BRINX RESOURCES LTD - FORM 10-K

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - BRINX RESOURCES LTD	Financial_Report.xls
EX-3.5 - EXH 3-5 AMD TO BYLAWS - BRINX RESOURCES LTD	exh3-5_amdbylaws.htm
EX-10.1 - EXH 10-1 MGT CONSULTING AGMT - BRINX RESOURCES LTD	exh10-1_agreement.htm
EX-31.1 - EXH 31-1 CERTIFICATION - BRINX RESOURCES LTD	exh31-1_certification.htm
EX-32.2 - EXH 32-2 CERTIFICATION - BRINX RESOURCES LTD	exh32-2_certification.htm
EX-31.2 - EXH 31-2 CERTIFICATION - BRINX RESOURCES LTD	exh31-2_certification.htm
EX-32.1 - EXH 32-1 CERTIFICATION - BRINX RESOURCES LTD	exh32-1_certification.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended October 31, 2011

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

For the transition period from to

Commission file number: 333-102441

BRINX RESOURCES LTD.

(Exact name of registrant as specified in its charter)

Nevada 98-0388682

(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)

820 Piedra Vista Road NE, Albuquerque, NM 87123

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (505) 250-9992

Securities registered under Section 12(b) of the Act: None

Securities registered under Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. [ ]Yes [X]No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. [X]Yes [ ]No

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).

[X]Yes [ ]No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

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 Act). [ ]Yes [X]No

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. $2,962,380 as of April 30, 2011

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 24,629,832 as of February 9, 2012

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements.” All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or the negative thereof or variations thereon or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) include, but are not limited to, our assumptions about energy markets, production levels, reserve levels, operating results, competitive conditions, technology, the availability of capital resources, capital expenditure obligations, the supply and demand for oil and gas, the weather, inflation, the availability of goods and services, oil and natural gas drilling risks, general economic conditions (either internationally or nationally or in the jurisdictions in which we are doing business), legislative or regulatory changes (including changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations), the securities or capital markets and other factors disclosed under “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations,” “Item 2. Properties” and elsewhere in this report. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the Cautionary Statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

“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.

PART I

ITEM 1. BUSINESS.

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 produced.

Until 2005, our focus was on our undeveloped mineral interests and we were considered, at that time, to be a development stage company engaged in the acquisition and exploration of mineral and oil and gas properties. We still hold an interest in undeveloped mineral interests located in New Mexico (the “Antelope Pass Project”). However, in 2005, we suspended activities on our undeveloped mineral properties indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on our undeveloped mineral properties during the fiscal year ended October 31, 2011.

During 2005 and 2006, we acquired undeveloped oil and gas interests and commenced exploration activities on those interests. The undeveloped oil and gas interests were located in Oklahoma, Mississippi and California. In 2006, we commenced oil and gas production and started earning revenues.

Our plan of operations is to continue to produce commercial quantities of oil and gas and to drill re-entries to test the oil and gas productive capabilities of our oil and gas properties. As noted above, we have suspended our efforts indefinitely on the Antelope Pass Project in order to focus on our oil and gas interests.

Corporate Background

We were incorporated under the laws of the State of Nevada on December 23, 1998, initially to explore mining claims and property in New Mexico.

Property Acquisitions and Dispositions

Palmetto Point Project

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

On January 30, 2008, we incurred $36,498 for workovers to install submersible pumps. From November 2008 to July 2009, we incurred $44,623 for the Belmont Lake Project. The total cost of the Palmetto Point Project, including costs for the PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52 wells, was $732,630 as of August 12, 2011.

On August 12, 2011, we signed the asset purchase agreement with Lexaria Corp., a Nevada corporation (“Lexaria”), to sell our oil and gas assets in Mississippi for a total of $400,000 and 800,000 shares of restricted common stock with a fair value of $0.34 per share from Lexaria treasury. These properties consist principally of the Belmont Lake Oil Field and all undeveloped acreage in the Palmetto Point Project. The sum of $200,000 was deposited on August 12, 2011 and a final payment of $200,000 was made on January 13, 2012. The disposed reserves represented more than 25% of the total reserves which we considered to represent a significant alteration between capitalized costs and proved reserves and hence a loss on the sale was recognized in the Statement of Operations in the amount of $109,299.

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, 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 held a 10% working interest in the Mississippi Frio-Wilcox Joint Venture project before production and a prorated reduced working interest after production based on the operator’s interest portion.

On June 21, 2007, we assigned our 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 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.

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 to Lexaria.

Three Sands Project

On October 6, 2005, we acquired a 40% working interest in Vector Exploration Inc.’s Three Sands Project for a total buy-in cost of $88,000 plus dry hole costs (the “Three Sands Project”). The Three Sands Project is located in Oklahoma. For the year ended October 31, 2006, we expended $530,081 in exploration costs. In June 2007, we acquired a 40% working interest in the William #4-10 well for a total cost of $285,196 and paid a further $17,000 in costs relating to the well. On March 19, 2008, we participated in the KC 80 #1-11 well and paid $75,000 for the prepaid drilling costs. During March and April 2008, we expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 from May to July 2008 for the KC 80 #1-11 well. The total cost of the Three Sands Project as of October 31, 2011 was $1,451,543. Our working interest in the Three Sands Project includes leasehold interests, one re-entry production well, one salt water disposal well and three drilled oil and gas wells. We also participate in drilling operations and related costs, in proportion to our 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 Before Casing Point (“BCP”) Interest shall be 6.25% and the After Casing Point (“ACP”) Interest shall be 5.00%. From January to July 2009, we expended an additional $213,925 in addition to $18,850 that was spent in previous periods. The well, Wigley #1-11, was abandoned during March 2009, and the cost and its buy-in cost total of $33,423 were moved to the proved properties pool. Selman #1-21 and Bagwell #1-20 started producing during May 2009, Ard #1-36 started producing during June 2009, and Selman #2-21 started producing during July 2009. The Selman #2-21 was later abandoned in April 2010. The interests are located in Garvin County, Oklahoma. The total cost of the 2008-3 Drilling Program was $302,361 as of October 31, 2011.

King City, California

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. We paid $100,000 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 parties’ working interest. The total cost of the King City Prospect was $263,561 as at October 31, 2011.

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 prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The well, James #1-18, was abandoned in September 2009 and the cost and its buy-in cost total of $41,934 were moved to the proved properties pool. Little Chief #1-3 was abandoned in November 2009 and the cost and its buy-in cost total of $35,528 were moved to the proved properties pool. J.C. Carlton #1-31 was abandoned in April 2010 and the cost and its buy-in cost total of $38,630 were moved to the proved properties pool. As of October 31, 2011, the total cost of the 2009-2 Drilling Program was $114,420. The interests are located in Garvin County, Oklahoma.

2009-3 Drilling Program, Oklahoma

On August 12, 2009, we acquired a 5.00% 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 of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Jackson #1-18 started producing in January 2010 and an amount of $63,725, which included the buy-in cost, was moved to the proved properties pool. Miss Gracie #1-18 started producing in March 2010 and an amount of $62,268, which included its buy-in cost, was moved to the proved properties pool. Brewer #1-20 was abandoned in June 2010 and the cost and its buy-in cost total of $64,936 were moved to the proved properties pool. Waunice #1-36 started producing in June 2010 and an amount of $43,848, which included its buy-in cost, was moved to the proved properties pool. It was later abandoned in September 2010. The total cost of the 2009-3 Drilling Program, including drilling costs, as of October 31, 2011, was $300,080. The interests are located in Garvin County, Oklahoma.

2009-4 Drilling Program, Oklahoma

On December 19, 2009, we acquired a 5.00% 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 of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Dennis #1-8 started producing in May 2010 and an amount of $79,892, which included the buy-in cost, was moved to the proved properties pool. It was later abandoned in September 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 $49,637 which included the buy-in cost was moved to the proved property pool. As of October 31, 2011, the total cost of the 2009-4 Drilling Program was $190,146. The interests are located in Garvin County, Oklahoma.

Washita Bend 3D Exploration Project, Oklahoma

On March 1, 2010, we 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 of October 31, 2011, the total cost, including seismic costs, was $482,882.

South Wayne Prospect, Oklahoma

On March 14, 2010, we acquired a 5.00% working interest in McPherson #1-1 well for a payment of $5,000 for leasehold, prospect and geophysical fees, and dry hole costs of $32,370. The total cost, including drilling costs, as of October 31, 2011 was $61,085. 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%. The interests are located in McClain County, Oklahoma.

2010-1 Drilling Program, Oklahoma

On April 23, 2010, we acquired a 5.00% 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 of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Julie #1-14 was abandoned in October 2010 and the cost and buy-in cost total of $47,035 were moved to the proved properties

pool. 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 $58,995, which included the buy-in cost, was moved to the proved property pool. As of October 31, 2011, the total cost of the 2010-1 Drilling Program was $253,855. The interests are located in Garvin County, Oklahoma.

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.

Antelope Pass Project

In September 2002, we acquired a 100% interest in leases on unpatented lode mining claims in the Antelope Pass Project, located in the Hidalgo County, New Mexico for $811, from Leroy Halterman, who was a non-affiliate of our company at that time. The Antelope Pass Project consists of the Kendra 1 through Kendra 8 mineral claims. Unpatented claims are mining claims for which the holder has no patent, or document that conveys title. The 2011-2012 Bureau of Land Management maintenance fee has been paid and the claims are valid until August 31, 2012 without any additional expenditure. We have suspended our efforts indefinitely on the Antelope Pass Project.

