BRINX RESOURCES LTD - FORM 10-K

Attached files

file	filename
EX-23.1 - EXH 23-1 CONSENT - BRINX RESOURCES LTD	exh23-1_consent.htm
EX-32.1 - EXH 32-1 CERTIFICATION - BRINX RESOURCES LTD	exh32-1_certification.htm
EX-31.1 - EXH 31-1 CERTIFICATION - BRINX RESOURCES LTD	exh31-1_certification.htm
EX-99.1 - EXH 99-1 RESERVE REPORT - BRINX RESOURCES LTD	exh99-1_reservereport.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended October 31, 2013

[ ]	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

(State or other jurisdiction of incorporation or organization)

98-0388682

(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.

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. $740,074 as of April 30, 2013

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, 2014

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

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

PART I

ITEM 1. BUSINESS.

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

Until 2005, our focus was on our undeveloped mineral interests and we were considered, at that time, to be a development stage company engaged in the acquisition and exploration of mineral and oil and gas properties. At that time, we held 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, 2013.

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

Our plan of operations is to continue to participate in the production of commercial quantities of oil and gas and the drilling of 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 and have allowed these claims to lapse subsequent to October 31, 2013.

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.

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, 2013.

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 $406,766 as at October 31, 2013.

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, 2013, the total cost of the 2009-2 Drilling Program was $114,420. The interests are located in Garvin County, Oklahoma.

2009-3 Drilling Program, Oklahoma

On August 12, 2009, we acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program. 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, 2013, was $349,320. 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. 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, 2013, 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, 2013, the total cost, including seismic costs, was $793,551.

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, 2013 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, 2013, the total cost of the 2010-1 Drilling Program was $270,665. 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, 2013, the cost of the Double T Ranch#1 SWDW was $50,812.

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 title. We have suspended our efforts indefinitely on the Antelope Pass Project and the claims were allowed to lapse subsequent to the year-end.

Exploration and Acquisition Capital Expenditures

During the fiscal years ended October 31, 2013, 2012, and 2011, we incurred $293,988, $284,707, and $625,941, 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 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 the oil and gas industry.

Major Customers

During the fiscal years ended October 31, 2013 and 2012, we collected $235,170 (95%) and $382,540 (81%), 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 2014.

Compliance with Government Regulation

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

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

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, 2013 and 2012, we incurred $nil and $30,000, respectively, for Mr. Halterman’s services.

After Mr. Halterman’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 $8,500 per month for services rendered under a Management Consulting Agreement. For the fiscal years ended October 31, 2013 and 2012, we paid Mr. Cabianca $162,000 and $122,000 in management fees, respectively.

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 years ended October 31, 2013 and 2012, we paid Ms. Knight $6,000 and $1,000, respectively, for her services.

On July 10, 2013, Christopher Mulgrew was elected to fill the vacancy in our board of directors created by an increase in the number of directors. Mr. Mulgrew receives $2,500 per month for his service as a director. For the fiscal year ended October 31, 2013, we paid Mr. Mulgrew $10,000 for his services, which include carrying on the functions of an Audit Committee.

We engaged Kulwant Sandher to serve as our chief financial officer on a part-time basis from November 2009 to July 2013 and pay him CAD$2,500 plus taxes per month. For the fiscal years ended October 31, 2013 and 2012, we paid Mr. Sandher $66,060 and $78,597, respectively, for his services.

For the fiscal years ended October 31, 2013 and 2012, we incurred $84,000 and $74,000, 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.

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 prolivic 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. For the year ended October 31, 2013, the three producing wells in this program have produced a total of 384 Bbls of oil and 85 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 for the year ended October 31, 2013 totaled 613 Bbls of oil and nil 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.

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. The other well has been converted to a salt water disposal well. As of October 31, 2013, there has been no production of hydrocarbons.

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. All three of the wells were completed in the deepest pay zone. The third well in this program is currently shut-in. Total production from these wells for the year ended October 31, 2013 was 1,322 Bbls of oil and 1,030 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 for the year ended October 31, 2013 was 104 Bbls of oil and 18 Mcf of natural gas. Additional pay zones are located above the currently producing horizon and it is anticipated that these zones 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. The 3-D program was designed to refine and better define the structures discovered during the earlier program and pinpoint drill locations. We participated in the seismic program and the related prospect generation and acquisition phase without any promotion.

All of the project area, which covers approximately 86,350 acres or 135 square miles, has been permitted and 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 has been completed. A total of 5,148 acres of leases have been acquired. As a result of seismic evaluation and analysis, eight initial prospects have been identified, with the first well drilled on May 14, 2013. On May 27, 2013, this well was classified as a dry hold and costs associated therewith have been moved to proved properties. On August 1, 2013, Karges #1-35 was also classified as a dry hole and the costs of $77,041 associated therewith have been moved to proved properties. On September 4, 2013, Carol #1-22 was drilled and completed with no economic hydrocarbons present. The costs associated with this well were moved to the proved property pool. The total costs of $148,391 associated with these wells were transferred to the proved property pool.

