UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended April 30, 2015

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

For the transition period from ________________ to _______________

333-102441

 (Commission file number)

BRINX RESOURCES LTD.

(Exact name of registrant as specified in its charter)

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

Address of principal executive offices)                                (Zip Code)

(505) 250-9992

(Registrant's telephone number, including area code)

Not applicable

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

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

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).

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.

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

[  ]Yes   [x] No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:  24,629,832 shares of Common Stock, $0.001 par value, as of June 3, 2015

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BRINX RESOURCES LTD.

INDEX

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BRINX RESOURCES LTD.
BALANCE SHEETS
		APRIL 30,				OCTOBER 31,
		2015				2014
		(Unaudited)				(Audited)
ASSETS
Current assets
Cash and cash equivalents	$		52,308		$		109,953
Marketable securities			-				37,076
Accounts receivable			1,605				8,579
Prepaid expenses and deposit			1,701				23,506
Total current assets			55,614				179,114
Oil and gas interests, full cost method of accounting,
net of accumulated depletion			305,978				951,502
Property, plant and equipment(net)			580				967
Total assets	$		362,172		$		1,131,583
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities	$		135,771		$		54,912
Total current liabilities			135,771				54,912
Asset retirement obligations			36,763				34,754
Total liabilities			172,534				89,666
Stockholders' equity
Preferred stock - $0.001 par value; authorized - 25,000,000 shares
Series A Preferred stock - $0.001 par value; authorized - 1,000,000 shares
Issued and outstanding - 500,001 shares			500				500
Common stock - $0.001 par value; authorized - 100,000,000 shares
Issued and outstanding - 24,629,832 shares			24,630				24,630
Capital in excess of par value			2,868,057				2,868,057
Accumulative other comprehensive loss			-				(173,020	)
Retained earnings			(2,703,549	)			(1,678,250	)
Total stockholders' equity			189,638				1,041,917
Total liabilities and stockholders' equity	$		362,172		$		1,131,583

 

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

 

 

 

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BRINX RESOURCES LTD.
STATEMENTS OF COMPREHENSIVE (LOSS)
(UNAUDITED)
		FOR THE THREE MONTHS ENDED								FOR THE SIX MONTHS ENDED
		APRIL 30,								APRIL 30,
		2015				2014				2015				2014
REVENUES
Natural gas and oil sales	$		2,527		$		20,952		$		9,348		$		104,517
DIRECT COSTS
Production costs			6,554				8,692				15,048				20,102
Depreciation, depletion and accretion			5,259				9,081				19,246				45,169
General and administrative			133,839				112,863				253,772				231,382
Writedown of natural gas and oil properties			-				-				596,203				-
Writeoff of undeveloped minerial interests			-				-				-				3,101
Total Expenses			(145,652	)			(130,636	)			(884,269	)			(299,754	)
OPERATING (LOSS)			(143,125	)			(109,684	)			(874,921	)			(195,237	)
OTHER INCOME
Interest income			-				79				-				129
Realized (loss) on sale of marketable security			(150,378	)			-				(150,378	)			-
NET(LOSS)			(293,503	)			(109,605	)			(1,025,299	)			(195,108	)
OTHER COMPREHENSIVE INCOME/(LOSS), NET OF TAX
Unrealized gain on held for sale of marketable security			-				174,880				-				172,800
COMPREHENSIVE INCOME/(LOSS) FOR THE YEARS	$		(293,503	)	$		65,275		$		(1,025,299	)	$		(22,308	)
Net Income/(Loss) Per Common Share
- Basic	$		(0.01	)	$		(0.00	)	$		(0.04	)	$		(0.01	)
- Diluted	$		(0.01	)	$		(0.00	)	$		(0.04	)	$		(0.01	)
Weighted average number of common shares outstanding
- Basic			24,629,832				24,629,832				24,629,832				24,629,832
- Diluted			24,629,832				24,629,832				24,629,832				24,629,832

 

