Triangle Petroleum 10Q 2009 Q3 Quarterly report

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 October 31, 2008

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

For the Transition Period from _________ to _________

Commission file number: 000-51321

TRIANGLE PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Nevada		98-0430762
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

Suite 1250, 521 - 3 Avenue SW

Calgary, Alberta

Canada T2P 3T3

(Address of Principal Executive Offices)

(403) 262-4471

(Registrant’s telephone number, including area code)

(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. Yes x No o

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

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer ¨	Smaller reporting company x
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No x

As of December 10, 2008, there were 67,426,043 shares of registrant’s common stock outstanding.

TRIANGLE PETROLEUM CORPORATION AND SUBSIDIARIES

INDEX

PART I.	FINANCIAL INFORMATION

	ITEM 1.	Financial Statements	3

		Consolidated balance sheets at October 31, 2008 and January 31, 2008 (unaudited)	3

		Consolidated statements of operations for the three and nine months ended October 31, 2008 and 2007 (unaudited)	4

		Consolidated statements of stockholder's equity for the nine months ended October 31, 2008 and 2007 (unaudited)	5

		Consolidated statements of cash flows for the three and nine months ended October 31, 2008 and 2007 (unaudited)	6

		Notes to unaudited consolidated financial statements	7 – 13

	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14-26

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	27

	ITEM 4T.	Controls and Procedures	27

PART II.	OTHER INFORMATION

	ITEM 1	Legal proceedings	29
	ITEM 1A	Risk factors	29
	ITEM 2	Unregistered sales of equity securities and use of proceeds	29
	ITEM 3	Defaults upon senior securities	29
	ITEM 4	Submission of matters to a vote of security holders	29
	ITEM 5	Other information	29
	ITEM 6	Exhibits	29

	SIGNATURES		30

Triangle Petroleum Corporation

Consolidated Balance Sheets

(Expressed in U.S. dollars)

(Unaudited)

	October 31, 2008 $			January 31, 2008 $

ASSETS

Current Assets

Cash and cash equivalents		17,278,404			4,581,589
Prepaid expenses		408,080			797,307
Other receivables		822,843			1,689,391

Total Current Assets		18,509,327			7,068,287

Debt Issue Costs, net		-			465,833

Property and Equipment		45,796			66,121

Oil and Gas Properties (Note 4)		16,974,672			24,978,949

Total Assets		35,529,795			32,579,190

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities

Accounts payable		2,505,971			3,533,833
Accrued interest on convertible debentures		2,106,163			2,751,096
Accrued liabilities		707,608			420,384
Derivative liabilities (Note 7)		-			3,262,846
Convertible debentures less unamortized discount of $1,435,650 and $1,321,869, respectively (Note 6)		8,564,350			4,778,271

Total Current Liabilities		13,884,092			14,746,430

Asset Retirement Obligations (Note 5)		852,935			1,003,353

Convertible Debentures, less unamortized discount of $nil and $3,229,279, respectively (Note 6)		-			6,770,721

Total Liabilities		14,737,027			22,520,504

Going Concern (Note 2)
Subsequent events (note 11)

Stockholders’ Equity

Common Stock (Note 8) Authorized: 100,000,000 shares, par value $0.00001 Issued: 67,426,043 shares (2008 – 46,794,530 shares)		674			468

Additional Paid-In Capital (Note 8)		80,540,714			57,852,277

Warrants (Note 9)		4,237,100			-

Deficit		(63,985,720	)		(47,794,059	)

Total Stockholders’ Equity		20,792,768			10,058,686

Total Liabilities and Stockholders’ Equity		35,529,795			32,579,190

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

Triangle Petroleum Corporation

Consolidated Statements of Operations

(Expressed in U.S. dollars)

(Unaudited)

	Three Months Ended October 31,			Three Months Ended October 31,			Nine Months Ended October 31,			Nine Months Ended October 31,
	2008			2007			2008			2007
	$			$			$			$

Revenue, net of royalties		54,500			191,632			314,450			384,859

Operating Expenses

Oil and gas production		29,718			146,396			93,099			220,199
Depletion, depreciation and accretion		52,735			151,327			146,302			391,884
Depreciation – property and equipment		10,368			9,178			30,115			30,792
General and administrative		847,022			1,717,907			3,190,427			5,252,439
Impairment of oil and gas properties		8,000,000			4,604,726			8,000,000			8,496,129
Gain on sale of assets		-			-			(10,705	)		-
Foreign exchange loss		2,429,433			467,707			2,454,022			627,454

		11,369,276			7,097,241			13,903,260			15,018,897

Loss from Operations		(11,314,776	)		(6,905,609	)		(13,588,810	)		(14,634,038	)

Other Income (Expenses)

Accretion of discounts on convertible debentures		(602,277	)		(1,704,802	)		(2,608,681	)		(6,313,336	)
Amortization of debt issue costs		-			(109,584	)		(182,637	)		(340,937	)
Loss on debt extinguishment		-			-			(160,662	)		-
Interest expense		(189,041	)		(317,671	)		(654,371	)		(1,006,419	)
Interest income		127,681			147,416			209,911			543,082
Unrealized gain on fair value of derivatives		-			2,926,091			793,589			6,481,505

Total Other Income (Expenses)		(663,637	)		941,450			(2,602,851	)		(636,105	)

Net Loss for the Period		(11,978,413	)		(5,964,159	)		(16,191,661	)		(15,270,143	)

Net Loss Per Share – Basic and Diluted		(0.18	)		(0.16	)		(0.28	)		(0.44	)

Weighted Average Number of Shares Outstanding – Basic and Diluted		67,426,000			37,345,000			58,592,000			34,699,000

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

Triangle Petroleum Corporation

Statement of Stockholders’ Equity

Period from January 31, 2008 to October 31, 2008

(Expressed in U.S. dollars)

(Unaudited)

					Additional
	Common Stock				Paid-in
	Shares		Amount		Capital			Warrants		Deficit			Total
		#	$		$			$		$			$

Balance – January 31, 2008		46,794,530		468		57,852,277			-		(47,794,059	)		10,058,686

Issuance of common stock for cash pursuant to private placement at $1.40 per unit in June 2008		18,257,500		183		21,323,217			4,237,100		-			25,560,500

Share issuance costs						(2,251,230	)		-					(2,251,230	)

Issuance of common stock on conversion of convertible debentures at a weighted average price of $0.88 per share		2,374,013		23		2,100,117			-		-			2,100,140

Fair value of conversion features of convertible debentures converted		-		-		1,039,906			-		-			1,039,906

Stock based compensation		-		-		476,427			-		-			476,427

Net loss for the period		-		-		-			-		(16,191,661	)		(16,191,661	)

Balance – October 31, 2008		67,426,043		674		80,540,714			4,237,100		(63,985,720	)		20,792,768

Triangle Petroleum Corporation

Statement of Stockholders’ Equity

Period from January 31, 2007 to October 31, 2007

(Expressed in U.S. dollars)

(Unaudited)

					Additional
	Common Stock				Paid-in
	Shares		Amount		Capital			Deficit			Total
		#	$		$			$			$

Balance – January 31, 2007		22,475,866		225		13,088,795			(18,193,312	)		(5,104,292	)

Issuance of common stock for cash pursuant to private placement at $1.40 per unit in June 2008		10,412,000		104		20,823,896			-			20,824,000

Share issuance costs						(1,515,994	)					(1,515,994	)

Issuance of common stock on conversion of convertible debentures at a weighted average price of $1.31 per share		4,766,939		47		6,249,953			-			6,250,000

Fair value of conversion features of convertible debentures converted		-		-		1,802,063			-			1,802,063

Investor relation services		50,000		1		108,499			-			108,500

Stock based compensation		-		-		2,958,479			-			2,958,479

Net loss for the period		-		-		-			(15,270,143	)		(15,270,143	)

Balance – October 31, 2007		37,704,805		377		43,515,691			(33,463,455	)		10,052,613

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

Triangle Petroleum Corporation

Consolidated Statements of Cash Flows

(Expressed in U.S. dollars)

(Unaudited)

	Three Months Ended October 31,			Three Months Ended October 31,			Nine Months Ended October 31,			Nine Months Ended October 31,
	2008			2007			2008			2007
	$			$			$			$
Operating Activities
Net loss		(11,978,413	)		(5,964,159	)		(16,191,661	)		(15,270,143	)

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

Accretion of discounts on convertible debentures		602,277			1,704,802			2,608,681			6,313,336
Amortization of debt issue costs		-			109,584			182,637			340,937
Depletion, depreciation and accretion		52,735			180,695			146,302			391,884
Depreciation – property and equipment		10,368			9,178			30,115			30,792
Impairment of oil and gas properties		8,000,000			4,604,726			8,000,000			8,496,129
Stock-based compensation		135,393			913,365			476,427			3,066,979
Gain on sale of assets		-			-			(10,705	)		-
Loss on debt extinguishment		-			-			160,662			-
Unrealized gain on fair value of derivatives		-			(2,926,091	)		(793,589	)		(6,481,505	)
Unrealized foreign exchange changes		2,443,118			-			2,443,118			-

