10-K

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, 2012

[  ] 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.)

c/o Dill Dill Carr Stonbraker & Hutchings, P.C., 455 Sherman Street, Suite 300, Denver, Colorado 80203

(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.

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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.  $1,396,511 as of April 30, 2012

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 January 25, 2013

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.

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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, 2012.

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 operation 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.

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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.

On September 10, 2012, we signed an asset purchase agreement with GLM Energy Inc., to sell the oil and gas assets in the Three Sands Project effective June 1, 2012 for a total of $352,144.  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 Statements of Comprehensive Income in the amount of $96,491 for the year ended October 31, 2012.

2008-3 Drilling Program, Oklahoma

On January 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2008-3 Drilling Program.  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 is 6.25% and the After Casing Point (“ACP”) Interest is 5.00%.  The interests are located in Garvin County, Oklahoma.  The total cost of the 2008-3 Drilling Program was $309,152 as of October 31, 2012.

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 party’s working interest.  The total cost of the King City Prospect was $404,121 as at October 31, 2012.

2009-2 Drilling Program, Oklahoma

On June 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-2 Drilling Program.  We agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  As of October 31, 2012, the total cost of the 2009-2 Drilling Program was $114,420.  The interests are located in Garvin County, Oklahoma.

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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.  We agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  The total cost of the 2009-3 Drilling Program, including drilling costs, as of October 31, 2012, was $337,749.  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 is 6.25% and the ACP Interest is 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, 2012, the total cost of the 2009-4 Drilling Program was $190,182.  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 is 5.625% and the ACP Interest is 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  As of October 31, 2012, the total cost, including seismic costs, was $537,361.

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, 2012 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 is 6.25% and the ACP Interest is 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.  We agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  As of October 31, 2012, the total cost of the 2010-1 Drilling Program was $254,817.  The interests are located in Garvin County, Oklahoma.

Double T Ranch#1 SWDW, Oklahoma

On July 17, 2012, we acquired a 3.00% working interest in the drilling, completion and operations of the Double T Ranch#1 SWDW located in Garvin County from Ranken Energy Corporation. At October 31, 2012, the cost of the Double T Ranch#1 SWDW was $43,078.

International Exploration Program

We are attempting to expand our 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

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title.   The 2011-2012 Bureau of Land Management maintenance fee has been paid and the claims are valid until August 31, 2013 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, 2012, 2011, and 2010, we incurred $284,707, $625,941, and $1,170,104, 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, 2012 and 2011, we collected $382,540 (81%) and $798,912 (64%), 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 2013.

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

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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 rules and regulations of 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 served as our president and secretary and a director until his death on April 6, 2012 and received monthly management fees of $6,000 until that time.  For the fiscal years ended October 31, 2012 and 2011, we incurred $30,000 and $72,000, respectively, for Mr. Halterman’s services.

After Mr. Halternan’s passing, Kenneth Cabianca became our president and receives a monthly fee of $5,000, effective as of July 1, 2012, for such services.  We also pay Mr. Cabianca management fees of $7,500 per month for services rendered under a Management Consulting Agreement.  For the fiscal years ended October 31, 2012 and 2011, we paid Mr. Cabianca $122,000 and $101,000 in management fees, respectively.

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, 2012 and 2011, we paid Mr. Sandher $78,597 and $76,813, respectively, for his services.

On August 24, 2012, Georgia Knight was elected to fill the vacancy in our board of directors created by Mr. Halterman’s passing.  Ms. Knight receives $500 per month for her service as a director.  For the fiscal year ended October 31, 2012, we paid Ms. Knight $1,000 for her services.

For the fiscal years ended October 31, 2012 and 2011, we incurred $74,000 and $71,000, 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 $7,000 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

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

Three Sands Project

On October 6, 2005, we acquired a 40% working interest in Vector Exploration Inc.’s Three Sands Project located in Noble County, Oklahoma.

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On September 10, 2012, we signed an asset purchase agreement with GLM Energy Inc., to sell the oil and gas assets in the Three Sands Project effective June 1, 2012 for a total of $352,144.  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 Statements of Comprehensive Income in the amount of $96,491 for the year ended October 31, 2012.

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 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, 2012, the three producing wells in this program have produced a total of 177,340 Bbls of oil and 35,218 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 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.

2009-3 Drilling Program, Oklahoma.On August 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program 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.  This 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.  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, 2012 totaled 134,474 Bbls of oil and 34,999 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 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.

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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, 2012, 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 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 were completed in the deepest pay zone as of October 31, 2010 with one well continuing to produce at a rate of 11 Bbls of oil per day and a second producing at a rate of 115 Bbls of oil per day in October 2012.  The third well in this program is currently shut-in.  Total production from these wells as of October 31, 2012 was 104,007 Bbls of oil and 19,519 Mcf of natural gas.

South Wayne Prospect, Oklahoma. On March 14, 2010, we acquired a 5% working interest in Okland Oil’s South Wayne prospect 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.  Total production for the McPherson well as of October 31, 2012 was 18,782 Bbls of oil and 10,521 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 which 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.

Work has commenced on this project.  Shooting and data acquisition started on the Oklahoma 3-D project in late February 2011.  The project covers approximately 86,350 acres or 135 square miles of which approximately 83,043 acres or 130 square miles has been permitted.

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 still under way.

As of October 31, 2012, 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 up to a 10-well exploration program on 10 separate prospects will start in the near future.

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Double T Ranch#1 SWDW, Oklahoma.  On July 17, 2012, we acquired a 3.00% working interest in the drilling, completion and operations of the Double T Ranch#1 SWDW located in Garvin County from Ranken Energy Corporation.

King City Oil Field

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

International Exploration Program

We are attempting to expand our 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, 2012, 2011 and 2010.

	For the fiscal year ended October 31, 2012	For the fiscal year ended October 31, 2011	For the fiscal year ended October 31, 2010
Production Data:
Natural gas (Mcf)	14,017	26,662	17,574
Oil (Bbls)	4,300	11,962	8,213
Average Prices:
Natural gas (per Mcf)	$4.93	$6.01	$4.85
Oil (per Bbl)	$93.13	$89.81	$65.66
Production Costs:
Natural gas (per Mcf)	$1.31	$1.77	$2.02
Oil (per Bbl)	$17.84	$11.16	$7.25

Productive Wells

The following table summarizes information at October 31, 2012, 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.

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	Gross			Net
Location	Oil	Gas	Total	Oil	Gas	Total
Oklahoma	9	0	9	0.45	0.00	0.45
California	0	0	0	0.0	0.00	0.0
Total	9	0	9	0.45	0.00	0.45

Unaudited Oil and Gas Reserve Quantities

The following unaudited reserve estimates for Oklahoma, presented as of October 31, 2012, were prepared by Harper and Associates, an independent petroleum engineering firm.

The combined estimated proved reserves prepared by 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 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.

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, 2010		93,239			98,847
Revisions of previous estimate		(9,396)			24,000
Discoveries		4,698			33,096
Reserves sold to third parties		(37,780)			(3,580)
Production		(11,962)			(26,662	)
Estimated quantity, October 31, 2011		38,799			125,701
Reserves sold to third parties		(2,909	)		(99,737	)
Revisions of previous estimate		(17,260)			1,723
Discoveries		-			-
Production		(4,300	)		(14,017	)
Estimated quantity, October 31, 2012		14,330			13,670

The revisions in the Company’s estimates of proved oil and gas reserves are due to the fact that there was more substantive data, such as a longer history of production, available to its engineers which allowed them to better quantify the reserve estimates.

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Proved Reserves at year end	Developed	Undeveloped	Total
Crude Oil (Bbls)
October 31, 2012	12,880	1,450	14,330
October 31, 2011	36,969	1,830	38,799
October 31, 2010	70,129	23,110	93,239
Gas (MCF)
October 31, 2012	12,570	1,100	13,670
October 31, 2011	124,501	1,200	125,701
October 31, 2010	98,617	230	98,847

Internal Controls Over Preparation of Proved Reserve Estimates

Our policies regarding internal controls over reserve estimates requires reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by one or more independent third party reserve engineering firms under the supervision of our management. Our management provides to our third party reserve engineers, reserve estimate preparation material such as property interests, production, current costs of operation and development, current prices for production, geoscience and engineering data, and other relevant information.  During the fiscal year ended October 31, 2012, we retained Harper & Associates, Inc. as independent third-party reserve engineers, to prepare our estimates of proved reserves.  For more information about the evaluations performed by Harper & Associates, Inc., see copies of its report filed as exhibits to this Form 10-K.

Our former President, Leroy Halterman, was the person primarily responsible for overseeing the preparation of reserves estimates conducted by independent third-party engineers.  Mr. Halterman had 40 years of geology experience, which included being president of a natural resource investment firm.  He directed over 30 mineral project appraisals and evaluations prior to joining us.  In these capacities, Mr. Halterman had a very high degree of working knowledge and understanding of geologic formations, drilling and completion parameters.  Given his familiarity with the properties he had previously directed and those current properties we hold,  we  considered Mr. Halterman to be a qualified person in overseeing the preparation of our internal reserve estimates by a third-party engineering firm.  Mr. Halterman was a graduate of the Missouri School of Mines with a Bachelor of Science degree in Geology.  Mr. Halterman passed away in April 2012.

We have engaged Mr. Brian Ault to oversee the preparation of the reserve estimates conducted by independent third-party engineers.  Mr. Ault has 25 years of experience in drilling, completion, production, regulatory reporting/permitting, reservoir studies and evaluations of United States oil and gas fields.  Mr. Ault graduated from Marietta College in May 1986 with a Bachelor of Science degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers.  Given his qualifications, we consider Mr. Ault to be a qualified person in overseeing the preparation of our internal reserve estimates by a third-party engineering firm.

Oil and Gas Acreage

The following table sets forth the undeveloped and developed acreage, by area, held by us as of October 31, 2012.  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 the fiscal year ended October 31, 2012 in anticipation of the large leasing efforts that will begin in the near future on prospects generated within the 135 square mile Oklahoma 3D seismic program.

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	Undeveloped Acres		Developed Acres
	Gross	Net	Gross	Net
Oklahoma	5,573.6	392.6	640.0	96.0
California	10,000.0	2,000.0	0.0	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, 2012, 2011 and 2010.  We drilled less wells the past two years as we plan to drill numerous future wells based upon prospects generated by the new 135 square mile Oklahoma 3D seismic program.  This past year we participated in the drilling of the Double T Ranch#1 salt water disposal well located in Garvin County, Oklahoma.

	2012		2011		2010
	Gross	Net	Gross	Net	Gross	Net
Exploratory wells:
Productive	0	0	1	.05	9	0.45
Dry	0	0	0	.05	4	0.20
Development wells:
Productive	0	0	1	.2	4	0.47
Dry	0	0	0	0	1	0.085
Total wells	0	0	2	.3	18	1.205

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 $3,101 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.

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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, 2013.

Office Space

Until his death in April 2012, we used the offices of Leroy Halterman, our former president, located at 820 Piedra Vista Road NE, Albuquerque, NM 87123.  Since then, our offices have been located temporarily in care of the registrant’s counsel, Dill Dill Carr Stonbraker & Hutchings, P.C., 455 Sherman Street, Suite 300, Denver, Colorado 80203.

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, 2012, we recognized $51,276 in revenue from the Joe Murray Farms well and a total of $170,571 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

ITEM 4.         Mine Safety Disclosures.

Not applicable.

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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
2011 Fiscal Year	High	Low
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
2012 Fiscal Year
Quarter ending 01/31/12	$0.18	$0.101
Quarter ending 04/30/12	$0.169	$0.0815
Quarter ending 07/31/12	$0.145	$0.07
Quarter ending 10/31/12	$0.1	$0.055

As of January 14, 2013, there were 29record holders of our common stock, and one record holder of our Series A preferred stock.  The closing bid price of our common stock on January 24, 2013 was $0.075.

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

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, 2012 or 2011.  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:

§   $300,000 to $500,000 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

§   $700,000 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.

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Accordingly, we anticipate spending approximately $1,000,000 to $1,200,000 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  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, 2012 and 2011, 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, 2012 and 2011:

	October 31,			October 31,
	2012			2011
Balance, beginning of year	$	26,335		$	27,494
Liabilities assumed		-			774
Revisions		(1,941	)		(5,232	)
Accretion expense		3,160			3,299
Balance, end of year	$	27,554		$	26,335

The reclamation obligation relates to the Bagwell #1-20, Bagwell #2-20, Jackson #1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis #2-8, Gehrke #1-24, and Miss Jenny #1-8 wells at the Oklahoma Properties, and 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 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

16

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 $469,107 from natural gas and oil sales during the fiscal year ended October 31, 2012, compared with $1,241,015 during the fiscal year ended October 31, 2011, a decrease of $771,908 due primarily to a decrease in the number of producing wells.  In the fiscal year ended October 31, 2012, we sold 14,017 Mcf of natural gas and 4,300 Bbls of oil, and in 2011, we sold approximately 26,662 Mcf of natural gas and 11,962 Bbls of oil.  Our natural gas volumes decreased by 47%, and our oil volume decreased by 64%.  The average price received for our natural gas sales in 2012 was $4.93 per Mcf, versus $6.01 per Mcf in 2011, representing a decrease of $1.08 or 18%.  The average price received for our crude oil sales in 2012 was $93.13 per Bbl, versus $89.81 per Bbl in 2011, representing an increase of $3.32 or 4%.

