UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended July 31, 2013

o	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 17th 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 o

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

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

As of September 5, 2013, there were 83,199,760 shares of the registrant’s common stock outstanding.

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Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets

(In thousands, except share data)

(Unaudited)

	July 31, 2013			January 31, 2013
ASSETS
CURRENT ASSETS
Cash and equivalents	$	49,380		$	33,117
Accounts receivable:
Oil and natural gas sales	20,970			10,625
Trade	38,815			28,541
Other	1,043			955
Investment in marketable securities	5,769			5,065
Derivative asset	—			603
Inventory, deposits and prepaid expenses	3,847			2,307
Total current assets	119,824			81,213

LONG-TERM ASSETS
Oil and natural gas properties at cost, using the full cost method of accounting:
Unproved properties and properties under development, not being amortized	84,773			94,529
Proved properties	367,648			220,894
	452,421			315,423
Less: accumulated amortization	(33,373		)	(16,666		)
Net oil and natural gas properties	419,048			298,757
Pressure pumping equipment (less accumulated depreciation of $4.9 million and $2.5 million, respectively)	33,609			19,060
Other property and equipment (less accumulated depreciation of $1.6 million and $0.9 million, respectively)	19,817			15,779
Equity investment	22,061			11,768
Other long-term assets	2,556			1,745
Total assets	$	616,915		$	428,322

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	35,098		$	37,043
Accrued liabilities:
Exploration and development	52,043			30,433
Other	9,800			7,486
Notes payable	5,876			—
Short-term borrowings on Credit Facilities	5,839			—
Asset retirement obligations	2,464			2,949
Derivative liability	2,459			—
Total current liabilities	113,579			77,911

LONG-TERM LIABILITIES
Long-term borrowings on Credit Facilities	104,481			25,000
5% Convertible Note	126,118			123,023
Asset retirement obligations	583			473
Derivative liability	240			292
Total liabilities	345,001			226,699

COMMITMENTS AND CONTINGENCIES (Note 11)
STOCKHOLDERS’ EQUITY
Common stock, $0.00001 par value, 140,000,000 shares authorized; 56,509,234 and 46,733,011 shares issued and outstanding at July 31, 2013 and January 31, 2013, respectively	—			—
Additional paid-in capital	381,924			323,643
Accumulated deficit	(110,010		)	(122,020		)
Accumulated other comprehensive income	—			—
Total stockholders’ equity	271,914			201,623
Total liabilities and stockholders’ equity	$	616,915		$	428,322

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

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Triangle Petroleum Corporation

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(In thousands, except per share data)

(Unaudited)

	For the Three Months Ended July 31,						For the Six Months Ended July 31,
	2013			2012			2013			2012
REVENUES:
Oil and natural gas sales	$	34,639		$	7,507		$	55,699		$	12,680
Pressure pumping services	15,590			2,595			28,710			2,595
Other	165			156			279			225
Total revenues	50,394			10,258			84,688			15,500
EXPENSES:
Production taxes	3,919			837			6,363			1,429
Other lease operating expenses	2,830			214			5,046			457
Gathering, transportation and processing	69			33			106			43
Depreciation and amortization	10,918			2,997			18,391			5,170
Accretion of asset retirement obligations	9			84			17			168
Pressure pumping	12,692			1,845			23,878			2,032
General and administrative:
Stock-based compensation	1,438			1,433			3,033			2,798
Salaries and benefits	4,133			2,510			7,258			4,676
Other general and administrative	1,309			1,567			3,093			3,325
Total operating expenses	37,317			11,520			67,185			20,098

INCOME (LOSS) FROM OPERATIONS	13,077			(1,262		)	17,503			(4,598		)

OTHER INCOME (EXPENSE):
Loss from derivative activities	(4,399		)	—			(3,187		)	—
Interest expense	(1,969		)	(32		)	(3,441		)	(42		)
Loss from equity investment	(596		)	—			—			—
Interest income	43			85			80			98
Other income	643			—			1,055			9
Total other income (expense)	(6,278		)	53			(5,493		)	65

NET INCOME (LOSS) BEFORE INCOME TAXES	6,799			(1,209		)	12,010			(4,533		)
Income tax provision	—			—			—			—
NET INCOME (LOSS)	6,799			(1,209		)	12,010			(4,533		)
Less: net loss attributable to noncontrolling interest in subsidiary	—			256			—			552
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	6,799		$	(953	)	$	12,010		$	(3,981	)

Net income (loss) per common share outstanding:
Basic	$	0.12		$	(0.02	)	$	0.22		$	(0.09	)
Diluted	$	0.12		$	(0.02	)	$	0.22		$	(0.09	)

Weighted average common shares outstanding:
Basic	56,451			44,265			54,561			44,162
Diluted	57,012			44,265			55,089			44,162

COMPREHENSIVE INCOME (LOSS):
Net income (loss) attributable to common stockholders	$	6,799		$	(953	)	$	12,010		$	(3,981	)
Other comprehensive income (loss)	—			—			—			—
Total comprehensive income (loss)	$	6,799		$	(953	)	$	12,010		$	(3,981	)

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

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Triangle Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	For the Six Months Ended July 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	12,010		$	(4,533	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	18,391			5,170
Stock-based compensation	3,069			3,327
Interest expense not paid in cash	2,545			29
Accretion of asset retirement obligations	17			168
Loss on derivatives	3,187			—
Unrealized income on securities held for investment	(990		)	—
Changes in related current assets and current liabilities:
Inventory, deposits and prepaid expenses	(1,025		)	(825		)
Accounts receivable:
Oil and natural gas sales	(10,059		)	(37		)
Trade	(10,241		)	(22,754		)
Other	(88		)	51
Accounts payable and accrued liabilities	15,101			23,688
Asset retirement expenditures	(484		)	(248		)
Cash provided by operating activities	31,433			4,036

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures	(130,132		)	(55,952		)
Sale of oil and natural gas properties	—			2,712
Purchase of pressure pumping equipment	(15,953		)	(21,391		)
Purchase of other property and equipment	(4,318		)	(484		)
Investment in Caliber Midstream Partners, L.P.	(9,000		)	—
Cash advanced to operators for oil and natural gas property	—			539
Cash used in investing activities	(159,403		)	(74,576		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock	55,800			—
Proceeds from Credit Facilities	90,320			13,700
Repayments to Credit Facilities	(5,000		)	(13,700		)
Proceeds from Notes Payable	5,876			120,000
Debt issuance costs	(1,538		)	(377		)
Cash paid to settle tax on vested restricted stock units	(1,225		)	(1,553		)
Issuance of common stock for exercise of options	—			12
Cash provided by financing activities	144,233			118,082

NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS	16,263			47,542
CASH AND EQUIVALENTS, BEGINNING OF PERIOD	33,117			68,815
CASH AND EQUIVALENTS, END OF PERIOD	$	49,380		$	116,357

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

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Triangle Petroleum Corporation

Condensed Consolidated Statement of Stockholders’ Equity

For the Six Months Ended July 31, 2013

(in thousands, except share data)

(Unaudited)

	Shares of Common Stock	Common Stock at Par Value		Additional Paid-in Capital			Accumulated Deficit			Total Equity
Balance - January 31, 2013	46,733,011	$	—	$	323,643		$	(122,020	)	$	201,623
Shares issued at $6.00/share	9,300,000	—		55,800			—			55,800
Shares issued for services	5,000	—		36						36
Vesting of restricted stock units (net of shares surrendered for taxes)	471,223	—		(1,225		)	—			(1,225		)
Stock-based compensation	—	—		3,670			—			3,670
Net income for the period	—	—		—			12,010			12,010
Balance - July 31, 2013	56,509,234	$	—	$	381,924		$	(110,010	)	$	271,914

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

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Triangle Petroleum Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

1. Organization and Nature of Operations

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

RockPile Energy Services, LLC, a wholly-owned subsidiary founded in June 2011, is a provider of hydraulic pressure pumping and complementary well completion services to oil and natural gas exploration and production companies in the Williston Basin of North Dakota and Montana.

The Company also holds leasehold interests in acreage in the Maritimes Basin of Nova Scotia, which we fully impaired as of January 31, 2012.

2. Basis of Presentation and Significant Accounting Policies

The accompanying condensed consolidated balance sheet as of January 31, 2013 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 its wholly-owned subsidiaries: (i) Triangle USA Petroleum Corporation (“TUSA”), incorporated in the State of Colorado, and its wholly-owned subsidiaries, (ii) RockPile Energy Services, LLC (“RockPile”), organized in the State of Delaware, and its wholly-owned subsidiaries, (iii) Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, (iv) Leaf Minerals, LLC, organized in the State of Colorado, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, and (vi) Triangle Caliber Holdings, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated. The Company accounts for its 30% voting interest in Caliber Midstream Partners, L.P. (“Caliber”) and 50% voting interest in Caliber Midstream GP LLC (“Caliber Midstream GP”) under the equity method. The Company’s fiscal year-end is January 31.

Certain information and footnote disclosures 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 for the fiscal year ended January 31, 2013, filed with the SEC on May 1, 2013, and amended on May 31, 2013 to incorporate the Part III information (“Fiscal 2013 Form 10-K”).

In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the three and six month periods ended July 31, 2013 are not necessarily indicative of the operating results for the entire fiscal year ending January 31, 2014.

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 the amortization, and any impairment, of capitalized oil and natural gas property costs, each of which can represent a significant component of the consolidated financial statements. Management estimated the proved reserves as of July 31, 2013 with consideration of (1) the proved reserve estimates for the prior fiscal year-end audited by independent engineering consultants and (2) any significant new discoveries and changes during the interim period in production, pricing, ownership, and other factors underlying reserve estimates.

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Significant Accounting Policies

For descriptions of the Company’s significant accounting policies, see Note 3 — Summary of Significant Accounting Policies in our audited financial statements included in our Fiscal 2013 Form 10-K.

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.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2011-11 (“ASU 2011-11”), Balance Sheet: Disclosures about Offsetting Assets and Liabilities which applies to certain items in the statement of financial position (balance sheet), and was further clarified in January 2013 by ASU 2013-01, Balance Sheet: Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarified the scope of ASU 2011-11 to derivative instruments, repurchase agreements and securities lending transactions. The effective date for the amendments is for annual periods beginning after January 1, 2013, and interim periods within those annual periods. ASU 2011-11 requires disclosures of the gross and net amounts for items eligible for offset in the balance sheet. The Company records its derivative financial instruments on a net basis by contract. The gross amounts are disclosed in Note 9 — Commodity Derivative Instruments. The adoption of this standard had no impact on the Company’s financial position or results of operations.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date, are not expected to have a material impact on the financial statements upon adoption.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, total stockholders’ equity, net income, or net cash provided by or used in operating, investing or financing activities.

Asset Retirement Obligations

The following table reflects the change in asset retirement obligations for the six-month period ended July 31, 2013 (in thousands):

	For the Six
	Months Ended
	July 31, 2013
Balance, January 31, 2013	$	3,422
Liabilities incurred	290
Revision of estimates	(188		)
Sale of assets	(10		)
Liabilities settled	(484		)
Accretion	17
Balance, July 31, 2013	3,047
Less current portion of obligations	(2,464		)
Long-term asset retirement obligations	$	583

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3. Segment Reporting

In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have two reportable operating segments. The Company identified each segment based on management’s responsibility and the nature of their products, services, and costs. There are no major distinctions in geographical areas served as all operations are in the Williston Basin of the United States. The exploration and production operating segment is responsible for finding and producing oil and natural gas. The pressure pumping and other services operating segment is responsible for pressure pumping for both Triangle-operated wells and wells operated by third-parties.

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 for the three months ended July 31, 2013 (in thousands):

For the Three Months Ended July 31, 2013

	Exploration and Production			Pressure Pumping and Other Services			Corporate and Other (1)			Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	34,639		$	—		$	—		$	—		$	34,639
Pressure pumping services for third parties	—			16,972			—			(1,382		)	15,590
Intersegment revenues	—			27,148			—			(27,148		)	—
Other	—			165			272			(272		)	165
Total revenues	34,639			44,285			272			(28,802		)	50,394
Expenses
Production taxes and other lease operating	6,749			—			—			—			6,749
Gathering, transportation and processing	69			—			—			—			69
Depreciation and amortization	10,111			1,600			135			(928		)	10,918
Accretion of asset retirement obligations	9			—			—			—			9
Pressure pumping	—			30,370			—			(17,678		)	12,692
General and Administrative:													—
Stock-based compensation	247			99			1,092			—			1,438
Other general and administrative	1,569			2,446			1,427			—			5,442
Total operating expenses	18,754			34,515			2,654			(18,606		)	37,317
Income (loss) from operations	15,885			9,770			(2,382		)	(10,196		)	13,077
Other expense, net	(4,193		)	(216		)	(576		)	(1,293		)	(6,278		)
Net income (loss) before income taxes	$	11,692		$	9,554		$	(2,958	)	$	(11,489	)	$	6,799

(1) Corporate and Other includes our corporate office and several subsidiaries that management does not consider in the exploration and production or pressure pumping segments. These subsidiaries have limited activity.