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

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BRINX RESOURCES LTD.
STATEMENTS OF CASH FLOWS
(UNAUDITED)
		FOR THE SIX MONTHS ENDED
		APRIL 30,
		2015				2014
CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES
Net (loss)	$		(1,025,299	)	$		(195,108	)
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and accretion			19,246				45,169
Realized loss on sale of marketable security			150,378				-
Writedown of natural gas and oil properties			596,203				-
Writeoff of undeveloped mineral interests			-				3,101
Changes in working capital:
Decrease in accounts receivable			6,974				17,992
Decrease in prepaid expenses and deposit			21,805				365
Increase / (Decrease) in accounts payable and accrued liabilities			119,026				(55,289	)
Net cash (used in) operating activities			(111,667	)			(183,770	)
CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES
Redemption of Certificate of deposit			-				100,000
Sale of marketable security			59,718				-
Sale proceeds of natural gas and oil working interests			-				275,148
Payments on oil and gas interests			(5,696	)			(89,202	)
Net cash provided by / (used in) investing activities			54,022				285,946
CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES
Net cash provided by /(used in) financing activities			-				-
Net increase / (decrease) in cash			(57,645	)			102,176
Cash and cash equivalents, beginning of the years			109,953				60,812
Cash and cash equivalents, end of the years	$		52,308		$		162,988
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	$		-		$		-
Cash paid for taxes	$		-		$		-
Accounts payable settled with transfer of well	$		38,167		$		-

 

 

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BRINX RESOURCES LTD.

 

 

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 oil and gas interests in Oklahoma and California.  In 2006, the Company commenced oil and gas production and started earning revenues.

The accompanying financial statements of the Company are unaudited.  In the opinion of management, the financial statements include all adjustments, consisting only of normal recurring adjustments, necessary for fair presentation.  The results of operations for the six-month period ended April 30, 2015 are not necessarily indicative of the operating results for the entire year.  These financial statements should be read in conjunction with the financial statements and notes included in the Company's Form 10-K for the year ended October 31, 2014.

USE OF ESTIMATES

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

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

OIL AND GAS INTERESTS

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

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

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

REVENUE RECOGNITION

Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers.  Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred.  Revenues from the production of oil and natural gas properties in which the Company shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period.  Gas imbalances occur when the Company's actual sales differ from its entitlement under existing working interests.  The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field.  At April 30, 2015 and 2014, the Company had no overproduced imbalances.

ACCOUNTS RECEIVABLE

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

OTHER EQUIPMENT

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

IMPAIRMENT OF LONG-LIVED ASSETS

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

ASSET RETIREMENT OBLIGATIONS

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

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

INCOME / (LOSS) PER SHARE

Basic income/(loss) per share is computed based on the weighted average number of common shares outstanding during each year.  The computation of diluted earnings per share assumes the conversion, exercise or contingent issuance of securities only when such conversion, exercise or issuance would have the dilutive effect on income/(loss) per share.  The dilutive effect of outstanding options was nil as of April 30, 2015 and 2014.

 

 

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INCOME / (LOSS) PER SHARE (continued)

The table below presents the computation of basic and diluted earnings per share for the six-month periods ended April 30, 2015 and 2014:

INCOME TAXES

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

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

CASH EQUIVALENTS

 

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

MARKETABLE SECURITIES AND INVESTMENTS

 

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

FAIR VALUE

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

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FAIR VALUE (continued)

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

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

 

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

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

CONCENTRATION OF CREDIT RISK

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

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

RECENT ACCOUNTING PRONOUNCEMENTS

In May 2014, FASB issued ASU 2014-09, Revenue from Contracts with Customers, which eliminates the transaction- and industry-specific revenue recognition guidance under current GAAP and replaces it with a principle-based approach for determining revenue recognition. Public entities are required to adopt the revenue recognition standard for reporting periods beginning after December 15, 2016, and interim and annual reporting periods thereafter. The Company is currently evaluating the impact this ASU will have on the Company's financial statements.

FASB issued ASU 2014-15 on August 27, 2014, providing guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if "conditions or events raise substantial doubt about the entity's ability to continue as a going concern." The ASU applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. The Company currently discloses a going-concern in Note 1 however the Company will evaluate the impact this ASU will have on the financial statements.

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GOING CONCERN

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

As shown in the accompanying financial statements, the Company has incurred a net loss of $2,703,549 since inception.  To achieve profitable operations, the Company requires additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity.  Management believes that sufficient funding will be available to meet its business objectives including anticipated cash needs for working capital and is currently evaluating several financing options.  However, there can be no assurance that the Company will be able to obtain sufficient funds to continue the development of its properties and, if successful, to commence the sale of its projects under development.  As a result of the foregoing, there exists substantial doubt about the Company's ability to continue as a going concern.  These financial statements do not include any adjustments that might result from the outcome of this uncertainty.

During the period ended April 30, 2015, the Company sold its remaining 617,929 shares of Lexaria generating $59,718 in proceeds and realizing a loss of $150,378.