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 completed in January 2012. On April 15, 2013, we elected to plug and abandon this well. All costs associated with this well have been moved to the proved property pool for depletion. After further and in-depth evaluation and consultation, we have elected not to participate any further at King City as we deem this project not to be economically viable.

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, 2013, 2012 and 2011.

	For the fiscal year ended October 31, 2013	For the fiscal year ended October 31, 2012	For the fiscal year ended October 31, 2011
Production Data:
Natural gas (Mcf)	1,120	14,017	26,662
Oil (Bbls)	2,450	4,300	11,962
Average Prices:
Natural gas (per Mcf)	$4.37	$4.93	$6.01
Oil (per Bbl)	$96.18	$93.13	$89.81
Production Costs:
Natural gas (per Mcf)	$1.48	$1.31	$1.77
Oil (per Bbl)	$17.72	$17.84	$11.16

Productive Wells

The following table summarizes information at October 31, 2013, relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, but specifically exclude wells drilled and cased during the fiscal year that have yet to be tested for completion (e.g., all of the operated wells drilled by the Company during this year have been cased in preparation for completion, but no operations have been initiated that would allow these wells to be productive). Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests in the gross wells.

	Gross			Net
Location	Oil	Gas	Total	Oil	Gas	Total
Oklahoma	12	0	12	0.50	0.00	0.50
California	0	0	0	0.00	0.00	0.00
Total	12	0	12	0.50	0.00	0.50

Unaudited Oil and Gas Reserve Quantities

The following unaudited reserve estimates for Oklahoma, presented as of October 31, 2013, 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 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, 2011		38,799			125,701
Revisions of previous estimate		(17,260	)		1,723
Discoveries		-			-
Reserves sold to third parties		(2,909	)		(99,737	)
Production		(4,300	)		(14,017	)
Estimated quantity, October 31, 2012		14,330			13,670
Reserves sold to third parties		-			-
Revisions of previous estimate		(1,061	)		(3,220	)
Discoveries		-			-
Production		(2,449	)		(1,120	)
Estimated quantity, October 31, 2013		10,820			9,330

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, 2013	9,620	1,200	10,820
October 31, 2012	12,880	1,450	14,330
October 31, 2011	36,969	1,830	38,799
Gas (MCF)
October 31, 2013	7,330	2,000	9,330
October 31, 2012	12,570	1,100	13,670
October 31, 2011	124,501	1,200	125,701

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, 2013, 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 a copy of its report filed as an exhibit to this Form 10-K.

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, 2013. 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, 2013 in anticipation of the drilling program that has been started. Large leasing efforts will not begin in the near future until the drilling program on the Washita Bend project has been completed.

	Undeveloped Acres		Developed Acres
	Gross	Net	Gross	Net
Oklahoma	5,573.6	392.6	640.0	96.0
California	nil	nil	0.0	0.0
Total	5,573.6	392.6	640.0	96.0

Drilling Activity

The following table sets forth our drilling activity during the years ended October 31, 2013, 2012 and 2011. The Company drilled 3 new wells in Washita Bend project during the fiscal year ended October 31, 2013.

	2013		2012		2011
	Gross	Net	Gross	Net	Gross	Net
Exploratory wells:
Productive	0	0	0	0	1	.05
Dry	3	0.15	0	0	0	.05
Development wells:
Productive	0	0	0	0	1	.2
Dry	0	0	0	0	0	0

Total wells	3	0.15	0	0	2	.3

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.

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. The claims on this project were allowed to lapse subsequent to October 31, 2013.

Office Space

Our offices are located temporarily in care of our counsel, Dill Dill Carr Stonbraker & Hutchings, P.C., 455 Sherman Street, Suite 300, Denver, Colorado 80203.

ITEM 3. LEGAL PROCEEDINGS.

Hamm Litigation

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. During the years ended October 31, 2013 and 2012, we recognized $12,391 and $51,276 in revenue from the Joe Murray Farms well, respectively, and as of October 31, 2013, a total of $182,962 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

Beckett Complaint

In April 2013, Jeffrey R. Beckett, a shareholder of the Company, filed a lawsuit in the District Court of Washoe County, Nevada, against the Company, its directors, Kenneth A. Cabianca and Georgia Knight, and a principal of one of the Company’s consultants, Sarah Cabianca, generally alleging mismanagement of the Company’s affairs by the directors to the detriment of the Company and its shareholders. The lawsuit seeks the issuance of an injunction, the appointment of a receiver and unspecified damages. In June 2013, Mr. Beckett filed a similar complaint against the same defendants in the United States District Court for the District of Nevada. The Company believes this lawsuit has been improperly brought and lacks merit. The Company is vigorously defending the lawsuit.

