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EX-99.2 - EXH 99-2 HARPER REPORT - BRINX RESOURCES LTDexh-harper_report.htm
EX-32.2 - EXH 32-2 CERTIFICATION - BRINX RESOURCES LTDexh32-2_certification.htm
EX-31.2 - EXH 31-2 CERTIFICATION - BRINX RESOURCES LTDexh31-2_certification.htm
EX-31.1 - EXH 31-1 CERTIFICATION - BRINX RESOURCES LTDexh31-1_certification.htm
EX-32.1 - EXH 32-1 CERTIFICATION - BRINX RESOURCES LTDexh32-1_certification.htm
 


 
UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K/A
Amendment No. 1

(Mark One)
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended October 31, 2011

[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                                                            to                      

Commission file number:  333-102441

BRINX RESOURCES LTD.
(Exact name of registrant as specified in its charter)

            Nevada                                                                                                    98-0388682                 
(State or other jurisdiction of incorporation or organization)                                 (I.R.S. Employer Identification No.)

820 Piedra Vista Road NE, Albuquerque, NM 87123
(Address of principal executive offices)           (Zip Code)

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  [X]Yes     [  ]No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
[X]Yes                      [  ]No

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

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

 
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Large accelerated filer[  ]                                                                                                Accelerated filer[  ]
Non-accelerated filer[  ]                                                                                                Smaller reporting company[X] 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). [  ]Yes     [X]No

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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:  24,629,832 as of February 9, 2012
 
 
EXPLANATORY NOTE
 
We are filing this Amendment No. 1 to Form 10-K for the fiscal year ended October 31, 2011, as originally filed with the SEC on February 14, 2012 to (1) revise Item 2, Properties,  in particular, Unaudited Oil and Gas Reserve Quantities, as it relates to the internal controls over the preparation of the reserve reports, (2) revise Item 8, Financial Statements and Supplemental Data, in particular, the Notes to the Financial Statements; and (3) file the reserve reports and related consents of the engineering firms as exhibits.

This Amendment No. 1 continues to speak as of the date of the original Form 10-K for the fiscal year ended October 31, 2011 and we have not updated or amended the disclosures contained herein to reflect events that have occurred since the filing of the Form 10-K, or modified or updated those disclosures in any way other than as described in the preceding paragraphs.  Accordingly, this Amendment No. 1 should be read in conjunction with our filings made with the SEC subsequent to the filing of the original Form 10-K on February 14, 2012.

 
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ITEM 2.           PROPERTIES.

Oil and Gas Properties

Recently Disposed Mississippi Properties

Palmetto Point Project

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

Sale.  On August 12, 2011, we entered into an agreement to sell our interest in the Belmont Lake field and all our other properties and wells located in the state of Mississippi.  We received an immediate payment of $200,000 and 800,000 shares of restricted stock in Lexaria Corp. and a final payment of $200,000 was paid on January 13, 2012. The sale of this property will allow management to focus its efforts on our Oklahoma program and the associated recently shot 3-D seismic program. The Mississippi Frio-Wilcox Joint Venture program described below was the successor to the Palmetto Point Program.

Activities Prior to Sale.  As of October 31, 2007, Griffin & Griffin, operator of the Palmetto Point Project, drilled all ten of the wells in the Palmetto Point Project.  Eight of the wells were successful and two were dry holes which were not completed.  Seven of the eight successful wells were completed.  During the three-month period ended July 31, 2011, the Belmont Lake Oil field produced 10,496 Bbls of oil and all natural gas produced was consumed on the lease for compression and gas lift for the oil produced.

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

Mississippi Frio-Wilcox Joint Venture

Location and Access. The Mississippi Frio-Wilcox Joint Venture is located on the border of southern Mississippi and Louisiana along the floodplain of the Mississippi river. The area is approximately 20 miles west of Woodville, Mississippi and approximately 50 miles northwest of Baton Rouge, Louisiana.  The wells are located in Township 2 North, Ranges 4 & 5, in West Adams and Wilkinson Counties in the state of Mississippi. The area is accessible via Interstate 55 (approximately 100 miles south of Jackson, Mississippi) and then west via state highways.  The drill locations are accessed by secondary gravel and dirt roads.

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

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

Costs Including Previous Work.  As of August 12, 2011, we had expended $400,000 in connection with the Mississippi Frio-Wilcox Joint Venture, including leasing, title, drilling, and casing.

 
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Current Oklahoma Projects

2008-3 Drilling Program, Oklahoma.  On January 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581.  We agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  From January 2009 to July 2009, we expended $213,925 in addition to $18,850 that was spent in previous periods.  The total cost of the 2008-3 Drilling Program as of October 31, 2011 was $302,361. The interests are located in Garvin County, South Central Oklahoma.

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

Five wells were drilled during 2009.  Production casing was set on four of the five wells and the fifth well was deemed non-commercial and was plugged and abandoned.   Two of the four completed wells are still producing commercial quantities of oil and gas, with one of the wells still flowing naturally and producing most of the oil.  One development well was drilled in August of 2011 near the highest producing well in the program.  As of October 31, 2011, the three producing wells in this program have produced a total of 176,407 Bbls of oil and 34,915 Mcf of natural gas.

2009-2 Drilling Program, Oklahoma.  On June 15, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,563.  We agreed to participate in the drilling operations to casing point in the initial test well of each of three prospects.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The interests are located in Garvin County, Oklahoma.  A total of three wells were drilled in this program and targeted pay zones that were the same as in the 2008-3 program.  The zones included the prolific Oil Creek, Bromide Sands, Viola, Deese and Layton Sandstone. This program is composed of three 3-D seismically defined separate prospects.   All wells were drilled in the last fiscal quarter of 2009. Two of the wells were deemed non-commercial and were plugged and abandoned.  Production casing was set on one of the three wells and completion efforts have taken place on the third well; however, after testing it was also deemed non-commercial and plugged.  As of October 31, 2011, the total cost of the 2009-2 Drilling Program was $114,420.

