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, 2009

¨ 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 ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   ¨ Yes  ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer,” 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 ¨   No x

As of November 20, 2009, there were 69,926,043 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, 2009 and January 31, 2009 (unaudited)	3
		Consolidated statements of operations for the three and nine months ended October 31, 2009 and 2008 (unaudited)	4
		Consolidated statements of cash flows for the three and nine months ended October 31, 2009 and 2008 (unaudited)	5
		Consolidated statements of stockholders’ equity for the three and nine months ended October 31, 2009 and 2008 (unaudited)	6
		Notes to unaudited consolidated financial statements	7 – 11
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12 – 21
	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	21
	ITEM 4T.	Controls and Procedures	21
PART II.	OTHER INFORMATION
	ITEM 1	Legal Proceedings	23
	ITEM 1A	Risk Factors	23
	ITEM 2	Unregistered Sales of Equity Securities and Use of Proceeds	23
	ITEM 3	Defaults Upon Senior Securities	23
	ITEM 4	Submission of Matters to a Vote of Security Holders	23
	ITEM 5	Other Information	23
	ITEM 6	Exhibits	23
	SIGNATURES		24

2

Triangle Petroleum Corporation

Consolidated Balance Sheets

(Expressed in U.S. dollars)

(Unaudited)

	October 31, 2009 $			January 31, 2009 $
ASSETS
Current Assets
Cash and cash equivalents		5,510,117			8,449,471
Prepaid expenses		321,271			339,839
Other receivables		278,799			998,511
Total Current Assets		6,110,187			9,787,821
Property and Equipment		46,548			39,765
Oil and Gas Properties (Note 3)		18,963,802			16,942,864
Total Assets		25,120,537			26,770,450
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable		411,970			2,123,079
Accrued liabilities		178,565			90,539
Total Current Liabilities		590,535			2,213,618
Asset Retirement Obligations (Note 4)		1,146,951			727,862
Total Liabilities		1,737,486			2,941,480
Going Concern (Note 1)
Commitment (Note 8)
Subsequent Events (Note 9)
Stockholders’ Equity
Common Stock Authorized: 150,000,000 shares, par value $0.00001 Issued: 69,926,043 shares (January 31, 2009 – 69,926,043 shares)		699			699
Additional Paid-In Capital		81,557,941			81,155,715
Warrants (Note 5)		4,237,100			4,237,100
Deficit		(62,412,689	)		(61,564,544	)
Total Stockholders’ Equity		23,383,051			23,828,970
Total Liabilities and Stockholders’ Equity		25,120,537			26,770,450

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

3

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,
	2009			2008			2009			2008
	$			$			$			$
Revenue, net of royalties		29,345			54,500			92,432			314,450
Operating Expenses
Oil and gas production		20,893			29,718			73,469			93,099
Depletion and accretion (Notes 3 and 4)		54,470			52,735			145,947			146,302
Depreciation – property and equipment		7,272			10,368			18,946			30,115
General and administrative (Note 7)		618,214			847,022			2,293,362			3,190,427
Impairment of oil and gas properties		-			8,000,000			-			8,000,000
Gain on sale of assets		(783,612	)		-			(908,233	)		(10,705	)
Foreign exchange loss (gain)		31,000			2,429,433			(676,654	)		2,454,022
		(51,763	)		11,369,276			946,837			13,903,260
Gain (loss) from Operations		81,108			(11,314,776	)		(854,405	)		(13,588,810	)
Other Income (Expense)
Accretion of discounts on convertible debentures		-			(602,277	)		-			(2,608,681	)
Amortization of debt issue costs		-			-			-			(182,637	)
Loss on debt extinguishment		-			-			-			(160,662	)
Interest expense		-			(189,041	)		-			(654,371	)
Interest and royalty income		47			127,681			6,260			209,911
Unrealized gain on fair value of derivatives		-			-			-			793,589
Total Other Income (Expense)		47			(663,637	)		6,260			(2,602,851	)
Income (Loss) for the Period		81,155			(11,978,413	)		(848,145	)		(16,191,661	)
Net Loss Per Share – Basic and Diluted		-			(0.18	)		(0.01	)		(0.28	)
Weighted Average Number of Shares Outstanding – Basic and Diluted		69,926,000			67,426,000			69,926,000			58,592,000

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

4

Triangle Petroleum Corporation

Consolidated Statements of Cash Flows

(Expressed in U.S. dollars)

(Unaudited)

