Brinx Resources (BNXR) 10-Q 2009 Q3 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 July 31, 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 August 31, 2009

BRINX RESOURCES LTD.

INDEX

		Page
PART I.	UNAUDITED FINANCIAL INFORMATION
Item 1.	Interim Financial Statements
	Balance Sheets July 31, 2009 (unaudited) and October 31, 2008	3
	Statements of Operations (unaudited) Three and Nine Months Ended July 31, 2009 and 2008	4
	Statements of Cash Flows (unaudited) Nine Months Ended July 31, 2009 and 2008	5
	Notes to Financial Statements (unaudited)	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	20
Item 4.	Controls and Procedures	20
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	21
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	21
Item 3.	Defaults Upon Senior Securities	21
Item 4.	Submission of Matters to a Vote of Security Holders	21
Item 5.	Other Information	21
Item 6.	Exhibits	21
Signatures		23

2

BRINX RESOURCES LTD.
BALANCE SHEETS
	July 31		OCTOBER 31
	2009		2008
ASSETS	(UNAUDITED)		(AUDITED)
Current assets
Cash and cash equivalents	$	2,360,801	$	3,617,109
Accounts receivable		98,477		71,377
Prepaid expenses and deposit		13,000		15,808
Total current assets		2,472,278		3,704,294
Undeveloped mineral interests, at cost		811		811
Oil and gas interests, full cost method of accounting,
net of accumulated depletion		1,438,011		1,152,365
Total assets	$	3,911,100	$	4,857,470
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	36,480	$	2,404
Income taxes payable		-		580,000
Total current liabilities		36,480		582,404
Deferred income taxes		337,717		337,717
Asset retirement obligations		33,535		30,766
Total liabilities		407,732		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		676,983		1,080,198
Total stockholders' equity		3,503,368		3,906,583
Total liabilities and stockholders' equity	$	3,911,100	$	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 NINE MONTHS
	PERIOD ENDED						PERIOD ENDED
	JULY 31,						JULY 31,
	2009			2008			2009			2008
REVENUES
Natural gas and oil sales	$	135,126		$	772,984		$	245,405		$	1,648,748
DIRECT COSTS
Production costs		23,156			50,683			75,612			190,393
Depletion and accretion		59,512			107,155			131,790			252,285
Impairment		-			-			-			-
General and administrative		163,506			144,398			435,569			376,406
		(246,174	)		(302,236	)		(642,971	)		(819,084	)
OPERATING INCOME (LOSS)		(111,048	)		470,748			(397,566	)		829,664
OTHER INCOME AND EXPENSE
Interest income		-			-			1,291			-
Interest expense - related		-			-			-			(209	)
NET INCOME (LOSS) BEFORE INCOME TAXES		(111,048	)		470,748			(396,275	)		829,455
Income taxes		6,940			-			6,940			-
NET INCOME (LOSS) FOR THE PERIOD	$	(117,988	)	$	470,748		$	(403,215	)	$	829,455
Net Income Per Common Share
- Basic	$	(0.005	)	$	0.019		$	(0.016	)	$	0.034
- Diluted	$	(0.005	)	$	0.019		$	(0.016	)	$	0.034
Weighted average number of common shares outstanding
- Basic		24,529,832			24,529,832			24,529,832			24,529,832
- Diluted		24,529,832			24,729,832			24,529,832			24,729,832