2009-3 Drilling Program, Oklahoma. On August 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775.  We agreed to participate in the drilling operations to casing point in the initial test well on each of four prospects.   The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total costs incurred, including drilling costs, as of October 31, 2011 was $300,080. The interests are located in Garvin County, Oklahoma.  Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands. This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the four prospects.   All four of the wells have been drilled and production casing has been set on all four.  Two of the wells had successful drill stem tests that flowed oil and gas to the surface.  Electric and radiation logs indicate multiple pay zones in all four wells.

One of the four wells in this program was completed in late January 2010 as a flowing oil and gas well.  The well was flowing naturally at rates between 400 and 500 Bbls of fluid per day with an oil cut of between 50% and 70% oil.  Natural gas was being produced at a rate of over 400 Mcf per day.  The well only produced for a few days before snow and ice storms forced shutting the well in because the produced oil and water could not be hauled away from the location and the storage tanks for these liquids were full.  Conditions have improved and the well is now producing oil and gas with the use of a pumping unit.  The second well that also had a flowing drill stem test was completed in late March 2010 and that well is currently producing oil and natural gas with the use of a pumping unit.  Total production from these two producing wells as of October 31, 2011 totaled 133,276 Bbls of oil and 34,911 Mcf of natural gas.

In late June 2010, a successful development well was drilled as an offset to the naturally flowing well that is still producing at a rate of 90 Bbls oil and 11 Mcf of natural gas per day with the aid of a pumping unit.  This development well was completed in early August 2010 and is still producing with the aid of a pumping unit at a rate of 130 Bbls of oil and 18 Mcf of natural gas per day and should add significantly to this program’s future oil and gas
 
 
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production.  Total production from this producing well as of October 31, 2011 was 96,304 Bbls of oil and 10,766 Mcf of natural gas.

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

2009-4 Drilling Program, Oklahoma.  On December 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-4 Drilling Program for a total buy-in cost of $13,482.  We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total costs incurred, including drilling costs, as of October 31, 2011 was $190,146.  The interests are located in Garvin County, Oklahoma. Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands. This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the two prospects.

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

2010-1 Program, Oklahoma. On April 23, 2010, we acquired a 5% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,163.  We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects.   The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total cost incurred, including drilling costs, as of October 31, 2011 was $253,855. The interests are located in Garvin County, Oklahoma.  Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands. This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the two prospects.

As of late October 2010, all four wells of the four-well program had been drilled.  Three of the wells had production casing set and one well was plugged and abandoned.  The three successful wells intercepted multiple pay zones including the prolific lowest zone.  One well had a flowing drill stem test but the other two wells were not drill stem tested.  All three wells show excellent porosity, permeability, and hydrocarbon shows.  Completion of these wells started in mid-September 2010.  All three of the wells have been completed in the deepest pay zone as of October 31, 2011 with one well producing at a rate of 11 Bbls of oil per day, a second producing at a rate of 15 Bbls of oil and the third was producing at a rate of 230 Bbls of oil per day in October 2011.  Total production from these wells as of October 31, 2011 was 102,234 Bbls of oil and 18,923 Mcf of natural gas.  As of October 31, 2011, the wells were producing at a combined rate of 255 Bbls of oil and 65 Mcf of natural gas per day.

South Wayne Prospect, Oklahoma. On March 14, 2010, we acquired a 5% working interest in Okland Oil’s South Wayne prospect for a total buy-in cost of $5,000 and dry hole costs of $32,370.  We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  The total cost incurred, including drilling costs, as of October 31, 2011 was $61,085.  The well and related leasehold interests are located in McClain County, Oklahoma.  As of October 31, 2010, the well had been drilled and production casing has been set.  The well was perforated in July 2010 and immediately started flowing oil at a rate of 200 Bbls per day.  The flow of oil was slowed and stopped due to a buildup of paraffin.  A pumping unit was placed on the well in late August 2010 and the well is now producing water free at a rate of 31 Bbls of oil and 20 Mcf of natural gas.  Total production for the McPherson well as of October 31, 2011 was 18,606 Bbls of oil and 10,414 Mcf of natural gas.  Additional pay zones are located above the currently producing horizon and it is anticipated that these zone will be perforated in the future adding additional production to the well.
 
 
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Washita Bend 3D Exploration Project, Oklahoma.  On March 1, 2010, we agreed to participate with a 5% working interest in a 3-D seismic program managed by Ranken Energy Corporation for a buy-in cost of $46,250.  The Oklahoma 3-D seismic program will cover approximately 135 square miles in a known oil and gas producing area.   An earlier 2-D seismic program over the same area indicated a number of untested structures.  We expect the 3-D program will refine and better define the structures discovered during the earlier program and pinpoint drill locations.  We will participate in the seismic program and the related prospect generation and acquisition phase without any promotion.  The BCP Interest shall be 5.625% and the ACP Interest shall be 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  The total cost, including seismic costs, as of October 31, 2011 was $482,882.
 
Work has commenced on this project.  Shooting and data acquisition started on the Oklahoma 3-D project in late February 2011.  The project is slated to cover approximately 86,350 acres or 135 square miles of which approximately 83,043 acres or 130 square miles have now been permitted.  Weather related delays have intermittently forced postponement of the actual data gathering portion of the project which is now underway.

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

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

Three Sands Project

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

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

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

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

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

Present Activities.  Drilling of the Kodesh #1 disposal well was completed on October 3, 2005 and drilling of the Kodesh #2 well was completed on October 23, 2005. Completion and equipping of these wells took place
 
 
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during mid-December 2005 through early January 2006.  The Kodesh #1 is being used for salt water disposal well.  In January 2011, the pump was replaced on the Kodesh #2 well and a new pay zone was perforated and fracture treated, increasing production of oil and natural gas.  As of October 31, 2011, it has produced 4,449 Bbls of oil and 12,739 Mcf of natural gas.

