Brinx Resources (BNXR) 10-Q 2009 Q2 Quarterly report

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 April 30, 2009

[  ] 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

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:  24,529,832 shares of Common Stock, $0.001 par value, as of May 31, 2009

BRINX RESOURCES LTD.

INDEX

		Page
PART I.	UNAUDITED FINANCIAL INFORMATION
Item 1.	Interim Financial Statements
	Balance Sheets April 30, 2009 (unaudited) and October 31, 2008	3
	Statements of Operations (unaudited) Three and Six Months Ended April 30, 2009 and 2008	4
	Statements of Cash Flows (unaudited) Six Months Ended April 30, 2009 and 2008	5
	Notes to Financial Statements (unaudited)	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	18
Item 4.	Controls and Procedures	19
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	20
Item 1A.	Risk Factors	20
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	20
Item 3.	Defaults Upon Senior Securities	20
Item 4.	Submission of Matters to a Vote of Security Holders	20
Item 5.	Other Information	20
Item 6.	Exhibits	20
Signatures		21

2

BRINX RESOURCES LTD.

BALANCE SHEETS
 

	April 30		OCTOBER 31
	2009		2008
ASSETS	(UNAUDITED)		(AUDITED)
Current assets
Cash and cash equivalents	$	2,634,952	$	3,617,109
Accounts receivable		31,765		71,377
Prepaid expenses and deposit		12,500		15,808
Total current assets		2,679,217		3,704,294
Undeveloped mineral interests, at cost		811		811
Oil and gas interests, full cost method of accounting,
net of accumulated depletion		1,319,977		1,152,365
Total assets	$	4,000,005	$	4,857,470
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	8,320	$	2,404
Income taxes payable		-		580,000
Total current liabilities		8,320		582,404
Deferred income taxes		337,717		337,717
Asset retirement obligations		32,612		30,766
Total liabilities		378,649		950,887
Commitments and contingencies
Stockholders' equity
Preferred stock - $0.01 par value; authorized - 1,000,000 shares
Issued - none		-		-
Common stock - $0.001 par value; authorized - 100,000,000 shares
Issued and outstanding - 24,529,832 shares		24,530		24,530
Capital in excess of par value		2,801,855		2,801,855
Retained earnings		794,971		1,080,198
Total stockholders' equity		3,621,356		3,906,583
Total liabilities and stockholders' equity	$	4,000,005	$	4,857,470

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

3

BRINX RESOURCES LTD.

STATEMENTS OF OPERATIONS

(Unaudited)

	FOR THE THREE MONTHS						FOR THE SIX MONTHS
	PERIOD ENDED						PERIOD ENDED
	APRIL 30,						APRIL 30,
	2009			2008			2009			2008
REVENUES
Natural gas and oil sales	$	42,150		$	380,472		$	110,279		$	875,764
DIRECT COSTS
Production costs		22,042			72,685			52,456			139,710
Depletion and accretion		29,073			62,075			72,278			145,130
Impairment		-			-			-			-
General and administrative		154,724			110,261			272,063			232,008
		(205,839	)		(245,021	)		(396,797	)		(516,848	)
OPERATING INCOME (LOSS)		(163,689	)		135,451			(286,518	)		358,916
OTHER INCOME AND EXPENSE
Interest income		-			-			1,291			-
Interest expense - related		-			-			-			(209	)
NET INCOME (LOSS) FOR THE PERIOD	$	(163,689	)	$	135,451		$	(285,227	)	$	358,707
Net Income Per Common Share
- Basic	$	(0.007	)	$	0.006		$	(0.012	)	$	0.015
- Diluted	$	(0.007	)	$	0.005		$	(0.012	)	$	0.014
Weighted average number of common shares outstanding
- Basic		24,529,832			24,529,832			24,529,832			24,529,832
- Diluted		24,529,832			25,299,042			24,529,832			25,299,042

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

4

BRINX RESOURCES LTD.