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

4

BRINX RESOURCES LTD.
STATEMENTS OF CASH FLOWS
(Unaudited)
	FOR THE NINE MONTHS
	PERIOD ENDED
	JULY 31,
	2009			2008
CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES
Net income (loss)	$	(403,215	)	$	829,455
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Stock based compensation (note 6)		-			26,077
Depletion and accretion		131,790			252,285
Changes in working capital:
Decrease (increase) in accounts receivable		(27,100	)		(181,960	)
Decrease in prepaid expenses and deposit		2,808			-
Increase (decrease) in accounts payable and accrued liabilities		34,076			(194,207	)
Interest accrued to related party notes		-			209
Increase (Decrease) in due to related party					(1,171	)
(Decrease) in income taxes		(580,000	)		-
Net cash provided by (used in) operating activities		(841,641	)		730,688
CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES
Expenditures on oil and gas interests		(414,667	)		(275,959	)
Net cash (used in) investing activities		(414,667	)		(275,959	)
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		(1,256,308	)		434,015
Cash and cash equivalents, beginning of periods		3,617,109			42,257
Cash and cash equivalents, end of periods	$	2,360,801		$	476,272
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Assets retirement costs incurred	$	(2,769	)	$	(3,113	)
Assets retirement obligation incurred	$	2,769		$	3,113
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 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.  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 nine months period ended July 31, 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)

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, 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 July 31, 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 nine months periods ended July 31, 2009 and 2008:

	July 31, 2009			July 31, 2008
Basic earnings per share computation:
Income (Loss) from continuing operations	$	(403,215	)	$	829,455
Basic shares outstanding		24,529,832			24,529,832
Basic earnings per share	$	(0.016	)	$	0.034
Diluted earnings per share computation:
Income (Loss) from continuing operations	$	(403,215	)	$	829,455
Basic shares outstanding		24,529,832			24,529,832
Incremental shares from assumed conversions:
Stock options		-			200,000
Warrants		-			-
Diluted shares outstanding		24,529,832			24,729,832
Diluted earnings per share	$	(0.016	)	$	0.034

The calculation for earnings per share excluded 200,000 stock options as these would have an anti-dilutive effect as at July 31, 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:

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

	July 31, 2009		October 31, 2008
Accounts receivable	$	98,477	$	71,377
Less: allowance for doubtful account		-		-
	$	98,477	$	71,377

3.   OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:

	July 31, 2009			October 31, 2008
2008-3 Drilling Program, Oklahoma	$	242,506		$	-
2009-2 Drilling Program, Oklahoma		26,625			-
King City Prospect, California		100,000			-
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		(1,147,220	)		(1,018,199	)
	$	1,438,011		$	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 to July 2009, the Company expended an additional $213,925.  The total cost of the 2008-3 Drilling Program as at July 31, 2009 was $242,506.  The well, Wigley #1-11, was abandoned on March 2009, and the cost of $23,510 was moved to the proved properties.  Selman #1-21 and Bagwell #1-20 started producing on May 2009, and Ard #1-36 started producing on June 2009.  The interests are located in Garvin County, Oklahoma.

2009-2 Drilling Program, Oklahoma

On June 19, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,562.50.  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%.  The interests are located in Garvin County, Oklahoma.

King 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 40% of dry hole cost of the first well.  Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each parties working interest.

Three Sands Project, Oklahoma

On October 6, 2005, the Company acquired a 40% working interest in Vector Exploration Inc’s Three Sands Project for a total buy-in cost of $88,000 plus dry hole costs.  For the year ended October 31, 2006, the Company expended $530,081 in exploration costs.  In June 2007, the Company acquired a 40% working interest in William #4-10 well for a total cost of $285,196 and paid a further $17,000 in costs relating to the well.  On March 19, 2008, the Company participated in the KC 80#1-11 well and paid $75,000 for the prepaid drilling costs.  During March and April 2008, the Company expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 during May to July 2008 for the KC 80#1-11 well.  The total cost of the Three Sands Project as at July 31, 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.  During November 2008 to July 2009, the Company incurred $44,623 for 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 July 31, 2009.  The interests are located in Mississippi.

9

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 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.

Impairment

Under the full cost method, the Company is subject to a ceiling test.  This ceiling test determines whether there is an impairment to the proved properties.  The impairment amount represents the excess of capitalized costs over the present value, discounted at 10%, of the estimated future net cash flows from the proven oil and gas reserves plus the cost, or estimated fair market value.  There was no impairment cost for the nine months period ended July 31, 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 $129,021 and $249,172 for the nine months periods ended July 31, 2009 and 2008, respectively.