During January 2007, we re-entered the Dye Estate #1 well.  Production of natural gas from the Dye Estate #1 well commenced in mid-August 2007.  As of  October 31, 2011, the Dye Estate #1 well has produced 8,752 Mcf of natural gas and is currently averaging natural gas production at a rate of 11  Mcf per day. Water from the Dye Estate #1 well is being disposed in the Kodesh #1 disposal well.

We commenced drilling the William #4-10 well in early June 2007, reaching a total depth of 4,810 feet in mid-June 2007.  Electric and radiation logs indicated that the William #4-10 well contained four potential commercial pay zones, the Wilcox Sand, Mississippi Lime, Layton Sand and the Tonkawa Sand.  Completion of the lowest zone, the Wilcox Sand, occurred in mid-August 2007.  Production from the William #4-10 well started in mid-October 2007. During the first quarter of 2008, we perforated, fracture treated and tested the Mississippi Lime and the lower Layton Sand to increase the production rate of both gas and oil from the William #4-10 well and provide data regarding the potential of these formations for the remainder of the leases on the Three Sands Project.  As of October 31, 2011, the William #4-10 well had produced 2,670 Bbls oil and 108,116 Mcf of gas.  The well is currently producing a small amount of oil per day and natural gas at a rate of 115 Mcf of natural gas.
 
Drilling commenced on the KC 80 #1-11 well in mid-February 2008 and reached total depth of 4,720 feet by the end of February 2008.  The KC 80 #1-11 has been surveyed with radiation and electrical logs.  The primary target for the well is the upper Mississippian Limestone and Chat Formation. The KC-80 well’s logs indicate significant thickness of Chat and upper Mississippi Limestone with good porosity, permeability, and hydrocarbon shows.

Completion of the KC 80 #1-11 well started in late April 2008.  The lowest pay zone, the Mississippian, was acidized and partially fracture treated.  In early August a similar treatment was given to the Chat zone or the horizon that lies above the lowest pay zone. As of October 31, 2011, the KC 80 #1-11 well is producing at a rate of 2 Bbls of oil and 30Mcf of natural gas daily.  As of October 31, 2011, the KC 80 #1-11 has produced 6,109 Bbls of oil and 43,809 Mcf of natural gas.

Drilling commenced on the Taylor #1 well on October 7, 2010 and reached a total depth of 4,825 feet on October 14, 2010.  The primary target of the well was the Mississippian Limestone.  The well was fracture treated in mid-December 2010 and production testing will follow.  There was no production from this well prior to mid-December 2010.  The well is currently producing at a rate of 3 Bbls of oil per day and 103 mcf of gas per day.  Production from this well as of October 31, 2011 totaled 1,863 Bbls of oil and 38,807 Mcf of natural gas.

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

King City Oil Field

Effective May 25, 2009, we entered into an agreement with Sunset Exploration to explore for oil and gas on 10,000 acres located in west central California.  The agreement calls for us to earn a 20% working interest in the project by funding a maximum of 50% of a $200,000 geophysical survey composed of gravity and seismic surveys and agreeing to carry Sunset Exploration for 40% of dry hole cost of the first well.  The total cost of the King City Oil Field as at October 31, 2011 was $263,561.  Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each party’s working interest.  The geophysical surveys have been completed and most have been processed and interpreted.  The initial surveys indicated that several more short geophysical survey lines would improve the interpretation.  These additional lines have been completed and subsequently several stages of reprocessing have been applied to the original data.  In midsummer 

 
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2011, permitting of the first drill hole began and the well was started in mid-November 2011.  Production casing was set on November 28, 2011 and was completed in January 2012.
 
International Exploration Program

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

Production and Prices

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

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

Productive Wells

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

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

Unaudited Oil and Gas Reserve Quantities

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

The combined estimated proved reserves prepared by J L. Thomas Engineering and Harper and Associates are summarized in the table below, in accordance with definitions and pricing requirements as prescribed by the Securities and Exchange Commission (the “SEC”).  Prices paid for oil and natural gas vary widely depending upon the quality such as the Btu content of the natural gas, gravity of the oil, sulfur content and location of the production related to the refinery or pipelines.
 
 
8

 

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

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

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

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

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

Proved Reserves at year end
Developed
Undeveloped
Total
Crude Oil (Bbls)
     
  October 31, 2011
 36,969
 1,830
 38,799
  October 31, 2010
 70,129
23,110
 93,239
  October 31, 2009
 25,773
30,670
 56,443
Gas (MCF)
     
  October 31, 2011
124,501
 1,200
125,701
  October 31, 2010
 98,617
    230
 98,847
  October 31, 2009
 62,626
10,800
 73,426
 
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 reserves engineers, reserves 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, 2011, we retained J.L. Thomas Engineering, Inc. and Harper & Associates, Inc. as independent third-party reserve engineers, to prepare our estimates of proved reserves.  For more information about the evaluations performed by J.L. Thomas Engineering, Inc. and Harper & Associates, Inc., see copies of their respective reports filed as exhibits to this Form 10-K.
 
Our President, Leroy Halterman, was the person primarily responsible for overseeing the preparation of reserves estimates conducted by independent third-party engineers.  Mr. Halterman had 40 years of geology experience, which included being president of a natural resource investment firm.  He directed over 30 mineral project appraisals and evaluations prior to joining us.  In these capacities, Mr. Halterman had a very high degree of  

 
9

 

working knowledge and understanding of geologic formations, drilling and completion parameters.  Given his familiarity with the properties he had previously directed and those current properties we hold,  we  considered Mr. Halterman to be a qualified person in overseeing the preparation of our internal reserve estimates by a third-party engineering firm.  Mr. Halterman was a graduate of the Missouri School of Mines with a Bachelor of Science degree in Geology.
 
