f10q-043010.htm

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).

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PART I.	UNAUDITED FINANCIAL INFORMATION

Item 1.	Interim Financial Statements	3

	Balance Sheets April 30, 2010 (unaudited) and October 31, 2009	4

	Statements of Operations (unaudited) Three Months and Six Months Ended April 30, 2010 and 2009	5

	Statements of Cash Flows (unaudited) Six Months Ended April 30, 2010 and 2009	6

	Notes to Financial Statements (unaudited)	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23

Item 4.	Controls and Procedures	23

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	24

Item 1A.	Risk Factors	24

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	24

Item 3.	Defaults Upon Senior Securities	24

Item 4.	Removed and Reserved	24

Item 5.	Other Information	24

Item 6.	Exhibits	24

Signatures		26

BRINX RESOURCES LTD.
BALANCE SHEETS

	APRIL 30,		OCTOBER 31,
	2010		2009
ASSETS	(UNAUDITED)		(AUDITED)

Current assets
Cash and cash equivalents	$	1,371,495	$	1,947,950
Accounts receivable		82,538		97,198
Income taxes receivable		254,000		253,814
Prepaid expenses and deposit		276,260		270,610

Total current assets		1,984,293		2,569,572

Undeveloped mineral interests, at cost		811		811

Oil and gas interests, full cost method of accounting,
net of accumulated depletion		1,868,466		1,637,010

Total assets	$	3,853,570	$	4,207,393


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
Accounts payable and accrued liabilities	$	23,620	$	75,185

Total current liabilities		23,620		75,185

Asset retirement obligations		39,231		37,011

Total liabilities		62,851		112,196


Stockholders' equity
Preferred stock - $0.001 par value; authorized - 1,000,000 shares
Issued - none		-		-

Common stock - $0.001 par value; authorized - 100,000,000 shares
Issued and outstanding - 24,629,832 shares		24,630		24,530

Capital in excess of par value		2,859,599		2,801,991

Retained earnings		906,490		1,268,676

Total stockholders' equity		3,790,719		4,095,197

Total liabilities and stockholders' equity	$	3,853,570	$	4,207,393

BRINX RESOURCES LTD.
STATEMENTS OF OPERATIONS
(UNAUDITED)

	FOR THE THREE MONTHS						FOR THE SIX MONTHS
	PERIOD ENDED						PERIOD ENDED
	APRIL 30,						APRIL 30,
	2010			2009			2010			2009

REVENUES
Natural gas and oil sales	$	107,030		$	42,150		$	228,056		$	110,279

DIRECT COSTS
Production costs		25,110			22,042			42,688			52,456
Depletion and accretion		31,473			29,073			69,012			72,278
General and administrative		210,986			154,724			479,463			272,063

Total Expenses		(267,569	)		(205,839	)		(591,163	)		(396,797	)

OPERATING INCOME (LOSS)		(160,539	)		(163,689	)		(363,107	)		(286,518	)

OTHER INCOME AND EXPENSE
Interest income		921			-			921			1,291

NET INCOME (LOSS) FOR THE PERIODS	$	(159,618	)	$	(163,689	)	$	(362,186	)	$	(285,227	)

Net Income Per Common Share
- Basic	$	(0.007	)	$	(0.007	)	$	(0.015	)	$	(0.012	)
- Diluted	$	(0.007	)	$	(0.007	)	$	(0.015	)	$	(0.012	)

Weighted average number of common shares outstanding
- Basic		24,629,832			24,529,832			24,579,003			24,529,832
- Diluted		24,629,832			24,529,832			24,579,003			24,529,832

BRINX RESOURCES LTD.
STATEMENTS OF CASH FLOWS
(UNAUDITED)

	FOR THE SIX MONTHS
	PERIOD ENDED
	APRIL 30,
	2010			2009
CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES

Net income (loss)	$	(362,186	)	$	(285,227	)

Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Stock based compensation (note 5)		30,708			-
Depletion and accretion		69,012			72,278
Shares issued to Investor Relations Services Inc. for services rendered		27,000			-