	Three Months Ended October 31, 2009			Three Months Ended October 31, 2008			Nine Months Ended October 31, 2009			Nine Months Ended October 31, 2008
	$			$			$			$
Operating Activities
Gain (loss) for the period		81,155			(11,978,413	)		(848,145	)		(16,191,661	)
Adjustments to reconcile loss for the period to net cash used in operating activities:
Accretion of discounts on convertible debentures		-			602,277			-			2,608,681
Amortization of debt issue costs		-			-			-			182,637
Depletion and accretion (Notes 3 and 4)		54,470			52,735			145,947			146,302
Depreciation – property and equipment		7,272			10,368			18,946			30,115
Impairment of oil and gas costs		-			8,000,000			-			8,000,000
Stock-based compensation (Note 6)		131,763			135,393			402,226			476,427
Gain on sale of assets		(783,612	)		-			(908,233	)		(10,705	)
Loss on debt extinguishment		-			-			-			160,662
Unrealized gain on fair value of derivatives		-			-			-			(793,589	)
Unrealized foreign exchange changes		29,466			2,443,118			(680,346	)		2,443,118
Asset retirement costs (Note 4)		(17,447	)		(127,514	)		(23,956	)		(499,151	)
Changes in operating assets and liabilities (Note 7)		49,036			149,628			555,502			172,584
Cash Used in Operating Activities		(447,897	)		(712,408	)		(1,338,059	)		(3,274,580	)
Investing Activities
Purchase of property and equipment		(2,222	)		(5,850	)		(25,729	)		(9,791	)
Oil and gas property expenditures (Note 3)		(273,586	)		(1,127,139	)		(2,418,364	)		(4,863,048	)
Cash advances from partners		-			(1,560,410	)		(677,843	)		1,006,674
Proceeds received from sale of oil and gas properties		744,408			13,000			877,733			3,921,998
Cash Provided by (Used in) Investing Activities		468,600			(2,680,399	)		(2,244,203	)		55,833
Financing Activities
Proceeds from issuance of common stock		-			-			-			25,560,500
Share issuance costs		-			(25,569	)		-			(2,048,156	)
Convertible debenture repayment		-			-			-			(4,800,000	)
Cash Provided by Financing Activities		-			(25,569	)		-			18,712,344
Unrealized foreign exchange change on cash and cash equivalents		(30,616	)		(2,796,782	)		642,908			(2,796,782	)
Increase (Decrease) in Cash and Cash Equivalents		(9,913	)		(6,215,158	)		(2,939,354	)		12,696,815
Cash and Cash Equivalents – Beginning of Period		5,520,030			23,493,562			8,449,471			4,581,589
Cash and Cash Equivalents – End of Period		5,510,117			17,278,404			5,510,117			17,278,404
Cash								5,510,117			223,269
Cash equivalents								-			17,055,135
Non-cash Investing and Financing Activities
Common stock issued for conversion of debentures		-			-			-			2,100,140
Supplemental Disclosures
Interest Paid		-			-			-			1,299,860

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

5

Triangle Petroleum Corporation

Statement of Stockholders’ Equity

Nine Months Ended October 31, 2009 and 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 feature of convertible debentures converted		-		-		1,039,906			-		-			1,039,906
Stock based compensation (Note 6)		-		-		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
Balance – January 31, 2009		69,926,043		699		81,155,715			4,237,100		(61,564,544	)		23,828,970
Stock based compensation (Note 6)		-		-		402,226			-		-			402,226
Net loss for the period		-		-		-			-		(848,145	)		(848,145	)
Balance – October 31, 2009		69,926,043		699		81,557,941			4,237,100		(62,412,689	)		23,383,051

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

6

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.  The Company’s primary exploration and development acreage is located in the Horton Bluff formation of the Maritimes Basin in Canada. The Company also has minor producing properties in the Fort Worth Basin and in the Alberta Deep Basin.

1. Going Concern

The Company is primarily engaged in the acquisition, exploration and development of oil and gas resource properties and has a limited number of producing wells that generate cash flows from operations. The Company has not generated significant revenues from operations and has incurred significant losses since inception. These factors, among others, raise substantial doubt about the Company’s ability to continue as a going concern.

The Company will have to raise additional funds through equity or debt offerings, dispositions of assets or other means 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.

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.

2. Accounting Policies

(a)        Basis of Presentation

These financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States, and are expressed in U.S. dollars. These consolidated financial statements include the accounts of the Company and its two wholly-owned subsidiaries, Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, and Triangle USA Petroleum Corporation, incorporated in the State of Colorado, USA. All significant intercompany balances and transactions have been eliminated. The Company’s fiscal year-end is January 31.

In the opinion of management, the accompanying financial statements reflect all adjustments necessary of a normal recurring nature to present fairly our financial position at October 31, 2009 and our operations and cash flows for the three and nine month periods ended October 31, 2009 and 2008. 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. The results for interim periods are not necessarily indicative of annual results.

Certain reclassifications have been made to the prior period’s financial statements to conform to the current period’s presentation. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended January 31, 2009.

The Company’s oil and gas operations are generally conducted jointly with others and, as such, these financial statements reflect the Company’s proportionate share of these operations.

7

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

2. Accounting Policies (continued)

(b)        Recently Adopted Accounting Pronouncements

U.S. accounting standards setters have implemented new standards in December 2007 with respect to accounting for business combinations. These new standards require 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 was effective to business combinations after February 1, 2009. The adoption of these standards will impact business combinations, if any, after February 1, 2009.

In December 2007, new accounting standards were issued with respect to non-controlling interests in consolidated financial statements. These new standards require 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. These new standards were effective for the Company commencing on February 1, 2009. The adoption of these standards did not affect the Company's financial statements.

In March 2008, new accounting standards were issued with respect to disclosures about derivative instruments and hedging activities, which require disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. These new standards were effective on February 1, 2009. The adoption of these standards did not affect the Company's financial statements.

In May 2009, new accounting standards were issued with respect to subsequent events, which are intended to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  In particular, these standards set forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. These standards are effective for interim and annual periods ending after June 15, 2009. The adoption of this standard did not impact the third quarter financial statements except for disclosures with respect to the financial statement approval date. Subsequent events have been evaluated through November 23, 2009, the date at which the financial statements were approved for distribution.

