f10q-073111_brinx.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended July 31, 2011

[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to _______________

333-102441

(Commission file number)

BRINX RESOURCES LTD.

(Exact name of registrant as specified in its charter)

Nevada

(State or other jurisdiction

of incorporation or organization)

98-0388682

(IRS Employer

Identification No.)

820 Piedra Vista Road NE, Albuquerque, New Mexico 87123

(Address of principal executive offices) (Zip Code)

(505) 250-9992

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

[x] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

[ ] Yes [ ] No (Not Required)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [ ]	Accelerated filer [ ]
Non-accelerated filer [ ]	Smaller reporting company [x]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

[ ]Yes [x] No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 24,629,832 shares of Common Stock, $0.001 par value, as of September 9, 2011

BRINX RESOURCES LTD.

INDEX

		Page
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	3

	Balance Sheets July 31, 2011 (unaudited) and October 31, 2010	4

	Statements of Operations (unaudited) Three and Nine months Ended July 31, 2011 and 2010	5

	Statements of Cash Flows (unaudited) Nine months Ended July 31, 2011 and 2010	6

	Notes to Financial Statements (unaudited)	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27

Item 4.	Controls and Procedures	27

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	27

Item 1A.	Risk Factors	27

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	27

Item 3.	Defaults Upon Senior Securities	27

Item 4.	Removed and Reserved	28

Item 5.	Other Information	28

Item 6.	Exhibits	28

Signatures		29

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

BRINX RESOURCES LTD.
BALANCE SHEETS

	JULY 31		OCTOBER 31,
	2011		2010
ASSETS	(Unaudited)		(Audited)

Current assets
Cash and cash equivalents	$	314,183	$	21,029
Investment - Certificate of deposit		400,000		800,000
Accounts receivable		185,393		148,924
Prepaid expenses and deposit		16,205		128,055

Total current assets		915,781		1,098,008

Undeveloped mineral interests, at cost		811		811

Oil and gas interests, full cost method of accounting,
net of accumulated depletion		2,781,946		2,577,519

Total assets	$	3,698,538	$	3,676,338

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
Accounts payable and accrued liabilities	$	36,578	$	37,777

Total current liabilities		36,578		37,777

Asset retirement obligations		30,734		27,494

Total liabilities		67,312		65,271

Stockholders' equity
Preferred stock - $0.001 par value; authorized - 1,000,000 shares
Issued - none		-		-

Common stock - $0.001 par value; authorized - 100,000,000 shares
Issued and outstanding - 24,629,832 shares		24,630		24,630

Capital in excess of par value		2,868,057		2,868,057

Retained earnings		738,539		718,380

Total stockholders' equity		3,631,226		3,611,067

Total liabilities and stockholders' equity	$	3,698,538	$	3,676,338

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

BRINX RESOURCES LTD.
STATEMENTS OF OPERATIONS
(UNAUDITED)

	FOR THE THREE MONTHS						FOR THE NINE MONTHS
	PERIOD ENDED						PERIOD ENDED
	JULY 31,						JULY 31,
	2011			2010			2011			2010

REVENUES
Natural gas and oil sales	$	291,527		$	254,173		$	1,062,679		$	482,229

DIRECT COSTS
Production costs		40,385			20,119			162,262			62,807
Depletion and accretion		79,388			106,446			285,481			175,458
General and administrative		221,338			200,208			593,249			679,671

Total Expenses		(341,111	)		(326,773	)		(1,040,992	)		(917,936	)

OPERATING INCOME (LOSS)		(49,584	)		(72,600	)		21,687			(435,707	)

OTHER INCOME
Interest income		350			1,701			900			2,622

NET INCOME (LOSS) BEFORE INCOME TAXES		(49,234	)		(70,899	)		22,587			(433,085	)
Provision for income taxes		2,428			-			2,428			-

NET INCOME (LOSS) FOR THE PERIODS	$	(51,662	)	$	(70,899	)	$	20,159		$	(433,085	)

Net Income (Loss) Per Common Share
- Basic	$	(0.002	)	$	(0.003	)	$	0.001		$	(0.018	)
- Diluted	$	(0.002	)	$	(0.003	)	$	0.001		$	(0.018	)

Weighted average number of common shares outstanding
- Basic		24,629,832			24,629,832			24,629,832			24,596,132
- Diluted		24,629,832			24,629,832			24,749,314			24,596,132

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

BRINX RESOURCES LTD.
STATEMENTS OF CASH FLOWS
(Unaudited)

	FOR THE NINE MONTHS
	PERIOD ENDED
	JULY 31,
	2011			2010
CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES

Net income (loss)	$	20,159		$	(433,085	)

Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Stock based compensation		-			31,015
Depletion and accretion		285,481			175,548
Shares issued to Investor Relations Services Inc. for services rendered		-			27,000
Changes in working capital:
Decrease (Increase) in accounts receivable		(36,469	)		(50,258	)
Decrease (Increase) in prepaid expenses and deposit		111,850			67,604
Increase (Decrease) in accounts payable and accrued liabilities		(1,199	)		20,057
Increase (Decrease) in income taxes receivable		-			253,814

Net cash provided by (used in) operating activities		379,822			91,695

CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES

Investment - Certificate of deposit		400,000			-
Payments on oil and gas interests		(486,668	)		(711,103	)

Net cash provided by (used in) investing activities		(86,668	)		(711,103	)

CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES

Net cash (used in) financing activities		-			-

Net increase (decrease) in cash		293,154			(619,408	)

Cash and cash equivalents, beginning of periods		21,029			1,947,950

Cash and cash equivalents, end of periods	$	314,183		$	1,328,542


SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for taxes paid	$	2,428		$	-

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

Assets retirement costs incurred	$	(3,240	)	$	(3,330	)

Investment in natural oil and gas working interests included in	$	28,640		$	93,208
accounts payable

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

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Brinx Resources Ltd. (the “Company”) was incorporated under the laws of the State of Nevada on December 23, 1998, and issued its initial common stock in February 2001. The Company holds undeveloped mineral interests located in New Mexico and holds oil and gas interests located in Oklahoma, California, Mississippi and Louisiana. In 2006, the Company commenced oil and gas production and started earning revenues.