Changes in working capital:
Decrease (Increase) in accounts receivable		14,660			39,612
Decrease (Increase) in prepaid expenses and deposit		(5,650	)		3,308
Increase (Decrease) in accounts payable and accrued liabilities		(51,565	)		5,916
Increase (Decrease) in income taxes receivable		(186	)		-
Increase (Decrease) in income taxes payable		-			(580,000	)

Net cash provided by (used in) operating activities		(278,207	)		(744,113	)

CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES

Payments on oil and gas interests		(298,248	)		(238,044	)

Net cash provided by (used in) investing activities		(298,248	)		(238,044	)

CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES

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

Net cash (used in) financing activities		-			-

Net increase (decrease) in cash		(576,455	)		(982,157	)

Cash and cash equivalents, beginning of periods		1,947,950			3,617,109

Cash and cash equivalents, end of periods	$	1,371,495		$	2,634,952


SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for taxes paid	$	1,386		$	-

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

Assets retirement costs incurred	$	(2,220	)	$	(1,846	)

Investment in natural oil and gas working interests included in	$	13,556		$	-
accounts payable

Brinx Resources Ltd. (the “Company”) was incorporated under the laws of the State of Nevada on December 23, 1998, and issued its initial common stock in February 2001. The Company holds undeveloped mineral interest located in New Mexico and holds oil and gas interests located in Oklahoma, California, Mississippi and Louisiana. In 2006, the Company commenced oil and gas production and started earning revenues. Prior to 2006, the Company was considered a development stage company as defined by FASB ASC 915 (prior authoritative literature: SFAS No. 7), effective 2006, the Company ceased being considered a development stage company.

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 months period ended April 30, 2010 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, 2009.

Except for the historical information contained in this Form 10-Q, this Form contains forward-looking statements that involve risks and uncertainties. The Company’s actual results could differ materially from those discussed in this Report. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in this Report and any documents incorporated herein by reference, as well as the Annual Report on Form 10-K for the year ended October 31, 2009.

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 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).

The Company utilizes the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration; are capitalized within a cost center. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas interests unless the sale represents a significant portion of oil and gas interests and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas interests is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production. Amortizable costs include estimates of future development costs of proved undeveloped reserves.

Capitalized costs of oil and gas interests may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved interests. Should capitalized costs exceed this ceiling, and impairment is recognized. The present value of estimated future net cash flows is computed by applying year end prices 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 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, 2010 and 2009, the Company had no overproduced imbalances.

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 convertible securities is reflected in diluted earnings per share by application of the "as if converted method." The dilutive effect of outstanding options and warrants and their equivalents is reflected in diluted earnings per share by application of the treasury stock method. Hence 500,000 options were excluded from the earnings per share calculation for the six months period ended April 30, 2010, since they were considered to be anti-dilutive. The table below presents the computation of basic and diluted earnings per share for the six months periods ended April 30, 2010 and 2009:

	April 30, 2010			April 30, 2009
Basic earnings per share computation:
Income (Loss) from continuing operations and net income	$	(362,186	)	$	(285,227	)
Basic shares outstanding		24,579,003			24,529,832
Basic earnings per share	$	(0.015	)	$	(0.012	)

Diluted earnings per share computation:
Income (Loss) from continuing operations	$	(362,186	)	$	(285,227	)
Basic shares outstanding		24,579,003			24,529,832
Incremental shares from assumed conversions:
Stock options		-			-
Warrants		-			-
Diluted shares outstanding		24,579,003			24,529,832
Diluted earnings per share	$	(0.015	)	$	(0.012	)

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; however, the at risk amounts were $1,121,495 for the six month period ended April 30, 2010 and $1,697,950 for the year ended October 31, 2009.

Effective November 1, 2006, the Company adopted the fair value recognition provisions of FASB ASC 718 (prior authoritative literature: SFAS No. 123R) “Share Based Payment” using the modified prospective method as described in “Accounting for Stock-Based Compensation – Transition and Disclosure”, as prescribed by the United States Securities and Exchange Commission (“SEC”).