For the fiscal year ended October 31, 2012, we incurred a net loss of $764,988, compared with a net loss of $131,443 for the fiscal year ended October 31, 2011 (an increase in net loss of $633,545).

We incurred direct costs of $1,254,308 for the fiscal year ended October 31, 2012, compared with $1,373,358 for the fiscal year ended October 31, 2011, a decrease of $119,050.  The decrease in our direct costs was largely attributable to decreases in our production costs, depletion and accretion costs, and general and administrative costs, offset by an increase in our writedown of natural oil and gas properties.  Our general and administrative costs decreased to $595,386 for the fiscal year ended October 31, 2012, from $735,384 for the fiscal year ended October 31, 2011 due to a decrease in costs of investor relations and consulting services.

Our depletion and accretion costs decreased from $344,932 during the fiscal year ended October 31, 2011 to $145,835 for the fiscal year ended October 31, 2012, a decrease of $199,097.  Depletion is calculated based on production rates produced during the year.  Our depletion and accretion costs decreased as a result of a decrease in our oil and gas production.

Our production costs decreased from $183,743 for the fiscal year ended October 31, 2011 to $101,690 for the fiscal year ended October 31, 2012, a decrease of $82,053.  Our production costs decreased as a result of a decrease in our oil and gas production, but increased as a percentage of sales from 15% to 22%.

During the fiscal year ended October 31, 2012, writedown of natural gas and oil properties was $314,906, compared to $nil for the fiscal year ended October 31, 2011.  This was due to the disposal of the Company’s wells in Oklahoma and the increasing decline in the life of the remaining wells.

We had an unrealized loss on held for sale marketable security of $112,000 for the fiscal year ended October 31, 2012 as compared to an unrealized loss on held for sale marketable security of $64,000 for the fiscal year ended October 31, 2011.  The value of our shares in Lexaria Corp. at October 31, 2012 was $0.12 per share, as compared to $0.26 per share as at October 31, 2011, giving rise to the increase in such unrealized loss.

Liquidity and Capital Resources

As of October 31, 2012, we had cash and short term investments of $940,512 and working capital of $1,113,259, compared to cash and short term investments of $801,047 and working capital of $1,365,078 as of October 31, 2011.

During the fiscal year ended October 31, 2012, net cash used in operating activities was $127,972, compared to net cash of $405,959 provided by operating activities for the fiscal year ended October 31, 2011. This difference was due to a reduction in revenue from the previous year and the resulting increased net loss for fiscal 2012.

17

Net cash provided by investing activities during the fiscal year ended October 31, 2012 was $267,437, compared with $25,941 used during the fiscal year ended October 31, 2011.  We used $283,587 in cash for our oil and gas interests compared to $624,771 during the previous year.  We received $552,144 from the sale of our Mississippi assets and Three Sands Project during the 2012 fiscal year and $200,000 from the sale of its Mississippi assets during the 2011 fiscal year.

No cash was provided by or used in financing activities during the fiscal years ended October 31, 2012 and 2011.

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, 2012.

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

Not required for smaller reporting companies.

ITEM 8.         FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

18

[EXCELSIS LETTERHEAD]

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, 2012 and 2011 and the related statements of comprehensive income, stockholders’ equity and cash flows for each of the years in the two-year period ended October 31, 2012. 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, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the two-year period ended October 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

/s/ Excelsis Accounting Group

Excelsis Accounting Group

Reno, NV

January 29, 2013

1495 Ridgeview Drive, Ste. 200, Reno, Nevada 89519

Tel: 775.332.4200 · Fax: 775.332.4210

www.excelsisaccounting.com

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BRINX RESOURCES LTD.

BALANCE SHEETS

	October 31,			OCTOBER 31,
	2012			2011
ASSETS
Current assets
Cash and cash equivalents	$	540,512		$	401,047
Investment - Certificate of deposit		400,000			400,000
Marketable securities		96,000			208,000
Accounts receivable		38,485			329,748
Prepaid expenses and deposit		44,594			37,254
Total current assets		1,119,591			1,376,049
Undeveloped mineral interests, at cost		3,101			1,981
Oil and gas interests, full cost method of accounting,
net of accumulated depletion		1,450,330			2,074,900
Total assets	$	2,573,022		$	3,452,930
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	6,332		$	10,971
Total current liabilities		6,332			10,971
Asset retirement obligations		27,554			26,335
Total liabilities		33,886			37,306
Stockholders' equity
Preferred stock - $0.001 par value; authorized - 25,000,000 shares
Series A Preferred stock - $0.001 par value; authorized
- 1,000,000.  Issued and outstanding - 500,001 shares		500			-
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		(176,000	)		(64,000	)
Retained earnings		(178,051	)		586,937
Total stockholders' equity		2,539,136			3,415,624
Total liabilities and stockholders' equity	$	2,573,022		$	3,452,930

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

20

BRINX RESOURCES LTD.

STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

	YEAR ENDED
	OCTOBER 31,
	2012			2011
REVENUES
Natural gas and oil sales	$	469,107		$	1,241,015
DIRECT COSTS
Production costs		101,690			183,743
Depletion and accretion		145,835			344,932
General and administrative		595,386			735,384
Loss on sale of natural gas and oil properties		96,491			109,299
Writedown of natural gas and oil properties		314,906			-
Total Expenses		(1,254,308	)		(1,373,358	)
OPERATING INCOME/(LOSS)		(785,201	)		(132,343	)
OTHER INCOME
Interest income		213			900
Other Income		20,000			-
NET INCOME/(LOSS)		(764,988	)		(131,443	)
OTHER COMPREHENSIVE INCOME/(LOSS), NET OF TAX
Unrealized (loss) on held for sale marketable security		(112,000	)		(64,000	)
COMPREHENSIVE INCOME/(LOSS) FOR THE YEARS	$	(876,988	)	$	(195,443	)
Net Income/(Loss) Per Common Share
- Basic	$	(0.03	)	$	(0.01	)
- Diluted	$	(0.03	)	$	(0.01	)
Weighted average number of common shares outstanding
- Basic		24,629,832			24,629,832
- Diluted		24,629,832			24,629,832

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

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BRINX RESOURCES LTD.

STATEMENT OF STOCKHOLDERS' EQUITY

	PREFERRED STOCK				COMMON STOCK
														Accumulative
									Capital in					Other			Total
	Number				Number				Excess of		Retained			Comprehensive			Stockholders'
	of Shares		Amount		of Shares		Amount		Par Value		Earnings			(Loss)			Equity
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	)
Net (loss)		-		-		-		-		-		(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
Comprehensive income / (loss)
Shares issued to a director		500,001		500		-		-		-		-			-			500
Unrealized (loss) on held for sale marketable security		-		-		-		-		-		-			(112,000	)		(112,000	)
Net (loss)		-		-		-		-		-		(764,988	)		-			(764,988	)
Comprehensive (loss)
BALANCES, OCTOBER 31, 2012		500,001	$	500		24,629,832	$	24,630	$	2,868,057	$	(178,051	)	$	(176,000	)	$	2,539,136

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

22

BRINX RESOURCES LTD.

STATEMENTS OF CASH FLOWS

	YEAR ENDED
	OCTOBER 31,
	2012			2011
CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES
Net (loss)	$	(764,988	)	$	(131,443	)
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion and accretion		145,835			344,932
Loss on sale of natural gas and oil properties		96,491			109,299
Writedown of natural gas and oil properties		314,906			-
Changes in working capital:
Decrease in accounts receivable		91,763			19,176
Decrease / (Increase) in prepaid expenses and deposit		(7,340	)		90,801
(Decrease) in accounts payable and accrued liabilities		(4,639	)		(26,806	)
Net cash provided by /(used in) operating activities		(127,972	)		405,959
CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES
Redemption of Certificate of deposit		-			400,000
Sale proceeds of natural gas and oil working interests		552,144			200,000
Payments on mineral interest		(1,120	)		(1,170	)
Payments on oil and gas interests		(283,587	)		(624,771	)
Net cash provided by /(used in) investing activities		267,437			(25,941	)
CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES
Net cash provided by /(used in) financing activities		-			-
Net increase in cash		139,465			380,018
Cash and cash equivalents, beginning of years		401,047			21,029
Cash and cash equivalents, end of years	$	540,512		$	401,047
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for taxes	$	-		$	2,428
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Assets retirement costs incurred	$	(3,160	)	$	(3,299	)
Investment in natural oil and gas working interests included in	$	-		$	-
accounts payable
Issuance of preferred shares to a director	$	500			-

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

23

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 in New Mexico and oil and gas interests 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 value 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.  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, 2012 and 2011, the Company had no overproduced imbalances.

24

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 year.  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 was nil as of October 31, 2012 and 300,000 as of October 31, 2011.  As the Company is reporting net losses in both years, 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, 2012 and 2011:

	October 31, 2012			October 31, 2011
Basic earnings per share computation:
(Loss) from continuing operations	$	(764,988	)	$	(131,443	)
Basic shares outstanding		24,629,832			24,629,832
Basic earnings per share	$	(0.03	)	$	(0.01	)

25

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, if any, are presented as a component of “Other assets” and “Other liabilities and accrued expenses,” respectively, in the balance sheet.  Tax provisions are computed in accordance with FASB ASC 740, “Accounting for Income Taxes.”

The Company applies 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 de-recognition, 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 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.

26

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.”

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 had no effect on the calculation of net income, comprehensive income or earnings per share.

2. MARKETABLE SECURITIES

In August 2011, 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, 2012 was $0.12 per share, as compared to $0.26 per share as at October 31, 2011, giving rise to an unrealized loss of $112,000 for the year ended October 31, 2012 (2011 – unrealized loss of $64,000).  The Company evaluated the prospects of Lexaria in relation to the severity and duration of the impairment. Based on that evaluation and the Company’s ability and intent to hold the shares for a reasonable period of time sufficient for a recovery, the Company does not consider the shares to be other-than-temporarily impaired at October 31, 2012.

3.         ACCOUNTS RECEIVABLE

Accounts receivable consists of revenues receivable, interest receivable and other receivable.  The revenue receivable are from the operators of the oil and gas projects for the sale of oil and gas by the operators on the Company’s 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, 2012 and October 31, 2011.  Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.

	October 31, 2012		October 31,    2011
Accounts receivable	$	38,485	$	329,748
Less: allowance for doubtful account		-		-
	$	38,485	$	329,748

27

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

4.   OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:

	October 31, 2012			October 31, 2011
2008-3 Drilling Program, Oklahoma	$	309,152		$	302,361
2009-2 Drilling Program, Oklahoma		114,420			114,420
2009-3 Drilling Program, Oklahoma		337,749			300,080
2009-4 Drilling Program, Oklahoma		190,182			190,146
2010-1 Drilling Program, Oklahoma		254,817			253,855
Washita Bend 3D, Oklahoma		537,361			482,882
Double T Ranch #1 SWDW, Oklahoma		43,078			--
Kings City Prospect, California		404,121			263,561
South Wayne Prospect, Oklahoma		61,085			61,085
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi		(222,123	)		(222,123	)
Three Sands Project, Oklahoma		555,715			1.451,453
Asset retirement cost		2,593			4,534
Less:  Accumulated depletion and impairment		(1,137,820	)		(1,127,444	)
	$	1,450,330		$	2,074,900

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.  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”) is 6.25% and the After Casing Point Interest (“ACP”) is 5.00%.  At October 31, 2012, the total cost of the 2008-3 Drilling Program was $309,152.  The interests are located in Garvin County, Oklahoma.

2009-2 Drilling Program, Oklahoma

On June 19, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2009-2 Drilling Program.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At October 31, 2012, 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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At October 31, 2012, the total cost of the 2009-3 Drilling Program was $337,749.  The interests are located in Garvin County, Oklahoma.

28

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

4.           OIL AND GAS INTERESTS (continued)

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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At October 31, 2012, the total cost of the 2009-4 Drilling Program was $190,182.  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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At October 31, 2012, the total cost of the 2010-1 Drilling Program was $254,817.  The interests are located in Garvin County, Oklahoma.