Accounts receivable consists of revenues receivable, interest receivable and other receivable.  The revenue receivable are from the operators of the oil and gas projects for the sale of oil and gas by the operators on the Company's behalf and are carried at net receivable amounts less an estimate for doubtful accounts.  Management considers all accounts receivable to be fully collectible at April 30, 2015 and October 31, 2014.  Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.

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4.	OIL AND GAS INTERESTS   The Company holds the following oil and natural gas interests:

 

 

		April 30, 2015				October 31, 2014
2008-3 Drilling Program, Oklahoma		$	314,819			$	312,794
2009-2 Drilling Program, Oklahoma			114,420				114,420
2009-3 Drilling Program, Oklahoma			353,399				353,399
2009-4 Drilling Program, Oklahoma			190,182				190,182
2010-1 Drilling Program, Oklahoma			(47,813	)			(47,813	)
Washita Bend 3D, Oklahoma			816,618				926,598
Double T Ranch #1 SWDW, Oklahoma			53,632				51,816
Kings City Prospect, California			406,766				406,766
South Wayne Prospect, Oklahoma			61,085				61,085
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi			(222,123	)			(222,123	)
Three Sands Project, Oklahoma			555,715				555,715
Asset retirement cost			2,604				2,689
Less: Accumulated depletion and impairment			(2,293,326	)			(1,754,026	)
		$	305,978			$	951,502

 

2008-3 Drilling Program, Oklahoma

On January 12, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation's 2008-3 Drilling Program.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The Before Casing Point Interest ("BCP") is 6.25% and the After Casing Point Interest ("ACP") is 5.00%.  At April 30, 2015, the total cost of the 2008-3 Drilling Program was $314,819.  The interests are located in Garvin County, Oklahoma.

2009-2 Drilling Program, Oklahoma (continued)

On June 19, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation's 2009-2 Drilling Program.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At April 30, 2015, the total cost of the 2009-2 Drilling Program was $114,420.  The interests are located in Garvin County, Oklahoma.

2009-3 Drilling Program, Oklahoma

On August 12, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation's 2009-3 Drilling Program.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP is 5.00%.  At April 30, 2015, the total cost of the 2009-3 Drilling Program was $353,399.  The interests are located in Garvin County, Oklahoma.

2009-4 Drilling Program, Oklahoma

On December 19, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation's 2009-4 Drilling Program.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  At April 30, 2015, the total cost of the 2009-4 Drilling Program was $190,182.  The interests are located in Garvin County, Oklahoma.

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2010-1 Drilling Program, Oklahoma

On April 23, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation's 2010-1 Drilling Program.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  

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

Washita Bend 3D Exploration Project, Oklahoma

On March 1, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation's Washita Bend 3D Exploration Project.  The BCP Interest is 5.625% and the ACP Interest is 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells.  At April 30, 2015, the total costs including seismic costs, was $816,618.

As a result of seismic evaluation and analysis, eight initial prospects at the Washita Bend Project have been identified.  Lucretia #1-14 was the first well drilled on May 14, 2013.  This well was classified as a dry hole on May 27, 2013.  On August 1, 2013, Karges #1-35 was also classified as a dry hole. On September 4, 2013, Carol #1-22 was plugged and abandoned.  The costs of $148,391 associated therewith have been moved to proved properties. During November 2013, Bunch #1-17 started production, the costs of $76,890 have been moved to proved properties. On March 20, 2014, Hamilton 1-5 was plugged and abandoned.  The costs of $44,793 associated therewith have been moved to proved properties.

On December 9, 2014, the Company agreed to forfeit all of its right, title, interest, and ownership of any kind in and to the Washita Bend 3D Exploration Program.  The Company also agreed that Ranken Energy Corporation exchanged Brinx's joint interest billing balance through October 31, 2014 in the amount of $38,167 for all right, title, interest and ownership of any kind in the Bunch#1-17 well and Cross Bow prospect, effective November 1, 2014.  All costs related to this project were moved to the proved property pool during the quarter ending January 31, 2015.

Double T Ranch#1 SWDW, Oklahoma

On July 17, 2012, the Company acquired a 3.00% working interest in the drilling, completion and operations of the Double T Ranch#1 SWDW located in Garvin County from Ranken Energy Corporation.  At April 30, 2015, the cost of the Double T Ranch#1 SWDW was $53,632 and was moved to the proved property pool.