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 April 30, 2010 and October 31, 2009. Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.

	April 30, 2010			October 31, 2009
2008-3 Drilling Program, Oklahoma	$	261,356		$	258,980
2009-2 Drilling Program, Oklahoma		114,030			82,935
2009-3 Drilling Program, Oklahoma		215,466			137,356
2009-4 Drilling Program, Oklahoma		97,578			-
Washita Bend 3D, Oklahoma		51,719			-
Kings City Prospect, California		100,000			100,000
Three Sands Project, Oklahoma		1,197,523			1,197,523
McPherson #1-1, Oklahoma		37,370			-
Palmetto Point Project, Mississippi		420,000			420,000
Frio-Wilcox Prospect, Mississippi		400,000			400,000
PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52, Mississippi		221,820			221,820
Asset retirement cost		22,949			22,949
Less: Accumulated depletion and impairment		(1,271,345	)		(1,204,553	)
	$	1,868,466		$	1,637,010

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%. During January to July 2009, the Company expended a $213,925 in addition to $18,850 that was spent in previous periods. The total cost of the 2008-3 Drilling Program as at April 30, 2010 was $261,356. The well, Wigley#1-11, was abandoned during March 2009. The cost of $31,170 was moved to the proved properties pool. As Selman#1-21 and Bagwell#1-20 started producing during May 2009, the costs of $70,025 for Selman#1-21 and $55,190 for Bagwell#1-20 were moved to the proved properties pool. Ard#1-36 started producing during June 2009 and the cost of $44,645 was moved to the proved properties pool. Selman#2-21 started producing during July 2009 and was abandoned on April 20, 2010; the cost of $60,326 was moved to the proved properties pool. The interests are located in Garvin County, 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 and the cost of $40,852 was moved to the proved properties pool. Little Chief#1-3 was abandoned on November 17, 2009 and the cost of $34,732 was moved to the proved properties pool. J.C. Carlton#1-31 was abandoned on April 30, 2010 and the cost of $38,446 was moved to the proved properties pool. As at April 30, 2010, the total cost of the 2009-2 Drilling Program was $114,030. The interests are located in Garvin County, 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 and an amount of $59,215 was moved to the proved properties pool. Miss Gracie#1-18 started producing during March 2010 and an amount of $63,228 was moved to the proved properties pool. As at April 30, 2010, the total cost of the 2009-3 Drilling Program was $215,466. The interests are located in Garvin County, Oklahoma.

On December 19, 2009, the Company acquired a 5.00% working interest in Ranken Energy Coporation’s 2009-4 Drilling Program for a total buy-in cost of $10,812 and leasehold costs of $2,670. 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 total cost incurred, including drilling costs, for the six-month period ended April 30, 2010 was $97,578.

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 agreeing to carry Sunset exploration for 40% 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.

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 during May to July 2008 for the KC 80#1-11 well. The total cost of the Three Sands Project as at April 30, 2010 was $1,197,523. The interests are located in 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 total costs incurred, including drilling costs, for the six-month period ended April 30, 2010 was $37,370. 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.

On February 28, 2006, the Company acquired a 10% working interest before production and 8.5% revenue interest after production in a 10 well program at Griffin & Griffin Exploration Inc.’s Palmetto Point Project for a total buy-in cost of $350,000. On September 26, 2006, the Company acquired an additional two wells within this program for $70,000. On October 1, 2007, the Company acquired a 10% working interest and participated in drilling two more wells within the Palmetto Point Project, the (PP F-12-2 and PP F-12-3 wells), at a cost of $69,862. On October 25, 2007, the Company paid $17,000 for a sidetrack, a deviation of the existing PP-F-12-3 well at an angle to reach additional targeted oil sands.

On January 30, 2008, the Company incurred $36,498 for work-overs to install submersible pumps and subsequently paid on February 1, 2008. During November 2008 to July 2009, the Company incurred $44,623 for Belmont Lake Project. The total cost of the Palmetto Point Project, which included costs for the PP F-12-2, PP F-12-3, PP F-12-4 and PP F-52 wells, is $641,820 as of April 30, 2010. The interests are located in Mississippi.

