2010.  The primary target of the well was the Mississippian Limestone.  The well was fracture treated in mid-December 2010 and production testing will follow.  There was no production from this well prior to mid-December 2010.  Production from this well as of January 31, 2011 totaled 887 Bbls of oil nad 5,961 Mcf of natural gas





Palmetto Point Project





Location and Access.The Palmetto Point Project is located on the border of southern Mississippi and Louisiana along the floodplain of the Mississippi river. The area is approximately 20 miles west of Woodville, Mississippi and approximately 50 miles northwest of Baton Rouge, Louisiana.  The wells are located in Township 2 North, Ranges 4 & 5, in West Adams and Wilkinson Counties in the state of Mississippi. The area may be accessed via Interstate 55 (approximately 100 miles south of Jackson, Mississippi) and then west via state highways.  The drill locations are accessed by secondary gravel and dirt roads. Transporting natural gas to the market will be accomplished via a series of pipelines which cross the project area.





Previous Operations and History. Griffin & Griffin, the operator for the Palmetto Point Project, has over 40 years of operations history in the Palmetto Point Project area and has acquired substantial data and 3-D seismic data for the Palmetto Point Project.  To date, Griffin & Griffin has drilled, owned or operated more than 100 Frio wells in the region. More specifically, Griffin & Griffin has drilled to a subsurface depth and has penetrated the sands of the Frio Formation on the Palmetto Point Project.





Geology of the Palmetto Point Project. The prospect wells were located to test the Frio Geological Formation. Frio wells typically enjoy low finding costs. Griffin & Griffin has utilized seismic “bright spot” technology, which helps to identify gas reservoirs and to delineate reservoir geometry and limits. The term “bright spot” is used to describe a geophysical amplitude anomaly, which is simply a velocity change from a higher velocity to lower velocity.  Sands that contain gas are predictable by this method because the gas will provide a slower velocity response giving an abnormally intense trough-peak reflections, therefore termed a “bright spot”. The data evaluation in the Frio section gives a direct hydrocarbon indication (“HCI”) allowing one to not only see gas seismically, but also the lateral extent of each gas reservoir at various depths to include multiple horizons at some locations.





The gas targets at the Palmetto Point Project occur at shallow depths and have minimal completion costs. The Frio project in the area of Southwest Mississippi and North-Central Louisiana is a very complex series of sand representing marine transgressions and regressions and resulting in the presence of varying depositional environments. Structurally, the Frio gas accumulations are a function of local structure and/or structural nose formed as a result of differential compaction features. However, stratigraphic termination (updip pinchout of sands within shales) also plays a role in most Frio accumulations. The stratigraphy is so complex that seismic direct HCI evaluations are presently the only viable exploratory tool for the Frio prospect.





Proposed Program of Exploration.  The Palmetto Point Project program has been completed and no further exploration wells are planned.  We are assessing additional development wells in the Belmont Lake oil field discovered by the PP F-12 well.  The Mississippi Frio-Wilcox Joint Venture program described below is the successor to the Palmetto Point Program and will continue our exploration and development in the Frio and Wilcox projects.





Costs Including Previous Work.As of January 31, 2011, we have expended $782,600in connection with the Palmetto Point Project, including leasing, title, drilling, and casing.





21


Present Activities.As of October 31, 2007, Griffin & Griffin, operator of the Palmetto Point Project, 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-3 was completed as a flowing oil well.





Both the PP F-12 and the PP F-3 oil well locations and several of our gas well locations were 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 was virtually no damage to our surface equipment located at the well heads, as our batteries and other production facilities were located above the flood waters.  The only damage was to our lost production because the well 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.  At the end of October 2009 both wells were producing oil at combined rates of between 80 and 100 barrels of oil per day.





In early September 2010, flood waters had receded sufficiently again to resume work on the Palmetto Point Project and three development wells were drilled in the field.  One well encountered only natural gas and was plugged and abandoned.  The remaining two wells were completed as oil wells.  One of the completed oil wells flowed naturally and contributed approximately 2,000 barrels of oil to the production totals prior to October 31, 2010.  Present activities include completion of a source gas well, completing a salt water disposal well and running gas injection line and production line to the new wells and tanks battery.  All four oil wells including both the new wells and previously drilled and completed well should be in production by the start of the second fiscal quarter.





During the three-month period ended January 31, 2011, the Belmont Lake Oil field produced 12,711 Bbls of oil and all natural gas produced was consumed on the lease for compression and gas lift for the oil produced.





Mississippi Frio-Wilcox Joint Venture





Location and Access. The Mississippi Frio-Wilcox Joint Venture is located on the border of southern Mississippi and Louisiana along the floodplain of the Mississippi river. The area is approximately 20 miles west of Woodville, Mississippi and approximately 50 miles northwest of Baton Rouge, Louisiana.  The wells are located in Township 2 North, Ranges 4 & 5, in West Adams and Wilkinson Counties in the state of Mississippi. The area is accessible via Interstate 55 (approximately 100 miles south of Jackson, Mississippi) and then west via state highways.  The drill locations are accessed by secondary gravel and dirt roads. Transporting natural gas to the market will be accomplished via a series of pipelines which cross the project area.





Previous Operations and History.  As described above, we participated in the ten-well Palmetto Point Project program in the same area as the Mississippi Frio-Wilcox Joint Venture. The Mississippi Frio-Wilcox Joint Venture is the successor to the Palmetto Point Project. Griffin & Griffin, the operator for the Palmetto Point Project, is also the operator for the Mississippi Frio-Wilcox Joint Venture.  Griffin & Griffin has over 40 years of operations history in the Mississippi Frio-Wilcox Joint Venture area and has acquired substantial data and 3-D seismic for the Mississippi Frio-Wilcox Joint Venture.  To date, Griffin & Griffin has drilled, owned or operated more than 100 Frio wells in the region.