3. Oil and Gas Properties

Nine months ended October 31, 2009:

	Costs						Accumulated Depletion									Net Carrying
	Opening		Additions		Closing		Opening		Depletion		Gain			Closing		Value
	$		$		$		$		$		$			$		$
Proved Properties		12,775,959		21,377		12,797,336		12,703,090		38,781		-			12,741,871		55,465
Unproven Properties		34,746,896		1,130,109		35,877,005		17,876,901		-		(908,233	)		16,968,668		18,908,337
Total		47,522,855		1,151,486		48,674,341		30,579,991		38,781		(908,233	)		29,710,539		18,963,802

8

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

3. Oil and Gas Properties (continued)

Proved Properties

At October 31, 2009, the carrying value of the Company’s proved properties was $55,465 (January 31, 2009 - $72,869), which were all located in the Alberta Deep Basin of Canada. For the three month period ended October 31, 2009, depletion expense was $8,436 (2008 - $12,796) in Canada and $nil (2008 - $nil) in the United States. For the nine month period ended October 31, 2009, depletion expense was $24,327 (2008 - $57,902) in Canada and $14,454 (2008 - $5,922) in the United States.

Unproven Properties

All of the Company’s unproven properties are not subject to depletion.

In September 2009, the Company sold its 50% working interest in 11,800 gross acres (5,900 net acres) in the Fayetteville area of Arkansas and all the related seismic rights for net cash proceeds of $744,408. The net book value of the U.S. properties at the time of sale was $171 and non-cash asset retirement obligations pertaining thereto were $39,375. As such, the Company recorded a gain on sale of assets of $783,612.

In June 2009, the Company sold its 25% working interest in 17,307 acres in the Nugget area of Colorado (Rocky Mountains project) for cash of $83,325 and recovered a drilling deposit in the Fayetteville area of Arkansas for cash of $50,000. The net book value of the U.S. properties at the time of sale was $8,704. As such, the Company recorded a gain on sale of assets of $124,621.

In June 2009, the Company acquired an additional 30% working interest in the Windsor Block of the Maritimes Basin in Nova Scotia from Contact Exploration Inc. (“Contact”) for a cash payment of approximately $245,000. The Company also agreed to provide Contact a 5.75% non-convertible gross overriding royalty interest and assumed the liabilities related to Contact's former working interest.

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

	October 31, 2009 $		January 31, 2009 $
Windsor Block of Maritimes Basin  (Nova Scotia)		18,703,319		16,818,586
Western Canadian Shale (Alberta and B.C.)		205,018		51,409
Total unproven acquisition and exploration costs		18,908,337		16,869,995

4. Asset Retirement Obligations

	Nine Months October 31, 2009 $			Nine Months October 31, 2008 $
Balance, beginning of period		727,862			1,003,353
Liabilities incurred		375,254			439,083
Liabilities settled as part of disposition		(39,375	)		(172,828	)
Liabilities settled in cash		(23,956	)		(499,151	)
Accretion		107,166			82,478
Balance, end of period		1,146,951			852,935

9

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

5. Warrants

As at October 31, 2009, 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.

6. Stock Options

No stock options were granted during the three month period ended October 31, 2009. The weighted average grant date fair value of stock options granted during the nine month period ended October 31, 2009 was $0.213. No stock options were exercised during the three and nine month periods ended October 31, 2009. During the three and nine month periods ended October 31, 2009, the Company recorded stock-based compensation of $131,763 and $402,226 (2008 - $135,393 and $476,427), respectively, as general and administrative expense.

A summary of the Company’s stock options outstanding is as follows:

	Options #			Weighted  Average  Exercise Price $		Aggregate Intrinsic Value $
Outstanding, January 31, 2009		4,985,000			1.14
Granted		250,000			0.27
Forfeited		(100,000	)		0.24
Outstanding, October 31, 2009		5,135,000			1.11	-
Exercisable, October 31, 2009		2,085,000			2.16	-

The weighted average remaining contractual life of stock options outstanding as of October 31, 2009 was 3.6 years.

As at October 31, 2009, there was $669,116 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 24 months.

A summary of the status of the Company’s non-vested share options as of October 31, 2009, and changes during the nine month period ended October 31, 2009, is presented below:

	Options #			Weighted Average  Grant-Date Fair Value $
Non-vested at January 31, 2009		3,525,000			0.31
Granted		250,000			0.21
Vested		(625,000	)		0.73
Forfeited		(100,000	)		0.09
Non-vested at October 31, 2009		3,050,000			0.22

10

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

7. Supplementary Cash Flow Information

	Three Months Ended October 31, 2009			Three Months Ended October 31, 2008			Nine Months Ended October 31, 2009			Nine Months Ended October 31, 2008
	$			$			$			$
Changes in operating assets and liabilities
Unrealized foreign exchange changes		(860	)		(19,809	)		(5,354	)		(19,809	)
Prepaid expenses		22,840			3,622			(781	)		58,261
Other receivables		22,860			(292,757	)		706,104			837,680
Accounts payable		574			278,796			(153,828	)		(18,944	)
Accrued interest on convertible debentures		-			189,045			-			(644,932	)
Accrued liabilities		3,622			(9,269	)		9,361			(39,672	)
Total		49,036			149,628			555,502			172,584

8. Commitment

The Company entered into a 10-year production lease for 474,625 gross acres on the Windsor Block in Nova Scotia, Canada on April 15, 2009. During the first five years of the lease, Triangle has agreed to continue to evaluate the Windsor Block by drilling seven wells, completing three wells previously drilled and acquiring seismic, which was estimated to cost C$12.7 million gross (approximately US$11.8 million). At the end of the fifth year of the lease, areas of the block not adequately drilled or otherwise evaluated may be subject to surrender. Furthermore, at the end of the second year of the lease, a technical report is required to be provided to and assessed by the Nova Scotia government to maintain certain lands.