Exploration and Acquisition Capital Expenditures

During the fiscal years ended October 31, 2011, 2010, and 2009, we incurred $625,941, $1,170,104, and $668,446, respectively, in identifying and acquiring oil and natural gas interests, and for exploration costs.

Principal Products

We conduct exploration activities to locate oil and natural gas. As we continue our production of these products, we anticipate that generally they will be sold to purchasers in the immediate area where the products are produced. We expect that the principal markets for oil and natural gas will continue to be refineries and transmission companies that have facilities near our producing properties.

Competition

Oil and gas exploration, mineral exploration and acquisition of undeveloped properties are highly competitive and speculative businesses. We compete with a number of other companies, including major mining and oil and gas companies and other independent operators that are more experienced and which have greater financial resources. We do not hold a significant competitive position in either the mining industry or the oil and gas industry.

Major Customers

During the fiscal years ended October 31, 2011 and 2010, we collected $798,912 (64%) and $451,359 (69%), respectively, of our revenues from Ranken Energy Corporation, the operator of the Oklahoma Properties. Since we work with only a few operators, we will continue to be dependent on these few operators for a substantial portion of our revenues in fiscal year 2012.

Compliance with Government Regulation

Our oil and gas operations are subject to various levels of government controls and regulations in the United States. Legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, numerous federal, state and local departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of

which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas drilling, gas processing plants and production activities, increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. A breach or violation of such laws and regulations may result in the imposition of fines and penalties. At present, we do not believe that compliance with environmental legislation and regulations will have a material effect on our operations; however, any changes in environmental legislation or regulations or in our activities may cause compliance with such legislation and/or regulation to have a material impact on our operations. In addition, certain types of operations require the submission and approval of environmental impact assessments. Environmental legislation is evolving in a manner that means stricter standards, and enforcement, fines and penalties for non-compliance are becoming more stringent. Environmental assessments of proposed projects carry a heightened degree of responsibility for companies and directors, officers and employees. The cost of compliance with changes in governmental regulations has a potential to reduce the profitability of operations. We intend to ensure that we comply fully with all environmental regulations relating to our operations.

With respect to our Oklahoma oil and gas interests, we are required to file Oklahoma Form 1000 and pay $100 to obtain state permits for oil and gas drill sites on private lands. Although we do not presently hold any interest in leases on state or federal lands, in the future we may be required to obtain environmental assessments in connection with wildlife impacts or archeological clearances.

With respect to our Antelope Pass Project, we will be required to conduct all mineral exploration activities in accordance with the Bureau of Land Management (“BLM”) of the United States Department of the Interior. If we proceed with our Antelope Pass Project, we will be required to obtain a permit prior to the initiation of exploration. To obtain a permit we will have to submit plans of operations to both the BLM and the State of New Mexico as part of our permit application.

Employees

Leroy Halterman serves as our president and secretary and a director. As of the date of this report, Mr. Halterman receives monthly management fees of $6,000. For the fiscal years ended October 31, 2011 and 2010, we incurred $72,000 and $60,000, respectively, for Mr. Halterman’s services. As of September 30, 2011, we no longer reimburse Mr. Halterman for office space.

We engaged Kulwant Sandher to serve as our chief financial officer on a part-time basis beginning November 2009 and pay him CAD$2,500 plus taxes per month. For the fiscal years ended October 31, 2011 and 2010, we paid Mr. Sandher $76,813 and $72,068, respectively, for his services.

We pay management fees of $8,500 per month to Kenneth Cabianca, one of our directors. For the fiscal years ended October 31, 2011 and 2010, we paid Mr. Cabianca $101,000 and $90,000 in management fees, respectively.

For the fiscal years ended October 31, 2011 and 2010, we incurred $71,000 and $60,000, respectively, for administrative services performed by Downtown Consulting. Downtown Consulting is an entity owned and controlled by Sarah Cabianca, the daughter of Kenneth Cabianca and one of our shareholders. We pay Downtown Consulting a monthly fee of $6,000 for its services. We anticipate that we will be conducting most of our business through agreements with consultants and third parties. We have not entered into any arrangements or negotiations with any other consultants or third parties and our employees are not covered under a collective bargaining agreement.

ITEM 1A. RISK FACTORS.

Not required for smaller reporting companies.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

Not required for smaller reporting companies.

ITEM 2. PROPERTIES.

Oil and Gas Properties

Recently Disposed Mississippi Properties

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.

Sale. 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 final payment of $200,000 was paid on January 13, 2012. 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. The Mississippi Frio-Wilcox Joint Venture program described below was the successor to the Palmetto Point Program.

Activities Prior to Sale. 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. 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.

Costs Including Previous Work. As of August 12, 2011, we had expended $732,630 in connection with the Palmetto Point Project, including leasing, title, drilling, and casing.

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.

Sale. 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.

Activities Prior to Sale. 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. At that time, we 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 August 12, 2011, we had expended $400,000 in connection with the Mississippi Frio-Wilcox Joint Venture, including leasing, title, drilling, and casing.

Current Oklahoma Projects

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 October 31, 2011 was $302,361. 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. One development well was drilled in August of 2011 near the highest producing well in the program. As of October 31, 2011, the three producing wells in this program have produced a total of 176,407 Bbls of oil and 34,915 Mcf of natural gas.

2009-2 Drilling Program, Oklahoma. On June 15, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,563. 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 October 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 October 31, 2011 was $300,080. 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 Bbls 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 oil and gas with the use of a pumping unit. The second well that also had a flowing drill stem test was completed in late March 2010 and that well is currently producing oil and natural gas with the use of a pumping unit. Total production from these two producing wells as of October 31, 2011 totaled 133,276 Bbls of oil and 34,911 Mcf of natural gas.

In late June 2010, a successful development well was drilled as an offset to the naturally flowing well that is still producing at a rate of 90 Bbls oil and 11 Mcf of natural gas per day with the aid of a pumping unit. This development well was completed in early August 2010 and is still producing with the aid of a pumping unit at a rate

of 130 Bbls of oil and 18 Mcf of natural gas per day and should add significantly to this program’s future oil and gas production. Total production from this producing well as of October 31, 2011 was 96,304 Bbls of oil and 10,766 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 October 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 October 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 October 31, 2011 was $253,855. 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 2010. All three of the wells have been completed in the deepest pay zone as of October 31, 2011 with one well producing at a rate of 11 Bbls of oil per day, a second producing at a rate of 15 Bbls of oil and the third was producing at a rate of 230 Bbls of oil per day in October 2011. Total production from these wells as of October 31, 2011 was 102,234 Bbls of oil and 18,923 Mcf of natural gas. As of October 31, 2011, the wells were producing at a combined rate of 255 Bbls of oil and 65 Mcf of natural gas per day.

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 October 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 water free at a rate of 31 Bbls of oil and 20 Mcf of natural gas. Total production for the McPherson well as of October 31, 2011 was 18,606 Bbls of oil and 10,414 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 October 31, 2011 was $482,882.

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 lands is now under way.

As of October 31, 2011, all of the permitted area had been shot and data acquired. All initial or first run processing data has been completed and interpretation of the data and mapping as well as prospect delineation has started. Title research and leasing on a number of potential prospects is underway and it is anticipated that an up to 10-well exploration program on 10 separate prospects will start after the first of the year.

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 October 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 January 2011, the pump was replaced on the Kodesh #2 well and a new pay zone was perforated and fracture treated, increasing production of oil and natural gas. As of October 31, 2011, it has produced 4,449 Bbls of oil and 12,739 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 October 31, 2011, the Dye Estate #1 well has produced 8,752 Mcf of natural gas and is currently averaging natural gas production at a rate of 11 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 October 31, 2011, the William #4-10 well had produced 2,670 Bbls oil and 108,116 Mcf of gas. The well is currently producing a small amount of oil per day and natural gas at a rate of 115 Mcf of natural gas.

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

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 October 31, 2011, the KC 80 #1-11 well is producing at a rate of 2 Bbls of oil and 30Mcf of natural gas daily. As of October 31, 2011, the KC 80 #1-11 has produced 6,109 Bbls of oil and 43,809 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. The well is currently producing at a rate of 3 Bbls of oil per day and 103 mcf of gas per day. Production from this well as of October 31, 2011 totaled 1,863 Bbls of oil and 38,807 Mcf of natural gas.

The Three Sands Project lies in an area where there has been considerable recent leasing and drilling activity for horizontal development of the relatively shallow pay zones. We, together with our partners, will consider farming out the non-producing well bore portions of this prospect for cash and overrides but plan to retain our current producing well bores. We will continue to focus on our upcoming 3D seismic drilling program in southern Oklahoma.

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 40% of dry hole cost of the first well. The total cost of the King City Oil Field as at October 31, 2011 was $263,561. 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. In midsummer 2011, permitting of the first drill hole began and the well was started in mid-November 2011. Production casing

was set on November 28, 2011 and was completed in January 2012.

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.

Production and Prices

The following table sets forth information regarding net production of oil and natural gas, and certain price and cost information for fiscal years ended October 31, 2011, 2010 and 2009.

