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 July 31, 2012

¨ 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  001-34945

TRIANGLE PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Nevada	98-0430762
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

1200 17^th Street, Suite 2600

Denver, CO 80202

(Address of Principal Executive Offices)

(303) 260-7125

(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).    x Yes  ¨ No

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 filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨	Accelerated filer x
Non-accelerated filer ¨	Smaller reporting company ¨
(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 August 31, 2012, there were 44,311,163 shares of the registrant’s common stock outstanding.

TRIANGLE PETROLEUM CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JULY 31, 2012

PART I.  FINANCIAL INFORMATION
	ITEM 1.	Financial Statements
		Condensed Consolidated Balance Sheets – July 31, 2012 and January 31, 2012	3
		Condensed Consolidated Statements of Operations and Comprehensive Loss – Three and Six months ended July 31, 2012 and 2011	4
		Condensed Consolidated Statements of Cash Flows - Six months ended July 31, 2012 and 2011	5
		Condensed Consolidated Statement of Stockholders’ Equity - Six months ended July 31, 2012	6
		Notes to Condensed Consolidated Financial Statements	7 – 22
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	31
	ITEM 4.	Controls and Procedures	31
PART II.  OTHER INFORMATION
	ITEM 1.	Legal Proceedings	32
	ITEM 1A.	Risk Factors	32
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
	ITEM 3.	Defaults Upon Senior Securities	33
	ITEM 4.	Mine Safety Disclosures	33
	ITEM 5.	Other Information	33
	ITEM 6.	Exhibits	34
	SIGNATURES		36

2

Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets

(unaudited)

	July 31,			January 31,
	2012			2012
ASSETS
CURRENT ASSETS
Cash	$	116,357,033		$	68,815,040
Prepaid expenses		407,914			161,650
Accounts receivable:
Oil and natural gas sales		5,459,171			5,422,453
Trade		26,683,171			3,929,465
Other		423,106			474,016
Inventory		351,360			-
Total current assets		149,681,755			78,802,624
LONG-TERM ASSETS
Oil and gas properties at cost, using the full cost method of accounting:
Unproved properties and properties under development, not being amortized		105,031,334			111,716,360
Proved properties		107,054,256			33,172,419
		212,085,590			144,888,779
Less: accumulated amortization		(8,129,001	)		(3,118,000	)
Net oil and natural gas properties		203,956,589			141,770,779
Other property and equipment (less accumulated depreciation of $644,065 and $85,122, respectively)		28,599,684			1,226,725
Deposits on equipment under construction		-			5,647,576
Prepaid drilling costs		1,653,506			2,192,963
Other long-term assets		779,818			203,987
Total assets	$	384,671,352		$	229,844,654
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	27,860,573		$	3,428,917
Accrued liabilities:
Exploration and development		23,359,289			11,807,040
Other		3,624,317			3,189,806
Asset retirement obligations		1,448,790			1,539,871
Total current liabilities		56,292,969			19,965,634
LONG-TERM LIABILITIES
Credit facility		-			-
Convertible note		120,000,000			-
Asset retirement obligations		125,856			83,418
Total liabilities		176,418,825			20,049,052
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY
Common stock, $0.00001 par value, 70,000,000 shares authorized; 44,310,085 and 43,515,958 shares issued and outstanding at July 31, 2012 and January 31, 2012, respectively		443			435
Additional paid-in capital		317,189,954			314,199,952
Accumulated deficit		(112,240,921	)		(108,260,138	)
Accumulated other comprehensive income		-			-
Total parent company stockholders’ equity		204,949,476			205,940,249
Noncontrolling interest in subsidiary		3,303,051			3,855,353
Total stockholders' equity		208,252,527			209,795,602
Total liabilities and stockholders’ equity	$	384,671,352		$	229,844,654

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

3

Triangle Petroleum Corporation

Condensed Consolidated Statements of Operations and Comprehensive Loss

(unaudited)

	Three Months Ended July 31,						Six Months Ended July 31,
	2012			2011			2012			2011
REVENUES
Oil and natural gas sales	$	7,507,137		$	624,985		$	12,679,613		$	1,138,267
Pressure-pumping services		2,594,552			-			2,594,552			-
Other		156,104			-			225,051			-
		10,257,793			624,985			15,499,216			1,138,267
EXPENSES
Production taxes		837,020			87,897			1,428,677			128,401
Other lease operating		246,709			704,384			499,555			732,714
Depletion, depreciation and amortization		2,996,855			178,224			5,170,218			341,985
Accretion of asset retirement obligations		84,095			70,259			167,589			140,319
Pressure-pumping		1,845,348			-			2,031,516			-
General and administrative:
Stock-based compensation		1,433,047			3,491,693			2,797,941			3,557,791
Salaries and benefits		2,510,134			885,499			4,676,348			1,545,193
Other general and administrative		1,566,770			1,623,490			3,324,954			2,083,832
Foreign exchange loss		262			10,328			409			2,066
Total operating expenses		11,520,240			7,051,774			20,097,207			8,532,301
LOSS FROM OPERATIONS		(1,262,447	)		(6,426,789	)		(4,597,991	)		(7,394,034	)
OTHER INCOME (EXPENSE)
Other income		61			-			8,563			-
Interest income		85,094			98,764			98,217			194,237
Interest expense		(31,614	)		-			(41,874	)		-
Total other income (expense)		53,541			98,764			64,906			194,237
NET LOSS BEFORE INCOME TAXES		(1,208,906	)		(6,328,025	)		(4,533,085	)		(7,199,797	)
Income tax provision		-			-			-			-
NET LOSS		(1,208,906	)		(6,328,025	)		(4,533,085	)		(7,199,797	)
Less: net loss attributable to noncontrolling interest in subsidiary		256,398			-			552,302			-
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(952,508	)	$	(6,328,025	)	$	(3,980,783	)	$	(7,199,797	)
NET LOSS PER COMMON SHARE - BASIC AND DILUTED	$	(0.02	)	$	(0.15	)	$	(0.09	)	$	(0.19	)
Weighted average common shares outstanding - basic and diluted		44,264,769			43,009,659			44,162,484			37,834,109
COMPREHENSIVE LOSS
Net loss attributable to common stockholders	$	(952,508	)	$	(6,328,025	)	$	(3,980,783	)	$	(7,199,797	)
Other comprehensive income (loss)		-			-			-			-
Total comprehensive loss	$	(952,508	)	$	(6,328,025	)	$	(3,980,783	)	$	(7,199,797	)

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

4

Triangle Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Six Months Ended July 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(4,533,085	)	$	(7,199,797	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		5,170,218			341,985
Stock-based compensation		3,327,241			3,557,791
Accretion of asset retirement obligations		167,589			140,319
Amortization of prepaid loan costs		29,109			-
Changes in related current assets and liabilities:
Prepaid expenses and deposits		(474,221	)		(209,480	)
Accounts receivable:
Oil and natural gas sales		(36,718	)		-
Trade		(22,753,706	)		-
Other		50,910			(95,047	)
Inventory		(351,360	)		-
Accounts payable and accrued liabilities		23,688,185			(1,934,518	)
Asset retirement expenditures		(248,069	)		-
Cash provided by (used in) operating activities		4,036,093			(5,398,747	)
CASH FLOWS FROM INVESTING ACTIVITIES
Oil and natural gas property expenditures		(55,951,965	)		(74,298,775	)
Sale of oil and natural gas properties		2,712,066			46,800
Purchase of other property and equipment		(21,875,692	)		(243,906	)
Cash advanced to operators for oil and natural gas property expenditures		539,457			(2,071,104	)
Cash used in investing activities		(74,576,134	)		(76,566,985	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock		-			142,312,500
Common stock issuance costs		-			(7,569,527	)
Proceeds from issuance of convertible note		120,000,000			-
Credit facility issuance costs		(376,984	)		-
Proceeds from credit facility		13,700,000			-
Repayment of credit facility		(13,700,000	)		-
Cash paid to settle tax on vested restricted stock units		(1,553,482	)		-
Issuance of common stock for exercise of options		12,500			110,651
Cash provided by financing activities		118,082,034			134,853,624
NET INCREASE IN CASH		47,541,993			52,887,892
CASH, BEGINNING OF PERIOD		68,815,040			57,773,269
CASH, END OF PERIOD	$	116,357,033		$	110,661,161

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

5

Triangle Petroleum Corporation

Condensed Consolidated Statement of Stockholders' Equity

(unaudited)

For the six months ended July 31, 2012

	Shares of Common Stock		Common Stock at Par Value		Additional Paid- in Capital			Accumulated Deficit			Non-controlling interest in Subsidiary			Total Equity
Balance - January 31, 2012		43,515,958	$	435	$	314,199,952		$	(107,814,197	)	$	3,944,542		$	210,330,732
Cumulative effect of change in accounting principle		-		-		-			(445,941	)		(89,189	)		(535,130	)
Balance - January 31, 2012, as adjusted		43,515,958		435		314,199,952			(108,260,138	)		3,855,353			209,795,602
Common stock issued for the purchase of oil and natural gas properties		225,000		2		1,203,748			-			-			1,203,750
Shares issued for consulting services		10,000		1		72,899			-			-			72,900
Exercise of stock options		4,167		-		12,500			-			-			12,500
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes)		17,230		-		98,728			-			-			98,728
Vesting of restricted stock units (net of shares surrendered for taxes)		537,730		5		(1,553,486	)		-			-			(1,553,481	)
Stock-based compensation		-		-		3,155,613			-			-			3,155,613
Net loss for the period		-		-		-			(3,980,783	)		(552,302	)		(4,533,085	)
Balance - July 31, 2012		44,310,085	$	443	$	317,189,954		$	(112,240,921	)	$	3,303,051		$	208,252,527

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

6

Triangle Petroleum Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

1. Organization and Nature of Operations

Triangle Petroleum Corporation (“Triangle,” “we,” “us,” “our,” or the “Company”) is an exploration and production company currently focused on the development of unconventional shale oil and natural gas resources in the Bakken Shale and Three Forks formations in the Williston Basin of North Dakota and Montana.

