10-Q 1 v329937_10q.htm FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

For the quarterly period ended October 31, 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)

Delaware		98-0430762
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer 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 December 4, 2012, there were 44,359,011 shares of the registrant’s common stock outstanding.

TRIANGLE PETROLEUM CORPORATION AND SUBSIDIARIES

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

PART I. FINANCIAL INFORMATION

	ITEM 1.	Financial Statements

		Condensed Consolidated Balance Sheets - October 31, 2012 and January 31, 2012	3

		Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) -Three and Nine months ended October 31, 2012 and 2011	4

		Condensed Consolidated Statements of Cash Flows - Nine months ended October 31, 2012 and 2011	5

		Condensed Consolidated Statement of Stockholders’ Equity - Nine months ended October 31, 2012	6

		Notes to Condensed Consolidated Financial Statements	7 – 23

	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	35

	ITEM 4.	Controls and Procedures	36

PART II. OTHER INFORMATION

	ITEM 1.	Legal Proceedings	37
	ITEM 1A.	Risk Factors	37
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
	ITEM 3.	Defaults Upon Senior Securities	39
	ITEM 4.	Mine Safety Disclosures	40
	ITEM 5.	Other Information	40
	ITEM 6.	Exhibits	40

	SIGNATURES		42

Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets

(unaudited)

	October 31,			January 31,
	2012			2012
ASSETS
CURRENT ASSETS
Cash	$	45,035,443		$	68,815,040
Prepaid expenses		1,081,459			161,650
Accounts receivable:
Oil and natural gas sales		6,244,907			5,422,453
Trade		26,827,223			3,929,465
Other		473,286			474,016
Derivative asset		2,230,323			-
Inventory		740,752			-
Total current assets		82,633,393			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		112,076,617			111,716,360
Proved properties		150,409,697			33,172,419
		262,486,314			144,888,779
Less: accumulated amortization		(11,429,001	)		(3,118,000	)
Net oil and natural gas properties		251,057,313			141,770,779
Other property and equipment (less accumulated depreciation of $1,911,025 and $85,122, respectively)		31,854,365			1,226,725
Equity investment		11,950,403			-
Derivative asset		3,059,943			-
Deposits on equipment under construction		-			5,647,576
Prepaid drilling costs		444,611			2,192,963
Other long-term assets		1,608,411			203,987
Total assets	$	382,608,439		$	229,844,654

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	14,117,258		$	3,428,917
Accrued liabilities:
Exploration and development		29,007,148			11,807,040
Other		4,870,214			3,189,806
Asset retirement obligations		1,448,790			1,539,871
Total current liabilities		49,443,410			19,965,634

LONG-TERM LIABILITIES
Long-term borrowings on Credit Facility		-			-
5% Convertible Note		121,500,000			-
Asset retirement obligations		403,605			83,418
Total liabilities		171,347,015			20,049,052

COMMITMENTS AND CONTINGENCIES (Note 11)
STOCKHOLDERS' EQUITY
Common stock, $0.00001 par value, 70,000,000 shares authorized; 44,329,972 and 43,515,958 shares issued and outstanding at October 31, 2012 and January 31, 2012, respectively		444			435
Additional paid-in capital		318,981,413			314,199,952
Accumulated deficit		(111,248,055	)		(108,260,138	)
Accumulated other comprehensive income		-			-
Total parent company stockholders’ equity		207,733,802			205,940,249
Noncontrolling interest in subsidiary		3,527,622			3,855,353
Total stockholders' equity		211,261,424			209,795,602
Total liabilities and stockholders’ equity	$	382,608,439		$	229,844,654

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

Triangle Petroleum Corporation

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(unaudited)

	Three Months Ended October 31,						Nine Months Ended October 31,
	2012			2011			2012			2011
REVENUES
Oil and natural gas sales	$	10,443,055		$	3,462,471		$	23,122,668		$	4,600,739
Pressure-pumping services		12,530,558			-			15,125,110			-
Other		215,791			-			440,432			-
		23,189,404			3,462,471			38,688,210			4,600,739
EXPENSES
Production taxes		1,202,312			407,039			2,630,989			535,439
Other lease operating		1,470,847			168,107			1,970,401			900,822
Depletion, depreciation and amortization		3,983,549			1,231,817			9,324,004			1,573,802
Accretion of asset retirement obligations		5,065			70,786			172,653			211,105
Pressure-pumping		8,881,112			-			10,742,392			-
General and administrative:
Stock-based compensation		1,506,635			1,998,586			4,304,576			5,556,377
Salaries and benefits		2,284,281			814,597			6,960,628			1,889,708
Other general and administrative		2,584,004			1,004,575			5,908,958			3,558,489
Foreign exchange loss		-			8,862			-			10,928
Total operating expenses		21,917,805			5,704,369			42,014,601			14,236,670

INCOME (LOSS) FROM OPERATIONS		1,271,599			(2,241,898	)		(3,326,391	)		(9,635,931	)

OTHER INCOME (EXPENSE)
Gain on derivative activities		1,401,267			-			1,401,267			-
Other income (loss)		(50,371	)		-			(41,809	)		-
Interest income		25,093			102,774			123,310			297,011
Interest expense		(1,430,151	)		-			(1,472,025	)		-
Total other income (expense)		(54,162	)		102,774			10,743			297,011

NET INCOME (LOSS) BEFORE INCOME TAXES		1,217,437			(2,139,124	)		(3,315,648	)		(9,338,920	)
Income tax provision		-			-			-			-
NET INCOME (LOSS)		1,217,437			(2,139,124	)		(3,315,648	)		(9,338,920	)
Less: (net income) loss attributable to noncontrolling interest in subsidiary		(224,571	)		28,936			327,731			28,936
Net income (loss) attributable to common stockholders	$	992,866		$	(2,110,188	)	$	(2,987,917	)	$	(9,309,984	)

Net Income (loss) per common share outstanding - basic	$	0.02		$	(0.05	)	$	(0.07	)	$	(0.23	)
Net Income (loss) per common share outstanding - diluted	$	0.02		$	(0.05	)	$	(0.07	)	$	(0.23	)

Weighted average common shares outstanding - basic		44,326,947			43,261,133			44,217,660			39,662,997
Weighted average common shares outstanding - diluted		44,465,281			43,261,133			44,217,660			39,662,997

COMPREHENSIVE INCOME (LOSS)
Net income (loss) attributable to common stockholders	$	992,866		$	(2,110,188	)	$	(2,987,917	)	$	(9,309,984	)
Other comprehensive income (loss)		-			-			-			-
Total comprehensive income (loss)	$	992,866		$	(2,110,188	)	$	(2,987,917	)	$	(9,309,984	)

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

Triangle Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Nine Months Ended October 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(3,315,648	)	$	(9,338,920	)
Adjustments to reconcile net loss to net cash used in operating activities:
Add back expenses (incomes) not using (providing) cash:
Depreciation, depletion and amortization		9,324,004			1,573,802
Stock-based compensation		4,476,203			5,556,377
Interest expense not paid in cash		1,459,260			-
Accretion of asset retirement obligations		172,653			211,105
Unrealized (income) loss on derivatives		(1,401,267	)		-
Unrealized (income) loss on equity investment		50,000			-
		10,765,205			(1,997,636	)
Changes in related current assets and liabilities:
Prepaid expenses and deposits		(1,200,066	)		2,522
Accounts receivable:
Oil and natural gas sales		(822,454	)		(4,801,372	)
Trade		(22,897,758	)		-
Other		730			-
Inventory		(740,752	)		-
Accounts payable and accrued liabilities		8,150,058			(1,433,709	)
Asset retirement expenditures		(253,463	)		-
Cash used in operating activities		(6,998,500	)		(8,230,195	)