Oil and Gas Acreage

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

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

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

 
2011
2010
2009
 
Gross
Net
Gross
Net
Gross
Net
Exploratory wells:
           
   Productive
1
.05
9
0.45
8
.40
   Dry
0
.05
4
0.20
3
.15
Development wells:            
   Productive .2  0.47 
   Dry 0.085 
             
        Total wells .3  18  1.205  11  .55 

Mineral Property

Antelope Pass Project

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

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

 
 
Highway 338 to the town of Animas and then west for seven miles via State Highway 9.  The property can be reached on gravel roads and dirt tracks.

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

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

Under the General Mining Law of 1872, which governs our mining claims and leases, we, as the holder of the claim, have the right to develop the minerals located in the land identified in the claim.  We must pay an annual maintenance fee of $125 per claim to hold the claim.  Claims can be held indefinitely with or without mineral production, subject to challenge if not developed.  Using land under an unpatented mining claim for anything but mineral and associated purposes violates the General Mining Law of 1872.  All fees have been paid keeping the mining claims valid until August 31, 2012.
 
Office Space
 
We are using the offices of Leroy Halterman, our president.  These offices are located at 820 Piedra Vista Road NE, Albuquerque, NM 87123.  As of September 30, 2011 we no longer reimburse Mr. Halterman for the use of this space.


 
ITEM 8.           FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

 
11

 







REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Stockholders of Brinx Resources, Ltd.
 
We have audited the accompanying balance sheets of Brinx Resources Ltd. as of October 31, 2011 and 2010 and the related statements of operations, stockholders’ equity and comprehensive income, and cash flows for the periods then ended. Brinx Resources Ltd.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Brinx Resources, Ltd. as of October 31, 2011 and 2010, and the results of its operations and its cash flows for the periods then ended in conformity with accounting principles generally accepted in the United States of America.
 
 
/s/ Mark Bailey & Company, Ltd.

 
Mark Bailey & Company, Ltd.
Reno, Nevada
February 13, 2012





 
12

 

 BRINX RESOURCES LTD.
 BALANCE SHEETS
             
   
OCTOBER 31,
   
OCTOBER 31,
 
   
2011
   
2010
 
 ASSETS
           
             
 Current assets
           
 Cash and cash equivalents
  $ 401,047     $ 21,029  
 Investment - certificate of deposit
    400,000       800,000  
 Marketable securities
    208,000       -  
 Accounts receivable
    329,748       148,924  
 Prepaid expenses and deposit
    37,254       128,055  
                 
 Total current assets
    1,376,049       1,098,008  
                 
 Undeveloped mineral interests, at cost
    1,981       811  
                 
 Oil and gas interests, full cost method of accounting,
               
net of accumulated depletion
    2,074,900       2,577,519  
                 
 Total assets
  $ 3,452,930     $ 3,676,338  
                 
                 
 LIABILITIES AND STOCKHOLDERS' EQUITY
               
                 
 Current liabilities
               
 Accounts payable and accrued liabilities
  $ 10,971     $ 37,777  
                 
 Total current liabilities
    10,971       37,777  
                 
 Asset retirement obligations
    26,335       27,494  
                 
 Total liabilities
    37,306       65,271  
                 
                 
 Stockholders' equity
               
        Preferred stock - $0.001 par value; authorized - 25,000,000 shares
         
 Issued - none
    -       -  
                 
        Common stock - $0.001 par value; authorized - 100,000,000 shares
         
 Issued and outstanding - 24,629,832 shares
    24,630       24,630  
                 
 Capital in excess of par value
    2,868,057       2,868,057  
                 
 Accumulative other comprehensive loss
    (64,000 )     -  
                 
 Retained earnings
    586,937       718,380  
                 
 Total stockholders' equity
    3,415,624       3,611,067  
                 
 Total liabilities and stockholders' equity
  $ 3,452,930     $ 3,676,338  
 
The accompanying notes are an integral part of these financial statements.
 
 
13

 
 
 BRINX RESOURCES LTD.
 STATEMENTS OF OPERATIONS
             
             
   
YEAR ENDED
 
   
OCTOBER 31,
 
   
2011
   
2010
 
             
 REVENUES
           
Natural gas and oil sales
  $ 1,241,015     $ 657,929  
                 
 DIRECT COSTS
               
 Production costs
    183,743       96,267  
 Depletion and accretion
    344,932       220,078  
   General and administrative
    732,956       893,795  
      Loss on sale of natural gas and oil properties
    109,299       -  
                 
 Total Expenses
    (1,370,930 )     (1,210,140 )
                 
 OPERATING INCOME/(LOSS)
    (129,915 )     (552,211 )
                 
 OTHER INCOME
               
 Interest income
    900       3,327  
                 
 NET INCOME/(LOSS) BEFORE INCOME TAXES
    (129,015 )     (548,883 )
 Provision for income taxes
    2,428       1,413  
                 
 NET INCOME/(LOSS) FOR THE YEARS
  $ (131,443 )   $ (550,296 )
                 
 Net Income/(Loss) Per Common Share
               
                 
  - Basic
  $ (0.01 )   $ (0.02 )
  - Diluted
  $ (0.01 )   $ (0.02 )
                 
 Weighted average number of common shares outstanding
               
                 
  - Basic
    24,629,832       24,604,627  
  - Diluted
    24,629,832       24,604,627  
 
The accompanying notes are an integral part of these financial statements.
 