Asset retirement costs		(127,514	)		-			(499,151	)		-

Changes in operating assets and liabilities

Unrealized foreign exchange changes		(19,809	)		-			(19,809	)		-
Prepaid expenses		3,622			42,107			58,261			(7,746	)
Other receivables		(292,757	)		(573,654	)		837,680			(619,287	)
Accounts payable		278,796			(161,106	)		(18,944	)		48,306
Accrued interest on convertible debentures		189,045			317,671			(644,932	)		378,359
Accrued liabilities		(9,268	)		(100,268	)		(39,672	)		123,966

Cash Used in Operating Activities		(712,408	)		(1,843,150	)		(3,274,580	)		(3,187,993	)

Investing Activities
Purchase of property and equipment		(5,850	)		(4,316	)		(9,791	)		(35,992	)
Oil and gas property expenditures		(1,127,139	)		(6,096,236	)		(4,863,048	)		(13,522,965	)
Cash advances from partners, net		(1,560,410	)		-			1,006,674			-
Proceeds received from sale of oil and gas properties		13,000			-			3,921,998			983,902

Cash Provided by (Used in) Investing Activities		(2,680,399	)		(6,100,552	)		55,833			(12,575,055	)

Financing Activities
Proceeds from issuance of common stock		-			-			25,560,500			20,824,000
Share issuance costs		(25,569	)		-			(2,048,156	)		(1,515,994	)
Convertible debenture repayment		-			-			(4,800,000	)		-

Cash Provided by (Used in) Financing Activities		(25,569	)		-			18,712,344			19,308,006

Unrealized foreign exchange on cash and cash equivalents		(2,796,782	)		-			(2,796,782	)		-

Increase (Decrease) in Cash and Cash Equivalents		(6,215,158	)		(7,943,702	)		12,696,815			3,544,958

Cash and Cash Equivalents – Beginning of Period		23,493,562			17,287,642			4,581,589			5,798,982

Cash and Cash Equivalents – End of Period		17,278,404			9,343,940			17,278,404			9,343,940

Cash								223,269			649,562
Cash equivalents								17,055,135			8,694,378

Non-cash Investing and Financing Activities
Common stock issued for conversion of debentures		-			750,000			2,100,140			6,250,000
Supplemental Disclosures:
Interest Paid		-			-			1,299,860			628,058

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

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

(Unaudited)

Triangle Petroleum Corporation, together with its consolidated subsidiaries (“Triangle” or the “Company”), is an independent oil and gas company focused primarily on the acquisition, exploration and development of resource properties consisting mainly of shale gas reserves. Our primary exploration and development acreage is located in the Horton Bluff formation of the Maritimes Basin in Canada and in the Fayetteville Shale of the Arkoma Basin in the United States. We have producing properties in the Fort Worth Basin and in the Alberta Deep Basin.

1.	Basis of Presentation

The accompanying consolidated financial statements of Triangle have been prepared in accordance with generally accepted accounting principles ("GAAP") in the U.S. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at October 31, 2008 and our operations and cash flows for the three and nine month periods ended October 31, 2008 and 2007. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they should be read along with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended January 31, 2008. In the prior year, the Company was accounted for as an exploration stage entity. Starting in the fourth quarter of fiscal 2008, the Company was no longer accounted for as an exploration stage entity.

Certain reclassifications have been made to the prior period’s financial statements to conform to the current period’s presentation.

2.	Going Concern

The Company is primarily engaged in the acquisition, exploration and development of oil and gas resource properties. The Company will have to raise additional funds through equity or debt offerings, dispositions of assets or other means to finance the repayment of the convertible debentures (if the holders do not elect to convert), to finance commitments to continue to earn lands related to farm-out agreements, to fund general and administrative expenses and to complete the exploration and development phase of its programs. While the Company has been successful in raising funds in the past, there can be no assurance that it will be able to do so in the future. The continuation of the Company as a going concern is dependent upon its ability to obtain necessary additional funds to continue operations and to determine the existence, discovery and successful exploitation of economically recoverable reserves in its resource properties, confirmation of the Company’s interests in the underlying properties, and the attainment of profitable operations. We presently do not have any available credit, bank financing or other external sources of liquidity. Due to our brief history and historical operating losses, our operations have not been a source of liquidity. We will need to obtain additional capital in order to expand operations and become profitable. In order to obtain capital, we may need to sell additional shares of our common stock or borrow funds from private lenders. There can be no assurance that we will be successful in obtaining additional funding.

Failure to obtain additional financing will result in the going concern assumption being inappropriate and adjustments would be required to the carrying values of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used.

3.	Accounting Policies

(a)

Recently Adopted Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards ("SFAS") No. 157, "Fair Value Measurements” ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. On February 12, 2008, the FASB issued Staff Position No. FAS 157-2 ("FSP 157-2") which proposed a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually).

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

(Unaudited)

3.	Accounting Policies (continued)

On February 1, 2008 Triangle elected to implement SFAS 157 with the one-year deferral for certain non-financial assets and liabilities. Beginning February 1, 2009, the Company will adopt the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. We are in the process of evaluating this portion of the standard and have not yet determined the impact that it will have on our financial statements upon adoption in 2009.

SFAS 157 (as amended), defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

Beginning February 1, 2008, assets and liabilities recorded at fair value in the consolidated balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels—defined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities—are as follows:

Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

The fair value of the Company’s derivative liabilities was measured using Level III inputs. The significant unobservable inputs to the fair value measurement included estimates of volatility of the share price and term of the contract. The inputs were calculated based on historical data as well as current estimated amounts. See Note 7.

The estimated fair values of derivative liabilities, being the conversion feature of the December 8, 2005 convertible debenture, included in the consolidated balance sheets at October 31, 2008 and January 31, 2008 are summarized below. The decrease in the derivative liability from January 31, 2008 to October 31, 2008 is primarily attributable to the settlement of derivatives as a result of the repayment of the underlying debentures.

	Significant Unobservable Inputs (Level III) October 31, 2008 $		Significant Unobservable Inputs (Level III) January 31, 2008 $

Derivative liability – conversion feature		-		3,262,846

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”. This statement permits entities to choose to measure many financial instruments and certain other items at fair value. Most of the provisions of SFAS No. 159 apply only to entities that elect the fair value option. However, the amendment to SFAS No. 115 “Accounting for Certain Investments in Debt and Equity Securities” applies to all entities with available-for-sale and trading securities. Effective February 1, 2008, the Company adopted SFAS No. 159. The adoption of this statement did not have a material effect on the Company's current financial statements.

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

(Unaudited)

3.	Accounting Policies (continued)

(b)

Recent Issued Accounting Pronouncements

In December 2007, the Financial Accounting Standard Board (FASB) revised the Statement of Financial Accounting Standard (SFAS) No. 141, “Business Combinations”. SFAS No. 141R requires an acquirer to be identified for all business combinations and applies the same method of accounting for business combinations – the acquisition method – to all transactions. In addition, transaction costs associated with acquisitions are required to be expensed. The revised statement is effective to business combinations in years beginning on or after December 31, 2008. The adoption of this statement will impact business combinations, if any, after the effective date.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements”. SFAS no. 160 requires the Company to report non-controlling interest in subsidiaries as equity in the consolidated financial statements; and all transactions between equity and non controlling interests as equity. SFAS No. 160 is effective for the Company commencing on February 1, 2009 and it will not impact the Company's current financial statements.

In March 2008, the FASB has issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”, which requires disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective on February 1, 2009 and is not anticipated to significantly effect the Company's financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS No. 162 directs the GAAP hierarchy to the entity, not the independent auditors, as the entity is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. SFAS No. 162 is effective November 15, 2008. SFAS No. 162 is not expected to have a material impact on the Company’s financial statements.

In May 2008, the FASB directed the FASB Staff to issue FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (FSP APB 14-1). FSP APB 14-1 applies to convertible debt instruments that, by their stated terms, may be settled in cash (or other assets) upon conversion, including partial cash settlement of the conversion option. FSP APB 14-1 requires bifurcation of the instrument into a debt component that is initially recorded at fair value and an equity component. The difference between the fair value of the debt component and the initial proceeds from issuance of the instrument is recorded as a component of equity. The liability component of the debt instrument is accreted to par using the effective yield method; accretion is reported as a component of interest expense. The equity component is not subsequently re-valued as long as it continues to qualify for equity treatment. FSP APB 14-1 is effective for the Company on February 1, 2009. Early adoption is not permitted. The Company is evaluating the impact of adopting FSP APB 14-1 on the Company’s financial statements.