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The following table presents selected financial information for Triangle’s operating segments for the six months ended July 31, 2013 (in thousands):

For the Six Months Ended July 31, 2013

	Exploration and Production			Pressure Pumping and Other Services			Corporate and Other (1)			Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	55,699		$	—		$	—		$	—		$	55,699
Pressure pumping services for third parties	—			32,002			—			(3,292		)	28,710
Intersegment revenues	—			38,887			—			(38,887		)	—
Other	—			279			548			(548		)	279
Total revenues	55,699			71,168			548			(42,727		)	84,688
Expenses
Production taxes and other lease operating	11,409			—			—			—			11,409
Gathering, transportation and processing	106			—			—			—			106
Depreciation and amortization	16,729			2,839			258			(1,435		)	18,391
Accretion of asset retirement obligations	17			—			—			—			17
Pressure pumping	—			49,491			—			(25,613		)	23,878
General and Administrative:
Stock-based compensation	569			310			2,154			—			3,033
Other general and administrative	3,033			4,425			2,893			—			10,351
Total operating expenses	31,863			57,065			5,305			(27,048		)	67,185
Income (loss) from operations	23,836			14,103			(4,757		)	(15,679		)	17,503
Other expense, net	(2,840		)	(369		)	(991		)	(1,293		)	(5,493		)
Net income (loss) before income taxes	$	20,996		$	13,734		$	(5,748	)	$	(16,972	)	$	12,010

Total Assets	$	496,825		$	86,583		$	405,793		$	(372,286	)	$	616,915
Net oil and natural gas properties	$	436,021		$	—		$	—		$	(16,973	)	$	419,048
Pressure pumping equipment	$	—		$	33,609		$	—		$	—		$	33,609
Other property and equipment - net	$	1,607		$	16,588		$	1,622		$	—		$	19,817
Total Liabilities	$	208,604		$	40,713		$	128,482		$	(32,798	)	$	345,001

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The following table presents selected financial information for Triangle’s operating segments for the three months ended July 31, 2012 (in thousands):

For the Three Months Ended July 31, 2012

	Exploration and Production		Pressure Pumping and Other Services			Corporate and Other (1)			Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	7,507	$	—		$	—		$	—		$	7,507
Pressure pumping services for third parties	—		2,595			—			—			2,595
Intersegment revenues	—		5,524						(5,524		)	—
Other	57		—			99			—			156
Total revenues	7,564		8,119			99			(5,524		)	10,258
Expenses
Production taxes and other lease operating	1,051		—			—			—			1,051
Gathering, transportation and processing	33		—			—			—			33
Depreciation and amortization	3,122		9			(134		)	—			2,997
Accretion of asset retirement obligations	3		—			81			—			84
Pressure pumping	—		6,170			—			(4,325		)	1,845
General and Administrative:												—
Stock-based compensation	704		—			729			—			1,433
Other general and administrative	1,174		2,277			626			—			4,077
Total operating expenses	6,087		8,456			1,302			(4,325		)	11,520
Income (loss) from operations	1,477		(337		)	1,203			(1,199		)	(1,262		)
Other income, net	39		—			14			—			53
Net income (loss) before income taxes	$	1,516	$	(337	)	$	1,189		$	(1,199	)	$	(1,209	)

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The following table presents selected financial information for Triangle’s operating segments for the six months ended July 31, 2012 (in thousands):

For the Six Months Ended July 31, 2012

	Exploration and Production		Pressure Pumping and Other Services			Corporate and Other (1)			Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	12,680	$	—		$	—		$	—		$	12,680
Pressure pumping services for third parties	—		2,595			—			—			2,595
Intersegment revenues	—		5,524			—			(5,524		)	—
Other	77		—			270			(122		)	225
Total revenues	12,757		8,119			270			(5,646		)	15,500
Expenses
Production taxes and other lease operating	1,886		—			—			—			1,886
Gathering, transportation and processing	43		—			—			—			43
Depreciation and amortization	5,238		11			(79		)	—			5,170
Accretion of asset retirement obligations	5		—			163			—			168
Pressure pumping	—		6,357			—			(4,325		)	2,032
General and Administrative:
Stock-based compensation	1,318		—			1,480			—			2,798
Other general and administrative	2,365		3,875			1,761			—			8,001
Total operating expenses	10,855		10,243			3,325			(4,325		)	20,098
Income (loss) from operations	1,902		(2,124		)	3,055			(1,321		)	(4,598		)
Other income, net	39		9			17			—			65
Net income (loss) before income taxes	$	1,941	$	(2,115	)	$	3,038		$	(1,321	)	$	(4,533	)

4. Property and Equipment

During the six months ended July 31, 2013, we acquired oil and natural gas properties and participated in the drilling and/or completion of wells, for total consideration of approximately $136.9 million ($6.2 million for the acquisition of leaseholds).

In the three and six months ended July 31, 2013, we capitalized $0.9 million and $1.7 million, respectively, of internal land, geology and operations department costs directly associated with property acquisition, exploration (including lease record maintenance) and development. In the three and six months ended July 31, 2012, we capitalized $0.4 million and $0.8 million of internal land and geology 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.

Pressure pumping equipment consists primarily of costs for two frac spreads and complimentary well completion equipment which are all in service as of July 31, 2013.

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Restricted Stock Units

During the six months ended July 31, 2013, the Company granted 982,133 restricted stock units as compensation to officers, directors and employees. The restricted stock units vest over one to five years. As of July 31, 2013, there was approximately $14.7 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 2.7 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, 2013	2,424,085		$	7.02
Units granted during the six months ended July 31, 2013	982,133		$	6.15
Units forfeited during the six months ended July 31, 2013	(20,919	)	$	6.69
Units that vested during the six months ended July 31, 2013	(667,280	)	$	7.41
Restricted stock units outstanding - July 31, 2013	2,718,019		$	6.30

For the three and six months ended July 31, 2013, the Company recorded stock-based compensation related to restricted stock units of $1.3 million and $2.7 million, respectively, in general and administrative expenses. An additional $0.3 million and $0.6 million of stock based compensation was capitalized to oil and natural gas properties during the three and six months ended July 31, 2013, respectively.

For the three and six months ended July 31, 2012, the Company recorded stock-based compensation related to restricted stock units of $1.4 million and $2.8 million, respectively, in general and administrative expenses. An additional $0.2 million of stock based compensation was capitalized to oil and natural gas properties during the three and six months ended July 31, 2012.

Stock Options

The following table summarizes the status of stock options outstanding under the Rolling Plan (for a discussion of the Rolling Plan, see Note 10 — Share-Based Compensation in our audited financial statements included in our Fiscal 2013 Form 10-K):

	Number of Shares	Weighted Average Exercise Price
Options outstanding - January 31, 2013 (231,666 exercisable)	231,666	$	1.48
Less: options exercised	—
Options outstanding - July 31, 2013 (231,666 exercisable)	231,666	$	1.48

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The following table presents additional information related to the stock options outstanding under the Rolling Plan at July 31, 2013:

		Remaining
Exercise Price		Contractual Life	Number of shares
per Share		(years)	Outstanding		Exercisable
$	3.00	0.50	30,000		30,000
$	1.25	1.33	201,666		201,666
			231,666		231,666

Weighted average exercise price per share			$	1.48	$	1.48

Weighted average remaining contractual life			1.23		1.23

As of July 31, 2013, all compensation expense related to stock options under the Rolling Plan has been recognized. All such options became fully vested in fiscal year 2013. The aggregate intrinsic value of the options as of July 31, 2013 was $1.3 million.

On July 4, 2013, the Company entered into a CEO Stand-Alone Stock Option Agreement with Jonathan Samuels, the Company’s President and Chief Executive Officer (the “CEO Option Grant”). The CEO Option Grant is a stand-alone stock option agreement unrelated to the Company’s existing Amended and Restated 2011 Omnibus Incentive Plan. As such, the CEO option Grant requires stockholder approval before any shares of the Company’s common stock can be issued thereunder. The options under the CEO Option Grant were granted as of the execution date thereof; however, the options granted thereunder were not exercisable, and would have expired and become null and void in their entirety, if they were not approved by the stockholders of the Company on or before July 4, 2015. Thus, no compensation expense was recognized for these option grants prior to being approved by the stockholders. At the Company’s Annual Meeting of Stockholders held on August 30, 2013, the CEO Option Grant was approved.

The CEO Option Grant covers a total of 6.0 million shares of Company common stock and is divided into five tranches, each with a different exercise price, as follows:

Name of Tranche	Number of Shares	Exercise Price
“$7.50 Tranche”	750,000	$7.50 per share
“$8.50 Tranche”	750,000	$8.50 per share
“$10.00 Tranche”	1,500,000	$10.00 per share
“$12.00 Tranche”	1,500,000	$12.00 per share
“$15.00 Tranche”	1,500,000	$15.00 per share

Each tranche of the CEO Option Grant generally vests and becomes exercisable on the same vesting schedule, with 10% of each tranche becoming vested and exercisable on each of the first two anniversaries of the grant date, 50% of each tranche becoming vested and exercisable on the third anniversary of the grant date, 20% of each tranche becoming vested and exercisable on the fourth anniversary of the grant date, and the remaining 10% of each tranche becoming vested and exercisable on the fifth anniversary of the grant date. Once any portion of the CEO Option Grant becomes vested, it is exercisable until the option expires. The options expire ten years after their grant date.

RockPile Share Based Compensation

At July 31, 2013, RockPile (an LLC) had 30.0 million Series A Units authorized by the LLC Agreement (as defined below) with 25.5 million Series A Units outstanding, all of which are owned by Triangle. Series A Units were issued to the three parties who had contributed the initial $24.0 million in RockPile’s paid-in capital prior to October 31, 2011. Triangle had contributed $20.0 million and received 20.0 million Series A Units on October 31, 2011. On

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A summary of RockPile’s Series B Unit activity and vesting for the six months ended July 31, 2013 is as follows:

	Series B-1 Units		Series B-2 Units		Series B-3 Units
Units unvested at January 31, 2013	1,441,667		60,000		—
Units granted	—		—		910,000
Units vested	—		—		—
Units unvested at July 31, 2013	1,441,667		60,000		910,000

Weighted average award date unit fair value	$	0.44	$	0.29	$	0.70
Remaining vesting period (years)	0.93		2.08		3.78

Non-cash compensation cost related to the Series B Units was $0.1 million and $0.3 million for the three and six months ended July 31, 2013, respectively.

As of July 31, 2013, there was approximately $1.0 million of unrecognized compensation cost related to non-vested Series B Units. We expect to recognize such cost on a pro-rata basis on the Series B Units vesting schedule during the next four fiscal years.

7. Earnings Per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted net income per common share reflects increases in average shares outstanding from the potential dilution that could occur upon (i) exercise of options to acquire common stock and (ii) vesting of restricted stock units, both computed using the treasury stock method. That method assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company at the quarter’s average stock price using assumed proceeds from (a) the exercise cost of the options and (b) cash equaling the foregone future compensation expense of hypothetical early vesting of the RSUs outstanding, adjusted for certain assumed income tax effects.

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the three and six months ended July 31, 2013 and 2012 (in thousands, except per share data):

	For the Three Months Ended July 31,					For the Six Months Ended July 31,
	2013		2012			2013		2012
Net income (loss) attributable to common shareholders	$	6,799	$	(953	)	$	12,010	$	(3,981	)

Basic weighted average common shares outstanding	56,451		44,265			54,561		44,162
Effect of dilutive securities	561		—			528		—
Diluted weighted average common shares outstanding	57,012		44,265			55,089		44,162

Basic net income (loss) per share	$	0.12	$	(0.02	)	$	0.22	$	(0.09	)
Diluted net income (loss) per share	$	0.12	$	(0.02	)	$	0.22	$	(0.09	)

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8. Notes Payable and Credit Facilities

As of the dates indicated in the table below, the Company’s debt consisted of the following (in thousands):

	July 31, 2013			January 31, 2013
TUSA Credit Facility	$	96,000		$	25,000
5% Convertible Note	126,118			123,023
RockPile Credit Facility	14,320			—
RockPile Notes Payable	5,876			—
Total debt	242,314			148,023
Less: Current portion	(11,715		)	—
Total debt, net of current portion	$	230,599		$	148,023

The weighted average effective interest rates of the loans were 4.0% at July 31, 2013 and 4.6% at January 31, 2013.