The accompanying financial statements of the Company are unaudited. In the opinion of management, the financial statements include all adjustments, consisting only of normal recurring adjustments, necessary for fair presentation. The results of operations for the nine-month period ended July 31, 2011 are not necessarily indicative of the operating results for the entire year. These financial statements should be read in conjunction with the financial statements and notes included in the Company’s Form 10-K for the year ended October 31, 2010.

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.

Capitalized costs of oil and gas interests may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved interests. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying a twelve month average of 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.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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

REVENUE RECOGNITION

Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers. Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred. Revenues from the production of oil and natural gas properties in which the Company shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field. At July 31, 2011 and 2010, the Company had no overproduced imbalances.

ACCOUNTS RECEIVABLE

Accounts receivable are carried at net receivable amounts less an estimate for doubtful accounts. Management determines the allowance for doubtful accounts by regularly evaluating individual customer receivables and considering a customer’s financial condition, credit history, and current economic conditions. Trade receivables are written off when deemed uncollectible. Recoveries of receivables previously written off are recorded when received.

IMPAIRMENT OF LONG-LIVED ASSETS

The Company has adopted FASB ASC 360 (prior authoritative literature: SFAS No. 144) "Accounting for the Impairment or Disposal of Long-Lived Assets", which requires that long-lived assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and gas interests accounted for under the full cost method are subject to a ceiling test, described above, and are excluded from this requirement.

ASSET RETIREMENT OBLIGATIONS

The Company follows FASB ASC 410-20 (prior authoritative literature: SFAS No. 143) "Accounting for Asset Retirement Obligations", that addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.

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

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

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 a dilutive effect on income/(loss) per share. 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-month periods ended July 31, 2011 and 2010:

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(continued)

INCOME / (LOSS) PER SHARE (continued)

	July 31, 2011		July 31, 2010
Basic earnings per share computation:
Income (Loss) from continuing operations and net income	$	20,159	$	(433,085	)
Basic shares outstanding		24,629,832		24,596,132
Basic earnings per share	$	0.001	$	(0.018	)

Diluted earnings per share computation:
Income (Loss) from continuing operations	$	20,159	$	(433,085	)
Basic shares outstanding		24,629,832		24,596,132
Incremental shares from assumed conversions:
Stock options		119,482		-
Warrants		-		-
Diluted shares outstanding		24,749,314		24,596,132
Diluted earnings per share	$	0.001	$	(0.018	)

The calculation for earnings per share at July 31, 2010 excluded 400,000 stock options as these were not in the money.

CASH EQUIVALENTS

For purposes of reporting cash flows, the Company considers as cash equivalents all highly liquid investments with a maturity of three months or less at the time of purchase. On occasion, the Company may have cash balances in excess of federally insured amounts.

FAIR VALUE

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

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

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

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

The carrying amounts reported in the balance sheets for the cash and cash equivalents, investments in certificates of deposits, receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of fair value because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(continued)

CONCENTRATION OF CREDIT RISK

Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents, investments in certificates of deposit and accounts receivable. The Company maintains cash at one financial institution. The Company periodically evaluates the credit worthiness of financial institutions, and maintains cash accounts only in large high quality financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts. The Company believes credit risk associated with cash and cash equivalents to be minimal.

The Company has recorded trade accounts receivable from the business operations. Management periodically evaluates the collectability of the trade receivables and believes that the Company’s receivables are fully collectable and that the risk of loss is minimal.

EQUITY BASED COMPENSATION

The Company adopted the fair value recognition provisions of FASB ASC 718 (prior authoritative literature: SFAS No. 123R) “Share Based Payment”.

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

	Nine-month periods ended
	July 31, 2011	July 31, 2010
Expected volatility	-	149%
Risk-free interest rate	-	0.11%
Expected life	-	2 years
Dividend yield	-	0.00%

RECENT ACCOUNTING PRONOUNCEMENTS

There are no new accounting standards that are expected to have a significant impact on the Company’s financial statements.

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, 2011 and October 31, 2010. Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.

	July 31, 2011		October 31, 2010
Accounts receivable	$	185,393	$	148,924
Less: allowance for doubtful account		-		-
	$	185,393	$	148,924

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

3.	OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:

	July 31, 2011			October 31, 2010
2008-3 Drilling Program, Oklahoma	$	290,938		$	257,564
2009-2 Drilling Program, Oklahoma		114,420			115,582
2009-3 Drilling Program, Oklahoma		303,606			294,164
2009-4 Drilling Program, Oklahoma		190,146			172,530
2010-1 Drilling Program, Oklahoma		270,716			232,212
Washita Bend 3D, Oklahoma		478,602			337,398
Kings City Prospect, California		120,775			106,091
Three Sands Project, Oklahoma		1,451,543			1,279,633
South Wayne Prospect, Oklahoma		61,085			60,914
Palmetto Point Project, Mississippi		420,000			420,000
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi		373,555			312,630
Frio-Wilcox Prospect, Mississippi		400,000			400,000
Asset retirement cost		8,992			8,992
Less: Accumulated depletion and impairment		(1,702,432	)		(1,420,191	)
	$	2,781,946		$	2,577,519

2008-3 Drilling Program, Oklahoma

On January 12, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The Before Casing Point Interest “BCP” shall be 6.25% and the After Casing Point Interest “ACP” shall be 5.00%. During January to July 2009, the Company expended $213,925 in addition to $18,850 that was spent in previous periods. The well, Wigley#1-11, was abandoned during March 2009. The cost and its buy-in cost total of $33,423 were moved to the proved properties. Selman#1-21 and Bagwell#1-20 started producing during May 2009, the cost and its buy-in cost total of $67,707 for Selman#1-21 and $57,921 for Bagwell#1-20 were moved to the proved properties. Ard#1-36 started producing during June 2009 and the cost and its buy-in cost total of $42,647 was moved to the proved properties. Selman#2-21 started producing during July 2009 and was abandoned on April 20, 2010; the cost and its buy-in cost total of $57,483 were moved to the proved properties pool. The total cost of the 2008-3 Drilling Program as at July 31, 2011 was $290,938. The interests are located in Garvin County, Oklahoma.