South Wayne Prospect, Oklahoma

On March 14, 2010, the Company acquired a 5.00% working interest in McPherson#1-1 well for a payment for leasehold, prospect and geophysical fees of $5,000, and dry hole costs of $32,370.  The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  The interests are located in McClain County, Oklahoma.  The total cost of the South Wayne prospect as at April 30, 2015 was $61,085.

 

 

 

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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 if lower, of unproved interests.  There was $596,203 and $nil impairment cost for the six-month periods ended April 30, 2015 and 2014, respectively.  The large impairment recorded during the quarter ended January 31, 2015 was primarily related to the termination of our working interest agreement in Washita and all costs being moved to the proved pool.

Depletion

Under the full cost method, depletion is computed on the units of production method based on proved reserves.  Depletion expense recognized was $16,765 and $42,884 for the six-month periods ended April 30, 2015 and 2014, respectively.

 

			April 30, 2015				October 31, 2014
	Proved properties		$	2,599,304			$	2,061,127
	Unproved properties			-				644,401
	Total Proved and Unproved properties			2,599,304				2,705,528
	Accumulated depletion expense			(899,469	)			(921,402	)
	Impairment			(1,393,857	)			(832,624	)
	Net capitalized cost		$	305,978			$	951,502

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

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 April 30, 2015 and October 31, 2014, the Company recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with "Accounting for Asset Retirement Obligations".  The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production.  The Company amortizes the amount added to the oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining life of the respective well.  The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to

 

 

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5.	ASSET RETIREMENT OBLIGATIONS (continued)

plug and abandon wells in the future and federal and state regulatory requirements.  The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.  Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.

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

The information below reflects the change in the asset retirement obligations during the six-month period ended April 30, 2015 and year ended October 31, 2014:

The reclamation obligation relates to the Ard#1-36, Bagwell#1-20, Bagwell#2-20, Miss Gracie#1-18, Joe Murray Farm#1-18, Gehrke#1-24, Jack#1-13, Jackson 1-18, and Double T Ranch at Oklahoma Properties, and McPherson#1-1 well at South Wayne Prospect.  The present value of the reclamation liability may be subject to change based on management's current estimates, changes in remediation technology or changes in applicable laws and regulations.  Such changes will be recorded in the accounts of the Company as they occur.

PREFERRED STOCK

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

  (a) amend, alter, or repeal any provision of the Articles of Incorporation or the Bylaws of the Company (including any filing of a Certificate of Designation)   that alters or changes the voting powers, preferences, or other special rights or privileges, or restrictions of the Series A Preferred Stock;

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

 

 

 

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PREFERRED STOCK (continued)

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

(d) purchase or otherwise acquire any share or shares of Preferred Stock or Common Stock (or pay into or set aside for a sinking fund for such purpose); provided, however, that this restriction shall not apply to the repurchase of shares of Common Stock from employees, officers, directors, consultants or other persons performing services for the Company or any subsidiary pursuant to agreements under which the Company has the option to repurchase such shares at cost or at cost upon the occurrence of certain events, such as the termination of employment;

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

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

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

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

During the six-month period ended April 30, 2015 and 2014, the Company entered into the following transactions with related parties:

a)	The Company paid or accrued $42,000 (2014 - $42,000) to a related entity, for administration services.

b)	The Company paid or accrued $81,000 (2014 - $81,000) in management fees to the director and President of the Company.

c)	The Company paid or accrued $18,000 (2014 - $18,000) in consulting fee to the director of the Company.

As at April 30, 2015, there was $117,000 (2014 - $ nil) due to the related parties in accounts payable and accrued liabilities.

 

 

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The Company collected $9,256 (2014: $99,798) or 99% (2014: 95%) of its revenues from one of its operators during the six-month period ended April 30, 2015. As of April 30, 2015, $1,169 (2014: $14,422) was due from this operator.