TUSA Credit Facility

On July 30, 2013, TUSA entered into Amendment No. 1 to the Amended and Restated Credit Agreement and Master Assignment with Wells Fargo Bank, National Association, as administrative agent and issuing lender, and the other lenders named therein, as lenders. The Amendment amends that certain Amended and Restated Credit Agreement (the “A&R Credit Agreement”), dated as of April 11, 2013, among TUSA, Wells Fargo, as administrative agent and issuing lender, and the other lenders named therein to (i) increase the borrowing base under the A&R Credit Agreement from $110.0 million to $165.0 million, (ii) permit TUSA to hedge up to 85% of the anticipated production of (x) oil, (y) gas, and (z) natural gas liquid volumes, respectively, attributable to TUSA’s total proved reserves, and (iii) make revisions enabling TUSA to enter into a second lien credit facility at a future date. Further, Wells Fargo, in its capacity as a lender under the A&R Credit Agreement, assigned to the other lenders a portion of its lending commitment initially established in the A&R Credit Agreement. As of July 31, 2013, TUSA, as borrower, had borrowings of $96.0 million outstanding under the TUSA Credit Facility.

The borrowing base under the TUSA Credit Facility is subject to redetermination by the beginning of August 2013, November 2013, February 2014 and May 2014, and thereafter on a semi-annual basis by the beginning of each May and November. In addition, TUSA has the option to request one unscheduled interim redetermination prior to May 1, 2014 during any year and two additional redeterminations after May 1, 2014 during any year. With a five-year term, all borrowings under the TUSA Credit Facility mature on April 11, 2018.

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

The Credit Facility contains financial covenants requiring TUSA to comply with the following: (i) TUSA must maintain a ratio of consolidated current assets (as defined in the Credit Facility) to consolidated current liabilities (as defined in the Credit Facility) of at least 1.0 to 1.0; and (ii) the ratio of TUSA’s consolidated debt to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) may not be greater than 4.0 to 1.0. As of July 31, 2013, TUSA was in compliance with all financial covenants under the Credit Facility.

Convertible Note

On July 31, 2012, the Company sold to NGP a $120 million Convertible Note (the “Convertible Note”) that became convertible after November 16, 2012 into Company common stock at a conversion rate of one share per $8.00 of note principal (see Note 12 — Long-Term Debt in our audited financial statements included in our Fiscal 2013 Form 10-K).

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The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, 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 will be paid-in-kind by adding to the principal balance of the Convertible Note; provided that, after July 31, 2017, the Company has the option to make such interest payments in cash. As of July 31, 2013, $6.1 million of accrued interest has been added to the principal balance of the Convertible Note.

RockPile Credit Facility

On February 25, 2013, RockPile entered into a Credit and Security Agreement (the “RockPile Credit Agreement”) between RockPile, as borrower, and Wells Fargo Bank, National Association, as lender (the “Lender”). The RockPile Credit Agreement provides for a maximum borrowing of $20.0 million. Borrowings under the RockPile Credit Agreement are available to: (i) provide for the working capital and general corporate requirements of RockPile, (ii) purchase equipment, (iii) pay any fees and expenses in connection with the RockPile Credit Agreement, and (iv) support letters of credit. The maturity date of the RockPile Credit Agreement is February 25, 2016, unless sooner terminated as provided in the RockPile Credit Agreement. The RockPile Credit Agreement has three components:

i) Equipment Term Loan: The equipment term loan has a maximum borrowing of $10.5 million. The loan bears interest at the daily three month LIBOR plus 4.50%. Payments on this loan are interest only until September 2013 at which time monthly principle payments of $350,000 plus monthly accrued and unpaid interest will be due. At July 31, 2013, the full $10.5 million was outstanding, the interest rate was 4.875% and accrued and unpaid interest was $44,078.

ii) Discretionary Capex Term Loan: The discretionary capex term loan has a maximum borrowing of $2.0 million. This loan bears interest at the daily three month LIBOR plus 4.50%. Payments on this loan are interest only until January 2014 at which time monthly principle payments of $74,074 plus accrued and unpaid interest will be due. At July 31, 2013, the full $2.0 million was outstanding, the interest rate was 4.875% and accrued and unpaid interest was $8,396.

iii) Revolving Loan: The revolving loan has a maximum borrowing of $7.5 million. RockPile can draw down on this facility from time to time in amounts not to exceed the maximum borrowing or an amount supported by a borrowing base certificate, whichever is less. This loan bears interest at the daily three month LIBOR plus 4.00%. Amounts outstanding under this loan may be repaid and reborrowed at any time. At July 31, 2013, $1.8 million was outstanding, the interest rate was 4.375% and accrued interest was $3,319.

At July 31, 2013, there were no letters of credit outstanding.

The borrowings under the RockPile Credit Agreement are also guaranteed by Triangle and each subsidiary of RockPile, provided that the Lender will consider releasing the guaranty of Triangle upon receipt and review of RockPile’s audited financial statements for the fiscal year ending January 31, 2014. If the Lender chooses not to release Triangle’s guaranty within 30 days following receipt of RockPile’s audited financial statements for the fiscal year ending January 31, 2014, RockPile will have no obligation to pay a termination fee should it opt to refinance with another lender or otherwise prepay and terminate the RockPile Credit Agreement. Borrowings under the RockPile Credit Agreement are secured by certain of RockPile’s assets, including all of its equipment and other personal property of RockPile but excluding any owned real property. In addition, the subsidiary guarantors (and not Triangle) pledged certain of their assets to secure their obligations under the guaranty.

The RockPile Credit Agreement contains standard representations, warranties and covenants for a transaction of its nature, 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 RockPile Credit Agreement also contains various covenants and restrictive provisions which may, among other things, limit RockPile’s ability to sell assets, incur additional indebtedness, make investments or loans, and create liens. As of July 31, 2013, RockPile was in compliance with all financial covenants under the Credit Facility.

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The Company’s commodity derivative contracts as of July 31, 2013 are summarized below:

Collars	Basis	Quantity (Bbl/d)	Strike Price ($/Bbl)
May 1, 2013 - September 30, 2013	NYMEX	250 bopd	$90.00 - $102.50
July 1, 2013 - December 31, 2013	NYMEX	500 bopd	$87.00 - $101.75
May 1, 2013 - December 31, 2013	NYMEX	500 bopd	$85.00 - $104.30
May 1, 2013 - December 31, 2013	NYMEX	500 bopd	$85.00 - $100.50
May 1, 2013 - December 31, 2013	NYMEX	250 bopd	$90.00 - $101.50
May 1, 2013 - December 31, 2013	NYMEX	100 bopd	$87.50 - $100.00
August 1, 2013 - December 31, 2013	NYMEX	250 bopd	$94.00 - $110.25
August 1, 2013 - December 31, 2013	NYMEX	500 bopd	$90.00 - $105.00
August 1, 2013 - December 31, 2013	NYMEX	250 bopd	$90.00 - $107.85
August 1, 2013 - December 31, 2013	NYMEX	250 bopd	$93.00 - $107.50
October 1, 2013 - December 31, 2013	NYMEX	250 bopd	$90.00 - $106.50
January 1, 2014 - March 31, 2014	NYMEX	250 bopd	$85.00 - $98.75
January 1, 2014 - June 30, 2014	NYMEX	500 bopd	$85.00 - $100.80
January 1, 2014 - June 30, 2014	NYMEX	250 bopd	$87.00 - $101.00
April 1, 2014 - June 30, 2014	NYMEX	150 bopd	$84.25 - $100.00
January 1, 2014 - December 31, 2014	NYMEX	250 bopd	$85.00 - $99.50
January 1, 2014 - December 31, 2014	NYMEX	500 bopd	$80.00 - $101.20
January 1, 2014 - December 31, 2014	NYMEX	250 bopd	$82.00 - $98.00
January 1, 2014 - December 31, 2014	NYMEX	500 bopd	$83.00 - $99.25
January 1, 2014 - December 31, 2014	NYMEX	250 bopd	$85.00 - $100.00
January 1, 2014 - December 31, 2014	NYMEX	250 bopd	$85.00 - $100.50
July 1, 2014 - December 31, 2014	NYMEX	500 bopd	$83.50 - $100.00
January 1, 2015 - December 31, 2015	NYMEX	500 bopd	$80.00 - $94.50

Puts	Basis	Quantity (Bbl)	Average Strike Price ($/Bbl)
Expiring on December 13, 2013	NYMEX	500,000	$	75.00

(1) NYMEX refers to prices of West Texas Intermediate crude oil at Cushing, Oklahoma as quoted on the New York Mercantile Exchange.

The following table sets forth a summary of the distribution of net fair value of the Company’s derivative instruments:

Counterparty	July 31, 2013		January 31, 2013
Wells Fargo Bank, N.A.	66	%	100	%
Bank of America Merrill Lynch	34	%	—	%
Total	100	%	100	%

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The following tables detail the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category (in thousands):

		As of July 31, 2013
Underlying Commodity	Location on Consolidated Balance Sheet	Gross Amount of Recognized Assets (Liabilities)			Gross Amount of Offset in the Consolidated Balance Sheets		Net Amount of Assets (Liabilities) Presented in the Consolidated Balance Sheet
Crude oil derivative	Current liabilities	$	(2,645	)	$	186	$	(2,459	)

Crude oil derivative	Long-term liabilities	$	(240	)	$	—	$	(240	)

		As of January 31, 2013
Underlying Commodity	Location on Consolidated Balance Sheet	Gross Amount of Recognized Assets (Liabilities)			Gross Amount of Offset in the Consolidated Balance Sheets			Net Amount of Assets (Liabilities) Presented in the Consolidated Balance Sheet
Crude oil derivative	Current assets	$	1,305		$	(702	)	$	603

Crude oil derivative	Long-term liabilities	$	(292	)	$	—		$	(292	)

The amount of loss recognized related to the Company’s derivative financial instruments was as follows (in thousands):

	Three Months Ended July 31,					Six Months Ended July 31,
	2013			2012		2013			2012
Unrealized loss on derivative contracts	$	(2,806	)	$	—	$	(1,594	)	$	—
Realized loss on derivative contracts	(1,593		)	—		(1,593		)	—
Total loss on derivative contracts	$	(4,399	)	$	—	$	(3,187	)	$	—

Unrealized gains and losses resulting from derivatives are recorded at fair value on the condensed consolidated balance sheets and changes in fair value are recognized on the condensed consolidated statement of operations and comprehensive income (loss). 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

The FASB’s Accounting Standards Codification (“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

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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; and

· 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 July 31, 2013 by level within the fair value hierarchy (in thousands):

	Level 1		Level 2		Level 3		Total
Assets:
Investment in marketable securities	$	5,769	$	—	$	—	$	5,769
Derivative liabilities	$	—	$	2,699	$	—	$	2,699

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. The Company considers its counterparty to be of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At July 31, 2013, 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 $126.1 million at July 31, 2013) has an estimated fair value at July 31, 2013 of $164.1 million, based on discounted cash flow analysis and option pricing (Level 3). The increase in fair value from January 31, 2013 is largely due to an increase in option value for Triangle common stock’s closing price being $7.10 per share at July 31, 2013 compared with $6.29 per share at January 31, 2013.

The following table presents the rollforward of the Company’s Level 3 financial liability’s fair value (in thousands):

Ending balance, January 31, 2013	$	132,900
Interest paid in-kind	3,095
Increase in net unrecognized loss	28,125
Ending balance, July 31, 2013	$	164,120

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11. Commitments and Contingencies

At July 31, 2013, 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.

As of July 31, 2013 the Company was subject to commitments on three drilling rig contracts. The contracts expire in September 2013 and April 2014. In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $6.6 million as of July 31, 2013 as required under the terms of the contract.

On August 5, 2013 the Company entered into an additional drilling rig contract that is effective August 5, 2013 and expires on February 4, 2015. In the event of early termination of the contract, the Company would be obligated to pay an aggregate amount of approximately $16.4 million as required under the terms of the contract.

12. Supplemental Disclosures of Cash Flow Information

	For the Six Months Ended July 31,
	2013		2012
	(in thousands)
Cash paid during the period for:
Interest expense	$	1,042	$	42

Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increased (decreased) accrued liabilities and decreased prepaid well costs	$	6,700	$	12,730
Issuance of common stock	$	—	$	1,204
Change in asset retirement obligations	$	92	$	32
Capitalized stock-based compensation	$	605	$	358
Capitalized interest	$	1,100	$	—

13. Income Taxes

The Company has net deferred tax assets as of July 31, 2013 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. The Company will continue to evaluate whether a valuation allowance is needed in future reporting periods. As of July 31, 2013 and 2012, a full valuation allowance was placed against net deferred tax assets. As a result, no income tax expense or benefit was recorded for the three or six months ended July, 2013 and 2012.