ITEM 4. Mine Safety Disclosures.

Not applicable.

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
2012 Fiscal Year	High	Low
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

2013 Fiscal Year
Quarter ending 01/31/13	$0.08	$0.035
Quarter ending 04/30/13	$0.0945	$0.0415
Quarter ending 07/31/13	$0.06	$0.0441
Quarter ending 10/31/13	$0.05	$0.0126

As of January 27, 2014, there were 28 record 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, 2014 was $0.022.

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, 2013 or 2012. Subsequent to October 31, 2013, the Antelope Pass Project was allowed to lapse.

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:

§	$200,000 to $300,000 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

§	$572,000 for operating expenses, including professional, legal, investor relations and accounting expenses associated with our being a reporting issuer under the Securities Exchange Act of 1934.

Accordingly, we anticipate spending approximately $772,000 to $872,000 over the next twelve months in pursuing our stated plan of operations, which will be funded by debt or equity raises dependent upon market conditions.

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, 2013 and 2012, 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, 2013 and 2012:

	October 31,		October 31,
	2013		2012
Balance, beginning of year	$	27,554	$	26,335
Liabilities assumed		-		-
Revisions		774		(1,941	)
Accretion expense		3,308		3,160
Balance, end of year	$	31,636	$	27,554

The reclamation obligation relates to the Ard #1-36, Bagwell #1-20, Bagwell #2-20, Jackson #1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis #2-8, Gehrke #1-24, Jack #1-13 and Miss Jenny #1-8 wells at the Oklahoma Properties 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 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 $235,170 from natural gas and oil sales during the fiscal year ended October 31, 2013, compared with $469,107 during the fiscal year ended October 31, 2012, a decrease of $233,937 due primarily to a decrease in the number of producing wells. In the fiscal year ended October 31, 2013, we sold 1,120 Mcf of natural gas and 2,449 Bbls of oil and in 2012, we sold 14,017 Mcf of natural gas and 4,300 Bbls of oil. Our natural gas volume decreased by 92%, and our oil volume decreased by 43%. The average price received for our natural gas sales in 2013 was $4.37 per Mcf, versus $4.93 per Mcf in 2012, representing a decrease of $0.56 or 11%. The average price received for our crude oil sales in 2013 was $96.18 per Bbl, versus $93.13 per Bbl in 2012, representing an increase of $3.05 or 3%. The decrease in production was due primarily to a decrease in the number of producing wells caused by the sale of our Three Sands property and the natural decline in reserves.

For the fiscal year ended October 31, 2013, we incurred a net loss of $1,025,700, compared with a net loss of $764,988 for the fiscal year ended October 31, 2012 (an increase in net loss of $260,712).

We incurred direct costs of $1,261,626 for the fiscal year ended October 31, 2013, compared with $1,254,308 for the fiscal year ended October 31, 2012, a small increase of $7,318.

Our production costs decreased from $101,690 for the fiscal year ended October 31, 2012 to $39,129 for the fiscal year ended October 31, 2013, a decrease of $62,561. Our production costs decreased as a result of a decrease in the number of producing wells and a decrease in our oil and gas production. Production costs also decreased as a percentage of sales from 22% to 17%.

Our depletion and accretion costs increased from $145,835 during the fiscal year ended October 31, 2012 to $154,914 for the fiscal year ended October 31, 2013, an increase of $9,079. Depletion is calculated based on production rates produced during the year.

Our general and administrative costs increased by $47,182, from $595,386 in 2012 to $642,568 in 2013. The increase in general and administrative costs was due largely to an increase in legal expenses of $90,907 resulting from the costs of defending the Beckett Complaint, offset by a decrease of $51,869 in investor relations expenses.

During the fiscal year ended October 31, 2013, write down of natural gas and oil properties was $425,015, compared to $314,906 for the fiscal year ended October 31, 2012. 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 $52,000 for the fiscal year ended October 31, 2013 as compared to an unrealized loss on held for sale marketable security of $112,000 for the fiscal year ended October 31, 2012. The value of our shares in Lexaria Corp. at October 31, 2013 was $0.055 per share, as compared to $0.12 per share as at October 31, 2012, giving rise to the unrealized loss.

Liquidity and Capital Resources

As of October 31, 2013, we had cash and short term investments of $260,812 and working capital of $319,178, compared to cash and short term investments of $940,512 and working capital of $1,113,259 as of October 31, 2012. The decrease in working capital was caused by a net cash used in operations of $383,390 and payments on drilling activities of $293,988.

During the fiscal year ended October 31, 2013, net cash used in operating activities was $383,390, compared to net cash of $127,972 used in operating activities for the fiscal year ended October 31, 2012. This increase in cash used was primarily due to the increased net loss for fiscal 2013.