4.	Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas operations whereby all costs of exploring for and developing oil and gas reserves are initially capitalized on a country-by-country (cost center) basis. Capitalized costs, less estimated salvage value, are depleted using the units-of-production method whereby historical costs and future development costs are amortized over the total estimated proved reserves. Costs of acquiring and evaluating unproven properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. These costs are assessed periodically to ascertain whether impairment has occurred (i.e., "impairment tests”). The Company incurred an $8,000,000 impairment charge in the third quarter of fiscal 2009 related to its Fayetteville assets. All of the Company’s oil and gas properties are located in the United States and Canada. The following table summarizes information regarding the Company's oil and gas acquisition, exploration and development activities:

	Costs									Accumulated Depletion									Net Book
	Opening		Additions		Dispositions			Closing		Opening		Depletion		Loss (Gain)			Closing		Value
	$		$		$			$		$				$			$		$

Proved Properties		12,886,510		50,108		(164,985	)		12,771,633		12,472,601		63,824		(40,710	)		12,495,715		275,918
Unproven Properties		34,397,768		3,920,732		(3,757,013	)		34,561,487		9,832,728		8,000,000		30,005			17,862,733		16,698,754

Total		47,284,278		3,970,840		(3,921,998	)		47,333,120		22,305,329		8,063,824		(10,705	)		30,358,448		16,974,672

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

(Unaudited)

4.	Oil and Gas Properties (Continued)

Proved Properties

The Company's proved acquisition and exploration costs were distributed in the following geographic areas:

	October 31, 2008 $		January 31, 2008 $

Alberta Deep Basin – Canada		275,918		324,162
Barnett Shale (Texas) – United States		-		89,747

Total proved acquisition and exploration costs		275,918		413,909

In Canada, depletion and depreciation expense for the three and nine month periods ended October 31, 2008 was $12,796 and $57,902 (2007 - $62,249 and $122,002), respectively.

In the U.S., depletion and depreciation expense for the three and nine month periods ended October 31, 2008 was $nil and $5,922 (2007 - $80,429 and $231,864), respectively. In June 2008, the Company sold its interests in two Barnett shale wells for gross proceeds of $164,985. The net book value of the US proven property costs at the time of the sale was $131,820 and the related properties had an asset retirement obligation of $7,545. As such the Company recorded a gain on the sale of assets of $40,710.

Unproven Properties

All of the Company’s unproven properties are not subject to depletion. The Company's unproven acquisition and exploration costs were distributed in the following geographic areas:

	October 31, 2008 $		January 31, 2008 $

Windsor Block of Maritimes Basin (Nova Scotia)		16,228,496		15,441,144
Beech Hill Block of Maritimes Basin (New Brunswick)		123,365		21,975
Western Canadian Shale (Alberta and B.C.)		44,511		-
Canada		16,396,372		15,463,119

Fayetteville Shale (Arkansas)		299,395		8,289,901
Rocky Mountains (Colorado, Montana, Wyoming)		2,987		812,020
United States		302,382		9,101,921

Total unproven acquisition and exploration costs		16,698,754		24,565,040

In Canada, $16,228,496 of unproven property costs were excluded from costs subject to depletion which relate to Canadian shale gas exploration costs mainly in the Windsor Block of the Maritimes Basin. The Company anticipates that these costs will be subject to depletion in fiscal 2011, when the Company anticipates having pipelines built and commissioned to market potential gas from the Windsor Block.

In July 2008, the Company received cash of $2,943,510 for a partner’s share of its 30% working interest in exploration costs associated with the Windsor Block of Nova Scotia. Also, the related properties had an asset retirement obligation that was reduced by $165,283 for the partner’s share of its 30% working interest.

In the U.S., $302,382 of unproven property costs were excluded from costs subject to depletion which relates mainly to Fayetteville Shale gas acquisition costs. Due to recent economic conditions, the Company has extended the timing of its anticipated sale of the acreage position related to these costs from fiscal 2009 to mid fiscal 2010. Furthermore, in September 2008 the Company sold 20 net acres of its 10,437 net acres for $13,000 and in November 2008, the Company sold 240 of its 10,437 net acres for $288,000. The Company recorded an $8,000,000 impairment charge on the remaining land in the third quarter.

In June 2008, the Company sold its 25% working interest in 9,692 acres in the Phat City area of Montana (Rocky Mountains project) for cash of $800,503. The net book value of the Rocky Mountains project at the time of the sale was $830,508, which related to U.S. Rocky Mountain leasehold acquisition costs. As such the Company recorded a loss on the sale of assets of $30,005.

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

(Unaudited)

5.	Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and natural gas properties is recorded when a liability is incurred, generally through a lease construction or acquisition or completion of a well. The current estimated costs are escalated at an inflation rate and discounted to present value at a credit adjusted risk-free rate over the estimated economic life of the properties. Such costs are capitalized as part of the basis of the related asset and are depleted as part of the applicable full cost pool. The associated liability is recorded initially as a long-term liability. Subsequent adjustments to the initial asset and liability are recorded to reflect revisions to estimated future cash flow requirements. In addition, the liability is adjusted to reflect accretion expense as well as settlements during the period. A reconciliation of the changes in the asset retirement obligations is as follows:

	Nine Months October 31, 2008 $			Nine Months October 31, 2007 $

Balance, beginning of period		1,003,353			90,913
Liabilities incurred		439,083			290,434
Liabilities settled as part of dispositions		(172,828	)		-
Liabilities settled in cash		(499,151	)		-
Accretion		82,478			38,018

Balance, end of period		852,935			419,365

6.	Convertible Debentures

Agreement Date	December 8, 2005 $			December 28, 2005 $			Total $

Balance, January 31, 2008		4,778,271			6,770,721			11,548,992

Converted		(2,100,140	)		-			(2,100,140	)
Repaid		(4,000,000	)		-			(4,000,000	)
Accretion - expensed		815,052			1,793,629			2,608,681
Accretion - settled		506,817			-			506,817
Balance, October 31, 2008		-			8,564,350			8,564,350
Amount classified as current		-			8,564,350			8,564,350
Face value at October 31, 2008		-			10,000,000			10,000,000
Interest rate		5.0	%		7.5	%

On June 5, 2008, the Company repaid $4,000,000 of convertible debentures that were due to mature on December 8, 2008 plus an early redemption fee of $800,000 and accrued interest of $1,299,860. The carrying value of the debentures at the time of repayment, including the conversion feature of the debenture that was accounted for as a derivative, was $4,639,338, which is equal to the face value of $4,000,000, less unamortized discounts of $506,817 and deferred financing costs of $283,196, plus the derivative liability of $1,429,351. The Company paid $4,800,000 on settlement ($4,000,000 face value plus a 20% early redemption fee of $800,000); therefore a $160,662 loss was recorded on the extinguishment of the debenture.

7.	Derivative Liabilities

The Company was required to bifurcate and separately account for the embedded conversion feature contained in the December 8, 2005 convertible debenture as a derivative. The Company was required to record the derivative at the estimated fair value on each balance sheet date with changes in fair values reflected in the statement of operations.

	Conversion Feature Fair Value
	$
January 31, 2008		3,262,846
Conversion features settled on conversion		(1,039,906	)
Change in fair value		(793,589	)
Conversion features settled on repayment		(1,429,351	)
October 31, 2008		-

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

(Unaudited)

7.	Derivative Liabilities (continued)

The Company used the Black-Scholes valuation model to calculate the fair value of derivative liabilities. The following table shows the assumptions used in the calculation of the conversion feature in the December 8, 2005 convertible debenture.

	Strike Price		Volatility			Risk Free Rate			Dividend Yield		Term in Years

Weighted Average Assumptions at: June 3, 2008 (repayment date)	$	1.34		110.50	%		1.99	%		–		0.51

8.	Common Stock

	Shares		Common Stock		Additional Paid- In Capital
			$			$
January 31, 2008		46,794,530		468		57,852,277
Private Placement, net of share issuance costs of $2,251,230		18,257,500		183		19,071,987
Conversion of debentures		2,374,013		23		3,140,023
Stock based compensation						476,427
October 31, 2008		67,426,043		674		80,540,714

During the nine month period ended October 31, 2008, 2,374,013 shares were issued upon the conversion of convertible debentures in the amount of $2,100,140. The fair value of the conversion feature related to the converted debentures was $1,039,906, which was transferred from the derivative liability to additional paid-in capital upon conversion.