Washita Bend 3D Exploration Project, Oklahoma

On March 1, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s Washita Bend 3D Exploration Project.  The BCP Interest is 5.625% and the ACP Interest is 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  At October 31, 2012, the total costs, including seismic costs, was $537,361.

Double T Ranch#1 SWDW, Oklahoma

On July 17, 2012, the Company acquired a 3.00% working interest in the drilling, completion and operations of the Double T Ranch#1 SWDW located in Garvin County from Ranken Energy Corporation. At October 31, 2012, the cost of the Double T Ranch#1 SWDW was $43,078.

Kings City Prospect, California

A Farmout agreement was made effective on May 25, 2009 between the Company and Sunset Exploration, Inc., to explore for oil and natural gas on 10,000 acres located in west central California.  The Company paid $100,000 (50% pro rata share of $200,000)  to earn a 20% working interest in project by funding a maximum of 50% of a $200,000 in a geophysical survey composed of gravity and seismic surveys and 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, 2012 was $404,121.

Three Sands Project, Oklahoma

On October 6, 2005, the Company acquired a 40% working interest in Vector Exploration Inc.’s Three Sands Project.

On September 10, 2012, the Company signed the asset purchase agreement with GLM Energy Inc., to sell the oil and gas assets effective June 1, 2012 for a total of $352,144.  The disposed reserves represented more than 25% of the total reserves which the Company considered to represent a significant alteration between capitalized costs and proved reserves and hence a loss on the sale was recognized in the Statements of Comprehensive Income in the amount of $96,491 for the year ended October 31, 2012.

29

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

4.            OIL AND GAS INTERESTS (continued)

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 is 6.25% and the ACP Interest is 5.00%.  The interests are located in McClain County, Oklahoma.  The total cost of the South Wayne prospect as at October 31, 2012 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 received 800,000 shares of restricted common stock in Lexaria Corp.  These properties consist principally of the Belmont Lake Oil Field and all undeveloped acreage in the Palmetto Point Project.  $200,000 was received on August 12, 2011.  $10,000 per month was paid in November and December 2011 and the balance of $200,000 was paid on January 13, 2012. The disposed reserves represented more than 25% of the total reserves which the Company 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 for the period ended October 31, 2011.

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 $314,906 and $0 in impairment cost for the years ended October 31, 2012 and 2011, respectively.

Depletion

Under the full cost method, depletion is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production.  Depletion expense recognized was $142,675 and $341,633 for the year ended October 31, 2012 and 2011, respectively.

Capitalized Costs

	October 31, 2012			October 31, 2011
Proved properties	$	1,603,590		$	2,395,902
Unproved properties		984,560			806,443
Total Proved and Unproved properties		2,588,150			3,202,345
Accumulated depletion expense		(734,698	)		(989,713	)
Impairment		(403,122	)		(137,732	)
Net capitalized cost	$	1,450,330		$	2,074,900

30

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

4.            OIL AND GAS INTERESTS (continued)

Results of Operations

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

	October 31, 2012			October 31, 2011
Revenues	$	469,107		$	1,241,015
Production costs		(101,690	)		(183,743	)
Depletion and accretion		(145,835	)		(344,932	)
Results of operations (excluding corporate overhead)	$	221,582		$	712,340

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, 2012 and 2011, the Company recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with “Accounting for Asset Retirement Obligations”.  The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production.  The Company amortizes the amount added to the oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining life of the respective well.  The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements.  The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.  Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.

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

The information below reflects the change in the asset retirement obligations during the years ended October 31, 2012 and 2011:

	October 31, 2012			October 31, 2011
Balance, beginning of years	$	26,335		$	27,494
Liabilities assumed		-			774
Revisions		(1,941	)		(5,232	)
Accretion expense		3,160			3,299
Balance, end of years	$	27,554		$	26,335

The reclamation obligation relates to the Bagwell#1-20, Bagwell#2-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24 and Miss Jenny#1-8 wells at Oklahoma Properties, and 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.

31

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

6. COMMON STOCK

PREFERRED STOCK

The Company has authorized 25,000,000 shares of preferred stock.  On February 10, 2012, the Company issued 500,001 Series A preferred stock at par value.  The rights attached to these Series A preferred stock include:

·       The holders of the Series A preferred stock can redeem their stock at a predetermined redemption price.

·       The holders of the Series A Preferred Stock shall be entitled to elect one director of the Company in connection with each annual election of directors who shall be the designated “Series A Director”.    With respect to any other matter submitted for a vote (or a written consent in lieu thereof) by the stockholders of the Company (except as to which the Series A Preferred Stock will be entitled to vote separately as a class), the holders of Series A Preferred Stock and the holders of the common stock, $0.001 par value of the Company (“Common Stock”) shall vote together as a single class and not as separate series.

·       The Company shall not without first obtaining the approval (by vote or written consent, as provided by law) of the holders of a majority of the Series A Preferred Stock do any of the following:

(a)          amend, alter, or repeal 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 Preferred Stock;

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

(c)           authorize or issue, or obligate itself 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 authorize any increase in the authorized or designated number of any such security;

(d)           purchase or otherwise acquire any share or shares of Preferred Stock or Common Stock (or pay 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)           authorize the voluntary or involuntary dissolution, liquidation or winding-up of the Company;

(f)           pay 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 aggregate net profits for the fiscal year of the Company in which such dividend is declared and the immediately preceding fiscal year;

(g)           cause the Company to enter into or engage, directly or indirectly, in any material respect any line of business other than the 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; or

32

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

6. COMMON STOCK (continued)

PREFERRED STOCK (continued)

(h)           enter into any transaction with any officer, director or stockholder of the Company or any "affiliate" or "associate" (as such terms are defined in the regulations promulgated by the Securities and Exchange Commission under the Securities Exchange Act of 1940) of any such person or entity, other than normal employment arrangements and benefit programs on reasonable terms and other than any transaction (or series of related transactions) involving not more than $100,000 in the aggregate that has been approved by a majority of the Board of Directors (excluding any director who is interested in such transaction, either directly or through one of his affiliates or associates) after full disclosure of the terms thereof to the Board of Directors and after the determination by such majority of the Board of Directors

                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.  A summary of the changes in stock options for the year ended October 31, 2012 is presented below:

	Options Outstanding
				Weighted Average
	Number of Shares			Exercise Price
Balance, October 31, 2011		300,000		$	0.10
Expired on November 2, 2011		(300,000	)		0.10
Balance, October 31, 2012		-		$	-

7.         RELATED PARTY TRANSACTIONS

During the years ended October 31, 2012 and 2011, the Company entered into the following transactions with related parties:

a)     The Company paid $30,000 (2011 - $72,000) in management fees and reimbursement of office space of $nil (2011 - $4,400) to the former President of the Company.

b)     The Company paid $74,000 (2011 - $71,000) to a related entity, for administration services.

c)     The Company paid $122,000 (2011 - $101,000) in management fees to the director and current President of the Company.

d)     The Company paid $78,597 (2011 - $76,813) in consulting and accounting fees to the Chief Financial Officer of the Company.

e)     The Company paid $1,000 (2011 - $ nil) in consulting fee to the director of the Company.

8. INCOME TAXES

Income tax expense (benefit) for the years ended October 31, 2012 and 2011, respectively, consists of the following:

	October 31		October 31
		2012		2011
Current taxes	$	-		-
Deferred taxes		-		-
Net income tax provision (benefit)	$	-	$	-

33

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS
 

8. INCOME TAXES (continued)

The effective income tax rate for years ended October 31, 2012 and 2011, respectively, are:

	October 31		October 31
		2012		2011
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 that give rise to significant portions of the deferred tax assets and deferred tax liabilities are provided below:

	October 31			October 31
	2012			2011
Deferred tax assets & liabilities:
Federal and state net operating loss carryovers	$	1,065,303		$	174,204
Asset retirement liability		9,644			9,217
Stock options granted		-			8,897
Book depletion in excess of tax depreciation		(589,608	)		138,422
Deferred tax asset	$	485,339		$	330,740
Valuation Allowance		(485,339	)		(330,740	)
Deferred tax liability	$	-		$	-

The Company has $3,043,724 of net operating loss carry forwards as of October 31, 2012 which will begin to expire on October 31, 2029.

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 statements of comprehensive income in the provision for income taxes.  As of October 31, 2012 and 2011, the Company had not incurred interest or penalties related to uncertain tax positions.

9.           UNAUDITED OIL AND GAS RESERVE QUANTITIES

The following unaudited reserve estimates presented as of October 31, 2012 and 2011 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.

34

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

9.        UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)

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, 2010		93,239			98,847
Revisions of previous estimate		(9,396	)		24,000
Discoveries		4,698			33,096
Reserves sold to third parties		(37,780	)		(3,580	)
Production		(11,962	)		(26,662	)
Estimated quantity, October 31, 2011		38,799			125,701
Reserves sold to third parties		(2,909	)		(99,737	)
Revisions of previous estimate		(17,260	)		1,723
Discoveries		-			-
Production		(4,300	)		(14,017	)
Estimated quantity, October 31, 2012		14,330			13,670

The revisions in the Company’s estimates of proved oil and gas reserves are due to the fact that there was more substantive data, such as a longer history of production, available to its engineers which allowed them to better quantify the reserve estimates.

Proved Reserves at year end	Developed	Undeveloped	Total
Crude Oil (Bbls)
October 31, 2012	12,880	1,450	14,330
October 31, 2011	36,969	1,830	38,799
Gas (MCF)
October 31, 2012	12,570	1,100	13,670
October 31, 2011	124,501	1,200	125,701

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 year-end 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.  Certain balances from 2011 have been updated based on revised calculations.

35

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

9.        UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)

	October 31,  2012			October 31, 2011
Future Cash inflows	$	1,396,960		$	4,192,510
Future production costs		(521,440	)		(1,033,904	)
Future development costs		(61,250	)		(61,250	)
Future income tax expense		-			-
Future cash flows		814,270			3,097,356
10% annual discount for estimated timing of cash flows		(359,860	)		(1,063,697	)
Standardized measure of discounted future net cash	$	454,410		$	2,033,659

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, 2012			October 31, 2011
Beginning of year	$	2,033,659		$	2,533,242
Sales and transfers of oil and gas produced, net production costs		(367,417	)		(1,057,272	)
Net changes in prices and production costs and other		(89,162	)		228,959
Net sale of reserves in place		(471,660	)		(2,200,776	)
Changes in future development costs		-			242,276
Revisions of previous estimates		(1,618,488	)		(852,521	)

Other		263,641			944,503
Net change in income taxes		-			1,840,474
Accretion discount		703,837			354,774
Total change in the standardized measure during the year		(1,579,249	)		(499,583	)
Standardize measure, end of year	$	454,410		$	2,033,659

10.       MAJOR CUSTOMERS

We collected $382,540 (2011: $798,912) or 81% (2011: 64%) of our revenues from one of our operators during the year ended October 31, 2012. As of October 31, 2012, $34,095 (2011: $90,602) was due from this operator.

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

36

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

11.       CONTINGENCIES (continued)

escrowed and there is no assurance that the Company will be able to recover these proceeds.  The Company recognized $51,276 in revenue during year ended October 31, 2012 and $119,295 in revenue during the year ended October 31, 2011 from the Joe Murray Farms well and a total of $170,571 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

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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, 2012, 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, Kenneth Cabianca and Kulwant Sandher.  Based on this evaluation, Messrs. Cabianca and Sandher concluded that the design and operation of our disclosure controls and procedures were not effective because of the following material weaknesses that existed at October 31, 2012:

·      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, 2012.  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, 2012, 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

38

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, 2012, 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
Kenneth A. Cabianca	72	Director and President
Georgia Knight	49	Director
Kulwant Sandher	51	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:

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 remained a director.  Mr. Cabianca was appointed our president effective immediately after Mr. Halterman’s death.  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.

Georgia Knight was elected as a director on August 24, 2012, filling the vacancy created by Mr. Halterman’s death.  Ms Knight has a 28-year background in securities related employment with both publicly traded and private business ventures, and has extensive experience in the financing of mining projects, primarily through private placements with institutional investors and junior public mining companies.  Since October 2004, Ms. Knight has been the president and secretary of BVB Management Svs. Ltd., a company that provides management and administrative consulting services.  Ms. Knight was elected as a director and a member of the audit committee

39

of Leeta Gold Corp. in April 2004 and continues to serve in these positions.  Ms. Knight served as a director of Primo Resources (n/k/a Pacific Coal Resources Ltd.) from December 1999 to March 2011, and was its Chief Financial Officer from 2009 to 2011.  From June 2005 to March 2012, Ms. Knight served as a director of Whistler Gold Exploration Corp. (f/k/a Maximum Ventures Inc.).  Ms. Knight also served as a director of Bluenose Gold Corp. (f/k/a International Alliance Resources Inc.) from December 2005 to March 2012.  Ms. Knight completed The Canadian Securities Course in 1990 and received a Graduate Certificate from Simon Fraser University for Corporate Governance and Regulatory Compliance in 1994.  During the past five years, Ms. Knight 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 to 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.