Hamm Litigation

In September 2010, two lawsuits were filed in the District Court of Garvin County in the State of Oklahoma by Harold Hamm ("Hamm") against certain defendants ("Defendants") and consolidated together alleging, among other things, that Hamm owns an interest in two oil and gas leases in Garvin County and is entitled to a 50% participatory interest.  The Company was not named as a party in these legal proceedings, but Hamm's allegations include that he is entitled to a 50% participatory interest in the Joe Murray Farms well drilled as part of the 2009-3 Drilling Program, in which the Company purchased a 6.25% working interest before casing point and 5.0% working interest after casing point.  The Defendants and the Company believe that there is no merit to Hamm's allegations.  In connection with these proceedings, the Defendants were ordered in January 2011 to escrow fifty percent (50%) of the revenues generated within the subject area pending the outcome of these proceedings.  For this reason, fifty percent (50%) of the revenues the Company is entitled to that have been generated by production from the Joe Murray Farms well is being escrowed and there is no assurance that the Company will be able to recover these proceeds.  The Company recognized $ nil in revenue during the six months ended April 30, 2015, and $7,643 in revenue during the year ended October 31, 2014. As at April 30, 2015, revenue from the Joe Murray Farms totaling $190,448 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

Beckett Complaint

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

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Overview

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

Our original business plan was to proceed with the exploration of the Antelope Pass Project to determine whether there were commercially exploitable reserves of gold located on the property comprising the mineral claims.  Based on the geological report and recommendation prepared by Leroy Halterman, who was our geological consultant at that time, we completed geological mapping, sampling and assaying in connection with the first phase of a staged exploration program during the fiscal year ended October 31, 2004.  In 2005, we suspended our activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on the Antelope Pass Project during the past few years.  The Company allowed the lease to expire during the six months ended January 31, 2014.

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

Oil and Gas Properties

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

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

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

Note that all production amounts disclosed for the individual properties below are for the Company's working interest.

2008-3 Drilling Program, Oklahoma.  On January 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation's 2008-3 Drilling Program for a total buy-in cost of $28,581.  We agreed to participate in the drilling operations to casing point in the initial test well of each prospect.  The BCP Interest is 6.25% and the ACP Interest is 5.00%.  The total cost of the 2008-3 Drilling Program as of April 30, 2015 was $314,819.  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.  For the six months ended April 30, 2015, the three producing wells in this program have produced a total of 72 Bbls of oil and nil Mcf of natural gas. 

 

 

 

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2009-2 Drilling Program, Oklahoma.  On June 15, 2009, we acquired a 5% working interest in Ranken Energy Corporation's 2009-2 Drilling Program located in Garvin County, Oklahoma.  As of April 30, 2015, the total cost of the 2009-2 Drilling Program was $114,420.  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.

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 is 6.25% and the ACP Interest is 5.00%.  The total costs incurred, including drilling costs, as of April 30, 2015 was $353,399.  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.  This well only produced for a few days before snow and ice storms forced shutting the well in because the produced oil and water could not be hauled away from the location and the storage tanks for these liquids were full.  The well is now producing oil and gas with the use of a pumping unit.  The second well that also had a flowing drill stem test was completed in late March 2010 and that well is currently producing oil and natural gas with the use of a pumping unit.  Total production from these two producing wells for the six months ended April 30, 2015 totaled 59 Bbls of oil and nil Mcf of natural gas.

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

2009-4 Drilling Program, Oklahoma.  On December 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation's 2009-4 Drilling Program 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 is 6.25% and the ACP Interest is 5.00%.  The total costs incurred, including drilling costs, as of April 30, 2015 was $190,182.  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.  The other well has been converted to a salt water disposal well.  As of April 30, 2015, there has been no production of hydrocarbons.

2010-1 Program, Oklahoma. On April 23, 2010, we acquired a 5% working interest in Ranken Energy Corporation's 2010-1 Drilling Program 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 is 6.25% and the ACP Interest is 5.00%.  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.

 

 

 

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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 showed excellent porosity, permeability, and hydrocarbon shows.  All three of the wells were completed in the deepest pay zone.  The third well in this program is currently shut-in.  Total production from these wells for the six months ended April 30, 2015 was 39 Bbls of oil and 355 Mcf of natural gas.

On January 1, 2014, we sold all of our working interest in Miss Jenny #1-8 for $275,147 less sales commission as part of the sale of 100% of the well by its operator.

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 is 6.25% and the ACP Interest is 5.00%.  The total cost incurred, including drilling costs, as of April 30, 2015 was $61,085.  The well and related leasehold interests are located in McClain County, Oklahoma.  The well was perforated in July 2010 and immediately started flowing oil at a rate of 200 Bbls per day.  The flow of oil was slowed and stopped due to a buildup of paraffin.  A pumping unit was placed on the well in late August 2010.  Total production for the McPherson well for the six months ended April 30, 2015 was nil Bbls of oil and nil Mcf of natural gas.  Additional pay zones are located above the currently producing horizon and it is anticipated that these zone will be perforated in the future adding additional production to the well.