On June 3, 2008, 18,257,500 units were issued in a private placement for gross proceeds of $25,560,500. The net proceeds after deducting expenses were $23,309,270. The Company paid the placement agents of the offering a cash fee of 7% of the gross proceeds of the offering. Each unit was priced at $1.40 per unit and consists of one share of common stock (relative fair value of $19,072,170 or $1.045 per share) and one-half share purchase warrant (relative fair value of $4,237,100 or $0.232 per unit – see Note 9). One full warrant can be exercised into one share of common stock for a period of two years at a price of $2.25 per share. Pursuant to the terms of the sale, the Company was required, on a best efforts basis, to file a registration statement with the SEC, and to cause such registration statement to be declared effective by the SEC, within 150 days after closing, to permit the public resale of the shares underlying the warrants. The registration statement was declared effective by the SEC on July 14, 2008. Also, pursuant to the terms of the sale, the Company was required, on a best efforts basis, to list the Company’s shares on the Toronto Stock Exchange (which includes the TSX Venture Exchange) on or before December 31, 2008. The Company’s shares of common stock commenced trading on the TSX Venture Exchange on December 5, 2008.

Warrants

As at October 31, 2008, the Company had 9,128,750 warrants outstanding that can be exercised into 9,128,750 shares of common stock at a price of $2.25 per share, which expire on June 3, 2010. The warrants were granted on June 3, 2008, at which time they had a relative fair value compared to the common stock issued of $4,237,100.

10.	Stock Options

The weighted average grant date fair value of stock options granted during the three and nine month periods ended October 31, 2008 was $0.259 and $0.693, respectively. No stock options were exercised during the three and nine month periods ended October 31, 2008. During the three and nine month periods ended October 31, 2008, the Company recorded stock-based compensation of $135,393 and $476,427, respectively, as general and administrative expense.

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

(Unaudited)

10.	Stock Options (continued)

A summary of the Company’s stock option activity is as follows:

	Number of Options			Weighted Average Exercise Price $		Aggregate Intrinsic Value $

Outstanding, January 31, 2008		2,580,000			2.54

Granted		1,250,000			1.54
Forfeited		(220,000	)		3.33

Outstanding, October 31, 2008		3,610,000			2.14	

Exercisable, October 31, 2008		2,030,000			2.48	

The weighted average remaining contractual life of stock options outstanding as of October 31, 2008 was 3.65 years.

The fair value of the options granted during the quarter of $0.26 (nine months ended October 31, 2008 - $0.69 per option) was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions:

	Three Months Ended October 31, 2008			Nine Months Ended October 31, 2008

Expected dividend yield		0	%		0	%
Expected volatility		81	%		79	%
Expected life (in years)		3.5			3.5
Risk-free interest rate		2.67	%		2.71	%
Estimated forfeiture rate		30	%		30	%

As at October 31, 2008, there was $1,131,570 of total unrecognized compensation costs related to non-vested share-based compensation arrangements which are expected to be recognized over a weighted-average period of 16 months.

A summary of the status of the Company’s non-vested share options as of October 31, 2008, and changes during the nine month period ended October 31, 2008, is presented below:

Non-vested share options	Options #			Weighted-Average Grant-Date Fair Value $

Non-vested at January 31, 2008		1,250,000			0.93
Granted		1,250,000			0.69
Vested		(920,000	)		0.98
Non-vested at October 31, 2008		1,580,000			0.72

11.	Subsequent Events

Subsequent to the end of the quarter, the Company sold 240 of its 10,000 net acres of land in the Fayetteville shale for $288,000.

The Company’s shares of common stock commenced trading on the TSX Venture exchange on December 5, 2008.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This Management's Discussion and Analysis of Financial Condition and Results of Operations includes a number of forward-looking statements that reflect Management's current views with respect to future events and financial performance. You can identify these statements by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words. Those statements include statements regarding the intent, belief or current expectations of us and members of our management team as well as the assumptions on which such statements are based. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve risk and uncertainties, and that actual results may differ materially from those contemplated by such forward-looking statements.

Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the Securities and Exchange Commission. The following Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Company should be read in conjunction with the Consolidated Financial Statements and notes related thereto included in this Quarterly Report on Form 10-Q. Important factors currently known to Management could cause actual results to differ materially from those in forward-looking statements. We undertake no obligation to update or revise forward-looking statements to reflect changed assumptions, the occurrence of unanticipated events or changes in the future operating results over time. We believe that our assumptions are based upon reasonable data derived from and known about our business and operations. No assurances are made that actual results of operations or the results of our future activities will not differ materially from our assumptions. Factors that could cause differences include, but are not limited to, expected market demand for our products, fluctuations in pricing for materials, and competition.

Overview

Prior to May 2005, we were known as Peloton Resources Inc., a mining exploration company. Peloton was actively searching for ore bodies containing gold in British Columbia. A consultant was hired to assess the economic viability of exploring for and developing gold reserves on Peloton’s properties. Based upon his report, Peloton decided to abandon all mining activities and to commence shifting towards an oil and gas exploration company. In connection with the shift in operational focus, we changed our name to Triangle Petroleum Corporation.

We are an exploration company focused on emerging shale gas opportunities. Our corporate strategy is to utilize our U.S. shale gas experience to secure early stage shale gas projects in Canada. In conjunction with this strategy, we have screened and participated in various projects in North America with numerous potential joint venture partners. Based on activity to date, we have selected and designated one project as core from our portfolio of projects, based on our belief that it provides the best prospect for exploring for commercial quantities of gas. This core project is focused on a shale gas opportunity located in the Maritimes Basin of Eastern Canada, on the Windsor Block in Nova Scotia and on the Beech Hill Block of New Brunswick. We intend to execute our operating plan in order to realize the full value of the land base that has been established in the Maritimes Basin. We have acquired 2D and 3D seismic and drilled two vertical test wells in late 2007 and drilled three vertical exploration wells in 2008 on the Windsor Block (516,000 gross acres, 361,200 net acres or 232,200 net acres if our joint venture participant elects to participate) in Nova Scotia and acquired 2D seismic in 2008, creating the option to earn an interest in the Beech Hill Block (68,000 gross acres, 47,600 net acres or 30,600 net acres if our joint venture participant elects to participate) in New Brunswick.

We are also in the process of evaluating a potential secondary shale gas project in Western Canada. In addition, we have non-core interests in the Fayetteville Shale trend in Arkansas (20,344 gross acres, 10,172 net acres), the Barnett Shale trend in Texas (478 gross acres, 61 net acres), and conventional oil and gas plays in the Kakwa and Wapiti areas of Alberta (23,360 gross acres, 5,394 net acres) and the states of Colorado and Wyoming (38,419 gross acres and 9,605 net acres). These projects areas are currently designated as non-core due to our desire to focus our limited manpower resources on one core and one secondary project.

Plan of Operations

The following table contains forward looking information about budgeted cash flows that are based on certain assumptions that include, but are not limited to, successful drilling and completions results, the ability to supplement our working capital by completing equity or debt financings and selling non-core assets, continued funding from work program partners, Zodiac Exploration Corp. (“Zodiac”) exercising its option under the Zodiac Joint Venture Agreement to earn an additional 12.5% working interest by paying 50% of the second $15 million in gross costs, and the availability of drilling and completion equipment. All references to "C$" in the following table are to Canadian dollars (C$1.00=US$0.80).

We intend to pursue our core projects in the Province of Nova Scotia pursuant to a work program and budget pertaining to certain acreage interests in the Windsor Block of Nova Scotia as of September 15, 2008. The work program and budget covers an 18-month period from July 1, 2008 to December 31, 2009. It estimates gross expenditures of Cdn$47.5 million (Cdn$14.0 million net). The work program budget assumes that Zodiac will fund 50% of drilling costs up to $15 million gross ($7.5 million net to Zodiac) to earn a 12.5% interest in the Windsor Block and that Zodiac will exercise its option to earn an additional 12.5% interest in the Windsor Block by funding an additional $7.5 million net to Zodiac costs as per the terms of the Zodiac Joint Venture Agreement. Details of the Zodiac Joint Venture Agreement may be found under the headings "Properties" and "Liquidity and Capital Resources".

		Triangle Work Program and Budget
Timing of Expenditures		Exploration & Development Activity	Gross Cost (C$000's)		Triangle Net Cost (C$000's)			Cost Per Quarter (C$000's)
								Gross		Triangle Net
	Q3 2008	Drill & case N-14-A (Kennetcook #3)		3,000		600	(1)
		Drill & case O-61-C (Stanley #1)		3,000		600	(1)		6,000		1,200
	Q4 2008	Drill & case E-38-A (Kennetcook #4)		3,000		600	(1)
		Complete N-14-A (Kennetcook #3)		3,000		600	(1)
		Complete O-61-C (Stanley #1)		3,000		600	(1)		9,000		1,800
	Q1 2009	Complete E-38-A (Kennetcook #4)		3,000		600	(2)
		Drill & case Kennetcook #5		4,000		800	(2)
		Complete Kennetcook #5		3,500		700	(2)		10,500		2,100
	Q2 2009	Drill & case Kennetcook #6		2,000		400	(2)
		Complete Kennetcook #6		2,000		400	(2)		4,000		800
	Q3 2009	Drill & case Kennetcook #7		3,000		1,350	(3)
		Complete Kennetcook #7		3,000		1,350	(3)
		Drill & case Avon #1		3,000		1,350	(3)
		Complete Avon #1		3,000		1,350	(3)		12,000		5,400
	Q4 2009	Drill & case Stanley #2 delineation well		3,000		1,350	(3)
		Complete Stanley #2 delineation well		3,000		1,350	(3)		6,000		2,700
Total Budget Expenditures			$	C47,500	$	C14,000

Notes:

(1)	Assumes Triangle pays 20%, Zodiac pays 50%, and Contact Exploration Corp. (“Contact”) pays 30%.