STATEMENTS OF CASH FLOWS

(Unaudited)

	FOR THE SIX MONTHS
	PERIOD ENDED
	APRIL 30,
	2009			2008
CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES
Net income (loss)	$	(285,227	)	$	358,707
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Stock based compensation (note 6)		-			26,077
Depletion and accretion		72,278			145,130
Changes in working capital:
Decrease (increase) in accounts receivable		39,612			48,546
Decrease in prepaid expenses and deposit		3,308			-
Increase (decrease) in accounts payable and accrued liabilities		5,916			(85,445	)
Interest accrued to related party notes		-			209
Increase (Decrease) in due to related party					3,829
(Decrease) in deferred income taxes		(580,000	)		-
Net cash provided by (used in) operating activities		(744,113	)		497,053
CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES
Expenditures on oil and gas interests		(238,044	)		(143,779	)
Net cash (used in) investing activities		(238,044	)		(143,779	)
CASH FLOWS PROVDED BY (USED IN) FINANCING ACTIVITIES
Repayment of loan to related party		-			(20,714	)
Net cash (used in) financing activities		-			(20,714	)
Net increase (decrease) in cash		(982,157	)		332,560
Cash and cash equivalents, beginning of periods		3,617,109			42,257
Cash and cash equivalents, end of periods	$	2,634,952		$	374,817
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Assets retirement costs incurred	$	(1,846	)	$	(2,075	)
Assets retirement obligation incurred	$	1,846		$	2,075
Reduction in full cost pool due to change in estimated drilling costs	$	-		$	48,760

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

5

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, Mississippi and Louisiana.  In 2006, the Company commenced oil and gas production and started earning revenues.  Prior to 2006, the Company was considered a development stage company as defined by Statement of Financial Accounting Standards (“SFAS”) No. 7.  Effective 2006, the Company ceased being considered a development stage company.

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 six months period ended April 30, 2009 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, 2008.

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, 2008.

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.

6

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (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, and 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.

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 April 30, 2009 and 2008, 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.  The table below presents the computation of basic and diluted earnings per share for the six months periods ended April 30, 2009 and 2008:

	April 30, 2009			April 30, 2008
Basic earnings per share computation:
Income (Loss) from continuing operations	$	(285,227	)	$	358,707
Basic shares outstanding		24,529,832			24,529,832
Basic earnings per share	$	(0.012	)	$	0.015
Diluted earnings per share computation:
Income (Loss) from continuing operations	$	(285,227	)	$	358,707
Basic shares outstanding		24,529,832			24,529,832
Incremental shares from assumed conversions:
Stock options		-			200,000
Warrants		-			569,210
Diluted shares outstanding		24,529,832			25,299,042
Diluted earnings per share	$	(0.012	)	$	0.014

The calculation for earnings per share excluded 200,000 stock options as these were not in the money as at April 30, 2009.

7

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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

EQUITY BASED COMPENSATION

Effective November 1 2006, the Company adopted the fair value recognition provisions of SFAS 123(R), “Share Based Payment”, using the modified prospective method as described in SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”.

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:

	Six months period ended
	April 30, 2009	April 30, 2008
Expected volatility	0.00%	100.36%
Risk-free interest rate	0.00%	4.50%
Expected life	0 years	2 years
Dividend 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 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 April 30, 2009 and October 31, 2008.  Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.

	April 30, 2009		October 31, 2008
Accounts receivable	$	31,765	$	71,377
Less: allowance for doubtful account		-		-
	$	31,765	$	71,377

3.   OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:

	April 30, 2009			October 31, 2008
2008-3 Drilling Program, Oklahoma	$	192,498		$	-
Three Sands Project, Oklahoma		1,197,523			1,196,600
Palmetto Point Project, Mississippi		420,000			420,000
Frio-Wilcox Prospect, Mississippi		400,000			400,000
PP F-12-2, PP F-12-3 and PP F-52, Mississippi		178,191			133,568
Asset retirement cost		20,396			20,396
Less: Accumulated depletion and impairment		(1,088,631	)		(1,018,199	)
	$	1,319,977		$	1,152,365

8

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

3.   OIL AND GAS INTERESTS (continued)

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 $28,581.25.  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 2009, the Company expended an amount of $51,013 for the estimated drilling costs. From February to April 2009, the Company expended an additional $112,905.  The total cost of the 2008-3 Drilling Program as at April 30, 2009 was $192,498.  The well, Wigley #1-11, was abandoned on March 2009, and the cost of $23,510 was moved to the proved properties.  The interests are located in Garvin County, Oklahoma.