CASH FLOWS FROM INVESTING ACTIVITIES
Oil and natural gas property expenditures		(94,525,730	)		(84,865,060	)
Sale of oil and natural gas properties		3,264,745			46,800
Purchase of other property and equipment		(26,816,549	)		(5,534,819	)
Investment in Caliber Midstream Partners, L.P.		(12,000,403	)		-
Purchase of derivative contracts		(3,889,000	)		-
Non-controlling interest in subsidiary		-			4,000,000
Cash refund of collateral account		-			105,264
Cash advanced to operators for oil and natural gas property expenditures		-			(4,287,435	)
Cash used in investing activities		(133,966,937	)		(90,535,250	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock		-			142,312,310
Common stock issuance costs		-			(7,569,527	)
Proceeds from issuance of convertible note		120,000,000			-
Debt issuance costs		(1,207,427	)		-
Proceeds from credit facility		13,700,000			-
Repayments to credit facility		(13,700,000	)		-
Cash paid to settle tax on vested restricted stock units		(1,619,233	)		-
Issuance of common stock for exercise of options		12,500			110,651
Cash provided by financing activities		117,185,840			134,853,434

NET INCREASE (DECREASE) IN CASH		(23,779,597	)		36,087,989
CASH, BEGINNING OF PERIOD		68,815,040			57,773,269
CASH, END OF PERIOD	$	45,035,443		$	93,861,258

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

Triangle Petroleum Corporation

Condensed Consolidated Statement of Stockholders' Equity

(unaudited)

For the nine months ended October 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)		557,617		6		(1,619,238	)		-			-			(1,619,232	)
Stock-based compensation		-		-		5,012,824			-			-			5,012,824
Net loss for the period		-		-		-			(2,987,917	)		(327,731	)		(3,315,648	)
Balance - October 31, 2012		44,329,972	$	444	$	318,981,413		$	(111,248,055	)	$	3,527,622		$	211,261,424

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

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) Triangle Caliber Holdings, LLC, (c) its 83.33% owned subsidiary RockPile, and (d) certain insignificant wholly-owned limited liability companies. All significant intercompany balances and transactions have been eliminated. The Company accounts for its 30% voting interest in Caliber Midstream Partners, L.P. and 50% voting interest in Caliber Midstream GP LLC under the equity method. 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 nine month periods ended October 31, 2012 are not necessarily indicative of the operating results for the entire fiscal year ending January 31, 2013.

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 October 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.

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 7 – 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 October 31, 2012, the Company had no outstanding loan balance under its Credit Facility.

Our derivative contracts are recorded on the consolidated balance sheets at fair value. The accounting treatment for settlements and the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. We did not choose to apply hedge accounting treatment to any of the contracts we entered into during the periods covered in these condensed consolidated financial statements. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. See Note 9 – Commodity Derivative Instruments for additional information regarding our derivative instruments.

Convertible Note—On July 31, 2012, the Company sold to NGP Triangle Holdings, LLC (“NGP”) a $120,000,000 promissory note (“Convertible Note”) that became convertible after November 16, 2012, where conversion would be settled entirely in Company common stock at a conversion rate of 1 share per $8.00 of note principal, with no right of the holder to receive cash in lieu of stock. Under ASC 815, the Convertible Note is not bifurcated and is accounted for as, or like, a stock-based conventional convertible debt where the Convertible Note principal is recorded as a $120,000,000 long-term liability until conversion or redemption.

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.

Prior to November 16, 2012, the Convertible Note was a non-convertible note for which the potential conversion feature was not to be treated as an embedded derivative under ASC 815.

The Convertible Note’s potential conversion feature did not require Note bifurcation under ASC 470. Neither the Note terms before nor after November 16, 2012 permitted or required the use of all or partial cash for settlement of conversion.

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 October 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.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“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 (“IFRS”) 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 FASB issued additional guidance intended to result in convergence between U.S. GAAP and 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” (“ASU 2011-05”)- 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.

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 nine-month periods ended October 31, 2012.

Asset Retirement Obligations

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

	For the nine months ended October 31,
	2012			2011
Balance, beginning of period	$	1,623,289		$	1,403,697
Liabilities incurred		186,127			31,112
Revision of estimates		147,862			164,176
Sale of assets		(24,073	)		-
Liabilities settled		(253,463	)		(76	)
Accretion		172,653			211,105
Balance, end of period		1,852,395			1,810,014
Less current portion of obligations		(1,448,790	)		(1,732,121	)
Long-term asset retirement obligations	$	403,605		$	77,893

The $1,448,790 current liability at October 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. 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 October 31, 2012
Revenues
Oil and natural gas sales	$	10,443,055		$	-	$	-		$	10,443,055
Pressure-pumping services		-			12,530,558		-			12,530,558
Intersegment revenues		-			11,335,462		(11,335,462	)		-
Other		215,791			-		-			215,791
		10,658,846			23,866,020		(11,335,462	)		23,189,404
Expenses
Lease operating		2,673,159			-		-			2,673,159
Depletion, depreciation and amortization		3,355,408			1,202,645		(574,504	)		3,983,549
Accretion of asset retirement		5,065			-		-			5,065
Pressure-pumping		-			16,276,024		(7,394,912	)		8,881,112
General and Administrative:
Stock-based compensation		1,506,635			-		-			1,506,635
Other general and administrative		3,183,104			1,685,181		-			4,868,285
Total operating expenses		10,723,371			19,163,850		(7,969,416	)		21,917,805

Income (loss) from operations		(64,525	)		4,702,170		(3,366,046	)		1,271,599
Other income (expense)		(54,251	)		89		-			(54,162	)
Net income (loss) before income taxes	$	(118,776	)	$	4,702,259	$	(3,366,046	)	$	1,217,437

Nine Months ended October 31, 2012
Revenues
Oil and natural gas sales	$	23,122,668		$	-	$	-		$	23,122,668
Pressure-pumping services		-			15,125,110		-			15,125,110
Intersegment revenues		-			16,859,149		(16,859,149	)		-
Other		440,432			-		-			440,432
		23,563,100			31,984,259		(16,859,149	)		38,688,210
Expenses
Lease operating		4,601,390			-		-			4,601,390
Depletion, depreciation and amortization		8,525,627			1,621,860		(823,483	)		9,324,004
Accretion of asset retirement		172,653			-		-			172,653
Pressure-pumping		-			22,213,332		(11,470,940	)		10,742,392
General and Administrative:
Stock-based compensation		4,304,576			-		-			4,304,576
Other general and administrative		7,310,304			5,559,282		-			12,869,586
Total operating expenses		24,914,550			29,394,474		(12,294,423	)		42,014,601

Income (loss) from operations		(1,351,450	)		2,589,785		(4,564,726	)		(3,326,391	)
Other income (expense)		2,153			8,590		-			10,743
Net income (loss) before income taxes	$	(1,349,297	)	$	2,598,375	$	(4,564,726	)	$	(3,315,648	)