40

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.

Audit Committee

We do not have an Audit Committee at this time.

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, 2012 and 2011.  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 ($)	Stock Awards ($)	All Other Compensation	Total ($)
Leroy Halterman President and Secretary	2012 2011	30,000 72,000	-0- -0-		30,000 72,000
Kenneth Cabianca (1) President	2012 2011	20,000 -0-	500(2) -0-	102,000(3)	122,500 101,000

_____________

(1)   Kenneth Cabianca was appointed to serve as President after Mr. Halterman’s death in April 2012.  He was not an officer in the Company in 2011.

(2)   The fair value of the stock grant to Mr. Cabianca was estimated as of the date of grant using the par value of such stock.

(3)   Kenneth Cabianca received such amount as compensation for services as a director and pursuant to the Management Consulting Agreement.

In addition to the above, we reimbursed Mr. Halterman $nil and $4,400 for office space for the fiscal years ended October 31, 2012 and 2011, respectively.

During the last two fiscal years ended October 31, 2012 and 2011, other than as set forth above, there were no grants of stock options, stock appreciation rights, benefits under long-term incentive plans or other forms of compensation involving our officers.  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.

The following table sets forth compensation of our directors for the last completed fiscal year ended October 31, 2012.  Mr. Halterman did 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 ($)
Georgia Knight	1,000	-0-	-0-	0	1,000

41

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 January 28, 2013, 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
	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%
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%	2,554,702	10.4%	3,054,703	12.2%
Barry T. Brooks (7) 3843 Jamestown Road Springfield, OH  45502	0	--	1,876,157	7.6%	1,876,157	7.5%
Jeff Beckett (8) 3800 North Woodward Ave, Suite 300 Birmingham, MI  48009	0	--	2,634,935	10.7%	2,634,935	10.5%

__________________

(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 January 28, 2013.

(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)   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.

(8)   All information for Jeff Beckett was obtained from the Schedule 13D/A filed by Mr. Beckett on December 17 2012.

Equity Compensation Plan Information

As of October 31, 2012, 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

42

Equity compensation plans not approved by security holders	-0-	N/A	N/A
Total	-0-	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.

For the fiscal years ended October 31, 2012 and 2011, we incurred $74,000 and $71,000, 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.

During the fiscal years ended October 31, 2012 and 2011, we paid $30,000 and $72,000, respectively, in management fees and $nil and $4,400, respectively, as reimbursement for office space to our former president, Lee Halterman.

During the fiscal years ended October 31, 2012 and 2011, we paid $122,000 and $101,000, respectively, in management fees to a director and our current president, 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 certain actions by the Company that could affect the Series A Preferred stockholders or the Company, pay any dividend or other distribution with limited exceptions, or enter into certain other transactions, all as set forth therein.  On March 14, 2012, Kenneth Cabianca was elected the Series A director.

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

43

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, 2012, Mark Bailey & Company, Ltd. d/b/a Excelsis Accounting Group (“Excelsis”) is expected to bill us approximately $35,500 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, 2011, Excelsis billed us $35,500 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 2012 and 2011.

Tax Fees

For the fiscal year ended October 31, 2012, Excelsis is expected to bill us $9,000 for tax compliance services.  For the fiscal year ended October 31, 2011, Excelsis billed us $6,000 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 2012 and 2011.

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. 

44

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 (5)
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 (5)
23.1	Consent of Harper & Associates, Inc.
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
99.1	Reserve Report from Harper & Associates, Inc. dated January 14, 2013
101*	Financial statements from the Annual Report on Form 10-K of Brinx Resources Ltd. for the year ended October 31, 2012, formatted in XBRL: (i) the Balance Sheets; (ii) the Statements of Comprehensive Income; (iii) the Statements of Cash Flows; (iv) the Statements of Stockholders’ Equity; and (v) the Notes to Financial Statements.

___________________

(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 annual report on Form 10-K for the fiscal year ended October 31, 2011 filed February 14, 2012.

*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.

45

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:  January 31, 2013	By:	/s/ Kenneth A. Cabianca
		Kenneth A. Cabianca, 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/ Kenneth A. Cabianca	President, Secretary and Director (principal executive officer)	January 31, 2013
Kenneth A. Cabianca
/s/ Kulwant Sandher	Chief Financial Officer (principal financial and accounting officer)	January 31, 2013
Kulwant Sandher
/s/ Georgia Knight	Director	January 31, 2013
Georgia Knight

46

EX-23.1

EXHIBIT 23.1

CONSENT OF HARPER & ASSOCIATES, INC.

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to all references to Harper & Associates, Inc., independent petroleum engineers, and the reports prepared by such independent petroleum engineers appearing in Brinx Resources Ltd.’s Annual Report on Form 10-K for the year ended October 31, 2012 to be filed with the U.S. Securities and Exchange Commission.

	HARPER & ASSOCIATES, INC.
	By:	/s/ Gl Michael Harper
		G. Michael Harper, President
		P.E. 34481 TX
Fort Worth, Texas
Dated:  January 29, 2013

EX-99.1

EXHIBIT 99.1

RESERVE REPORT FROM

HARPER & ASSOCIATES, INC.

DATED JANUARY 14, 2013

HARPER &ASSOCIATES, INC.

CONSULTANTS AT OIL AND GAS TECHNOLOGY

6815 MANHATTAN BLVD.

SUITE 201

FORT WORTH, TEXAS 76120

G. MICHAEL HARPER PRESIDENT www.harper-associates.com  (817) 457-9955 (FAX) (817) 457-9569 m@harper-associates.com

January 14, 2013

Brinx Resources, LTD

820 Piedra Vista Rd., NE

Albuquerque, NM 87123

                                                                        Re: SEC Reserve Evaluation Brinx Resources, LTD Interests Oklahoma Properties As of November 1, 2012

Dear Sir:

Petroleum reserves for certain properties of Brinx Resources, LTD (“Brinx”) were determined and economic forecasts prepared for the working interests of Brinx.  The properties are located in Garvin County, Oklahoma.  Net Oklahoma reserves herein represent 100 percent proportion of Brinx total reserves.  The assumptions, data, methods and procedures used were appropriate for the purpose served by the reports and we used all methods and procedures as we considered necessary under the circumstances to prepare the reports.

The reserve estimations comply with the definitions of the U.S. Security Exchange Commission.  Reserves are classified as proved developed producing (“PDP”), behind-pipe (“PBP”) and undeveloped (“PUD”).  Proved reserves are those reported where the level of certainty is at least 90 percent probable that the quantities actually recovered will equal or exceed the estimates reserves under the specific prices herein.  Probable behind-pipe (“PrBP”) reserves are reported herein also where the level of certainty is at least 50 percent probable that the quantities actually recovered will equal or exceed the estimates reserves under the specific prices herein.  Those quantities were determined using all geologic and engineering methods and procedures as considered necessary under the circumstances to prepare the report.  All assumptions, lease descriptions and holdings, ownership, historical prices, operating lease cost, well planned investments and past production were appropriately presented by Brinx.

For the evaluation, the table below summarizes net proved reserves and cumulative future cash flow (before U.S. federal income tax), undiscounted and discounted at 10 percent per year.

RESERVE SUMMARY

PROVED	PDP	PBP	PUD	PrBP	TOTAL
Completions	8	1	1	1	11
Net Oil, Bbls.	6,600	4,160	1,450	2,120	14,330
Net Gas, MCF	5,780	6,180	1,100	620	13,670
Revenue ($)
-Oil	614,780	387,590	134,720	197,620	1,334,710
Gas	29,330	26,220	4,290	2,410	62,250
Total	644,110	413,810	139,010	200,030	1,396,960
Operating Expense ($)	223,620	111,430	46,970	40,300	422,330
ProductionTaxes ($)	45,700	29,360	9,860	14,190	99,110
Investments ($)		8,750	45,000	7,500	61,250
Future Cum Net Income ($)	374,790	264,270	37,170	138,030	814,270
Future Cum Net Income @ 10% DF ($)	274,070	103,990	23,960	52,390	454,410

Brinx Resources, LTD

SEC Reserve Evaluation

As of November 1, 2012

January 14, 2013

Page 2 of 3

Reserves and economic results for each reserve class are attached, along with a one-line summary.  Individual well reserves are presented herein.   Reserve class and well performance graphs are enclosed.

Price/Cost Parameters.  Oil, condensate, NGL and gas revenue is based on the average prices for last 12 months for each lease and no escalation.  BTU content, fuel and shrinkage for gas production and the quality of oil production are considered.

Expenses are based on the well operating costs from November 2011 through October 2012.  Expenses are recurring monthly values including G&A.  Operating expenses and investments are not escalated.  Production severance taxes are deducted from revenue.

ASSUMPTIONS

No consideration was given to possible changes in operating conditions or actions of governmental regulatory agencies affecting prices.  Interests were accepted as represented.  Discount factors are calculated at mid-year, compounded annually, and applied to yearly lump sum revenues, expenses and investments.

DATA ACQUISITION

Brinx and operator, Ranken Energy Corporation (“Ranken”), provided well and reserve information including pressure and production data through November 2012.  Additional production information was obtained on offset wells completed in correlative geologic formations with similar production performance.  During our analysis, we were given access to data as was desired and consulted freely with Mr. James Huling, and the officers and employees of Brinx and Ranken.

An examination of the field facilities and operating procedures was not conducted in view of the available data that we had to assess and with our operational experience in Garvin County, Oklahoma.  Data used in the preparation of the evaluation was obtained from the records of the offset operators, public data, private evaluations, Ranken and Brinx.  Basic reservoir and geologic data together with engineering work will be retained on file for review by authorized personnel.

RESERVE DEFINITIONS

The determination of the reserves is based on a petroleum engineering evaluation, supported by an independent geologic interpretation that involved direct and indirect characterization and estimates of reservoir properties.  These properties are derived from data available at the time of preparation.  One should not construe that the reserve quantities are exact.  As additional data becomes available or well operating conditions change, the likely condensate or gas recovery of a reservoir may change, and consequently reserve quantities change.

Reserve estimates comply with the definitions of the U. S. Security Exchange Commission (“SEC”).  The reserves and dollars reported herein are not determined for the following purposes: 1) litigation, 2) loan basis, and 3) market value estimate.

EVALUATOR

This evaluation was conducted and/or supervised by Mr. Michael Harper, President.  He served on the Board of Directors of the SPE for the term 1986-1989.  He has practiced professional petroleum engineering for 35 years.  Before founding his consulting firm, Harper spent five years involved in condensate and gas evaluations, property appraisals and reservoir engineering with the firm of CG&A, Inc.  His engineering studies involved United States and International areas.  Previously, he had been with Placid Oil Company for 10 years.  There Harper's experience included five years working as senior reserve, production and reservoir engineer at the Placid headquarters in Dallas, Texas.  Fields studied were inland, wetlands and offshore in respective states of Alabama, Florida, Louisiana, Mississippi, New Mexico, Oklahoma and Texas.  Overseas evaluations were prepared on geologic features in the North and the Mediterranean Seas.  His five years of experience, onshore and offshore, were spent in field supervision and the engineering design of workovers and drilling wells.

Brinx Resources, LTD

SEC Reserve Evaluation

As of November 1, 2012

January 14, 2013

Page 3 of 3

Harper's education was at Louisiana State University where he received Bachelor and Master of Science Degrees in Petroleum Engineering.  Academic honor societies are Pi Epsilon Tau, Tau Beta Pi and Phi Kappa Phi.  Professional engineering registrations are in Texas and Louisiana.  Memberships in professional associations at the local, state and national levels are the Society of Petroleum Engineers, the American Association of Petroleum Geologists, Society of Petroleum Evaluation Engineers and the Society of Petroleum Well Log Analysts.  Evaluation courses and seminars include geologic description of condensate and gas reservoirs, gas well performance and appraisal, computer applications and 1979 through 2001 Symposiums on Hydrocarbon Economics and Evaluation.  Mr. Harper was the 1996-1997 secretary of the Petroleum Club in Fort Worth.  He currently serves as Chairman, SPE Directors’ Club.

EVALUATORQUALIFICATIONS

I, Michael Harper, a consulting Professional Petroleum Engineer, with an office at 6815 Manhattan Blvd. Ste 201, Fort Worth, Texas 76120, hereby certify:

1.           That I am President of Harper & Associates, Inc. and I did prepare this SEC reserve report with corresponding economic values of Brinx interests in the leases.

2.           That I graduated in Petroleum Engineering in 1966 with a Bachelor of Science degree and Master of Science degree in 1968 from Louisiana State University at Baton Rouge, Louisiana.  Academic honor societies are Pi Epsilon Tau, Tau Beta Pi and Phi Kappa Phi.