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 April 30, 2009 was $1,197,523.  The interests are located in 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 workovers to install submersible pumps and subsequently paid on February 1, 2008.  From November 2008 to April 2009, the Company incurred $44,623 for the Belmont Lake Project.  The total cost of the Palmetto Point Project, to include costs for the PP F-12-2, PP F-12-3 and PP F-52 wells, is $598,191 as of April 30, 2009.  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 wells 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.

9

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

3.           OIL AND GAS INTERESTS (continued)

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 six months period ended April 30, 2009 or 2008, 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 $28,150 and $145,130 for the six months periods ended April 30, 2009 and 2008, respectively.

Capitalized Costs

	April 30, 2009			October 31, 2008
Proved properties	$	2,152,754		$	2,106,564
Unproved properties		255,854			64,000
Total Proved and Unproved properties		2,408,608			2,170,564
Accumulated depletion expense		(869,092	)		(798,660	)
Impairment		(219,539	)		(219,539	)
Net capitalized cost	$	1,319,977		$	1,152,365

Results of Operations

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

	April 30, 2009			April 30, 2008
Revenues	$	110,279		$	875,764
Production costs		(52,456	)		(139,710	)
Depletion and accretion		(72,278	)		(145,130	)
Results of operations (excluding corporate overhead)	$	(14,455	)	$	590,924

4.           LOANS AND INTEREST PAYABLE TO RELATED PARTIES

The unsecured loans and accrued interest at 6%, previously outstanding at October 31, 2007 was paid in full on January 9, 2008.

	April 30, 2009		October 31, 2008
Loan repayable on December 31, 2007, bears interest at 6% per annum, and is unsecured	$	-	$	19,070
Total loans		-		19,070
Plus: accrued interest		-		2,815
Total loans and interest payable		-		21,885
Less: amount paid		-		(20,714	)
Less: exchange gain		-		(1,171	)
	$	-	$	-

Interest expensed was $ nil for the six months period ended April 30, 2009 and $209 for the year ended October 31, 2008.

10

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

5.           ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS 143 “Accounting for asset retirement obligations”.  SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  SFAS 143 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 April 30, 2009 and October 31, 2008, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with SFAS No. 143.  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 six months period ended April 30, 2009 and year ended October 31, 2008:

	April 30, 2009		October 31, 2008
Balance, beginning of period	$	30,766	$	34,584
Liabilities assumed		-		3,376
Revisions		-		(11,344	)
Accretion expense		1,846		4,150
Balance, end of period	$	32,612	$	30,766

The reclamation obligation relates to the Kodesh, Dye Estate, KC 80 and William wells at the Three Sands Property; and the Palmetto Point Project and CMR-USA39-14 well at the Frio-Wilcox Project.  The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes in applicable laws and regulations.  Such changes will be recorded in the accounts of the Company as they occur.

6. COMMON STOCK

PRIVATE PLACEMENTS

On December 28, 2005, the Company completed a 291,392 unit private placement at $1.75 per unit for gross proceeds of $509,936.  Each unit consists of one share of common stock and one common stock purchase warrant exercisable at $2.25 per share which expired on December 27, 2007.

On February 28, 2006, the Company completed a 100,000 unit private placement at $1.50 per unit for gross proceeds of $150,000.  Each unit consists of one share of common stock and one common stock purchase warrant exercisable at $2.00 per share, which expired on February 27, 2008.

On March 15, 2006, the Company completed a 269,230 unit private placement at $1.30 per unit for gross proceeds of $349,999.  Each unit consists of one share of common stock and one common stock purchase warrant exercisable at $1.80 per share, which expired on March 14, 2008.

11

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

6. COMMON STOCK (continued)

On May 3, 2006, the Company completed an 184,600 unit private placement at $1.30 per unit for gross proceeds of $239,980. Each unit consists of one share of common stock and one common stock purchase warrant exercisable at $1.80 per share, which expire on May 2, 2008.