As of October 31, 2012
Total Assets	$	352,227,478		$	35,566,014	$	(5,185,053	)	$	382,608,439
Other property and equipment - net	$	2,339,626		$	29,514,739	$	-		$	31,854,365
Total Liabilities	$	160,891,175		$	9,835,512	$	620,328		$	171,347,015

4. Property and Equipment

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

	October 31,			January 31,
	2012			2012
Oil and gas properties, full cost method:
Unproved properties and properties under development, not being amortized	$	112,076,617		$	111,716,360
Proved properties		150,409,697			33,172,419
		262,486,314			144,888,779
Less accumulated amortization		(11,429,001	)		(3,118,000	)
Net carrying value of oil and gas properties		251,057,313			141,770,779
Cost of other property and equipment		33,765,390			1,311,847
Deposits on equipment under construction		-			5,647,576
Less accumulated depreciation and amortization		(1,911,025	)		(85,122	)
Net property and equipment	$	282,911,678		$	148,645,080

During the nine months ended October 31, 2012, we acquired oil and natural gas properties and participated in the drilling and/or completion of wells, for total consideration of approximately $120.7 million, which consisted of cash in the amount of $94.5 million ($16.3 million for the acquisition of undeveloped leaseholds), accrued liabilities of $24.3 million and stock consideration of $1.9 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 nine months ended October 31, 2012, we capitalized $1.5 million 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 $31 million spent to acquire pressure pumping equipment and facilities 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 nine-month periods ended October 31, 2012 and October 31, 2011.

5. Investment in Unconsolidated Affiliate

On October 1, 2012, Triangle Caliber Holdings, LLC (“Triangle Caliber Holdings”), a wholly owned subsidiary of Triangle, entered into a joint venture with FREIF Caliber Holdings LLC (“FREIF Caliber Holdings”), a wholly owned subsidiary of First Reserve Energy Infrastructure Fund, L.P. The newly formed joint venture entity, Caliber Midstream Partners, L.P. (“Caliber”), plans to provide crude oil, natural gas and water transportation services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana.

In connection with the joint venture, Triangle Caliber Holdings entered into a Contribution Agreement, dated October 1, 2012 (the “Contribution Agreement”), with FREIF Caliber Holdings, Caliber, and Caliber Midstream GP LLC (“Caliber GP” and together with Caliber, the “Caliber Joint Venture Entities”). Pursuant to the terms of the Contribution Agreement, Triangle Caliber Holdings agreed to transfer certain assets, consisting primarily of rights-of-way located in McKenzie County, North Dakota, as well as cash consideration with an aggregate value of $30 million to the Caliber Joint Venture Entities in exchange for (A) a fifty percent (50%) membership interest in Caliber GP, (B) 3,000,000 Class A Units representing a thirty percent (30%) limited partner interest in Caliber, and (C) 4,000,000 Class A Trigger Units. Also pursuant to the terms of the Contribution Agreement, FREIF Caliber Holdings agreed to contribute $70 million to the Caliber Joint Venture Entities in exchange for (A) a fifty percent (50%) membership interest in Caliber GP, and (B) 7,000,000 Class A Units representing a seventy percent (70%) limited partner interest in Caliber.

Upon the achievement of certain operational thresholds, the Class A Trigger Units held by Triangle Caliber Holdings will convert into Class A Units, resulting in Triangle Caliber Holdings and FREIF Caliber Holdings each owning a 50% limited partner interest in Caliber. A portion of the above referenced cash contribution amounts to Caliber by each of Triangle Caliber Holdings and FREIF Caliber Holdings were funded concurrently with the execution of the Contribution Agreement, with the balance of the contributions to be funded in two equal contributions in the fourth quarter of fiscal year 2013 and the first quarter of fiscal year 2014, respectively.

Triangle also received (A) 4,000,000 warrants with an exercise price of $14.69, the warrants have a 12-year life, contain a cashless exercise feature and standard provisions whereby the strike price is reduced by the amount of any per unit Class A distributions, subject to a $5.00 floor, (B) 2,400,000 warrants with a strike price of $24.00 (and feature the same provisions of the $14.69 warrants), and (C) 1,600,000 Trigger warrants which become warrants with a $14.69 strike price as described above, subject to the certain business performance metrics associated with the Class A Trigger units.

While the Contribution Agreement sets forth the minimum initial capital contributions to the joint venture by Triangle Caliber Holdings and FREIF Caliber Holdings, the limited partnership agreement governing the joint venture permits the contribution of additional capital in return for additional Class A units in the joint venture.

We use the equity method of accounting for our investment in Caliber, with earnings or losses reported in “other income (expense)” on the condensed consolidated statement of operations.

6. Stockholders’ Equity

Common Stock

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

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 557,617 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 an employment 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 granted under the Rolling Plan. All outstanding awards under the Rolling Plan shall continue in accordance with their applicable terms and conditions.

The 2011 Plan, as amended, authorizes 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 was 4,000,000 shares at October 31, 2012 and was increased to 5,900,000 shares subsequent to October 31(See Note 14 – Subsequent Events), 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 - October 31, 2012 (138,334 exercisable)		231,666		$	1.48

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

		Remaining
Exercise price		contractual life		Number of shares
per share		(years)		Outstanding		Exercisable
$	3.00		1.24		30,000		30,000
$	1.25		2.08		201,666		108,334
					231,666		138,334

Weighted average exercise price per share	$	1.48	$	1.63

Weighted average remaining contractual life		1.97		2.15

As of October 31, 2012, there is no remaining unrecognized compensation expense related to stock options. All remaining unvested options vest on November 30, 2012. The aggregate intrinsic value of the options as of October 31, 2012 and 2011 was $1.1 million and $1.0 million, respectively.

For the nine months ended October 31, 2012, the Company recorded stock-based compensation related to stock option grants of $59,906 as general and administrative expense.

Restricted Stock Units

During the nine months ended October 31, 2012, the Company issued 848,600 restricted stock units as compensation to officers, directors and employees. The restricted stock units vest over one to four years. As of October 31, 2012, there was approximately $13.1 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 2.2 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 nine months ended October 31, 2012		848,600		$	6.34
Units forfeited during the nine months ended October 31, 2012		(3,600	)	$	7.62
Units that vested during the nine months ended October 31, 2012		(738,257	)	$	7.57
Restricted stock units outstanding - October 31, 2012		2,595,085		$	6.62

For the nine months ended October 31, 2012, the Company recorded stock-based compensation related to restricted stock units of $4.3 million in general and administrative expenses. An additional $0.7 million of stock-based compensation was capitalized to oil and natural gas properties.

7. 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 October 31, 2012, the Credit Facility had a borrowing base of $52,500,000. As of October 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 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 October 31, 2012, TUSA was in compliance with all financial covenants under the Credit Facility.

8. Convertible Note

On July 31, 2012, the Company sold to NGP the $120,000,000 Convertible Note that became convertible after November 16, 2012 into Company common stock at a conversion rate of 1 share per $8.00 of note principal (see Note 14 – Subsequent Events).