Given the substantial net operating loss carry forwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated as any such adjustments would likely adjust net operating loss carry forwards. As such, as of July 31, 2013, the Company has not recognized any interest or penalties related to uncertain tax benefits.

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14. Related Party Transactions

On October 1, 2012, TUSA entered into two midstream services agreements with Caliber North Dakota LLC (“Caliber North Dakota”). Caliber North Dakota LLC is a wholly owned subsidiary of Caliber, LP in which Triangle has a 30% ownership. The two agreements were as follows: (a) an agreement for crude oil gathering, stabilization, treating and redelivery, and (b) an agreement for (i) natural gas compression, gathering, dehydration, processing and redelivery; (ii) produced water transportation and disposal services; and (iii) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. Under the agreements, TUSA committed to deliver minimum monthly revenues derived from the fees paid by TUSA to Caliber North Dakota, LLC for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the in-service date of the Caliber North Dakota, LLC facilities (the date on which the Caliber North Dakota, LLC central facility has been substantially completed and has commenced commercial operation - which is estimated to occur in October, 2013). For the six months ended July 31, 2013, Caliber North Dakota, LLC had $6.8 million of revenue ($6.5 million from TUSA) mainly comprised of fresh water and water disposal revenues as well as well connect fees. See Note 5 — Equity Investment of the condensed consolidated financial statements for further discussion.

Except for the Caliber North Dakota, LLC agreement discussed in the preceding paragraph, the Company had no reportable related party transactions during the three or six months ended July 31, 2013.

15. Subsequent Events

We have evaluated subsequent events and are not aware of any significant events that occurred subsequent to July 31, 2013 but prior to the filing with the SEC of this Form 10-Q that would have a material impact on our consolidated financial statements, except for those items listed below.

Private Placement

On August 6, 2013, the Company entered into a Stock Purchase Agreement (the “Stock Purchase Agreement”) with TIAA Oil and Gas Investments, LLC (“TOGI”). As permitted under the terms of the Stock Purchase Agreement, on August 28, 2013, TOGI assigned its rights and obligations to purchase 11,350,000 shares of the Company’s common stock, par value $0.00001 per share (“Common Stock”), under the Stock Purchase Agreement to ActOil Bakken, LLC (the “Purchaser”), which is an affiliate of TOGI.

Pursuant to the Stock Purchase Agreement, on August 28, 2013, the Company issued to the Purchaser 11,350,000 shares of common stock at $7.20 per share for gross proceeds to the Company of $81.7 million ($80.9 million net after transaction costs) and concurrently entered into a Rights Agreement (the “Rights Agreement”) with the Purchaser. Under the Rights Agreement, the Purchaser is entitled to certain demand registration rights and unlimited piggyback registration rights under the Securities Act of 1933, as amended. The Stock Purchase Agreement restricts the Purchaser from selling, pledging or otherwise disposing of the Company’s common stock acquired by the Purchaser for a period of 180 days after August 28, 2013, without the Company’s consent, which covers the period through and including February 24, 2014.

The Rights Agreement also grants the Purchaser the preemptive right to purchase its pro rata share on a fully diluted basis of any future equity offerings by the Company until such time as the Purchaser and its affiliates cease to hold at least the lesser of (i) 50% of the shares of common stock acquired by the Purchaser pursuant to the Stock Purchase Agreement and (ii) 10% of the Company’s then-outstanding shares of the common stock (a “Termination Event”). Such rights are subject to customary exclusions such as securities offered in connection with employee benefits plans, business combinations, pro-rata distributions, and stockholder rights plans.

Pursuant to the Rights Agreement, on the date on which the aggregate amount paid to the Company by the Purchaser and certain of its affiliates as consideration for shares of common stock exceeds $150.0 million, the Purchaser will be entitled to designate one director to serve on the Board of Directors of the Company until such time as a Termination Event occurs.

The Rights Agreement further provides that, for so long as the Purchaser holds (i) 50% of the common stock purchased by the Purchaser under the Stock Purchase Agreement, and (ii) 10% of the then issued and outstanding

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common stock, without the prior written consent of the Purchaser, the Company and its subsidiaries shall not incur any indebtedness unless the Consolidated Leverage Ratio (as defined in the Rights Agreement) does not exceed 5.0 to 1.0 (provided that debt outstanding under the Company’s senior credit facility and its 5% convertible note issued in July 2012 are excluded from such calculation).

Public Equity Offering

On August 8, 2013, Triangle Petroleum Corporation entered into an underwriting agreement (the “Underwriting Agreement”) with Wells Fargo Securities, LLC, as representative of the several underwriters named therein (collectively, the “Underwriters”), pursuant to which the Company agreed to issue and sell to the Underwriters in a firm commitment offering (the “Offering”) 15,000,000 shares of Common Stock at a price to the public of $6.25 per share. Pursuant to the Underwriting Agreement, the Company also granted to the Underwriters a 30-day over-allotment option to purchase up to an additional 2,250,000 shares of Common Stock at the same public offering price. The Offering was made pursuant to the Company’s effective registration statement on Form S-3 (Registration Statement No. 333-171958) previously filed with the Securities and Exchange Commission on January 31, 2011. The Offering closed on August 14, 2013.

The gross proceeds to the Company from the Offering were approximately $93.8 million ($88.4 million net, after deducting underwriting discounts and commissions and other estimated offering expenses payable by the Company but before consideration of the possible underwriter over-allotment noted above). The Company intends to use the net proceeds from the Offering and from any exercise by the Underwriters of their option to purchase additional shares of Common Stock to fund its drilling and development program, to pursue select acquisition opportunities and for other general corporate purposes, including working capital.

The Underwriting Agreement contains customary representations, warranties and agreements by the Company, customary conditions to closing, customary indemnification obligations of the Company and the Underwriters, including for liabilities under the Securities Act of 1933, as amended, other obligations of the parties and termination provisions. The representations, warranties and covenants contained in the Underwriting Agreement were made only for purposes of such agreement and as of specific dates, were solely for the benefit of the parties to such agreement, and may be subject to limitations agreed upon by the contracting parties, including being qualified by confidential disclosures exchanged between the parties in connection with the execution of the Underwriting Agreement.

On September 6, 2013, the Underwriters exercised their 30-day over-allotment option to purchase an additional 2,250,000 shares of the Company’s common stock at the Offering price of $6.25 per share. The over-allotment option closing will occur on September 11, 2013. The gross proceeds from the exercise of the over-allotment option will total approximately $14.1 million, and the net proceeds, after underwriting discounts and commissions, received by the Company will total approximately $13.4 million.

Acquisition of Oil and Gas Assets

August 28, 2013 Acquisition and Acreage Trade

On August 28, 2013, pursuant to the terms of a definitive Purchase and Sale Agreement entered into on August 5, 2013, TUSA acquired an unaffiliated oil and gas company’s interests in approximately 5,600 net acres of Williston Basin leaseholds, and related producing properties located in McKenzie County, North Dakota, along with various other related rights, permits, contracts, equipment and other assets. The seller received aggregate consideration of approximately $83.8 million in cash. The effective date for the acquisition was July 1, 2013, with purchase price adjustments calculated as of the closing date on August 28, 2013. The acquisition provided strategic additions adjacent to the Company’s core project area. The acquisition contributed no revenue to the Company for the three and six months ended July 31, 2013 and 2012. Transaction costs related to the acquisition incurred through July 31, 2013 were approximately $0.06 million and are recorded in the statement of operations within the general and administrative expenses line item. The Company estimates an additional $0.1 million of transaction costs will be incurred in the second half of fiscal 2014.

The acquisition will be accounted for using the acquisition method under ASC Topic 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of

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August 28, 2013. Management has not had the opportunity to complete its assessment of the fair values of assets acquired and liabilities assumed. Accordingly, the allocation will change as additional information becomes available and is assessed by the Company, and the impact of such changes may be material. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed (in thousands):

Preliminary purchase price:
Consideration given
Cash			$	83,805
Total consideration given			$	83,805

Preliminary fair value allocation of purchase price:
Accounts receivable			$	5,174
Oil and natural gas properties:
Proved properties	$	30,927
Unproved properties	$	49,817
Total oil and natural gas properties			80,744
Accounts payable			(1,981		)
Asset retirement obligation assumed			(132		)
Fair value of net assets acquired			$	83,805

Also on August 28, 2013, the Company closed a trade agreement with the same unaffiliated oil and gas company (the “Trade Agreement”) to exchange certain of Triangle’s oil and gas leasehold interests in the seller’s operated units in return for approximately 600 net acres of leasehold interests held by the seller in units then operated by the Company. The effective date of the Trade Agreement was also July 1, 2013.

Pro Forma Financial Information

The following unaudited pro forma financial information represents the combined results for the Company and the above noted properties acquired and exchanged for the three and six months ended July 31, 2013 and 2012 as if the acquisition and exchange had occurred on February 1, 2012. The seller’s fiscal year ended on December 31, 2012. The pro forma results below include the operating revenues and direct operating expenses for the acquired and exchanged properties for the three and six months ended June 30, 2013 and 2012. As the seller’s fiscal year is within 93 days of the Company’s fiscal year, no adjustment for the differing periods has been considered. The Company’s historical operating results for the properties conveyed in the Exchange Agreement were insignificant for the three and six months ended July 31, 2013, and therefore no adjustment was provided to remove their activity from the pro forma financial information presented below.

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For purposes of the pro forma information it was assumed that the net proceeds generated from the issuance of the Company’s common stock pursuant to the Stock Purchase Agreement were utilized to fund the August 28, 2013 acquisition and that such issuance occurred on February 1, 2012. The pro forma information includes the effects of adjustments for depreciation, amortization and accretion expense of $2.3 million and $4.2 million for the three and six months ended July 31, 2013, respectively, as compared to $0.4 million and $0.01 million for the three and six months ended July 31, 2012, respectively. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed, or the common shares had been issued, as of the beginning of the period, nor are they necessarily indicative of future results.

	Three Months Ended				Six Months Ended
	July 31,				July 31,
(in thousands, except per share data)	2013		2012		2013		2012
Operating revenues	$	56,939	$	12,297	$	97,603	$	17,966
Net income (loss)	$	7,978	$	151	$	15,876	$	(2,113	)

Earnings (loss) per common share:
Basic	$	0.12	$	—	$	0.24	$	(0.04	)
Diluted	$	0.12	$	—	$	0.24	$	(0.04	)

Weighted average common shares outstanding:
Basic	67,801		55,615		65,911		55,450
Diluted	68,362		55,615		66,438		55,450

August 2, 2013 Acquisition

On August 2, 2013, TUSA entered into and closed agreements with an unaffiliated oil and gas company to purchase 1,241 net acres and various other related rights, permits, contracts, equipment and other assets for an (i) aggregate cash consideration equal to approximately $13.5 million and (ii) an aggregate of 325,000 shares of the Company’s common stock. The Company has valued the 325,000 shares of common stock issued at $2.4 million based on the closing price of the Company’s common stock of $7.50 per share on the issue date. The effective date for the acquisition was October 1, 2011, with purchase price adjustments calculated as of the closing date on August 2, 2013. The acquisition contributed no revenue to the Company for the three and six month periods ended July 31, 2013 and 2012.

The acquisition will be accounted for using the acquisition method under ASC Topic 805, Business Combinations, which require the acquired assets and liabilities to be recorded at fair values as of the acquisition date of August 2, 2013. Management has not had the opportunity to complete the assessment of the fair values of assets acquired and liabilities assumed.

Other Acquisitions

Subsequent to July 31, 2013, TUSA entered into various agreements with unrelated parties to purchase a combined total of approximately 1,065 acres and various other related rights, permits, contracts, equipment and other assets for aggregate cash consideration of $6.1 million. These acquisitions will be accounted for using the acquisition method under ASC Topic 805, Business Combinations, which require the acquired assets and liabilities to be recorded at fair values as of the acquisition date. Management has not had the opportunity to complete the assessment of the fair values of assets acquired and liabilities assumed.

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Drilling Rig Commitment

On August 5, 2013 the Company entered into a single drilling rig contract. The contract is effective August 5, 2013 and expires on February 4, 2015. In the event of early termination of the contract, the Company would be obligated to pay an aggregate amount of approximately $16.4 million as required under the terms of the contract.

16. Significant Changes in Proved Oil and Natural Gas Reserves

Our proved oil and natural gas reserves at July 31, 2013 significantly increased from our proved oil and natural gas reserves at January 31, 2013. Our proved reserves are in the Bakken or Three Forks formations in the North Dakota counties of McKenzie, Williams or Dunn.