We own an 83.33% interest in RockPile Energy Services LLC, a Delaware limited liability company (“RockPile”), which is a hydraulic pressure pumping company focused on the Williston Basin of North Dakota and Montana. RockPile was formed in June of 2011 and commenced field operations in July 2012.

2. Basis of Presentation and Significant Accounting Policies

The accompanying condensed consolidated balance sheet as of January 31, 2012 has been derived from our audited financial statements. The accompanying unaudited condensed interim consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) and are expressed in U.S. dollars. These condensed consolidated financial statements include the accounts of the Company and (a) its wholly-owned subsidiaries: (i) Triangle USA Petroleum Corporation (“TUSA”), incorporated in the State of Colorado (including TUSA’s wholly owned subsidiaries) and (ii) Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, (b) its 83.33% owned subsidiary RockPile and (c) certain insignificant wholly-owned limited liability companies. All significant intercompany balances and transactions have been eliminated. The Company’s fiscal year-end is January 31.

Certain information and footnote disclosure normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”) have been condensed or omitted pursuant to SEC rules and regulations. We believe the disclosures made are adequate to make the information not misleading. We recommend that these condensed consolidated financial statements be read in conjunction with our audited financial statements and notes included in our Annual Report on Form 10-K/A for the fiscal year ended January 31, 2012, filed with the SEC on May 18, 2012.

In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the three and six month periods ended July 31, 2012 are not necessarily indicative of the operating results for the entire fiscal year ending January 31, 2013.

Change in Accounting Principle: RockPile changes fiscal year-end from December 31 to January 31

RockPile has historically had a December 31 year-end. Thus, RockPile’s financial results included in our consolidated financial statements were a month behind the financial results of our oil and natural gas exploration and production operating segment. With the start of RockPile operations in July 2012, RockPile has changed to a January 31 year-end. The change is preferable as it results in contemporaneous reporting of RockPile’s financial results in providing pressure pumping services for owners of oil wells operated by our subsidiary TUSA. The change avoids the need to provide supplemental disclosure of material intervening events arising from a one-month lag in financial reporting.

7

A change in a subsidiary’s fiscal year-end is a change in accounting principle for Triangle. Paragraph 810-10-45-13 of the Accounting Standards Codification (“ASC”) requires that the elimination of a reporting lag between a parent and subsidiary be reported as a change in accounting principle. Topic 250 of the ASC requires this change to be applied retrospectively in financial statements for all periods presented. Accordingly, the financial statements presented herein reflect RockPile financial results as if RockPile had always had a January 31 fiscal year-end.

The change had no impact on our statements of operations or cash flows for the six-month period ended July 31, 2011, given that RockPile was newly formed and inactive prior to August 2011. Since RockPile began pressure pumping operations in July 2012, the accounting change has the following notable effects on the statement of operations for the three and six month periods ended July 31, 2012:

· Recognition of $2,594,552 in pressure-pumping revenue and $1,845,348 in pressure-pumping expenses for the month of July 2012,

· Increasing general and administrative expenses by approximately $118,000 and $82,000, respectively,

· Reducing consolidated net loss by $1,228,198 and $1,258,914 respectively,

· Reducing net loss attributable to common stockholders by $1,023,498 and $1,049,095, respectively, and

· Reducing net loss per share by approximately $0.02 and $0.02, respectively.

The change in accounting principle had the following impact on the Condensed Consolidated Balance Sheet as of July 31, 2012:

· Cash decreased by approximately $0.9 million,

· Current assets increased by approximately $1.2 million,

· Fixed assets decreased by approximately $0.9 million,

· Total assets increased by approximately $0.3 million,

· Total liabilities decreased by approximately $0.2 million, and

· Accumulated deficit decreased by approximately $0.5 million.

For the Condensed Consolidated Balance Sheet as of January 31, 2012, the change in accounting principle:

· Decreased current assets by $744,099,

· Decreased total assets by $742,048,

· Decreased current liabilities and total liabilities by $206,920 each,

· Increased accumulated deficit by $445,942, and

· Decreased stockholders’ equity by $535,130.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, including contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and natural gas reserve quantities provide the basis for the calculation of depletion, depreciation, amortization and impairment, each of which represents a significant component of the consolidated financial statements. Management estimated the proved reserves as of July 31, 2012 with consideration of (1) the proved reserve estimates for the prior fiscal year-end prepared by independent engineering consultants and (2) any significant new discoveries and changes during the interim period in production, ownership, and other factors underlying reserve estimates

8

Significant Accounting Policies

For descriptions of the Company’s significant accounting policies, please see pages 53 through 55 of our Annual Report on Form 10-K/A for the fiscal year ended January 31, 2012, filed with the SEC on May 18, 2012.

Amortization of oil and natural gas property costs is computed on a closed quarter basis, using the estimated proved reserves as of the end of the quarter. Amortization for the fiscal year is the sum of the four quarterly amortization amounts.

Deferred financing costs include origination, legal, and other fees incurred in connection with TUSA entering into its Credit Facility (as defined below). See Note 6 – Credit Facility. Deferred financing costs related to the Credit Facility are amortized to interest expense on a straight-line basis over the respective borrowing term.

The carrying amounts reported in the consolidated balance sheets for cash, accounts receivable, prepaid expenses, accounts payable and accrued liabilities approximate fair value because of the immediate or short-term maturity of these financial instruments. The recorded value of the Company’s Credit Facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. As of July 31, 2012, the Company had no outstanding loan balance under its Credit Facility.

Convertible Note—As further described in Note 7, on July 31, 2012, the Company both issued a $120,000,000 Convertible Note (“Note”) and received $120,000,000 cash for that Note. The Company has elected (under ASC Topic 825) to not carry the $120,000,000 Note at fair value. The Note is a hybrid instrument containing a compound embedded derivative liability. The compound embedded derivative includes the conversion feature and early redemption options. The conversion feature begins after the close of the Company’s upcoming Annual Stockholders’ meeting scheduled for December 3, 2012. At July 31, 2012, the $120,000,000 Note consisted of a compound embedded derivative liability with an estimated $42,500,000 fair value at July 31, 2012 and a discounted note with a carrying value of $77,500,000.

The discounted note’s $42,500,000 discount will be amortized to interest expense using the effective interest method over the ten years prior to when the Note holder can have the Note redeemed. The compound embedded derivatives within the secured convertible notes have been recorded at estimated fair value at the date of issuance; and will be marked-to-market each subsequent reporting period with changes in fair value recorded to the Company's statement of operations as derivative instrument expense.

Fair Value Measurement—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk.

As of July 31, 2012, the carrying amounts of our cash and cash equivalents, trade receivables and payables and prepaid expenses represented fair value because of the short-term nature of these instruments.

9

Recent Accounting Pronouncements

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”), which requires that an entity disclose both gross and net information about instruments and transactions that are either eligible for offset in the balance sheet or subject to an agreement similar to a master netting agreement, including derivative instruments. ASU 2011-11 was issued in order to facilitate comparison of financial statements prepared under U.S. GAAP and International Financial Reporting Standards by requiring enhanced disclosures, but does not change existing U.S. GAAP that permits balance sheet offsetting. This authoritative guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The adoption of this authoritative guidance will not have an impact on Triangle's financial position or results of operations, but may require enhanced disclosures regarding its derivative instruments in future periods.

ASU 2011-04 “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” - In May 2011, the Financial Accounting Standards Board (“FASB”) issued additional guidance intended to result in convergence between U.S. GAAP and International Financial Reporting Standards (“IFRS”) requirements for measurement of and disclosures about fair value. The amendments are not expected to have a significant impact on companies applying U.S. GAAP. Principal provisions of the amendments include: (i) application of the ‘highest and best use’ is relevant only when measuring fair value for non-financial assets and liabilities; (ii) a prohibition on grouping financial instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the group; (iii) an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to financial instruments with quoted prices in active markets); (iv) guidance that fair value measurement of equity instruments should be made from the perspective of a market participant that holds that instrument as an asset; and (v) a requirement that for recurring Level 3 fair value measurements, entities disclose quantitative information about unobservable inputs, a description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for balance sheet items not carried at fair value but for which fair value is disclosed, entities will be required to disclose the Level within the fair value hierarchy that applies to the fair value measurement disclosed. This guidance is effective for interim and annual periods beginning after December 15, 2011. We have adopted this guidance effective January 1, 2012. The adoption of this guidance did not have an impact on the Company’s fair value measurements, financial condition, results of operations or cash flows.

