Triangle Petroleum 10Q 2014 Q3 Quarterly report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended October 31, 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 December 4, 2013, there were 85,622,326 shares of the registrant’s common stock outstanding.

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TRIANGLE PETROLEUM CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED OCTOBER 31, 2013

PART I. FINANCIAL INFORMATION

	ITEM 1.	Financial Statements

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

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

		Condensed Consolidated Statements of Cash Flows — Nine months ended October 31, 2013 and 2012	5

		Condensed Consolidated Statement of Stockholders’ Equity — Nine months ended October 31, 2013	6

		Notes to Condensed Consolidated Financial Statements	7

	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	52

	ITEM 4.	Controls and Procedures	54

PART II. OTHER INFORMATION

	ITEM 1.	Legal Proceedings	55
	ITEM 1A.	Risk Factors	55
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
	ITEM 3.	Defaults Upon Senior Securities	57
	ITEM 4.	Mine Safety Disclosures	57
	ITEM 5.	Other Information	57
	ITEM 6.	Exhibits	59

	SIGNATURES		60

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Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets

(In thousands, except share data)

(Unaudited)

	October 31, 2013			January 31, 2013
ASSETS
CURRENT ASSETS
Cash and equivalents	$	100,163		$	33,117
Accounts receivable:
Oil and natural gas sales	27,448			10,625
Trade	71,436			28,541
Other	247			955
Related party	2,031			—
Investment in marketable securities	—			5,065
Derivative asset	—			603
Inventory, deposits and prepaid expenses	4,492			2,307
Total current assets	205,817			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	131,428			94,529
Proved properties	510,712			220,894
Total oil and natural gas properties at cost	642,140			315,423
Less: accumulated amortization	(50,173		)	(16,666		)
Net oil and natural gas properties	591,967			298,757
Pressure pumping and related services equipment (less accumulated depreciation of $7.2 million and $2.5 million, respectively)	38,572			19,060
Other property and equipment (less accumulated depreciation of $2.0 million and $0.9 million, respectively)	20,590			15,779
Equity investment	22,395			11,718
Goodwill	5,251			—
Derivative asset	368			—
Other long-term assets	4,128			1,795
Total assets	$	889,088		$	428,322

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	49,275		$	37,043
Accrued liabilities:
Exploration and development	30,047			30,433
Other	27,552			7,486
Notes payable	5,876			—
Short-term borrowings on credit facilities	6,835			—
Asset retirement obligations	2,465			2,949
Derivative liability	342			—
Total current liabilities	122,392			77,911

LONG-TERM LIABILITIES
Long-term borrowings on credit facilities	157,785			25,000
5% convertible note	127,694			123,023
Other notes payable	764			—
Asset retirement obligations	2,081			473
Derivative liability	—			292
Other	1,499			—
Total liabilities	412,215			226,699

COMMITMENTS AND CONTINGENCIES (Note 11)
STOCKHOLDERS’ EQUITY
Common stock, $0.00001 par value, 140,000,000 shares authorized; 85,596,468 and 46,733,011 shares issued and outstanding at October 31, 2013 and January 31, 2013, respectively	1			—
Additional paid-in capital	569,523			323,643
Accumulated deficit	(92,651		)	(122,020		)
Accumulated other comprehensive income	—			—
Total stockholders’ equity	476,873			201,623
Total liabilities and stockholders’ equity	$	889,088		$	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						For the Nine Months Ended
	October 31,						October 31,
	2013			2012			2013			2012
REVENUES:
Oil and natural gas sales	$	55,477		$	10,443		$	111,176		$	23,123
Pressure pumping and related services	33,072			10,743			62,061			13,338
Other	—			114			—			339
Total revenues	88,549			21,300			173,237			36,800
EXPENSES:
Production taxes	6,161			1,202			12,524			2,631
Lease operating expenses	4,443			1,442			9,489			1,898
Gathering, transportation and processing	1,443			29			1,549			72
Depreciation and amortization	18,609			3,984			37,000			9,324
Accretion and other asset retirement obligation expenses	983			5			1,000			173
Pressure pumping and related services	29,164			8,881			53,042			10,742
General and administrative:
Stock-based compensation	2,457			1,507			5,489			4,305
Salaries and benefits	4,740			2,284			11,998			6,961
Other general and administrative	3,361			2,584			6,454			5,909
Total operating expenses	71,361			21,918			138,545			42,015