Geology of the Palmetto Point Project.The prospect wells are located to test the Frio Geological Formation. The gas targets at the Mississippi Frio-Wilcox Joint Venture occur at shallow depths and have minimal completion costs. The Frio in the area of Southwest Mississippi and North-Central Louisiana is a very complex series of sand representing marine transgressions and regressions and resulting in the presence of varying depositional environments. Structurally, the Frio gas accumulations are a function of local structure and/or structural nose formed as a result of differential compaction features. However, stratigraphic termination (updip pinchout of sands within shales) also plays a role in most Frio accumulations. The stratigraphy is so complex that seismic HCI evaluations are the only viable exploratory tool for the Mississippi Frio-Wilcox Joint Venture.





22


Proposed Program of Exploration.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 interest 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.





Costs Including Previous Work.As of January 31, 2011, we have expended $400,000 in connection with the Mississippi Frio-Wilcox Joint Venture, including leasing, title, drilling, and casing.





Present Activities.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 October 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





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.  Based on this data, two drill locations have been selected and permitting is underway.  Drilling of one of these locations is anticipated in the spring of 2011.





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, 2011 or during the fiscal years ended October 31, 2010 and 2009.  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 January 31, 2011 compared to the three months ended January 31, 2010.We realized revenues of $373,759 during the three months ended January 31, 2011, compared with $121,025 during the three months ended January 31, 2010, an increase of $252,734, due to additional wells producing and an increase in commodity prices.  During the three-month period ended January 31, 2011, 4,229 Bbls of oil and 3,039 Mcf of gas





23
 
 were produced at our oil and gas properties, as compared to 1,358 Bbls of oil and 3,204 Mcf of gas for the three months ended January 31, 2010.





We incurred production costs of $58,824 during the three months ended January 31, 2011, compared with $17,578 during the three months ended January 31, 2010, an increase of $41,246.  The increase in our production costs is related to an increase in the costs of production from our producing wells.





Our depletion and accretion costs were $95,159 during the three months ended January 31, 2011, compared with $37,539 during the three months ended January 31, 2010, an increase of $57,620.  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 decreased to $202,917 for the three months ended January 31, 2011, from $268,477 for the three months ended January 31, 2010.  The decrease is primarily attributable to decreases in investor relations expenses of $35,230, consulting fees of $28,695, stock based compensation expenses of $15,558 and legal expenses of $15, 119.





For the three months ended January 31, 2011, we incurred net income of $17,059, compared to a net loss of $202,569 for the three months ended January 31, 2010.  The profit was largely attributable to a 209% increase in revenues for the quarter, with only a 10% increase in expenses.





As a result of our net income for the quarter, we had retained earnings of $735,439 at January 31, 2011.





Liquidity and Capital Resources





As of January 31, 2011, we had cash and a certificate of deposit totaling $719,596 and working capital of $918,304, compared to cash and a certificate of deposit totaling $821,029 and working capital of $1,060,231 as of October 31, 2010.  Our accounts receivable increased to $240,447 at January 31, 2011, compared with $148,924 at October 31, 2010, an increase of $91,523.  In addition, our current liabilities increased to $129,659 at January 31, 2011, compared with $37,777 at October 31, 2010.





During the three months ended January 31, 2011, operating activities provided cash of $152,712, as compared to using net cash of $253,816 for the quarter ended January 31, 2010.  The principal reason for the change was due to the profitable operations for the 2011 quarter.





Investing activities provided net cash of $145,855 during the three months ended January 31, 2011, compared with $123,207 used during the three months ended January 31, 2010.  While more cash was used for payments on oil and gas prospects during the 2011 quarter, we also redeemed a $400,000 certificate of deposit.





Off-Balance Sheet Arrangements





As of January 31, 2011, 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





24





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 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 January 31, 2011 and October 31, 2010, 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 three-month period ended January 31, 2011 and the year ended October 31, 2010:





January 31, 2011


October 31, 2010Balance, beginning of period

$
27,494


$
37,011Liabilities assumed


-



2,700Revisions


-



(16,658
)Accretion expense


1,080



4,441Balance, end of period

$
28,574


$
27,494





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, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24, Jack#1-13 and Miss Jenny#1-8 wells at Oklahoma Properties.  The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes in applicable laws and regulations.  Such changes will be recorded in our accounts as they occur.





Reserve Estimates.Our estimates of oil and natural gas reserves are projections based on an interpretation of geological and engineering data.  There are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures.  Estimates of the economically   recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on the risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially.  Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.





Forward Looking Statements





Certain statements in this Quarterly Report on Form 10-Q as well as statements made by us in periodic press releases and oral statements made by our officials to analysts and shareholders in the course of presentations about the Company, constitute “forward-looking statements”.   Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward looking statements.  Such factors include, among other things, (1) general economic and business conditions; (2) interest rate changes; (3) the relative stability of the debt and equity markets; (4) government regulations particularly





25
 
 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, 2011, 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 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 January 31, 2011 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.





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





None.





26





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.







27


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 16, 2011                                                                                     By:  /s/ Leroy Halterman


Leroy Halterman


President and Secretary


(principal executive officer)











March 16, 2011                                                                                     By:  /s/ Kulwant Sandher


Kulwant Sandher


Chief Financial Officer


(principal financial and accounting officer)