(2)	Assumes Triangle pays 20%, Zodiac elects to pay 50% to earn an additional 12.5% working interest, and Contact pays 30%.

(3)	Assumes Triangle pays 45%, Zodiac pays 25%, and Contact pays 30%.

The work program, including the wells in Avon and Stanley, satisfies the requirements of a 10-well commitment made to the Nova Scotia Department of Energy in support of a production agreement and land tenure application submitted June 24, 2008. The 10 locations must be drilled prior to the end of 2011. Four locations must be drilled in Kennetcook prior to the end of 2009, which is satisfied by the 2008 portion of the work program, and two wells in each of Avon, Stanley and Wolfville, which requirements are partially satisfied by this work program, with the balance to be completed in 2010 and 2011.

We intend to allocate our working capital to the work program and budget as described in the table above. However, there may be circumstances where, for sound business reasons, a reallocation of the funds may be necessary. In particular, we have identified six other locations in the Kennetcook area which are equally viable to the locations proposed in the table below, and therefore substitutions or additions may occur. Furthermore, while we intend to use our working capital as described in the work program and budget, our current working capital is not sufficient to complete the work program. On December 9, 2008, we entered into a best efforts financing agreement with Wolverton Capital Markets, a division of Wolverton Securities Ltd. and Research Capital Corporation to offer flow-through common shares on a private placement basis at a price of C$0.25 per flow-through share for gross proceeds of C$3 million. Proceeds from the sale of the flow-through shares, if any, will be used to incur Canadian exploration expenses on our shale gas projects in the Maritimes Basin prior to December 31, 2009. These qualifying expenditures will be renounced to subscribers of the flow-through shares effective on or before December 31, 2008.

We intend to complete the wells listed in the work program and budget, based on our own past experience in the area, and employing best practices of other operators in the industry working in similar basins. Completions are expected to consist of perforating, fracture treating, and multi-day flow-testing several distinct geological intervals within each well. Depending on geological interpretation, it is expected that two to four intervals may be completed in any given vertical well. Horizontal wells may contain up to five separate completion intervals. Size and number of fracture treatments will depend on geologic and rock mechanics data received as the wells are drilled and logged. Perforation intervals are expected to be 1 to 10 metres thick, within overall prospective shale intervals that may be on the order of 100 metres thick. Fracture stimulation, likely using slick water and sand proppant, will be undertaken in virtually all cases. The size of fracture is expected to be between 10 and 100 tonnes per perforated interval. Industry best practices will be continually reviewed and employed if applicable. The expected completion program cost estimated in the work program and budget includes these estimates and assumptions.

Properties

All of our oil and gas properties are located in the United States and Canada.

Canada

Maritimes Basin - Eastern Canadian Shale Gas Project

During fiscal 2007 and early fiscal 2008, a multi-disciplined geoscience team screened prospective basins in Eastern Canada. The screening process included an assessment of the geological history for a given area, estimates of pressure and temperature profiles and a determination of the ability to fracture stimulate a prospective shale package. As a direct result of implementing this strategy, we executed two farm-in agreements with a Canadian company to pursue two shale gas opportunities in the Maritimes Basin in March and May 2007.

Beech Hill Block

The Beech Hill Farm-In Agreement was entered into with Contact in March 2007 and covers approximately 68,000 gross acres in the Moncton Sub-Basin of the Maritimes Basin located in the Province of New Brunswick, Canada. We are entitled to earn a 70% working interest in the block subsequent to the acquisition and evaluation of a minimum Cdn$250,000 seismic program and then electing no later than December 31, 2008 to drill a test well by mid-2009. Effective May 31, 2008, we entered into the Zodiac Joint Venture Agreement, wherein Zodiac agreed to incur the first Cdn$250,000 of costs for the seismic program for the option to earn a 25% working interest in the Beech Hill Block after paying 50% of the test well costs. Based upon Zodiac participating in the test well, we would retain a 45% working interest and would continue as operator.

During June and July 2008, approximately $280,000 gross ($30,000 net) expenditures were incurred to complete the acquisition phase of approximately 30 kilometres (18 miles) of 2D seismic on the Beech Hill Block. We now have until the end of 2008 to interpret this data and decide whether or not to drill a well by mid-2009 in order to earn a 70% working interest (net 45% should Zodiac elect to participate). Zodiac has paid Cdn$250,000 towards the seismic program, thereby earning the option to participate in the drilling of the first potential well. The Beech Hill Block is covered by leases and licenses to search for oil and natural gas with the New Brunswick government which expire between February 2009 and June 2011.

Windsor Block

The Windsor Block Farm-In Agreement was entered into with Contact in May 2007 and covers approximately 516,000 gross acres in the Windsor Sub-Basin of the Maritimes Basin located in the Province of Nova Scotia, Canada. During fiscal 2008, we earned a 70% working interest in the block by drilling and completing a test well. In July 2008, our joint venture partner, Contact, elected to maintain its 30% working interest instead of converting to a 5% gross overriding royalty. Effective May 31, 2008, we entered into the Zodiac Joint Venture Agreement to drill as many as six new delineation wells on the Windsor Block. The joint venture provides for an initial commitment by Zodiac to pay 50% of drilling costs, up to Cdn$7.5 million (Cdn$15 million gross), to earn a 12.5% working interest in the entire Windsor Block. Within 30 days of fulfilling this expenditure commitment, Zodiac has the option to commit another Cdn$7.5 million (Cdn$15 million gross) for an additional 12.5% working interest. Based upon Zodiac spending the entire Cdn$15 million, we would retain a 45% working interest and would continue as operator, and Zodiac would earn a 25% working interest in the Windsor Block.

From May 2007 to June 2008, we spent approximately $17.5 million (net $14.6 million) on the first stage of the Windsor Block exploration program, consisting of drilling and completing two vertical test wells (Kennetcook #1 and Kennetcook #2), a 2D and 3D seismic program and geological studies. Both of the vertical test wells, the seismic and geological studies have provided us with sufficient valuable technical information for us to believe that this has the potential to be a significant shale gas resource project. In conjunction with Contact electing to maintain their 30% working interest instead of converting to a gross over-riding royalty in July 2008, Contact paid us 30% of the gross costs ($2.9 million) for the second well and seismic program that was expended in this first stage of the drilling program that was not a part of the earning parameter.

The Windsor Block is covered by an exploration agreement with the Nova Scotia government, originally issued in 1999, which was due to expire on September 15, 2008, and has now been extended by the Nova Scotia Department of Energy an additional 180 days. We are working with the Nova Scotia government to convert the exploration agreement into a production agreement. We submitted a development plan application in mid June 2008, which triggered an automatic six month extension of the exploration agreement while the Nova Scotia government reviews the application. If the production agreement is not granted, our right to explore for and develop oil and gas on this block would be forfeited.

In July 2008, we started the second stage of the Windsor Block shale gas exploration program to test the gas content and productivity of the Horton Bluff shales in various locations across the Windsor Block, and also to evaluate potential overlying conventional oil and gas reservoirs.

The first vertical exploration well in this program, N-14-A, spud in mid July 2008 and cased in August 2008. N-14-A is located approximately eight kilometers (five miles) north of our two 2007 vertical test wells. N-14-A was drilled to a depth of 2,600 meters (8,500 feet). Log, core, and lab analysis indicates a potentially gas-bearing Horton Bluff shale and sand interval, approximately 1,000 meters (3,300 feet) thick.

The second vertical exploration well, O-61-C, spud in August 2008, and was cased in October 2008. This well is located approximately 22 kilometers (14 miles) west of from N-14-A, in a separate fault block. Total depth drilled was 2,960 meters (9,700 feet). Logs indicate the presence of over 300 meters (1,000 feet) of shale within the Horton Bluff section as well as several potential tight sand intervals.

Our third vertical exploration well, E-38-A, spud in late October 2008, and was cased in November 2008. The well is located in the Kennetcook area near N-14-A, but in a separate fault block. Total depth drilled was 1,700 meters (5,600 feet), and casing was run to 1,500 meters (4,900 feet). A shale section of approximately 1,000 meters (3,300 feet) is being evaluated for completion.

Completion operations commenced on the N-14-A well at the end of October 2008, with a four-stage perforation and fracture treatment taking place in early December 2008. The completion consisted of a four-stage frac treatment across a 100 meter (330 foot) interval, each stage consisting of approximately 50 tonnes (110,000 pounds) per stage.