The reserve estimates presented below (expressed in thousands of barrels of oil (“MBbls”), millions of cubic feet of natural gas (“MMcf”) and thousands of barrels of oil equivalent (“MBoe”)) were made in accordance with oil and natural gas reserve estimation and disclosure authoritative accounting guidance issued by the FASB effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC’s “Modernization of Oil and Gas Reporting” rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.

The reserve estimates at July 31, 2013 were estimated by our in-house senior reservoir engineer, who has been a Registered Professional Engineer in Colorado since 1984 and has over 30 years’ experience as a petroleum engineer. Our reserve estimate at January 31, 2013, was audited by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. Proved reserves are the estimated quantities of oil and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. For the purposes of preparing the proved reserves presented below, such average pricing was $87.36 per barrel of oil and $5.56 per mcf of natural gas for the reserves presented as of July 31, 2013. For the reserves presented as of January 31, 2013, such average pricing was $84.76 per barrel of oil and $5.23 per mcf of natural gas. The reserves presented below do not reflect any of the acquisitions closed subsequent to July 31, 2013.

	% of				July 31,	January 31,
	Reserves		Oil	Gas	2013	2013	%
Reserve Category	(Mboe)		(MBbls)	(MMcf)	MBoe	MBoe	Change
July 31, 2013 Assets
Proved Developed	45	%	8,413	8,665	9,857	5,969	65	%
Proved Undeveloped	55	%	10,296	11,567	12,223	8,668	41	%
Total Proved	100	%	18,709	20,232	22,080	14,637	51	%

The primary reason for the increases in proved reserves is the drilling and completion of wells in the first six months of fiscal year 2014, whereby our net interest in producing wells increased 78% from 16 net wells at January 31, 2013 to 28.4 net wells at July 31, 2013, and our net interest in proved undeveloped locations increased 36% from 19.8 net future development wells at January 31, 2013 to 27 net future development wells at July 31, 2013.

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

Forward-Looking Statements

We or our representatives may make forward-looking statements, oral or written, including statements in this Quarterly Report on Form 10-Q, press releases and filings with the Securities and Exchange Commission (“SEC”), regarding, among other things, 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 Fiscal 2013 Form 10-K and in this Quarterly Report on Form 10-Q 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.

Overview

Triangle Petroleum Corporation (“Triangle” or the “Company” or “we” or “our”) is a growth-oriented, independent energy company focused on the exploration, development and production of unconventional shale oil and natural gas resources in the United States. Our oil and natural gas reserves and operations are primarily concentrated in the Bakken Shale and Three Forks formations of the Williston Basin in North Dakota and Montana. As of July 31, 2013, we held leasehold interests in approximately 86,000 net acres in the Williston Basin, approximately 36,000 of which are in our core focus area primarily in McKenzie and Williams Counties, North Dakota, which we refer to as our “Core Acreage.” Our Core Acreage has a high oil saturation, is slightly over-pressured, and has the potential for multiple benches. The remaining 50,000 net acres comprise our “Station Prospect” located in Roosevelt and Station Counties, Montana.

Our primary strategy is to grow our production volumes through the efficient development of our operated Bakken Shale and Three Forks drilling inventory. We use pad drilling, which increases efficiencies while controlling costs and minimizing environmental impact. We also use advanced completion, collection and production techniques that optimize reservoir production while reducing costs. We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation (“TUSA”). Our estimated proved oil and gas reserves as of July 31, 2013 totaled 22,080 Mboe.

Our daily production for the fiscal quarter ended July 31, 2013 averaged approximately 4,287 Boepd of which 2,799 Boepd is net to our interests in wells we operate (“operated wells”) and 1,488 Boepd is from wells operated by third-parties (“non-operated wells”). All production in fiscal year 2014 is from wells in North Dakota, primarily from the Bakken Shale formation and, to a lesser extent, the Three Forks formation.

In an effort to better control key operations, reduce costs, and retain supply chain value in the Williston Basin, which we view as a resource-constrained and cost-heavy basin, we formed RockPile Energy Services, LLC, or RockPile, our wholly-owned oilfield services subsidiary, and entered into a 30% owned joint venture arrangement with First Reserve Energy Infrastructure Fund, or FREIF, to form Caliber Midstream Partners LP, or Caliber. RockPile provides pressure pumping services, which we believe lowers our realized well completion costs and affords us greater control over completion schedules, quality control and pay cycles. Caliber currently provides produced water transportation and crude oil and natural gas gathering services and is expected to provide natural gas processing services during the third quarter of fiscal year 2014. We expect that Caliber will reduce the cost and environmental impacts of trucking oil and water and

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reduce or eliminate the emissions generated by the flaring of produced natural gas. In addition to providing services to TUSA, each of RockPile and Caliber are focused on growing their respective businesses through securing independent, third-party contracts.

Summary of operating and financial results for six months ended July 31, 2013:

· Production volumes totaled 635,929 Boe for the six months ended July 31, 2013. This is an increase of 280% from 167,360 Boe for the six months ended July 31, 2012.

· Oil and natural gas sales were $55.7 million compared to $12.7 million for the six months ended July 31, 2012.

· Our average realized oil price increased to $90.11 per barrel compared to $80.85 per barrel in the first six months of fiscal year 2013.

· Proved reserves were an estimated 22,080 Mboe at July 31, 2013 compared to 14,637 Mboe at January 31, 2013.

· Net income of $12.0 million for the six months ended July 31, 2013 compared to a net loss of $4.5 million for the six months ended July 31, 2012.

· Cash flow provided by operating activities was $31.4 million for the six months ended July 31, 2013 compared to cash provided by operating activities of $4.0 million for the six months ended July 31, 2012.

· TUSA’s credit facility was syndicated with an increased maximum credit availability of $500.0 million and a borrowing base of $165.0 million at July 31, 2013.

· Drilled and completed 13 gross (9.24 net) operated wells during the first six months of fiscal year 2014.

Recent Events

Acquisition of Oil and Gas Assets

On August 28, 2013, TUSA acquired from an unaffiliated oil and gas company certain oil and gas leaseholds located in McKenzie County, North Dakota comprising approximately 6,200 net acres, and various other related rights, permits, contracts, equipment and other assets for total consideration of $83.8 million. The effective date for the Acquisition was July 1, 2013. See Note 15 — Subsequent Events under Item 1 of this Quarterly Report for further discussion.

In addition to the above acquisition, subsequent to July 31, 2013, TUSA entered into various agreements with unrelated parties to acquire an aggregate of approximately 2,306 net acres for aggregate consideration of approximately $19.6 million plus 325,000 shares of our common stock. See Note 15 — Subsequent Events under Item 1 of this Quarterly Report for further discussion.

Production from the above acquisitions averaged 1,150 Boe per day, based on produced volumes in June 2013. The acquired leasehold includes seven to nine controlled drilling spacing units and is largely held by production. The interests are contiguous to existing acreage in our core area of operations and are located adjacent to or within close proximity to the operations of Caliber, which we expect will provide synergies. The acquisitions increase (i) our total core acreage to approximately 45,000 net acres, and (ii) net production to approximately 5,650 Boe per day, assuming our estimated 21-day sales volumes, as of July 31, 2013. Additionally, the acquired leasehold, combined with successful down-spacing tests for Triangle and other operators, increases our inventory from six years to eight to twelve years.

Public Equity Offering

On August 8, 2013, we entered into an underwriting agreement (the “Underwriting Agreement”) with Wells Fargo Securities, LLC, as representative of the several underwriters named therein (collectively, the “Underwriters”), pursuant to which we agreed to issue and sell to the Underwriters in a firm commitment offering (the “Offering”) 15,000,000 shares of the Company’s common stock, par value $0.00001 per share at a price to the public of $6.25 per share. Pursuant to the Underwriting Agreement, the Company also granted the Underwriters a 30-day over-allotment option to purchase up to an additional 2,250,000 shares of common stock at the same public offering price. The Offering was made pursuant to the Company’s effective registration statement on Form S-3 (Registration Statement No. 333-171958) previously filed with the Securities and Exchange Commission on January 31, 2011. The Offering closed on August 14, 2013. The Underwriters exercised their over-allotment option on September 6, 2013, which will close on September 11, 2013. The total net proceeds to the Company from the Offering and the exercise of the over-allotment option will be approximately

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$101.8 million, after deducting underwriting discounts and commissions and other estimated offering expenses payable by the Company. See Note 15 — Subsequent Events under Item 1 of this Quarterly Report for further discussion of this transaction.

Private Placement

On August 28, 2013, the Company issued to ActOil Bakken, LLC (“ActOil”), an affiliate of Teachers Insurance and Annuity Association of America, 11,350,000 shares of common stock at $7.20 per share for gross proceeds of $81.7 million and concurrently entered into a Rights Agreement with the purchaser. See Note 15 — Subsequent Events under item 1 of this Quarterly Report for further discussion of this transaction.

Amendment to Senior Credit Facility and Increase in Borrowing Base

On July 31, 2013, TUSA entered into a first amendment to its Amended and Restated Credit Agreement to, among other things, increase its hedging capacity and make the necessary amendments to enable TUSA to enter into a second lien credit facility. Concurrent with the amendment, the borrowing base under the senior credit facility was increased to $165.0 million.

Reserve Update

As of July 31, 2013, we have estimated proved reserves of 18.7 million barrels of oil and 20.2 million cubic feet of natural gas, or 22.1 million barrels of oil equivalent (MMboe). Pro forma for the acquisitions of oil and gas assets after July 31, 2013, we have estimated proved reserves of 24.3 million barrels of oil and 24.1 million cubic feet of natural gas, or 28.4 million barrels of oil equivalent (MMboe). Our reserve quantities are comprised of 85% crude oil and 15% natural gas. The July 31, 2013 proved reserves (prior to the addition of reserves associated with the oil and gas assets acquired after July 31, 2013) reflect a 51% increase over the January 31, 2013 proved reserves of 14,637 MMboe. Our proved oil and gas reserves at July 31, 2013 and the reserve estimates for the acquisitions of oil and gas assets after July 31, 2013 were estimated by our in-house senior reservoir engineer, who has been a Registered Professional Engineer in Colorado since 1984 and has over 30 years’ experience as a petroleum engineer. The following table summarizes our actual and pro forma reserves as of July 31, 2013:

	% of				July 31,	January 31,
	Reserves		Oil	Gas	2013	2013	%
Reserve Category	(Mboe)		(MBbls)	(MMcf)	MBoe	MBoe	Change
July 31, 2013 Assets
Proved Developed	45	%	8,413	8,665	9,857	5,969	65	%
Proved Undeveloped	55	%	10,296	11,567	12,223	8,668	41	%
Total Proved	100	%	18,709	20,232	22,080	14,637	51	%

Pro Forma for Acquisitions after July 31, 2013
Proved Developed	42	%	10,291	9,509	11,876	5,969	99	%
Proved Undeveloped	58	%	14,051	14,596	16,484	8,668	90	%
Total Proved - Pro Forma	100	%	24,342	24,105	28,360	14,637	94	%

In estimating the proved reserves presented above, we used the Securities and Exchange Commission’s definition of proved reserves. Projected future cash flows were based on economic and operating conditions as of July 31, 2013 except that future oil and natural gas prices used in the projections reflected an unweighted arithmetic average of the first-day-of-the-month price for each month during the 12-month period prior to that date. For the purposes of preparing the Company’s actual proved reserves at July 31, 2013, such average pricing was $87.36 per barrel of oil and $5.56 per mcf of natural gas, and at January 31, 2013 was $84.76 per barrel of oil and $5.23 per Mcf of natural gas. For the reserves acquired after July 31, 2013, added to our actual reserves to arrive at the pro forma presentation presented above, such additional proved reserves were calculated using a price of $86.33 per barrel of oil and $4.51 per mcf of natural gas,

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which represented the unweighted average of the first-day-of-the-month prices for each of the twelve months ending June 30, 2013, the most recent twelve-month period prior to the July 1, 2013 effective date for such acquisitions.