On July  31,  2006,  the  Company  completed  a  384,610  unit  private placement at $1.30 per unit for gross  proceeds of $499,993.  Each unit consists of one share of common stock and one common stock purchase warrant exercisable at $1.80 per share, which expired on July 30, 2008.

               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 shall expire and be canceled two years from the Grant Date and is one hundred percent (100%) vested as of the Grant Date.  The Company recorded a total of $26,077 for stock compensation expenses.

A summary of the changes in stock options for the six months period ended April 30, 2009 is presented below:

	Options Outstanding
		Weighted Average
	Number of Shares	Exercise Price
Balance, October 31, 2007	-	$          -
Grant on November 2, 2007	200,000	0.24
Exercised	-	-
Balance, October 31, 2008	200,000	$    0.24
Granted	-	-
Exercised	-	-
Balance, April 30, 2009	200,000	$    0.24

The Company has the following options outstanding and exercisable.

April 30, 2009	Options outstanding and exercisable
Range of exercise prices	Number of shares	Weighted average remaining contractual life	Weighted Average  Exercise Price
$0.24	200,000	0.50 years	0.24

7.            RELATED PARTY TRANSACTIONS

During the six months periods ended April 30, 2009 and 2008, the Company entered into the following transactions with related parties:

a)     The Company paid $30,000 (2008 - $27,300) in management fees and reimbursement of office space $2400 (2008 - $2,400) to the President of the Company.

b)     The Company paid $30,000 (2008 - $18,128) to a related entity, for administration services, and $53,000 (2008 - $ nil) for consulting.

c)     The Company paid $45,000 (2008 - $10,000) in management fees to the director of the Company.

d)     Interest expense on loans payable to related parties totaled $nil and $209 for the six months periods ended April 30, 2009 and April 30, 2008 respectively.

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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.   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 six-month period ended April 30, 2009 or during the fiscal years ended October 31, 2008, 2007 and 2006.  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.

2008-3 Drilling Program, Oklahoma.  On January 12, 2009, we acquired a 5% working interest in the Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581.25.  We 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 2009, we expended an additional amount of $51,013 for the estimated drilling costs.  From February to April 2009, we expended an additional $112,905.  The total cost of the 2008-3 Drilling Program as at April 30, 2009 was $192,498.  The interests are located in Garvin County, 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.

The first well in this program, the Selman #1-21, has already been drilled and reached a total depth of 6842 feet on January 28, 2009.  Open logs were ran on the well and these logs combined with the mud log indicate potential pay zones in the Gibson Sand and Viola Formation. The top of the Viola was found 47 feet structurally high to a nearby well that produced 577 million cubic feet of gas and 9,572 barrels of oil.  This well was perforated and fracture treated over a large interval.  The well is still recovering load water but is producing 161 mcf of natural gas and 10 to 12 barrels of oil. In the last five days of April 2009, the well produced 719 mcf of natural gas.

The remaining four wells in the program were drilled during the second quarter.  Three wells, the Selman #2-21, the Ard #1-36 and the Bagwell #1-20, were successful and production casing was set.  The fourth well, the Wigley #1-11, was plugged and abandoned.  Completion has started on the Selman #2-21 and frac load water is

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being recovered along with good shows of oil and gas.  It is anticipated that the results of the well will be very similar to the Selman #1-21.

Completion of the Ard #1-36 has also started.  The well was perforated is the lowest potential pay zone and flowed natural gas at a rate of over 500,000 cubic feet per day on an 8/64 inch choke and 1420 pound per square inch flowing tubing pressure.  The next step will be installing surface production equipment before the well can start selling natural gas.  The Bagwell #1-20 has not been perforated yet but some surface production equipment has been set.  Heavy rains and flooding in the area have hampered and slow all completion efforts on this program.  During May 2009, the Bagwell  31-20 was completed as a naturally flowing oil well.