ASU 2011-05 “Comprehensive Income: Presentation of Comprehensive Income”- In June 2011, the FASB issued guidance intended to eliminate the option to report other comprehensive income and its components in the statement of changes in equity. ASU 2011-05 requires that all non-owner changes in stockholders’ equity be presented in either a single continuous statement of comprehensive income or in two separate but consecutive statements. This new guidance is to be applied retrospectively for interim and annual periods beginning after December 15, 2011. The adoption of this guidance does not have an impact on the Company’s financial condition, results of operations or cash flows.

10

Reclassifications

Certain amounts in the fiscal 2012 condensed consolidated financial statements have been reclassified to conform to the fiscal 2013 financial statement presentation. Such reclassifications have had no effect on net loss for the three-month and six-month periods ended July 31, 2012.

Asset Retirement Obligations

The following table reflects the change in asset retirement obligations for the periods presented:

	For the six months ended July 31,
	2012			2011
Balance, beginning of period	$	1,623,289		$	1,403,697
Liabilities incurred		48,654			18,271
Revision of estimates		-			(53,322	)
Sale of assets		(15,223	)		-
Liabilities settled		(249,663	)		(76	)
Accretion		167,589			140,319
Balance, end of period		1,574,646			1,508,889
Less current portion of obligations		(1,448,790	)		-
Long-term asset retirement obligations	$	125,856		$	1,508,889

The $1,448,790 current liability at July 31, 2012 is for reclamation of frac ponds and abandonment of well bores in Canada.

3. Segment Reporting

In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have two reportable operating segments. Our exploration and production operating segment and our pressure pumping services operating segment are managed separately because of the nature of their products and services. The exploration and production operating segment is responsible for finding and producing oil and natural gas. The pressure pumping services operating segment is responsible for pressure pumping for both Triangle-operated wells and wells operated by third parties. RockPile is a pressure pumping services company that was formed in June 2011 and initially funded after July 31, 2011. Historically, our pressure pumping services business was presented as part of other operations as it had not yet begun operations and was not considered significant. RockPile began operations in July 2012, and as a result is now being recognized as a reportable segment.

11

Management evaluates the performance of our segments based upon income (loss) before income taxes. The following table presents selected financial information for Triangle’s operating segments.

	Exploration and Production			Pressure Pumping Services			Intercompany Eliminations			Consolidated Total
Three Months Ended July 31, 2012
REVENUES
Oil and natural gas sales	$	7,507,137		$	-		$	-		$	7,507,137
Pressure-pumping services		-			2,594,552			-			2,594,552
Intersegment revenues		-			5,523,687			(5,523,687	)		-
Other		156,104			-			-			156,104
		7,663,241			8,118,239			(5,523,687	)		10,257,793
EXPENSES
Lease operating		1,083,729			-			-			1,083,729
Depletion, depreciation and amortization		2,988,320			8,535			-			2,996,855
Accretion of asset retirement obligations		84,095			-			-			84,095
Pressure-pumping		-			6,170,355			(4,325,007	)		1,845,348
General and Administrative:
Stock-based compensation		1,433,047			-			-			1,433,047
Other general and administrative		1,797,848			2,279,056			-			4,076,904
Foreign exchange loss		262			-			-			262
Total operating expenses		7,387,301			8,457,946			(4,325,007	)		11,520,240
INCOME (LOSS) FROM OPERATIONS		275,940			(339,707	)		(1,198,680	)		(1,262,447	)
OTHER INCOME (EXPENSE)		53,452			89			-			53,541
NET INCOME (LOSS) BEFORE INCOME TAXES	$	329,392		$	(339,618	)	$	(1,198,680	)	$	(1,208,906	)
Six Months ended July 31, 2012
REVENUES
Oil and natural gas sales	$	12,679,613		$	-		$	-		$	12,679,613
Pressure-pumping services		-			2,594,552			-			2,594,552
Intersegment revenues		-			5,523,687			(5,523,687	)		-
Other		225,051			-			-			225,051
		12,904,664			8,118,239			(5,523,687	)		15,499,216
EXPENSES
Lease operating		1,928,232			-			-			1,928,232
Depletion, depreciation and amortization		5,158,945			11,273			-			5,170,218
Accretion of asset retirement obligations		167,589			-			-			167,589
Pressure-pumping		-			6,356,523			(4,325,007	)		2,031,516
General and Administrative:
Stock-based compensation		2,797,941			-			-			2,797,941
Other general and administrative		4,127,202			3,874,100			-			8,001,302
Foreign exchange loss		409			-			-			409
Total operating expenses		14,180,318			10,241,896			(4,325,007	)		20,097,207
INCOME (LOSS) FROM OPERATIONS		(1,275,654	)		(2,123,657	)		(1,198,680	)		(4,597,991	)
OTHER INCOME (EXPENSE)		56,316			8,590			-			64,906
NET INCOME (LOSS) BEFORE INCOME TAXES	$	(1,219,338	)	$	(2,115,067	)	$	(1,198,680	)	$	(4,533,085	)
As of July 31, 2012
Total assets	$	358,058,961		$	29,116,969		$	(2,504,578	)	$	384,671,352
Other property and equipment - net	$	1,560,663		$	27,039,021		$	-		$	28,599,684
Total liabilities	$	170,392,301		$	7,332,422		$	(1,305,898	)	$	176,418,825

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4. Property and Equipment

Property and equipment at July 31, 2012 and January 31, 2012, consisted of the following:

	July 31,			January 31,
	2012			2012
Oil and natural gas properties, using the full cost method:
Unproved properties and properties under development, not being amortized	$	105,031,334		$	111,716,360
Proved properties		107,054,256			33,172,419
		212,085,590			144,888,779
Less accumulated amortization		(8,129,001	)		(3,118,000	)
Net carrying value of oil and natural gas properties		203,956,589			141,770,779
Cost of other property and equipment		29,243,749			1,311,847
Deposits on equipment under construction		-			5,647,576
Less accumulated depreciation and amortization		(644,065	)		(85,122	)
Net property and equipment	$	232,556,273		$	148,645,080

During the six months ended July 31, 2012, we acquired oil and natural gas properties and participated in the drilling and/or completion of wells, for total consideration of approximately $69.9 million, which consisted of cash in the amount of $56.0 million ($10.3 million for the acquisition of undeveloped leaseholds), accrued liabilities of $12.7 million and stock consideration of $1.2 million.

On April 30, 2012, we sold a 7% interest (approximately 3,700 net undeveloped acres) in the Station Prospect for $2,712,066. The proceeds of this sale were recorded as a reduction of the full cost pool consistent with full cost accounting rules.

In the six months ended July 31, 2012, we capitalized $794,000 of internal land and geology department costs directly associated with property acquisition, exploration (including lease record maintenance) and development. The internal land and geology department costs were capitalized to unevaluated costs.

Other property and equipment is located in the U.S. and includes approximately $27 million spent to acquire pressure pumping equipment for RockPile. The equipment was placed into service in July 2012.

Ceiling-Test Impairments

The Company uses the full-cost accounting method, which requires recognition of an impairment of oil and natural gas properties when the total net carrying value of oil and natural gas properties exceed a ceiling as described on page 53 of our Annual Report on Form 10-K/A for the fiscal year ended January 31, 2012, filed with the SEC on May 18, 2012. The Company did not have such impairments for the six-month periods ended July 31, 2012 and July 31, 2011.

5. Stockholders’ Equity

Common Stock

The following transactions occurred during the six months ended July 31, 2012 with regard to shares of the Company’s common stock:

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· The Company issued 225,000 shares of common stock as additional consideration for interests in federal oil and natural gas leases (720 net acres) in McKenzie County, North Dakota.

· The Company issued 4,167 shares of common stock pursuant to the exercise of stock options.

· The Company issued 470,178 shares of common stock (net of shares surrendered for taxes) for restricted stock units that vested during the period.

· The Company issued 10,000 shares of common stock for consulting services.

· The Company issued 17,230 shares of common stock (net of shares surrendered for taxes) in connection with a termination agreement.

Stock Options

Effective January 28, 2009, the Company’s board of directors approved a Stock Option Plan (the “Rolling Plan”) whereby the number of authorized but unissued shares of common stock that may be issued upon the exercise of stock options granted under the Rolling Plan at any time could not exceed 10% of the issued and outstanding shares of common stock on a non-diluted basis at any time, and such aggregate number of shares of common stock available for issuance automatically increased or decreased as the number of issued and outstanding shares of common stock changed. Pursuant to the Rolling Plan, stock options became exercisable ratably in one-third increments on each of the first, second and third anniversaries of the date of the grant, and could be granted at an exercise price of not less than fair value of the common stock at the time of grant and for a term not to exceed ten years.

Upon approval of the 2011 Omnibus Incentive Plan (the “2011 Plan”) by the Company’s stockholders on July 22, 2011, the Rolling Plan was terminated and no additional awards may be made under the Rolling Plan. All outstanding awards under the Rolling Plan shall continue in accordance with their applicable terms and conditions.

The 2011 Plan authorized the Company to issue stock options, stock appreciation rights (“SAR”s), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards to any employee, consultant, independent contractor, director or officer of the Company and its subsidiaries. The maximum number of shares of common stock reserved for issuance under the 2011 Plan is 4,000,000 shares, subject to adjustment for certain transactions.