9. Commodity Derivative Instruments

Through TUSA, the Company has entered into commodity derivative instruments, as described below. The Company has utilized single-day puts and costless collars to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the settlement price is above the ceiling price and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts are currently with one counterparty. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the same underlier with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the derivative activities line on the consolidated statement of operations. The Company's valuation estimate takes into consideration the counterparties' credit worthiness, the Company's credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant's view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

The Company's commodity derivative contracts as of October 31, 2012 are summarized below:

Contract Type	Counterparty	Basis (1)	Quantity	Strike Price ($/Bbl)	Term or End Date
Collar	Wells Fargo Bank, N.A.	NYMEX	500 bopd	$87.00 / $103.60	November 1, 2012 - December 31, 2012
Collar	Wells Fargo Bank, N.A.	NYMEX	500 bopd	$87.00 / $103.80	November 1, 2012 - December 31, 2012
Collar	Wells Fargo Bank, N.A.	NYMEX	500 bopd	$85.00 / $104.30	January 1, 2013 - December 31, 2013
Collar	Wells Fargo Bank, N.A.	NYMEX	500 bopd	$80.00 / $101.20	January 1, 2014 - December 31, 2014
Put	Wells Fargo Bank, N.A.	NYMEX	200,000 bbl	$75.00	June 17, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	100,000 bbl	$75.00	June 17, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	100,000 bbl	$75.00	June 17, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	300,000 bbl	$75.00	December 16, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	100,000 bbl	$75.00	December 16, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	100,000 bbl	$75.00	December 16, 2013

(1) NYMEX refers to quoted prices on the New York Mercantile Exchange

The following table details the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category:

Underlying Commodity	Location on Balance Sheet	As of October 31, 2012		As of January 31, 2012
Crude oil derivative contract	Current assets	$	2,230,323	$	-

Crude oil derivative contract	Long-term assets	$	3,059,943	$	-

The amount of income recognized related to the Company's derivative financial instruments was as follows:

	Three Months Ended October 31,				Nine Months Ended October 31,
	2012		2011		2012		2011
Unrealized gain (loss) on derivative contracts	$	1,401,267	$	-	$	1,401,267	$	-
Realized gain (loss) on derivative contracts		-		-		-		-
	$	1,401,267	$	-	$	1,401,267	$	-

Unrealized gains and losses resulting from derivatives are recorded at fair value on the condensed consolidated balance sheet and changes in fair value are recognized on the condensed consolidated statement of operations. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the derivative activities line on the condensed consolidated statements of operations.

10. Fair Value Measurements

ASC Topic 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company's assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

• Level 1: Quoted prices are available in active markets for identical assets or liabilities;

• Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;

• Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis in periods after initial recognition.

The following table presents the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of October 31, 2012 by level within the fair value hierarchy:

	Level 1		Level 2		Level 3		Total
Assets:
Derivative assets	$	-	$	5,290,266	$	-	$	5,290,266

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company's own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At October 31, 2012, derivative instruments utilized by the Company consist of both costless collars and single-day puts. The crude oil derivative markets are highly active. Although the Company's derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

The Convertible Note (carried at $121,500,000 at October 31, 2012) has an estimated fair value at October 31, 2012 of $130,400,000, based on discounted cash flow analysis and option pricing (Level 3). The excess of fair value over carrying value is largely due to an increase in option value for Triangle common stock's closing price being $6.39/share at October 31, 2012 compared with $5.59/share when the Convertible Note was issued on July 31, 2012.

11. Commitments and Contingencies

At October 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 October 1, 2012, TUSA entered into two midstream services agreements with Caliber North Dakota LLC, one for crude oil gathering, stabilization, treating and redelivery and one for gas (i) compression, gathering, dehydration, processing and redelivery; (ii) produced water transportation and disposal services; and (iii) fresh water transportation for TUSA’s oil and gas drilling and production operations. Under the agreements, TUSA committed to deliver minimum monthly volumes of oil, gas, and produced water to Caliber and to receive minimum monthly volumes of fresh water from Caliber for a primary term of 15 years beginning on the in-service date of the Caliber facilities (the date on which the Caliber central facility has been substantially completed and has commenced commercial operation, estimated to occur between July 31, 2013 and September 1, 2013). The total volume commitment over the 15 year term consists of (i) 32,932,923 bbls of oil with a total value of $36.1 million, (ii) 37,103,897 mcf of natural gas with a total value of $132.7 million, (iii) 23,201,030 bbls of produced water with a total value of $127.0 million, and (iv) 9,494,378 bbls of fresh water with a total value of $41.3 million.

On October 1, 2012, Triangle entered into a Services Agreement with Caliber GP and Caliber to provide administrative services to the Caliber necessary to operate, manage, maintain and report the operating results of the Caliber’s gathering pipelines, transportation pipelines, related equipment and other assets of Caliber.

The Company also entered into an agreement with an outside party for fresh water supply beginning in November 2012. The Company will pay $60,760 per month through April 2013 and $173,508 per month from May 2013 through October 2014.

As of October 31, 2012, RockPile had various commitments for $6,565,000 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 $771,000 in fiscal 2013, $2,413,000 in fiscal 2014, $1,803,000 in fiscal 2015 and $1,578,000 thereafter.

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.

As of October 31, 2012 the Company was subject to commitments on a drilling rig contract. The contract expires in September 2013. In the event of early termination of the contract, the Company would be obligated to pay an aggregate amount of approximately $6.7 million as of October 31, 2012 as required under the terms of the contract.

12. Supplemental Disclosures of Cash Flow Information

	Nine Months Ended October 31,
	2012		2011
Cash paid during the period for:
Interest expense (including capitalized amounts)	$	12,765	$	-

Non-cash investing activities:
Additions to oil and natural gas properties through:
Increased accrued liabilities	$	24,300,550	$	9,839,143
Issuance of common stock	$	1,911,999	$	11,780,358
Change in asset retirement obligations	$	309,916	$	-

Non-cash financing activities:
Interest paid in-kind (including capitalized amounts)	$	1,500,000	$	-

13. Income Taxes

The Company has net deferred tax assets as of October 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 nine months ended October 31, 2012 and 2011.

14. Subsequent Events

The Company held the 2012 Annual Meeting of Stockholders on November 16, 2012, at which the Company’s stockholders approved the reincorporation of the Company from the State of Nevada to the State of Delaware pursuant to a merger of the Company with and into a newly formed Delaware corporation wholly-owned by the Company. The reincorporation was effective at 11:59 p.m. EST on November 30, 2012, and the registrant is now a Delaware corporation. Additionally, the Company’s stockholders approved an increase in the total number of shares of authorized common stock to 140,000,000, as well as an amendment to the 2011 Omnibus Incentive Plan to increase the number of shares of common stock reserved for issuance under the plan from the maximum of 4,000,000 shares to an aggregate 5,900,000 shares.

At the 2012 Annual Meeting of the Stockholders , the Company’s stockholders also approved the issuance of shares that would be needed for full conversion of the Convertible Note and full conversion of additions to the principal balance of the note for interest paid-in-kind (see Note 8 – Convertible Note). The note conversion is not permitted to be settled in cash.

15. 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 October 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 October 31, 2012			Change		% Change
Proved producing		572			3,732			3,160		552	%
Proved non-producing		-			292			292		n/a
Proved undeveloped		905			4,254			3,349		370	%
Total proved		1,477			8,278			6,801		460	%
% being oil reserves		92	%		86	%

The primary reason for the increases in proved reserves is the drilling and completion of wells in the first nine months of fiscal year 2013, whereby our net interest in producing wells increased from 3.4 net wells at January 31, 2012 to 9.65 net wells at October 31, 2012, and our net interest in proved undeveloped locations increased from 2.6 net future development wells at January 31, 2012 to 8.78 net future development wells at October 31, 2012.