During the first year of the lease, the Company has agreed to perform completion operations on the three wells drilled in the prior year and acquire seismic, which was estimated to cost C$2 million gross (approximately US$1.9 million). The Company posted a C$200,000 (approximately US$189,000) gross refundable deposit related to the first year commitment; should the Company not perform the work, a portion or all of the deposit could be forfeited. As of November 30, 2009, all three of the required well completions have been performed and the seismic has been acquired, which should satisfy the first year lease requirements.

9. Subsequent Events

In November 2009, the Company sold its remaining acreage in the Fayetteville area of Arkansas (3,380 net acres) for cash proceeds of approximately $247,000.  Also in November 2009, the Company entered into an agreement to sell its 18% working interest in one producing well and its 12% working interest in 1,280 gross acres (154 net acres) in the Alberta Deep Basin of Canada for cash proceeds of C$450,000 (approximately US$420,000), which is scheduled to close in early December.

11

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

We are an exploration company focused on emerging shale opportunities.  Our core project is focused on the Windsor Block in Nova Scotia, which is a shale gas opportunity located in the Maritimes Basin of Eastern Canada where we have an 87% working interest in 474,625 gross acres (412,924 net acres). We are also in the process of evaluating a potential secondary shale project in Western Canada. 

Our corporate strategy is to utilize our team’s U.S. shale experience to secure early stage shale projects in Canada.  In conjunction with this strategy, we have participated in various shale gas projects in North America, including the Barnett Shale trend in Texas (three producing wells), the Fayetteville Shale trend in Arkansas and the Beech Hill Block in New Brunswick.  We have also participated in conventional oil and gas plays in the province of Alberta (one producing well) and in the U.S Rocky Mountains. These other projects are currently designated as non-core due to our desire to focus our resources on our one core project

Prior to May 2005, we were known as Peloton Resources Inc., a mining exploration company which was actively searching for ore bodies containing gold in British Columbia. In May 2005, we abandoned all mining activities, changed our name to Triangle Petroleum Corporation and shifted our focus towards oil and gas exploration.

Plan of Operations

During fiscal 2010, our plan of operations was to finalize the Windsor Block production lease and fulfill the first year operations requirements under this new lease, which consisted of completing the three exploration wells drilled in 2008 and acquiring additional seismic, all of which has been completed and should satisfy the first year operations requirements. We also planned to search for one or more new joint venture partners to join us in the next phase of our Windsor Block exploration program and to actively position ourselves for entry into potential shale plays in Western Canada. For the balance of fiscal 2010, our plan is to process and interpret the seismic acquired on the Windsor Block in October 2009, continue searching for new joint venture partners in our Windsor Block exploration program and continue to position ourselves for entry into potential shale plays in Western Canada. We intend to allocate our available working capital to the Windsor Block and Western Canada as described above.  However, there may be circumstances where, for sound business reasons, a reallocation of the funds may be necessary.  Furthermore, while we intend to use our working capital as described above, our current working capital is not sufficient to complete the anticipated exploration programs.

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Properties

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

Core Property

Eastern Canadian Shale Gas Project – Windsor Block– We have an 87% working interest in 474,625 gross acres (412,924 net acres) in the Windsor Sub-Basin of the Maritimes Basin located in the Province of Nova Scotia, Canada and serve as operator of the Windsor Block; Zodiac Exploration Corp. has earned a 13% working interest in the Windsor Block. We acquired an additional 30% working interest in the Windsor Block in June 2009 from Contact Exploration Inc. (“Contact”) in exchange for agreeing to provide Contact a 5.75% non-convertible gross overriding royalty interest. Contact also received a cash payment of C$270,000 (approximately US$254,000) and we assumed the liabilities related to Contact's former working interest. Up to April 15, 2009, the land was governed by an exploration agreement. On April 15, 2009, the Windsor Block exploration agreement was transferred to a 10-year production lease. Under the terms of this lease:

· The production lease grants rights to 474,625 gross acres (412,924 net acres), covering substantially all of the land which we had leased previously under the terms of the exploration agreement. Fringe acreage deemed non-prospective was voluntarily surrendered;

· We hold rights to conventional oil and gas within the lease, which includes shale gas, in the Windsor and Horton Groups, excluding natural gas from coal. We believe coals are not prospective within the Windsor Block;

· To retain rights to this land block, we have agreed to continue to evaluate the lands during the first five years of the lease by drilling seven wells, completing three exploration wells previously drilled, and acquiring seismic, which was estimated to cost C$12.7 million gross (approximately US$11.9 million). These wells are to be distributed across the land block to fully evaluate conventional and shale resources. In addition to annual progress reporting to maintain the lease in good standing, on the second anniversary of the lease, we are obliged to provide a detailed report to the Nova Scotia government to assess our evaluation activities to maintain certain lands.  After the fifth anniversary, leased areas not adequately drilled or otherwise evaluated may be subject to surrender;