On August 2, 2006, the Company signed a memorandum agreement with Griffin & Griffin LLC (the “Operator”) to participate in two proposed drilling programs located in Mississippi and Louisiana. The Company acquired a 10% working interest in this project before production and a prorated reduced working interest after production based on the Operator’s interest portion. The Company paid $400,000 for the interest.

On June 21, 2007, the Company assigned all future development obligations for any new well at its Frio-Wilcox Prospect to a third party. The Company maintained its original interest, rights, title and benefits to all seven wells drilled with the Company’s participation at the Frio-Wilcox Prospect property between August 3, 2006 and June 19, 2007, specifically wells CMR-USA-39-14, Dixon #1, Faust #1 TEC F-1, CMR/BR F-14, RB F-1 Red Bug #2, BR F-33, and Randall #1 F-4, and any offset wells that could be drilled to any of these specified wells.

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 six months periods ended April 30, 2010 or 2009, respectively.

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 $66,792 and $70,432 for the six- month periods ended April 30, 2010 and 2009, respectively.

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, 2010 and October 31, 2009, 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%.

The reclamation obligation relates to the Kodesh, Dye Estate, KC 80 and William wells at the Three Sands Property; the Palmetto Point Project well at the Frio-Wilcox Project; and ARD#1-36, Bagwell#1-20, Selman#1-21 and Selman#2-21 wells at Oklahoma Properties. The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes in applicable laws and regulations. Such changes will be recorded in the accounts of the Company as they occur.

On November 2, 2007, the Company granted a non-qualified stock option with respect to 200,000 shares to the President. The exercise price is $0.24 per share. The Option shall expire and be canceled two years from the Grant Date and is one hundred percent (100%) vested as of the Grant Date. The Company recorded a total of $26,077 for stock compensation expenses.

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 will fully vest in six months and expire in two years from the Grant Date. The Company recorded a total of $12,322 and $136 and for stock compensation expenses for the six months ended April 30, 2010 and the year ended October 31, 2009.

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 will fully vest in six months and expire in two years from the Grant Date. The Company recorded a total of $18,386 for stock compensation expenses for the six months ended April 30, 2010.

	Options Outstanding
	Number of Shares			Weighted Average
				Exercise Price
Balance, October 31, 2008		200,000		$	0.24
Grant on October 30, 2009		200,000			0.10
Exercised		-			-
Balance, October 31, 2009		400,000			0.17
Granted on November 2, 2009		300,000			0.10
Expired on November 2, 2009		(200,000	)		0.24
Exercised		-			-
Balance, April 30, 2010		500,000		$	0.10

Our original business plan was to proceed with the exploration of the Antelope Pass Project to determine whether there were commercially exploitable reserves of gold located on the property comprising the mineral claims. Based on the geological report and recommendation prepared by Leroy Halterman, who was our geological consultant at that time, we completed geological mapping, sampling and assaying in connection with the first phase of a staged exploration program during the fiscal year ended October 31, 2004. In 2005, we suspended our activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on the Antelope Pass Project during the fiscal years ended October 31, 2009 or 2008 or the six months ended April 30, 2010. At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project.

“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.

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 an additional $213,925. The total cost of the 2008-3 Drilling Program as of April 30, 2010 was $261,356. 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. All four completed wells are producing commercial quantities of oil and gas with one well producing most of the oil. As of April 30, 2010, the wells in this program have produced a total of 109,506 Bbls of oil and 40,402 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 $26,562. 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, Deesse 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 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, for the six-month period ended April 30, 2010 was $215,466. 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 test 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 as a flowing oil and gas well. The well was flowing naturally at rates between 400 and 500 barrels 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 the recent 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 and selling oil and natural gas. The second well that also had a flowing drill stem test was completed in late March and that well is currently producing as a naturally flowing oil and gas well. Total production from these two producing wells as of April 30, 2010 totaled 12,842 barrels of oil and 7,136 mcf of natural gas. In mid-May, we drilled an offset well that is still flowing naturally and producing approximately 270 barrels of oil per day. Drilling of the new development well will start in early June.