14

 
BRINX RESOURCES LTD.
STATEMENT OF STOCKHOLDERS' EQUITY

   
PREFERRED STOCK
   
COMMON STOCK
                               
                           
Capital in
         
Cumulative
   
Total
   
Comprehensive
 
   
Number
         
Number
         
Excess of Par
   
Retained
   
Comprehensive
   
Shareholder's
   
Income/(Loss)
 
   
of Shares
   
Amount
   
of Shares
   
Amount
   
Value
   
Earnings
   
(Loss)
   
Equity
       
                                                       
 BALANCES, October 31, 2009
    -       -       24,529,832       24,530       2,801,991       1,268,676       -       4,095,197       -  
                                                                         
Valuation of stock options (Note 5)
    -       -       -       -       39,166       -       -       39,166          
                                                                         
Shares issued to Investor Relations Services
    -       -       100,000       100       26,900       -       -       27,000          
 Inc. for services rendered
                                                                       
                                                                         
 Net (loss)
    -       -       -       -       -       (550,296 )     -       (550,296 )        
                                                                         
 BALANCES, October 31, 2010
    -       -       24,629,832       24,630       2,868,057       718,380       -       3,611,067       -  
                                                                         
 Comprehensive income / (loss)
                                                                       
Unrealized (loss) on held for sale marketable security
    -       -       -       -       -       -       (64,000 )     (64,000 )     (64,000 )
Net (loss)
    -       -       -       -       -       (131,443 )     -       (131,443 )     (131,443 )
 Comprehensive (loss)
                                                                       
                                                                         
 BALANCES, OCTOBER 31, 2011
    -     $ -       24,629,832     $ 24,630     $ 2,868,057     $ 586,937     $ (64,000 )   $ 3,415,624     $ (195,443 )
 
The accompanying notes are an integral part of these financial statements.


 
15

 

 BRINX RESOURCES LTD.
 STATEMENTS OF CASH FLOWS
             
             
   
YEAR ENDED
 
   
OCTOBER 31,
 
   
2011
   
2010
 
             
 CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES
           
             
 Net (loss)
  $ (131,443 )   $ (550,296 )
                 
 Adjustments to reconcile net income to net cash provided by
               
     operating activities:
               
 Stock based compensation (note 5)
    -       39,166  
 Depletion and accretion
    344,932       220,078  
 Loss on sale of natural gas and oil properties
    109,299       -  
   Shares issued to Investor Relations Services Inc. for services rendered
    -       27,000  
 Changes in working capital:
               
 Decrease/(Increase) in accounts receivable
    19,176       (51,726 )
 Decrease in prepaid expenses and deposit
    90,801       142,555  
 (Decrease) in accounts payable and accrued liabilities
    (26,806 )     (37,408 )
 Increase (Decrease) in income taxes receivable
    -       253,814  
                 
 Net cash provided by (used in) operating activities
    405,959       43,183  
                 
 CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES
               
                 
 Redemption/(purchase) of certificate of deposit
    400,000       (800,000 )
 Sale proceeds of natural gas and oil working interests
    200,000       -  
 Payments on mineral interest
    (1,170 )     -  
 Payments on oil and gas interests
    (624,771 )     (1,170,104 )
                 
 Net cash provided by (used in) investing activities
    (25,941 )     (1,970,104 )
                 
 CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES
               
                 
 Net cash (used in) financing activities
    -       -  
                 
 Net increase (decrease) in cash
    380,018       (1,926,921 )
                 
 Cash and cash equivalents, beginning of years
    21,029       1,947,950  
                 
 Cash and cash equivalents, end of years
  $ 401,047     $ 21,029  
                 
                 
 SUPPLEMENTAL CASH FLOW INFORMATION
               
                 
 Cash paid for taxes
  $ 2,428     $ 1,413  
                 
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
         
                 
 Assets retirement costs incurred
  $ (3,299 )   $ (4,440 )
                 
Investment in natural oil and gas working interests included in
  $ -     $ 20,645  
 accounts payable
               
 
The accompanying notes are an integral part of these financial statements.
 
 
16

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS

 
1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

USE OF ESTIMATES

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

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

OIL AND GAS INTERESTS

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

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

REVENUE RECOGNITION

Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers.  Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred.  Revenues from the production of oil and natural gas properties in which the Company shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period.  Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests.  The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field.  At October 31, 2011 and 2010, the Company had no overproduced imbalances.
 
 
17

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS

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

ACCOUNTS RECEIVABLE

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

IMPAIRMENT OF LONG-LIVED ASSETS

The Company has adopted FASB ASC 360 "Accounting  for the  Impairment  or Disposal of Long-Lived  Assets," which requires that long-lived assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Oil and gas interests accounted for under the full cost method are subject to a ceiling test, described above, and are excluded from this requirement.

ASSET RETIREMENT OBLIGATIONS

The Company follows FASB ASC 410-20 "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.

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

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

INCOME / (LOSS) PER SHARE

Basic income/(loss) per share is computed based on the weighted average number of common shares outstanding during each period.  The computation of diluted earnings per share assumes the conversion, exercise or contingent issuance of securities only when such conversion, exercise or issuance would have the dilutive effect on income/(loss) per share.  The dilutive effect of outstanding options, 300,000 as of October, 31, 2011 and 500,000 as of October 31, 2010, and warrants and their equivalents is reflected in diluted earnings per share by application of the treasury stock method. As the Company is reporting net losses in both periods, the conversion of options for the calculation of diluted earnings per share would be considered anti-dilutive. The table below presents the computation of basic and diluted earnings per share for the years ended October 31, 2011 and 2010:
 
   
October 31,   
2011    
   
October 31,
2010
 
Basic earnings per share computation:
           
 
(Loss) from continuing operations and net loss
  $ (128,321 )   $ (550,296 )
Basic and diluted shares outstanding
    24,629,832       24,604,627  
Basic and diluted earnings per share
  $ (0.01 )   $ (0.02 )

 
 
18

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS

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

INCOME TAXES

Deferred tax assets and liabilities are recognized for temporary differences between the financial reporting and tax bases of the firm’s assets and liabilities. Valuation allowances are established to reduce deferred tax assets to the amount that more likely than not will be realized. The firm’s tax assets and liabilities are presented as a component of “Other assets” and “Other liabilities and accrued expenses,” respectively, in the consolidated statements of financial condition. Tax provisions are computed in accordance with FASB ASC 740, “Accounting for Income Taxes.”
 