	For the fiscal year ended October 31, 2011	For the fiscal year ended October 31, 2010	For the fiscal year ended October 31, 2009
Production Data:
Natural gas (Mcf)	26,662	17,574	18,597
Oil (Bbls)	11,962	8,213	6,461
Average Prices:
Natural gas (per Mcf)	$6.01	$4.85	$2.90
Oil (per Bbl)	$89.81	$65.66	$51.41
Production Costs:
Natural gas (per Mcf)	$1.77	$2.02	$1.20
Oil (per Bbl)	$11.16	$7.25	$13.81

Productive Wells

The following table summarizes information at October 31, 2011, relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, but specifically exclude wells drilled and cased during the fiscal year that have yet to be tested for completion (e.g., all of the operated wells drilled by the Company during this year have been cased in preparation for completion, but no operations have been initiated that would allow these wells to be productive). Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests in the gross wells.

	Gross			Net
Location	Oil	Gas	Total	Oil	Gas	Total
Oklahoma	14	0	14	0.70	0.00	0.70
California	0	0	0	0.0	0.00	0.0
Total	14	0	14	0.70	0.00	0.70

Unaudited Oil and Gas Reserve Quantities

The following unaudited reserve estimates for Oklahoma, presented as of October 31, 2011, were prepared by J L. Thomas Engineering and Harper and Associates, both independent petroleum engineering firms.

The combined estimated proved reserves prepared by J L. Thomas Engineering and Harper and Associates are summarized in the table below, in accordance with definitions and pricing requirements as prescribed by the Securities and Exchange Commission (the “SEC”). Prices paid for oil and natural gas vary widely depending upon the quality such as the Btu content of the natural gas, gravity of the oil, sulfur content and location of the production related to the refinery or pipelines.

There are many uncertainties inherent in estimating proved reserve quantities and in projecting future

production rates and the timing of development expenditures. In addition, reserve estimates of new discoveries that have little production history are more imprecise than those of properties with more production history. Accordingly, these estimates are expected to change as future information becomes available.

Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

Unaudited net quantities of proved developed and undeveloped reserves of crude oil and natural gas (all located within United States) are as follows:

	Crude Oil			Natural Gas
Changes in proved reserves	(Bbls)			(Mcf)
Estimated quantity, October 31, 2009		56,443			73,426
Revisions of previous estimate		-			-
Discoveries		45,009			42,995
Reserves sold to third parties		-			-
Production		(8,213	)		(17,574	)
Estimated quantity, October 31, 2010		93,239			98,847
Reserves sold to third parties		(37,780	)		(3,580	)
Revisions of previous estimate		(9,396	)		24,000
Discoveries		4,698			33,096
Production		(11,962	)		(26,662	)
Estimated quantity, October 31, 2011		38,799			125,701

Proved Reserves at year end	Developed	Undeveloped	Total
Crude Oil (Bbls)
October 31, 2011	36,969	1,830	38,799
October 31, 2010	70,129	23,110	93,239
October 31, 2009	25,773	30,670	56,443
Gas (MCF)
October 31, 2011	124,501	1,200	125,701
October 31, 2010	98,617	230	98,847
October 31, 2009	62,626	10,800	73,426

Oil and Gas Acreage

The following table sets forth the undeveloped and developed acreage, by area, held by us as of October 31, 2011. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves. Developed acres are acres, which are spaced or assignable to productive wells. Gross acres are the total number of acres in which we have a working interest. Net acreage is obtained by multiplying gross acreage by our working interest percentage in the properties. The table does not include acreage in which we have a contractual right to acquire or to earn through drilling projects, or any other acreage for which we have not yet received leasehold assignments. Leasing efforts were minimal during fiscal 2011 in anticipation of the large leasing efforts that have started in January 2012 on prospects within the 130 square mile Oklahoma 3D seismic program.

	Undeveloped Acres		Developed Acres
	Gross	Net	Gross	Net
Oklahoma	5,573.6	392.6	640.0	96.0
California	10,000.0	2,000.00	0	0
Total	15,573.6	2,392.6	640.0	96.0

Drilling Activity

The following table sets forth our drilling activity during the years ended October 31, 2011, 2010 and 2009. We drilled less wells in 2011 as we plan to drill numerous future wells based upon prospect generated by the new 135 square mile Oklahoma 3D seismic program.

	2011		2010		2009
	Gross	Net	Gross	Net	Gross	Net
Exploratory wells:
Productive	1	.05	9	0.45	8	.40
Dry	0	.05	4	0.20	3	.15
Development wells:
Productive	1	.2	4	0.47	0	0
Dry	0	0	1	0.085	0	0

Total wells	2	.3	18	1.205	11	.55

Mineral Property

Antelope Pass Project

We suspended activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties in 2005. We have not conducted any operations or exploration activities on the Antelope Pass Project since 2005. To date, we have expended $1,981 in connection with the Antelope Pass Project, including geological mapping, sampling and assaying.

Location and Access. The Antelope Pass Project is located in west central Hidalgo County, New Mexico, approximately ten miles east of the New Mexico-Arizona border. The Antelope Pass Project lies in the Peloncillo Mountains, 35 miles southwest of Lordsburg, New Mexico. The closest major air service to the property is located in Tucson, Arizona. Access to the property is from Tucson traveling east via Interstate Highway 10 for approximately 130 miles to the Animas, New Mexico exit. From that exit, travel is south 20 miles on State Highway 338 to the town of Animas and then west for seven miles via State Highway 9. The property can be reached on gravel roads and dirt tracks.

The property is comprised of low hills and alluvial valleys, with elevations ranging from a low of 4,480 feet to a high of 4,580 feet. Vegetation is sparse and includes desert grasses, cacti, and creosote bushes. The Antelope Pass Project consists of eight unpatented lode mining claims totaling 160 acres, situated in Township 27 South, Range 20 West, Sections 18 and 19 and Township 27 South, Range 21 West, Sections 13 and 24. A lode is a mineral deposit in consolidated rock as opposed to a placer deposit, which is a deposit of sand or gravel that contains particles of gold, ilmenite, gemstones, or other heavy minerals of value.

The claims are located on federal lands under the administration of the Bureau of Land Management (BLM). They are not subject to any royalties, but annual maintenance fees must be paid to the BLM of $125 per claim or a total of $1,000 for the entire claim block to keep them valid. Including federal and county filing fees, an expenditure of approximately $125 per claim for total payment of $1,000 per year for the entire claim block is required to keep the claims valid.

Under the General Mining Law of 1872, which governs our mining claims and leases, we, as the holder of the claim, have the right to develop the minerals located in the land identified in the claim. We must pay an annual maintenance fee of $125 per claim to hold the claim. Claims can be held indefinitely with or without mineral production, subject to challenge if not developed. Using land under an unpatented mining claim for anything but mineral and associated purposes violates the General Mining Law of 1872. All fees have been paid keeping the mining claims valid until August 31, 2012.

Office Space

We are using the offices of Leroy Halterman, our president. These offices are located at 820 Piedra Vista Road NE, Albuquerque, NM 87123. As of September 30, 2011 we no longer reimburse Mr. Halterman for the use of this space.

ITEM 3. LEGAL PROCEEDINGS.

In September 2010, two lawsuits were filed in the District Court of Garvin County in the State of Oklahoma by Harold Hamm (“Hamm”) against certain defendants (“Defendants”) and consolidated together alleging, among other things, that Hamm owns an interest in two oil and gas leases in Garvin County and is entitled to a 50% participatory interest. We were not named as a party in these legal proceedings, but Hamm’s allegations include a claim that he is entitled to a 50% participatory interest in the Joe Murray Farms well drilled as part of the 2009-3 Drilling Program, in which we purchased a 6.25% working interest before casing point and 5.0% working interest after casing point. We and the Defendants believe that there is no merit to Hamm’s allegations. In connection with these proceedings, the Defendants were ordered in January 2011 to escrow fifty percent (50%) of the revenues generated within the subject area pending the outcome of these proceedings. For this reason, fifty percent (50%) of the revenues we are entitled to that have been generated by production from the Joe Murray Farms well is being escrowed and there is no assurance that we will be able to recover these proceeds. As of October 31, 2011, we recognized $119,295 in revenue from the Joe Murray Farms well and $119,295 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

ITEM 4. (Removed and Reserved).

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our common stock was listed for quotation on the OTC Bulletin Board from July 27, 2004 to February 23, 2011 and has been quoted on the OTC.QB since that date under the symbol “BNXR”. The following table sets forth the range of high and low bid quotations for each fiscal quarter of the last two fiscal years. These quotations reflect inter-dealer prices without retail mark-up, markdown, or commissions and may not necessarily represent actual transactions.

	Bid Prices
2010 Fiscal Year	High	Low
Quarter ending 01/31/10	$0.395	$0.065
Quarter ending 04/30/10	$0.32	$0.155
Quarter ending 07/31/10	$0.195	$0.07
Quarter ending 10/31/10	$0.139	$0.05

2011 Fiscal Year
Quarter ending 01/31/11	$0.139	$0.1
Quarter ending 04/30/11	$0.144	$0.1
Quarter ending 07/31/11	$0.185	$0.13
Quarter ending 10/31/11	$0.17	$0.12

As of January 18, 2012, there were 34 record holders of our common stock. The closing bid price of our stock on February 9, 2012 was $0.16

Since our inception, no cash dividends have been declared on our common stock.

We had no sales of unregistered securities during the quarter ended October 31, 2011.