Net cash used in investing activities during the fiscal year ended October 31, 2013 was $96,310, compared with $267,437 provided during the fiscal year ended October 31, 2012. We used $293,988 in cash for our oil and gas interests compared to $283,587 during the previous year. We received $552,144 from the sale of our Mississippi assets and Three Sands Project during the 2012 fiscal year.

No cash was provided by or used in financing activities during the fiscal years ended October 31, 2013 and 2012.

We sold all our working interest in the Miss Jenny #1-8 well from the 2010-1 drilling program on January 1, 2014 for $275,147, less commissions, as part of the sale of 100% of the well by the operator.

Going Concern

As shown in the accompanying consolidated financial statements, we have incurred a net loss of $1,203,751 since inception. To achieve profitable operations, we require additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity. Management believes that sufficient funding will be available to meet our business objectives including anticipated cash needs for working capital and is currently evaluating several financing options. However, there can be no assurance that we will be able to obtain sufficient funds to continue the development of our properties and, if successful, to commence the sale of our projects under development. As a result of the foregoing, there exists substantial doubt about our ability to continue as a going concern. These consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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, 2013.

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

Not required for smaller reporting companies.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying balance sheets of Brinx Resources Ltd. as of October 31, 2013 and 2012 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, 2013. 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, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the two-year period ended October 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that Brinx Resources Ltd. will continue as a going concern. As discussed in Note 1 of the accompanying financial statements the Company has incurred recurring losses from operations and will need to raise additional capital to meet its business objectives. These factors raise substantial doubt about its ability to continue as a going concern. Management's plans to continue as a going concern are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Excelsis Accounting Group

Excelsis Accounting Group

Reno, NV

January 29, 2014

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

Tel: 775.332.4200 * Fax: 775.332.4210

www.excelsisaccounting.com

BRINX RESOURCES LTD.
BALANCE SHEETS

	OCTOBER 31,			OCTOBER 31,
	2013			2012

ASSETS

Current assets
Cash and cash equivalents	$	60,812		$	540,512
Investment - Certificate of deposit		200,000			400,000
Marketable securities		44,000			96,000
Accounts receivable		35,760			38,485
Prepaid expenses and deposit		41,871			44,594

Total current assets		382,443			1,119,591

Undeveloped mineral interests, at cost		3,101			3,101

Oil and gas interests, full cost method of accounting,
net of accumulated depletion		1,169,052			1,450,330

Property, plant and equipment(net)		1,741			-

Total assets	$	1,556,337		$	2,573,022


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
Accounts payable and accrued liabilities	$	63,265		$	6,332

Total current liabilities		63,265			6,332

Asset retirement obligations		31,636			27,554

Total liabilities		94,901			33,886

Commitments and contingencies		-			-

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 shares
Issued and outstanding - 500,001 shares		500			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		(228,000	)		(176,000	)

Retained earnings		(1,203,751	)		(178,051	)

Total stockholders' equity		1,461,436			2,539,136

Total liabilities and stockholders' equity	$	1,556,337		$	2,573,022

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

BRINX RESOURCES LTD.
STATEMENTS OF COMPREHENSIVE (LOSS)


	YEAR ENDED
	OCTOBER 31,
	2013			2012

REVENUES
Natural gas and oil sales	$	235,170		$	469,107

DIRECT COSTS
Production costs		39,129			101,690
Depreciation, depletion and accretion		154,914			145,835
General and administrative		642,568			595,386
Loss on sale of natural gas and oil properties		-			96,491
Writedown of natural gas and oil properties		425,015			314,906

Total Expenses		(1,261,626	)		(1,254,308	)

OPERATING (LOSS)		(1,026,456	)		(785,201	)

OTHER INCOME
Interest income		756			213
Other Income		-			20,000

NET(LOSS)		(1,025,700	)		(764,988	)

OTHER COMPREHENSIVE INCOME/(LOSS), NET OF TAX
Unrealized (loss) on held for sale marketable security		(52,000	)		(112,000	)

COMPREHENSIVE (LOSS) FOR THE YEARS	$	(1,077,700	)	$	(876,988	)

Net Income/(Loss) Per Common Share

- Basic	$	(0.04	)	$	(0.03	)
- Diluted	$	(0.04	)	$	(0.03	)

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.

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, 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

Comprehensive income / (loss)
Unrealized (loss) on held for sale marketable security		-		-		-		-		-		-			(52,000	)		(52,000	)
Net (loss)		-		-		-		-		-		(1,025,700	)		-			(1,025,700	)
Comprehensive (loss)

BALANCES, OCTOBER 31, 2013		500,001	$	500		24,629,832	$	24,630	$	2,868,057	$	(1,203,751	)	$	(228,000	)	$	1,461,436

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

BRINX RESOURCES LTD.
STATEMENTS OF CASH FLOWS


	YEAR ENDED
	OCTOBER 31,
	2013			2012

CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES

Net (loss)	$	(1,025,700	)	$	(764,988	)

Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and accretion		154,914			145,835
Loss on sale of natural gas and oil properties		-			96,491
Writedown of natural gas and oil properties		425,015			314,906
Changes in working capital:
Decrease in accounts receivable		2,725			91,763
Decrease / (Increase) in prepaid expenses and deposit		2,723			(7,340	)
Increase / (Decrease) in accounts payable and accrued liabilities		56,933			(4,639	)

Net cash (used in) operating activities		(383,390	)		(127,972	)

CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES

Purchase of equipment		(2,322	)		-
Redemption of Certificate of deposit		200,000			-
Sale proceeds of natural gas and oil working interests		-			552,144
Payments on mineral interest		-			(1,120	)
Payments on oil and gas interests		(293,988	)		(283,587	)

Net cash provided by / (used in) investing activities		(96,310	)		267,437

CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES

Net cash provided by /(used in) financing activities		-			-

Net increase / (decrease) in cash		(479,700	)		139,465

Cash and cash equivalents, beginning of years		540,512			401,047

Cash and cash equivalents, end of years	$	60,812		$	540,512


SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

Assets retirement costs incurred	$	(3,308	)	$	(3,160	)

Issuance of preferred shares to a director	$	-		$	500

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

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Brinx Resources Ltd. (the “Company”) was incorporated under the laws of the State of Nevada on December 23, 1998, and issued its initial common stock in February 2001. The Company holds 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 statement in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial costs from environmental accidents or events for which the Company may be currently liable. In addition, the Company’s oil and gas business makes it vulnerable to changes in prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices and estimated reserves. Price declines reduce the estimated quantity of proved reserves and increase annual depletion expense (which is based on proved reserves).

OIL AND GAS INTERESTS

The Company utilizes the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration; are capitalized within a cost center. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas interests unless the sale represents a significant portion of oil and gas interests and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas interests are 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 ends, 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, 2013 and 2012, the Company had no overproduced imbalances.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

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

ACCOUNTS RECEIVABLE

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

OTHER EQUIPMENT

Computer equipment is stated at cost. Provision for depreciation on computer equipment is calculated using the straight-line method over the estimated useful life of three years.

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, 2013 and 2012.

The table below presents the computation of basic and diluted earnings per share for the years ended October 31, 2013 and 2012:

	October 31, 2013			October 31, 2012
Basic earnings per share computation:
(Loss) from continuing operations	$	(1,025,700	)	$	(764,988	)
Basic shares outstanding		24,629,832			24,629,832
Basic earnings per share	$	(0.04	)	$	(0.03	)

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.

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.

RECENT ACCOUNTING PRONOUNCEMENTS

On February 5, 2013, the FASB issued ASU 2013-02, which requires entities to disclose the following additional information about items reclassified out of accumulated other comprehensive income (AOCI): (1) changes in AOCI balances by component, (2) significant items reclassified out of AOCI by component either on the face of the income statement or as a separate footnote to the financial statements. For public entities, the ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. The Company does not expect this ASU to have a material impact on the financial statements.

GOING CONCERN

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern.

As shown in the accompanying consolidated financial statements, the Company has incurred a net loss of $1,203,751 since inception. To achieve profitable operations, the Company requires additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity. Management believes that sufficient funding will be available to meet its business objectives including anticipated cash needs for working capital and is currently evaluating several financing options. However, there can be no assurance that the Company will be able to obtain sufficient funds to continue the development of its properties and, if successful, to commence the sale of its projects under development. As a result of the foregoing, there exists substantial doubt about the Company’s ability to continue as a going concern. These consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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, 2013 was $0.055 per share, as compared to $0.12 per share as at October 31, 2012, giving rise to an unrealized loss of $52,000 for the year ended October 31, 2013 (2012 – unrealized loss of $112,000). The Company evaluated the prospects of Lexaria in relation to the severity and duration of the impairment. Based on the 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, 2013.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

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, 2013 and October 31, 2012. Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.

	October 31, 2013		October 31, 2012
Accounts receivable	$	35,760	$	38,485
Less: allowance for doubtful account		-		-
	$	35,760	$	38,485

4.	OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:

	October 31, 2013			October 31, 2012
2008-3 Drilling Program, Oklahoma	$	309,152		$	309,152
2009-2 Drilling Program, Oklahoma		114,420			114,420
2009-3 Drilling Program, Oklahoma		349,320			337,749
2009-4 Drilling Program, Oklahoma		190,182			190,182
2010-1 Drilling Program, Oklahoma		270,665			254,817
Washita Bend 3D, Oklahoma		793,551			537,361
Double T Ranch #1 SWDW, Oklahoma		50,812			43,078
Kings City Prospect, California		406,766			404,121
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			555,715
Asset retirement cost		3,367			2,593
Less: Accumulated depletion and impairment		(1,713,860	)		(1,137,820	)
	$	1,169,052		$	1,450,330

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, 2013, 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, 2013, the total cost of the 2009-2 Drilling Program was $114,420. The interests are located in Garvin County, Oklahoma.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

4. OIL AND GAS INTERESTS (continued)

2009-3 Drilling Program, Oklahoma

On August 12, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program. 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 is 5.00%. At October 31, 2013, the total cost of the 2009-3 Drilling Program was $349,320. 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, 2013, 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, 2013, the total cost of the 2010-1 Drilling Program was $270,665. 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, 2013, the total costs including seismic costs, was $793,551.