Capitalized Costs

	July 31, 2009			October 31, 2008
Proved properties	$	2,439,385		$	2,106,564
Unproved properties		145,846			64,000
Total Proved and Unproved properties		2,585,231			2,170,564
Accumulated depletion expense		(927,681	)		(798,660	)
Impairment		(219,539	)		(219,539	)
Net capitalized cost	$	1,438,011		$	1,152,365

Results of Operations

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

	July 31, 2009			July 31, 2008
Revenues	$	245,405		$	1,648,748
Production costs		(75,612	)		(190,393	)
Depletion and accretion		(131,790	)		(252,285	)
Results of operations (excluding corporate overhead)	$	38,003		$	1,206,070

10

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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.

	July 31, 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 nine months period ended July 31, 2009 and $209 for the year ended October 31, 2008.

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 July 31, 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 nine months period ended July 31, 2009 and year ended October 31, 2008:

	July 31, 2009		October 31, 2008
Balance, beginning of period	$	30,766	$	34,584
Liabilities assumed		-		3,376
Revisions		-		(11,344	)
Accretion expense		2,769		4,150
Balance, end of period	$	33,535	$	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.

11

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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.

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 nine months period ended July 31, 2009 is presented below:

	Options Outstanding
	Number of Shares		Weighted Average 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, July 31, 2009		200,000	$	0.24

The Company has the following options outstanding and exercisable.

July 31, 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	0.25 years	0.24

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BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

7.            RELATED PARTY TRANSACTIONS

During the nine months periods ended July 31, 2009 and 2008, the Company entered into the following transactions with related parties:

a)        The Company paid $45,000 (2008 - $41,325) in management fees and reimbursement of office space $3,600 (2008 - $3,600) to the President of the Company.

b)     The Company paid $45,000 (2008 - $33,128) to a related entity, for administration services, and $96,500 (2008 - $ nil) for consulting.

c)     The Company paid $79,500 (2008 - $25,000) in management fees to the director of the Company.

d)     Interest expense on loans payable to related parties totaled $nil and $209 for the nine months periods ended July 31, 2009 and July 31, 2008 respectively.

8.            SUBSEQUENT EVENTS

On August 2009, the Company acquired a 5% working interest in the 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 Before Casing Point Interest “BCP” shall be 6.25% and the After Casing Point Interest “ACP” shall be 5.00%.

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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 nine-month period ended July 31, 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.  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%.  From January 2009 to July 2009, we expended an additional $213,925.  The total cost of the 2008-3 Drilling Program as at July 31, 2009 was $242,506.  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 and now is in production

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.   The Selman #2 was completed and treated with very similar results as the Selman #1.

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Completion of the Ard #1-36 has also started and has been completed.  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.  Within a short time the well began making large quantities of water along with the gas and a decision was made to place a plug over the zone and move up the hole and perforate another zone.  As of the time of this filing, the new zone was producing at a rate of 35 barrels of oil and 17 mcf of natural gas.  Plans are to complete an additional zone up the hole to increase the production rate.

 The last well in the program the Bagwell #1-20 has been perforated and surface production equipment has been set.  During mid May 2009, the Bagwell 31-20 was completed as a naturally flowing oil well.  Initial flow rates were between 380 and 400 barrels of oil and 50 Mcf of gas of gas per day.  As of July 31, 2009, the well is still flowing at rates between 380 and 400 barrels of oil per day and as of August 1, 2009 has produced at total of 29,542 barrels of oil and 3,091 Mcf of natural gas.  As of the date of this report, the well is still producing oil and gas at a rate of between 380 and 400 barrels per day and 50 Mcf of natural gas per day.