3.           That I am a registered Professional Engineer in Louisiana #13687 and Texas #34481.  That I am a certified earth scientist - SIPES #2861.  That I have thirty-two years experience in drilling, production, reservoir studies and evaluations of Canada, Mediterranean, North Sea and United States oil and gas fields.

4.           That Memberships held in professional associations: the Society of Petroleum Engineers (#070557); the American Association of Petroleum Geologists; the Society of Petroleum Well Log Analysts; the Society of Petroleum Evaluation Engineers; and the American Association of Drilling Engineers.  I served on the National Board of Directors of the Society of Petroleum Engineers for the term 1986-1989.  I served as National Director of the Society of Petroleum Evaluation Engineers for the term 2000-2003.

5.           That Principal or its employees in the firm have no direct or indirect interests, nor do they expect to receive any direct or indirect interest in the oil and gas properties reviewed nor do they have any direct or indirect interest in the properties of Brinx.

6.           That I am an independent engineer contracted to review certain leases of Brinx in Oklahoma.

7.           That I have no direct or indirect interests in the actual outcome from the reports that have been prepared for Mr. Kulwant Sandher.

Yours very truly,

/s/ G. Michael Harper

G. Michael Harper, President

HARPER & ASSOCIATES, INC.

P. E. 34481 TX

EX-31.1

Exhibit 31.1

RULE 15d-14(a) CERTIFICATION

I, Kenneth A. Cabianca, certify that:

1.           I have reviewed this annual report on Form 10-K of Brinx Resources Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 31, 2013

/s/ Kenneth A. Cabianca                                    

Kenneth A. Cabianca, President and Secretary

(principal executive officer)

EX-31.2

Exhibit 31.2

RULE 15d-14(a) CERTIFICATION

I, Kulwant Sandher, certify that:

1.           I have reviewed this annual report on Form 10-K of Brinx Resources Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 31, 2013

/s/ Kulwant Sandher                                    

Kulwant Sandher, Chief Financial Officer

 (principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Brinx Resources Ltd. (the “Company”) on Form 10-K for the year ending October 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Leroy Halterman, Principal Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Kenneth A. Cabianca                                                                                                    

Kenneth A. Cabianca

President and Secretary

Principal Executive Officer

Date: January 31, 2013

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Brinx Resources Ltd. (the “Company”) on Form 10-K for the year ending October 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kulwant Sandher, Principal Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Kulwant Sandher                                                                                                   

Kulwant Sandher

Chief Financial Officer

Principal Financial Officer

Date: January 31, 2013

XML

INCOME TAXES (Details) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Current taxes	$ 0	$ 0
Deferred taxes	0	0
Net income tax provision (benefit)	$ 0	$ 0

XML

UNAUDITED OIL AND GAS RESERVE QUANTITIES (Details 3) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Standardized measure of discounted cash flows:
Beginning of year	$ 2,033,659	$ 2,533,242
Sales and transfers of oil and gas produced, net production costs	(367,417)	(1,057,272)
Net changes in prices and production costs and other	(89,162)	228,959
Net sale of reserves in place	(471,660)	(2,200,776)
Changes in future development costs	0	242,276
Revisions of previous estimates	(1,618,488)	(852,521)
Other	263,641	944,503
Net change in income taxes	0	1,840,474
Accretion discount	703,837	354,774
Total change in the standardized measure during the year	(1,579,249)	(499,583)
Standardize measure, end of year	$ 454,410	$ 2,033,659

XML

UNAUDITED OIL AND GAS RESERVE QUANTITIES (Details 1) (Gas) (Natural Gas [Member])	Oct. 31, 2012 Mcf	Oct. 31, 2011 Mcf	Oct. 31, 2010 Mcf
Natural Gas [Member]
Proved Reserves at year end
Developed	12,570	124,501
Undeveloped	1,100	1,200
Total	13,670	125,701	98,847

XML

OIL AND GAS INTERESTS (Details Textual) (USD $)	12 Months Ended																																12 Months Ended		12 Months Ended											12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011	Oct. 31, 2012 Drilling Program Oklahoma One [Member]	Oct. 31, 2011 Drilling Program Oklahoma One [Member]	Jan. 12, 2009 Drilling Program Oklahoma One [Member]	Jan. 31, 2009 Drilling Program Oklahoma One [Member] After Casing Point [Member]	Jan. 31, 2009 Drilling Program Oklahoma One [Member] Before Casing Point [Member]	Oct. 31, 2012 Drilling Program Oklahoma Two [Member]	Oct. 31, 2011 Drilling Program Oklahoma Two [Member]	Jun. 19, 2009 Drilling Program Oklahoma Two [Member]	Jul. 31, 2009 Drilling Program Oklahoma Two [Member] After Casing Point [Member]	Jul. 31, 2009 Drilling Program Oklahoma Two [Member] Before Casing Point [Member]	Oct. 31, 2012 Drilling Program Oklahoma Three [Member]	Oct. 31, 2011 Drilling Program Oklahoma Three [Member]	Aug. 12, 2009 Drilling Program Oklahoma Three [Member]	Oct. 31, 2009 Drilling Program Oklahoma Three [Member] After Casing Point [Member]	Oct. 31, 2009 Drilling Program Oklahoma Three [Member] Before Casing Point [Member]	Oct. 31, 2012 Drilling Program Oklahoma Four [Member]	Oct. 31, 2011 Drilling Program Oklahoma Four [Member]	Dec. 19, 2009 Drilling Program Oklahoma Four [Member]	Jan. 31, 2010 Drilling Program Oklahoma Four [Member] After Casing Point [Member]	Jan. 31, 2010 Drilling Program Oklahoma Four [Member] Before Casing Point [Member]	Oct. 31, 2012 Drilling Program Oklahoma Five [Member]	Oct. 31, 2011 Drilling Program Oklahoma Five [Member]	Apr. 23, 2010 Drilling Program Oklahoma Five [Member]	Apr. 30, 2010 Drilling Program Oklahoma Five [Member] After Casing Point [Member]	Apr. 30, 2010 Drilling Program Oklahoma Five [Member] Before Casing Point [Member]	Oct. 31, 2012 Washita Bend Oklahoma [Member]	Oct. 31, 2011 Washita Bend Oklahoma [Member]	Mar. 01, 2010 Washita Bend Oklahoma [Member]	Apr. 30, 2010 Washita Bend Oklahoma [Member] After Casing Point [Member]	Apr. 30, 2010 Washita Bend Oklahoma [Member] Before Casing Point [Member]	Oct. 31, 2011 Palmetto Point Project Mississippi [Member]	Oct. 31, 2012 Palmetto Point Project Mississippi [Member]	Oct. 31, 2011 Palmetto Point Project Mississippi [Member] Monthly Payment One [Member]	Oct. 31, 2012 Palmetto Point Project Mississippi [Member] Monthly Payment Two [Member]	Oct. 31, 2012 Palmetto Point Project Mississippi [Member] Monthly Payment Three [Member]	Oct. 31, 2012 Palmetto Point Project Mississippi [Member] Monthly Payment Four [Member]	Oct. 31, 2009 Kings City Prospect California [Member]	Oct. 31, 2012 Kings City Prospect California [Member]	Oct. 31, 2011 Kings City Prospect California [Member]	May 25, 2009 Kings City Prospect California [Member]	Oct. 31, 2012 Three Sands Project Oklahoma [Member]	Oct. 31, 2011 Three Sands Project Oklahoma [Member]	Oct. 06, 2005 Three Sands Project Oklahoma [Member]	Oct. 31, 2012 Three Sands Project Oklahoma [Member] Glm Energy Inc [Member]	Oct. 31, 2010 South Wayne Prospect Oklahoma [Member]	Oct. 31, 2012 South Wayne Prospect Oklahoma [Member]	Oct. 31, 2011 South Wayne Prospect Oklahoma [Member]	Mar. 14, 2010 South Wayne Prospect Oklahoma [Member]	Oct. 31, 2010 South Wayne Prospect Oklahoma [Member] After Casing Point [Member]	Oct. 31, 2010 South Wayne Prospect Oklahoma [Member] Before Casing Point [Member]	Oct. 31, 2012 Double T Ranch 1 Swdw, Oklahoma [Member]	Oct. 31, 2011 Double T Ranch 1 Swdw, Oklahoma [Member]
Business Acquisition, Percentage of Voting Interests Acquired					5.00%	5.00%	6.25%			5.00%	5.00%	6.25%			5.00%	5.00%	6.25%			5.00%	5.00%	6.25%			5.00%	5.00%	6.25%			5.00%	5.00%	5.625%										20.00%			40.00%					5.00%	5.00%	6.25%	3.00%
Oil and Gas Property, Full Cost Method, Gross			$ 309,152	$ 302,361				$ 114,420	$ 114,420				$ 337,749	$ 300,080				$ 190,182	$ 190,146				$ 254,817	$ 253,855				$ 537,361	$ 482,882				$ (222,123)	$ (222,123)						$ 404,121	$ 263,561		$ 555,715	$ 1,451,543				$ 61,085	$ 61,085				$ 43,078	$ 0
Description Of Land Allocated For Exploration																																							10,000 acres located in west central California
Percentage Of Costs Incurred To Explore and Develop Oil and Gas Properties																																							50.00%
Costs Incurred To Explore and Develop Oil and Gas Properties																																							200,000
Dry Hole Cost Of Exploration Projects																																															32,370
Dry Hole Cost Of Exploration Projects, Percentage																																							33.33%
Payment For Lease Hold Prospect and Geophysical Fees																																															5,000
Proceeds From Sale Of Oil and Gas Property and Equipment	552,144	200,000																															400,000		200,000	10,000	10,000	200,000
Equity Instrument Consideration Restricted Shares Received (in shares)																																	800,000
Gain (Loss) on Sale of Oil and Gas Property	(96,491)	(109,299)
Payments to Explore and Develop Oil and Gas Properties																																							100,000
Business Acquisition Percentage Of Voting Interests Acquired One																															5.00%	5.00%
Depletion	142,675	341,633
Loss on Sale of Proved Property																																	109,299
Disposed Reserves Percentage																																	25.00%
Impairment Of Proved Properties Discounted Rate	10.00%
Oil and Gas Properties Sale Agreement Amount																																														352,144
Disposed Reserves Oil and Gas Properties Percentage																																														25.00%
Write- Down Of Oil and Gas Property	$ 314,906	$ 0

XML

UNAUDITED OIL AND GAS RESERVE QUANTITIES (Tables)

12 Months Ended

Oct. 31, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule Of Changes In Proved Developed and Undeveloped Reserves Quantities [Table Text Block]

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, 2010		93,239			98,847
Revisions of previous estimate		(9,396	)		24,000
Discoveries		4,698			33,096
Reserves sold to third parties		(37,780	)		(3,580	)
Production		(11,962	)		(26,662	)
Estimated quantity, October 31, 2011		38,799			125,701
Reserves sold to third parties		(2,909	)		(99,737	)
Revisions of previous estimate		(17,260	)		1,723
Discoveries		-			-
Production		(4,300	)		(14,017	)
Estimated quantity, October 31, 2012		14,330			13,670

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

The revisions in the Company’s estimates of proved oil and gas reserves are due to the fact that there was more substantive data, such as a longer history of production, available to its engineers which allowed them to better quantify the reserve estimates.

Proved Reserves at year end	Developed	Undeveloped	Total
Crude Oil (Bbls)
October 31, 2012	12,880	1,450	14,330
October 31, 2011	36,969	1,830	38,799
Gas (MCF)
October 31, 2012	12,570	1,100	13,670
October 31, 2011	124,501	1,200	125,701

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

Discounting the future net cash inflows at 10% is a method to measure the impact of the time value of money.  Certain balances from 2011 have been updated based on revised calculations.