· During the first year of the lease, we agreed to complete the three exploration wells that were drilled in the prior year and acquire seismic, which was estimated to cost C$2 million gross (approximately US$1.9 million). A C$200,000 (US$188,000) gross refundable deposit was posted related to the first year commitment; should the work not be competed, a portion or all of the deposit could be forfeited;

· Current royalty rates are set at 10% in Nova Scotia; and

· Tenure on some or all of the lands is eligible for renewal after the first 10 years, based on the establishment of commercial production and/or the satisfaction of certain drilling and evaluation criteria.

From May 2007 to June 2008, we executed the first phase of the Windsor Block exploration program consisting of a 2D and 3D seismic program, geological studies, and drilling and completing two vertical test wells (Kennetcook #1 and Kennetcook #2). From July 2008 to September 2009, we executed the second phase of the Windsor Block shale gas exploration program, which consisted of drilling three vertical exploration wells (N-14-A, O-61-C and E-38-A) and undertaking completion operations on all three of these wells.

During the first quarter of fiscal 2010, we tested the N-14-A well, which was completed in early December 2008 with a four-stage perforation and fracture treatment. The frac flowback operations were suspended in April 2009 after the well recovered 15% of load fluid but negligible gas production.  Subsequent analysis indicated an unusually high insitu stress regime in the immediate vicinity of the well, which contributed to fracture ineffectiveness. Completion operations on the O-61-C well commenced in March 2009 and continued into early May. Several tight sand and carbonate intervals were perforated but have not yet been fracture-treated. No hydrocarbons flowed from the well.

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During the second and third quarters of fiscal 2010, three intervals in the E-38-A well were perforated and treated with diagnostic “micro-fracs.”  The two lower intervals appeared to have high insitu stress and a tendency to fracture horizontally.  The upper tested interval indicated lower stress and the likelihood of desirable vertical fracturing. As this was a diagnostic frac in a very low permeability zone, no gas flow was expected, and none was detected. We are continuing to work with these results to determine future completion operations as well looking for future drilling locations and completion strategies.

Also during the second quarter of fiscal 2010, the two wells drilled in 2007, Kennetcook #1 and Kennetcook #2, were re-entered to isolate and test individual zones to try to identify the “gassiest” intervals in each well and eliminate water inflow. From these tests, it appears the fracture treatments undertaken previously had commingled multiple zones together, making it difficult to determine which zone is contributing to the water inflow.

All three of our most recent wells (N-14-A, O-61-C, and E-38-A) still have a variety of completion and testing opportunities.  Our technical team is in the process of evaluating and ranking these opportunities with a goal of demonstrating hydrocarbon production and providing further direction to the ongoing exploration drilling program in the Windsor Block.

In October 2009, we acquired 30 kilometers of 2D seismic on the Windsor Block. Processing and interpretation of the seismic data is currently underway. The program is estimated to cost approximately $500,000. This seismic program assesses a geologic structure in the west-central area of the Windsor Block, where no seismic has yet been acquired. We believe that the best potential for both Horton Bluff gas shales and conventional reservoirs exists in areas with geologic structure. This seismic program, combined with the three completion operations on previously drilled vertical exploration wells, should satisfy the first-year requirements of our 10-year production lease.

Other Properties

Western Canadian Shale Project – We continue to actively position ourselves for an entry into potential shale plays in Alberta or British Columbia. Our objective is to potentially establish an initial land position and to commence an exploration program in 2009 or 2010. To date, we have undertaken in-depth technical studies of several prospective shale horizons using our proprietary shale knowledge and experience, and have identified prospective areas where we believe we may have a technical and business advantage. A joint venture partner will be added at the appropriate time to provide funding and mitigate exploration risk. This approach is consistent with the strategy we employed to establish our position in the Windsor Block in Nova Scotia.

Non-Core Properties – In fiscal 2009, there was no exploration activity on our non-producing and undeveloped land positions and we continue to plan not to participate in any exploration activity for these projects in fiscal 2010. We are in the process of rationalizing our non-core properties. During fiscal 2010, we sold:

· our 25% working interest 4,327 non-operated net acres in the U.S. Rocky Mountains for gross proceeds of $83,325 in June 2009;

· our 50% working interest in 5,900 non-operated net acres in the Fayetteville Shale and all the related seismic data for gross cash proceeds of $767,000 in September 2009 and our remaining 3,380 non-operated net acres of the Fayetteville Shale acreage for gross cash proceeds of $247,000 in November 2009. Costs related to these sales were approximately $70,000; and

· we entered into an agreement to sell one of the producing wells and our 12% working interest in 154 non-operated net acres in the Alberta Deep Basin for C$450,000 (approximately US$420,000) in November 2009, which is scheduled to close in early December.

Our remaining non-core producing properties include one well in the Alberta Deep Basin of Canada and three low working interest shale gas wells in the Barnett Shale trend. Our remaining non-core acreage holdings includes 5,165 net acres in the Alberta Deep Basin of Canada, 4,747non-operated net acres in the U.S. Rocky Mountains, and 61 non-operated net acres in the Barnett Shale trend.