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

All of the project area, which covers approximately 86,350 acres or 135 square miles, was permitted and shot and data acquired.  All initial or first run processing data was completed and interpretation of the data and mapping as well as prospect delineation started.  Title research and leasing on a number of potential prospects was completed.  A total of 5,148 acres of leases were acquired.  As a result of seismic evaluation and analysis, eight initial prospects were identified, with the first well (Lucretia #1-14) drilled on May 14, 2013.  On May 27, 2013, this well was classified as a dry hole.  On August 1, 2013, Karges #1-35 was also classified as a dry hole.  On September 4, 2013, Carol #1-22 was drilled and completed with no economic hydrocarbons present.  The costs associated with this well were moved to the proved property pool.  During November 2013, Bunch #1-17 started production, and the costs of $76,890 were moved to proved properties.  On March 20, 2014, Hamilton #1-5 was plugged and abandoned.  The costs of $44,793 associated therewith have been moved to proved properties.

On December 9, 2014, we agreed to forfeit all of our right, title, interest, and ownership of any kind in and to the Washita Bend 3D Exploration Program.  We also agreed that Ranken Energy Corporation exchanged our joint interest billing balance through October 31, 2014 in the amount of $38,167 for all right, title, interest and ownership of any kind in the Bunch #1-17 well and Cross Bow prospect, effective November 1, 2014.  All costs related to this project were moved to the proved property pool during the quarter ended January 31, 2015.

Double T Ranch#1 SWDW, Oklahoma.  On July 17, 2012, we acquired a 3.00% working interest in the drilling, completion and operations of the Double T Ranch#1 SWDW located in Garvin County from Ranken Energy Corporation.  At April 30, 2015, the cost of the Double T Ranch#1 SWDW was $53,632 and was moved to the proved property pool.

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 called 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

 

 

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gravity and seismic surveys and agreeing to carry Sunset Exploration for 33.33% of dry hole cost of the first well.  Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres were to be proportionate to each party's working interest.  The geophysical surveys have been completed and most have been processed and interpreted.  The initial surveys indicated that several more short geophysical survey lines would improve the interpretation.  These additional lines have been completed and subsequently several stages of reprocessing have been applied to the original data.  In midsummer 2011, permitting of the first drill hole began and the well was completed in January 2012.  On April 15, 2013, we elected to plug and abandon this well.  All costs associated with this well have been moved to the proved property pool for depletion.  After further and in-depth evaluation and consultation, we have elected not to participate any further at King City as we deem this project not to be economically viable.  As at April 30, 2015, the total costs were $406,766.

International Exploration Program

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

Mineral Interests

Antelope Pass.  In 2005, we suspended our activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on the Antelope Pass Project during the past few years.  The claims were allowed to lapse during the three months ended January 31, 2014.

Results of Operations

Three months ended April 30, 2015 compared to the three months ended April 30, 2014.  We realized revenues of $2,527 during the three months ended April 30, 2015, compared with $20,952 during the three months ended April, 2014, a decrease of $18,425, due primarily to a decrease in the number of producing wells.  During the three-month period ended April 30, 2015, 72 Bbls of oil and 209 Mcf of gas (net to our working interest) were produced at our oil and gas properties, as compared to 345 Bbls of oil and 250 Mcf of gas for the three months ended April 30, 2014.  The decrease in production was due primarily to a decrease in the number of producing wells caused by the sale of our interest in the Miss Jenny #1-8, the exchange of the Bunch #1-17 for our outstanding joint interest billing balance, and the natural decline in reserves.

 

We incurred production costs of $6,554 during the three months ended April 30, 2015, compared with $8,692 during the three months ended April 30, 2014, a decrease of $2,138.  Our production costs decreased as a result of a decrease in the number of producing wells and a decrease in our oil and gas production.

Our general and administrative costs increased to $133,839 for the three months ended April 30, 2015, from $112,863 for the three months ended April 30, 2014.  The increase of $20,976 is primarily attributable to amounts paid for filing fees and production and preparation of the reserve report.

There were no write downs or write-offs during the three months ended April 30, 2015.  We wrote off $3,101 in undeveloped mineral interests for the fiscal year ended October 31, 2014, as we allowed our mineral claims to lapse.

We incurred a loss on the sale of marketable security of $150,378 for the three months ended April 30, 2015, as compared to $nil for the three months ended April 30, 2014.