Three Sands Project, Oklahoma.  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.  In June 2007, we 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, we participated in the KC 80#1-11 well and paid $75,000 for the prepaid drilling costs.  During 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 for the KC 80#1-11 well.  The total cost of the Three Sands Project as at April 30, 2009 was $1,197,523.  The interests are located in Oklahoma.

During the three-month period ended April 30, 2009, 757 Bbls of oil and 9,496 Mcf of natural gas were produced at the Three Sands Project.

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 #2 well continues to produce oil on a daily basis, but is no longer producing natural gas. As of April 30, 2009, it has produced 3,690 Bbls of oil and 4,086 Mcf of natural gas.  At the time of this report, the Kodesh #2 well is not producing as the result of a failure of the downhole pump which needs either to be repaired or replaced.

During 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 April 30, 2009, the Dye Estate #1 well has produced 3,095 Mcf of natural gas and as is averaging natural gas production 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. Initial production rates from the William #4-10 well averaged 3.5 Bbls of oil and 10 Mcf of natural gas per day.  During January 2008, we moved up the hole and perforated and fracture treated the Mississippi Lime Formation, increasing daily production to 7 Bbls of oil and 25 Mcf of natural gas per day, but since that time the oil production has decline to 3 barrels of oil per day but the natural gas has risen to over 70 Mcf of gas per day.  As of April 30, 2009, the Williams #4-10 has produced 1,867 Bbls of oil and 19,611 Mcf of natural gas.

Drilling commenced on the KC 80 #1-11 well at the Three Sands Project 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 April 30, 2009, the KC 80 #1-11 well is producing at a rate of 7 Bbls of oil and 35 Mcf of natural gas daily.  As of April 30, 2009, the KC 80-1-11 has produced 3,621 barrels of oil and 14,789 Mcf of natural gas.  Further drilling and completion of new wells on this project will be dependent on an improvement of oil and gas prices.

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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 a 10% working interest in the PP F-12-2 and PP F-12-3 wells within the Palmetto Point Project 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.  On January 30, 2008, we incurred an additional $36,498 for our share of workover costs, including costs to install tubing and submersible pumps to maintain production rates.  We subsequently paid these costs on February 1, 2008.  From November 2008 to April 2009, we incurred $44,623 for the Belmont Lake Project.  As of April 30, 2009, our total costs associated with the Palmetto Point Project, to include our costs for the PP F-12-2 and PP F-12-3 wells, are $598,191.

During the three-month period ended April 30, 2009, 9,893 Bbls of oil and 16,061 MCF of natural gas were produced at the Palmetto Point Project.

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 have been 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 of oil per day and in December 2007 was offset by two additional wells, 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. Additionally, we commenced production at the PP F-6B and PP F52-A wells in October 2007.  In December 2007, the PP F52-A well started producing oil along with the natural gas, flowing naturally.  However, the well ceased flowing during the first quarter of fiscal 2008 and as a result, was placed on a pump during the last calendar quarter of 2008.

As of April 30, 2009, our completed oil and gas wells at the Palmetto Point Project have had total production of 269,315 Mcf of natural gas and 45,045 Bbls of oil.  However, the current average daily production rate at the Palmetto Point Project has declined to 169 Mcf per day of natural gas and oil has fallen to 120 Bbls of oil per day.

Both the PP F-12 PP F-12-3 oil well locations and several of our gas well locations were flooded at the Palmetto Point Project in early 2008.  Prior to the flooding, we had partly completed work to install submersible pumps at each well; however, the work could not be completed before the locations were flooded.  There has been virtually no damage to our surface equipment located at the well heads, as our batteries and other production facilities are located above the floodwaters.  We do not believe that the flooding will adversely affect future oil recovery from these wells.  Floodwaters have now receded and blocked the roads with fallen trees have been cleared.   A workover rig was brought in to install the pumps and installation of pumps has been completed.  Production from these wells started in late October 2008 and both wells are still producing.

 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 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.  We paid $400,000 for the interest.

On June 21, 2007, we assigned our future development interests and obligations for any new wells on our Mississippi Frio-Wilcox Joint Venture property 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 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.