The two reaming wells were completed in late May. One well awaited a natural gas pipeline to complete before it could be produced. The pipeline was completed in late May and the well is now producing and selling both oil and gas at rates of 5 barrels of oil per day and over three-quarter of a million cubic feet of natural gas. The second well after testing was deemed to be noncommercial and will be plugged and abandoned.

2009-4 Program, Oklahoma. On December 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $10,812. 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, for the six-month period ended April 30, 2010 was $97,578. 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 and reached total depth on February 20, 2010. The second well drilling started in late February 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 continues to be a problem with heavy rain causing flooding and other delays. Completion efforts have started on the first well and it may be several weeks before completion starts on the second well.

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. 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, for the six-month period ended April 30, 2010 was

Washita Bend 3D Exploration Project, Oklahoma. On March 1, 2010, we agreed to participate with a 5% interest in a 3-D seismic program managed by an experienced local operator 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. Brinx 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 costs, including seismic costs, for the six-month period ended April 30, 2010 was $51,719.

Three Sands Project. On October 6, 2005, we acquired a 40% working interest in Vector Exploration Inc.’s Three Sands Project for a total buy-in cost of $88,000 plus dry hole costs (the “Three Sands Project”). The Three Sands Project is located in Oklahoma. For the year ended October 31, 2006, we expended $530,081 in exploration costs. In June 2007, we acquired a 40% working interest in the William #4-10 well for a total cost of $285,196 and paid a further $17,000 in costs relating to the well. On March 19, 2008, we participated in the KC 80 #1-11 well and paid $75,000 for the prepaid drilling costs. During March and April 2008, we expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 during May to July 2008. The total cost of the Three Sands Project as of April 30, 2010 was $1,197,523. Our working interest in the Three Sands Project includes leasehold interests, one re-entry production well, and two drilling wells. We also participate in drilling operations and related costs, in proportion to our working interest.

Drilling of the Kodesh #1 disposal well was completed on October 3, 2005 and drilling of the Kodesh #2 well was completed on October 23, 2005. Completion and equipping of these wells took place during mid-December 2005 through early January 2006. The Kodesh #1 is being used as a salt water disposal well. The Kodesh #2 well no longer produces oil on a daily basis, but there is a small amount of natural gas being produced. As of April 30, 2010, it has produced 3,690 Bbls of oil and 7,321 Mcf of natural gas. At the time of this report, the Kodesh #2 well is not producing oil because of a failure of the downhole pump which needs either to be repaired or replaced. We plan to increase both oil and gas production in this well by perforating new zones in Kodesh #2 during the second or third quarter of this year. The downhole pump will also be replaced. In addition to the reworking of the Kodesh #2, the operator is currently considering drilling a new well in the third or fourth quarter.

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 April 30, 2010, the Dye Estate #1 well has produced 5,439 Mcf of natural gas and is currently averaging natural gas production at a rate of 6 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 April 30, 2010, the William #4-10 well has produced 2,316 Bbls oil and 48,943 Mcf of 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.

It should be noted that all wells in the Three Sands Project were shut-in for most of the month of January 2010 while the operator was changing natural gas purchasers. As of April 30, 2010, all wells were back producing. During the three-month period ended April 30, 2010, 550 Bbls of oil and 12,534 Mcf of natural gas were produced at the Three Sands Project.

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

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 and are currently producing. One of the eight wells, the PP F-12, was completed as a flowing oil well in early October 2007. The PP F-12 well flowed oil at rates of over 100 Bbls per day and in December 2007 was offset by two additional wells in the project, the PP F-12-2 and PP F-12-3. The PP F-12-2 was a dry hole and the PP F-12-3 was completed as a flowing oil well.