As a result of seismic evaluation and analysis, eight initial prospects at the Washita Bend Project have been identified. Lucretia #1-14 was the first well drilled on May 14, 2013. This well was classified as a dry hole on May 27, 2013. On August 1, 2013, Karges #1-35 was also classified as a dry hole. On September 4, 2013, Carol #1-22 was plugged and abandoned. The costs of $148,391 associated therewith have been moved to proved properties.

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, 2013, the cost of the Double T Ranch#1 SWDW was $50,812.

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 geophysical survey composed of gravity and seismic surveys and carry Sunset exploration for 33.33% 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, 2013 was $406,766. On April 15, 2013, the Company elected to plug and abandon this well. All costs associated with this well have been moved to the proved property pool for depletion.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

4. OIL AND GAS INTERESTS (continued)

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 Statement of Comprehensive Income/(Loss) 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, 2013 was $61,085.

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 impairment cost of $425,015 and $314,906 for the years ended October 31, 2013 and 2012, respectively.

Depletion

Under the full cost method, depletion is computed on the units of production method based on proved reserves. Depletion expense recognized was $151,026 and $142,675 for the year ended October 31, 2013 and 2012, respectively.

Capitalized Costs

	October 31, 2013			October 31, 2012
Proved properties	$	2,186,940		$	1,603,590
Unproved properties		695,972			984,560
Total Proved and Unproved properties		2,882,912			2,588,150
Accumulated depletion expense		(885,724	)		(734,698	)
Impairment		(828,136	)		(403,122	)
Net capitalized cost	$	1,169,052		$	1,450,330

Results of Operations

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

	October 31, 2013			October 31, 2012
Revenues	$	235,170		$	469,107
Production costs		(39,129	)		(101,690	)
Depletion and accretion		(154,914	)		(145,835	)
Results of operations (excluding corporate overhead)	$	41,127		$	221,582

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

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, 2013 and October 31, 2012, 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, 2013 and 2012:

	October 31, 2013		October 31, 2012
Balance, beginning of years	$	27,554	$	26,335
Liabilities assumed		-		-
Revisions		774		(1,941	)
Accretion expense		3,308		3,160
Balance, end of years	$	31,636	$	27,554

The reclamation obligation relates to the Ard#1-36, Bagwell#1-20, Bagwell#2-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Gehrke#1-24 Jack#1-13 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.

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.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

6. COMMON STOCK (continued)

PREFERRED STOCK (continued)

·	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.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

7.	RELATED PARTY TRANSACTIONS

During the years ended October 31, 2013 and 2012, the Company entered into the following transactions with related parties:

a)	The Company paid $84,000 (2012 - $74,000) to a related entity, for administration services.

b)	The Company paid $162,000 (2012 - $122,000) in management fees to the director and President of the Company.

c)	The Company paid $66,060 (2012 - $78,597) in consulting and accounting fees to the former Chief Financial Officer of the Company.

d)	The Company paid $16,000 (2012 - $1,000) in consulting fees to the directors of the Company.

8. INCOME TAXES

Income tax expense (benefit) for the years ended October 31, 2013 and 2012, respectively, consists of the following:

	October 31		October 31
	2013		2012
Current taxes	$	-	$	-
Deferred taxes		-		-
Net income tax provision (benefit)	$	-	$	-

The effective income tax rate for years ended October 31, 2013 and 2012, respectively, are:

	October 31		October 31
	2013		2012
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
	2013			2012
Deferred tax assets:
Federal and state net operating loss carryovers	$	1,373,903		$	1,065,303
Asset retirement liability		11,073			9,644
Write-down of oil and gas properties		148,755			-
Book depletion in excess of tax depreciation		(64,572	)		(589,608	)
Deferred tax asset	$	1,469,159		$	485,339

Valuation Allowance		(1,469,159	)		(485,339	)
Deferred tax liability	$	-		$	-

The Company has $3,925,437 of net operating loss carry forward as of October 31, 2013, which will expire on October 31, 2030.