All stock options outstanding are those originally issued under the Rolling Plan. The following table summarizes the status of stock options outstanding under the Rolling Plan:

	Number of Shares			Weighted Average Exercise Price
Options outstanding – January 31, 2011 (125,833 exercisable)		343,334		$	1.60
Less: options forfeited		(25,000	)	$	3.00
Less: options exercised		(82,501	)	$	1.34
Options outstanding – January 31, 2012 (142,500 exercisable)		235,833		$	1.50
Less: options exercised		(4,167	)	$	3.00
Options outstanding – July 31, 2012 (138,334 exercisable)		231,666		$	1.48

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The following table presents additional information related to the stock options outstanding at July 31, 2012:

Exercise price		Remaining contractual life		Number of Shares
per share		(years)		Outstanding		Exercisable
$	3.00		1.50		30,000		30,000
$	1.25		2.33		201,666		108,334
					231,666		138,334
Weighted average exercise price per share				$	1.48	$	1.63
Weighted average remaining contractual life					2.23		2.15
Aggregate intrinsic value, July 31, 2012				$	773,281	$	876,543

As of July 31, 2012, there was approximately $20,000 of total unrecognized compensation expense related to stock options. This compensation expense is expected to be recognized over the remaining vesting period of the related stock options of approximately seven months.

For the six months ended July 31, 2012, the Company recorded stock-based compensation related to stock option grants of $39,937 as general and administrative expense.

Restricted Stock Units

During the six months ended July 31, 2012, the Company issued 521,600 restricted stock units as compensation to officers, directors and employees. The restricted stock units vest over one to four years. As of July 31, 2012, there was approximately $12.78 million of total unrecognized compensation expense related to unvested restricted stock units. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 2.34 years. When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit. The following table summarizes the status of restricted stock units outstanding:

	Number of Shares			Weighted- Average Award Date Fair Value
Restricted stock units outstanding – January 31, 2011		509,636		$	5.61
Units granted in fiscal 2012		2,645,110		$	7.06
Units forfeited in fiscal 2012		(134,000	)	$	6.81
Units that vested in fiscal 2012		(532,404	)	$	6.20
Restricted stock units outstanding – January 31, 2012		2,488,342		$	7.02
Units granted during the six months ended July 31, 2012		521,600		$	6.49
Units that vested during the six months ended July 31, 2012		(709,257	)	$	7.77
Restricted stock units outstanding – July 31, 2012		2,300,685		$	6.64

For the six months ended July 31, 2012, the Company recorded stock-based compensation related to restricted stock units of $2.78 million in general and administrative expenses.

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6. Credit Facility

On April 12, 2012, TUSA entered into a Credit Agreement (the “Credit Facility”) with Wells Fargo Bank, National Association, as administrative agent and issuing lender and with other banks and financial institutions party thereto, as co-lenders. The maximum credit available under the Credit Facility is $300 million. As of July 31, 2012, the Credit Facility had a borrowing base of $27,500,000. As of July 31, 2012, TUSA, as borrower, had no borrowings outstanding under the Credit Facility.

The borrowing base under the Credit Facility is subject to redetermination in October 2012, January 2013 and April 2013, and thereafter on a semi-annual basis in April and October of each year. In addition, TUSA has the option to request one unscheduled interim redetermination per annum. With a five-year term, all borrowings under the Credit Facility mature on April 12, 2017.

The Credit Facility is secured by (1) certain of TUSA’s assets, including (i) at least 85% of the adjusted engineered value of TUSA’s proved oil and natural gas interests evaluated in determining the borrowing base for the revolving Credit Facility and (ii) all of the personal property of TUSA and its subsidiaries, and (2) a pledge by Triangle of the equity interests it holds in TUSA. The obligations under the Credit Facility are guaranteed by each of Triangle and a domestic subsidiary of TUSA.

Borrowings under the Credit Facility bear interest, at TUSA’s option, at either (i) the Adjusted Base Rate (the highest of (A) the Administrative Agent’s prime rate, (B) the federal funds rate plus 0.5%, and (C) the Eurodollar Rate (as defined in the Credit Facility) plus 1%), plus an applicable margin that ranges between 0.75% and 1.75%, depending on TUSA’s utilization percentage of the then effective borrowing base or (ii) the Eurodollar Rate plus an applicable margin that ranges between 1.75% and 2.75%, depending on the utilization percentage of the then effective borrowing base. Additionally, the Credit Facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage.

The Credit Facility contains representations, warranties and covenants that are customary for similar credit arrangements, including, among other things, covenants relating to (i) financial reporting and notification, (ii) payment of obligations, (iii) compliance with applicable laws and (iv) notification of certain events. The Credit Facility also contains various covenants and restrictive provisions which may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, make investments or loans and create liens.

The Credit Facility contains financial covenants requiring TUSA to comply with the following: (i) TUSA must maintain a ratio of consolidated current assets (as defined in the Credit Facility) to consolidated current liabilities (as defined in the Credit Facility) of at least 1.0 to 1.0; and (ii) the ratio of TUSA’s consolidated debt to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) may not be greater than 4.0 to 1.0. As of July 31, 2012, TUSA was in compliance with all financial covenants under the Credit Facility.

7. Convertible Note

On July 31, 2012, pursuant to a Note Purchase Agreement between the Company and NGP Triangle Holdings, LLC (the “Purchaser”), the Company sold to the Purchaser a convertible promissory note with an initial principal amount of $120,000,000 (the “Convertible Note”), which is also the purchase price for the Convertible Note. Pursuant to the Note Purchase Agreement, the Company also entered into an Investment Agreement (the “Investment Agreement”) and a Registration Rights Agreement (the “Registration Rights Agreement”) with the Purchaser.

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Convertible Note

The Convertible Note is convertible into shares (the “Conversion Shares”) of the Company’s common stock, at an initial conversion price of $8.00 per share. The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, to be paid on each December 31, March 31, June 30 and September 30, and on the date of any redemption, conversion or exchange of the Convertible Note. Such interest payments will be paid-in-kind by adding to the principal balance of the Convertible Note; provided that, following the fifth anniversary of closing, the Company has the option to make such interest payments in cash.

The Convertible Note is not convertible prior to the next annual meeting of the Company’s stockholders. Following such annual meeting, per NYSE MKT LLC (“NYSE MKT”) rules, the Convertible Note may convert into no more than 19.9% of the Company’s outstanding shares of common stock as of the date of issuance of the Convertible Note, or approximately 8.8 million shares of common stock, unless the stockholders of the Company approve the full convertibility of the Convertible Note. If the Convertible Note is converted prior to the stockholders approving full convertibility of the Convertible Note, then in addition to approximately 8.8 million shares of common stock, the holder will receive cash in an amount equal to the value of the additional shares of common stock into which the Convertible Note would have converted, subject to NYSE MKT’s limitation on conversion.

The Convertible Note does not have a stated maturity. Following the fifth anniversary of the closing, if the price of the Company’ common stock exceeds $11.00 per share and certain trading volume requirements are met, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, payable, at the Company’s option, in cash or common stock. Following the eighth anniversary of the closing, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the principal plus accrued and unpaid interest, payable in cash. Further, following either the tenth anniversary of the closing or a change of control of the Company, the holders of the Convertible Note will have the right to require the Company to redeem the Convertible Note at a price equal to the principal amount plus accrued and unpaid interest, with an additional make-whole payment for scheduled interest payments remaining if such right is exercised prior to the fifth anniversary of closing.

If at any time while the Convertible Note remains outstanding the Company does not have a sufficient number of authorized, unissued and unreserved shares of its common stock to cover the full conversion of the Convertible Note, then the interest rate on the Convertible Note will increase to 11% until the Company’s stockholders approve an increase in the number of authorized shares of common stock sufficient to cover full conversion of the Convertible Note. At July 31, 2012, the Company had 23,969,087 authorized, unissued and unreserved shares of its common stock.

So long as not less than 50% of the initial aggregate principal amount of the Convertible Note is outstanding and held by the Purchaser, the Company has agreed to obtain the prior written consent of the Purchaser before submitting certain resolutions or matters to a vote of the holders of common stock for approval or to require the approval of such holders of common stock as would be required to approve such resolution or matter if all then-outstanding Convertible Note(s) held by the Purchaser had been converted into Conversion Shares immediately prior to the record date for such meeting of stockholders and the Purchaser had voted all of such Conversion Shares against such resolution or matter. The foregoing will not apply to stockholder-initiated proposals required to be submitted to the stockholders of the Company by federal law or pursuant to the bylaws of the Company or to proposals regarding the election or removal of directors of the Company, the ratification of the appointment of independent auditors, matters required to comply with terms of the Convertible Note or advisory votes required to be submitted to the stockholders of the Company by federal law.

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The Convertible Note includes customary events of default (each an “Event of Default”), including, among other things, payment defaults, covenant breaches, insolvency, certain events of bankruptcy, liquidation and material judgments. If any such Event of Default occurs, the Company must pay interest on the principal amount and any other amounts then past due from time to time outstanding under the Convertible Note at a default interest rate of 11%.

The Convertible Note contains transfer restrictions prohibiting the Purchaser from transferring the Convertible Note to any transferee other than an affiliate of the Purchaser without the prior written consent of the Company (which consent shall not be unreasonably withheld following the 5^th anniversary of the closing).