2009-2 Drilling Program, Oklahoma

On June 19, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,562. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The well, James#1-18, was abandoned on September 21, 2009. The cost and its buy-in cost total of $41,934 were moved to the proved properties. Little Chief#1-3 was abandoned on November 17, 2009; the cost and its buy-in cost total of $35,528 were moved to the proved properties. J.C. Carlton#1-31 was abandoned on April 30, 2010; the cost and its buy-in cost total of $38,630 were moved to the proved properties. As at July 31, 2011, the total cost of the 2009-2 Drilling Program was $114,420. The interests are located in Garvin County, Oklahoma.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

3.	OIL AND GAS INTERESTS (continued)

2009-3 Drilling Program, Oklahoma

On August 12, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Jackson#1-18 started producing during January 2010; an amount of $63,725 which included the buy-in cost was moved to the proved property pool. Miss Gracie#1-18 started producing during March 2010; an amount of $62,268 which included its buy-in cost was moved to the proved property pool. Brewer#1-20 was abandoned on June 2, 2010; the cost and its buy-in cost total of $64,936 were moved to the proved properties. Waunice#1-36 started producing during June 2010 and was abandoned on September 23, 2010; an amount of $43,848 which included its buy-in cost was moved to the proved property pool. As at July 31, 2011, the total cost of the 2009-3 Drilling Program was $303,606. The interests are located in Garvin County, Oklahoma.

2009-4 Drilling Program, Oklahoma

On December 19, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-4 Drilling Program for a total buy-in cost of $13,482. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Dennis#1-8 started producing during May 2010; an amount of $79,892 which included the buy-in cost was moved to the proved property pool, it was abandoned on September 27, 2010. Dennis#2-8 was abandoned on November 17, 2010; an amount of $34,068 which included the buy-in cost was moved to the proved property pool. Murray Trust#3-19 was abandoned on December 13, 2010; an amount of $12,917 which included the buy-in cost was moved to the proved property pool. Murray Trust#2-19 started producing during November 2010; an amount of $52,910 which included the buy-in cost was moved to the proved property pool.

As at July 31, 2011, the total cost of the 2009-4 Drilling Program was $190,146. The interests are located in Garvin County, Oklahoma.

2010-1 Drilling Program, Oklahoma

On April 23, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,163. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Julie#1-14 was abandoned on October 2, 2010; the cost and its buy-in cost total of $47,035 were moved to the proved properties. Jack#1-13 started producing during November 2010; an amount of $73,993 which included the buy-in cost was moved to the proved property pool. Miss Jenny started producing during December 2010; an amount of $61,640 which included the buy-in cost was moved to the proved property pool. As at July 31, 2011, the total cost of the 2010-1 Drilling Program was $270,716. The interests are located in Garvin County, Oklahoma.

Washita Bend 3D Exploration Project, Oklahoma

On March 1, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s Washita Bend 3D Exploration Project for a buy-in cost of $46,250. The BCP Interest shall be 5.625% and the ACP Interest shall be 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells. As at July 31, 2011, the total costs, including seismic costs was $478,602.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

3. OIL AND GAS INTERESTS (continued)

Kings City Prospect, California

A Farmout agreement was made effective on May 25, 2009 between the Company and Sunset Exploration, Inc., to explore for oil and natural gas on 10,000 acres located in west central California. The Company paid $100,000 (50% pro rata share of $200,000) to earn a 20% working interest in the project by funding a maximum of 50% of a $200,000 in a geophysical survey composed of gravity and seismic surveys and agreed to carry Sunset Exploration for 33.33% of dry hole cost of the first well. Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each party’s working interest. The total cost of the King City prospect as at July 31, 2011 was $120,775.

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, 2011 was $1,451,543. The interests are located in Oklahoma.

South Wayne Prospect, Oklahoma

On March 14, 2010, the Company acquired a 5.00% working interest in McPherson#1-1 well for a payment for leasehold, prospect and geophysical fees of $5,000, and dry hole costs of $32,370. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The interests are located in McClain County, Oklahoma. The total cost of the South Wayne prospect as at July 31, 2011 was $61,085.

Palmetto Point Project, Mississippi

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

On January 30, 2008, the Company incurred $36,498 for work-overs to install submersible pumps. From November 2008 to July 2009, the Company incurred $44,623 for the Belmont Lake Project. The total cost of the Palmetto Point Project, which included costs for the PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52 wells, were $793,555 as of July 31, 2011. The interests are located in Mississippi.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

3. OIL AND GAS INTERESTS (continued)

Frio-Wilcox Project, Mississippi

On August 2, 2006, the Company signed a memorandum agreement with Griffin & Griffin LLC (the “Operator”) to participate in two proposed drilling programs located in Mississippi and Louisiana. The Company acquired a 10% working interest in this project before production and a prorated reduced working interest after production based on the Operator’s interest portion. The Company paid $400,000 for the interest.

On June 21, 2007, the Company assigned all future development obligations for any new well at its Frio-Wilcox Prospect to a third party. The Company maintained its original interest, rights, title and benefits to all seven wells drilled with the Company’s participation at the Frio-Wilcox Prospect property between August 3, 2006 and June 19, 2007, specifically wells CMR-USA-39-14, Dixon #1, Faust #1 TEC F-1, CMR/BR F-14, RB F-1 Red Bug #2, BR F-33, and Randall #1 F-4, and any offset wells that could be drilled to any of these specified wells.

Impairment

Under the full cost method, the Company is subject to a ceiling test. This ceiling test determines whether there is an impairment to the proved properties. The impairment amount represents the excess of capitalized costs over the present value, discounted at 10%, of the estimated future net cash flows from the proven oil and gas reserves plus the cost, or estimated fair market value. There was no impairment cost for the nine-month periods ended July 31, 2011 and 2010, respectively.

Depletion

Under the full cost method, depletion is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production. Depletion expense recognized was $282,241 and $172,128 for the nine-month periods ended July 31, 2011 and 2010, respectively.