The firm adopted the provisions of FASB ASC 740-10 “Accounting for Uncertainty in Income Taxes — an Interpretation.” A tax position can be recognized in the financial statements only when it is more likely than not that the position will be sustained upon examination by the relevant taxing authority based on the technical merits of the position. A position that meets this standard is measured at the largest amount of benefit that will more likely than not be realized upon settlement. A liability is established for differences between positions taken in a tax return and amounts recognized in the financial statements. FASB ASC 740-10 also provides guidance on derecognition, classification, interim period accounting and accounting for interest and penalties.

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

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

FAIR VALUE

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

Level 1 inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
 
Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
 
Level 3 inputs to valuation methodology are unobservable and significant to the fair measurement.

The carrying amounts reported in the balance sheets for the cash and cash equivalents, investments in certificates of deposits, receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of fair value because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest.  Marketable securities are valued using Level 1 inputs.

 
19

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
 
1.           ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)

CONCENTRATION OF CREDIT RISK

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

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

EQUITY BASED COMPENSATION

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

The fair value of each option granted has been estimated as of the date of the grant using the Black-Scholes option pricing model with the following assumptions:
 
 
Years ended
October 31, 2011
October 31, 2010
Expected volatility
-
   219%
Risk-free interest rate
-
   0.92%
Expected life
 -
   2 years
Dividend yield
-
   0.00%
 
RECENT ACCOUNTING PRONOUNCEMENTS

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

2.  
MARKETABLE SECURITIES

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

 
20

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS

3.            ACCOUNTS RECEIVABLE

Accounts receivable consists of revenues receivable from the operators of the oil and gas projects for the sale of oil and gas by the operators on their behalf and are carried at net receivable amounts less an estimate for doubtful accounts.  Management considers all accounts receivable to be fully collectible at October 31, 2011 and October 31, 2010.  Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.
 
   
October 31, 2011
   
October 31, 2010
 
Accounts receivable
  $ 329,748     $ 148,924  
Less: allowance for doubtful account
    -       -  
    $ 329,748     $ 148,924  


4.  
OIL AND GAS INTERESTS

The Company holds the following oil and natural gas interests:
 
   
Oct 31, 2011
   
October 31, 2010
 
2008-3 Drilling Program, Oklahoma
 
$
302,361
   
$
257,564
 
2009-2 Drilling Program, Oklahoma
   
114,420
     
115,582
 
2009-3 Drilling Program, Oklahoma
   
300,080
     
294,164
 
2009-4 Drilling Program, Oklahoma
   
190,146
     
172,530
 
2010-1 Drilling Program, Oklahoma
   
253,855
     
232,212
 
Washita Bend 3D, Oklahoma
   
482,882
     
337,398
 
Kings City Prospect, California
   
263,561
     
106,091
 
Three Sands Project, Oklahoma
   
1,451,543
     
1,279,633
 
South Wayne Prospect, Oklahoma
   
61,085
     
60,914
 
Palmetto Point Project, Mississippi
   
-
     
420,000
 
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi
   
(222.123)
     
312,630
 
Frio-Wilcox Prospect, Mississippi
   
-
     
400,000
 
Asset retirement cost
   
4,534
     
8,992
 
Less: Accumulated depletion and impairment
   
(1,127,444
)
   
(1,420,191
)
   
$
2,074,900
   
$
2,577,519
 

2008-3 Drilling Program, Oklahoma
 
 
On January 12, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The Before Casing Point Interest (“BCP”) shall be 6.25% and the After Casing Point Interest (“ACP”) shall be 5.00%.  From January to July 2009, the Company expended a $213,925 in addition to $18,850 that was spent in previous periods.  The well, Wigley#1-11, was abandoned during March 2009.  The cost and its buy-in cost total of $33,423 were moved to the proved properties.  Selman#1-21 and Bagwell#1-20 started producing during May 2009, the cost and its buy-in cost total of $67,707 for Selman#1-21 and $57,921 for Bagwell#1-20 were moved to the proved properties. Ard#1-36 started producing during June 2009 and the cost and its buy-in cost total of $42,647 was moved to the proved properties.  Selman#2-21 started producing during July 2009 and was abandoned on April 20, 2010; the cost and its buy-in cost total of $57,483 were moved to the proved properties pool.  The total cost of the 2008-3 Drilling Program as at October 31, 2011 was $302,361.  The interests are located in Garvin County, Oklahoma.
 
 
21

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
 
 
4.
OIL AND GAS INTERESTS (continued)

2009-2 Drilling Program, Oklahoma

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

2009-3 Drilling Program, Oklahoma

On August 12, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  Jackson#1-18 started producing during January 2010; an amount of $63,725 which included the buy-in cost was moved to the proved property pool.  Miss Gracie#1-18 started producing during March 2010; an amount of $62,268 which included its buy-in cost was moved to the proved property pool.  Brewer#1-20 was abandoned on June 2, 2010; the cost and its buy-in cost total of $64,936 were moved to the proved properties.  Waunice#1-36 started producing during June 2010 and was abandoned on September 23, 2010; an amount of $43,848 which included its buy-in cost was moved to the proved property pool.  As at October 31, 2011, the total cost of the 2009-3 Drilling Program was $300,080.  The interests are located in Garvin County, Oklahoma.