Both the PP F-12 PP F-12-3 oil well locations and several of our gas well locations have been flooded at the Palmetto Point Project. Prior to the flooding, we had partly completed work to install gas lift pumps at each well; however, the work could not be completed before the locations were flooded. There has been virtually no damage to our surface equipment located at the well heads, as our batteries and other production facilities are located above the flood waters. Thus far, the only damage has been to our recent lost production because the well had to be shut-in. We do not believe that the flooding will adversely affect future oil recovery from these wells.

In early September 2008, flood waters had receded sufficiently and work began on placing the PP F-12 and PP F12-3 back on line and producing oil. Gas lift pumps were installed on both wells and other modification and additional equipment such as compressors were also installed. At the end of April 2010, both wells were producing oil at combined rates of between 65 and 75 barrels of oil per day. This reduction in production rates is largely the result of flooding which has not allowed for the wells to be serviced. When flood waters have receded, we plan to service the two producing wells and to drill an additional well to better drain the reservoir. Depending upon the thickness of the pay zone intercepted in the new well, it may be converted to a horizontal well to increase production.

Mississippi Frio-Wilcox Joint Venture. On August 2, 2006, we executed a memorandum agreement with Griffin & Griffin (as operator of the project), Delta Oil and Gas, Inc., Turner Valley Oil and Gas Company, Lexaria Corp., a Nevada corporation (“Lexaria”), and the Stallion Group to participate in two proposed drilling programs located in Southwest Mississippi and Northeast Louisiana, comprised of up to 50 natural gas and/or oil wells, at a price of $400,000 (the “Mississippi Frio-Wilcox Joint Venture”). We hold a 10% working interest in the Mississippi Frio-Wilcox Joint Venture project before production and a prorated reduced working interest after production based on the operator’s interest portion.

On June 21, 2007, we assigned our 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 interests to be of nominal value. We have 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. We do not anticipate expending additional exploration funds on the project.

Nine wells were drilled on the Mississippi Frio-Wilcox Joint Venture, of which, five wells were initially deemed successful and four wells were dry holes and were not completed. One of the five wells initially deemed to be successful was the BR F-24. However, subsequent testing of the BR F-24 indicated that it was not commercially viable and the well was plugged and abandoned in 2007. The four remaining successful wells were the Faust #1, USA 39-14, USA 1-37 and the BR F-33. The USA 39-14 has been completed and is now producing natural gas. As of April 30, 2010, these four wells were shut-in natural gas wells with no production. No further exploration wells are currently planned for this project.

King City Oil Field. We entered into an agreement with Sunset Exploration effective May 25, 2009, 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 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. Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each parties working interest. The geophysical surveys have already started and most have been completed. However, one line in the new series of seismic profiles has not been completed as the result of heavy rains. Data acquired and processed thus far indicates several potential drill targets.

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

Antelope Pass. 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 six-month period ended April 30, 2010 or during the fiscal years ended October 31, 2009 and 2008. At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project. All Bureau of Land Management fees and filing have been paid and performed making the claim valid until at least September 1, 2010.

Three months ended April 30, 2010 compared to the three months ended April 30, 2009. We realized revenues of $107,030 during the three months ended April 30, 2010, compared with $42,150 during the three months ended April 30, 2009, an increase of $64,880, due to additional wells producing and an increase in commodity prices. During the three-month period ended April 30, 2010, 1,295 Bbls of oil and 3,581 Mcf of gas were produced at our oil and gas properties, as compared to 794 Bbls of oil and 3,997 Mcf of gas for the three months ended April 30, 2009.

Our general and administrative costs increased to $210,986 for the three months ended April 30, 2010, from $154,724 for the three months ended April 30, 2009. The increase is primarily attributable to increases in consulting fees of $73,410 and management fees of $37,500. We are attempting to expand our property base by locating other resources properties. Accordingly, we have hired consultants to gather data on properties that may be of interest to us. As of the date of this filing, we have not found a suitable acquisition.