	October 31,  2012			October 31, 2011
Future Cash inflows	$	1,396,960		$	4,192,510
Future production costs		(521,440	)		(1,033,904	)
Future development costs		(61,250	)		(61,250	)
Future income tax expense		-			-
Future cash flows		814,270			3,097,356
10% annual discount for estimated timing of cash flows		(359,860	)		(1,063,697	)
Standardized measure of discounted future net cash	$	454,410		$	2,033,659

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

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, 2012			October 31, 2011
Beginning of year	$	2,033,659		$	2,533,242
Sales and transfers of oil and gas produced, net production costs		(367,417	)		(1,057,272	)
Net changes in prices and production costs and other		(89,162	)		228,959
Net sale of reserves in place		(471,660	)		(2,200,776	)
Changes in future development costs		-			242,276
Revisions of previous estimates		(1,618,488	)		(852,521	)

Other		263,641			944,503
Net change in income taxes		-			1,840,474
Accretion discount		703,837			354,774
Total change in the standardized measure during the year		(1,579,249	)		(499,583	)
Standardize measure, end of year	$	454,410		$	2,033,659

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CONTINGENCIES (Details Textual) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Oil and Gas Revenue	$ 469,107	$ 1,241,015
Drilling Program Oklahoma Three [Member]
Percentage of Pending Outcome of Legal Proceedings (in percentage)	50.00%
Oil and Gas Revenue	51,276
Oil and Gas Revenue Unrecognized	$ 170,571	$ 119,295
Drilling Program Oklahoma Three [Member] | Before Casing Point Interest Percentage [Member]
Cost Method Investment Ownership Percentage (in percentage)	6.25%
Drilling Program Oklahoma Three [Member] | After Casing Point Interest Percentage [Member]
Cost Method Investment Ownership Percentage (in percentage)	5.00%

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INCOME TAXES (Details Textual) (USD $)	12 Months Ended
	Oct. 31, 2012
Operating Loss Carryforwards	$ 3,043,724
Operating Loss Carryforwards, Expiration Dates	31-Oct-2029

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COMMON STOCK (Details Textual) (USD $)						12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011	Oct. 31, 2012 Series A Preferred Stock [Member]	Feb. 10, 2012 Series A Preferred Stock [Member]	Oct. 31, 2011 Series A Preferred Stock [Member]	Oct. 31, 2012 Common Stock [Member] Maximum [Member]
Preferred Stock, Shares Authorized (in shares)	25,000,000	25,000,000	1,000,000		1,000,000
Preferred Stock, Shares Issued (in shares)			500,001	500,001	0
Preferred Stock, Par Or Stated Value Per Share (in dollars per share)	$ 0.001	$ 0.001	$ 0.001		$ 0.001
Preferred Stock, Dividend Rate, Percentage						10.00%
Related Party Transaction Maximum Amounts Of Transaction			$ 100,000

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UNAUDITED OIL AND GAS RESERVE QUANTITIES (Details 2) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Future Cash inflows	$ 1,396,960	$ 4,192,510
Future production costs	(521,440)	(1,033,904)
Future development costs	(61,250)	(61,250)
Future income tax expense	0	0
Future cash flows	814,270	3,097,356
10% annual discount for estimated timing of cash flows	(359,860)	(1,063,697)
Standardized measure of discounted future net cash	$ 454,410	$ 2,033,659

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ACCOUNTS RECEIVABLE

12 Months Ended

Oct. 31, 2012

Receivables [Abstract]

Loans, Notes, Trade and Other Receivables Disclosure [Text Block]

3.         ACCOUNTS RECEIVABLE

Accounts receivable consists of revenues receivable, interest receivable and other receivable.  The revenue receivable are from the operators of the oil and gas projects for the sale of oil and gas by the operators on the Company’s 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, 2012 and October 31, 2011.  Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.

	October 31, 2012		October 31,    2011
Accounts receivable	$	38,485	$	329,748
Less: allowance for doubtful account		-		-
	$	38,485	$	329,748

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UNAUDITED OIL AND GAS RESERVE QUANTITIES (Details) (Oil) (Oil [Member])	12 Months Ended
	Oct. 31, 2012 bbl	Oct. 31, 2011 bbl
Oil [Member]
Changes in proved reserves
Estimated quantity, at begining of the period	38,799	93,239
Revisions of previous estimate	(17,260)	(9,396)
Discoveries	0	4,698
Reserves sold to third parties	(2,909)	(37,780)
Production	(4,300)	(11,962)
Estimated quantity, at end of the period	14,330	38,799

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ACCOUNTS RECEIVABLE (Details) (USD $)	Oct. 31, 2012	Oct. 31, 2011
Accounts receivable	$ 38,485	$ 329,748
Less: allowance for doubtful account	0	0
Accounts Receivable, Net, Current	$ 38,485	$ 329,748

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MARKETABLE SECURITIES (Details Textual) (USD $)	1 Months Ended	12 Months Ended
	Aug. 31, 2011	Oct. 31, 2012	Oct. 31, 2011
Marketable Securities Number Of Shares (in shares)	800,000
Marketable Securities (in dollars per share)	$ 0.34	$ 0.12	$ 0.26
Marketable Securities, Unrealized Gain (Loss)		$ (112,000)	$ (64,000)

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UNAUDITED OIL AND GAS RESERVE QUANTITIES (Details) (Gas) (Natural Gas [Member])	12 Months Ended
	Oct. 31, 2012 Mcf	Oct. 31, 2011 Mcf
Natural Gas [Member]
Changes in proved reserves
Estimated quantity, at begining of the period	125,701	98,847
Revisions of previous estimate	1,723	24,000
Discoveries	0	33,096
Reserves sold to third parties	(99,737)	(3,580)
Production	(14,017)	(26,662)
Estimated quantity, at end of the period	13,670	125,701

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OIL AND GAS INTERESTS (Details) (USD $)	Oct. 31, 2012	Oct. 31, 2011
Asset retirement cost	$ 2,593	$ 4,534
Less: Accumulated depletion and impairment	(1,137,820)	(1,127,444)
Oil and Gas Property, Full Cost Method, Net	1,450,330	2,074,900
2008-3 Drilling Program, Oklahoma [Member]
Oil and Gas Property, Full Cost Method, Gross	309,152	302,361
2009-2 Drilling Program, Oklahoma [Member]
Oil and Gas Property, Full Cost Method, Gross	114,420	114,420
2009-3 Drilling Program, Oklahoma [Member]
Oil and Gas Property, Full Cost Method, Gross	337,749	300,080
2009-4 Drilling Program, Oklahoma [Member]
Oil and Gas Property, Full Cost Method, Gross	190,182	190,146
2010-1 Drilling Program, Oklahoma [Member]
Oil and Gas Property, Full Cost Method, Gross	254,817	253,855
Washita Bend 3D, Oklahoma [Member]
Oil and Gas Property, Full Cost Method, Gross	537,361	482,882
Double T Ranch 1 Swdw, Oklahoma [Member]
Oil and Gas Property, Full Cost Method, Gross	43,078	0
Kings City Prospect California [Member]
Oil and Gas Property, Full Cost Method, Gross	404,121	263,561
South Wayne Prospect, Oklahoma [Member]
Oil and Gas Property, Full Cost Method, Gross	61,085	61,085
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi [Member]
Oil and Gas Property, Full Cost Method, Gross	(222,123)	(222,123)
Three Sands Project, Oklahoma [Member]
Oil and Gas Property, Full Cost Method, Gross	$ 555,715	$ 1,451,543

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OIL AND GAS INTERESTS (Details 1) (USD $)	Oct. 31, 2012	Oct. 31, 2011
Proved properties	$ 1,603,590	$ 2,395,902
Unproved properties	984,560	806,443
Total Proved and Unproved properties	2,588,150	3,202,345
Accumulated depletion expense	(734,698)	(989,713)
Impairment	(403,122)	(137,732)
Net capitalized cost	$ 1,450,330	$ 2,074,900

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MARKETABLE SECURITIES

12 Months Ended

Oct. 31, 2012

Marketable Securities [Abstract]

Marketable Securities [Text Block]

2. MARKETABLE SECURITIES

In August 2011, 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, 2012 was $0.12 per share, as compared to $0.26 per share as at October 31, 2011, giving rise to an unrealized loss of $112,000 for the year ended October 31, 2012 (2011 – unrealized loss of $64,000).  The Company evaluated the prospects of Lexaria in relation to the severity and duration of the impairment. Based on that evaluation and the Company’s ability and intent to hold the shares for a reasonable period of time sufficient for a recovery, the Company does not consider the shares to be other-than-temporarily impaired at October 31, 2012.

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OIL AND GAS INTERESTS (Details 2) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Revenues	$ 469,107	$ 1,241,015
Production costs	(101,690)	(183,743)
Depletion and accretion	(145,835)	(344,932)
Results of operations (excluding corporate overhead)	$ 221,582	$ 712,340

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INCOME TAXES (Details 1)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Federal statutory income tax rate	35.00%	35.00%
Net effective income tax (benefit) rate	35.00%	35.00%

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BALANCE SHEETS (USD $)	Oct. 31, 2012	Oct. 31, 2011
ASSETS
Cash and cash equivalents	$ 540,512	$ 401,047
Investment - Certificate of deposit	400,000	400,000
Marketable securities	96,000	208,000
Accounts receivable	38,485	329,748
Prepaid expenses and deposit	44,594	37,254
Total current assets	1,119,591	1,376,049
Undeveloped mineral interests, at cost	3,101	1,981
Oil and gas interests, full cost method of accounting, net of accumulated depletion	1,450,330	2,074,900
Total assets	2,573,022	3,452,930
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued liabilities	6,332	10,971
Total current liabilities	6,332	10,971
Asset retirement obligations	27,554	26,335
Total liabilities	33,886	37,306
Stockholders' equity
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	(176,000)	(64,000)
Retained earnings	(178,051)	586,937
Total stockholders' equity	2,539,136	3,415,624
Total liabilities and stockholders' equity	2,573,022	3,452,930
Series A Preferred Stock [Member]
Stockholders' equity
Preferred stock - $0.001 par value; authorized - 25,000,000 shares Series A Preferred stock - $0.001 par value; authorized - 1,000,000. Issued and outstanding - 500,001 shares	$ 500	$ 0

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UNAUDITED OIL AND GAS RESERVE QUANTITIES (Details 1) (Oil) (Oil [Member])	Oct. 31, 2012 bbl	Oct. 31, 2011 bbl	Oct. 31, 2010 bbl
Oil [Member]
Proved Reserves at year end
Developed	12,880	36,969
Undeveloped	1,450	1,830
Total	14,330	38,799	93,239

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STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES
Net (loss)	$ (764,988)	$ (131,443)
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and accretion	145,835	344,932
Loss on sale of natural gas and oil properties	96,491	109,299
Writedown of natural gas and oil properties	314,906	0
Changes in working capital:
Decrease in accounts receivable	91,763	19,176
Decrease / (Increase) in prepaid expenses and deposit	(7,340)	90,801
(Decrease) in accounts payable and accrued liabilities	(4,639)	(26,806)
Net cash provided by /(used in) operating activities	(127,972)	405,959
CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES
Redemption of Certificate of deposit	0	400,000
Sale proceeds of natural gas and oil working interests	552,144	200,000
Payments on mineral interest	(1,120)	(1,170)
Payments on oil and gas interests	(283,587)	(624,771)
Net cash provided by /(used in) investing activities	267,437	(25,941)
CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES
Net cash provided by /(used in) financing activities	0	0
Net increase in cash	139,465	380,018
Cash and cash equivalents, beginning of years	401,047	21,029
Cash and cash equivalents, end of years	540,512	401,047
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for taxes	0	2,428
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Assets retirement costs incurred	(3,160)	(3,299)
Investment in natural oil and gas working interests included in accounts payable	0	0
Issuance of preferred shares to a director	$ 500	$ 0

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ASSET RETIREMENT OBLIGATIONS (Details Textual)	12 Months Ended
	Oct. 31, 2012
Liability, Weighted Average Risk Free Discount Rate	12.00%

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ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Oct. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The information below reflects the change in the asset retirement obligations during the years ended October 31, 2012 and 2011:

	October 31, 2012			October 31, 2011
Balance, beginning of years	$	26,335		$	27,494
Liabilities assumed		-			774
Revisions		(1,941	)		(5,232	)
Accretion expense		3,160			3,299
Balance, end of years	$	27,554		$	26,335

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COMMON STOCK (Details) (USD $)	12 Months Ended
	Oct. 31, 2012
Options Outstanding Number of Shares, Balance at October 31, 2011	300,000
Options Outstanding Number of Shares, Expired on November 2, 2011	(300,000)
Options Outstanding Number of Shares, Balance at October31, 2012	0
Options Outstanding Weighted Average Exercise Price, Balance at October 31, 2011 (in dollars per share)	$ 0.10
Options Outstanding Weighted Average Exercise Price, Expired on November 2, 2011 (in dollars per share)	$ 0.10
Options Outstanding Weighted Average Exercise Price, Balance at October 31, 2012 (in dollars per share)	$ 0

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INCOME TAXES (Tables)

12 Months Ended

Oct. 31, 2012

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Income tax expense (benefit) for the years ended October 31, 2012 and 2011, respectively, consists of the following:

	October 31		October 31
		2012		2011
Current taxes	$	-		-
Deferred taxes		-		-
Net income tax provision (benefit)	$	-	$	-

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The effective income tax rate for years ended October 31, 2012 and 2011, respectively, are:

	October 31		October 31
		2012		2011
Federal statutory income tax rate		35.00%		35.00%
Net effective income tax (benefit) rate		35.00%		35.00%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

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

	October 31			October 31
	2012			2011
Deferred tax assets & liabilities:
Federal and state net operating loss carryovers	$	1,065,303		$	174,204
Asset retirement liability		9,644			9,217
Stock options granted		-			8,897
Book depletion in excess of tax depreciation		(589,608	)		138,422
Deferred tax asset	$	485,339		$	330,740
Valuation Allowance		(485,339	)		(330,740	)
Deferred tax liability	$	-		$	-

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ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Oct. 31, 2012

Organization, Consolidation and Presentation Of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]

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 in New Mexico and oil and gas interests 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 value 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.  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, 2012 and 2011, the Company had no overproduced imbalances.