2009-2 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 $26,563.  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%.  The interests are located in Garvin County, Oklahoma.  Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola This program is composed of four 3-D seismically defined separate prospects with one exploratory well in three of the Limestone, Deese Sandstone and Layton Sandstone.   Drilling of the first well commenced in late August 2009 and as of September 8, 2009, the well was drilled to 4,700 feet.

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 July 31, 2009 was $1,197,523.  The interests are located in Oklahoma.

During the three-month period ended July 31, 2009, 573 Bbls of oil and 11,358 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 no longer produces oil on a daily basis, but there is a small amount of natural gas being produced. As of July 31, 2009, it has produced 3,690 Bbls of oil and 4,624 Mcf of natural gas.  At the time of this report, the Kodesh #2 well is not producing oil but it is producing a small amount natural gas 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 July 31, 2009, the Dye Estate #1 well has produced 3,621 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 2 barrels of oil per day but the natural gas has risen to over 80 Mcf of gas per day.  As of July 31, 2009, the Williams #4-10 has produced 2,014 Bbls of oil and 26,596 Mcf of natural gas.

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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 July 31, 2009, the KC 80 #1-11 well is producing at a rate of 5 Bbls of oil and 37 Mcf of natural gas daily.  As of July 31, 2009, the KC 80-1-11 has produced 4,047 barrels of oil and 18,118 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.  This is especially true in the case of natural gas where the current price do not warrant further drilling until the price of natural gas has improved.

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 July 2009, we incurred $44,623 for the Belmont Lake Project.  As of July 31, 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 quarter ended July 31, 2009, two development wells and two reworks were planned for the Belmont Lake oil field in the Palmetto Point project.  One will be a vertical well and a second well will be a horizontal well.  Drilling of these wells should start within the next two months.

During the three-month period ended July 31, 2009, 9,325 Bbls of oil and 20,551 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 July 31, 2009, our completed oil and gas wells at the Palmetto Point Project have had total production of 289,866 Mcf of natural gas and 53,470 Bbls of oil.  However, the current average daily production rate at the Palmetto Point Project has increased to 223 Mcf per day of natural gas and oil has fallen to 101 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

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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.

Plans are to drill one horizontal well in the Belmont Lake filed, the PP F-4, during the next three months.  Additional drilling will depend upon the success of the PP F-4.

 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.

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 were producing natural gas.  As of July 31, 2009, these three wells have produced 227,501 Mcf of natural gas and are all are currently shut-in natural gas wells with no production.  No further exploration wells are currently planned for this project.

King City Oil Field

Late in the quarter ending July 31, 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 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 40% of dry hole cost of the first well.  Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each parties working interest.  The geophysical surveys have already started.

Mineral Interests

Antelope Pass.  In 2005, we suspended our activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on the Antelope Pass Project during the nine-month period ended July 31, 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, 2010.

Results of Operations

Three months ended July 31, 2009 compared to the three months ended July 31, 2008.  We realized revenues of $135,126 during the three months ended July 31, 2009, compared with $772,984 during the three months ended July 31, 2008, a decrease of $637,858, due to our sale of the Owl Creek Project in August 2008 and lower commodity prices.  During the three-month period ended July 31, 2009, 1,941 Bbls of oil and 764 Mcf of gas were produced at our oil and gas properties, as compared to 10,959 Bbls of oil and 70,895 Mcf of gas for the three months ended July 31, 2008.  The reduction was caused by the sale of the Owl Creek Project in August 2008.

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We incurred production costs of $23,156 during the three months ended July 31, 2009, compared with $50,683 during the three months ended July 31, 2008, a decrease of $27,527, but significantly higher as a percentage of revenues, due to unusual costs incurred with our Mississippi projects.  

Our depletion and accretion costs were $59,512 during the three months ended July 31, 2009, compared with $107,155 during the three months ended July 31, 2008, a decrease of $47,643.  The decrease in our depletion costs is related to the sale of the Owl Creek property.