Capitalized Costs

	July 31, 2011			October 31, 2010
Proved properties	$	3,804,140		$	3,188,673
Unproved properties		680,238			809,037
Total Proved and Unproved properties		4,484,378			3,997,710
Accumulated depletion expense		(1,482,893	)		(1,200,652	)
Impairment		(219,539	)		(219,539	)
Net capitalized cost	$	2,781,946		$	2,577,519

Results of Operations

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

	July 31, 2011			July 31, 2010
Revenues	$	1,062,679		$	482,229
Production costs		(162,262	)		(62,807	)
Depletion and accretion		(285,481	)		(175,458	)
Results of operations (excluding corporate overhead)	$	614,936		$	243,964

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

4. ASSET RETIREMENT OBLIGATIONS

The Company follows FASB ASC 410-20 “Accounting for Asset Retirement Obligations” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This policy requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. As of July 31, 2011 and October 31, 2010, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with “Accounting for Asset Retirement Obligations”. The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production. The Company amortizes the amount added to the oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining life of the respective well. The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is a discounted liability using a credit-adjusted risk-free rate of 12%. Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.

The Company amortizes the amount added to oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining useful lives of the respective wells.

The information below reflects the change in the asset retirement obligations during the nine-month period ended July 31, 2011 and the year ended October 31, 2010:

	July 31, 2011		October 31, 2010
Balance, beginning of periods	$	27,494	$	37,011
Liabilities assumed		-		2,700
Revisions		-		(16,658	)
Accretion expense		3,240		4,441
Balance, end of periods	$	30,734	$	27,494

The reclamation obligation relates to the Kodesh, Dye Estate, KC 80 and William wells at the Three Sands Property; the Palmetto Point Project well at the Frio-Wilcox Project; and ARD#1-36, Bagwell#1-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24, Jack#1-13 and Miss Jenny#1-8 wells at Oklahoma Properties. The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes in applicable laws and regulations. Such changes will be recorded in the accounts of the Company as they occur.

5.	COMMON STOCK

STOCK OPTIONS

Although the Company does not have a formal stock option plan, all options granted in the past have been approved by the Board of Directors.

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

On October 30, 2009, the Company granted a non-qualified stock option with respect to 200,000 shares to the CFO. The exercise price is $0.10 per share. The options are fully vested and expire on October 30, 2011.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

5. COMMON STOCK (continued)

STOCK OPTIONS (continued)

On November 2, 2009, the Company granted a non-qualified stock option with respect to 300,000 shares to the President. The exercise price is $0.10 per share. The options are fully vested and expire on November 2, 2011.

A summary of the changes in stock options for the nine-month period ended July 31, 2011 is presented below:

	Options Outstanding
				Weighted Average
	Number of Shares			Exercise Price
Balance, October 31, 2009		400,000		$	0.17
Granted on November 2, 2009		300,000			0.10
Expired on November 2, 2009		(200,000	)		0.24
Exercised		-			-
Balance, October 31, 2010		500,000		$	0.10
Balance, July 31, 2011		500,000		$	0.10

The Company has the following options outstanding and exercisable.

July 31, 2011	Options outstanding and exercisable
Range of exercise prices	Number of shares	Weighted average r emaining contractual life	Weighted Average Exercise Price
$0.10 $0.10	200,000 300,000	0.24 years 0.25 years	0.10 0.10

6. RELATED PARTY TRANSACTIONS

During the nine-month periods ended July 31, 2011 and 2010, the Company entered into the following transactions with related parties:

a)	The Company paid $54,000 (2010 - $45,000) in management fees and reimbursement of office space of $3,600 (2010 - $3,600) to the President of the Company.

b)	The Company paid $53,000 (2010 - $45,000) to a related entity, for administration services.

c)	The Company paid $75,500 (2010 - $67,500) in management fees to the director of the Company.

d)	The Company paid $57,628 (2010 - $53,509) in consulting and accounting fees to the Chief Financial Officer of the Company.

7. SUBSEQUENT EVENTS

On August 12, 2011, the Company signed an asset purchase agreement to sell the oil and gas assets in Mississippi for a total of $400,000 and 800,000 shares of restricted common stock with a deemed price of $0.30 per share from Lexaria Corp. These properties consist principally of the Belmont Lake Oil Field and all undeveloped acreage in the Palmetto Point Project. Under the asset purchase agreement, the Company received $200,000 on August 12, 2011.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are an independent oil and gas company engaged in exploration, development and production of oil and natural gas. As production of these products continues, they will be sold to purchasers in the immediate area where the products are extracted.

Our original business plan was to proceed with the exploration of the Antelope Pass Project to determine whether there were commercially exploitable reserves of gold located on the property comprising the mineral claims. Based on the geological report and recommendation prepared by Leroy Halterman, who was our geological consultant at that time, we completed geological mapping, sampling and assaying in connection with the first phase of a staged exploration program during the fiscal year ended October 31, 2004. In 2005, we suspended our activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on the Antelope Pass Project during the fiscal years ended October 31, 2010 or 2009 or the nine months ended July 31, 2011. At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project.

Our plan of operations is to continue to produce commercial quantities of oil and gas and to drill new exploratory and development wells and re-entries to test the oil and gas productive capabilities of our oil and gas properties. In addition to the drilling and producing of oil and gas wells, we have expanded and plan to continue to expand into exploration and project acquisition through the participation in new 3-D geophysical surveys and related project acquisitions.

Oil and Gas Properties

“Bbl” is defined herein to mean one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

“Mcf” is defined herein to mean one thousand cubic feet of natural gas at standard atmospheric conditions.

“Working interest” is defined herein to mean an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the mineral owners of royalties.

Note that all production amounts disclosed for the individual properties below are for 100% of the production for such property and not the production amount relating only to the Company’s working interest.

2008-3 Drilling Program, Oklahoma. On January 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581. We agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. From January 2009 to July 2009, we expended $213,925 in addition to $18,850 that was spent in previous periods. The total cost of the 2008-3 Drilling Program as of July 31, 2011 was $290,938. The interests are located in Garvin County, South Central Oklahoma.

This program is composed of four 3-D seismically defined separate prospects with one exploratory well in three of the prospects and two in the fourth prospect. Targeted pay zones include the prolific Bromide Sands, Viola Limestone, Deese Sandstone and Layton Sandstone. One of the wells has very similar geology and structure to the Bromide sands in the Owl Creek field.