Completion operations on the other two wells drilled in this program are being evaluated by our technical teams and our partners. Operations will move forward on the basis of that technical evaluation, equipment availability, government approvals, and partner concurrence.

Western Canadian Shale Program

We continue to actively evaluate various shale packages in Alberta and British Columbia. Our objective is to potentially secure an initial land position. To date, we have participated in a multi-company geological study of the Western Canadian Sedimentary Basin, reviewed this study, identified our own key technical indicators, correlated these key indicators back to the study and identified prospective shale areas. This follows the corporate strategy in the Maritimes Basin of utilizing our U.S. shale gas experience to secure early stage shale gas projects in Canada.

Alberta Canada Deep Basin - Western Canadian Conventional Program (non-core project)

In fiscal 2009, there is no exploration activity planned on this project. We are producing from two wells. The first well is located in the Kakwa Area and we have an 18% interest before payout (12% after payout). The second well is located in the Wapiti Area and we have an approximate 35% working interest.

United States

Arkoma Basin Arkansas - Fayetteville Shale Program (non-core project)

Based upon escalating land prices in this basin and due to the lack of progress in accelerating the exploration program, we decided in late March 2008 to sell the 10,400 non-operated net acres. We are planning to sell this acreage in the most effective manner by assessing new industry activity and overall direct acreage sales. In June 2008, we and the operator of the lands entered into agreements with Tristone Capital to market the property. The sale of this acreage was expected to be concluded before the end of 2008, but has now been extended to mid 2009 due to the economy. In November 2008, we sold 240 of the net acres for $288,000 and wrote-off the remaining land value.

States of Colorado, Montana and Wyoming - Rocky Mountain Program (non-core project)

We drilled initial test wells in Colorado and Wyoming in 2006 and 2007 that were not successful in the primary targets. In June 2008, we sold our third prospect in this project, located in Northern Montana, consisting of 9,692 net acres of land, for proceeds of approximately $800,000.

Greater Fort Worth Basin Texas - Barnett Shale Program (non-core project)

In fiscal 2009, there is no exploration activity planned on this project. At the beginning of the year, we had six low working interest shale gas wells pipeline connected (5.75%-15% working interest), of which four were producing. The operator of two of the six wells commenced voluntary bankruptcy proceedings in the prior year. During 2008, through the trustee, we sold our interest in the two wells in an auction of the operator's assets for proceeds of approximately $165,000. As such, we currently have four low working interest shale gas wells pipeline connected (11%-15% working interest), of which one well is currently producing.

Results of operations for the three and nine months ended October 31, 2008 compared to the three and nine months ended October 31, 2007

Daily Sales Volumes, Working Interest before royalties

		Three Months Ended October 31, 2008		Three Months Ended October 31 2007		Nine Months Ended October 31, 2008		Nine Months Ended October 31, 2007
Barnett Shale in Texas, USA	Mcfpd		33		333		58		193
Deep Basin in Alberta, Canada	Mcfpd		80		247		108		127
Total Company	Mcfpd		113		580		166		320
Total Company	Boepd*		19		97		28		53

* Mcf converted into BOE on a basis of 6:1

Net Operating Results

		Three Months Ended October 31, 2008		Three Months Ended October 31, 2007		Nine Months Ended October 31, 2008		Nine Months Ended October 31, 2007
Volumes	Mcf		10,401		53,516		45,306		87,492
Price	$/Mcf		6.63		5.77		8.50		6.28
Revenue		$	69,008	$	308,613	$	384,970	$	549,554
Royalties			14,508		116,981		70,520		164,695
Revenue, net of royalties			54,500		191,632		314,450		384,859
Production expenses			29,718		146,396		93,099		220,199
Net		$	24,782	$	45,236	$	221,351	$	164,660

For the three and nine month periods ended October 31, 2008, we realized $69,008 and $384,970, respectively, in revenue from sales of natural gas and natural gas liquids, as compared to $308,613 and $549,554 in the same periods in 2007. Revenue decreased mainly due to reduced production volumes since we sold two Barnett Shale wells. Royalties as a percent of revenue was 21% and 18% for the three month and nine month periods ended October 31, 2008, respectively, compared to 38% and 30% in the same periods in 2007; the royalty rate decreased mainly as a result of lower royalty rates in Canada as a result of the Gas Cost Allowance credit received monthly from the Alberta government starting in 2008. Production expenses related to this revenue were $17.14/Boe and $12.32/Boe for the three and nine month periods ended October 31, 2008, respectively, compared to $16.41/Boe and $15.10/Boe in the same periods in 2007.

Depletion, Depreciation and Accretion (“DD&A”)

	Three Months Ended October 31, 2008		Three Months Ended October 31, 2007		Nine Months Ended October 31, 2008		Nine Months Ended October 31, 2007
Depletion – oil and gas properties	$	12,796	$	142,676	$	63,824	$	353,866
Accretion		39,939		8,651		82,478		38,018
Depletion and Accretion		52,735		151,327		146,302		391,884
Depreciation – property and equipment		10,368		9,178		30,115		30,792
Total	$	63,103	$	160,505	$	176,417	$	422,676
Depletion per BOE	$	7.38	$	16.00	$	8.45	$	24.27

Unproven property costs of $24,698,754 were excluded from costs subject to depletion at October 31, 2008. Depletion expense related to oil and gas properties decreased in the three and nine months periods ended October 31, 2008 compared to the same periods in 2007 primarily as a result of the U.S. properties having no depletion starting in the second quarter of fiscal 2009 as the related proved property costs were nil.

General and Administrative (“G&A”)

	Three Months Ended October 31, 2008			Three Months Ended October 31, 2007			Nine Months Ended October 31, 2008			Nine Months Ended October 31, 2007
Salaries, benefits and consulting fees	$	391,750		$	431,290		$	1,349,859		$	1,082,577
Office costs		230,333			125,797			680,827			547,438
Professional fees		47,920			65,916			344,866			212,033
Public company costs		126,443			225,562			455,444			430,151
Operating overhead recoveries		(84,815	)		(44,023	)		(116,996	)		(86,739	)
Stock-based compensation		135,391			913,365			476,427			3,066,979
Total G&A	$	847,022		$	1,717,907		$	3,190,427		$	5,252,439

General and administrative expenses have decreased in the three and nine month periods ended October 31, 2008 compared to the same periods in 2007 primarily due to decreased stock-based compensation expense mainly as a result of shares issued to our executives that have now been fully expensed.

Salaries, wages and consulting fees increased in the nine month period ended October 31, 2008 compared to the same period in 2007 due to increased staff and the payment of bonuses to employees in July 2008. Salaries, wages and consulting fees decreased in the three month period ended October 31, 2008 compared to the same period in 2007 due to non-recurring staff recruitment costs paid in the third quarter of 2007.

Office costs increased in the nine month period ended October 31, 2008 compared to the same period in 2007 due to increased office rent associated with the new corporate headquarters starting the second half of 2007. Office costs increased in the three month period ended October 31, 2008 compared to the same period in 2007 due to an insurance credit booked in the third quarter of 2007 and the reversal of a $65,000 bad debt expense for revenue that was received in the third quarter of 2007.

Professional fees increased in the nine month period ended October 31, 2008 compared to the same period in 2007 due to increased year-end audit and reserve evaluation fees, increased audit and accounting fees for the restatements of our 10-K and 10-Q filings with the SEC. Professional fees in the three month period ended October 31, 2008 were consistent with the same period in 2007.

Public company costs consist mainly of fees for investor relations and also include directors' fees, press release and SEC filing costs, printing costs and transfer agent fees. Public company costs increased marginally in the nine month period ended October 31, 2008 compared to the same period in 2007 mainly due to increased director fees, which is partially offset by reduced investor relation costs related to management implementing cost reductions. Public company costs decreased in the three month period ended October 31, 2008 compared to the same period in 2007 mainly due to reduced investor relation costs related to management implementing cost reductions.

Accretion of Discounts on Convertible Debentures

Agreement Date	Three Months Ended October 31, 2008		Three Months Ended October 31, 2007		Nine Months Ended October 31, 2008		Nine Months Ended October 31, 2007
June 14, 2005	$	-	$	-	$	-	$	515,626
December 8, 2005		-		864,619		813,337		3,304,559
December 28, 2005		602,277		840,183		1,795,344		2,493,151
Total accretion of discounts	$	602,277	$	1,704,802	$	2,608,681	$	6,313,336

Accretion of discounts on convertible debentures decreased in the three and nine month periods ended October 31, 2008 compared to the same periods in 2007 due primarily to the June 14, 2005 debenture discounts being realized prior to fiscal 2009, the conversion of December 8, 2005 debentures throughout fiscal 2008 and fiscal 2009 which reduced the accretion base, the repayment of the December 8, 2005 debentures on June 5, 2008, and the reduction of the December 28, 2005 accretion since the maturity date was extended.