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Results of operations for the three and nine months ended October 31, 2009 compared to the three and nine months ended October 31, 2008

Daily Sales Volumes, Working Interest before royalties

		Three Months Ended  October 31, 2009		Three Months Ended  October 31, 2008		Nine Months Ended  October 31, 2009		Nine Months Ended  October 31, 2008
Barnett Shale in Texas, USA	Mcf/day		35		33		48		58
Deep Basin in Alberta, Canada	Mcf/day		68		80		66		108
Total Company	Mcf/day		103		113		114		166
Total Company	Boe/day*		17		19		19		28

* Thousand Cubic Feet (“Mcf”) converted into Barrel of Oil Equivalent (“Boe”) on a basis of 6:1

Net Operating Results

		Three Months Ended October 31, 2009		Three Months Ended October 31, 2008		Nine Months Ended October 31, 2009		Nine Months Ended October 31, 2008
Volumes	Mcf		9,499		10,401		31,039		45,306
Price	$/Mcf		3.54		6.63		3.53		8.50
Revenue		$	33,622	$	69,008	$	109,606	$	384,970
Royalties			4,277		14,508		17,174		70,520
Revenue, net of royalties			29,345		54,500		92,432		314,450
Production expenses			20,893		29,718		73,469		93,099
Net		$	8,452	$	24,782	$	18,963	$	221,351

For the three and nine month periods ended October 31, 2009, we realized $33,622 and $109,606, respectively, in revenue from sales of natural gas and natural gas liquids, as compared to $69,008 and $384,970 in the same periods of the prior year. Revenue decreased mainly due to reduced natural gas prices, and to a lesser effect, due to reduced production volumes. Royalties as a percent of revenue were 13% and 16% for the three and nine month periods ended October 31, 2009, respectively, as compared to 21% and 18% in the same periods of the prior year. The decrease in royalty rates is due to the sliding scale of royalty rates as gas prices decrease. Production expenses related to this revenue were $13.20/Boe and $14.20/Boe for the three and nine month periods ended October 31, 2009, respectively, compared to $17.14/Boe and $12.33/Boe in the same periods of the prior year; the increase in the per Boe rate in the nine month period ended October 31, 2009 was mainly the effect of fixed production costs being spread over reduced production volumes.

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Depletion, Depreciation and Accretion

	Three Months Ended October 31, 2009		Three Months Ended October 31, 2008		Nine Months Ended October 31, 2009		Nine Months Ended October 31, 2008
Depletion – oil and gas properties	$	8,434	$	12,796	$	38,781	$	63,824
Accretion		46,036		39,939		107,166		82,478
Depletion and Accretion		54,470		52,735		145,947		146,302
Depreciation – property and equipment		7,272		10,368		18,946		30,115
Total	$	61,742	$	63,103	$	164,893	$	176,417
Depletion per BOE	$	5.33	$	7.38	$	7.50	$	8.45

Unproven property costs of $18,908,337 (January 31, 2009 – $16,869,995) were excluded from costs subject to depletion at October 31, 2009. Depletion expense per Boe related to oil and gas properties in the three and nine month periods ended October 31, 2009 decreased as compared with the same period of the prior year mainly as a result of the ceiling test write-downs on proved properties in the previous year which decreased the depletion base.

General and Administrative (“G&A”)

	Three Months Ended October 31, 2009			Three Months Ended October 31, 2008			Nine Months Ended October 31, 2009			Nine Months Ended October 31, 2008
Salaries, benefits and consulting fees	$	288,339		$	391,750		$	1,053,322		$	1,349,859
Office costs		124,943			230,333			428,070			680,827
Professional fees		25,975			47,920			209,823			344,866
Public company costs		57,130			126,441			242,185			455,444
Operating overhead recoveries		(9,936	)		(84,815	)		(42,264	)		(116,996	)
Stock-based compensation		131,763			135,393			402,226			476,427
Total G&A	$	618,214		$	847,022		$	2,293,362		$	3,190,427

G&A expenses decreased in the three and nine month periods ended October 31, 2009 compared to the same period of the prior year primarily due to management implementing cost reductions and in the nine months ended October 31, 2009 due to the strengthening of the U.S. dollar versus the Canadian dollar, including:

· Salaries, benefits and consulting fees, which are primarily incurred in Canadian dollars, decreased $103,411 and $296,537 in the three and nine month periods, respectively, mainly due to reduced staff and consultants of $101,000 and $167,000, respectively, and the strengthening of the U.S. dollar versus the Canadian dollar by 11% in the nine month period causing a decrease of $132,000;

· Office costs, which are primarily incurred in Canadian dollars, decreased in the three and nine month periods $105,390 and $252,757, respectively, mainly due to reduced software, insurance and travel costs of $51,000 and $126,000, respectively, and the strengthening of the U.S. dollar versus the Canadian dollar by 11% in the nine month period causing a decrease of $67,000;

· Professional fees, which are primarily incurred in Canadian dollars, decreased in the nine month period $135,043 mainly due to reduced audit and accounting fees of $101,000, which were higher in the prior year due to non-recurring audit and accounting fees for restatements of financial statements, and the strengthening of the U.S. dollar versus the Canadian dollar by 11% causing a decrease of $33,000, which was offset by increased legal fees of $9,000 due to the TSX Venture listing late in the prior year. Professional fees decreased in the three month period $21,945 mainly due to decreased legal fees of $13,000 and reduced audit and tax fees of $8,000 due to the TSX Venture listing late in the prior year; and

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· Public company costs decreased in the three and nine month periods $69,313 and $213,259, respectively, mainly due to reduced investor relation costs of $40,000 and $149,000, respectively.  Public company costs consist mainly of fees for investor relations and also include directors' fees, press release costs, Securities Exchange Commission  and Toronto Stock Exchange filing costs, printing costs and transfer agent fees.