ITEM 6. SELECTED FINANCIAL DATA.

Not required for smaller reporting companies.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

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, 2011 or 2010. At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project.

Our present plan of operation is to continue our exploration and production activities on our oil and gas properties. We anticipate that we will incur the following expenses over the next twelve months in connection with our oil and gas properties:

§	$800,000 to $1,200,000 in connection with our oil and gas properties to include seismic acquisitions, lease and associated broker costs, drilling, completing and equipping new wells and for costs associated with production; and

§	$900,000 for operating expenses, including professional, legal, investor relations and accounting expenses associated with our being a reporting issuer under the Securities Exchange Act of 1934.

Accordingly, we anticipate spending approximately $1,700,000 to $2,100,000 over the next twelve months in pursuing our stated plan of operations. The Company expects currently producing and new wells to come online, generating sufficient cash to offset any increase in expenses.

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 average prices calculated on a simple average from the first day in the trailing 12 months, 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. FASB ASC 410-20 requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. As of October 31, 2011 and 2010, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with FASB ASC 410-20. The liability for the fair value of an

asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production. We amortize the amount added to the oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining life of the respective wells. The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is a discounted liability using a credit-adjusted risk-free rate of 12%. Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.

The information below reflects the change in the asset retirement obligations during the years ended October 31, 2011 and 2010:

	October 31,			October 31,
	2011			2010
Balance, beginning of year	$	27,494		$	37,011
Liabilities assumed		774			2,700
Revisions		(5,232	)		(16,658	)
Accretion expense		3,299			4,441
Balance, end of year	$	26,335		$	27,494

The reclamation obligation relates to the Kodesh, Dye Estate, KC 80 and William wells at the Three Sands Property; and ARD #1-36, Bagwell #1-20, Bagwell #2-20, 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 the 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 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.

Results of Operations

We realized revenues of $1,241,015 from natural gas and oil sales during the fiscal year ended October 31, 2011, compared with $657,929 during the fiscal year ended October 31, 2010, an increase of $583,086 due primarily to an increase in the number of producing wells and an increase in commodity prices. In 2011, we sold 26,662 Mcf of natural gas and 11,962 Bbls of oil, and in 2010, we sold approximately 17,574 Mcf of natural gas and 8,213 Bbls of oil. Our natural gas volumes increased by 52%, while our oil volume increased by 46%. The average price received for our natural gas sales in 2011 was $6.01 per Mcf, versus $4.85 per Mcf in 2010, representing an increase of $1.16 or 24%. The average price received for our crude oil sales in 2011 was $89.81 per Bbl, versus $65.66 per Bbl in 2010, representing an increase of $24.15 or 37%.

For the fiscal year ended October 31, 2011, we incurred a net loss of $131,443, compared with a net loss of $550,296 for the fiscal year ended October 31, 2010 (a decrease in net loss of $418,853).

We incurred direct costs of $1,370,930 for the fiscal year ended October 31, 2011, compared with $1,210,140 for the fiscal year ended October 31, 2010, an increase of $160,790. The increase in our direct costs was largely attributable to an increase in our production costs and depletion and accretion costs. Our general and administrative costs decreased to $732,956 for the fiscal year ended October 31, 2011, from $893,795 for the fiscal year ended October 31, 2010. The decrease in our general and administrative costs was attributable to a decrease in costs of investor relations and consulting services.

Our depletion and accretion costs increased from $220,078 during the fiscal year ended October 31, 2010 to $344,932 for the fiscal year ended October 31, 2011, an increase of $124,854. Depletion is calculated based on production rates produced during the year. Our depletion and accretion costs increased as a result of an increase in our oil and gas production.

Our production costs increased from $96,267 for the fiscal year ended October 31, 2010 to $183,743 for the fiscal year ended October 31, 2011, an increase of $87,476. Our production costs increased as a result of an increase in our oil and gas production.

Liquidity and Capital Resources

As of October 31, 2011, we had cash and short term investments of $801,047 and working capital of $1,365,078, compared to cash of $821,029 and working capital of $1,060,231 as of October 31, 2010.

During the fiscal year ended October 31, 2011, net cash provided by operating activities was $405,959, compared to cash of $43,183 provided by operating activities for the fiscal year ended October 31, 2010.

Net cash used in investing activities during the fiscal year ended October 31, 2011 was $25,941, compared with $1,970,104 used during the fiscal year ended October 31, 2010. We used $624,771 in cash for our oil and gas interests compared to $1,170,104 during the previous year. We redeemed $400,000 in a certificate of deposit with the Company’s bank. The Company received $200,000 from the sale of its Mississippi assets as of October 31, 2011.

No cash was provided by or used in financing activities during the fiscal years ended October 31, 2011 and 2010.

Recent Accounting Pronouncements

See footnote #1 to the financial statements.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of October 31, 2011.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not required for smaller reporting companies.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Brinx Resources, Ltd.

We have audited the accompanying balance sheets of Brinx Resources Ltd. as of October 31, 2011 and 2010 and the related statements of operations, stockholders’ equity and comprehensive income, and cash flows for the periods then ended. Brinx Resources Ltd.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Brinx Resources, Ltd. as of October 31, 2011 and 2010, and the results of its operations and its cash flows for the periods then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Mark Bailey & Company, Ltd.

Mark Bailey & Company, Ltd.

Reno, Nevada

February 13, 2012

BRINX RESOURCES LTD.
BALANCE SHEETS

	OCTOBER 31,			OCTOBER 31,
	2011			2010
ASSETS

Current assets
Cash and cash equivalents	$	401,047		$	21,029
Investment - certificate of deposit		400,000			800,000
Marketable securities		208,000			-
Accounts receivable		329,748			148,924
Prepaid expenses and deposit		37,254			128,055

Total current assets		1,376,049			1,098,008

Undeveloped mineral interests, at cost		1,981			811

Oil and gas interests, full cost method of accounting,
net of accumulated depletion		2,074,900			2,577,519

Total assets	$	3,452,930		$	3,676,338


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
Accounts payable and accrued liabilities	$	10,971		$	37,777

Total current liabilities		10,971			37,777

Asset retirement obligations		26,335			27,494

Total liabilities		37,306			65,271


Stockholders' equity
Preferred stock - $0.001 par value; authorized - 25,000,000 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

Accumulative other comprehensive loss		(64,000	)		-

Retained earnings		586,937			718,380

Total stockholders' equity		3,415,624			3,611,067

Total liabilities and stockholders' equity	$	3,452,930		$	3,676,338

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

BRINX RESOURCES LTD.
STATEMENTS OF OPERATIONS


	YEAR ENDED
	OCTOBER 31,
	2011			2010

REVENUES
Natural gas and oil sales	$	1,241,015		$	657,929

DIRECT COSTS
Production costs		183,743			96,267
Depletion and accretion		344,932			220,078
General and administrative		732,956			893,795
Loss on sale of natural gas and oil properties		109,299			-

Total Expenses		(1,370,930	)		(1,210,140	)

OPERATING INCOME/(LOSS)		(129,915	)		(552,211	)

OTHER INCOME
Interest income		900			3,327

NET INCOME/(LOSS) BEFORE INCOME TAXES		(129,015	)		(548,883	)
Provision for income taxes		2,428			1,413

NET INCOME/(LOSS) FOR THE YEARS	$	(131,443	)	$	(550,296	)

Net Income/(Loss) Per Common Share

- Basic	$	(0.01	)	$	(0.02	)
- Diluted	$	(0.01	)	$	(0.02	)

Weighted average number of common shares outstanding

- Basic		24,629,832			24,604,627
- Diluted		24,629,832			24,604,627

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

BRINX RESOURCES LTD.

STATEMENT OF STOCKHOLDERS' EQUITY

	PREFERRED STOCK				COMMON STOCK
									Capital in					Cumulative			Total			Comprehensive
	Number				Number				Excess of Par		Retained			Comprehensive			Shareholder's			Income/(Loss)
	of Shares		Amount		of Shares		Amount		Value		Earnings			(Loss)			Equity

BALANCES, October 31, 2009		-		-		24,529,832		24,530		2,801,991		1,268,676			-			4,095,197			-

Valuation of stock options (Note 5)		-		-		-		-		39,166		-			-			39,166

Shares issued to Investor Relations Services		-		-		100,000		100		26,900		-			-			27,000
Inc. for services rendered

Net (loss)		-		-		-		-		-		(550,296	)		-			(550,296	)

BALANCES, October 31, 2010		-		-		24,629,832		24,630		2,868,057		718,380			-			3,611,067			-

Comprehensive income / (loss)
Unrealized (loss) on held for sale marketable security		-		-		-		-		-		-			(64,000	)		(64,000	)		(64,000	)
Net (loss)		-		-		-		-		-		(131,443	)		-			(131,443	)		(131,443	)
Comprehensive (loss)

BALANCES, OCTOBER 31, 2011		-	$	-		24,629,832	$	24,630	$	2,868,057	$	586,937		$	(64,000	)	$	3,415,624		$	(195,443	)

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

BRINX RESOURCES LTD.
STATEMENTS OF CASH FLOWS


	YEAR ENDED
	OCTOBER 31,
	2011			2010

CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES

Net (loss)	$	(131,443	)	$	(550,296	)