2009-4 Drilling Program, Oklahoma

On December 19, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-4 Drilling Program for a total buy-in cost of $13,482.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  Dennis#1-8 started producing during May 2010; an amount of $79,892 which included the buy-in cost was moved to the proved property pool, it was abandoned on September 27, 2010.  Dennis#2-8 was abandoned on November 17, 2010; an amount of $34,068 which included the buy-in cost was moved to the proved property pool.  Murray Trust#3-19 was abandoned on December 13, 2010; an amount of $12,917 which included the buy-in cost was moved to the proved property pool.  Murray Trust#2-19 started producing during November 2010; an amount of $49,637, which included the buy-in cost was moved to the proved property pool.

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

2010-1 Drilling Program, Oklahoma

On April 23, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,163.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%.  Julie#1-14 was abandoned on October 2, 2010; the cost and its buy-in cost total of $47,035 were moved to the proved properties.  Jack#1-13 started producing during November 2010; an amount of $73,993 which included the buy-in cost was moved to the proved property pool.  Miss Jenny started producing during December 2010; an amount of $58,995, which included the buy-in cost was moved to the proved property pool.  As at October 31, 2011, the total cost of the 2010-1 Drilling Program was $253,855.  The interests are located in Garvin County, Oklahoma.

 
22

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
 
4.            OIL AND GAS INTERESTS (continued)

Washita Bend 3D Exploration Project, Oklahoma

On March 1, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s Washita Bend 3D Exploration Project for a buy-in cost of $46,250.  The BCP Interest shall be 5.625% and the ACP Interest shall be 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  As at October 31, 2011, the total costs, including seismic costs was $482,882.

King City Prospect, California

A Farmout agreement was made effective on May 25, 2009 between the Company and Sunset Exploration, Inc., to explore for oil and natural gas on 10,000 acres located in west central California.  The Company paid $100,000 (50% pro rata share of $200,000)  to earn a 20% working interest in project by funding a maximum of 50% of a $200,000 in a geophysical survey composed of gravity and seismic surveys and to carry Sunset exploration for 33.33% of dry hole cost of the first well.  Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each party’s working interest.  The total cost of the King City prospect as at October 31, 2011 was $263,561.

Three Sands Project, Oklahoma

On October 6, 2005, the Company acquired a 40% working interest in Vector Exploration Inc’s Three Sands Project for a total buy-in cost of $88,000 plus dry hole costs.  For the year ended October 31, 2006, the Company expended $530,081 in exploration costs.  In June 2007, the Company acquired a 40% working interest in William #4-10 well for a total cost of $285,196 and paid a further $17,000 in costs relating to the well.  On March 19, 2008, the Company participated in the KC 80#1-11 well and paid $75,000 for the prepaid drilling costs.  During March and April 2008, the Company expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 from May to July 2008 for the KC 80#1-11 well.  The total cost of the Three Sands Project as at October 31, 2011 was $1,451,543.  The interests are located in Oklahoma.

South Wayne Prospect, Oklahoma

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

Palmetto Point Project, Mississippi

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

Impairment

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

 
23

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
 
4.            OIL AND GAS INTERESTS (continued)

Depletion

Under the full cost method, depletion is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production.  Depletion expense recognized was $341,633 and $215,638 for the years ended October 31, 2011 and 2010, respectively.

Capitalized Costs

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

Results of Operations

Results of operations for oil and gas producing activities during the years ended are as follows:
 
   
October 31, 2011
   
October 31, 2010
 
Revenues
  $ 1,241,015     $ 657,929  
Production costs
    (183,743 )     (96,267 )
Depletion and accretion
    (344,932 )     (220,078 )
Results of operations (excluding corporate overhead)   $ 712,340     $ 341,584  
 
5.           ASSET RETIREMENT OBLIGATIONS

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

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


 
24

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS

 
5.           ASSET RETIREMENT OBLIGATIONS (continued)

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

   
October 31, 2011
   
October 31, 2010
 
Balance, beginning of periods
  $ 27,494     $ 37,011  
Liabilities assumed
    774       2,700  
    Revisions     (5,232     (16,658
Accretion expense
    3,299       4,441  
Balance, end of periods
  $ 26,335     $ 27,494  
 
The reclamation obligation relates to the Kodesh, Dye Estate, KC 80, Taylor and William wells at the Three Sands Property; and ARD#1-36, Bagwell#1-20, Bagwell#2-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24, Jack#1-13 and Miss Jenny#1-8 wells at Oklahoma Properties, McPherson#1-1 well at South Wayne Prospect.  The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes in applicable laws and regulations.  Such changes will be recorded in the accounts of the Company as they occur.

6.
COMMON STOCK

               STOCK OPTIONS

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

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

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

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

 
   
Options Outstanding
 
         
Weighted Average
 
   
Number of Shares
   
Exercise Price
 
Balance, October 31, 2010
    500,000     $ 0.10  
Expired on October 30, 2011
    (200,000 )     0.10  
Balance, October 31, 2011
    300,000     $ 0.10  
 
The Company has the following options outstanding and exercisable.

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


 
 
25

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS

 
7.            RELATED PARTY TRANSACTIONS

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

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

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

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

d)    
The Company paid $76,813 (2010 - $72,068) in consulting and accounting fees to the Chief Financial Officer of the Company.
 