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 October 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 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. Proved reserves under Canadian rules and guidelines are presented in two ways – gross (i.e., before deducting royalties) and net (i.e., after deducting royalties). Such proved reserves at October 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 October 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 October 31, 2012			Change		% Change
Gross (before royalties)
Proved producing		687			4,726			4,039		588	%
Proved non-producing		-			372			372		n/a
Proved undeveloped		1,125			6,013			4,888		434	%
Total proved		1,812			11,111			9,299		513	%
% being oil reserves		92	%		85	%

Net (after royalties)
Proved producing		559			3,808			3,249		581	%
Proved non-producing		-			295			295		n/a
Proved undeveloped		895			4,773			3,878		433	%
Total proved		1,454			8,876			7,422		510	%
% being oil reserves		92	%		85	%

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

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.

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, including but not limited to, those set forth among the Risk Factors noted 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, and in this Quarterly Report under the heading “Item 1A. Risk Factors”. 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. Except for certain disclosures in Note 15 to the accompanying company condensed consolidated financial statements, 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 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.

We commenced drilling our first operated well in October 2011. We had four gross (1.7 net) operated wells completed (with pressure pumping by Schlumberger) in May-June 2012 and six additional gross (3.3 net) operated wells completed (with pressure pumping by RockPile) by October 31, 2012. We expect to have at least five additional gross (2.3 net) operated wells completed (with pressure pumping by RockPile) by the end of January 2013. By January 31, 2013, we anticipate having spud 21 gross operated wells and having completed at least 15 gross (8.3 net) operated, horizontal wells in North Dakota or eastern Montana, for completion in the Middle Bakken 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 35,400 net acres primarily in McKenzie and Williams Counties, North Dakota. In Roosevelt and Sheridan Counties, Montana, our “Station Prospect” is a largely contiguous position within the thermally mature area of the Williston Basin. Our approximate 50,600 net acre position in the Station Prospect is predominantly operated acreage 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 have greater control over drilling and completion schedules and costs.

Recent Events

On October 1, 2012, Triangle Caliber Holdings, a wholly owned subsidiary of the Company, entered into a joint venture with FREIF Caliber Holdings, a wholly owned subsidiary of First Reserve Energy Infrastructure Fund, L.P. Caliber, the newly formed joint venture entity, plans to provide crude oil, natural gas and water transportation services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana. In connection with the joint venture, Triangle’s subsidiary agreed to transfer certain assets, consisting primarily of rights-of-way located in McKenzie County, North Dakota, as well as cash consideration with an aggregate value of $30.0 million, to the joint venture in exchange for a thirty percent limited partner interest in the joint venture entity and a fifty percent interest in the general partner that manages the joint venture. Upon the achievement of certain operational thresholds, trigger units held by Triangle would convert into limited partner interests to cause Triangle to own a fifty percent limited partner interest in the joint venture. For more information regarding the joint venture, see Note 5—Investment in Unconsolidated Affiliate under Item 1 in this Quarterly Report, as well as the description of the joint venture reported on our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 1, 2012 and incorporated herein by reference.

The Company held its 2012 Annual Meeting of Stockholders on November 16, 2012, at which the Company’s stockholders approved the reincorporation of the Company from the State of Nevada to the State of Delaware pursuant to a merger of the Company with and into a newly formed Delaware corporation wholly owned by the Company. The reincorporation was effective at 11:59 p.m. EST on November 30, 2012, and the Company is now a Delaware corporation. Additionally, the Company’s stockholders approved an increase in the total number of shares of authorized common stock from 70,000,000 shares to 140,000,000 shares. The Company’s Delaware Certificate of Incorporation, which authorizes the issuance of up to 140,000,000 shares of common stock, and Bylaws are filed as Exhibits 3.1 and 3.2, respectively, to the Current Report on Form 8-K filed with the SEC on October 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 each drilling approximately one well per month. A third rig, Pioneer 42, was contracted to drill five wells between April and November 2012. As of November 9, 2012, Pioneer 42 had drilled five wells and was released from Triangle’s drilling program. The focus of our near-term drilling program is on our core North Dakota acreage in McKenzie and Williams Counties.

Our non-operated leasehold position operations 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 position. Consistent with leading field operators, we plan to perform multi-stage fracs, with 25 to 31 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 has a moratorium on hydraulic fracturing and is currently conducting an extensive 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 October 31, 2012 Compared to the Three Months Ended October 31, 2011

For the fiscal quarter ended October 31, 2012, we recorded net income attributable to common stockholders of $992,866 ($0.02 per share of common stock, basic and diluted) as compared to a net loss attributable to common stockholders of $2,110,188 ($0.05 per share of common stock, basic and diluted) for the fiscal quarter ended October 31, 2011.

Oil and Natural Gas Operations

For the three months ended October 31, 2012, we had total oil and natural gas revenues of $10,443,055 compared with $3,462,471 for the three months ended October 31, 2011. Oil and natural gas sales and production costs for each period are summarized in the following table. Oil sales volumes and revenues in the three months ended October 31, 2012 increased by approximately 200% compared to the three months ended October 31, 2011. The increases were substantially due to our operated wells placed on production in the six months ended October 31, 2012.

	Three months ended October 31,
	2012			2011
U.S. oil and natural gas operations
Oil sold (barrels)		118,287			39,636
Average oil price per barrel	$	86.25		$	85.35
Oil revenue	$	10,202,076		$	3,382,804
Natural gas sold (mcf)		47,277			10,591
Average gas price per mcf	$	4.06		$	6.36
Natural gas revenue	$	191,950		$	67,331
Natural gas liquids sold (gallons)		67,896			7,832
Average gas liquids price per gallon	$	0.72		$	1.58
Natural gas liquids revenue	$	49,029		$	12,336
Total oil and natural gas revenues	$	10,443,055		$	3,462,471
Less production taxes		(1,202,312	)		(407,039	)
Less lease operating expense (excluding production taxes)		(1,437,817	)		(116,848	)
Less oil and natural gas amortization expense		(3,300,000	)		(1,222,000	)
Less accretion of asset retirement obligations		(5,065	)		(2,774	)
Income from U.S. oil and natural gas production		4,497,861			1,713,810
Gross profit from pressure pumping services		3,048,504			-
Other service revenues		215,791			-
Income from U.S. operations		7,762,156			1,713,810

Canadian oil and natural gas operations
Lease operating expense		(33,030	)		(51,259	)
Accretion of asset retirement obligations		-			(68,012	)
Loss from Canadian oil and natural gas operations		(33,030	)		(119,271	)
Income from operations		7,729,126			1,594,539
U.S. and Canadian other income (expense)
Gain on derivative activities		1,401,267			-
Other income (expense)		(25,278	)		102,774
Interest expense		(1,430,151	)		-
Foreign exchange gain (loss)		-			(8,862	)
Less depreciation of furniture and equipment		(82,607	)		(9,817	)
Less general and administrative expenses		(6,374,920	)		(3,817,758	)
Net income (loss)	$	1,217,437		$	(2,139,124	)
Total U.S. barrels of oil equivalent (“boe”) sold		127,783			41,588
U.S. oil and natural gas revenue per boe sold	$	81.72		$	83.26
U.S. production tax per boe sold	$	9.41		$	9.79
U.S. other lease operating expense per boe sold	$	11.25		$	2.81
U.S. amortization expense per boe sold	$	25.83		$	29.38

U.S. Production Taxes

Due primarily to the 200% increase in oil revenues for the quarterly period ended October 31, 2012 compared with the quarterly period ended October 31, 2011, our U.S. production taxes increased 195% to $1,202,312 from $407,039 for the same respective quarterly periods. With rare exception, North Dakota production tax rates for the past two years were 11.5% of oil revenue and approximately 11 cents per mcf of natural gas.