Adjustments to reconcile net income to net cash provided by
operating activities:
Stock based compensation (note 5)		-			39,166
Depletion and accretion		344,932			220,078
Loss on sale of natural gas and oil properties		109,299			-
Shares issued to Investor Relations Services Inc. for services rendered		-			27,000
Changes in working capital:
Decrease/(Increase) in accounts receivable		19,176			(51,726	)
Decrease in prepaid expenses and deposit		90,801			142,555
(Decrease) in accounts payable and accrued liabilities		(26,806	)		(37,408	)
Increase (Decrease) in income taxes receivable		-			253,814

Net cash provided by (used in) operating activities		405,959			43,183

CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES

Redemption/(purchase) of certificate of deposit		400,000			(800,000	)
Sale proceeds of natural gas and oil working interests		200,000			-
Payments on mineral interest		(1,170	)		-
Payments on oil and gas interests		(624,771	)		(1,170,104	)

Net cash provided by (used in) investing activities		(25,941	)		(1,970,104	)

CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES

Net cash (used in) financing activities		-			-

Net increase (decrease) in cash		380,018			(1,926,921	)

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

Cash and cash equivalents, end of years	$	401,047		$	21,029


SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for taxes	$	2,428		$	1,413

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

Assets retirement costs incurred	$	(3,299	)	$	(4,440	)

Investment in natural oil and gas working interests included in	$	-		$	20,645
accounts payable

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

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

USE OF ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial costs from environmental accidents or events for which the Company may be currently liable. In addition, the Company’s oil and gas business makes it vulnerable to changes in prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on average 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 average prices, in the preceding twelve months, 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 October 31, 2011 and 2010, the Company had no overproduced imbalances.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

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

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 "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 "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.

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 the dilutive effect on income/(loss) per share. The dilutive effect of outstanding options, 300,000 as of October, 31, 2011 and 500,000 as of October 31, 2010, and warrants and their equivalents is reflected in diluted earnings per share by application of the treasury stock method. As the Company is reporting net losses in both periods, the conversion of options for the calculation of diluted earnings per share would be considered anti-dilutive. The table below presents the computation of basic and diluted earnings per share for the years ended October 31, 2011 and 2010:

	October 31, 2011			October 31, 2010
Basic earnings per share computation:
(Loss) from continuing operations and net loss	$	(128,321	)	$	(550,296	)
Basic and diluted shares outstanding		24,629,832			24,604,627
Basic and diluted earnings per share	$	(0.01	)	$	(0.02	)

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

1.	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(continued)

INCOME TAXES

Deferred tax assets and liabilities are recognized for temporary differences between the financial reporting and tax bases of the firm’s assets and liabilities. Valuation allowances are established to reduce deferred tax assets to the amount that more likely than not will be realized. The firm’s tax assets and liabilities are presented as a component of “Other assets” and “Other liabilities and accrued expenses,” respectively, in the consolidated statements of financial condition. Tax provisions are computed in accordance with FASB ASC 740, “Accounting for Income Taxes.”

The firm adopted the provisions of FASB ASC 740-10 “Accounting for Uncertainty in Income Taxes — an Interpretation.” A tax position can be recognized in the financial statements only when it is more likely than not that the position will be sustained upon examination by the relevant taxing authority based on the technical merits of the position. A position that meets this standard is measured at the largest amount of benefit that will more likely than not be realized upon settlement. A liability is established for differences between positions taken in a tax return and amounts recognized in the financial statements. FASB ASC 740-10 also provides guidance on derecognition, classification, interim period accounting and accounting for interest and penalties.

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.

MARKETABLE SECURITIES AND INVESTMENTS

All equity investments are classified as available for sale and any subsequent changes in the fair value are recorded in current year’s comprehensive income. If in the opinion of management there has been a decline in the value of the investment below the carrying value that is considered to be other than temporary, the valuation adjustment is recorded in net earnings in the period of determination. The fair value of the investments is based on the quoted market price on the closing date of the period.

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. Marketable securities are valued using Level 1 inputs.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

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 “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:

	Years ended
	October 31, 2011	October 31, 2010
Expected volatility	-	219%
Risk-free interest rate	-	0.92%
Expected life	-	2 years
Dividend yield	-	0.00%

RECENT ACCOUNTING PRONOUNCEMENTS

In June 2011, authoritative guidance was issued on the presentation of comprehensive income. Specifically, the guidance allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. The new guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This guidance will be applied retrospectively and will be effective for our interim and annual reporting periods beginning after December 15, 2011. The changes in presentation of comprehensive income will have no effect on the calculation of net income, comprehensive income or earnings per share.

2.	MARKETABLE SECURITIES

The Company received 800,000 common shares in Lexaria Corp. on the sale of its oil and natural gas interests in Mississippi, with a value of $0.34 per share. The value of the shares at October 31, 2011 was $0.26 per share, giving rise to an unrealized loss of $64,000.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

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

	October 31, 2011		October 31, 2010
Accounts receivable	$	329,748	$	148,924
Less: allowance for doubtful account		-		-
	$	329,748	$	148,924

4.	OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:

	Oct 31, 2011			October 31, 2010
2008-3 Drilling Program, Oklahoma	$	302,361		$	257,564
2009-2 Drilling Program, Oklahoma		114,420			115,582
2009-3 Drilling Program, Oklahoma		300,080			294,164
2009-4 Drilling Program, Oklahoma		190,146			172,530
2010-1 Drilling Program, Oklahoma		253,855			232,212
Washita Bend 3D, Oklahoma		482,882			337,398
Kings City Prospect, California		263,561			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
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi		(222.123)			312,630
Frio-Wilcox Prospect, Mississippi		-			400,000
Asset retirement cost		4,534			8,992
Less: Accumulated depletion and impairment		(1,127,444	)		(1,420,191	)
	$	2,074,900		$	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%. From January to July 2009, the Company expended a $213,925 in addition to $18,850 that was spent in previous periods. The well, Wigley#1-11, was abandoned during March 2009. The cost and its buy-in cost total of $33,423 were moved to the proved properties. Selman#1-21 and Bagwell#1-20 started producing during May 2009, the cost and its buy-in cost total of $67,707 for Selman#1-21 and $57,921 for Bagwell#1-20 were moved to the proved properties. Ard#1-36 started producing during June 2009 and the cost and its buy-in cost total of $42,647 was moved to the proved properties. Selman#2-21 started producing during July 2009 and was abandoned on April 20, 2010; the cost and its buy-in cost total of $57,483 were moved to the proved properties pool. The total cost of the 2008-3 Drilling Program as at October 31, 2011 was $302,361. The interests are located in Garvin County, Oklahoma.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

4.	OIL AND GAS INTERESTS (continued)

2009-2 Drilling Program, Oklahoma

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

2009-3 Drilling Program, Oklahoma

On August 12, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Jackson#1-18 started producing during January 2010; an amount of $63,725 which included the buy-in cost was moved to the proved property pool. Miss Gracie#1-18 started producing during March 2010; an amount of $62,268 which included its buy-in cost was moved to the proved property pool. Brewer#1-20 was abandoned on June 2, 2010; the cost and its buy-in cost total of $64,936 were moved to the proved properties. Waunice#1-36 started producing during June 2010 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 October 31, 2011, the total cost of the 2009-3 Drilling Program was $300,080. 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 $49,637, which included the buy-in cost was moved to the proved property pool.

As at October 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 $58,995, which included the buy-in cost was moved to the proved property pool. As at October 31, 2011, the total cost of the 2010-1 Drilling Program was $253,855. The interests are located in Garvin County, Oklahoma.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

4. OIL AND GAS INTERESTS (continued)

Washita Bend 3D Exploration Project, Oklahoma

On March 1, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s Washita Bend 3D Exploration Project for a buy-in cost of $46,250. 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 October 31, 2011, the total costs, including seismic costs was $482,882.

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 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 October 31, 2011 was $263,561.

Three Sands Project, Oklahoma

On October 6, 2005, the Company acquired a 40% working interest in Vector Exploration Inc’s Three Sands Project for a total buy-in cost of $88,000 plus dry hole costs. For the year ended October 31, 2006, the Company expended $530,081 in exploration costs. In June 2007, the Company acquired a 40% working interest in William #4-10 well for a total cost of $285,196 and paid a further $17,000 in costs relating to the well. On March 19, 2008, the Company participated in the KC 80#1-11 well and paid $75,000 for the prepaid drilling costs. During March and April 2008, the Company expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 from May to July 2008 for the KC 80#1-11 well. The total cost of the Three Sands Project as at October 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 October 31, 2011 was $61,085.

Palmetto Point Project, Mississippi

On August 12, 2011, the Company signed the 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 fair value of $0.34 per share from Lexaria Corp. treasury. These properties consist principally of the Belmont Lake Oil Field and all undeveloped acreage in the Palmetto Point Project. $200,000 was deposited on August 12, 2011. The disposed reserves represented more than 25% of the total reserves which we considered to represent a significant alteration between capitalized costs and proved reserves and hence a loss on the sale was recognized in the Statement of Operations in the amount of $109,299.

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 years ended October 31, 2011 and 2010, respectively.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

4. OIL AND GAS INTERESTS (continued)

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 $341,633 and $215,638 for the years ended October 31, 2011 and 2010, respectively.