Volumes of reserves that will be actually recovered and cash flows that will be actually received from actual production may differ significantly from the proved reserve estimates and the related projected cash flows, respectively. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any proved reserve estimate is a function of the quality of available data, of engineering and geological interpretation and judgment, and of the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, proved reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Drilling and Completions

The following tables summarize the wells spud and completed during the three and six months ended July 31, 2013:

	For the Three Months Ended July 31, 2013
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	9	5.7	8	5.2
Non-operated wells	18	1.1	22	1.4
	27	6.8	30	6.6

	For the Six Months Ended July 31, 2013
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	18	11.9	13	10.2
Non-operated wells	44	2.8	52	3.4
	62	14.7	65	13.6

Properties, Plan of Operations and Capital Expenditures

We own operated and non-operated leasehold positions in the Williston Basin. As of July 31, 2013, we have completed a total of 29 (18.82 net) operated wells since entering the Williston Basin. During fiscal year 2014, we anticipate drilling approximately 33 (18.94 net) operated wells and completing approximately 30 (18.46 net) operated wells in North Dakota or eastern Montana. Of the 30 wells expected to be completed in fiscal year 2014, we have completed 13 gross wells and had an additional 5 gross wells in progress as of July 31, 2013. Twenty-seven of the wells are planned to be in the Bakken Shale and three are planned for the Three Forks formation. We also have economic interests in approximately 227 (10.84 net) non-operated wells.

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We are currently running a three-rig drilling program, which we anticipate continuing for the remainder of fiscal year 2014. The focus of our drilling program is on our Core Acreage in McKenzie and Williams Counties.

Our oil and natural gas property expenditures are summarized in the following tables for the periods indicated (in thousands):

	Six Months Ended July 31,
	2013		2012
Leasehold acquisitions	$	6,200	$	10,978
Drilling and Completion
Operated	102,900		44,862
Non-operated	25,381		11,045
Facilities and Infrastructure	2,424		—
	$	136,905	$	66,885

U.S. Leaseholds

As of July 31, 2013, we had approximately 2,300 lease agreements representing approximately 211,000 gross and 86,000 net acres in the Williston Basin of North Dakota and Montana. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
North Dakota	76,623	19,794	49,955	11,950	126,578	31,744
Montana	2,096	573	82,286	54,114	84,382	54,687
Total Williston Basin	78,719	20,367	132,241	66,064	210,960	86,431

We are subject to lease expirations if we or the operator of our non-operated acreage do not commence the development of operations within the agreed terms of our leases. All of our leases for undeveloped acreage will expire at the end of their respective primary terms except for leases where we either (i) make extension payment(s) under the lease terms, (ii) renew the existing lease, (iii) establish commercial production paying royalties to the lessor or (iv) exercise some other “savings clause” in the respective lease. We expect to establish production from most of our acreage prior to expiration of the applicable lease terms. However, there can be no guarantee we will do so.

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 to expire in 2019, but can be extended pending agreement of further development plans with the Nova Scotia regulators. As of January 31, 2012, we fully impaired and expensed the carrying value of our oil and natural gas leases in the Maritimes Basin.

Results of Operations for the Three Months Ended July 31, 2013 Compared to the Three Months Ended July 31, 2012

For the fiscal quarter ended July 31, 2013, we recorded net income attributable to common stockholders of $6.8 million ($0.12 per share of common stock, basic and diluted) as compared to a net loss attributable to common stockholders of $1.0 million ($0.02 per share of common stock, basic and diluted) for the fiscal quarter ended July 31, 2012. The following discussion highlights the primary drivers of the results within the two periods.

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Oil and Natural Gas Operations

The following table summarizes production volumes, average realized prices, oil and gas revenues and operating expenses for the three months ended July 31, 2013 and 2012:

					Change
	Three Months Ended July 31,				Increase			% Increase
	2013		2012		(Decrease)			(Decrease)
Production volumes:
Crude oil (Bbls)	378,107		93,730		284,377			303	%
Natural gas (Mcf)	82,425		60,226		22,199			37	%
Natural gas liquids (Gallons)	107,528		37,460		70,068			187	%
Total barrels of oil equivalent (Boe)	394,405		104,660		289,745			277	%

Average realized prices:
Crude oil ($ per Bbl)	$	90.37	$	77.01	$	13.37		17	%
Natural gas ($ per Mcf)	$	4.60	$	4.20	$	0.40		9	%
Natural gas liquids ($ per gallon)	$	0.83	$	0.97	$	(0.14	)	(14	)%
Total average realized price ($ per Boe)	$	87.83	$	71.73	$	16.10		22	%

Oil and natural gas revenues (in thousands):
Crude Oil	$	34,171	$	7,218	$	26,953		373	%
Natural gas	379		253		126			50	%
Natural gas liquids	89		36		53			146	%
Total oil and natural gas revenues	$	34,639	$	7,507	$	27,132		361	%

Operating expenses (in thousands):
Production taxes	$	3,919	$	837	$	3,082		368	%
Other lease operating expenses	2,830		220		2,610			1186	%
Gathering, transportation and processing	69		10		59			590	%
Oil and natural gas amortization expense	10,100		2,928		7,172			245	%
Accretion of asset retirement obligations	9		3		6			208	%
Total operating expenses	$	16,927	$	3,998	$	12,929		323	%

Operating expenses per boe:
Production taxes	$	9.94	$	8.00	$	1.94		24	%
Other lease operating expense	$	7.18	$	2.10	$	5.07		241	%
Gathering, transportation and processing	$	0.17	$	0.10	$	0.08		83	%
Oil and natural gas amortization expense	$	25.61	$	27.98	$	(2.37	)	(8	)%

Oil and Natural Gas Revenues

Revenues from oil and natural gas production for the three months ended July 31, 2013 increased 361% to $34.6 million from $7.5 million for the same period in 2012 primarily due to the significant increase in oil production from new wells (as noted in the Drilling and Completions section of Recent Events above), partially offset by normal production decline. Average realized oil prices increased 17% to $90.37 per barrel from $77.01 per barrel in the same period in 2012. Average realized gas prices increased 9% to $4.60 per Mcf in the second quarter of fiscal year 2014 from $4.20 per Mcf in the same period in 2012.

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Production Taxes

Due primarily to the 361% increase in oil and natural gas revenues for the three months ended July 31, 2013, as compared with the three months ended July 31, 2012, our U.S. production taxes increased approximately 368% to $3.9 million from $0.8 million for the same respective period. With rare exception, North Dakota production tax rates for the past two years were 11.5% of oil revenue and approximately $0.11 per mcf of natural gas. Effective July 1, 2013, the production tax rate for natural gas decreased to $.0833 per mcf.

Lease Operating Expense

Lease operating expense for U.S. operations (“LOE”) increased to $7.18 per Boe for the three months ended July 31, 2013 from $2.10 per Boe for the three months ended July 31, 2012. The increase is primarily the result of increased lease operating expenses associated with our operated properties. LOE for our operated properties was $8.22 per Boe for the three months ended July 31, 2013. This amount includes approximately $2.94 per Boe for water disposal costs. LOE for non-operated properties also increased from $3.37 per Boe for the three months ended July 31, 2012 to $5.22 per Boe for the three months ended July 31, 2013. Our second quarter of fiscal year 2014 reported lease operating expense per boe included a $0.61 per Boe benefit due to an over accrual of estimated lease operating expense in the first quarter of fiscal year 2014.

Gathering, Transportation and Processing

Gathering, transportation and processing (“GTP”) expenses increased to $0.17 per Boe for the three months ended July 31, 2013 from $0.10 per Boe for the three months ended July 31, 2012. Currently, all GTP costs are associated with non-operated wells and are primarily for the gathering and transportation of oil and natural gas. Going forward we expect GTP costs to increase as natural gas gathering, transportation and processing infrastructure becomes available for operated wells during the second half of fiscal year 2014.

Oil and Natural Gas Amortization

Oil and natural gas amortization expense increased 245% to $10.1 million for the three months ended July 31, 2013 from $2.9 million for the three months ended July 31, 2012. The increase is primarily related to a 277% increase in production in the second quarter of fiscal year 2014 as compared to the second quarter of fiscal year 2013.

Pressure Pumping Services Gross Profit

RockPile commenced operations in July 2012. We formed RockPile with strategic objectives to have both greater control over our largest cost center as well as to provide locally-sourced, high-quality completion services to Triangle and other operators in the Williston Basin. From formation through July 31, 2013, RockPile has been focused on procuring new pressure pumping and complementary equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, establishing third-party customers in the Williston Basin, and securing multiple credit facilities. RockPile’s results of operations are affected by a number of variables including drilling and stimulation activity in the Williston Basin, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers.

For the three months ended July 31, 2013, RockPile performed hydraulic fracturing and complementary services for Triangle and three distinct third-party customers. In July 2013, RockPile’s capacity was increased by placing a second equipment spread into service. This work resulted in 18 total well completions: eight for Triangle and ten for third-parties. Seven Triangle wells were completed using plug-and-perf applications, and one Triangle well was completed using a combination of plug-and-perf and sliding sleeve applications. Two third-party wells were completed using plug-and-perf applications and eight third-party wells were completed using a sliding sleeve application. RockPile revenue is comprised of service revenue (what we charge for equipment usage and labor) and materials revenue (what we charge for chemicals and proppant). Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), logistic expenses, insurance, repairs and maintenance and safety costs. Cost of goods sold as a percentage of revenue will vary based upon equipment utilization.

We recognized $2.4 million of gross profit from pressure pumping services for the three months ended July 31, 2013 after elimination of $9.9 million in intercompany gross profit. See Note 3 — Segment Reporting under Item 1 of this

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Quarterly Report. Below is a summary of the RockPile contribution to our consolidated results for the three months ended July 31, 2013, after eliminations (in thousands):

	RockPile		Eliminations			Consolidated
Revenues
Pressure pumping services	$	44,120	$	(28,530	)	$	15,590
Other	165		—			165
Total revenues	44,285		(28,530		)	15,755
Cost of Sales
Depreciation and amortization	1,600		(928		)	672
Pressure pumping costs	30,370		(17,678		)	12,692
Total Cost of Sales	31,970		(18,606		)	13,364
Gross profit	$	12,315	$	(9,924	)	$	2,391

General and Administrative Expenses

The following table summarizes general and administrative expenses for the three months ended July 31, 2013 and July 31, 2012, respectively (in thousands):

	Exploration and Production		Pressure Pumping and other Services		Corporate		Consolidated Total
For the three months ended July 31, 2013
Stock-based compensation	$	247	$	99	$	1,092	$	1,438
Salaries, benefits and other general and administrative	1,569		2,446		1,427		5,442
Total	$	1,816	$	2,545	$	2,519	$	6,880
Excluded costs*	$	770	$	—	$	933	$	1,703

For the three months ended July 31, 2012
Stock-based compensation	$	704	$	—	$	729	$	1,433
Salaries, benefits and other general and administrative	1,174		2,277		626		4,077
Total	$	1,878	$	2,277	$	1,355	$	5,510
Excluded costs*	$	408	$	—	$	—	$	408

*Excluded costs are (i) those personnel costs which are capitalized under the full cost accounting method as direct internal costs of acquisition, exploration and development of oil and gas properties, (ii) costs equal to overhead reimbursements charged by TUSA as well operator to third parties participating in TUSA-operated wells, and (iii) general and administrative expenses recovered by corporate charges to related entities for various general and administrative services.

Total general and administrative expense increased $1.4 million to $6.9 million at July 31, 2013 compared to $5.5 million at July 31, 2012. The increase in corporate general and administrative is primarily a result of increased compensation and benefit costs for personnel as the corporate headcount increased due to the growth of the business. The increase in general and administrative expenses at our Pressure Pumping Services segment is primarily attributable to increased compensation and benefit costs for personnel in RockPile’s headquarters and field offices as RockPile built its team and commenced operations in July 2012.