Six months ended April 30, 2010 compared to the six months ended April 30, 2009. We realized revenues of $228,056 during the six months ended April 30, 2010, compared with $110,279 during the six months ended April 30, 2009, an increase of $117,777, due to additional wells producing and an increase in commodity prices. During the six-month period ended April 30, 2010, 2,654Bbls of oil and 6,786 Mcf of gas were produced at our oil and gas properties, as compared to 1,925 Bbls of oil and 1,399 Mcf of gas for the six months ended April 30, 2009.

We incurred production costs of $42,688 during the six months ended April 30, 2010, compared with $52,456 during the six months ended April 30, 2009, a decrease of $9,768. The decrease in our production costs is related to decrease in maintenance on wells during the prior period, however this was offset by an increase in production costs as new wells were brought to production.

Our general and administrative costs increased to $479,463 for the six months ended April 30, 2010, from $272,063 for the six months ended April 30, 2009. The increase is primarily attributable to increases in consulting fees of $231,411 and management fees of $90,196. We are attempting to expand our property base by locating other resources properties. Accordingly, we have hired consultants to gather data on properties that may be of interest to us. As of the date of this filing, we have not found a suitable acquisition. In addition, we incurred stock-based compensation expense of $30,708 in the 2010 period as a result of stock options granted to our officers.

As of April 30, 2010, we had cash of $1,371,495 and working capital of $1,960,673, compared to cash of $1,947,950 and working capital of $2,494,387 as of October 31, 2009. Our accounts receivable decreased to $82,538 at April 30, 2010, compared with $97,198 at October 31, 2009, a decrease of $14,660. In addition, our current liabilities decreased to $23,620 at April 30, 2010, compared with $75,185 at October 31, 2009.

Oil and Gas Interests. We utilize the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas interests unless the sale represents a significant portion of oil and gas interests and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas interests is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production. Amortizable costs include estimates of future development costs of proved undeveloped reserves.

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

Asset Retirement Obligations. We follow FASB ASC 410-20 “Accounting for Asset Retirement Obligations”. FASB ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. FASB ASC 410-20 requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. As of October 31, 2009 and 2008, 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.

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.

Share Based Compensation. In December 2004, FASB ASC 718 (Prior Authoritative Literature: SFAS 123R) "Accounting for Stock-Based Compensation" was issued. This standard defines a fair value based method of accounting for an employee stock option or similar equity instrument. This statement requires entities to recognize related compensation expense to employees by adopting the fair value method.

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.

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, 2010, being the date of our most recently completed fiscal quarter. This evaluation was conducted under the supervision and with the participation of our officers, Leroy Halterman and Kulwant Sandher. Based on this evaluation, Messrs. Halterman and Sandher concluded that the design and operation of our disclosure controls and procedures are not effective since the following material weaknesses exist:

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, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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)
4.1	Certificate of Designation of Rights, Preferences, and Privileges for Series A Preferred Stock (4)
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

Regulation

S-K Number

Exhibit

32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer

Large accelerated filer [ ]	Accelerated filer [ ]
Non-accelerated filer [ ]	Smaller reporting company [x]

	Six-month periods ended
	April 30, 2010	April 30, 2009
Expected volatility	149%	0.00%
Risk-free interest rate	0.11%	0.00%
Expected life	2 years	0 years
Dividend yield	0.00%	0.00%

	April 30, 2010			October 31, 2009
Proved properties	$	2,696,118		$	2,571,104
Unproved properties		443,693			270,459
Total Proved and Unproved properties		3,139,811			2,841,563
Accumulated depletion expense		(1,051,806	)		(985,014	)
Impairment		(219,539	)		(219,539	)
Net capitalized cost	$	1,868,466		$	1,637,010

	April 30, 2010		October 31, 2009
Balance, beginning of period	$	37,011	$	30,766
Liabilities assumed		-		9,206
Revisions		-		(6,653	)
Accretion expense		2,220		3,692
Balance, end of period	$	39,231	$	37,011

April 30, 2010	Options outstanding and exercisable
Range of exercise prices	Number of shares	Weighted average remaining contractual life	Weighted Average Exercise Price
$0.10 $0.10	200,000 300,000	1.49 years 1.50 years	0.10 0.10