Investment Agreement

Pursuant to the Investment Agreement, the Purchaser is entitled to designate one director to the Board of Directors of the Company (the “Board”) until such time as (1) the Purchaser ceases to hold at least the lesser of 50% of the shares of common stock that would be issuable to the Purchaser upon conversion of the Convertible Note at the closing and 10% of the then-outstanding shares of common stock or (2) the Purchaser is in material breach of its standstill obligations or anti-hedging covenant as described below (each a “ Termination Event ”).

The Investment Agreement grants the Purchaser the right to purchase its pro-rata share on an as-converted basis of any future equity offerings by the Company until such time as a Termination Event occurs. Such rights are subject to customary exclusions such as securities offered in connection with employee benefits plans, business combinations, pro-rata distributions, and stockholder rights plans.

The Investment Agreement further provides that, for so long as at least 50% of the Convertible Note originally issued is outstanding and held by the Purchaser, the Company shall not take certain actions without the prior written consent of Purchaser, as follows:

· Enter into affiliate transactions, subject to certain exceptions;

· effect any amendment, modification or restatement of Company’s articles of incorporation or bylaws in any manner that could reasonably be expected to be materially adverse to the Purchaser;

· make any dividend or distribution in respect of, or redeem or repurchase, any equity securities of the Company;

· issue any equity securities that are senior to the common stock or any debt securities that are convertible into equity securities that are senior to the common stock;

· incur any indebtedness (other than pursuant to the Company’s senior credit facility or the terms of the Convertible Note) unless the Consolidated Leverage Ratio (as defined in the Investment Agreement) does not exceed 5.0 to 1.0 and no Event of Default (as defined in the Convertible Note) would result.

The Purchaser and its parent, NGP Natural Resources X, L.P., are subject to certain customary “standstill” provisions that limit their ability to acquire additional shares of common stock, solicit proxies or take certain other actions towards influencing or controlling the Company. The standstill provisions of the Investment Agreement survive until the later to occur of (1) the third anniversary of the closing and (2) such time as the Purchaser ceases to own at least 10% of the Company’s outstanding common stock (assuming full conversion of the outstanding Convertible Note).

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Registration Rights Agreement

Pursuant to the Registration Rights Agreement, the Purchaser is entitled to certain demand registration rights and unlimited piggyback registration rights under the Securities Act of 1933, as amended, for the shares of common stock into which the Convertible Note is convertible.

8. Commitments and Contingencies

At July 31, 2012, there were no known environmental or other regulatory matters related to the Company’s operations that were reasonably expected to result in a material liability other than asset retirement obligations which are reflected on the balance sheet. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on the Company’s financial position, results of operations or cash flows.

On April 16, 2012, the Company entered into an agreement to lease office space in Denver, Colorado for a term of 64 months. The annual rentals are approximately $315,000. In addition to the commitments for this new lease, the Company also has lease commitments for previous office space of approximately $300,000 per year for fiscal 2013 and fiscal 2014.

As of July 31, 2012, RockPile had various commitments for $6,846,000 in future expenditures relating to (i) leases of land, rail spur, rail cars and tractor trailer units, (ii) transloading services and track rental, and (iii) an agreement relating to the use of technology and equipment for transportation, transloading and storage of bulk commodities. The commitments by fiscal year are $1,612,000 in fiscal 2013, $2,413,000 in fiscal 2014, $1,243,000 in fiscal 2015, and $1,578,000 thereafter.

See Note 11 – Subsequent Events for discussion of a six-month commitment for a drilling rig.

9. Supplemental Disclosures of Cash Flow Information

	Six Months Ended July 31,
	2012		2011
Cash paid during the period for:
Interest expense	$	41,874	$	-
Non-cash investing activities:
Additions to oil and natural gas properties through:
Increased accrued liabilities	$	12,730,232	$	1,707,943
Issuance of common stock	$	1,203,750	$	11,780,358
Change in asset retirement obligations	$	31,837	$	-

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10. Income Taxes

The Company has net deferred tax assets as of July 31, 2012 primarily due to accumulated net operating losses. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, (i) cumulative historical pre-tax earnings, (ii) consistent and sustained pre-tax earnings, (iii) sustained or continued improvements in oil and natural gas commodity prices, and (iv) continued increases in production and proved reserves from the Williston Basin. The Company will continue to evaluate whether a valuation allowance is needed in future reporting periods. Due to the valuation allowance, no income tax expense or benefit was recorded for the six months ended July 31, 2012 and 2011.

11. Subsequent Events

On August 8, 2012 we entered into a six-month, one-rig drilling contract with Precision Drilling Company, LP, with an effective date of September 10, 2012. The contract has a term of 183 days with a contracted day rate of $22,500 per day. The minimum drilling commitment over the term of the contract is estimated to be $3.5 million.

On August 16, 2012, the Company purchased zero cost collars on the price of West Texas Intermediate crude oil at Cushing, buying puts to set a floor price and selling calls to set a ceiling price, on the following key terms:

· For the four months ending December 31, 2012, collars with an $87.00 floor and a $103.60 ceiling 500 barrels of oil per day (“bopd”)

· For the four months ending December 31, 2012, collars with an $87.00 floor and a $103.80 ceiling on 500 bopd

· For the calendar year 2013, collars with an $85.00 floor and a $104.30 ceiling on 500 bopd

· For the calendar year 2014, collars with an $80.00 floor and a $101.20 ceiling on 500 bopd

12. Significant Changes in Proved Oil and Natural Gas Reserves

Changes in proved reserves under SEC rules and guidelines

Our proved oil and natural gas reserves at July 31, 2012 materially increased from our proved oil and natural gas reserves at January 31, 2012, as summarized in the table below (in thousands of barrels of oil equivalent, “Mboe”). The proved reserves are in the Bakken or Three-Forks formations in the North Dakota counties of McKenzie, Williams or Dunn.

Proved Oil and Natural Gas Reserves (Mboe):	At January 31, 2012			At July 31, 2012			Change		% Change
Proved developed producing		572			2,643			2,071		362	%
Proved undeveloped		905			4,401			3,496		386	%
Total proved		1,477			7,044			5,567		377	%
% being oil reserves		92	%		87	%

The primary reason for the increases in proved reserves is the drilling and completion of wells in the first half of fiscal year 2013, whereby our net interest in producing wells increased from 3.4 net wells at January 31, 2012 to 7.7 net wells at July 31, 2012 and our net interest in proved undeveloped locations increased from 2.6 net future development wells at January 31, 2012 to 10.2 net future development wells at July 31, 2012.

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Our proved oil and natural gas reserves at January 31, 2012 have been derived from the reserve data in our Annual Report filed on Form 10-K/A for the fiscal year ended January 31, 2012, filed with the SEC on May 18, 2012. Our proved oil and natural gas reserves at July 31, 2012 were estimated by our in-house senior reservoir engineer, who has been a Registered Professional Engineer in Colorado since 1984 and has over 15 years’ experience as a petroleum engineer.  For disclosures on internal controls over reserve estimation, see pages 30 and 31 of our Annual Report filed on Form 10-K/A for the fiscal year ended January 31, 2012, filed with the SEC on May 18, 2012.

Changes in proved reserves under Canadian rules and guidelines

On April 16, 2012, the Company filed with the Canadian Securities Administrators the Company’s Form 51-101F1 (Statements of Reserves Data and Other Oil and Gas Information).  The filing is viewable under the Company’s profile on SEDAR at www.sedar.com.

The table below summarizes the changes in our proved oil and gas reserves under Canadian rules and guidelines for calculation of proved reserves in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). As explained more fully on page 12 of the Company’s Annual Report as Amended on Form 10-K/A for the fiscal year ended January 31, 2012 (filed on SEDAR on May 23, 2012), the Canadian rules and guidelines for calculation of the Company’s proved and probable reserves at January 31, 2012 reported in Form 51-101F1 differ from SEC rules and guidelines. Such proved reserves are before and after deducting royalties, which average approximately 20% of our proved reserves. Our total proved reserves at July 31, 2012, reflect the forecasted future changes in oil and gas prices and operating cost rate changes used for estimating proved reserves at January 31, 2012 as set forth in the aforementioned Form 51-101F1 (filed on SEDAR April 16, 2012). In contrast, under SEC rules our proved reserves in the table above are after royalties and based on oil and gas prices that are an average of historical first-of-the-month prices for the twelve months preceding the date of the proved reserves.

The proved reserve estimates at January 31, 2012 have been derived from the reserve data in our Annual Report filed on Form 10-K/A for the fiscal year ended January 31, 2012 (filed on SEDAR on May 23, 2012). Our proved reserve estimates at July 31, 2012 were prepared and evaluated by the Company’s aforementioned senior reservoir engineer.

Proved Oil and Natural Gas Reserves (Mboe):	At January 31, 2012			At July 31, 2012			Change		% Change
Gross (before royalties)
Proved developed producing		687			3,239			2,552		371	%
Proved undeveloped		1,125			5,131			4,006		356	%
Total proved		1,812			8,370			6,558		362	%
% being oil reserves		92	%		87	%
Net (after royalties)
Proved developed producing		559			2,640			2,081		372	%
Proved undeveloped		895			4,132			3,237		362	%
Total proved		1,454			6,772			5,318		366	%
% being oil reserves		92	%		87	%

Our Form 51-101F1 showed no probable reserves as at January 31, 2012.  The Company did not prepare any internal estimates of probable reserves as of July 31, 2012 under Canadian rules and guidelines.