ACCOUNTS RECEIVABLE

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

IMPAIRMENT OF LONG-LIVED ASSETS

The Company has adopted FASB ASC 360 “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 year.  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 was nil as of October 31, 2012 and 300,000 as of October 31, 2011.  As the Company is reporting net losses in both years, 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, 2012 and 2011:

	October 31, 2012			October 31, 2011
Basic earnings per share computation:
(Loss) from continuing operations	$	(764,988	)	$	(131,443	)
Basic shares outstanding		24,629,832			24,629,832
Basic earnings per share	$	(0.03	)	$	(0.01	)

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, if any, are presented as a component of “Other assets” and “Other liabilities and accrued expenses,” respectively, in the balance sheet.  Tax provisions are computed in accordance with FASB ASC 740, “Accounting for Income Taxes.”

The Company applies 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 de-recognition, 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 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.

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.”

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 had no effect on the calculation of net income, comprehensive income or earnings per share.

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BALANCE SHEETS [Parenthetical] (USD $)	Oct. 31, 2012	Oct. 31, 2011
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	25,000,000	25,000,000
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	24,629,832	24,629,832
Common stock, shares outstanding	24,629,832	24,629,832
Series A Preferred Stock [Member]
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, shares issued	500,001	0
Preferred stock, shares outstanding	500,001	0

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CONTINGENCIES

12 Months Ended

Oct. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

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. The Company recognized $51,276 in revenue during year ended October 31, 2012 and $119,295 in revenue during the year ended October 31, 2011 from the Joe Murray Farms well and a total of $170,571 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

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DOCUMENT AND ENTITY INFORMATION (USD $)	12 Months Ended
	Oct. 31, 2012	Jan. 25, 2013	Apr. 30, 2012
Entity Registrant Name	BRINX RESOURCES LTD
Entity Central Index Key	0001212641
Current Fiscal Year End Date	--10-31
Entity Filer Category	Smaller Reporting Company
Trading Symbol	bnxr
Entity Common Stock, Shares Outstanding		24,629,832
Document Type	10-K
Amendment Flag	false
Document Period End Date	Oct. 31, 2012
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2012
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	Yes
Entity Public Float			$ 1,396,511

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ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Oct. 31, 2012

Organization, Consolidation and Presentation Of Financial Statements [Abstract]

Use of Estimates, Policy [Policy Text Block]

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 value of proved reserves and increase annual depletion expense (which is based on proved reserves).

Oil and Gas Interests Policy [Policy Text Block]

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.  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, Policy [Policy Text Block]

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, 2012 and 2011, the Company had no overproduced imbalances.

Trade and Other Accounts Receivable, Policy [Policy Text Block]

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 or Disposal of Long-Lived Assets, Policy [Policy Text Block]

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, Policy [Policy Text Block]

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.

Earnings Per Share, Policy [Policy Text Block]

INCOME / (LOSS) PER SHARE

Basic income/(loss) per share is computed based on the weighted average number of common shares outstanding during each year.  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 was nil as of October 31, 2012 and 300,000 as of October 31, 2011.  As the Company is reporting net losses in both years, 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, 2012 and 2011:

	October 31, 2012			October 31, 2011
Basic earnings per share computation:
(Loss) from continuing operations	$	(764,988	)	$	(131,443	)
Basic shares outstanding		24,629,832			24,629,832
Basic earnings per share	$	(0.03	)	$	(0.01	)

Income Tax, Policy [Policy Text Block]

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, if any, are presented as a component of “Other assets” and “Other liabilities and accrued expenses,” respectively, in the balance sheet.  Tax provisions are computed in accordance with FASB ASC 740, “Accounting for Income Taxes.”

The Company applies 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 de-recognition, classification, interim period accounting and accounting for interest and penalties.

Cash and Cash Equivalents, Policy [Policy Text Block]

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.

Investment, Policy [Policy Text Block]

MARKETABLE SECURITIES AND INVESTMENTS

All equity investments are classified as available for sale and any subsequent changes in the fair value are recorded in 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 of Financial Instruments, Policy [Policy Text Block]

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.

Concentration Risk, Credit Risk, Policy [Policy Text Block]

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.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

EQUITY BASED COMPENSATION

The Company adopted the fair value recognition provisions of FASB ASC 718 “Share Based Payment.”

New Accounting Pronouncements, Policy [Policy Text Block]

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 had no effect on the calculation of net income, comprehensive income or earnings per share.

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STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
REVENUES
Natural gas and oil sales	$ 469,107	$ 1,241,015
DIRECT COSTS
Production costs	101,690	183,743
Depletion and accretion	145,835	344,932
General and administrative	595,386	735,384
Loss on sale of natural gas and oil properties	96,491	109,299
Writedown of natural gas and oil properties	314,906	0
Total Expenses	(1,254,308)	(1,373,358)
OPERATING INCOME/(LOSS)	(785,201)	(132,343)
OTHER INCOME
Interest income	213	900
Other Income	20,000	0
NET INCOME/(LOSS)	(764,988)	(131,443)
OTHER COMPREHENSIVE INCOME/(LOSS), NET OF TAX
Unrealized (loss) on held for sale marketable security	(112,000)	(64,000)
COMPREHENSIVE INCOME/(LOSS) FOR THE YEARS	$ (876,988)	$ (195,443)
Net Income/(Loss) Per Common Share
- Basic (in dollars per share)	$ (0.03)	$ (0.01)
- Diluted (in dollars per share)	$ (0.03)	$ (0.01)
Weighted average number of common shares outstanding
- Basic (in shares)	24,629,832	24,629,832
- Diluted (in shares)	24,629,832	24,629,832

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COMMON STOCK

12 Months Ended

Oct. 31, 2012

Stockholders' Equity Note [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

6. COMMON STOCK

PREFERRED STOCK

The Company has authorized 25,000,000 shares of preferred stock.  On February 10, 2012, the Company issued 500,001 Series A preferred stock at par value.  The rights attached to these Series A preferred stock include:

·       The holders of the Series A preferred stock can redeem their stock at a predetermined redemption price.

·       The holders of the Series A Preferred Stock shall be entitled to elect one director of the Company in connection with each annual election of directors who shall be the designated “Series A Director”.    With respect to any other matter submitted for a vote (or a written consent in lieu thereof) by the stockholders of the Company (except as to which the Series A Preferred Stock will be entitled to vote separately as a class), the holders of Series A Preferred Stock and the holders of the common stock, $0.001 par value of the Company (“Common Stock”) shall vote together as a single class and not as separate series.

·       The Company shall not without first obtaining the approval (by vote or written consent, as provided by law) of the holders of a majority of the Series A Preferred Stock do any of the following:

(a)          amend, alter, or repeal 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 Preferred Stock;

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

(c)           authorize or issue, or obligate itself 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 authorize any increase in the authorized or designated number of any such security;

(d)           purchase or otherwise acquire any share or shares of Preferred Stock or Common Stock (or pay 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)           authorize the voluntary or involuntary dissolution, liquidation or winding-up of the Company;

(f)           pay 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 aggregate net profits for the fiscal year of the Company in which such dividend is declared and the immediately preceding fiscal year;

(g)           cause the Company to enter into or engage, directly or indirectly, in any material respect any line of business other than the 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; or

(h)           enter into any transaction with any officer, director or stockholder of the Company or any "affiliate" or "associate" (as such terms are defined in the regulations promulgated by the Securities and Exchange Commission under the Securities Exchange Act of 1940) of any such person or entity, other than normal employment arrangements and benefit programs on reasonable terms and other than any transaction (or series of related transactions) involving not more than $100,000 in the aggregate that has been approved by a majority of the Board of Directors (excluding any director who is interested in such transaction, either directly or through one of his affiliates or associates) after full disclosure of the terms thereof to the Board of Directors and after the determination by such majority of the Board of Directors

                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.  A summary of the changes in stock options for the year ended October 31, 2012 is presented below:

	Options Outstanding
				Weighted Average
	Number of Shares			Exercise Price
Balance, October 31, 2011		300,000		$	0.10
Expired on November 2, 2011		(300,000	)		0.10
Balance, October 31, 2012		-		$	-

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Oct. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

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, 2012 and 2011, the Company recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with “Accounting for Asset Retirement Obligations”.  The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production.  The Company amortizes the amount added to the oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining life of the respective well.  The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements.  The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.  Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.

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

The information below reflects the change in the asset retirement obligations during the years ended October 31, 2012 and 2011:

	October 31, 2012			October 31, 2011
Balance, beginning of years	$	26,335		$	27,494
Liabilities assumed		-			774
Revisions		(1,941	)		(5,232	)
Accretion expense		3,160			3,299
Balance, end of years	$	27,554		$	26,335

The reclamation obligation relates to the Bagwell#1-20, Bagwell#2-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24 and Miss Jenny#1-8 wells at Oklahoma Properties, and 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.

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COMMON STOCK (Tables)

12 Months Ended

Oct. 31, 2012

Stockholders' Equity Note [Abstract]

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

A summary of the changes in stock options for the year ended October 31, 2012 is presented below:

	Options Outstanding
				Weighted Average
	Number of Shares			Exercise Price
Balance, October 31, 2011		300,000		$	0.10
Expired on November 2, 2011		(300,000	)		0.10
Balance, October 31, 2012		-		$	-

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ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Oct. 31, 2012

Organization, Consolidation and Presentation Of Financial Statements [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

The table below presents the computation of basic and diluted earnings per share for the years ended October 31, 2012 and 2011:

	October 31, 2012			October 31, 2011
Basic earnings per share computation:
(Loss) from continuing operations	$	(764,988	)	$	(131,443	)
Basic shares outstanding		24,629,832			24,629,832
Basic earnings per share	$	(0.03	)	$	(0.01	)

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UNAUDITED OIL AND GAS RESERVE QUANTITIES

12 Months Ended

Oct. 31, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

9.           UNAUDITED OIL AND GAS RESERVE QUANTITIES

The following unaudited reserve estimates presented as of October 31, 2012 and 2011 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, 2010		93,239			98,847
Revisions of previous estimate		(9,396	)		24,000
Discoveries		4,698			33,096
Reserves sold to third parties		(37,780	)		(3,580	)
Production		(11,962	)		(26,662	)
Estimated quantity, October 31, 2011		38,799			125,701
Reserves sold to third parties		(2,909	)		(99,737	)
Revisions of previous estimate		(17,260	)		1,723
Discoveries		-			-
Production		(4,300	)		(14,017	)
Estimated quantity, October 31, 2012		14,330			13,670

The revisions in the Company’s estimates of proved oil and gas reserves are due to the fact that there was more substantive data, such as a longer history of production, available to its engineers which allowed them to better quantify the reserve estimates.

Proved Reserves at year end	Developed	Undeveloped	Total
Crude Oil (Bbls)
October 31, 2012	12,880	1,450	14,330
October 31, 2011	36,969	1,830	38,799
Gas (MCF)
October 31, 2012	12,570	1,100	13,670
October 31, 2011	124,501	1,200	125,701

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 year-end 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.  Certain balances from 2011 have been updated based on revised calculations.

	October 31,  2012			October 31, 2011
Future Cash inflows	$	1,396,960		$	4,192,510
Future production costs		(521,440	)		(1,033,904	)
Future development costs		(61,250	)		(61,250	)
Future income tax expense		-			-
Future cash flows		814,270			3,097,356
10% annual discount for estimated timing of cash flows		(359,860	)		(1,063,697	)
Standardized measure of discounted future net cash	$	454,410		$	2,033,659

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, 2012			October 31, 2011
Beginning of year	$	2,033,659		$	2,533,242
Sales and transfers of oil and gas produced, net production costs		(367,417	)		(1,057,272	)
Net changes in prices and production costs and other		(89,162	)		228,959
Net sale of reserves in place		(471,660	)		(2,200,776	)
Changes in future development costs		-			242,276
Revisions of previous estimates		(1,618,488	)		(852,521	)

Other		263,641			944,503
Net change in income taxes		-			1,840,474
Accretion discount		703,837			354,774
Total change in the standardized measure during the year		(1,579,249	)		(499,583	)
Standardize measure, end of year	$	454,410		$	2,033,659

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RELATED PARTY TRANSACTIONS

12 Months Ended

Oct. 31, 2012

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

7.         RELATED PARTY TRANSACTIONS

During the years ended October 31, 2012 and 2011, the Company entered into the following transactions with related parties:

a)     The Company paid $30,000 (2011 - $72,000) in management fees and reimbursement of office space of $nil (2011 - $4,400) to the former President of the Company.

b)     The Company paid $74,000 (2011 - $71,000) to a related entity, for administration services.

c)     The Company paid $122,000 (2011 - $101,000) in management fees to the director and current President of the Company.

d)     The Company paid $78,597 (2011 - $76,813) in consulting and accounting fees to the Chief Financial Officer of the Company.

e)     The Company paid $1,000 (2011 - $ nil) in consulting fee to the director of the Company.