Interest Expense

Agreement Date	Three Months Ended October 31, 2008		Three Months Ended October 31, 2007		Nine Months Ended October 31, 2008		Nine Months Ended October 31, 2007
June 14, 2005	$	-	$	-	$	-	$	18,918
December 8, 2005		-		128,629		91,360		426,542
December 28, 2005		189,041		189,042		563,011		560,959
Total interest expense	$	189,041	$	317,671	$	654,371	$	1,006,419

Interest expense decreased for the three and nine month periods ended October 31, 2008 compared to the same periods in 2007 due primarily to the conversion and repayment of the December 8, 2005 convertible debentures.

Oil and Gas Properties

	Net Book Value January 31, 2008		Additions		Depletion and Impairment			Disposition			Gain (Loss)			Net Book Value October 31, 2008

Unproven
Windsor Block Maritimes Shale – Nova Scotia, Canada	$	15,441,144	$	3,730,862	$	-		$	(2,943,510	)	$	-		$	16,228,496
Beech Hill Block Maritimes Shale – New Brunswick, Canada		21,975		101,390		-			-			-			123,365
Western Canadian Shale – Alberta and B.C., Canada		-		44,511		-			-			-			44,511
Arkoma Basin, Arkansas – Fayetteville Shale		8,289,901		22,494		(8,000,000	)		(13,000	)		-			299,395
U.S. Rocky Mountains – Colorado, Montana, Wyoming		812,020		21,475		-			(800,503	)		(30,005	)		2,987
Proved
Alberta Deep Basin – Western Canada		324,162		9,658		(57,902	)		-			-			275,918
Greater Fort Worth Basin, Texas – Barnett Shale		89,747		40,450		(5,922	)		(164,985	)		40,710			-
Net	$	24,978,949	$	3,970,840	$	(8,063,824	)	$	(3,921,998	)	$	10,705		$	16,974,672

During the nine month period ended October 31, 2008, we spent $3,730,862 on the Windsor Block mainly as follows:

$1,772,000 testing Kennetcook #1 and #2;

$784,000 drilling the N-14-A well in the Kennetcook area of the Windsor Block of Nova Scotia;

$890,000 drilling the 0-61-C well in the Stanley area of the Windsor Block of Nova Scotia; and

$231,000 on initial drilling costs for the E-38-A well in the Kennetcook area of the Windsor Block of Nova Scotia that spud in late October 2008 and was drilling over quarter-end.

In July 2008, we received $2,943,510 in cash for our joint venture partner’s share of its 30% working interest in exploration costs associated with the Windsor Block in Nova Scotia. This disposition included $172,828 of non-cash asset retirement obligation reversals.

In September 2008, we sold 20 net acres of the 10,437 net acres of Fayetteville shale land for $13,000 and in November 2008, we sold an additional 240 of the 10,437 net acres for $288,000. As a result of these partial sales, and as result of reduced interest in land sales and reduced gas prices attributable to the slowdown in the economy, we wrote-down the land value at October 31, 2008 by $8,000,000 to $299,395.

In June 2008, we sold our 25% working interest in 9,692 acres in the Phat City area of Montana (Rocky Mountains project) for gross cash proceeds of $800,503. The net book value of the Rocky Mountains project at the time of the sale was $830,508, which related to U.S. Rocky Mountain leasehold acquisition costs. As such we recorded a loss on the sale of assets of $30,005.

In June 2008, we sold our interest in two Barnett shale wells for gross proceeds of $164,985. The net book value of the U.S. proved property costs at the time of the sale was $131,820 and the related properties had an asset retirement obligation on the books of $7,545. As such we recorded a gain on the sale of assets of $40,710.

Net Cash Oil and Gas Additions:

	Three Months Ended October 31, 2008			Nine Months Ended October 31, 2008
Net additions, per above table	$	2,227,249		$	3,970,840
Non-cash ARO additions		(393,633	)		(439,083	)
Non-cash ARO dispositions		35,399			172,828
Changes in investing working capital		(741,876	)		1,158,464
Net oil and gas additions, per Statement of Cash Flows	$	1,127,139		$	4,863,049

Liquidity and Capital Resources

To date, we have generated minimal revenues and have incurred operating losses in every quarter. We are an early stage production company, have not generated significant revenues from operations and have incurred significant losses since inception. These factors among others raise substantial doubt about our ability to continue as a going concern.

As at October 31, 2008, we had working capital of $4,625,235, resulting primarily from our cash and cash equivalents of $17,278,404 offset by payables of $3,213,579, convertible debentures of $8,564,350 and associated accrued interest of $2,106,163. We have a cash equivalents balance of $17,278,404 at October 31, 2008, which are held on deposit at a Schedule “1” Canadian Chartered Bank in U.S. term deposits and non-redeemable guaranteed investment certificates that mature in less than 90 days. For the nine month period ended October 31, 2008, we had net cash outflow from operating activities of $3,274,580, mainly related to cash general and administrative expenses of $2,714,000 and cash abandonment liability settlements of $499,151.

	October 31, 2008						January 31, 2008
Agreement Date	Face Value		Discount		Carrying Value		Face Value		Discount		Carrying Value
December 8, 2005	$	-	$	-	$	-	$	6,100,140	$	1,321,869	$	4,778,271
December 28, 2005		10,000,000		1,435,650		8,564,350		10,000,000		3,229,279		6,770,721
Total convertible debentures	$	10,000,000	$	1,435,650	$	8,564,350	$	16,100,140	$	4,551,148	$	11,548,992

We have $10,000,000 of convertible debentures outstanding as at October 31, 2008. The convertible debentures were issued on December 28, 2005 and mature on June 1, 2009, whereby $10,000,000 plus accrued interest is payable or convertible at the option of the holder at $4.00 per share. Based on the current share price, conversion is not likely and we will either be required to repay or refinance these debentures.

The December 8, 2005 debentures were convertible at the lower of (i) $5.00 or (ii) 90% of the average of the three lowest daily volume weighted average prices of our common stock of the 10 trading days immediately preceding the date of conversion. During the nine month period ended October 31, 2008, $2,100,140 of the December 8, 2005 convertible debentures were converted into 2,374,013 shares of common stock and the remaining $4,000,000 of these convertible debentures were repaid, subject to a 20% early redemption fee ($800,000).

We were committed to pay 66% of the drilling and completion costs for one well in our Fayetteville project to earn a 50% working interest. The operator had to spud this well before July 31, 2008 or we automatically earn our 50% working interest. The operator did not spud this well; therefore, we earned our 50% working interest. We were also committed to pay 33% of the costs to drill one well in our Rocky Mountains project to earn 25% working interest. On June 30, 2008, we sold our Montana acreage position along with this commitment.

We expect significant capital expenditures during the next 12 months for drilling programs on our Canadian shale program, overhead and working capital purposes. To partially fund these expenditures, we closed a private placement on June 3, 2008 for aggregate gross proceeds of $25,560,500. Also, to partially fund the remaining expenditures, we entered into a Joint Venture Agreement with Zodiac effective May 31, 2008, whereby Zodiac may pay up to 50% of the next C$30,000,000 in gross costs for the next six wells in the Windsor Block of Nova Scotia to earn up to 25% in the Block. There is a risk that neither Zodiac, nor our 30% joint venture partner in the Windsor Block, will be able to pay for their portion of the well costs, which would slow down or stop exploration on the Windsor Block. Also, to partially fund the remaining expenditures, we sold 240 of our 10,000 net undeveloped acres in the Fayetteville Shale in November 2008 for $288,000. We will have to raise additional funds to complete the exploration and development phase of our programs and, while we have been successful in doing so in the past, there can be no assurance that we will be able to do so in the future. Our continuation as a going concern for a period longer than the current fiscal year is dependent upon our ability to obtain necessary additional funds to continue operations and to determine the existence, discovery and successful exploitation of economically recoverable reserves in our resource properties, earning of our interests in the underlying properties, and the attainment of profitable operations.

By adjusting our operations to the level of capitalization, we believe we have sufficient capital resources to meet projected cash flow deficits in the near term. However, if during that period, or thereafter, we are not successful in generating sufficient liquidity from operations or in raising sufficient capital resources, on terms acceptable to us, this could have a material adverse effect on our business, results of operations, liquidity and financial condition.

We presently do not have any available credit, bank financing or other external sources of liquidity. Due to our brief history and historical operating losses, our operations have not been a source of liquidity. We will need to obtain additional capital in order to expand operations and become profitable. In order to obtain capital, we may need to sell additional shares of our common stock or borrow funds from private lenders. There can be no assurance that we will be successful in obtaining additional funding.