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In computing barrels of oil equivalent (“boes”), natural gas was converted into oil using the ratio of 6 mcf to 1 barrel of oil (“bbl”).  The term boes may be misleading, particularly if used in isolation. A boe conversion ratio of 1 bbl for 6 mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion of 6:1 basis may be misleading as an indication of value.

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

Forward-Looking Statements

We or our representatives may make forward-looking statements, oral or written, including statements in this Quarterly Report, press releases and filings with the SEC, regarding estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and natural gas production, the number of wells we anticipate drilling in the future, the potential number of operated drill spacing units and well locations on our acreage, the timing of anticipated drilling, our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward-looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and natural gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors set forth among the Risk Factors noted in our Annual Report on Form 10-K/A for the fiscal year ended January 31, 2012, including, but not limited to, the Risk Factors identified in Item 1A of such report. All subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

Information Regarding Disclosure of Oil and Natural Gas Reserves. Any references in this Quarterly Report to proved oil and natural gas reserves and future net revenue of such proved reserves have been determined in accordance with the SEC guidelines and the United States Financial Accounting Standards Board (the “U.S. Rules”) and not in accordance with NI 51-101. The practice of preparing production and reserve quantities data under NI 51-101 differs from the U.S. Rules. The primary differences between the two reporting requirements include, but are not limited to, the following: (i) NI 51-101 requires disclosure of proved and probable reserves; the U.S. Rules usually require disclosure of only proved reserves; (ii) NI 51-101 requires the use of forecast prices in the estimation of reserves; the U.S. Rules require the use of twelve-month average historical prices which are held constant; (iii) NI 51-101 requires disclosure of reserves on a gross (before royalties) and net (after royalties) basis; the U.S Rules require disclosure on a net (after royalties) basis; (iv) NI 51-101 requires disclosure of production on a gross (before royalties) basis; the U.S. Rules require disclosure on a net (after royalties) basis; and (v) NI 51-101 requires that reserves and other data be reported on a more granular product type basis than required by the U.S. Rules. The reserves data and other oil and natural gas information for the Company prepared in accordance with NI 51-101 can be found for viewing by electronic means in the Company’s Form 51-101F1 – Statements of Reserves Data and Other Oil and Gas Information under the Company’s profile on SEDAR at www.sedar.com.

Overview

We are an exploration and production company currently focused on the development of unconventional shale oil and natural gas resources in the Bakken Shale and Three Forks formations in the Williston Basin of North Dakota and Montana. Having identified an area of focus in the Bakken Shale and Three Forks formations that we believe will generate attractive returns on invested capital, we are continuing to explore further opportunities in the region. Our production in fiscal year 2013 to date is from wells in North Dakota, primarily from the Bakken Shale formation and the rest from the Three Forks formation.

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We commenced drilling our first operated well in October 2011. We had four gross (1.7 net) operated wells completed by Schlumberger in May-June 2012, two gross wells (1.2 net) completed by RockPile in July 2012, and we expect to have our seventh through eleventh gross (2.3 net) operated wells completed by RockPile by the end of October 2012. By January 31, 2013, we anticipate having drilled and completed at least 16 gross (7.1 net) operated, horizontal wells in North Dakota or eastern Montana, for completion in the Bakken Shale or Three Forks formations.

In our core area of North Dakota and eastern Montana, we are directing resources toward our operated program to develop its approximately 33,400 net acres primarily in McKenzie and Williams County, North Dakota. In Roosevelt County, Montana, our “Station Prospect” is a largely contiguous position within the thermally mature area of the Williston Basin. Our approximate 50,000 net acre position in the Station Prospect is predominantly operated acreage with an average remaining lease term of nearly four years and provides us with a development area that we believe is scalable for the future.

With a focus on establishing an efficient development model, when possible the Company is utilizing pad drilling, which expedites our operated program, while controlling costs and minimizing environmental impact. We also intend to continue to use innovative completion, collection and production techniques to optimize reservoir production while also reducing costs. Additionally, with the ability to utilize the completion capacity of RockPile, we are well positioned to lower implied production cost and have greater control over drilling and completion schedules. We anticipate RockPile will continue to progress towards full-time operations in the third quarter while providing us with hydraulic pressure pumping services and pursuing opportunities with third party customers.

Recent Events

On July 31, 2012, pursuant to a Note Purchase Agreement (the “Note Purchase Agreement”) between Triangle Petroleum Corporation (the “Company”) and NGP Triangle Holdings, LLC (“NGP”), the Company sold to NGP a convertible promissory note with an initial principal amount of $120,000,000 (the “Convertible Note”), which was also the purchase price for the Convertible Note. Pursuant to the Note Purchase Agreement, the Company also entered into an Investment Agreement and a Registration Rights Agreement with the Purchaser. The Convertible Note bears interest at 5% per annum, compounded quarterly, and the accrued interest and Convertible Note are convertible into Company common stock at a stock price of $8.00 per share. For more information regarding the Convertible Note, see Note 7—Convertible Note under Item 1 in this Quarterly Report, as well as the full text of the Note Purchase Agreement, the Convertible Note, the Investment Agreement, and the Registration Rights Agreement filed as exhibits to our Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.

Properties, Plan of Operations and Capital Expenditures

Williston Basin

We own operated and non-operated leasehold positions in the Williston Basin. We are currently running a 2+ rig drilling program. Two rigs, Xtreme 7 and Precision 106, are contracted full-time and drilling approximately one well per month. A third rig, Pioneer 42, was contracted to drill five wells between April and September 2012. As of September 5, 2012, Pioneer 42 had drilled 3 wells and is currently drilling a fourth. The focus of our near-term drilling program is on our core North Dakota acreage in McKenzie and Williams Counties.

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Our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Hess Corporation, Continental Resources, Inc., Statoil (formerly Brigham Exploration Company), Newfield Production Co., EOG Resources, Inc., XTO Energy Inc. (now a part of ExxonMobil), Whiting Petroleum Corporation, Slawson Exploration, Inc., and Kodiak Oil and Gas Corporation. These companies are experienced operators in the development of the Bakken Shale and Three Forks formations.

Using industry accepted well-spacing parameters and long lateral well bores, we believe that there could be over 75 operated drill spacing units and over 450 well locations for the Bakken Shale and Three Forks formations on our acreage in the Williston Basin. Based on current industry practices, we believe we can drill six to eight 9,500+ foot lateral wells on 1,280 acre spacing units within our acreage. Consistent with leading field operators, we plan to perform multi-stage fracs, with 25 to 30 stages on each lateral well. We also plan to drill shorter lateral wells on smaller units as dictated by our leasehold position. Separately, we have approximately 120 non-operated drill spacing units with greater than 2% working interest in our core area of North Dakota and Montana.

Other Properties

We have an 87% working interest in approximately 474,625 gross acres (approximately 412,924 net acres) of Nova Scotia oil and natural gas leases in the Windsor Sub-Basin of the Maritimes Basin. The leases are scheduled to expire in 2019, but can be extended pending agreement of further development plans with the Nova Scotia regulators. Nova Scotia is currently conducting an extensive hydraulic fracturing review to determine whether and how hydraulic fracturing will be allowed in the future. The review is expected to be completed in calendar year 2014. Nova Scotia also does not currently allow the common industry practice of using salt water disposal wells. While such government restrictions remain in place, it is uneconomic to proceed in further exploration and development of these leases. We do not know if and when the restrictions might be lifted, and we do not know if Nova Scotia would grant an extension to the leases as a result of exploration delays from Nova Scotia’s existing hydraulic fracturing review. Because of these factors, we fully impaired our oil and natural gas leases in the Maritimes Basin as of January 31, 2012.

Results of Operations for the Three Months Ended July 31, 2012 Compared to the Three Months Ended July 31, 2011

For the fiscal quarter ended July 31, 2012, we recorded a net loss of $952,508 ($0.02 per share of common stock, basic and diluted) as compared to a net loss attributable to common stockholders of $6,328,025 ($0.15 per share of common stock, basic and diluted) for the fiscal quarter ended July 31, 2011.

Oil and Natural Gas Operations

For the three months ended July 31, 2012, we had total oil and natural gas revenues of $7,507,137 compared with $624,985 for the three months ended July 31, 2011. Oil and natural gas sales and production costs for each period are summarized in the following table. Oil sales volumes and revenues increased in the three months ended July 31, 2012 compared to the three months ended July 31, 2011 due to production from our interests in wells in the Bakken Shale and Three Forks formations that were placed on production after July 31, 2011.