Five wells were drilled during 2009. Production casing was set on four of the five wells and the fifth well was deemed non-commercial and was plugged and abandoned. Two of the four completed wells are still producing commercial quantities of oil and gas, with one of the wells still flowing naturally and producing most of the oil.

During calendar year 2011, at least one development well is planned to be drilled. As of July 31, 2011, the two producing wells in this program have produced a total of 163,702 Bbls of oil and 32,181 Mcf of natural gas.

In July 2011, a development well offsetting the best well in the program was drilled on the prospect to recover the reserves that could not be recovered from the initial well that was still producing at a rate of 100 Bbls of oil per day from the lowest pay zones. The new well was perforated on September 1, 2011 and started flowing oil immediately after perforation. The initial flow rate was approximately 12 Bbls of oil per hour or 298 Bbls of oil per day. Flow rate from the well since perforation has declined and the decision was made to place the well on a pump. It is anticipated that once the well is on pump, it should produce at least 100 Bbls of oil per day for an extended period of time.

2009-2 Drilling Program, Oklahoma. On June 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,562. We agreed to participate in the drilling operations to casing point in the initial test well of each of three prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The interests are located in Garvin County, Oklahoma. A total of three wells were drilled in this program and targeted pay zones that were the same as in the 2008-3 program. The zones included the prolific Oil Creek, Bromide Sands, Viola, Deese and Layton Sandstone. This program is composed of three 3-D seismically defined separate prospects. All wells were drilled in the last fiscal quarter of 2009. Two of the wells were deemed non-commercial and were plugged and abandoned. Production casing was set on one of the three wells and completion efforts have taken place on the third well; however, after testing it was also deemed non-commercial and plugged. As of July 31, 2011, the total cost of the 2009-2 Drilling Program was $114,420.

2009-3 Drilling Program, Oklahoma. On August 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775. We agreed to participate in the drilling operations to casing point in the initial test well on each of four prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The total costs incurred, including drilling costs, as of July 31, 2011 was $303,606. The interests are located in Garvin County, Oklahoma. Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands. This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the four prospects. All four of the wells have been drilled and production casing has been set on all four. Two of the wells had successful drill stem tests that flowed oil and gas to the surface. Electric and radiation logs indicate multiple pay zones in all four wells.

One of the four wells in this program was completed in late January 2010 as a flowing oil and gas well. The well was flowing naturally at rates between 400 and 500 barrels of fluid per day with an oil cut of between 50% and 70% oil. Natural gas was being produced at a rate of over 400 Mcf per day. The well only produced for a few days before snow and ice storms forced shutting the well in because the produced oil and water could not be hauled away from the location and the storage tanks for these liquids were full. Conditions have improved and the well is now producing and selling oil and natural gas. The second well that also had a flowing drill stem test was completed in late March 2010 and that well is currently producing as a naturally flowing oil and gas well. Total production from these two producing wells as of July 31, 2011 totaled 119,894 Bbls of oil and 33,748 Mcf of natural gas.

In late June 2010, a successful development well was drilled as an offset to the naturally flowing well. This development well was completed in early August 2010 and after 11 months is producing at a rate of 150 Bbls of oil and 20 Mcf of natural gas per day and is expected to add significantly to this program’s future oil and gas production. Total production from this producing well as of July 31, 2011 was 83,446 Bbls of oil and 8,593 Mcf of natural gas.

The two remaining wells were completed in late May 2010. After testing, both wells were deemed to be non-commercial and have been plugged and abandoned.

2009-4 Drilling Program, Oklahoma. On December 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-4 Drilling Program for a total buy-in cost of $13,482. We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The total costs incurred, including drilling costs, as of July 31, 2011 was $190,146. The interests are located in Garvin County, Oklahoma. Targeted pay zones include the prolific Oil

Creek, Bromide Sands, Viola and Deese sands. This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the two prospects.

Drilling of the first well started in early February 2010 and reached total depth on February 20, 2010. The second well drilling started in late February 2010 and reached total depth on April 8, 2010. Both of the wells intercepted multiple potential productive horizons and production casing was set. The lowest horizon in the first well flowed oil and gas on a drill stem test. Weather was initially a problem with heavy rain causing flooding and other delays but both wells have now been completed. Both wells were treated for a poor cement bond and only one remains in production. The one well that could not be successfully treated for the poor cement bond was plugged and abandoned. Another well is being drilled as a twin to this well. If it is not successful it will be left unplugged as a possible salt water disposal well. As of July 31, 2011, both wells have been plugged and abandoned after producing a few thousand Bbls of oil.

2010-1 Program, Oklahoma. On April 23, 2010, we acquired a 5% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,163. We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The total cost incurred, including drilling costs, as of July 31, 2011 was $270,716. The interests are located in Garvin County, Oklahoma. Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands. This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the two prospects.

As of late October 2010, all four wells of the four-well program had been drilled. Three of the wells had production casing set and one well was plugged and abandoned. The three successful wells intercepted multiple pay zones including the prolific lowest zone. One well had a flowing drill stem test but the other two wells were not drill stem tested. All three wells show excellent porosity, permeability, and hydrocarbon shows. Completion of these wells started in mid-September. Two of the wells have been completed in the deepest pay zone with one well producing 20 Bbls of oil and the second was producing at a rate of 270 Bbls of oil per day in July 2011. Total production from these wells as of July 31, 2011 was 56,001 Bbls of oil and 6,482 Mcf of natural gas. As of July 31, 2011, the wells were producing at a combined rate of 300 barrels Bbls of oil and 80 Mcf of natural gas.

South Wayne Prospect, Oklahoma. On March 14, 2010, we acquired a 5% working interest in Okland Oil’s South Wayne prospect for a total buy-in cost of $5,000 and dry hole costs of $32,370. We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The total cost incurred, including drilling costs, as of July 31, 2011 was $61,085. The well and related leasehold interests are located in McClain County, Oklahoma. As of October 31, 2010, the well had been drilled and production casing has been set. The well was perforated in July 2010 and immediately started flowing oil at a rate of 200 Bbls per day. The flow of oil was slowed and stopped due to a buildup of paraffin. A pumping unit was placed on the well in late August 2010 and the well is now producing at a rate of 20-25 Bbls of oil and 23 Mcf of natural gas and no water. Total production for the McPherson well as of July 31, 2011 was 15,825 Bbls of oil and 8,623 Mcf of natural gas. Additional pay zones are located above the currently producing horizon and it is anticipated that these zone will be perforated in the future adding additional production to the well.