Loss from Derivative Activities

We have entered into commodity derivative instruments, primarily utilizing costless collars and single-day puts to reduce the effect of price changes on a portion of our future oil production. Our commodity derivative instruments are

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Oil and Natural Gas Operations

The following table summarizes production volumes, average realized prices, oil and gas revenues and operating expenses for the six months ended July 31, 2013 and 2012:

					Change
	Six Months Ended July 31,				Increase			% Increase
	2013		2012		(Decrease)			(Decrease)
Production volumes:
Crude oil (Bbls)	610,360		149,852		460,508			307	%
Natural gas (Mcf)	129,876		95,016		34,860			37	%
Natural gas liquids (Gallons)	164,777		70,218		94,559			135	%
Total barrels of oil equivalent (Boe)	635,929		167,360		468,569			280	%

Average realized prices:
Crude oil ($ per Bbl)	$	90.11	$	80.85	$	9.26		11	%
Natural gas ($ per Mcf)	$	4.31	$	5.16	$	(0.85	)	(16	)%
Natural gas liquids ($ per Gallon)	$	0.83	$	1.05	$	(0.22	)	(21	)%
Total average realized price ($ per Boe)	$	87.59	$	75.76	$	11.82		16	%

Oil and natural gas revenues (in thousands):
Crude Oil	$	55,002	$	12,116	$	42,886		354	%
Natural gas	560		490		70			14	%
Natural gas liquids	137		74		63			85	%
Total oil and natural gas revenues	$	55,699	$	12,680	$	43,019		339	%

Operating expenses (in thousands):
Production taxes	$	6,363	$	1,429	$	4,934		345	%
Other lease operating expenses	5,046		440		4,606			1047	%
Gathering, transportation and processing	106		43		63			147	%
Oil and natural gas amortization expense	16,707		5,020		11,687			233	%
Accretion of asset retirement obligations	17		5		12			239	%
Total operating expenses	$	28,239	$	6,937	$	21,302		307	%

Operating expenses per boe:
Production taxes	$	10.01	$	8.54	$	1.47		17	%
Other lease operating expense	$	7.93	$	2.63	$	5.31		202	%
Gathering, transportation and processing	$	0.17	$	0.26	$	(0.09	)	(35	)%
Oil and natural gas amortization expense	$	26.27	$	30.00	$	(3.72	)	(12	)%

Oil and Natural Gas Revenues

Revenues from oil and natural gas production for the six months ended July 31, 2013 increased 339% to $55.7 million from $12.7 million for the same period in 2012 primarily due to the significant increase in oil production from new wells (as noted in the Drilling and Completions section of Recent Events above), partially offset by normal production declines. Average realized oil prices increased 11% to $90.11 per barrel from $80.85 per barrel in the same

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Below is a summary of the RockPile contribution to our consolidated results for the six months ended July 31, 2013 after eliminations (in thousands):

	RockPile		Eliminations			Consolidated
Revenues
Pressure pumping services	$	70,889	$	(42,179	)	$	28,710
Other	279		—			279
Total revenues	71,168		(42,179		)	28,989
Cost of Sales
Depreciation and amortization	2,839		(1,435		)	1,404
Pressure pumping costs	49,491		(25,613		)	23,878
Total Cost of Sales	52,330		(27,048		)	25,282
Gross profit	$	18,838	$	(15,131	)	$	3,707

General and Administrative Expenses

The following table summarizes general and administrative expenses for the six months ended July 31, 2013 and July 31, 2012, respectively (in thousands):

	Exploration and Production		Pressure Pumping and other Services		Corporate		Consolidated Total
For the six months ended July 31, 2013
Stock-based compensation	$	569	$	310	$	2,154	$	3,033
Salaries, benefits and other general and administrative	3,033		4,425		2,893		10,351
Total	$	3,602	$	4,735	$	5,047	$	13,384
Excluded costs*	$	1,875	$	—	$	1,853	$	3,728

For the six months ended July 31, 2012
Stock-based compensation	$	1,318	$	—	$	1,480	$	2,798
Salaries, benefits and other general and administrative	2,365		3,875		1,761		8,001
Total	$	3,683	$	3,875	$	3,241	$	10,799
Excluded costs*	$	794	$	—	$	—	$	794

Total general and administrative expense increased $2.6 million to $13.4 million for the six months ended July 31, 2013 compared to $10.8 million for the six months ended July 31, 2012. The increase in corporate general and administrative is primarily a result of increased compensation and benefit costs for personnel as the corporate headcount increased due to the growth of the business. The increase in general and administrative expenses at our Pressure Pumping Services segment is primarily attributable to increased compensation and benefit costs for personnel in RockPile’s headquarters and field offices as RockPile built its team and commenced operations in July 2012.

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Loss from Derivative Activities

During the six months ended July 31, 2013, we recognized a $1.6 million unrealized loss and a $1.6 million realized loss on our commodity derivative positions due to increases in underlying crude oil prices. For additional discussion, please refer to Note 9 - Commodity Derivative Instruments under Item 1 of this Quarterly Report.

Interest Expense

The $3.4 million in interest expense for the six months ended July 31, 2013 consists of approximately $1.0 million in interest and amortized fees related to the TUSA credit facility and approximately $3.1 million in accrued interest and amortized fees related to our 5% convertible note with NGP. We also incurred approximately $0.4 million in interest expense associated with our RockPile credit facility and notes payable. Of the total $4.5 million in interest expense, $1.0 million was paid in cash. The $4.5 million in interest expense was reduced by approximately $1.1 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. See Note 8 — Notes Payable and Credit Facilities under Item 1 of this Quarterly Report for additional information regarding our credit facilities and convertible note. The Company had minimal interest expense during the six months ended July 31, 2012.

Other Income

During the six months ended July 31, 2013 we realized approximately $1.1 million in income from other activities. This increase was primarily attributable to the increase in value of our holdings in Emerald Oil Inc., which we acquired in the January 9, 2013 sale of oil and gas leases to Emerald. See Note 2 — Basis of Presentation and Significant Accounting Policies — Investment in Marketable Securities under Item 1 of the Quarterly Report.

Liquidity and Capital Resources

Overview

Our liquidity is highly dependent on the commodity prices we receive for the oil and natural gas we produce. Commodity prices are market driven and have been volatile; therefore, we cannot predict future commodity prices. Prices received for production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth.

In the second quarter of fiscal year 2014, our average realized price for oil was $90.37 per barrel, an increase of 17% over the realized price for the same period of fiscal year 2013. Future prices for oil will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors. We manage volatility in commodity prices by maintaining flexibility in our capital investment program. In addition, we periodically hedge a portion of our oil production to mitigate our potential exposure to price declines and the corresponding negative impact on cash flow available for investment.

As of July 31, 2013, we had cash of approximately $49.4 million consisting primarily of cash held in bank accounts, as compared to approximately $33.1 million at January 31, 2013. We also had available borrowing capacity under the TUSA credit facility of $69.0 million as of July 31, 2013. Subsequent to July 31, 2013, we raised net proceeds of $182.7 million from the issuance of 28.6 million shares of our common stock (see Note 15- Subsequent Events under Item 1 in this Quarterly Report for further details) and spent approximately $102.9 million on the purchase of oil and natural gas properties and leasehold acreage.

Capital Requirements Outlook

We are dependent on our anticipated cash flows from operations and the expected borrowing availability under our TUSA credit facility to fund our capital expenditures budget, our obligations under our convertible note and other contractual commitments (see Note 8- Notes Payable and Credit Facilities and Note 11 - Commitments and Contingencies under Item 1 in this Quarterly Report for further details). While we expect such sources of capital to be sufficient for such purposes, there can be no assurance that we will achieve our anticipated future cash flows from operations, that credit will be available under our TUSA credit facility when needed, or that we would be able to

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complete alternative transactions in the capital markets, if needed. Our ability to obtain financing on commercially reasonable terms is dependent on a number of factors, many of which we cannot control, including changes in our credit rating, interest rates, market perceptions of us and the oil and natural gas exploration and production industry and tax burdens due to new tax laws.

If our existing and potential sources of liquidity are not sufficient to satisfy our commitments and to undertake our currently planned expenditures, we have the flexibility to alter our development program. Our operatorship of a majority of our acreage allows us the ability to adjust our drilling schedule in response to changes in commodity prices or the oil field service environment. Further, if we were not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our planned expenditures or restructure our operations (including reducing our rig count and sub-contracting our pressure pumping services agreement, either of which may in certain circumstances result in termination fees depending on the timing and requirements of the underlying agreements), we would be unable to implement our planned exploration and drilling program, and we may be unable to service our debt obligations or satisfy our contractual obligations.

Debt

As of July 31, 2013, we have $242.3 million of debt outstanding. See Note 8 — Notes Payable and Credit Facilities under Item 1 of this Quarterly Report on Form 10-Q for further discussion of debt outstanding.

Working Capital

As part of our cash management strategy, we frequently use available funds to reduce the balance on our TUSA credit facility. However, due to certain restrictive covenants contained in our TUSA credit facility regarding our ability to dividend or otherwise transfer funds from TUSA to Triangle, we seek to maintain sufficient liquidity at Triangle to manage foreseeable and unforeseeable consolidated cash requirements. Since our principal source of operating cash flows (proved reserves to be produced in later periods) is not considered working capital, we often have low or negative working capital. Our working capital was approximately $6.2 million as of July 31, 2013, as compared to approximately $3.3 million at January 31, 2013.

Equity Offerings

Historically, we have financed our operations, property acquisitions and other capital investments in part from the proceeds of offerings of our equity and debt securities. We may offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

On August 8, 2013, we entered into an underwriting agreement with Wells Fargo Securities, LLC, as representative of the underwriters (collectively, the “Underwriters”), pursuant to which the Company agreed to issue and sell to the Underwriters in a firm commitment offering (the “Offering”) 15,000,000 shares of the Company’s common stock, par value $0.00001 per share (“Common Stock”), at a price to the public of $6.25 per share. Pursuant to the Underwriting Agreement, the Company also granted the Underwriters a 30-day over-allotment option to purchase up to an additional 2,250,000 shares of Common Stock at the same public offering price. The Offering was made pursuant to the Company’s effective registration statement on Form S-3 (Registration Statement No. 333-171958) previously filed with the Securities and Exchange Commission on January 31, 2011. The Offering closed on August 14, 2013. The Underwriters exercised their over-allotment option on September 6, 2013, which will close on September 11, 2013.

The net proceeds to the Company from the Offering, including the exercise of the Underwriters’ over-allotment option, are approximately $101.8 million, after deducting underwriting discounts and commissions and other estimated offering expenses payable by the Company. The Company intends to use the net proceeds from the Offering and the over-allotment option to fund the Company’s drilling and development program, to pursue select acquisition opportunities and for other general corporate purposes, including working capital.

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redeterminations after May 1, 2014 during any year. During July 2013, the redetermination increased our borrowing base by $55.0 million, from $110.0 million to the $165.0 million noted above.

On July 30, 2013, TUSA entered into Amendment No. 1 to Amended and Restated Credit Agreement and Master Assignment with Wells Fargo Bank, National Association, as administrative agent and issuing lender, and the other lenders named therein, as lenders. The Amendment No. 1 amended the TUSA credit facility to (i) increase the borrowing base under the A&R Credit Agreement from $110.0 million to $165.0 million, (ii) permit TUSA to hedge up to 85% of the anticipated production of (x) oil, (y) gas, and (z) natural gas liquid volumes, respectively, attributable to TUSA’s total proved reserves, and (iii) make revisions enabling TUSA to enter into a second lien credit facility at a future date. See Note 8 — Notes Payable and Credit Facilities under Item 1 of this Quarterly Report on Form 10-Q for further discussion.

Analysis of Changes in Cash Flows

The following is a summary of our change in cash and cash equivalents for the six months ended July 31, 2013 and 2012 (in thousands):

	For the Six Months Ended July 31,
	2013			2012			Change
Net cash provided by operating activities	$	31,433		$	4,036		$	27,397
Net cash used in investing activities	(159,403		)	(74,576		)	(84,827		)
Net cash provided by financing activities	144,233			118,082			26,151
	$	16,263		$	47,542		$	(31,279	)

Net Cash Provided by Operating Activities

Cash flows provided by operating activities was $31.4 million for the six months ended July 31, 2013. Cash flows provided by operating activities was $4.0 million for the six months ended July 31, 2012. The increase in operating cash flows was primarily due to higher oil revenues driven by higher sales volumes and prices, and increased revenue at RockPile driven by increased third party pressure pumping business, partially offset by increases in production expenses, production taxes, general and administrative expenses, and other expenses associated with the growth of our operations during the year.

Net Cash Used in Investing Activities

During the six months ended July 31, 2013, we used $159.4 million of cash in investing activities as compared to $74.6 million during the six months ended July 31, 2012. The increase in cash flows used in investing activities in the six months ended July 31, 2013 was primarily due to our larger capital budget and drilling program, which used $130.1 million, and to the purchase of a second frac spread, facility construction and the purchase of equipment for complimentary services at RockPile, which used $15.9 million. In addition to capital expenditures, we invested $9.0 million of cash in Caliber pursuant to our investment obligation to the joint venture.

Net Cash Provided by Financing Activities

Cash flows provided by financing activities for the six months ended July 31, 2013 totaled $144.2 million. The cash in-flow was primarily a result of the issuance of 9.3 million common shares to NGP and advances from notes payable and credit facilities.