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

8.	INCOME TAXES (continued)

The Company believes that all of its positions taken in tax filings are more likely than not to be sustained upon examination by tax authorities for the years ending 2010, 2011, and 2012. 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, 2013 and 2012, 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, 2013 and 2012 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:

Changes in proved reserves	(Bbls)			(MCF)
Estimated quantity, October 31, 2011		38,799			125,701
Revisions of previous estimate		(17,260	)		1,723
Discoveries		-			-
Reserves sold to third parties		(2,909	)		(99,737	)
Production		(4,300	)		(14,017	)
Estimated quantity, October 31, 2012		14,330			13,670
Reserves sold to third parties		-			-
Revisions of previous estimate		(1,061	)		(3,220	)
Discoveries		-			-
Production		(2,449	)		(1,120	)
Estimated quantity, October 31, 2013		10,820			9,330

Proved Reserves at year end	Developed	Undeveloped	Total
Crude Oil (Bbls)
October 31, 2013	9,620	1,200	10,820
October 31, 2012	12,880	1,430	14,330
Gas (MCF)
October 31, 2013	7,330	2,000	9,330
October 31, 2012	12,570	1,100	13,670

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

9. UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)

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

Future cash inflows were computed by applying average 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.

	October 31, 2013			October 31, 2012
Future Cash inflows	$	1,050,820		$	1,396,960
Future production costs		(349,510	)		(521,440	)
Future development costs		(57,500	)		(61,250	)
Future income tax expense		-			-
Future cash flows		643,810			814,270
10% annual discount for estimated timing of cash flows		(170,730	)		(359,860	)
Standardized measure of discounted future net cash	$	473,080		$	454,410

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, 2013			October 31, 2012
Beginning of year	$	454,410		$	2,033,659
Sales and transfers of oil and gas produced, net production costs		(196,041	)		(367,417	)
Net changes in prices and production costs and other		(99,340	)		(89,162	)
Net sale of reserves in place		-			(471,660	)
Changes in future development costs		(3,750)			-
Revisions of previous estimates		(32,430)			(1,618,488	)

Other		161,101		263,641
Net change in income taxes		-		-
Accretion discount		189,130		703,837
Total change in the standardized measure during the year		18,670		(1,579,249	)
Standardize measure, end of year	$	473,080	$	454,410

BRINX RESOURCES LTD.

NOTES TO FINANCIAL STATEMENTS

10. MAJOR CUSTOMERS

The Company collected $235,170 (2012: $382,540) or 95% (2012: 81%) of its revenues from one of its operators during the year ended October 31, 2013. As of October 31, 2013, $32,593 (2012: $34,095) was due from this operator.

11. CONTINGENCIES

Hamm Litigation

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 $12,391 in revenue during the year ended October 31, 2013, and $51,276 in revenue during the year ended October 31, 2012. As at October 31, 2013, revenue from the Joe Murray Farms totaling $182,962 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

Beckett Complaint

In April 2013, Jeffrey R. Beckett, a shareholder of the Company, filed a lawsuit in the District Court of Washoe County, Nevada against the Company, its directors, Kenneth A. Cabianca and George Knight, and a principal of one of the Company’s consultants, Sarah Cabianca, generally alleging mismanagement of the Company’s affairs by the directors to the detriment of the Company and its shareholders. The lawsuit seeks the issuance of an injunction, the appointment of a receiver and unspecified damages. In June 2013, Mr. Beckett filed a similar complaint against the same defendants in the United States District Court for the District of Nevada. The Company believes this lawsuit has been improperly brought and lacks merit. The Company is vigorously defending the lawsuit.

12. SUBSEQUENT EVENT

The Company sold all of its working interest in Miss Jenny#1-8 from the 2010-1 drilling program on January 1, 2014 for $275,147 less sales commission as part of the sale of 100% of the well by its operator.

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, 2013, being the date of our most recently completed fiscal year end. This evaluation was conducted under the supervision and with the participation of our sole officer, Kenneth Cabianca. Based on this evaluation, Mr. Cabianca 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, 2013:

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

·	Our sole officer is also a director. While we have a limited independent governing board consisting of two members, there was an inherent lack of segregation of duties.

·	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, 2013. 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, 2013, 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 board of directors and no audit committee, even though the one financial expert board member carries out the functions of an Audit Committee. Management believes that the material weakness set forth above does not have an effect on our financial statements.

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

Changes In Internal Controls Over Financial Reporting

There have been no changes in our internal controls over financial reporting during the quarter ended October 31, 2013, 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	73	President, Acting Chief Financial Officer, Secretary and Director
Georgia Knight	50	Director
Christopher Mulgrew	41	Director

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. Mr. Cabianca has been serving as the Acting Chief Financial Officer since the resignation of Kulwant Sandher on July 3, 2013. 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 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.