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	Three months ended July 31,
	2012			2011
U.S. oil and natural gas operations
Oil sold (barrels)		93,730			6,787
Average oil price per barrel	$	77.01		$	88.71
Oil revenue	$	7,217,922		$	602,096
Natural gas sold (mcf)		60,226			-
Average gas price per mcf	$	4.20		$	-
Natural gas revenue	$	253,011		$	-
Natural gas liquids sold (gallons)		37,460			11,365
Average gas liquids price per gallon	$	0.97		$	2.01
Natural gas liquids revenue	$	36,204		$	22,889
Total oil and natural gas revenues	$	7,507,137		$	624,985
Less production taxes		(837,020	)		(87,897	)
Less lease operating expense		(230,049	)		(135,342	)
Less oil and natural gas amortization expense		(2,927,883	)		(136,000	)
Less accretion of asset retirement obligations		(2,904	)		(1,938	)
Income from U.S. oil and natural gas production		3,509,281			263,808
Gross profit from pressure pumping services		749,204			-
Other service revenues		156,104			-
Income from U.S. oil and natural gas operations		4,414,589			263,808
Canadian oil and natural gas operations
Lease operating expense		(16,660	)		(569,042	)
Accretion of asset retirement obligations		(81,191	)		(68,321	)
Loss from Canadian oil and natural gas operations		(97,851	)		(637,363	)
Total income (loss) from oil and natural gas operations		4,316,738			(373,555	)
U.S. and Canadian other income (expense)
Other income		53,541			98,764
Foreign exchange loss		(262	)		(10,328	)
Depreciation of furniture and equipment		(68,972	)		(42,224	)
General and administrative expenses		(5,509,951	)		(6,000,682	)
Net loss	$	(1,208,906	)	$	(6,328,025	)
Total U.S. barrels of oil equivalent (“boe”) sold		104,660			7,058
U.S. oil and natural gas revenue per boe sold	$	71.73		$	88.55
U.S. lease operating and production tax expense per boe sold	$	10.20		$	31.63
U.S. amortization expense per boe sold	$	27.98		$	19.27

Lease Operating Expenses

Lease operating and production tax expenses for U.S. operations increased to $1,067,069 for the three months ended July 31, 2012 as compared with $223,239 for the three months ended July 31, 2011. The increase in lease operating and production tax expenses is primarily related to our increased number of wells and increased production in North Dakota as discussed above in “Oil and Natural Gas Operations”.

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Oil and Natural Gas Amortization Expense

Amortization of oil and natural gas properties increased to $2,927,883 in the three months ended July 31, 2012 from $136,000 for the three months ended July 31, 2011. This increase was due primarily to increased production from wells in the Bakken Shale formation as discussed above in “Oil and Natural Gas Operations.”

Pressure Pumping Gross Profit

Our 83.33% owned subsidiary, RockPile Energy Services LLC began providing pressure pumping (aka hydraulic fracturing) services in July 2012. RockPile’s revenues for July were $8,118,239, with a gross profit of $1,947,884 for services on two wells operated by Triangle USA Petroleum Corporation, a wholly-owned subsidiary of the Company (“TUSA”). TUSA’s working interest share in the pressure pumping costs required elimination of $5,523,687of intercompany revenue and $4,325,007 of intercompany cost of sales, with the $1,198,680 of eliminated gross profit credited against TUSA’s $5,523,687 in capitalized well costs. After intercompany eliminations, the Company had $2,594,552 in pressure pumping revenues and $749,204 gross profit from pressure pumping services in the three months ended July 31, 2012. RockPile generates revenue from services performed and from the chemicals and proppants that are consumed while providing hydraulic fracturing services. RockPile typically provides the chemicals and proppants required by the customer at an agreed upon price determined prior to execution. As a result, per well revenue is dependent upon the type and volume of chemicals and proppants used in the job design and the prevailing market prices for those items at the time the services are provided.

Other Income

Other income of $53,541 for the three months ended July 31, 2012 consists primarily of drilling overhead income, interest income and North Dakota lodging facility rental income. Other income of $98,764 for the three months ended July 31, 2011 is interest income from bank accounts. Interest expense of $31,614 for the three months ended July 31, 2012 is in connection with the amortization of the $377,000 in capitalized loan costs included within other long-term assets.

General and Administrative Expenses

The following table summarizes general and administrative expenses for the three months ended July 31:

					Increase
	2012		2011		(Decrease)
Stock-based compensation	$	1,433,047	$	3,491,693	$	(2,058,646	)
Salaries, benefits and consulting fees		1,165,014		885,499		279,515
Office rent and other office costs		342,916		406,937		(64,021	)
Professional fees		234,121		1,056,543		(822,422	)
Public company costs		55,797		160,010		(104,213	)
		3,230,895		6,000,682		(2,769,787	)
RockPile general and administrative expense		2,279,056		-		2,279,056
Total general and administrative expense	$	5,509,951	$	6,000,682	$	(490,731	)

General and administrative expenses (excluding RockPile) of $3,230,895 for the three months ended July 31, 2012 decreased from that of $6,000,682 for the same period in the prior fiscal year. The decrease is primarily attributable to the decrease in stock-based compensation. In the prior year, stock-based compensation included several quarters of cost due to the requirement for the 2011 Omnibus Plan to be approved before compensation could be recognized (See Note 8 of the January 31, 2012 10-K/A). RockPile’s general and administrative expense is primarily compensation costs for its 54 employees for the three months ended July 31, 2012 as the company prepared to commence operations in July 2012.

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Results of Operations for the Six Months Ended July 31, 2012 Compared to the Six Months Ended July 31, 2011

For the six months ended July 31, 2012, we recorded a net loss of $3,980,783 ($0.09 per share of common stock, basic and diluted) as compared to a net loss attributable to common stockholders of $7,199,797 ($0.19 per share of common stock, basic and diluted) for the six months ended July 31, 2011.

Oil and Natural Gas Operations

For the six months ended July 31, 2012, we had total oil and natural gas revenues of $12,679,613 compared with $1,138,267 for the six months ended July 31, 2011. Oil and natural gas sales and production costs for each period are summarized in the following table. Oil sales volumes and revenues increased in the six months ended July 31, 2012 compared to the six months ended July 31, 2011 due to production from our interests in wells in the Bakken Shale and Three Forks formations that were placed on production after July 31, 2011.

	Six months ended July 31,
	2012			2011
U.S. oil and natural gas operations
Oil sold (barrels)		149,852			12,122
Average oil price per barrel	$	80.85		$	91.75
Oil revenue	$	12,115,500		$	1,112,148
Natural gas sold (mcf)		95,016			-
Average gas price per mcf	$	5.15		$	-
Natural gas revenue	$	489,661		$	-
Natural gas liquids sold (gallons)		70,218			12,522
Average gas liquids price per gallon	$	1.06		$	2.09
Natural gas liquids revenue	$	74,452		$	26,119
Total oil and gas revenues	$	12,679,613		$	1,138,267
Less production taxes		(1,428,677	)		(128,401	)
Less lease operating expense		(482,895	)		(159,756	)
Less oil and natural gas amortization expense		(5,019,908	)		(299,761	)
Less accretion of asset retirement obligations		(5,207	)		(3,678	)
Income from U.S. oil and natural gas operations		5,742,926			546,671
Gross profit from pressure pumping services		563,036			-
Other service revenues		225,051			-
Income from U.S. oil and natural gas operations		6,531,013			546,671
Canadian oil and natural gas operations
Lease operating expense		(16,660	)		(572,958	)
Accretion of asset retirement obligations		(162,382	)		(136,641	)
Loss from Canadian oil and natural gas operations		(179,042	)		(709,599	)
Total income (loss) from oil and natural gas operations		6,351,971			(162,928	)
U.S. and Canadian other income (expense)
Other income		64,906			194,237
Foreign exchange loss		(409	)		(2,066	)
Depreciation of furniture and equipment		(150,310	)		(42,224	)
General and administrative expenses		(10,799,243	)		(7,186,816	)
Net loss	$	(4,533,085	)	$	(7,199,797	)
Total U.S. barrels of oil equivalent (“boe”) sold		167,360			12,420
U.S. oil and natural gas revenue per boe sold	$	75.76		$	91.65
U.S. lease operating and production tax expense per boe sold	$	11.42		$	23.20
U.S. amortization expense per boe sold	$	29.99		$	24.14

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Lease Operating Expenses

Lease operating and production tax expenses for U.S. operations increased to $1,911,572 for the six months ended July 31, 2012 as compared with $288,157 for the six months ended July 31, 2011. The increase in lease operating and production tax expenses is primarily related to our increased number of wells and increased production in North Dakota as discussed above in “Results of Operations for the Six Months Ended July 31, 2012 Compared to the Six Months Ended July 31, 2011 - Oil and Natural Gas Operations.”

Oil and Natural Gas Amortization Expense

Amortization of oil and natural gas properties increased to $5,019,908 for the six months ended July 31, 2012 from $299,761 for the six months ended July 31, 2011. This increase was due primarily to increased production from wells in the Bakken Shale formation as discussed above in “Oil and Natural Gas Operations.”

Other Income

Other income of $64,906 for the six months ended July 31, 2012 consists primarily of drilling overhead income, interest income and North Dakota lodging facility rental income. Other income of $194,237 for the six months ended July 31, 2011 is interest income from bank accounts. Interest expense of $41,874 for the six months ended July 31, 2012 is in connection with the amortization of the $377,000 in capitalized loan costs included within other long-term assets.

General and Administrative Expenses

The following table summarizes general and administrative expenses for the six months ended July 31:

					Increase
	2012		2011		(Decrease)
Stock-based compensation	$	2,797,941	$	3,557,791	$	(759,850	)
Salaries, benefits and consulting fees		2,482,023		1,545,193		936,830
Office rent and other office costs		729,695		685,118		44,577
Professional fees		796,054		1,074,658		(278,604	)
Public company costs		119,430		324,056		(204,626	)
		6,925,143		7,186,816		(261,673	)
RockPile general and administrative expense		3,874,100		-		3,874,100
Total general and administrative expense	$	10,799,243	$	7,186,816	$	3,612,427

General and administrative expenses (excluding RockPile) of $6,925,143 for the six months ended July 31, 2012 decreased slightly from that of $7,186,816 for the same period in the prior fiscal year. RockPile’s general and administrative expense is primarily compensation costs for its 54 employees for the six months ended July 31, 2012 as the Company prepared to commence operations in July 2012.