Washita Bend 3D Exploration Project, Oklahoma. On March 1, 2010, we agreed to participate with a 5% working interest in a 3-D seismic program managed by Ranken Energy Corporation for a buy-in cost of $46,250. The Oklahoma 3-D seismic program will cover approximately 135 square miles in a known oil and gas producing area. An earlier 2-D seismic program over the same area indicated a number of untested structures. We expect the 3-D program will refine and better define the structures discovered during the earlier program and pinpoint drill locations. We will participate in the seismic program and the related prospect generation and acquisition phase without any promotion. The BCP Interest shall be 5.625% and the ACP Interest shall be 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells. The total cost, including seismic costs, as of July 31, 2011 was $478,602.

Work has commenced on this project. Shooting and data acquisition started on the Oklahoma 3-D project in late February 2011. The project is slated to cover approximately 86,350 acres or 135 square miles of which

approximately 83,043 acres or 130 square miles have now been permitted. Weather related delays have intermittently forced postponement of the actual data gathering portion of the project which is now underway.

The project employs state of the art equipment and processing that will help pinpoint drill target and well locations. Initial testing to determine what sweep frequencies to be used reinforced the fact that the data to be acquired will be of high quality compared to surveys performed in the past. This survey is taking place over an area that was originally shot with 2-D seismic that located a number of anomalies but the data was not of sufficient quality to pinpoint well locations. In contrast, this 3-D survey is expected to pinpoint these locations, dramatically reducing the risk of drilling dry holes. A total of 5,148 acres of leases have been acquired thus far and leasing of additional land may start in the next several months. Drilling testing of these targets could begin as early as fall.

As of the end of the third fiscal quarter all of the permitted area had been shot and data acquired. Initial or first run processing data is nearing completion and interpretation of the data has started along with title research on several potential prospects.

Three Sands Project

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

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

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

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

Costs Including Previous Work. As of July 31, 2011, we have expended $1,451,543 in connection with the Three Sands Project, including leasing, title, drilling, and casing.

Present Activities. Drilling of the Kodesh #1 disposal well was completed on October 3, 2005 and drilling of the Kodesh #2 well was completed on October 23, 2005. Completion and equipping of these wells took place during mid-December 2005 through early January 2006. The Kodesh #1 is being used for salt water disposal well. In December 2010 and January 2011, the pump was replaced and new pay zones were perforated and fracture treated, thereby increasing production of oil and natural gas. The Kodesh #2 is now producing oil intermittently and natural gas on a daily basis. As of July 31, 2011, it has produced 3,987 Bbls of oil and 11,476 Mcf of natural gas.

During January 2007, we re-entered the Dye Estate #1 well. Production of natural gas from the Dye Estate #1 well commenced in mid-August 2007. As of July 31, 2011, the Dye Estate #1 well has produced 7,574 Mcf of natural gas and is currently averaging natural gas production at a rate of 8 Mcf per day. Water from the Dye Estate #1 well is being disposed in the Kodesh #1 disposal well.

We commenced drilling the William #4-10 well in early June 2007, reaching a total depth of 4,810 feet in mid-June 2007. Electric and radiation logs indicated that the William #4-10 well contained four potential commercial pay zones, the Wilcox Sand, Mississippi Lime, Layton Sand and the Tonkawa Sand. Completion of the

lowest zone, the Wilcox Sand, occurred in mid-August 2007. Production from the William #4-10 well started in mid-October 2007. During the first quarter of 2008, we perforated, fracture treated and tested the Mississippi Lime and the lower Layton Sand to increase the production rate of both gas and oil from the William #4-10 well and provide data regarding the potential of these formations for the remainder of the leases on the Three Sands Project. As of July 31, 2011, the William #4-10 well has produced 2,644 Bbls oil and 97,590 Mcf of gas. As of July 31, 2011, the well was producing a small amount of oil and natural gas at a rate of 111 Mcf per day.

Drilling commenced on the KC 80 #1-11 well in mid-February 2008 and reached total depth of 4,720 feet by the end of February 2008. The KC 80 #1-11 has been surveyed with radiation and electrical logs. The primary target for the well is the upper Mississippian Limestone and Chat Formation. The KC-80 well’s logs indicate significant thickness of Chat and upper Mississippi Limestone with good porosity, permeability, and hydrocarbon shows.

Completion of the KC 80 #1-11 well started in late April 2008. The lowest pay zone, the Mississippian, was acidized and partially fracture treated. In early August a similar treatment was given to the Chat zone or the horizon that lies above the lowest pay zone. As of July 31, 2011, the KC 80 #1-11 well was producing at a rate of 3 Bbls of oil and 30 Mcf of natural gas daily. As of July 31, 2011, the KC 80 #1-11 has produced 5,897 Bbls of oil and 41,097 Mcf of natural gas.

Drilling commenced on the Taylor #1 well on October 7, 2010 and reached a total depth of 4,825 feet on October 14, 2010. The primary target of the well was the Mississippian Limestone. The well was fracture treated in mid-December 2010 and production testing will follow. There was no production from this well prior to mid-December 2010. Production from this well as of July 31, 2011 totaled 1,611 Bbls of oil and 28,625 Mcf of natural gas.

Palmetto Point Project

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

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

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

The gas targets at the Palmetto Point Project occur at shallow depths and have minimal completion costs. The Frio project in the area of Southwest Mississippi and North-Central Louisiana is a very complex series of sand representing marine transgressions and regressions and resulting in the presence of varying depositional environments. Structurally, the Frio gas accumulations are a function of local structure and/or structural nose formed as a result of differential compaction features. However, stratigraphic termination (updip pinchout of sands

within shales) also plays a role in most Frio accumulations. The stratigraphy is so complex that seismic direct HCI evaluations are presently the only viable exploratory tool for the Frio prospect.