Capitalized Costs

	October 31, 2011			October 31, 2010
Proved properties	$	2,395,902		$	3,188,673
Unproved properties		806,443			809,037
Total Proved and Unproved properties		3,202,345			3,997,710
Accumulated depletion expense		(989,713	)		(1,200,652	)
Impairment		(137,732	)		(219,539	)
Net capitalized cost	$	2,074,900		$	2,577,519

Results of Operations

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

	October 31, 2011			October 31, 2010
Revenues	$	1,241,015		$	657,929
Production costs		(183,743	)		(96,267	)
Depletion and accretion		(344,932	)		(220,078	)
Results of operations (excluding corporate overhead)	$	712,340		$	341,584

5. 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 October 31, 2011 and 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.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

5. ASSET RETIREMENT OBLIGATIONS (continued)

The information below reflects the change in the asset retirement obligations during the years ended October 31, 2011 and 2010:

	October 31, 2011			October 31, 2010
Balance, beginning of periods	$	27,494		$	37,011
Liabilities assumed		774			2,700
Revisions		(5,232	)		(16,658	)
Accretion expense		3,299			4,441
Balance, end of periods	$	26,335		$	27,494

The reclamation obligation relates to the Kodesh, Dye Estate, KC 80, Taylor and William wells at the Three Sands Property; and ARD#1-36, Bagwell#1-20, Bagwell#2-20, 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, McPherson#1-1 well at South Wayne Prospect. The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes in applicable laws and regulations. Such changes will be recorded in the accounts of the Company as they occur.

6.	COMMON STOCK

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 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 expired on October 30, 2011.

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 are to expire on November 2, 2011.

A summary of the changes in stock options for the year ended October 31, 2011 is presented below:

	Options Outstanding
				Weighted Average
	Number of Shares			Exercise Price
Balance, October 31, 2010		500,000		$	0.10
Expired on October 30, 2011		(200,000	)		0.10
Balance, October 31, 2011		300,000		$	0.10

The Company has the following options outstanding and exercisable.

October 31, 2011	Options outstanding and exercisable
Range of exercise prices	Number of shares	Weighted average remaining contractual life	Weighted Average Exercise Price
$0.10	300,000	0.01 years	$0.10

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

7. RELATED PARTY TRANSACTIONS

During the years ended October 31, 2011 and 2010, the Company entered into the following transactions with related parties:

a)	The Company paid $72,000 (2010 - $60,000) in management fees and reimbursement of office space of $4,400 (2010 - $4,800) to the President of the Company.

b)	The Company paid $71,000 (2010 - $60,000) to a related entity, for administration services.

c)	The Company paid $101,000 (2010 - $90,000) in management fees to the director of the Company.

d)	The Company paid $76,813 (2010 - $72,068) in consulting and accounting fees to the Chief Financial Officer of the Company.

8.	INCOME TAXES

Income tax expense (benefit) for the years ended October 31, 2011 and for the year ended October 31, 2010 consists of the following:

	October 31		October 31
	2011		2010

Current Taxes	$	-	$	-
Deferred Taxes		-		-
Net income tax provision (benefit)	$	-	$	-

The effective income tax rate for years ended October 31, 2011 and the year ended October 31, 2010 are:

	October 31			October 31
	2011			2010
Federal statutory income tax rate		35.00	%		35.00	%

Net effective income tax (benefit) rate		35.00	%		35.00	%

The tax effects of temporary differences for the years ended October 31 that give rise to significant portions of the deferred tax assets and deferred tax liabilities are provided below:

	October 31			October 31
	2011			2010
Deferred tax assets:
Federal and state net operating loss carryovers	$	174,204		$	219,283
Asset retirement liability		9,217			10,409
Stock options granted (not exercised)		8,897			14,828
Book depletion in excess of tax depreciation		138,422			64,348
Deferred tax asset		330,741			308,868

Valuation Allowance		(330,741	)		(308,868	)
Net Deferred Tax Asset	$	-		$	-

Deferred tax liabilities:

Net Deferred Tax Liability	$	-	$	-

The Company has approximately $498,000 net operating loss carry forward as of October 31, 2011 which will expire on October 31, 2030.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

8.	INCOME TAXES (continued)

The Company believes that all of its positions taken in tax filings are more likely than not to be sustained upon examination by tax authorities. The Company includes interest and penalties arising from the underpayment of income taxes in the consolidated statements of operations in the provision for income taxes. As of October 31, 2011 and 2010, the Company had not incurred interest or penalties related to uncertain tax positions.

The tax years that remain subject to examination by major taxing authorities are those for the years ended October 31, 2011, 2010, 2009 and 2008.

9. UNAUDITED OIL AND GAS RESERVE QUANTITIES

The following- unaudited reserve estimates presented as of October 31, 2011 and 2010 were prepared by independent petroleum engineers. There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, reserve estimates of new discoveries that have little production history are more imprecise than those of properties with more production history. Accordingly, these estimates are expected to change as future information becomes available.

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., process and costs as of the date the estimate is made. Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

Unaudited net quantities of proved developed reserves of crude oil and natural gas (all located within United States) are as follows:

	Crude Oil			Natural Gas

Changes in proved reserves	(Bbls)			(MCF)
Estimated quantity, October 31, 2009		56,443			73,426
Revisions of previous estimate		-			-
Discoveries		45,009			42,995
Reserves sold to third parties		-			-
Production		(8,213	)		(17,574	)
Estimated quantity, October 31, 2010		93,239			98,847
Reserves sold to third parties		(37,780	)		(3,580	)
Revisions of previous estimate		(9,396)			24,000
Discoveries		4,698			33,096
Production		(11,962	)		(26,662	)
Estimated quantity, October 31, 2011		38,799			125,701

Proved Reserves at year end	Developed	Undeveloped	Total
Crude Oil (Bbls)
October 31, 2011	36,969	1,830	38,799
October 31, 2010	70,129	23,110	93,239
Gas (MCF)
October 31, 2011	124,501	1,200	125,701
October 31, 2010	98,617	230	98,847

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

9. UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)

The following information has been developed utilizing procedures prescribed by FASB ASC 932-235-55, "Disclosures About Oil and Gas Producing Activities,” and based on crude oil and natural gas reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

Future cash inflows were computed by applying average prices of oil and gas in the preceding twelve months to the estimated future production of proved oil and gas reserves. The future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved oil and gas reserves and the tax basis of proved oil and gas properties and available net operating loss carry-forwards. Discounting the future net cash inflows at 10% is a method to measure the impact of the time value of money.

	October 31, 2011			October 31, 2010
Future Cash inflows	$	3,180,013		$	7,989,374
Future production costs		(731,218	)		(1,893,661	)
Future development costs		(61,250	)		(303,526	)
Future income tax expense		(570,543	)		(1,840,474	)
Future cash flows		1,817,003			3,951,713
10% annual discount for estimated timing of cash flows		(1,063,697	)		(1,418,471	)
Standardized measure of discounted future net cash	$	753,306		$	2,533,242

UNAUDITED STANDARIZED MEASURE

The following presents the principal sources of the changes in the standardized measure of discounted future net cash flows.

Standardized measure of discounted cash flows:	October 31, 2011			October 31, 2010
Beginning of year	$	2,533,242		$	2,540,588
Sales and transfers of oil and gas produced, net production costs		4,809,361			(3,305,039	)
Net changes in prices and production costs and other		(1,162,443	)		1,085,363
Net changes due to discoveries		713,000			1,275,338
Changes in future development costs		(242,276	)		185,644
Revisions of previous estimates		(920,808	)		-

Other		(1,572,129	)		-
Net change in income taxes		(1,269,931	)		758,694
Accretion discount		(354,774	)		1,282,684
Future cash flows		(1,779,936	)		(1,290,030	)
End of year	$	753,306		$	2,533,242

10. MAJOR CUSTOMERS

We collected $798,912 (2010: $451,359) or 64% of our revenues from one of our operators during the year ended October 31, 2011. As of October 31, 2011, $90,602 was due from this operator.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

11. CONTINGENCIES

In September 2010, two lawsuits were filed in the District Court of Garvin County in the State of Oklahoma by Harold Hamm (“Hamm”) against certain defendants (“Defendants”) and consolidated together alleging, among other things, that Hamm owns an interest in two oil and gas leases in Garvin County and is entitled to a 50% participatory interest. The Company was not named as a party in these legal proceedings, but Hamm’s allegations include that he is entitled to a 50% participatory interest in the Joe Murray Farms well drilled as part of the 2009-3 Drilling Program, in which the Company purchased a 6.25% working interest before casing point and 5.0% working interest after casing point. The Defendants and the Company believe that there is no merit to Hamm’s allegations. In connection with these proceedings, the Defendants were ordered in January 2011 to escrow fifty percent (50%) of the revenues generated within the subject area pending the outcome of these proceedings. For this reason, fifty percent (50%) of the revenues the Company is entitled to that have been generated by production from the Joe Murray Farms well is being escrowed and there is no assurance that the Company will be able to recover these proceeds. As of October 31, 2011, the Company recognized $119,295 in revenue from the Joe Murray Farms well and $119,295 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

12.	SUBSEQUENT EVENTS

On February 10, 2012, the Company issued 500,001 Series A preferred stock.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None

ITEM 9A. 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 October 31, 2011, being the date of our most recently completed fiscal year end. 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 were effective.

As of October 31, 2011, the following material weaknesses existed:

·	We relied on external consultants for the preparation of our financial statements and reports. As a result, it was possible that our officers were not able to identify errors and irregularities in the financial statements and reports.