Accretion of Discounts on Convertible Debentures

Agreement Date	Three Months Ended  October 31, 2009		Three Months Ended  October 31, 2008		Nine Months Ended  October 31, 2009		Nine Months Ended  October 31, 2008
December 8, 2005	$	-	$	-	$	-	$	813,337
December 28, 2005		-		602,277		-		1,795,344
Total accretion of discounts	$	-	$	602,277	$	-	$	2,608,681

The accretion of discounts was fully recognized in the prior year since the December 8, 2005 debentures were fully converted and repaid June 5, 2008 and the December 28, 2005 debentures were settled December 18, 2008.

Interest Expense

Agreement Date	Three Months Ended  October 31, 2009		Three Months Ended  October 31, 2008		Nine Months Ended  October 31, 2009		Nine Months Ended  October 31, 2008
December 8, 2005	$	-	$	-	$	-	$	91,360
December 28, 2005		-		189,041		-		563,011
Total interest expense	$	-	$	189,041	$	-	$	654,371

There was no interest expense in the current period since the December 8, 2005 debentures were fully converted and repaid June 5, 2008 and the December 28, 2005 debentures were settled December 18, 2008.

Oil and Gas Properties

	Net Book Value January 31, 2009		Additions			Depletion and Impairment			Dispositions			Gain (Loss)		Net Book Value October 31, 2009
Unproven
Windsor Block Maritimes Shale – Nova Scotia, Canada	$	16,818,586	$	1,884,733		$	-		$	-		$	-	$	18,703,319
Western Canadian Shale – Alberta and B.C., Canada		51,409		153,609			-			-			-		205,018
Fayetteville and Rocky Mountains		-		(30,500	)		-			(877,733	)		908,233		-
Proved
Canada		72,869		6,923			(24,327	)		-			-		55,465
U.S.A.		-		14,454			(14,454	)		-			-		-
Net	$	16,942,864	$	2,029,219		$	(38,781	)	$	(877,733	)	$	908,233	$	18,963,802

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During the nine month period ended October 31, 2009, we focused on the Windsor Block and spent $1,884,733 primarily for:

· completing the second phase of the Windsor Block exploration program consisting of testing the N-14-A well (approximately $163,000), completion operations on the O-61-C well (approximately $206,000), completion operations on the E-38-A well (approximately $188,000) and capitalizing the related non-cash asset retirement costs (approximately $213,000);

· retesting the Kennetcook #1 and #2 wells (approximately $232,000);

· acquiring Contact’s 30% working interest in the Windsor Block for cash of $245,000 and the assumption of future estimated non-cash asset retirement costs of $144,750. We also agreed to provide Contact a 5.75% non-convertible gross overriding royalty interest on our resulting 87% working interest; and

· acquiring 2D seismic (approximately $441,000).

During the nine month period ended October 31, 2009, we sold our:

· 25% working interest 4,327 non-operated net acres in the U.S. Rocky Mountains for gross proceeds of $83,325 in June 2009; and

· 50% working interest in 5,900 non-operated net acres in the Fayetteville Shale and all the related seismic data for gross cash proceeds of $767,000 in September 2009. Furthermore, a $50,000 drilling deposit was refunded related to the Fayetteville Shale properties.

Net Cash Oil and Gas Additions:

	Three Months Ended October 31, 2009			Three Months Ended October 31, 2008			Nine Months Ended October 31, 2009			Nine Months Ended October 31, 2008
Net additions	$	797,156		$	2,227,249		$	2,029,220		$	3,970,840
Non-cash ARO additions		(230,504	)		(393,633	)		(375,254	)		(439,083	)
Non-cash ARO dispositions		39,375			35,399			39,375			172,828
Changes in investing working capital		(332,441	)		(741,876	)		725,023			1,158,463
Net oil and gas additions, per Statements of Cash Flows	$	273,586		$	1,127,139		$	2,418,364		$	4,863,048

Liquidity and Capital Resources

To date, we have not generated significant revenues and have incurred significant operating losses in every quarter. These factors among others raise substantial doubt about our ability to continue as a going concern.

As at October 31, 2009, we had working capital of $5,519,652, resulting primarily from our cash of $5,510,117, prepaid expenses of $321,271 and other receivables of $278,799, offset by payables and accrued liabilities of $590,535. For the nine month period ended October 31, 2009, we had a net cash outflow from operating activities before changes in working capital of $1,893,561, mainly related to $1,891,136 of cash general and administrative expenses, which is equal to general and administrative expenses net of non-cash stock based compensation expense.