8.  
INCOME TAXES

Income tax expense (benefit) for the years ended October 31, 2011 and for the year ended October 31, 2010 consists of the following:
   
October 31
   
October 31
 
   
2011
   
2010
 
             
Current Taxes
  $ -     $ -  
Deferred Taxes
    -       -  
Net income tax provision (benefit)
  $ -     $ -  
 
The effective income tax rate for years ended October 31, 2011 and the year ended October 31, 2010 are:

   
October 31
   
October 31   
 
   
2011
   
2010   
 
Federal statutory income tax rate
    35.00 %     35.00 %
                 
Net effective income tax (benefit) rate
    35.00 %     35.00 %

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

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

Deferred tax liabilities:
           
             
Net Deferred Tax Liability
  $ -     $ -  

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

 
 
26

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
 
 
8.  
INCOME TAXES (continued)
 
The Company believes that all of its positions taken in tax filings are more likely than not to be sustained upon examination by tax authorities. The Company includes interest and penalties arising from the underpayment of income taxes in the consolidated statements of operations in the provision for income taxes. As of October 31, 2011 and 2010, the Company had not incurred interest or penalties related to uncertain tax positions.

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

9.            UNAUDITED OIL AND GAS RESERVE QUANTITIES

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

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

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

   
Crude Oil
   
Natural Gas
 
             
Changes in proved reserves
 
(Bbls)
   
(MCF)
 
Estimated quantity, October 31, 2009
   
56,443
     
73,426
 
 Revisions of previous estimate
   
-
     
-
 
 Discoveries
   
45,009
     
42,995
 
 Reserves sold to third parties
   
-
     
-
 
 Production
   
(8,213
)
   
(17,574
)
 Estimated quantity, October 31, 2010
   
93,239
     
98,847
 
 Reserves sold to third parties
   
(37,780
)
   
(3,580
)
 Revisions of previous estimate
   
(9,396)
     
24,000
 
 Discoveries
   
4,698
     
33,096
 
 Production
   
(11,962
)
   
(26,662
)
Estimated quantity, October 31, 2011
   
38,799
     
125,701
 
 
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, 2011
36,969
1,830
38,799
    October 31, 2010
70,129
23,110
93,239
Gas (MCF)
     
    October 31, 2011
124,501
1,200
125,701
    October 31, 2010
98,617
230
98,847

 
 
27

 
 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS

 
9.           UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)

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

Future cash inflows were computed by applying average prices of oil and gas in the preceding twelve months to the estimated future production of proved oil and gas reserves. The future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved oil and gas reserves and the tax basis of proved oil and gas properties and available net operating loss carry-forwards. Discounting the future net cash inflows at 10% is a method to measure the impact of the time value of money.
 
  
 
 
October 31,
2011
   
October 31,
2010
 
Future Cash inflows
 
$
3,180,013
   
$
7,989,374
 
Future production costs
   
(731,218
)
   
(1,893,661
)
Future development costs
   
(61,250
)
   
(303,526
)
Future income tax expense
   
(570,543
)
   
(1,840,474
)
Future cash flows
   
1,817,003
     
3,951,713
 
10% annual discount for estimated timing of cash flows
   
(1,063,697
)
   
(1,418,471
)
Standardized measure of discounted future net cash
 
$
753,306
   
$
2,533,242
 

               UNAUDITED STANDARIZED MEASURE

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

Standardized measure of discounted cash flows:
 
October 31, 2011
   
October 31, 2010
 
Beginning of year
 
$
2,533,242
   
$
2,540,588
 
Sales and transfers of oil and gas produced, net production costs
   
4,809,361
     
(3,305,039
)
Net changes in prices and production costs and other
   
(1,162,443
   
1,085,363
 
Net changes due to discoveries
   
713,000
     
1,275,338
 
Changes in future development costs
   
(242,276
   
185,644
 
Revisions of previous estimates
   
(920,808
)    
-
 
Other
   
(1,572,129
)    
-
 
Net change in income taxes
   
(1,269,931
)    
758,694
 
Accretion discount
   
(354,774
)    
1,282,684
 
Future cash flows
   
(1,779,936
)
   
(1,290,030
)
End of year
 
$
753,306
   
$
2,533,242
 

10.         MAJOR CUSTOMERS

We collected $798,912 (2010: $451,359) or 64% of our revenues from one of our operators during the year ended October 31, 2011. As of October 31, 2011, $90,602 was due from this operator.
 
 
28

 
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS

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

12.
SUBSEQUENT EVENTS

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


 
29

 
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 (6)
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 (6)
16.1
Letter from Chisholm, Bierwolf, Nilson & Morrill, LLC dated September 8, 2010 (5)
23.1 Consent of J.L. Thomas Engineering, Inc.
23.2 Consent of Harper & Associates, Inc.
31.1
Rule 15d-14(a) Certification of Principal Executive Officer
31.2
Rule 15d-14(a) Certification of Principal Financial Officer
32.1
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer
32.2
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer
99.1 Reserve Report from J.L. Thomas Engineering, Inc. dated November 20, 2011
99.2 Reserve Report from Harper & Associates, Inc. dated February 2, 2012
101*
Financial statements from the Annual Report on Form 10-K of Brinx Resources Ltd. for the year ended October 31, 2011, formatted in XBRL: (i) the Balance Sheets; (ii) the Statements of Operations; (iii) the Statements of Cash Flows; (iv) the Statements of Stockholders’ Equity; and (v) the Notes to Financial Statements tagged as blocks of text.
___________________
(1)
Incorporated by reference to the exhibits to the registrant’s registration statement on Form SB-1, file number 333-102441.
(2)
Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated September 26, 2004, filed September 27, 2004.
(3)
Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated December 3, 2008, filed January 13, 2009.
(4)
Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated December 11, 2009, filed December 15, 2009.
(5)
Incorporated by reference to the exhibits to the registrant’s amended current report on Form 8-K dated September 1, 2010, filed September 9, 2010.
(6)
Filed on February 14, 2012.
 
 
30

 
 
*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.
 


 
31

 

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:  December 3, 2012
By:
 /s/ Kenneth A. Cabianca  
     Kenneth A. Cabianca, President  

 
 
 
 
 
 
 
 
 
32