We will still need additional capital in order to continue operations until we are able to achieve positive operating cash flow. Additional capital is being sought, but we cannot guarantee that we will be able to obtain such investments. Financing transactions may include the issuance of equity or debt securities, obtaining credit facilities, or other financing mechanisms. However, the trading price of our common stock and a downturn in the North American stock and debt markets could make it more difficult to obtain financing through the issuance of equity or debt securities. Even if we are able to raise the funds required, it is possible that we could incur unexpected costs and expenses, fail to collect significant amounts owed to us, or experience unexpected cash requirements that would force us to seek alternative financing. Furthermore, if we issue additional equity or debt securities, stockholders may experience additional dilution or the new equity securities may have rights, preferences or privileges senior to those of existing holders of our common stock. If additional financing is not available or is not available on acceptable terms, we will have to curtail our operations.

On December 9, 2008, we entered into a best efforts financing agreement with Wolverton Capital Markets, a division of Wolverton Securities Ltd. and Research Capital Corporation to offer flow-through common shares on a private placement basis at a price of C$0.25 per flow-through share for gross proceeds of C$3 million. Proceeds from the sale of the flow-through shares, if any, will be used to incur Canadian exploration expenses on our shale gas projects in the Maritimes Basin prior to December 31, 2009. These qualifying expenditures will be renounced to subscribers of the flow-through shares effective on or before December 31, 2008.

June 2008 Private Placement

On June 3, 2008, we sold an aggregate of 18,257,500 units in a private placement transaction for gross proceeds of $25,560,500. The net proceeds after deducting expenses were $23,309,270. We paid the placement agents of the offering a cash fee of 7% of the gross proceeds of the offering. Each unit was priced at $1.40 per unit and consists of one share of common stock and one-half of a warrant. One full warrant can be exercised into one share of common stock for a period of two years at a price of $2.25 per share. Pursuant to the terms of the sale, we were required, on a best efforts basis, to file a registration statement with the SEC, and to cause such registration statement to be declared effective by the SEC, within 150 days after closing, to permit the public resale of the shares underlying the warrants. The registration statement was declared effective by the SEC on July 14, 2008. Also, pursuant to the terms of the sale, we were required, on a best efforts basis, to list our shares of common stock on the Toronto Stock Exchange (which includes the TSX Venture Exchange) on or before December 31, 2008. Our shares of common stock commenced trading on the TSX Venture Exchange on December 5, 2008.

Critical Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires us 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 the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We base our estimates and assumptions on current facts, historical experience and various other factors that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities and the accrual of costs and expenses that are not readily apparent from other sources. The actual results experienced by us may differ materially and adversely from our estimates. To the extent there are material differences between the estimates and the actual results, future results of operations will be affected.

Investment in Oil and Gas Properties

We utilize the full cost method to account for our investment in oil and gas properties. Accordingly, all costs associated with acquisition and exploration of oil and gas reserves, including such costs as leasehold acquisition costs, interest costs relating to unproven properties, geological expenditures and direct internal costs are capitalized into the full cost pool. We had properties in two countries with proved reserves. For our proved oil and gas reserves, capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage, will be depleted on the units-of-production method using estimates of proved reserves. Investments in unproven properties and major development projects including capitalized interest, if any, are not amortized until proved reserves associated with the projects can be determined. If the future exploration of unproven properties is determined uneconomical, the amounts of such properties are added to the capitalized cost to be amortized. The capitalized costs included in the full cost pool are subject to a ceiling test.

Asset Retirement Obligations

We recognize a liability for future retirement obligations associated with our oil and gas properties. The estimated fair value of the asset retirement obligation is based on the current estimated cost escalated at an inflation rate and discounted at a credit adjusted risk-free rate. This liability is capitalized as part of the cost of the related asset and amortized over its useful life. The liability accretes until we settle the obligation. The costs are estimated by management based on its knowledge of industry practices, current laws and past experiences. The costs could increase significantly from management’s current estimate.

Stock-Based Compensation

We record compensation expense in the consolidated financial statements for stock options granted to employees, consultants and directors using the fair value method. Fair values are determined using the Black Scholes option pricing model, which is sensitive to the estimate of the Company’s stock price volatility and the options expected life. Compensation costs are recognized over the vesting period.

Derivative Liabilities

We record derivatives at their fair values on the date that they meet the requirements of a derivative instrument and at each subsequent balance sheet date. Fair values are determined using the Black Scholes option pricing model, which requires and is very sensitive to an estimate of the Company’s stock price volatility and term. Any change in fair value will be recorded as non-operating, non-cash income or expense at each reporting date.

Recently Issued Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements”. SFAS no. 160 requires the Company to report non-controlling interest in subsidiaries as equity in the consolidated financial statements; and all transactions between equity and non controlling interests as equity. SFAS No. 160 is effective for us commencing on February 1, 2009 and it will not impact our current financial statements.

In May 2008, the FASB directed the FASB Staff to issue FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (FSP APB 14-1). FSP APB 14-1 applies to convertible debt instruments that, by their stated terms, may be settled in cash (or other assets) upon conversion, including partial cash settlement of the conversion option. FSP APB 14-1 requires bifurcation of the instrument into a debt component that is initially recorded at fair value and an equity component. The difference between the fair value of the debt component and the initial proceeds from issuance of the instrument is recorded as a component of equity. The liability component of the debt instrument is accreted to par using the effective yield method; accretion is reported as a component of interest expense. The equity component is not subsequently re-valued as long as it continues to qualify for equity treatment. FSP APB 14-1 is effective for the Company on February 1, 2009. Early adoption is not permitted. We are evaluating the impact of adopting FSP APB 14-1 will have on our financial statements.

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required under Regulation S-K for “smaller reporting companies.”

ITEM 4T - CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of October 31, 2008. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Based on our evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as a result of the material weaknesses described below, our disclosure controls and procedures are not designed at a reasonable assurance level and are ineffective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is not accumulated nor communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The material weaknesses, which relate to internal control over financial reporting, that were identified are:

We did not have sufficient personnel in our accounting and financial reporting functions. As a result, we were not able to achieve adequate segregation of duties and were not able to provide for adequate reviewing of the financial statements. This control deficiency, which is pervasive in nature, results in a reasonable possibility that material misstatements of the financial statements will not be prevented or detected on a timely basis; and

We did not maintain sufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of US GAAP commensurate with our complexity and our financial accounting and reporting requirements. This control deficiency is pervasive in nature and specifically resulted in us restating previously filed annual and quarterly financial statements as a result of errors in the accounting for convertible debentures and warrants. Further, there is a reasonable possibility that material misstatements of the consolidated financial statements including disclosures will not be prevented or detected on a timely basis as a result.

We are committed to improving our financial organization. As part of this commitment, we will create a segregation of duties consistent with control objectives and will look to increase our personnel resources and technical accounting expertise within the accounting function by the end of fiscal 2010 to resolve non-routine or complex accounting matters. In addition, when funds are available to the Company, which we expect to occur by the end of fiscal 2010, we will take the following action to enhance our internal controls: Hiring additional knowledgeable personnel with technical accounting expertise to further support the current accounting personnel at the Company, which management estimates will cost approximately $100,000 per annum. In January 2008, the Company engaged an outside consultant that specializes in the accounting for derivative instruments that are embedded within the Company's financing transactions. The Company will continue to engage consultants in the future as necessary in order to ensure proper treatment.

Management believes that hiring additional knowledgeable personnel with technical accounting expertise will remedy the following material weaknesses: (A) lack of sufficient personnel in our accounting and financial reporting functions to achieve adequate segregation of duties; and (B) insufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of US GAAP commensurate with our complexity and our financial accounting and reporting requirements.

Management believes that the hiring of additional personnel who have the technical expertise and knowledge with the non-routine or technical issues we have encountered in the past will result in both proper recording of these transactions and a much more knowledgeable finance department as a whole. Due to the fact that our accounting staff consists of a Chief Financial Officer, accounting manager and accounting clerk, additional personnel will also ensure the proper segregation of duties and provide more checks and balances within the department. Additional personnel will also provide the cross training needed to support us if personnel turn over issues within the department occur. We believe this will greatly decrease any control and procedure issues we may encounter in the future.

We will continue to monitor and evaluate the effectiveness of our disclosure controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow.

(b) Changes in internal control over financial reporting.

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.

There were no changes in our internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. We are currently not aware of any such legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse affect on our business, financial condition or operating results.

Item 1A. Risk Factors.

Not required under Regulation S-K for “smaller reporting companies.”

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

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

None.

Item 6. Exhibits

31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended

31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14 and Rule 15d 14(a), promulgated under the Securities and Exchange Act of 1934, as amended

32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer)

32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer)

SIGNATURES

In accordance with requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TRIANGLE PETROLEUM CORPORATION

Date: December 11, 2008	By:	/s/ MARK GUSTAFSON
	Mark Gustafson
	Chief Executive Officer (Principal Executive Officer)

Date: December 11, 2008	By:	/s/ SHAUN TOKER
	Shaun Toker
	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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Triangle Petroleum (TPLMQ) Inactive 10-Q2009 Q3 Quarterly report

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