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

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

Management’s Annual Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 15d-15(f) under the Exchange Act. Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our officers have assessed the effectiveness of our internal controls over financial reporting as of October 31, 2011. In making this assessment, management used the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment using those criteria, management believes that, as of October 31, 2011, our internal controls are not effective as there is a reasonable possibility that a material misstatement of the Company’s financial statements may not be prevented or detected on a timely basis. This is due to the size of the Company and the fact that we have only one financial expert on our management team and no audit committee. Management believes that the material weakness set forth above does not have an effect on our financial statements.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to an exemption for smaller reporting companies under Section 989G of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

Changes In Internal Controls Over Financial Reporting

There have been no changes in our internal controls over financial reporting during the quarter ended October 31, 2011, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Information about our executive officers and directors follows:

Name	Age	Position and Term of Office
Leroy Halterman	66	Director, President and Secretary
Kenneth A. Cabianca	71	Director
Kulwant Sandher	50	Chief Financial Officer

Our Bylaws provide for a board of directors ranging from 1 to 12 members, with the exact number to be specified by the board. All directors hold office until the next annual meeting of the stockholders following their election and until their successors have been elected and qualified. The board of directors appoints officers. Officers hold office until the next annual meeting of our board of directors following their appointment and until their successors have been appointed and qualified.

Set forth below is a brief description of the recent employment and business experience of our directors and executive officers:

Leroy Halterman was appointed as a director and as our sole officer at the time on August 9, 2005. Mr. Halterman has 40 years of geology experience. From 1999 to 2004, Mr. Halterman served as vice president of Tecumseh Professional Associates, a private environmental, facility management, government consultant and natural resource firm based in Albuquerque, New Mexico. During this period he directed the company’s oil, gas and natural resource consulting and investments. Mr. Halterman served as principal in charge of maintenance and security for two U.S. Army Ammunition Plants. Additionally, he directed Tecumseh’s efforts in over thirty mineral project appraisals and evaluations. Since 2004, Mr. Halterman has been working as a consultant in the fields of oil and gas, precious and base metals, and aggregated resources. Since 1993, Mr. Halterman has been president and a director of Consolidated North American Resources, a private natural resource investment firm located in Las Vegas, Nevada. Mr. Halterman is a graduate of the Missouri School of Mines with a BS degree in Geology. He is registered as a geologist in Wyoming. During the past five years, Mr. Halterman has not served as an officer or director of any company, other than as described in this paragraph.

Kenneth A. Cabianca was our sole officer and director from our inception in December 1998 until August 9, 2005. On August 9, 2005, Mr. Cabianca resigned as our president but he remains a director. Since 1983, Mr. Cabianca has been an independent businessman and a management consultant of various companies. Many of his activities have been conducted through his company, Wellington Financial Corporation. His experience includes raising venture capital, general management, and public relations. From August 1991 to September 1999, Mr. Cabianca was a director and president of Primo Resources International Inc., a mining company whose stock trades on the CDNX. While he served as president Primo Resources engaged in joint ventures projects with Mitsubishi Corp., Mitsubishi Materials Corp., and Golden Peaks Resources Ltd. He served as a director of Primo Resources International again from October 2001 to November 2002. Mr. Cabianca received a D.D.S. degree and practiced dentistry in Vancouver, British Columbia from 1965 to 1986. He also received a Bachelor of Science degree from Creighton University in 1965. During the past five years, Mr. Cabianca has not served as an officer or director of any company, other than as described in this paragraph.

Kulwant Sandher was appointed on October 30, 2009 our Chief Financial Officer. He has been the Chief Financial Officer and a director of Delta Oil & Gas, Inc., a publicly-traded company since January 2007. Mr. Sandher was appointed as President and Chief Financial Officer of Turner Valley Oil & Gas Inc., a publicly-traded company, on August 2004 and continues in serve in these positions. Mr. Sandher is a Chartered Accountant in both England and Canadian jurisdictions. From April 2006 to October 2008, Mr. Sandher acted as Chief Financial Officer and as a member of the board of directors of The Stallion Group. From May 2004 to March 2006, Mr. Sandher served as Chief Operating Officer and Chief Financial Officer of Marketrend Interactive Inc. He also acted

as Chief Financial Officer of Serebra Learning Corporation, a public company on the TSX Venture Exchange, from September 1999 to October 2002.

Conflicts of Interest

Our officers and directors are associated with other firms involved in a range of business activities. Consequently, there are potential inherent conflicts of interest in their acting as officers and/or directors of our company. Insofar as they are engaged in other business activities, we anticipate that they will not devote all of their time to our affairs.

Our officers and directors are now and may in the future become shareholders, officers or directors of other companies, which may be formed for the purpose of engaging in business activities similar to us. Accordingly, additional direct conflicts of interest may arise in the future with respect to such individuals acting on behalf of us or other entities. Moreover, additional conflicts of interest may arise with respect to opportunities which come to the attention of such individuals in the performance of their duties or otherwise. Currently, we do not have a right of first refusal pertaining to opportunities that come to their attention and may relate to our business operations.

Our officers and directors are, so long as they are our officers or directors, subject to the restriction that all opportunities contemplated by our plan of operation which come to their attention, either in the performance of their duties or in any other manner, will be considered opportunities of, and be made available to us and the companies that they are affiliated with on an equal basis. A breach of this requirement will be a breach of the fiduciary duties of the officer or director. If we or the companies with which the officers and directors are affiliated both desire to take advantage of an opportunity, then said officers and directors would abstain from negotiating and voting upon the opportunity. However, all directors may still individually take advantage of opportunities if we should decline to do so. Except as set forth above, we have not adopted any other conflict of interest policy with respect to such transactions.

We do not have any audit, compensation, and executive committees of our board of directors. We do not have an audit committee financial expert.

Section 16(a) Beneficial Ownership Reporting Compliance

We are not subject to Section 16(a) of the Securities Exchange Act of 1934.

Code of Ethics

We have not yet adopted a code of ethics that applies to our principal executive officers, principal financial officer, principal accounting officer or controller, or persons performing similar functions, due to our relatively low level of activity to date. At a later time, the board of directors may adopt such a code of ethics.

Changes to Director Nominating Procedures

The Company adopted Amended and Restated Bylaws on December 10, 2009 pursuant to which Series A Preferred Shareholders would be entitled to elect one director to the Company’s board of directors. The Company has not issued any Series A Preferred Shares.

Other Changes

The Company amended its Bylaws effective as of February 9, 2012, to clarify the role of the director elected by the holders of the Series A Preferred Shares.

ITEM 11. EXECUTIVE COMPENSATION.

The following table sets forth information about the remuneration of our principal executive officer for services rendered for each of the last two fiscal years ended October 31, 2011 and 2010. We do not have any executive officers with total compensation of $100,000 or more. Certain columns as required by the regulations of the Securities and Exchange Commission have been omitted as no information was required to be disclosed under those columns.

SUMMARY COMPENSATION TABLE

Name and Principal Position	Year	Salary ($)	Option Awards ($)	Total ($)
Leroy Halterman President and Secretary	2011 2010	72,000 60,000	-0- 23,581(1)	72,000 83,581

_____________

(1)	The fair value of the option grant to Mr. Halterman was estimated as of the date of grant using the Black-Scholes option pricing model with the following assumptions: expected volatility of 219%, risk-free interest rate of 0.92%, expected life of 2 years and dividend yield of 0.00%.

In addition to the above, we reimbursed Mr. Halterman $4,400 and $4,800 for office space for the fiscal years ended October 31, 2011 and 2010, respectively.

During the last two fiscal years ended October 31, 2011 and 2010, there were no grants of stock options, stock appreciation rights, benefits under long-term incentive plans or other forms of compensation involving our officers, except for the stock option grant made to Mr. Halterman on November 2, 2009 and to Mr. Sandher on October 30, 2009. We have no employment agreements with our executive officers. We do not pay compensation to our directors for attendance at meetings. We reimburse our directors for reasonable expenses incurred during the course of their performance.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

Name	Number of Securities Underlying Unexercised Options (#) exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options	Option Exercise Price ($)	Option Expiration Date
Leroy Halterman	300,000	-0-	-0-	0.10	11/2/11

On November 2, 2009, we granted Mr. Halterman options to purchase 300,000 shares of common stock at $0.10 per share. The options fully vested six months from the date of grant and expired November 2, 2011.

The following table sets forth compensation of our directors for the last completed fiscal year ended October 31, 2011. Mr. Halterman does not receive any additional compensation for serving as a director.

DIRECTOR COMPENSATION

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)	Option Awards ($)	All Other Compensation ($)	Total ($)
Kenneth Cabianca	101,000	-0-	-0-	0	101,000

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table provides certain information as to the officers, directors and more than 5% shareholders. As of February 10, 2012, we had 24,629,832 shares common stock outstanding and 500,001 shares of preferred stock outstanding.