Our general and administrative costs increased to $163,506 for the three months ended July 31, 2009, from $144,398 for the three months ended July 31, 2008, despite decreases in state taxes of $45,643.  The increase is primarily attributable to increases in consulting fees of $46,416 and management fees of $20,475.  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 July 31 2009, we incurred a net loss of $117,988, compared to net income of $470,748 for the three months ended July 31, 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 $676,983 at July 31, 2009.

Nine months ended July 31, 2009 compared to the nine months ended July 31, 2008.  We realized revenues of $245,405 during the nine months ended July 31, 2009, compared with $1,648,748 during the nine months ended July 31, 2008, a decrease of $1,403,343, due to our sale of the Owl Creek Project in August 2008 and lower commodity prices.  During the nine-month period ended July 31, 2009, 3,964 Bbls of oil and 2,113 Mcf of gas were produced at our oil and gas properties, as compared to 13,626 Bbls of oil and 3,825 Mcf of gas for the nine months ended July 31, 2008.  The reduction as caused by the sale of the Owl Creek Project in August 2008.

We incurred production costs of $75,612 during the nine months ended July 31, 2009, compared with $190,393 during the nine months ended July 31, 2008, a decrease of $114,781, but significantly higher as a percentage of revenues, due to unusual costs incurred with our Mississippi projects.  

Our depletion and accretion costs were $131,790 during the nine months ended July 31, 2009, compared with $252,285 during the nine months ended July 31, 2008, a decrease of $120,495.  The decrease in our depletion costs is related to the sale of the Owl Creek property.

Our general and administrative costs increased to $435,569 for the nine months ended July 31, 2009, from $376,406 for the nine months ended July 31, 2008, despite decreases in state taxes of $92,602, stock-based compensation expenses of $26,077, accounting and auditing expenses of $24,052, and registration and filing fees of $12,208.  The increase is primarily attributable to increases in consulting fees of $102,309, management fees of $58,175, and office and miscellaneous expenses of $54,133.

For the nine months ended July 31, 2009, we incurred a net loss of $403,215, compared to net income of $829,455 for the nine months ended July 31, 2008.  The loss was largely attributable to the decrease in our revenues.

Liquidity and Capital Resources

As of July 31, 2009, we had cash of $2,360,801 and working capital of $2,435,798, compared to cash of $3,617,109 and working capital of $3,121,890 as of October 31, 2008.  Our accounts receivable increased to $98,477 at July 31, 2009, compared with $71,377 at October 31, 2008, an increase of $27,100.  In addition, our current liabilities decreased to $36,480 at July 31, 2009, compared with $582,404 at October 31, 2008.

During the nine months ended July 31, 2009, net cash used by operating activities was $841,641, compared to net cash provided of $730,688 during the nine months ended July 31, 2008.  The principal reason for the change was the net loss for the 2009 period.

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Net cash used by investing activities during the nine months ended July 31, 2009 was $414,667, compared with $275,959 during the nine months ended July 31, 2008.

We used cash of $20,714 to repay loans during the nine months ended July 31, 2008, and did not use any cash for financing activities during the 2009 period.

Off-Balance Sheet Arrangements

As of July 31, 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 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 July 31, 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 July 31, 2009 and October 31, 2008:

	July 31,		October 31,
	2009		2008
Balance, beginning of year	$	30,766	$	34,584
Liabilities assumed		-		3,376
Revisions		-		(11,344	)
Accretion expense		2,769		4,150
Balance, end of year	$	33,535	$	30,766

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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.

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 July 31, 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.  Based on this evaluation, Mr. Halterman concluded that the design and operation of our disclosure controls and procedures are not effective since the following material weaknesses exist:

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

·      We have a sole 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.

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·      We rely on an external consultant for administration functions, some of which do not have standard procedures in place for formal review by our sole officer

 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 July 31, 2009 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.

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

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____________________

(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.
September 10, 2009	By:	/s/ Leroy Halterman
		Leroy Halterman
		President, Secretary & Treasurer
		(principal executive and financial officer)

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