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Analysis of Changes in Cash Flows

Net Cash Provided by Operating Activities

Cash flows provided by operating activities was $4,036,093 for the six months ended July 31, 2012. Cash flows used in operating activities was $5,398,747 for the six months ended July 31, 2011. The $9,434,840 increase is primarily attributable to the following: (a) $11.5 million increase in cash received from revenue, (b) $4.7 million decrease in cash used for general and administrative expense, (c) $0.6 million increase in cash received from RockPile revenues, and (d) net recovery of $1.5 million of drilling costs paid for our operated wells (which was recorded as accounts receivable from various working interest partners).

Net Cash Used in Investing Activities

For the six months ended July 31, 2012, investing activities used $74,576,134 in cash as compared to $76,566,985 used in the six months ended July 31, 2011. Cash used in investing activities is primarily for the drilling and completion of oil and natural gas properties and to a lesser extent, the acquisition of unevaluated oil and natural gas properties.

Net Cash Provided by Financing Activities

Cash flows provided by financing activities for the six months ended July 31, 2012 totaled $118,082,034. The cash in-flow was primarily a result of proceeds from the $120 million Convertible Note (see Note 7 – Convertible Note under Item 1 in this Quarterly Report).

Cash flows provided by financing activities in the six months ended July 31, 2011 of $134,853,624 were primarily a result of the sale of 18,975,000 shares of our common stock for $7.50 per share in March 2011. Share issue costs in connection with the sale of these securities were $7,569,527.

Liquidity and Capital Resources

Our primary cash requirements are for exploration, acquisition and development of oil and natural gas properties. We currently anticipate capital requirements for fiscal year 2013 to be approximately $173 million. Approximately $98 million of these funds will be allocated towards our operated drilling program. We will also allocate $25 million toward additional acreage acquisitions and $25 million towards infrastructure. We expect to be able to fund these expenditures, as well as other commitments and working capital requirements, using existing capital, our reserve-based lending facility, or through participation in joint ventures and/or asset sales. We may expand or reduce our capital expenditures depending on, among other things, the results of future wells and our available capital.

As of July 31, 2012, we had cash of $116 million consisting primarily of cash held in bank accounts with Wells Fargo, Royal Bank of Canada and JP Morgan Chase, as compared to $68.8 million at January 31, 2012. Working capital was approximately $93.4 million as of July 31, 2012, as compared to $58.8 million at January 31, 2012. Our ability to continue to acquire property, accelerate our drilling program, and grow our oil and natural gas reserves and cash flow would be impacted if we are unable to obtain sufficient additional capital.

On July 31, 2012, we announced an investment by Natural Gas Partners, an Irving, Texas, based private equity firm. NGP Triangle Holdings, LLC purchased a $120 million Convertible Note. Additionally, we have a Wells Fargo reserve-based credit facility borrowing base of $27.5 million all of which was undrawn.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our major market risk is pricing applicable to our oil and natural gas production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and natural gas production has been volatile and unpredictable.

As of July 31, 2012, our operating subsidiary had $27.5 million available for borrowing under its credit facility, none of which was drawn as of such date. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at July 31, 2012 under our credit facility of $27.5 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $270,000.

For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 6—Credit Facility under Item 1 in this Quarterly Report.

ITEM 4. CONTROLS AND PROCEDURES

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of July 31, 2012. On the basis of this review, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that the 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 the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

There have not been any changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the SEC under the Exchange Act) during the Company’s most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s 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 effect on our business, financial condition or results of operations.

Item 1A. Risk Factors.

Except as discussed below, there have been no material changes to the risk factors set forth in our Annual Report on Form 10-K/A for the year ended January 31, 2012, as filed with the SEC on May 18, 2012. The risk factors in our Annual Report on Form 10-K/A for the year ended January 31, 2012, in addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

The holder of our Convertible Note has significant influence on our major corporate decisions, including control over some matters that require stockholder approval, and could take actions that could be adverse to stockholders.

In connection with the issuance and sale in July 2012 of our convertible note with an initial principal amount of $120.0 million (the “Convertible Note”), the Company entered into an Investment Agreement by and among the Company, NGP Triangle Holdings, LLC (“NGP”) and the parent company of NGP. Pursuant to the Investment Agreement, NGP is entitled to designate one director to the Board until the occurrence of a Termination Event (as defined in the Investment Agreement). The Investment Agreement further provides that, for so long as at least 50% of the Convertible Note originally issued is outstanding and held by NGP, the Company shall not take certain actions without the prior written consent of NGP. In addition, pursuant to the Convertible Note, for so long as at least 50% of the Convertible Note originally issued is outstanding and held by NGP, the Company has agreed to (i) obtain the prior written consent of NGP before submitting certain resolutions or matters to a vote of the stockholders, or (ii) require the approval of stockholders as would be required to approve such resolution or matter if the then-outstanding Convertible Note held by NGP had been converted into shares of common stock immediately prior to the record date for such meeting of stockholders and NGP had voted all of such shares of common stock against such resolution or matter.

If the stockholders approve the full convertibility of the Convertible Note, then the Convertible Note will be convertible into shares of common stock at an initial conversion price of $8.00 per share, which, based on the initial principal amount, would allow the Convertible Note to be converted into 15,000,000 shares of common stock plus any shares issuable upon the conversion of accrued interest. Accordingly, if NGP fully converts the Convertible Note, then NGP could hold at least 25.2% of our outstanding shares of common stock based on the Company’s outstanding shares of common stock as of August 31, 2012.

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As a result of the foregoing, NGP has significant influence over us, our management, our policies and, under both the Investment Agreement and following conversion of the Convertible Note as a significant stockholder, certain matters requiring stockholder approval. The interests of NGP, including in its capacity as a creditor, may differ from the interests of the Company’s stockholders and the ability of NGP to influence certain of our major corporate decisions may harm the market price of our common stock by delaying, deferring or preventing transactions that are in the best interest of all stockholders or discouraging third-party investors.

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

The table below provides a summary of shares of our common stock surrendered to us in payment of tax liability in connection with the vesting of restricted stock units during the six months ended July 31, 2012.

					Total Number of		Maximum Number (or
					Shares Purchased		Approximate Dollar
	Total				as Part of		Value) of Shares that
	Number of		Average		Publicly		may Yet Be Purchased
	Shares		Price Paid		Announced Plans		Under the Plans or
	Purchased		Per Share		or Programs		Programs
	(1)		(2)		(3)		(3)
February 1 - February 29, 2012		110,943	$	6.79		—		—
March 1 - March 31, 2012		8,175	$	7.62		—		—
April 1 - April 30, 2012		83,925	$	6.89		—		—
May 1 – May 31, 2012		10,123	$	5.59		—		—
June 1 – June 30, 2012		12,467	$	5.46		—		—
July 1 – July 31, 2012		14,983	$	5.30		—		—
Total		240,616	$	6.64		—		—

(1)  Shares of common stock surrendered by certain employees to the Company in satisfaction of their tax liability upon the vesting of their restricted stock units, as permitted by the Company’s 2011 Omnibus Incentive Plan. The number of shares of common stock actually issued to such employees upon the vesting of their restricted stock units was net of the shares surrendered in satisfaction of their tax liability.

(2)  No commission was paid in connection with the surrender of common stock.

(3)  These sections are not applicable as the Company has no publicly announced stock repurchase plans.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures

Not Applicable.

Item 5. Other Information.

None.

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Item 6.  Exhibits

4.1	5% Convertible Promissory Note, dated July 31, 2012, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.
4.2	Investment Agreement among Triangle Petroleum Corporation, NGP Triangle Holdings, LLC and NGP Natural Resources X, L.P., dated July 31, 2012, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.
4.3	Registration Rights Agreement between Triangle Petroleum Corporation and NGP Triangle Holdings, LLC, dated July 31, 2012, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.
10.1	Second Amended and Restated Employment Agreement, dated May 18, 2012, by and between Triangle Petroleum Corporation and Dr. Peter Hill, filed as an exhibit to the Annual Report on Form 10-K/A filed with the Securities and Exchange Commission on May 18, 2012 and incorporated herein by reference.
10.2	Second Amended and Restated Employment Agreement, dated May 18, 2012, by and between Triangle Petroleum Corporation and Jonathan Samuels, filed as an exhibit to the Annual Report on Form 10-K/A filed with the Securities and Exchange Commission on May 18, 2012 and incorporated herein by reference.
10.3	Employment Agreement, dated May 18, 2012, by and between Triangle Petroleum Corporation and Joseph Feiten, filed as an exhibit to the Annual Report on Form 10-K/A filed with the Securities and Exchange Commission on May 18, 2012 and incorporated herein by reference.
10.4	Note Purchase Agreement between Triangle Petroleum Corporation and NGP Triangle Holdings, LLC dated as of July 31, 2012, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.
18.1	Preferability Letter of KPMG
31.1	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
31.2	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
32.1	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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101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

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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:  September 10, 2012	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	Chief Executive Officer (Principal Executive Officer)
Date:  September 10, 2012	By:	/s/ JOSEPH FEITEN
	Joseph Feiten
	Chief Financial Officer (Principal Financial and Accounting Officer)

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