Cash flows provided by financing activities in the six months ended July 31, 2012 of $118.1 million was primarily a

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The Company’s commodity derivative contracts as of July 31, 2013 are summarized below:

Collars	Basis	Quantity (Bbl/d)	Strike Price ($/Bbl)
May 1, 2013 - September 30, 2013	NYMEX	250 bopd	$ 90.00 - $102.50
July 1, 2013 - December 31, 2013	NYMEX	500 bopd	$ 87.00 - $101.75
May 1, 2013 - December 31, 2013	NYMEX	500 bopd	$ 85.00 - $104.30
May 1, 2013 - December 31, 2013	NYMEX	500 bopd	$ 85.00 - $100.50
May 1, 2013 - December 31, 2013	NYMEX	250 bopd	$ 90.00 - $101.50
May 1, 2013 - December 31, 2013	NYMEX	100 bopd	$ 87.50 - $100.00
August 1, 2013 - December 31, 2013	NYMEX	250 bopd	$ 94.00 - $110.25
August 1, 2013 - December 31, 2013	NYMEX	500 bopd	$ 90.00 - $105.00
August 1, 2013 - December 31, 2013	NYMEX	250 bopd	$ 90.00 - $107.85
August 1, 2013 - December 31, 2013	NYMEX	250 bopd	$ 93.00 - $107.50
October 1, 2013 - December 31, 2013	NYMEX	250 bopd	$ 90.00 - $106.50
January 1, 2014 - March 31, 2014	NYMEX	250 bopd	$ 85.00 - $98.75
January 1, 2014 - June 30, 2014	NYMEX	500 bopd	$ 85.00 - $100.80
January 1, 2014 - June 30, 2014	NYMEX	250 bopd	$ 87.00 - $101.00
April 1, 2014 - June 30, 2014	NYMEX	150 bopd	$ 84.25 - $100.00
January 1, 2014 - December 31, 2014	NYMEX	250 bopd	$ 85.00 - $99.50
January 1, 2014 - December 31, 2014	NYMEX	500 bopd	$ 80.00 - $101.20
January 1, 2014 - December 31, 2014	NYMEX	250 bopd	$ 82.00 - $98.00
January 1, 2014 - December 31, 2014	NYMEX	500 bopd	$ 83.00 - $99.25
January 1, 2014 - December 31, 2014	NYMEX	250 bopd	$ 85.00 - $100.00
January 1, 2014 - December 31, 2014	NYMEX	250 bopd	$ 85.00 - $100.50
July 1, 2014 - December 31, 2014	NYMEX	500 bopd	$ 83.50 - $100.00
January 1, 2015 - December 31, 2015	NYMEX	500 bopd	$ 80.00 - $94.50

Puts	Basis	Quantity (Bbl)	Average Strike Price ($/Bbl)
Expiring on December 13, 2013	NYMEX	500,000	$	75.00

1) NYMEX refers to prices of West Texas Intermediate crude oil at Cushing, Oklahoma, as quoted on the New York Mercantile Exchange.

We determine the estimated 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. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes. 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.

Changes in commodity futures price strips during the quarterly period ended July 31, 2013 had a negative impact on the fair value of our derivative contracts. For the three and six months ended July 31, 2013, we reported unrealized non-cash mark-to-market losses on derivative contracts of $2.8 million and $1.6 million, respectively. We also reported realized losses on derivative contracts of $1.6 million during the three and six months ended July 31, 2013. The fair value of our derivative instruments at July 31, 2013 was a net liability of $2.7 million. This mark-to-market net liability relates to derivative instruments with various terms that are scheduled to be realized over the period from August 2013 through December 2015. Over this period, actual realized derivative settlements may differ significantly, either positively or negatively, from the unrealized mark-to-market valuation at July 31, 2013. An assumed increase of 10% in the forward commodity prices used in the July 31, 2013 valuation of our derivative instruments would result in a net derivative liability of approximately $15.6 million at July 31, 2013. Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $7.5 million at July 31, 2013.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

Other than the following, there have been no material changes to the risk factors set forth in our Fiscal 2013 Form 10-K. Those risk factors, in addition to the other risk factors below and the information set forth in this Quarterly Report on Form 10-Q, 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.

We have identified material weaknesses in our internal controls that, if not properly corrected, could result in material misstatement in our financial statements.

On April 17, 2013, our board of directors approved the audit committee’s and management’s recommendation that we file Amendment No. 1 on Form 10-Q/A (the “Amendment”) to amend and restate our Quarterly Report on Form 10-Q for the three months ended October 31, 2012, which was filed with the U.S. Securities and Exchange Commission, or SEC, on December 10, 2012. The Amendment includes an error correction that eliminates $1.8 million of previously recognized pressure pumping income, pursuant to recognition exception rules set forth in Regulation S-X Rule 4-10(c)(6)(iv), as further discussed in Item 7 of our Annual Report on Form 10-K for the fiscal year ended January 31, 2013. Accordingly, we identified a material weakness in our controls over the accounting for pressure pumping income. Our control for the accounting for service income was not designed to consider all of the relevant accounting literature applicable to service income, including related party considerations as described in the Regulation S-X Rule 4-10(c)(6)(iv). This material weakness resulted in a material error in our accounting for pressure pumping income and a restatement of our previously issued quarterly financial statements for the three months ended October 31, 2012. As a result of this material weakness, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were not effective as of July 31, 2013. We are in the process of implementing system and procedural changes to prevent these issues from recurring in fiscal year 2014. If we are not able to remedy the control deficiencies in a timely manner, or if other deficiencies arise in the future, we may be unable to provide holders of our securities with required financial information in a timely and reliable manner and we could be required to restate or correct our financial statements in the future.

Certain stockholders have 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, we entered into an Investment Agreement with NGP Triangle Holdings, LLC, or NGP, and its parent company. Pursuant to the Investment Agreement, NGP is entitled to designate one director to our 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, we will 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, we have 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

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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. As a result of the foregoing, NGP has significant influence over us, our management, our policies and, under both the Investment Agreement, as amended, and following conversion of the Convertible Note as a significant stockholder, certain matters requiring stockholder approval.

In March 2013, we sold to two affiliates of NGP 9,300,000 shares of our common stock in a private placement (the “NGP Private Placement”). In connection with the NGP Private Placement, we entered into an amendment to the Investment Agreement to modify the definition of “Termination Event,” thereby strengthening NGP’s board seat designation right. If NGP were to fully convert the Convertible Note on the date of this report, then NGP and its affiliates would hold approximately 25% of our outstanding shares of common stock.

Further, in August 2013, we sold to ActOil 11,350,000 shares of our common stock in a private placement. Following the completion of the private placement, ActOil beneficially owns shares of common stock representing approximately 14% of the combined voting power of our outstanding shares of common stock as of the date of this report.

The interests of NGP, including in its capacity as a creditor, and ActOil may differ from the interests of our other stockholders, and the ability of NGP and ActOil 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.

We have broad discretion in the use of our net proceeds from our recent public offering and may not use them effectively.

Our management has broad discretion in the application of the net proceeds from our public equity offering completed in August 2013. Our management may spend the proceeds of the public offering in ways that do not improve our results of operations or increase the value of our common stock. Our stockholders may not agree with our management’s choices in allocating and spending the net proceeds. These decisions could result in additional financial losses that could have a material adverse effect on our business and cause the price of our common stock to decline.

We may not realize the benefits of integrating the recently acquired properties.

The integration of approximately 9,350 net acres of producing oil and gas properties into our operations will be a significant undertaking and will require significant resources, as well as attention from our management team. We could encounter difficulties in the integration process, such as the need to revisit assumptions about reserves, future production, revenues, capital expenditures and operating costs, including synergies, the loss of commercial relationships or the need to address unanticipated liabilities. If we cannot successfully integrate the recently acquired properties into our business, we may fail to realize the expected benefits of those acquisitions.

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

On August 2, 2013, TUSA entered into and closed definitive purchase and sale agreements with OGR Bakken Resources, LLC and ODP AIV II, LP, respectively, to acquire an aggregate of 1,241 net acres in McKenzie County, North Dakota and related rights. The aggregate consideration for such oil and gas properties consisted of (i) $13.5 million in cash and (ii) 325,000 shares of the Company’s common stock.

As previously reported by the Company in a Current Report on Form 8-K filed with the SEC, on August 6, 2013, the Company entered into a Stock Purchase Agreement (the “Stock Purchase Agreement”) with TIAA Oil and Gas Investments, LLC (“TOGI”). As permitted under the terms of the Stock Purchase Agreement, on August 28, 2013, TOGI assigned its rights and obligations to purchase the common stock under the Stock Purchase Agreement to ActOil. Pursuant to the terms of the Stock Purchase Agreement, on August 28, 2013, the Company issued 11,350,000 shares of its common stock to ActOil in a private placement at a purchase price of $7.20 per share, for gross proceeds to the Company of $81.72 million. The Company paid advisory fees of $750,000 to Simmons & Company International in connection with the private placement.

The 325,000 shares of common stock issued on August 2, 2013, as well as the 11,350,000 shares of common stock issued on August 28, 2013, were issued without registration under the Securities Act of 1933, as amended (the “Securities Act”), in reliance upon the exemption from registration set forth in Section 4(2) of the Securities Act. The Company relied on this exemption based on applicable facts, including that (i) the offers and sales were made to a limited number of persons, all of whom represented that they were “accredited investors” (as such term is defined in Regulation D), (ii) no general solicitation or advertising was used in connection with the offering and sale of the Company’s common stock, and (iii) the investors represented that they were acquiring the Company’s common stock for investment purposes only. The aforementioned shares may not be offered or sold in the United States in the absence of an effective registration statement or exemption from the registration requirements under the Securities Act.

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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		Investment Agreement, dated July 31, 2012, among Triangle Petroleum Corporation, NGP Triangle Holdings, LLC and NGP Natural Resources X, L.P., 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.
4.2		First Amendment to Investment Agreement, dated March 8, 2013, between Triangle Petroleum Corporation, NGP Triangle Holdings, LLC, NGP Natural Resources X, L.P., and NGP Natural Resources X Parallel Fund, L.P., filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 13, 2013 and incorporated herein by reference.
4.3		Amended and Restated Registration Rights Agreement, dated March 8, 2013, between Triangle Petroleum Corporation, NGP Triangle Holdings, LLC, NGP Natural Resources X, L.P., and NGP Natural Resources X Parallel Fund, L.P., filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 13, 2013 and incorporated herein by reference.
10.1		Employment Agreement, dated May 1, 2013, by and between Triangle Petroleum Corporation and Justin Bliffen, filed as Exhibit 10.7 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on May 1, 2013 and incorporated herein by reference.
10.2		Retirement and General Release Agreement, dated June 18, 2013, between Triangle Petroleum Corporation and Joseph B. Feiten, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 20, 2013 and incorporated herein by reference.
10.3		Third Amended and Restated Employment Agreement, dated July 4, 2013, between Triangle Petroleum Corporation and Jonathan Samuels, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 10, 2013 and incorporated herein by reference.
10.4		CEO Stand-Alone Stock Option Agreement, dated July 4, 2013, between Triangle Petroleum Corporation and Jonathan Samuels, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 10, 2013 and incorporated herein by reference.
10.5		Amendment No. 1 to Amended and Restated Credit Agreement and Master Assignment, dated July 30, 2013, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Bank, National Association, as Lenders, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 5, 2013 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

PART I. FINANCIAL INFORMATION

ITEM 1.	Financial Statements

	Condensed Consolidated Balance Sheets — July 31, 2013 and January 31, 2013	3

	Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) — Three and Six months ended July 31, 2013 and 2012	4

	Condensed Consolidated Statements of Cash Flows — Six months ended July 31, 2013 and 2012	5

	Condensed Consolidated Statement of Stockholders’ Equity — Six months ended July 31, 2013	6

	Notes to Condensed Consolidated Financial Statements	7

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	48

ITEM 4.	Controls and Procedures	51

PART II. OTHER INFORMATION

ITEM 1.	Legal Proceedings	52
ITEM 1A.	Risk Factors	52
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
ITEM 3.	Defaults Upon Senior Securities	54
ITEM 4.	Mine Safety Disclosures	54
ITEM 5.	Other Information	54
ITEM 6.	Exhibits	55

SIGNATURES		56

Fiscal Year	Weighted Average Daily Volumes (oil barrels)	Weighted Average Floor		Weighted Average Ceiling
2013	3,291	$	87.78	$	103.48
2014	2,511	$	83.29	$	99.89
2015	458	$	80.00	$	94.50

	Total Number of Shares Purchased	Average Price Paid Per Share
	(1)	(2)
May 1, 2013 - May 31, 2013	7,562	5.40
June 1, 2013 to June 30, 2013	13,679	7.16
July 1, 2013 to July 31, 2013	17,305	7.31
	38,546	$	6.88

TRIANGLE PETROLEUM CORPORATION

	Date: September 9, 2013	By:	/s/ JONATHAN SAMUELS
		Jonathan Samuels
		President and Chief Executive Officer (Principal Executive Officer)

	Date: September 9, 2013	By:	/s/ JUSTIN BLIFFEN
		Justin Bliffen
		Chief Financial Officer (Principal Financial Officer)