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

Costs Including Previous Work. As of July 31, 2011, we have expended $793,555 in connection with the Palmetto Point Project, including leasing, title, drilling, and casing.

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

Both the PP F-12 and the PP F-12-3 oil well locations and several of our gas well locations were flooded at the Palmetto Point Project. Prior to the flooding, we had partly completed work to install gas lift pumps at each well; however, the work could not be completed before the locations were flooded. There was virtually no damage to our surface equipment located at the well heads, as our batteries and other production facilities were located above the flood waters. The only damage was to our lost production because the well had to be shut-in. We do not believe that the flooding will adversely affect future oil recovery from these wells.

In early September 2008, flood waters had receded sufficiently and work began on placing the PP F-12 and PP F12-3 back on line and producing oil. Gas lift pumps were installed on both wells and other modification and additional equipment such as compressors were also installed. At the end of October 2009, both wells were producing oil at combined rates of between 80 and 100 Bbls of oil per day.

In early September 2010, flood waters had receded sufficiently again to resume work on the Palmetto Point Project and three development wells were drilled in the field. One well encountered only natural gas and was plugged and abandoned. The remaining two wells, 12-4 and 12-5 were completed as oil wells. One of the completed oil wells flowed naturally and contributed approximately 2,000 Bbls of oil to the production totals prior to October 31, 2010. Present activities include completion of a source gas well, completing a salt water disposal well and running gas injection line and production line to the new wells and tanks battery. All four oil wells including both the new wells and previously drilled and completed wells were producing at the end of the second quarter.

During the three-month period ended July 31, 2011, the Belmont Lake Oil field produced 10,496 Bbls of oil and all natural gas produced was consumed on the lease for compression and gas lift for the oil produced. In mid-May 2011, all wells were shut in because oil could not be transported to the refinery due to the extreme flooding of the Mississippi River. These wells were placed back into production in early June after the water receded and have produced more or less continuously since that time.

On August 12, 2011, we entered into an agreement to sell our interest in the Belmont Lake field and all our other properties and wells located in the state of Mississippi. We received an immediate payment of $200,000 and 800,000 shares of restricted stock in Lexaria Corp. and a second payment of $200,000 is due on or before November 12, 2011. The sale of this property will allow management to focus its efforts on our Oklahoma program and the associated recently shot 3-D seismic program.

Mississippi Frio-Wilcox Joint Venture

Location and Access. The Mississippi Frio-Wilcox Joint Venture is located on the border of southern Mississippi and Louisiana along the floodplain of the Mississippi river. The area is approximately 20 miles west of

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

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

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

Proposed Program of Exploration. On June 21, 2007, we assigned our interests and all future development obligations for any new wells in the Mississippi Frio-Wilcox Joint Venture to Lexaria for the sum of $1. We believe the assigned interest to be of nominal value. We have maintained our original interest, rights, title and benefits to all seven wells drilled with our participation at the Mississippi Frio-Wilcox Joint Venture between August 3, 2006 and June 19, 2007, specifically wells CMR-USA-39-14, Dixon #1, Faust #1 TEC F-1, CMR/BR F-14, RB F-1 Red Bug #2, BR F-33, and Randall #1 F-4, and any offset wells that could be drilled to any of these specified wells.

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

Present Activities. Nine wells were drilled on the Mississippi Frio-Wilcox Joint Venture, of which, five wells were initially deemed successful and four wells were dry holes and were not completed. One of the five wells initially deemed to be successful was the BR F-24. However, subsequent testing of the BR F-24 indicated that it was not commercially viable and the well was plugged and abandoned in 2007. The four remaining successful wells were the Faust #1, USA 39-14, USA 1-37 and the BR F-33. The USA 39-14 has been completed and is now producing natural gas. As of July 31, 2011, these four wells were shut-in natural gas wells with no production. No further exploration wells are currently planned for this project.

As noted above, on August 12, 2011, we entered into an agreement to sell our interest in the Belmont Lake field and all other properties and wells located in the state of Mississippi.

King City Oil Field

Effective May 25, 2009, we entered into an agreement with Sunset Exploration to explore for oil and gas on 10,000 acres located in west central California. The agreement calls for us to earn a 20% working interest in the project by funding a maximum of 50% of a $200,000 geophysical survey composed of gravity and seismic surveys and agreeing to carry Sunset Exploration for 33.33% of dry hole cost of the first well. Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each party’s working interest. The geophysical surveys have been completed and most have been processed and interpreted. The initial surveys indicated that several more short geophysical survey lines would improve the interpretation. These additional lines have been completed and subsequently several stages of reprocessing have been applied to the original data. Based on this data, two drill locations have been selected and permitting is underway. Permitting was

thought to be near completion and drilling of one of these locations is anticipated in late June or July of 2011. However, the county passed additional oil and gas permitting regulations that will now delay the start of the well until late fall.

International Exploration Program

The Company is attempting to expand its property base by locating other resource properties internationally. Accordingly, we have hired consultants to gather data on properties that may be of interest to us. The consultants, on a best efforts basis, will attempt to acquire option agreements, lease agreements and/or the outright purchase of oil and/or gas properties internationally. As of the date of this filing, we have not found a suitable acquisition.

Mineral Interests

Antelope Pass. In 2005, we suspended our activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on the Antelope Pass Project during the nine-month period ended July 31, 2011 or during the fiscal years ended October 31, 2010 and 2009. At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project. All Bureau of Land Management fees and filing have been paid and performed making the claim valid until at least September 1, 2012.

Results of Operations

Three months ended July 31, 2011 compared to the three months ended July 31, 2010. We realized revenues of $291,527 during the three months ended July 31, 2011, compared with $254,173 during the three months ended July 31, 2010, an increase of $37,354, due to additional wells producing and an increase in commodity prices. During the three-month period ended July 31, 2011, 2,655 Bbls of oil and 7,146 Mcf of gas were produced at our oil and gas properties, as compared to 3,145 Bbls of oil and 5,321 Mcf of gas for the three months ended July 31, 2010.

We incurred production costs of $40,385 during the three months ended July 31, 2011, compared with $20,119 during the three months ended July 31, 2010, an increase of $20,266. The increase in our production costs is related to an increase in the costs of production from our producing wells.