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During the three-month period ended April 30, 2009, 10,354 MCF of natural gas was produced at the Mississippi Frio-Wilcox Joint Venture.

Nine wells were drilled on the Mississippi Frio-Wilcox Joint Venture, of which, four wells were deemed successful:  the Faust #1, USA 39-14, USA 1-37 and the BR F-33.  The USA 39-14 and BR F-33 have been completed and are now also producing natural gas.  As of April 30, 2009, these three wells have produced 227,501 Mcf of natural gas and are currently averaging a combined daily flow of 115 Mcf per day of natural gas.  No further exploration wells are currently planned for this project.

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 six-month period ended April 30, 2009 or during the fiscal years ended October 31, 2008, 2007 and 2006.  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, 2009.

Results of Operations

Three months ended April 30, 2009 compared to the three months ended April 30, 2008.  We realized revenues of $42,150 during the three months ended April 30, 2009, compared with $380,472 during the three months ended April 30, 2008, a decrease of $338,322, due to our sale of the Owl Creek Project in August 2008 and lower commodity prices.  During the three-month period ended April 30, 2009, 710 Bbls of oil and 3,746 Mcf of gas were produced at our oil and gas properties, as compared to 3,382 Bbls of oil and 6,995 Mcf of gas for the three months ended April 30, 2008.

We incurred production costs of $22,042 during the three months ended April 30, 2009, compared with $72,685 during the three months ended April 30, 2008, a decrease of $50,643, but significantly higher as a percentage of revenues, due to unusual costs incurred with our Mississippi projects.  

Our depletion and accretion costs were $29,073 during the three months ended April 30, 2009, compared with $62,075 during the three months ended April 30, 2008, a decrease of $33,002.  The decrease in our depletion costs is related to the sale of the Owl Creek property.

Our general and administrative costs increased to $154,724 for the three months ended April 30, 2009, from $110,261 for the three months ended April 30, 2008, despite decreases in legal expenses of $8,740 and accounting and auditing expenses of $6,588.  The increase is primarily attributable to increases in consulting fees of $45,828, office and miscellaneous expenses of $26,831, and management fees of $13,475.  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 April 30, 2009, we incurred a net loss of $163,689, compared to net income of $135,451 for the three months ended April 30, 2008.  The loss was largely attributable to the decrease in our revenues.

As a result of our net loss for the quarter, we had retained earnings of $794,971 at April 30, 2009.

Six months ended April 30, 2009 compared to the six months ended April 30, 2008.  We realized revenues of $110,279 during the six months ended April 30, 2009, compared with $875,764 during the six months ended April 30, 2008, a decrease of $765,485, due to our sale of the Owl Creek Project in August 2008 and lower commodity prices.  During the six-month period ended April 30, 2009, 2,023 Bbls of oil and 8,095 Mcf of gas were produced at our oil and gas properties, as compared to 8,490 Bbls of oil and 13,005 Mcf of gas for the six months ended April 30, 2008.

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We incurred production costs of $52,456 during the six months ended April 30, 2009, compared with $139,710 during the six months ended April 30, 2008, a decrease of $87,254, but significantly higher as a percentage of revenues, due to unusual costs incurred with our Mississippi projects.  

Our depletion and accretion costs were $72,278 during the six months ended April 30, 2009, compared with $145,130 during the six months ended April 30, 2008, a decrease of $72,852.  The decrease in our depletion costs is related to the sale of the Owl Creek property.

Our general and administrative costs increased to $272,063 for the six months ended April 30, 2009, from $232,008 for the six months ended April 30, 2008, despite decreases in stock-based compensation expenses of $26,077, legal expenses of $8,059 and accounting and auditing expenses of $23,888.  The increase is primarily attributable to increases in consulting fees of $55,893, office and miscellaneous expenses of $52,004, and management fees of $37,700.

For the six months ended April 30, 2009, we incurred a net loss of $285,227, compared to net income of $358,707 for the six months ended April 30, 2008.  The loss was largely attributable to the decrease in our revenues.