U.S. Other Lease Operating Expenses

Other lease operating expenses (“OLOE”) for U.S. operations increased by $1,320,969 (to $1,437,817 for the three months ended October 31, 2012 as compared with $116,848 for the three months ended October 31, 2011). That is a 1,130% increase attributable to (i) a 200% increase in production and (ii) an increase in OLOE /boe to $11.25/boe from $2.81/boe. That cost-per-boe increase is primarily the result of a $4.45 per BOE increase in non-operated lease operating expense and the addition of lease operating expenses for operated properties. For the three months ended October 31, 2012, lease operating expense for operated properties was $14.52 per BOE. Included in the operated wells’ lease operating expense rate above is $6.32/boe in temporary costs, primarily for workover expense and equipment rental on one operated well and higher formation water disposal rates in early months of new well production.

Oil and Natural Gas Amortization Expense

Amortization of oil and natural gas properties increased to $3,300,000 in the three months ended October 31, 2012 from $1,222,000 for the three months ended October 31, 2011. This increase was due primarily to the 207% increase in boe sold (for the fiscal quarter ended October 31, 2012, compared to the fiscal quarter ended October 31, 2011). The amortization expense per boe sold declined 12%, for the same respective quarterly periods, to partially offset the increased amortization expense attributable to increased boe sales.

Pressure Pumping

RockPile, our 83.33% owned subsidiary, began providing pressure pumping (aka hydraulic fracturing) services in July 2012. RockPile currently operates one modern, 15,000 pounds per square inch pressure-rated hydraulic fracturing fleet with eight pumps and an aggregate 18,000 horsepower.

RockPile’s financial results are primarily a function of the utilization of its equipment, the drilling and stimulation activities of its customers, the prices it charges for its services, its service performance and the cost of products, materials and labor. 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 proppant used in the job design and the prevailing market prices for those items at the time the services are provided.

During the third quarter, RockPile completed 183 stages on six wells operated by Triangle and one well operated by a third-party customer resulting in total revenue of $23,866,020 and gross profit of $6,414,550. Because we consolidate RockPile’s results, we are required to eliminate intercompany revenue of $11,335,462 and intercompany cost of sales of $7,969,416 related to our working interest in the wells on which services were performed. The $3,366,046 of eliminated gross profit was credited against our capitalized well costs. After intercompany eliminations, pressure pumping revenue for the third quarter was $12,530,558 with gross profit of $3,048,504.

Other

Other services revenue of $215,791 for the three months ended October 31, 2012 consists primarily of drilling overhead income, interest income and North Dakota lodging facility rental income. Gain on derivative activities of $1,401,267 is the unrealized gain on our costless collars and single-day puts. Interest expense of $1,430,151 for the three months ended October 31, 2012 is primarily related to our convertible note with NGP. A small part of the interest expense is the amortization of the capitalized loan costs included within long-term assets.

General and Administrative Expenses

The following table summarizes changes in general and administrative expenses for the quarterly period ended October 31, 2012 from the quarterly period ended October 31, 2011:

	October, 31 2012		October 31, 2011		Increase (Decrease)
Stock-based compensation	$	1,506,635	$	1,998,586	$	(491,951	)
Salaries, benefits and consulting fees		1,419,816		870,976		548,840
Office rent and other office costs		531,414		329,217		202,197
Professional fees		1,077,965		281,656		796,309
Public company costs		153,909		166,670		(12,761	)
		4,689,739		3,647,105		1,042,634
RockPile general and administrative expense		1,685,181		170,653		1,514,528
Total general and administrative expense	$	6,374,920	$	3,817,758	$	2,557,162

General and administrative expenses (excluding RockPile) of $4,689,739 for the three months ended October 31, 2012 increased from $3,647,105 for the same period in the prior fiscal year. The increase is primarily attributable to the increased number of employees and increased legal fees. The increased legal fees include approximately $535,000 attributable to the organization of the newly formed Caliber Midstream entities (see Note 5 – Investment in Unconsolidated Affiliate). The substantial increase in RockPile’s general and administrative expense is due to RockPile being newly formed a year ago and commencing operations in July 2012.

Results of Operations for the Nine Months Ended October 31, 2012 Compared to the Nine Months Ended October 31, 2011

For the nine months ended October 31, 2012, we recorded a net loss of $2,987,917 ($0.07 per share of common stock, basic and diluted) as compared to a net loss attributable to common stockholders of $9,309,984 ($0.23 per share of common stock, basic and diluted) for the nine months ended October 31, 2011.

Oil and Natural Gas Operations

For the nine months ended October 31, 2012, we had total oil and natural gas revenues of $23,122,668 compared with $4,600,739 for the nine months ended October 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 nine months ended October 31, 2012 compared to the nine months ended October 31, 2011 due to production from our interests in wells in the Bakken Shale and Three Forks formations that were placed on production after October 31, 2011.

	Nine months ended October 31,
	2012			2011
U.S. oil and natural gas operations
Oil sold (barrels)		268,139			51,758
Average oil price per barrel	$	83.23		$	86.85
Oil revenue	$	22,317,576		$	4,494,953
Natural gas sold (mcf)		142,293			10,591
Average gas price per mcf	$	4.79		$	6.36
Natural gas revenue	$	681,612		$	67,331
Natural gas liquids sold (gallons)		138,114			20,354
Average gas liquids price per gallon	$	0.89		$	1.89
Natural gas liquids revenue	$	123,480		$	38,455
Total oil and gas revenues	$	23,122,668		$	4,600,739
Less production taxes		(2,630,989	)		(535,439	)
Less lease operating expense (excluding production taxes)		(1,920,711	)		(276,605	)
Less oil and natural gas amortization expense		(8,311,001	)		(1,521,761	)
Less accretion of asset retirement obligations		(10,271	)		(6,451	)
Income from U.S. oil and natural gas operations		10,249,696			2,260,483
Gross profit from pressure pumping services		3,611,540			-
Other service revenues		440,432			-
Income from U.S. operations		14,301,668			2,260,483

Canadian oil and natural gas operations
Lease operating expense		(49,690	)		(624,217	)
Accretion of asset retirement obligations		(162,382	)		(204,654	)
Loss from Canadian oil and natural gas operations		(212,072	)		(828,871	)
Income from operations		14,089,596			1,431,612
U.S. and Canadian other income (expense)
Gain on derivative activities		1,401,267			-
Other income		81,501			297,011
Interest expense		(1,472,025	)		-
Foreign exchange gain (loss)		-			(10,928	)
Less depreciation of furniture and equipment		(241,825	)		(52,041	)
Less general and administrative expenses		(17,174,162	)		(11,004,574	)
Net loss	$	(3,315,648	)	$	(9,338,920	)
Total U.S. barrels of oil equivalent (“boe”) sold		295,143			54,008
U.S. oil and natural gas revenue per boe sold	$	78.34		$	85.19
U.S. production tax per boe sold	$	8.91		$	9.91
U.S. other lease operating expense per boe sold	$	6.51		$	5.12
U.S. amortization expense per boe sold	$	28.16		$	28.18

U.S. Production Taxes

Due primarily to the 403% increase in oil revenues for the nine months ended October 31, 2012 compared with the nine months ended October 31, 2011, our U.S. production taxes increased 391% to $2,630,989 from $535,439 for the same respective periods. North Dakota production tax rates for the past two years were 11.5% of oil revenue and approximately 11 cents per mcf of natural gas.