 

 

 

 

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For the three months ended April 30, 2015, we incurred a net loss of $293,503 compared to a net loss of $109,605 for the three months ended April 30, 2014.  The increase in net loss was attributable primarily to the loss on the sale of marketable security.

As a result of our net loss for the quarter, we had a retained loss of $2,703,549 at April 30, 2015.

Six months ended April 30, 2015 compared to the six months ended April 30, 2014.  We realized revenues of $9,348 during the six months ended April 30, 2015, compared with $104,517 during the six months ended April, 2014, a decrease of $95,169, due primarily to a decrease in the number of producing wells.  During the six-month period ended April 30, 2015, 174 Bbls of oil and 355 Mcf of gas (net to our working interest) were produced at our oil and gas properties, as compared to 1,070 Bbls of oil and 411 Mcf of gas for the six months ended April 30, 2014.  The decrease in production was due primarily to a decrease in the number of producing wells caused by the sale of our interest in the Miss Jenny #1-8, the exchange of the Bunch #1-17 for our outstanding joint interest billing balance, and the natural decline in reserves.

 

We incurred production costs of $15,048 during the six months ended April 30, 2015, compared with $20,102 during the six months ended April 30, 2014, a decrease of $5,054.  Our production costs decreased as a result of a decrease in the number of producing wells and a decrease in our oil and gas production.

Our general and administrative costs increased to $253,772 for the six months ended April 30, 2015, from $231,382 for the six months ended April 30, 2014.  The increase of $22,390 is primarily attributable to amounts paid for filing fees and production and preparation of the reserve report.

We wrote down $596,203 of our natural gas and oil properties during the six months ended April 30, 2015 due to the third party evaluation of the Company's reserves being significantly less than the book value on the balance sheet.  We wrote off $3,101 in undeveloped mineral interests for the fiscal year ended October 31, 2014, as we allowed our mineral claims to lapse.

We incurred a loss on the sale of marketable security of $150,378 for the six months ended April 30, 2015, as compared to $nil for the six months ended April 30, 2014.

For the six months ended April 30, 2015, we incurred a net loss of $1,025,299 compared to a net loss of $195,108 for the six months ended April 30, 2014.  The increase in net loss was attributable primarily to the impairment charge, loss on the sale of marketable security, and decrease in revenues for the period.

Liquidity and Capital Resources

 

As of April 30, 2015, we had cash of $52,308 and a working capital deficit of $80,157, compared to cash of $109,953 and working capital of $124,202 as of October 31, 2014.  The decrease in cash and working capital is due primarily to the loss for the six months ended April 30, 2015.

During the six months ended April 30, 2015, operating activities used cash of $111,667, as compared to net cash used of $183,770 for the six months ended April 30, 2014.  The adjustments of $596,203 for the writedown of natural gas and oil properties and $150,378 for the realized loss on sale of marketable security were not enough to offset the net loss of $1,025,299 for the 2015 period.

Investing activities, primarily the sale of marketable security, provided cash of $54,022 during the six months ended April 30, 2015, compared with $285,946 provided during the six months ended April 30, 2014.  In 2014, payments on oil and gas interests were higher by $83,506, but were offset by $275,148 in proceeds from the sale of our working interest and $100,000 from the redemption of a certificate of deposit.

 

 

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Off-Balance Sheet Arrangements

As of April 30, 2015, we did not have any off-balance sheet arrangements.  

Critical Accounting Policies

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

Capitalized costs of oil and gas interests may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved interests.  Should capitalized costs exceed this ceiling, an impairment is recognized.  The present value of estimated future net cash flows is computed by applying average prices, in the preceding twelve months, of oil and gas to estimated future production of proved oil and gas reserves as of year ends, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Subsequent to October 31, 2014, there have been significant declines in oil prices that may adversely affect our financial position and results of operations.  If the current downward trend in oil prices continues, there is a reasonable likelihood that we could incur impairment to our full cost pool in fiscal 2015 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12 month period under the SEC pricing methodology.

Asset Retirement Obligations. We follow FASB ASC 410-20 "Accounting for Asset Retirement Obligations," which  addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  FASB ASC 410-20 requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred.  As of April 30, 2015 and October 31, 2014, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with FASB ASC 410-20.  The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production.  We amortize the amount added to the oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining life of the respective wells. The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.  Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells

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

The information below reflects the change in the asset retirement obligations during the six-month period ended April 30, 2015 and the year ended October 31, 2014:

 

 

 

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The reclamation obligation relates to the Ard#1-36, Bagwell#1-20, Bagwell#2-20, Miss Gracie #1-18, Joe Murray Farm #1-18, Gehrke#1-24 and Jack#1-13, Jackson #1-18, and Double T Ranch wells at Oklahoma Properties, and McPherson#1-1 well at South Wayne Prospect.  The present value of the reclamation liability may be subject to change based on management's current estimates, changes in remediation technology or changes in applicable laws and regulations.  Such changes will be recorded in our accounts as they occur.