Christopher Mulgrew was elected as a director on July 10, 2013. Since March 2011, Mr. Mulgrew has been the managing partner of Gallant Ridge Capital, LLC, a business consulting and investor relations firm based in Houston, Texas, which specializes in working with companies whose market cap is less than $100 million. His previous experience includes serving from March 2010 to March 2011 as global controller at Kenda Capital, the fund manager of the $1.4 billion Shell Technology Ventures Fund. He has also served as the chief financial officer of companies in the brewing, alternative energy and emergency medicine industries. Mr. Mulgrew holds a Bachelor’s degree in Business Administration (BBA) from Simon Fraser University and a Master’s degree of Business Administration (MBA) from the Jesse H. Jones Graduate School of Business at Rice University. He also holds both the Chartered Accountant (CA) and Certified Public Accountant (CPA) designations and has completed the Master class in Private Equity program at the London Business School.

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.

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. Christopher Mulgrew, an independent director, carries out the functions of an Audit Committee.

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, 2013 and 2012. We do not have any other 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	2013 2012	-0- 30,000	-0- -0-	-0- -0-	-0- 30,000
Kenneth Cabianca (1) President	2013 2012	60,000 20,000	-0- 500(2)	102,000(3) 102,000(3)	162,000 122,500

________________

(1)	Kenneth Cabianca was appointed to serve as President after Mr. Halterman’s death in April 2012.

(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 amounts as compensation for services as a director and pursuant to the Management Consulting Agreement.

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 initially $90,000 per year. On April 23, 2013, the Agreement was amended to increase Mr. Cabianca’s cash compensation to $102,000 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 owns 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.

During the last two fiscal years ended October 31, 2013 and 2012, 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 pay Georgia Knight $500 per monthly for services as a director. We pay Christopher Mulgrew $2,500 per month for his services as a director, which includes carrying out the functions that would be performed by an Audit Committee. 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, 2013.

DIRECTOR COMPENSATION

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)	Option Awards ($)	All Other Compensation ($)	Total ($)
Georgia Knight	6,000	-0-	-0-	-0-	6,000
Christopher Mulgrew	10,000	-0-	-0-	-0-	10,000

ITEM 12.

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

The following table provides certain information as to the officers, directors and more than 5% shareholders. As of January 27, 2014, we had 24,629,832 shares common stock outstanding and 500,001 shares of preferred stock outstanding.

Name and Address of Beneficial Owner (1)	PREFERRED (2)		COMMON		TOTAL
Name and Address of Beneficial Owner (1)	Amount and Nature of Beneficial Ownership	Percent of Class (3)	Amount and Nature of Beneficial Ownership	Percent of Class (3)	Amount and Nature of Beneficial Ownership	Percent of Total (3)
Kenneth A. Cabianca (4) 4519 Woodgreen Drive West Vancouver, B.C. V7S 2T8 Canada	500,001 (5)	100%	2,554,702 (6)	10.4%	3,054,703 (6)	12.2%
Georgia Knight	0	--	0	--	0	--
Christopher Mulgrew	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	--	2,826,335	11.5%	2,826,335	11.2%

______________

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

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

(3)	This table is based on 24,629,832 shares of common stock outstanding and 500,001 shares of Series A preferred stock outstanding as of January 27, 2014.

(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 February 20, 2013.

Equity Compensation Plan Information

As of October 31, 2013, our compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance, are as follows

EQUITY COMPENSATION PLAN INFORMATION

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

During the fiscal years ended October 31, 2013 and 2012, we paid $nil and $30,000, respectively, in management fees to our former president, Lee Halterman.

During the fiscal years ended October 31, 2013 and 2012, we paid $162,000 and $122,000, 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 initially $90,000 per year. On April 23, 2013, the Agreement was amended to increase Mr. Cabianca’s cash compensation to $102,000 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 owns 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 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, 2013 Mark Bailey & Company, Ltd. dba Excelsis Accounting Group (“Excelsis”) is expected to bill us approximately $34,000 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, 2012, 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 2013 and 2012.

Tax Fees

For the fiscal year ended October 31, 2013, Excelsis is expected to bill us $9,000 for tax compliance services. For the fiscal year ended October 31, 2012, Excelsis billed us $9,000 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 2013 and 2012.

Pre-Approval Policies and Procedures

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

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

Regulation S-K Number	Exhibit
3.1	Articles of Incorporation (1)
3.2	Certificate of Change Pursuant to NRS 78.209 (2)
3.3	Amendment to the Articles of Incorporation (3)
3.4	Amended and Restated Bylaws (4)
3.5	Amendment to Amended and Restated Bylaws (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 and 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 and Financial Officer
99.1	Reserve Report from Harper & Associates, Inc. dated January 22, 2014
101*	Financial statements from the Annual Report on Form 10-K of Brinx Resources Ltd. for the year ended October 31, 2013, 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. (6)

________________

(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.

(6)	To be filed by amendment

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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BRINX RESOURCES LTD.

Date: January 29, 2014	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, Acting Chief Financial Officer, Secretary and Director (principal executive and financial officer)	January 29, 2014
Kenneth A. Cabianca

/s/ Christopher Mulgrew	Director	January 29, 2014
Christopher Mulgrew

/s/ Georgia Knight	Director	January 29, 2014
Georgia Knight

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