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On April 15, 2009 we converted the Windsor Block exploration agreement to a 10 year production lease for 474,625 gross acres (412,924 net acres) of land. During the first five years of the lease, we agreed to continue to evaluate the Block by drilling seven wells, completing three exploration wells previously drilled and acquiring seismic at a total gross estimate cost of C$12.7 million (US$11.7 million). At the end of the second year of the lease, a technical report is due and the Nova Scotia government may request the surrender of certain lands they deem not adequately evaluated. At the end of the fifth year of the lease, areas of the land block not adequately drilled or otherwise evaluated may be subject to surrender. During the first year of the lease, we have agreed to spend an estimated gross C$2,000,000 to complete the three exploration wells drilled in the prior year and to acquire seismic. We paid a C$200,000 gross refundable deposit related to the first year commitment; should we not have performed the work, a portion or all of the deposit could be forfeited. As of November 23, 2009, all three of the required well completions have been performed and the seismic has been acquired, which should satisfy the first year lease requirements.

We expect significant capital expenditures during the next 12 months for drilling programs on our Canadian shale program, overhead and working capital purposes. There is a risk that our joint venture partner in the Windsor Block will not be able to pay for their portion (13%) of the well costs, which would slow down or stop exploration on the Windsor Block. There is also a risk we may not secure a new joint operating partner in the Windsor Block, which would slow down or stop exploration on the Windsor Block. 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 2010 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 and the attainment of profitable operations.

By adjusting our operations to the current 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.

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.

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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 have 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 obligations 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 our stock price volatility and the options expected life. Compensation costs are recognized over the vesting period.

Recently Issued Accounting Pronouncements

In December 2008, the SEC adopted revisions to its required oil and gas reporting disclosures. Additionally, on two separate occasions in October 2009, the SEC issued certain compliance and disclosure interpretations of its oil and gas rules. The disclosure revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. In the three decades that have passed since adoption of these disclosure items, there have been significant changes in the oil and gas industry. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology. In addition, the amendments concurrently align the SEC’s full cost accounting rules with the revised disclosures. The revised disclosure requirements must be incorporated in registration statements filed on or after January 1, 2010, and annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required.

The following amendments have the greatest likelihood of affecting our reserve disclosures, including the comparability of our reserves disclosures with those of our peer companies:

· Pricing mechanism for oil and gas reserves estimation - The SEC’s current rules require proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. Price changes can be made only to the extent provided by contractual arrangements. The revised rules require reserve estimates to be calculated using a 12-month average price. The 12-month average price will also be used for purposes of calculating the full cost ceiling limitations. Price changes can still be incorporated to the extent defined by contractual arrangements. The use of a 12-month average price rather than a single-day price is expected to reduce the impact on reserve estimates and the full cost ceiling limitations due to short-term volatility and seasonality of prices;

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· Reasonable certainty - The SEC’s current definition of “proved oil and gas reserves” incorporates certain specific concepts such as “lowest known hydrocarbons,” which limits the ability to claim proved reserves in the absence of information on fluid contacts in a well penetration, notwithstanding the existence of other engineering and geoscientific evidence.

The revised rules amend the definition to permit the use of new reliable technologies to establish the reasonable certainty of proved reserves. This revision also includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations;

· The revised rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty. These revisions are designed to permit the use of reliable technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells.

Because the revised rules generally expand the definition of proved reserves, we expect our proved reserve estimates will increase upon adoption of the revised rules. However, we are not able to estimate the magnitude of the potential increase at this time; and

· Unproved reserves - The SEC’s current rules prohibit disclosure of reserve estimates other than proved in documents filed with the SEC. The revised rules permit disclosure of probable and possible reserves and provide definitions of probable reserves and possible reserves. Disclosure of probable and possible reserves is optional. However, such disclosures must meet specific requirements. Disclosures of probable or possible reserves must provide the same level of geographic detail as proved reserves and must state whether the reserves are developed or undeveloped. Probable and possible reserve disclosures must also provide the relative uncertainty associated with these classifications of reserves estimations. We have not yet determined whether we will disclose our probable and possible reserves in documents filed with the SEC.

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, 2009. 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.

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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:

a) 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

b) 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.

Management believes that hiring additional knowledgeable personnel with technical accounting expertise will remedy the material weaknesses. Due to the fact that our accounting staff consists of a Chief Financial Officer and accounting clerk, additional personnel will also ensure the proper segregation of duties and provide more checks and balances within the department. We believe this will greatly decrease any control and procedure issues we may encounter in the future. To compensate for the current limited number of personnel in the accounting and reporting group, we focus on audit committee oversight and the use of external consultants for complex accounting matters. Furthermore, we will continue to engage consultants in the future as necessary in order to ensure proper accounting treatment of complex transactions.

Management 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. As part of this commitment, we will continue to assess our current personnel resources and technical accounting expertise within the accounting function. As our activities levels increase, we will look to increase our personnel resources to increase segregation of duties and provide in-house non-routine or complex accounting expertise. When funds are available to us and as operations increase, we will hire additional knowledgeable personnel with technical accounting expertise to further support our current accounting personnel, which management estimates could cost approximately $100,000 per annum.

(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.

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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

31.01 Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.02 Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.01 Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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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:  November 23, 2009	By:	/s/ MARK GUSTAFSON
	Mark Gustafson
	Chief Executive Officer (Principal Executive Officer)
Date:  November 23, 2009	By:	/s/ SHAUN TOKER
	Shaun Toker
	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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