Reserve Estimates.  Our estimates of oil and natural gas reserves are projections based on an interpretation of geological and engineering data.  There are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures.  Estimates of the economically   recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on the risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially.  Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Forward Looking Statements

Certain statements in this Quarterly Report on Form 10-Q as well as statements made by us in periodic press releases and oral statements made by our officials to analysts and shareholders in the course of presentations about the Company, constitute "forward-looking statements".   Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward looking statements.  Such factors include, among other things, (1) general economic and business conditions; (2) interest rate changes; (3) the relative stability of the debt and equity markets; (4) government regulations particularly those related to the natural resources industries; (5) required accounting changes; (6) disputes or claims regarding our property interests; and (7) other factors over which we have little or no control.

Not required for smaller reporting companies.

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures, as defined in Rule 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act"), are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Act is accumulated and communicated to our officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Rule 15d-15 under the Exchange Act, requires us to carry out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of April 30, 2015, being the date of our most recently completed fiscal quarter.  This evaluation was conducted under the supervision and with the participation of our sole officer, Ken Cabianca.  Based on this evaluation, Mr. Cabianca concluded that the design and operation of our disclosure controls and procedures are not effective because of the following material weaknesses that existed at April 30, 2015:

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

 

 

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

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

Changes in Internal Controls Over Financial Reporting

In connection with the evaluation of our internal controls during our last fiscal quarter, our officers have concluded that there were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended April 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Hamm Litigation

In September 2010, two lawsuits were filed in the District Court of Garvin County in the State of Oklahoma by Harold Hamm ("Hamm") against certain defendants ("Defendants") and consolidated together alleging, among other things, that Hamm owns an interest in two oil and gas leases in Garvin County and is entitled to a 50% participatory interest.  We were not named as a party in these legal proceedings, but Hamm's allegations include a claim that he is entitled to a 50% participatory interest in the Joe Murray Farms well drilled as part of the 2009-3 Drilling Program, in which we purchased a 6.25% working interest before casing point and 5.0% working interest after casing point.  We and the Defendants believe that there is no merit to Hamm's allegations.  In connection with these proceedings, the Defendants were ordered in January 2011 to escrow fifty percent (50%) of the revenues generated within the subject area pending the outcome of these proceedings.  For this reason, fifty percent (50%) of the revenues we are entitled to that have been generated by production from the Joe Murray Farms well is being escrowed and there is no assurance that we will be able to recover these proceeds.  The Company recognized $nil in revenue during the six months ended April 30, 2015, and $7,643 in revenue during the year ended October 31, 2014. As at April 30, 2015, revenue from the Joe Murray Farms totaling $190,448 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

Beckett Complaint

In April 2013, Jeffrey R. Beckett, one of our shareholders, filed a lawsuit in the District Court of Washoe County, Nevada against us, our directors, Kenneth A. Cabianca and George Knight, and a principal of one of our consultants, Sarah Cabianca, generally alleging mismanagement of our affairs by our directors to our detriment and the detriment of our shareholders (the "State Lawsuit").  The State Lawsuit seeks the issuance of an injunction, the appointment of a receiver and unspecified damages.  In June 2013, Mr. Beckett filed a similar complaint against the same defendants in the United States District Court for the District of Nevada (the "Federal Lawsuit").  Sarah Cabianca has been dismissed from the State Lawsuit and the Federal Lawsuit has been dismissed.  We believe the State Lawsuit has been improperly brought and lacks merit, and are vigorously defending the State Lawsuits.  

Not required for smaller reporting companies.

None.

None.

Not applicable.

Not applicable.

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

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

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

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

(5)	Incorporated by reference to the exhibits to the registrant's annual report on Form 10-K for the fiscal year ended October 31, 2011, filed February 14, 2012.

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

	BRINX RESOURCES LTD.
	(Registrant)
June 15, 2015	By: /s/ Ken Cabianca
	Ken Cabianca                      President and Acting Chief Financial Officer                      (principal executive and financial officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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