U.S. Other Lease Operating Expenses

Other lease operating expenses (“OLOE”) for U.S. operations increased by $1,644,106 (to $1,920,711 for the nine months ended October 31, 2012 as compared with $276,605 for the nine months ended October 31, 2011). That approximately 600% increase is primarily due to a 446% increase in sales boe quantities along with an approximate 300% increase in net wells. The OLOE/boe was $6.51 for the nine months ended October 31, 2012 compared with $5.12/boe for the nine months ended October 31, 2011.

Oil and Natural Gas Amortization Expense

Amortization of oil and natural gas properties increased to $8,311,001 for the nine months ended October 31, 2012 from $1,521,761 for the nine months ended October 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

During the nine months ended October 31, 2012, RockPile completed 238 stages on seven wells operated by us and one well operated by a third-party customer resulting in total revenue of $31,984,259 and gross profit of $8,176,266. Because we consolidate RockPile’s results, we are required to eliminate intercompany revenue of $16,859,149 and intercompany cost of sales of $12,294,423 related to our working interest in the wells on which services were performed. The $4,564,726 of eliminated gross profit was credited against our capitalized well costs. After intercompany eliminations, pressure pumping revenue for the nine months ended October 31, 2012 was $15,125,110 with gross profit of $3,611,540.

Other

Other services revenue of $440,432 for the nine months ended October 31, 2012 consists primarily of drilling overhead income, interest income and North Dakota lodging facility rental income. Gain on derivative activities of $1,401,267 is the unrealized income on our costless collars and single-day puts. Interest expense of $1,472,025 for the nine months ended October 31, 2012 is primarily related to our Convertible Note with NGP. A small part of the interest expense is the amortization of the capitalized loan costs included within long-term assets.

General and Administrative Expenses

The following table summarizes changes general and administrative expenses for the nine months ended October 31, 2012 from the nine months ended October 31, 2011:

	October 31, 2012		October 31, 2011		Increase (Decrease)
Stock-based compensation	$	4,304,576	$	5,556,377	$	(1,251,801	)
Salaries, benefits and consulting fees		3,901,839		2,411,335		1,490,504
Office rent and other office costs		1,261,109		1,019,001		242,108
Professional fees		1,874,019		1,356,313		517,706
Public company costs		273,337		490,895		(217,557	)
		11,614,880		10,833,921		780,960
RockPile general and administrative expense		5,559,282		170,653		5,388,629
Total general and administrative expense	$	17,174,162	$	11,004,574	$	6,169,589

General and administrative expenses (excluding RockPile) of $11,614,881 for the nine months ended October 31, 2012 increased from that of $10,833,921 for the same period in the prior fiscal year. The increase is primarily attributable to the increased number of employees and increased legal fees. The increased legal fees include approximately $535,000 attributable to the organization of the newly formed Caliber Midstream entities (see Note 5 – Investment in Unconsolidated Affiliate). The substantial increase in RockPile’s general and administrative expense is due to RockPile being newly formed a year ago and subsequently incurring significant general and administrative expenses to commence operations in July 2012.

Analysis of Changes in Cash Flows

Net Cash Provided by Operating Activities

Cash flows used in operating activities was $7.0 million for the nine months ended October 31, 2012. Cash flows used in operating activities was $8.2 million for the nine months ended October 31, 2011. The $1.2 million decrease in cash used in operating activities is primarily attributable to the following: (a) an $22.5 million net increase in cash received from oil and natural gas sales revenue, less (b) a $7.8 million net increase in trade receivables net of the $15.1 million received or receivable for RockPile’s revenue from third parties and less (c) a $6.6 million net increase in cash used for general and administrative expenses, and less (d) a $2.7 million net increase in cash used for production taxes and other lease operating expenses, and less (e) a $0.8 million net decrease in other changes in accounts payable net of the $10.7 million in pressure pumping expenses paid or payable, and less (f) $2.2 million paid for inventory, prepaid deposits and current asset retirement obligations and less (g) $1.1 million in other cash uses.

Net Cash Used in Investing Activities

For the nine months ended October 31, 2012, investing activities used $134.0 million in cash as compared to $90.5 million used in the nine months ended October 31, 2011. The $43.5 million increase in cash used in investing activities is primarily attributable to the following: (a) $9.7 million increase in cash used for the drilling and completion of oil and natural gas properties, (b) approximately $21 million increase in purchase of RockPile equipment and facilities, (c) $12.0 million increase in cash used for the investment in Caliber, (d) $3.9 million increase in cash used for the purchase of derivative contracts, and (e) $3.2 million increase in cash from the sale of oil and natural gas properties.

Net Cash Provided by Financing Activities

Cash flows provided by financing activities for the nine months ended October 31, 2012 totaled $117.2 million. The cash in-flow was primarily a result of proceeds from the $120 million Convertible Note (see Note 8 – Convertible Note under Item 1 in this Quarterly Report).

Cash flows provided by financing activities in the nine months ended October 31, 2011 of $134.9 million 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 $7.6 million.

Commodity Price Risk Management

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and our management believes these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control.

We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil price volatility. All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. All realized and unrealized gains and losses are recorded to gain (loss) on derivatives on the statements of operations.

As of October 31, 2012, we had entered into derivative agreements covering 61,000 barrels for the remainder of calendar 2012, 1,082,500 barrels for calendar 2013 and 182,500 barrels for calendar 2014.

See Note 9 – Commodity Derivative Instruments to the accompanying condensed consolidated financial statements included in this Quarterly Report for additional details of our derivative financial instruments. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk, for a presentation of our oil derivative contracts as of October 31, 2012.

The Company recognized an unrealized gain of $1,401,267 in the derivative activities line on the condensed consolidated statements of operations.

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, future cash flow from operations, our reserve-based lending facility (with a current borrowing base of $52.5 million), and 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 October 31, 2012, we had cash of approximately $45.0 million consisting primarily of cash held in bank accounts with Wells Fargo, Royal Bank of Canada and JP Morgan Chase, as compared to approximately $68.8 million at January 31, 2012. Working capital was approximately $33.2 million as of October 31, 2012, as compared to approximately $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.

Accounting for the Convertible Note

Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report discloses that, under ASC Subtopic 815-15 Derivatives and Hedging – Embedded Derivatives and ASC Subtopic 470-20 Debt with Conversion and Other Options, Triangle’s $120,000,000 Convertible Note issued on July 31, 2012 is not bifurcated and is accounted for as, or like, a stock-based conventional convertible debt since the Note’s inception.