Liquidity and Capital Resources

As of April 30, 2009, we had cash of $2,634,952 and working capital of $2,670,897, compared to cash of $3,617,109 and working capital of $3,121,890 as of October 31, 2008.  Our accounts receivable decreased to $31,765 at April 30, 2009, compared with $71,377 at October 31, 2008, a decrease of $39,612.  In addition, our current liabilities decreased to $8,320 at April 30, 2009, compared with $582,404 at October 31, 2008.

During the six months ended April 30, 2009, net cash used by operating activities was $744,113, compared net cash provided of $497,053 during the six months ended April 30, 2008.  The principal reasons for the change were the net loss and the payment of $580,000 in income taxes for the 2009 period.

Net cash used by investing activities during the six months ended April 30, 2009 was $238,044, compared with $143,779 during the six months ended April 30, 2008.

We used cash of $20,714 to repay loans during the six months ended April 30, 2008, and did not use any cash for financing activities during the 2009 period.

Off-Balance Sheet Arrangements

As of April 30, 2009, 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

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

Asset Retirement Obligations. We follow SFAS 143 “Accounting for Asset Retirement Obligations”.  SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  SFAS 143 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 April 30, 2009 and October 31, 2008, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with SFAS No. 143.  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 periods ended April 30, 2009 and October 31, 2008:

	April 30,		October 31,
	2009		2008
Balance, beginning of year	$	30,766	$	34,584
Liabilities assumed		-		3,376
Revisions		-		(11,344	)
Accretion expense		1,846		4,150
Balance, end of year	$	32,612	$	30,766

The reclamation obligation relates to the Kodesh, Dye Estate, KC 80 and William wells at the Three Sands Property; the Palmetto Point Project and CMR-USA 39-14 well at the Frio-Wilcox Project.  The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes to the 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 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.

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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 sole officer, 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 April 30, 2009, being the date of our most recently completed fiscal quarter end.  This evaluation was implemented under the supervision and with the participation of our sole officer, Leroy Halterman.

In conducting his evaluation, our sole officer considered advice from our Independent Registered Public Accounting Firm, Chisholm, Bierwolf & Nilson, LLC (“Chisholm”) that based on several corrections to our financial statements and related disclosures proposed by Chisholm, there is a material weakness in our internal controls over financial reporting.  Additionally, although we are not required to segregate the principal executive officer and principal financial officer functions and we are not required to have an audit committee, Chisholm considered the fact that our sole officer serves in both of these functions and that we do not have an audit committee as dispositive in providing its advice to our sole officer.  As a result of this material weakness in our internal controls, our sole officer concluded further that the design and operation of our disclosure controls and procedures were not effective.

Our sole officer also considered various mitigating factors in making his determination.  There were no changes in our internal controls or in other factors that could significantly affect our internal controls subsequent to the date of evaluation.  Further, our sole officer also noted that we are still evaluating and implementing changes in our internal controls in response to the requirements of Sarbanes Oxley §404.  During fiscal 2009, we will continue to implement appropriate changes as they are identified, including changes to remediate material weaknesses in our internal controls.

Changes in Internal Controls Over Financial Reporting

In connection with the evaluation of our internal controls during our last fiscal quarter, our sole officer has concluded that there were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended April 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II.    OTHER INFORMATION

Item 1.         Legal Proceedings

None.

Item 1A.      Risk Factors

Not required for smaller reporting companies.

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

None.

Item 3.         Defaults Upon Senior Securities

None.

Item 4.         Submission of Matters to a Vote of Security Holders

None.

Item 5.         Other Information

Not applicable

Item 6.         Exhibits.

Regulation S-K Number	Exhibit
3.1	Articles of Incorporation (1)
3.2	Bylaws (1)
3.3	Certificate of Change Pursuant to NRS 78.209 (2)
3.4	Amended Bylaws (3)
3.5	Amendment to the Articles of Incorporation (3)
31.1	Rule 15d-14(a) Certification
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

___________________

(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.

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SIGNATURES

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

	BRINX RESOURCES LTD.
	(Registrant)
Date:  June 10, 2009	By:	/s/ Leroy Halterman
		Leroy Halterman
		President, Secretary & Treasurer
		(principal executive and financial officer)

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