Our depletion and accretion costs were $79,388 during the three months ended July 31, 2011, compared with $106,446 during the three months ended July 31, 2010, a decrease of $27,058. The decrease in our depletion costs is related to an increase in the reserves of the Company and a decrease in production from our wells.

Our general and administrative costs increased to $221,338 for the three months ended July 31, 2011, from $200,208 for the three months ended July 31, 2010. The increase of $21,130 is primarily attributable to an increase in payment to our consultants.

For the three months ended July 31, 2011, we incurred a net loss of $51,662, compared to a net loss of $70,899 for the three months ended July 31, 2010. The decreased loss was largely attributable to the increase in revenues and a decrease in our depletion and accretion costs.

As a result of our net income for the quarter, we had retained earnings of $738,539 at July 31, 2011.

Nine months ended July 31, 2011 compared to the nine months ended July 31, 2010. We realized revenues of $1,062,679 during the nine months ended July 31, 2011, compared with $482,229 during the nine months ended July 31, 2010, an increase of $580,450, due to additional wells producing and an increase in commodity prices. During the nine-month period ended July 31, 2011, 10,314 Bbls of oil and 19,770 Mcf of gas were produced at our oil and gas properties, as compared to 6,178 Bbls of oil and 13,302 Mcf of gas for the nine months ended July 31, 2010.

We incurred production costs of $162,262 during the nine months ended July 31, 2011, compared with $62,807 during the nine months ended July 31, 2010, an increase of $99,455. The increase in our production costs is related to an increase in production costs from our producing wells.

Our depletion and accretion costs were $285,481 during the nine months ended July 31, 2011, compared with $175,458 during the nine months ended July 31, 2010, an increase of $110,023. The increase in our depletion costs is related to a decrease in the reserves of the Company and an increase in production from our wells.

Our general and administrative costs decreased to $593,249 for the nine months ended July 31, 2011, from $679,671 for the nine months ended July 31, 2010. The decrease is primarily attributable to decreases in stock based compensation costs and investor relation costs, which were offset by increases in management fees.

For the nine months ended July 31, 2011, we earned a net income of $20,159, compared to a net loss of $433,085 for the nine months ended July 31, 2010. The income was largely attributable to the increase in revenues for the nine months ended July 31, 2011.

Liquidity and Capital Resources

As of July 31, 2011, we had cash and a certificate of deposit totaling $714,183 and working capital of $879,203, compared to cash and a certificate of deposit totaling $821,029 and working capital of $1,060,231 as of October 31, 2010. The decrease in working capital is due to amounts invested in oil and gas interests. Our accounts receivable increased to $185,393 at July 31, 2011, compared with $148,924 at October 31, 2010, an increase of $36,469. Our current liabilities decreased to $36,578 at July 31, 2011, compared with $37,777 at October 31, 2010.

During the nine months ended July 31, 2011, operating activities provided cash of $379,822, as compared to net cash provided of $91,695 for the nine months ended July 31, 2010. The principal reason for the change was due to the profitable operations for the 2011 fiscal year-to-date period.

Investing activities used net cash of $86,668 during the nine months ended July 31, 2011, compared with $711,103 used during the nine months ended July 31, 2010.

Off-Balance Sheet Arrangements

As of July 31, 2011, we did not have any off-balance sheet arrangements.

Critical Accounting Policies

Oil and Gas Interests. We utilize the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas interests unless the sale represents a significant portion of oil and gas interests and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas interests is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production. Amortizable costs include estimates of future development costs of proved undeveloped reserves.

Capitalized costs of oil and gas interests may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved interests. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying a twelve-month average of year end prices of oil and gas to estimated future production of proved oil and gas reserves as of year end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.

Asset Retirement Obligations. We follow FASB ASC 410-20 “Accounting for Asset Retirement Obligations” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This policy requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. As of July 31, 2011 and October 31, 2010, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with “Accounting for Asset Retirement Obligations.” The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production. We amortize the amount added to the oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining life of the respective well. The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is a discounted liability using a credit-adjusted risk-free rate of 12%. Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.

We amortize the amount added to oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining useful lives of the respective wells.

The information below reflects the change in the asset retirement obligations during the nine-month period ended July 31, 2011 and the year ended October 31, 2010:

	July 31, 2011		October 31, 2010
Balance, beginning of periods	$	27,494	$	37,011
Liabilities assumed		-		2,700
Revisions		-		(16,658	)
Accretion expense		3,240		4,441
Balance, end of periods	$	30,734	$	27,494

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 officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Rule 15d-15 under the Exchange Act, requires us to carry out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of July 31, 2011, being the date of our most recently completed fiscal quarter. This evaluation was conducted under the supervision and with the participation of our officers, Leroy Halterman and Kulwant Sandher. Based on this evaluation, Messrs. Halterman and Sandher concluded that the design and operation of our disclosure controls and procedures are not effective since the following material weaknesses exist:

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

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

Changes in Internal Controls Over Financial Reporting

In connection with the evaluation of our internal controls during our last fiscal quarter, our officers have concluded that there were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended July 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

None.

Item 1A. Risk Factors

Not required for smaller reporting companies.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Removed and Reserved

Not applicable.

Item 5. Other Information

Not applicable

Item 6. Exhibits.

Regulation S-K Number	Exhibit
3.1	Articles of Incorporation (1)
3.2	Certificate of Change Pursuant to NRS 78.209 (2)
3.3	Amendment to the Articles of Incorporation (3)
3.4	Amended and Restated Bylaws (4)
4.1	Certificate of Designation of Rights, Preferences, and Privileges for Series A Preferred Stock (4)
31.1	Rule 15d-14(a) Certification of Principal Executive Officer
31.2	Rule 15d-14(a) Certification of Principal Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer

________________

(1)	Incorporated by reference to the exhibits to the registrant’s registration statement on Form SB-1, file number 333-102441.

(2)	Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated September 26, 2004, filed September 27, 2004.

(3)	Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated December 3, 2008, filed January 13, 2009.

(4)	Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated December 11, 2009, filed December 15, 2009.

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.