Such accounting differs from that disclosed for the Convertible Note in our Quarterly Report on Form 10-Q for the quarterly period ended July 31, 2012, where page nine of that Quarterly Report disclosed that the Convertible Note consisted of (i) a compound embedded derivative liability (valued at $42,500,000) for the conversion feature and early redemption options and (ii) a discounted note payable with a carrying value of $77,500,000. That disclosure of Convertible Note bifurcation was based on an initial internal analysis of ASC Topic 815 and Topic 470 in the weeks preceding the filing. In October, the internal analysis was expanded to gain a better understanding of ASC 815 and ASC 470 as it applied to the unusual facts and circumstances of the Note. With the expanded analysis, we concluded that the Convertible Note would not be bifurcated under ASC 815 nor under ASC 470.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

We are exposed to commodity price risk, the potential risk of loss from adverse changes in the market price of oil and natural gas commodities. The prices we receive for our oil and natural gas 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.

We manage a portion of the risks associated with market fluctuations in oil prices using derivative instruments. We enter into oil derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also may limit the benefit we might otherwise have received from market price increases. The following table summarizes the oil derivative contracts that we have entered into for each year as of October 31, 2012.

Contract Type	Quantity	Strike Price ($/Bbl)	Term or End Date
Collar	500 bopd	$87.00 / $103.60	November 1, 2012 - December 31, 2012
Collar	500 bopd	$87.00 / $103.80	November 1, 2012 - December 31, 2012
Collar	500 bopd	$85.00 / $104.30	January 1, 2013 - December 31, 2013
Collar	500 bopd	$80.00 / $101.20	January 1, 2014 - December 31, 2014
Put	200,000 bbl	$75.00	June 17, 2013
Put	300,000 bbl	$75.00	December 16, 2013
Put	100,000 bbl	$75.00	June 17, 2013
Put	100,000 bbl	$75.00	June 17, 2013
Put	100,000 bbl	$75.00	December 16, 2013
Put	100,000 bbl	$75.00	December 16, 2013

Interest Rate Risk

As of October 31, 2012, our operating subsidiary had $52.5 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 October 31, 2012 under our credit facility of $52.5 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $525,000.

For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 7 - Credit Facility to the accompanying condensed consolidated financial statements included 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 October 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.

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 Company entered into an Investment Agreement by and among the Company, NGP and the parent company of NGP. Pursuant to the Investment Agreement, NGP is entitled to designate one director to the Triangle board of directors 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 original principal amount 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 original principal amount 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.

The Convertible Note is 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. If NGP were to fully convert the Convertible Note on the date of this Quarterly Report, then NGP would hold approximately 25% of our outstanding shares of common stock.

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.

Triangle’s Limited Partner Interest in the Caliber Joint Venture May be Diluted.

On October 1, 2012, a wholly owned subsidiary of the Company entered into a joint venture with FREIF Caliber Holdings to provide crude oil, natural gas and water transportation services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana. In connection with its investment in the joint venture entity, Triangle’s subsidiary received a 30% percent limited partner interest, as well as certain trigger units convertible into limited partner interests that would cause the Company to increase its ownership to a 50% limited partner interest. Further, Triangle’s subsidiary received certain trigger warrants that would allow Triangle to purchase additional limited partner interests at specified prices. The trigger units and trigger warrants vest upon the joint venture’s achievement of certain business performance metrics, namely connecting at least 162 TUSA wells to the joint venture’s gathering system or attaining aggregate revenues attributable to third party volumes equaling or exceeding 50% percent of projected distributable cash flows as set forth in the joint venture’s annual plan for six consecutive quarters or eight non-consecutive quarters.

There are numerous factors that may adversely affect the achievement of the aforementioned business performance metrics, including, but not limited to, depressed commodity prices, TUSA’s failure to establish commercial discoveries on properties that it intended to connect to the gathering system, competition from other oil and natural gas gathering, transportation and processing companies, regulatory barriers, increased drilling and production costs, and other factors causing TUSA and third party providers to shut in production or seek alternative sources for their transportation needs. If the business performance metrics are never achieved, our trigger units and trigger warrants will not vest, and we would be unable to increase our limited partner interest above 30% absent a direct capital outlay. Further, if FREIF Caliber Holdings makes an additional capital contribution and we choose not to invest additional capital in the joint venture, we would be diluted below our current 30% limited partner interest.

Anti-takeover provisions could make a third party acquisition of us difficult.

We are subject to Section 203 of the Delaware Business Combination Law, which prohibits a business combination between a corporation and an interested stockholder within three years of the time such stockholder became an interested stockholder, absent, in most cases, board or stockholder approval. An “interested stockholder” is any person who, together with affiliates and associates, is the owner of 15% or more of the outstanding voting stock of the corporation, and the term “business combination” encompasses a wide variety of transactions with or caused by an interested stockholder, including mergers, asset sales and other transactions in which the interested stockholder receives or could receive a benefit on other than a pro rata basis with other stockholders. Although a corporation can opt out of Section 203 in its certificate of incorporation, the Company has not opted out of this provision. Section 203 may have an anti-takeover effect for transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock.

Our derivative activities could result in financial losses or reduced income, or could limit our potential gains from increases in prices.

We use derivatives for a portion of our crude oil production to reduce exposure to adverse fluctuations in prices of crude oil and to achieve a more predictable cash flow. These arrangements expose us to the risk of financial loss in some circumstances, including when sales are different than expected, the counter-party to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive. These risks may be exacerbated by the fact that the Company's derivative contracts are currently with one counterparty.

In addition, derivative arrangements may limit the benefit from increases in the price for crude oil, and they may also require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than if our derivative instruments qualified for hedge accounting. For instance, if the price of crude oil rises significantly, it could result in significant non-cash charges each quarter, which could have a material negative effect on our net income.

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 three months ended October 31, 2012.

	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that may Yet Be Purchased Under the Plans or Programs
	(1)		(2)		(3)		(3)
August 1 - August 31, 2012		5,770	$	5.65		—		—
September 1 - September 30, 2012		3,344	$	7.33		—		—
October 1 - October 31, 2012		-	$	-		—		—
Total		9,114	$	6.63		—		—

(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.

Item 6. Exhibits.


2.1	Agreement and Plan of Merger, dated November 29, 2012, filed as Exhibit 2.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.

3.1	Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.

3.2	Bylaws of Triangle Petroleum Corporation, filed as Exhibit 3.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.

4.1	5% Convertible Promissory Note, dated July 31, 2012, filed as Exhibit 4.1 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 Exhibit 4.2 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 Exhibit 4.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.

4.4	Form of Common Stock Certificate of Triangle Petroleum Corporation, filed as Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.

10.1	Note Purchase Agreement, dated July 31, 2012, between Triangle Petroleum Corporation and NGP Triangle Holdings, LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.

10.2	Contribution Agreement, dated October 1, 2012, by and among Triangle Caliber Holdings, LLC, Caliber Midstream GP LLC, Caliber Midstream Partners, L.P., and FREIF Caliber Holdings LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 1, 2012 and incorporated herein by reference.

10.3	Amended and Restated 2011 Omnibus Incentive Plan, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 16, 2012 and incorporated herein by reference.

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

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

SIGNATURES

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


	TRIANGLE PETROLEUM CORPORATION

Date: December 7, 2012	By:	/s/ JONATHAN SAMUELS
	Name: Jonathan Samuels
	Title: Chief Executive Officer (Principal Executive Officer)

Date: December 7, 2012	By:	/s/ JOSEPH FEITEN
	Name: Joseph Feiten
	Title: Chief Financial Officer (Principal Financial and Accounting Officer)