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INCOME TAXES

12 Months Ended

Oct. 31, 2012

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

8. INCOME TAXES

Income tax expense (benefit) for the years ended October 31, 2012 and 2011, respectively, consists of the following:

	October 31		October 31
		2012		2011
Current taxes	$	-		-
Deferred taxes		-		-
Net income tax provision (benefit)	$	-	$	-

The effective income tax rate for years ended October 31, 2012 and 2011, respectively, are:

	October 31		October 31
		2012		2011
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 that give rise to significant portions of the deferred tax assets and deferred tax liabilities are provided below:

	October 31			October 31
	2012			2011
Deferred tax assets & liabilities:
Federal and state net operating loss carryovers	$	1,065,303		$	174,204
Asset retirement liability		9,644			9,217
Stock options granted		-			8,897
Book depletion in excess of tax depreciation		(589,608	)		138,422
Deferred tax asset	$	485,339		$	330,740
Valuation Allowance		(485,339	)		(330,740	)
Deferred tax liability	$	-		$	-

The Company has $3,043,724 of net operating loss carry forwards as of October 31, 2012 which will begin to expire on October 31, 2029.

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 statements of comprehensive income in the provision for income taxes.  As of October 31, 2012 and 2011, the Company had not incurred interest or penalties related to uncertain tax positions.

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MAJOR CUSTOMERS

12 Months Ended

Oct. 31, 2012

Major Customers [Abstract]

Major Customers [Text Block]

10.       MAJOR CUSTOMERS

We collected $382,540 (2011: $798,912) or 81% (2011: 64%) of our revenues from one of our operators during the year ended October 31, 2012. As of October 31, 2012, $34,095 (2011: $90,602) was due from this operator.

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ASSET RETIREMENT OBLIGATIONS (Details) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Balance, beginning of years	$ 26,335	$ 27,494
Liabilities assumed	0	774
Revisions	(1,941)	(5,232)
Accretion expense	3,160	3,299
Balance, end of years	$ 27,554	$ 26,335

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OIL AND GAS INTERESTS (Tables)

12 Months Ended

Oct. 31, 2012

Oil and Gas Interests Abstract [Abstract]

Schedule of Exploratory Wells Drilled [Table Text Block]

The Company holds the following oil and natural gas interests:

	October 31, 2012			October 31, 2011
2008-3 Drilling Program, Oklahoma	$	309,152		$	302,361
2009-2 Drilling Program, Oklahoma		114,420			114,420
2009-3 Drilling Program, Oklahoma		337,749			300,080
2009-4 Drilling Program, Oklahoma		190,182			190,146
2010-1 Drilling Program, Oklahoma		254,817			253,855
Washita Bend 3D, Oklahoma		537,361			482,882
Double T Ranch #1 SWDW, Oklahoma		43,078			--
Kings City Prospect, California		404,121			263,561
South Wayne Prospect, Oklahoma		61,085			61,085
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi		(222,123	)		(222,123	)
Three Sands Project, Oklahoma		555,715			1.451,453
Asset retirement cost		2,593			4,534
Less:  Accumulated depletion and impairment		(1,137,820	)		(1,127,444	)
	$	1,450,330		$	2,074,900

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

Capitalized Costs

	October 31, 2012			October 31, 2011
Proved properties	$	1,603,590		$	2,395,902
Unproved properties		984,560			806,443
Total Proved and Unproved properties		2,588,150			3,202,345
Accumulated depletion expense		(734,698	)		(989,713	)
Impairment		(403,122	)		(137,732	)
Net capitalized cost	$	1,450,330		$	2,074,900

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

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

	October 31, 2012			October 31, 2011
Revenues	$	469,107		$	1,241,015
Production costs		(101,690	)		(183,743	)
Depletion and accretion		(145,835	)		(344,932	)
Results of operations (excluding corporate overhead)	$	221,582		$	712,340

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ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Basic earnings per share computation:
(Loss) from continuing operations	$ (764,988)	$ (131,443)
Basic shares outstanding (in shares)	24,629,832	24,629,832
Basic earnings per share (in dollars per share)	$ (0.03)	$ (0.01)

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MAJOR CUSTOMERS (Details Textual) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Entity-Wide Revenue, Major Customer, Amount	$ 382,540	$ 798,912
Entity-Wide Revenue, Major Customer, Percentage	81.00%	64.00%
Due From Major Customer, Amount	$ 34,095	$ 90,602

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INCOME TAXES (Details 2) (USD $)	Oct. 31, 2012	Oct. 31, 2011
Deferred tax assets & liabilities:
Federal and state net operating loss carryovers	$ 1,065,303	$ 174,204
Asset retirement liability	9,644	9,217
Stock options granted	0	8,897
Book depletion in excess of tax depreciation	(589,608)	138,422
Deferred tax asset	485,339	330,740
Valuation Allowance	(485,339)	(330,740)
Deferred tax liability	$ 0	$ 0

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STATEMENT OF STOCKHOLDERS' EQUITY (USD $)	Preferred Stock [Member]	Common Stock [Member]	Capital In Excess Of Par Value [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total
BALANCES at Oct. 31, 2010	$ 0	$ 24,630	$ 2,868,057	$ 718,380	$ 0	$ 3,611,067
BALANCES (In shares) at Oct. 31, 2010	0	24,629,832
Comprehensive income / (loss)
Unrealized (loss) on held for sale marketable security	0	0	0	0	(64,000)	(64,000)
Net (loss)	0	0	0	(131,443)	0	(131,443)
Comprehensive (loss)						(195,443)
BALANCES at Oct. 31, 2011	0	24,630	2,868,057	586,937	(64,000)	3,415,624
BALANCES (In shares) at Oct. 31, 2011	0	24,629,832
Comprehensive income / (loss)
Shares issued to a director	500	0	0	0	0	500
Shares issued to a director (In shares)	500,001	0
Unrealized (loss) on held for sale marketable security	0	0	0	0	(112,000)	(112,000)
Net (loss)	0	0	0	(764,988)	0	(764,988)
Comprehensive (loss)						(876,988)
BALANCES at Oct. 31, 2012	$ 500	$ 24,630	$ 2,868,057	$ (178,051)	$ (176,000)	$ 2,539,136
BALANCES (In shares) at Oct. 31, 2012	500,001	24,629,832

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OIL AND GAS INTERESTS

12 Months Ended

Oct. 31, 2012

Oil and Gas Interests [Abstract]

Oil and Gas Interests [Text Block]

4.   OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:

	October 31, 2012			October 31, 2011
2008-3 Drilling Program, Oklahoma	$	309,152		$	302,361
2009-2 Drilling Program, Oklahoma		114,420			114,420
2009-3 Drilling Program, Oklahoma		337,749			300,080
2009-4 Drilling Program, Oklahoma		190,182			190,146
2010-1 Drilling Program, Oklahoma		254,817			253,855
Washita Bend 3D, Oklahoma		537,361			482,882
Double T Ranch #1 SWDW, Oklahoma		43,078			--
Kings City Prospect, California		404,121			263,561
South Wayne Prospect, Oklahoma		61,085			61,085
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi		(222,123	)		(222,123	)
Three Sands Project, Oklahoma		555,715			1.451,453
Asset retirement cost		2,593			4,534
Less:  Accumulated depletion and impairment		(1,137,820	)		(1,127,444	)
	$	1,450,330		$	2,074,900

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.  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”) is 6.25% and the After Casing Point Interest (“ACP”) is 5.00%.  At October 31, 2012, the total cost of the 2008-3 Drilling Program was $309,152.  The interests are located in Garvin County, Oklahoma.

2009-2 Drilling Program, Oklahoma

On June 19, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2009-2 Drilling Program.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At October 31, 2012, 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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At October 31, 2012, the total cost of the 2009-3 Drilling Program was $337,749.  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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At October 31, 2012, the total cost of the 2009-4 Drilling Program was $190,182.  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.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At October 31, 2012, the total cost of the 2010-1 Drilling Program was $254,817.  The interests are located in Garvin County, Oklahoma.

Washita Bend 3D Exploration Project, Oklahoma

On March 1, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s Washita Bend 3D Exploration Project.  The BCP Interest is 5.625% and the ACP Interest is 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  At October 31, 2012, the total costs, including seismic costs, was $537,361.

Double T Ranch#1 SWDW, Oklahoma

On July 17, 2012, the Company acquired a 3.00% working interest in the drilling, completion and operations of the Double T Ranch#1 SWDW located in Garvin County from Ranken Energy Corporation. At October 31, 2012, the cost of the Double T Ranch#1 SWDW was $43,078.

Kings City Prospect, California

A Farmout agreement was made effective on May 25, 2009 between the Company and Sunset Exploration, Inc., to explore for oil and natural gas on 10,000 acres located in west central California.  The Company paid $100,000 (50% pro rata share of $200,000)  to earn a 20% working interest in project by funding a maximum of 50% of a $200,000 in a geophysical survey composed of gravity and seismic surveys and 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, 2012 was $404,121.

Three Sands Project, Oklahoma

On October 6, 2005, the Company acquired a 40% working interest in Vector Exploration Inc.’s Three Sands Project.

On September 10, 2012, the Company signed the asset purchase agreement with GLM Energy Inc., to sell the oil and gas assets effective June 1, 2012 for a total of $352,144.  The disposed reserves represented more than 25% of the total reserves which the Company considered to represent a significant alteration between capitalized costs and proved reserves and hence a loss on the sale was recognized in the Statements of Comprehensive Income in the amount of $96,491 for the year ended October 31, 2012.

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 is 6.25% and the ACP Interest is 5.00%.  The interests are located in McClain County, Oklahoma.  The total cost of the South Wayne prospect as at October 31, 2012 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 received 800,000 shares of restricted common stock in Lexaria Corp.  These properties consist principally of the Belmont Lake Oil Field and all undeveloped acreage in the Palmetto Point Project.  $200,000 was received on August 12, 2011.  $10,000 per month was paid in November and December 2011 and the balance of $200,000 was paid on January 13, 2012. The disposed reserves represented more than 25% of the total reserves which the Company 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 for the period ended October 31, 2011.

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 $314,906 and $0 in impairment cost for the years ended October 31, 2012 and 2011, respectively.

Depletion

Under the full cost method, depletion is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production.  Depletion expense recognized was $142,675 and $341,633 for the year ended October 31, 2012 and 2011, respectively.

Capitalized Costs

	October 31, 2012			October 31, 2011
Proved properties	$	1,603,590		$	2,395,902
Unproved properties		984,560			806,443
Total Proved and Unproved properties		2,588,150			3,202,345
Accumulated depletion expense		(734,698	)		(989,713	)
Impairment		(403,122	)		(137,732	)
Net capitalized cost	$	1,450,330		$	2,074,900

Results of Operations

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

	October 31, 2012			October 31, 2011
Revenues	$	469,107		$	1,241,015
Production costs		(101,690	)		(183,743	)
Depletion and accretion		(145,835	)		(344,932	)
Results of operations (excluding corporate overhead)	$	221,582		$	712,340

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ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details Textual)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Capitalized Costs, Oil and Gas Producing Activities, Discounted Percentage	10.00%
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in shares)	0	300,000

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RELATED PARTY TRANSACTIONS (Details Textual) (USD $)	12 Months Ended
	Oct. 31, 2012	Oct. 31, 2011
Leroy Halterman [Member]
Management Fee, Amount Paid	$ 30,000	$ 72,000
Company Reimbursement For Office Space, Related Party	0	4,400
Affiliated Entity [Member]
Administrative Fees, Amount Paid	74,000	71,000
Director [Member]
Management Fee, Amount Paid	122,000	101,000
Professional Fees	1,000	0
Chief Financial Officer [Member]
Professional Fees	$ 78,597	$ 76,813

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ACCOUNTS RECEIVABLE (Tables)

12 Months Ended

Oct. 31, 2012

Receivables [Abstract]

Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]

	October 31, 2012		October 31,    2011
Accounts receivable	$	38,485	$	329,748
Less: allowance for doubtful account		-		-
	$	38,485	$	329,748