Name and Address of Beneficial Owner (1)	PREFERRED (2)		COMMON		TOTAL
Name and Address of Beneficial Owner (1)	Amount and Nature of Beneficial Ownership	Percent of Class (3)	Amount and Nature of Beneficial Ownership	Percent of Class (3)	Amount and Nature of Beneficial Ownership	Percent of Total (3)
Kenneth A. Cabianca (4) 4519 Woodgreen Drive West Vancouver, B.C. V7S 2T8 Canada	500,001 (5)	100%	2,554,702 (6)	10.4%	3,054,703 (6)	12.2%
Leroy Halterman 820 Piedra Vista Rd NE Albuquerque, NM 87123	0	--	50,000	(7)	50,000	(7)
Kulwant Sandher 604-700 West Pender Street Vancouver, B.C. V6C 1G8 Canada	0	--	0	--	0	--
All officers and directors as a group (3 persons)	500,001	100%	2,604,702	10.6%	3,104,703	12.4%
Barry T. Brooks (8) 3843 Jamestown Road Springfield, OH 45502	0	--	1,876,157	7.6%	1,876,157	7.5%
Jeff Beckett (9) 3800 North Woodward Ave, Suite 300 Birmingham, MI 48009	0	--	1,294,999(10)	5.3%	1,294,999(10)	5.2%

_________________

(1)	To our knowledge, except as set forth in the footnotes to this table and subject to applicable community property laws, each person named in the table has sole voting and investment power with respect to the shares set forth opposite such person’s name.

(2)	Holders of preferred stock and holders of common stock vote together as a single class, except for matters specifically reserved for voting by the holders of preferred stock.

(3)	This table is based on 24,629,832 shares of common stock outstanding and 500,001 shares of Series A preferred stock outstanding as of February 10, 2012.

(4)	Kenneth Cabianca may be deemed to be a promoter of our company.

(5)	All preferred stock held by Mr. Cabianca is Series A preferred stock.

(6)	128,000 shares of common stock are held by Golden Capital in trust for Mr. Cabianca.

(7)	Less than 0.1%.

(8)	All information for Barry Brooks was obtained from the Schedule 13G filed by Mr. Brooks on May 18, 2011, as amended by the Schedule 13G/A filed by Mr. Brooks on November 18, 2011.

(9)	All information for Jeff Beckett was obtained from the Schedule 13G filed by Mr. Beckett on December 15, 2011.

(10)	136,668 shares are held by Constance Francis Beckett.

Equity Compensation Plan Information

As of October 31, 2011, our compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance, are as follows

EQUITY COMPENSATION PLAN INFORMATION

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders	N/A	N/A	N/A
Equity compensation plans not approved by security holders	300,000	0.10	N/A
Total	300,000	N/A	N/A

Changes in Control

There are no agreements known to management that may result in a change of control of our company.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

During the fiscal years ended October 31, 2011 and 2010, we paid $72,000 and $60,000, respectively, in management fees and $4,400 and $4,800, respectively, as reimbursement for office space to our president, Lee Halterman.

During the fiscal years ended October 31, 2011 and 2010, we paid $101,000 and $90,000, respectively, in management fees to a director, Ken Cabianca. We entered into a Management Consulting Agreement with Mr. Cabianca, effective February 10, 2012, pursuant to which Mr. Cabianca agreed to provide management consulting services to the Company for consideration of 500,001 shares of Series A preferred stock and $90,000 per year. The term of the Management Consulting Agreement is five years with automatic one-year renewal terms, unless earlier terminated pursuant to the agreement. As a result of this Management Consulting Agreement, Mr. Cabianca will own 100% of the issued and outstanding Series A preferred stock, entitling him to elect the Series A director. Pursuant to the Amended and Restated Bylaws of the Company, as amended February 9, 2012, the affirmative vote of the Series A director is required for any of the following actions by the Company:

(a) the amendment, alteration, or repeal of any provision of the Articles of Incorporation or the Bylaws of the Company (including any filing of a Certificate of Designation) that alters or changes the voting powers, preferences, or other special rights or privileges, or restrictions of the Series A Director or the Series A Preferred Stock, relative to any class or series of capital stock of the Company;

(b) the increase or decrease of the total number of authorized shares of Series A Preferred Stock;

(c) the authorization or issuance of, or obligating the Company to issue, any other equity security, including any other security convertible into or exercisable for any other equity security, which has a preference over the Series A Preferred Stock with respect to voting, or the authorization of any increase in the authorized or designated number of any such security;

(d) the purchase or other acquisition of any share or shares of Preferred Stock or Common Stock (or payment into or set aside for a sinking fund for such purpose); provided, however, that this restriction shall not apply to the repurchase of shares of Common Stock from employees, officers, directors, consultants or other persons performing services for the Company or any subsidiary pursuant to agreements under which the Company has the option to repurchase

such shares at cost or at cost upon the occurrence of certain events, such as the termination of employment;

(e) the authorization of voluntary or involuntary dissolution, liquidation or winding-up of the Company;

(f) payment of any dividend or other distribution other than (i) in the case of the Common Stock, a dividend or distribution payable solely in Common Stock and (ii) any dividend or distribution the fair market value of which does not exceed 10% of the Company's net profits for the fiscal year of the Company in which such dividend is declared;

(g) causing the Company to enter into or engage, directly or indirectly, in any material respect, in any line of business other than the business anticipated to be conducted by the Company as of the date of the first issuance of the Series A Preferred Stock;

(h) entering into any transaction (or series of related transactions) involving more than $100,000 in the aggregate;

(i) the transfer of any of the Company’s assets outside the ordinary course of business;

(j) the creation, incurrence, or assumption of any indebtedness for borrowed money or the issuance of any guarantees, or mortgaging, encumbering, creating, incurring, or suffering to exist any liens related thereto, or entering into any derivative obligations or vendor financing arrangements;

(k) the election of the officers of the Company;

(l) any increase in the number of directors of the Company;

(m) the issuance of any shares of Common Stock or securities convertible into or exchangeable for Common Stock at a price per share less than the per share book value of the Company at the time of issuance;

(n) the adoption, amendment, or termination of any stock grant, option or purchase plan or other stock incentive program or arrangement for employees, officers, directors or consultant or advisors of or contractors with the Company of any of its subsidiaries; and

(o) the granting of any options to purchase Common Stock with an exercise price less than the fair market price of the Common Stock as of the date of grant.

As of the date of this report, other than the transactions described above, there are no, and have not been since inception, any material agreements or proposed transactions, whether direct or indirect, with any of the following:

-	any of our directors or officers;

-	any nominee for election as a director;

-	any principal security holder identified in Item 12 above; or

-	any relative or spouse, or relative of such spouse, of the above referenced persons.

Future Transactions

All future affiliated transactions will be made or entered into on terms that are no less favorable to us than those that can be obtained from any unaffiliated third party.

Director Independence

Our common stock is quoted on the OTC.QB. As such, we are not currently subject to corporate governance standards of listed companies, which require, among other things, that the majority of the board of directors be independent.

Since we are not currently subject to corporate governance standards relating to the independence of our directors, we choose to define an “independent” director in accordance with the NASDAQ Global Market’s requirements for independent directors (NASDAQ Marketplace Rule 5605(a)(2)). The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of the company and has not engaged in various types of business dealings with the company. We do not currently have an independent director under the above definition. We do not list that definition on our Internet website.

We presently do not have an audit committee, compensation committee, nominating committee, executive committee of our Board of Directors, stock plan committee or any other committees.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

Audit Fees

For the fiscal year ended October 31, 2011, Mark Bailey & Company, Ltd. (“Bailey”) is expected to bill us approximately $32,500 for the audit of our annual financial statements and review of financial statements included in our quarterly reports on Form 10-Q. For the fiscal year ended October 31, 2010, Bailey billed us $27,500 for the audit of our annual financial statements and review of financial statements included in our quarterly report on Form 10-Q.

Audit-Related Fees

There were no fees billed for services reasonably related to the performance of the audit or review of our financial statements outside of those fees disclosed above under “Audit Fees” for fiscal years 2011 and 2010.

Tax Fees

For the fiscal year ended October 31, 2011, Bailey is expected to bill us $6,000 for tax compliance services. For the fiscal year ended October 31, 2010, Bailey billed us $5,000 for tax compliance services.

All Other Fees

There were no other fees billed by our principal accountants other than those disclosed above for fiscal years 2011 and 2010.

Pre-Approval Policies and Procedures

Prior to engaging our accountants to perform a particular service, our directors obtain an estimate for the service to be performed. The directors in accordance with our procedures approved all of the services described above.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

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)
3.5	Amendment to Amended and Restated Bylaws
4.1	Certificate of Designation of Rights, Preferences, and Privileges for Series A Preferred Stock (4)
10.1	Management Consulting Agreement dated February 10, 2012
16.1	Letter from Chisholm, Bierwolf, Nilson & Morrill, LLC dated September 8, 2010 (5)
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
101*	Financial statements from the Annual Report on Form 10-K of Brinx Resources Ltd. for the year ended October 31, 2011, formatted in XBRL: (i) the Balance Sheets; (ii) the Statements of Operations; (iii) the Statements of Cash Flows; (iv) the Statements of Stockholders’ Equity; and (v) the Notes to Financial Statements tagged as blocks of text.

___________________

(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.

(5)	Incorporated by reference to the exhibits to the registrant’s amended current report on Form 8-K dated September 1, 2010, filed September 9, 2010.

*In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

Date: February 14, 2012	By:	/s/ Leroy Halterman
		Leroy Halterman, President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date


/s/ Leroy Halterman	President, Secretary and Director (principal executive officer)	February 14, 2012
Leroy Halterman

/s/ Kulwant Sandher	Chief Financial Officer (principal financial and accounting officer)	February 14, 2012
Kulwant Sandher

/s/ Kenneth A. Cabianca	Director	February 14, 2012
Kenneth A. Cabianca

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