INCOME (LOSS) FROM OPERATIONS	17,188			(618		)	34,692			(5,215		)

OTHER INCOME (EXPENSE):
Gain (loss) from derivative activities	2,123			1,401			(1,064		)	1,401
Interest expense	(1,993		)	(1,430		)	(5,434		)	(1,472		)
Interest income	53			25			133			123
Other income (expense)	(13		)	(50		)	1,042			(42		)
Total other income (expense)	170			(54		)	(5,323		)	10

NET INCOME (LOSS) BEFORE INCOME TAXES	17,358			(672		)	29,369			(5,205		)
Income tax provision	—			—			—			—
NET INCOME (LOSS)	17,358			(672		)	29,369			(5,205		)
Less: net loss attributable to noncontrolling interest in subsidiary	—			73			—			626
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	17,358		$	(599	)	$	29,369		$	(4,579	)

Net income (loss) per common share outstanding:
Basic	$	0.22		$	(0.01	)	$	0.47		$	(0.10	)
Diluted	$	0.20		$	(0.01	)	$	0.43		$	(0.10	)

Weighted average common shares outstanding:
Basic	79,058,647			44,326,947			62,816,559			44,217,660
Diluted	96,041,223			44,326,947			78,864,626			44,217,660

COMPREHENSIVE INCOME (LOSS):
Net income (loss) attributable to common stockholders	$	17,358		$	(599	)	$	29,369		$	(4,579	)
Other comprehensive income (loss)	—			—			—			—
Total comprehensive income (loss)	$	17,358		$	(599	)	$	29,369		$	(4,579	)

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 Nine Months Ended October 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	29,369		$	(5,205	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	37,000			9,324
Stock-based compensation	5,489			4,476
Interest expense not paid in cash	3,936			1,459
Accretion and other asset retirement obligation expenses	1,000			173
(Gain) loss on derivative activities	1,064			(1,401		)
Settlements on commodity derivative instruments	(779		)	—
Loss on equity investment	—			50
Gain on securities held for investment	(1,040		)	—
Changes in related current assets and current liabilities:
Inventory, deposits and prepaid expenses	(1,775		)	(1,941		)
Accounts receivable:
Oil and natural gas sales	(16,823		)	(822		)
Trade	(42,820		)	(22,899		)
Related party	(2,031		)	—
Other	697			1
Accounts payable and accrued liabilities	2,936			8,150
Asset retirement expenditures	(484		)	(253		)
Cash provided by (used in) operating activities	15,739			(8,888		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures	(294,283		)	(92,637		)
Sale of oil and natural gas properties	—			3,265
Purchase of pressure pumping and related services equipment	(26,201		)	(14,434		)
Purchase of other property and equipment	(5,285		)	(12,383		)
Sale of marketable securities	6,105			—
Investment in Caliber Midstream Partners, L.P.	(9,000		)	(12,000		)
Purchase of derivative contracts	—			(3,889		)
Cash used in investing activities	(328,664		)	(132,078		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock	245,333			—
Stock offering costs	(7,059		)	—
Proceeds from credit facilities	170,320			13,700
Repayments of credit facilities	(30,700		)	(13,700		)
Proceeds from notes payable	5,876			120,000
Debt issuance costs	(2,406		)	(1,208		)
Cash paid to settle tax on vested restricted stock units	(1,510		)	(1,619		)
Issuance of common stock for exercise of options	117			13
Cash provided by financing activities	379,971			117,186

NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS	67,046			(23,780		)
CASH AND EQUIVALENTS, BEGINNING OF PERIOD	33,117			68,815
CASH AND EQUIVALENTS, END OF PERIOD	$	100,163		$	45,035

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 Nine Months Ended October 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
Stock offering costs				(115		)				(115		)
Shares issued for services at $7.24/share	5,000	—		36			—			36
Shares issued at $6.25/share	17,250,000	—		107,813			—			107,813
Stock offering costs		—		(6,033		)	—			(6,033		)
Shares issued at $7.20/share	11,350,000	—		81,720			—			81,720
Stock offering costs		—		(911		)	—			(911		)
Shares issued for the purchase of oil and natural gas properties	325,000	—		2,438			—			2,438
Vesting of restricted stock units (net of shares surrendered for taxes)	540,124	—		(1,510		)	—			(1,510		)
Exercise of stock options	93,333			117						117
Stock-based compensation	—	—		6,525			—			6,525
Net income for the period	—	—		—			29,369			29,369
Balance - October 31, 2013	85,596,468	$	1	$	569,523		$	(92,651	)	$	476,873

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 a growth oriented independent energy company focused on the exploration, development and production of unconventional shale oil and natural gas resources in the Bakken Shale and Three Forks formations 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. We hold leasehold interests in approximately 94,000 net acres in the Williston Basin, approximately 45,000 of which are predominantly in our core focus area in McKenzie and Williams Counties, North Dakota. We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation (“TUSA”).

In June 2011, we formed RockPile Energy Services, LLC (“RockPile”), a wholly-owned subsidiary, which provides 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.

In September 2012, through our wholly-owned subsidiary, Triangle Caliber Holdings, LLC, we formed Caliber Midstream Partners, L.P. (“Caliber”), an unconsolidated joint venture with First Reserve Energy Infrastructure Fund (“FREIF”). Caliber, through its subsidiaries, was formed for the purpose of providing oil, natural gas and water transportation 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 prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), for which the primary accounting rules are set forth in the Accounting Standards Codification (“ASC”), adopted and updated by the Financial Accounting Standards Board (“FASB”). 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% economic interest in Caliber and its 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 our annual financial statements prepared in accordance with 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 (“Fiscal 2013 Form 10-K”).

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In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the three and nine month periods ended October 31, 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 October 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.

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.

Business Combinations

Business combinations are accounted for using the acquisition method.

The acquired identifiable net assets are measured at their fair values at the date of acquisition. Deferred taxes are recognized for any differences between the fair value of the net assets acquired and their tax basis. Any excess of purchase price over the fair value of the net assets acquired is recognized as goodwill. Associated transaction costs are expensed when incurred.

Goodwill

Our goodwill represents consideration paid in excess of the fair value of the identifiable net assets acquired in a business combination. Our goodwill is resulting from the October 16, 2013 acquisition of Team Well Service, Inc. by RockPile and is preliminary (see Note 4 — Property and Equipment). We review goodwill for impairment annually, or more frequently if events or changes in circumstances indicate that it is more likely than not that the fair value of the reporting unit could be less than its carrying amount.

No goodwill impairments existed at October 31, 2013. The recorded goodwill is not associated with a specific valued intangible. Therefore, neither the goodwill nor any future goodwill impairment would be tax deductible under current federal income tax law.

Investment in Unconsolidated Affiliate

We apply the equity method of accounting where we can exert significant influence over, but do not control or direct, the policies, decisions or activities of the entity. We use the cost method of accounting where we are unable to exert significant influence over the entity. The FASB’s accounting standards related to equity method investments and joint ventures requires entities to periodically review their equity method investments to determine whether current events or circumstances indicate that the carrying value of the equity method investment may be impaired. We evaluate our equity method investment for impairment when there are indicators of impairment. If indicators suggest impairment, we will

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perform an impairment test to assess whether an adjustment is necessary. The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary. If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value.

Recent Accounting Pronouncements

In December 2011, the FASB issued Accounting Standards Update 2011-11 (“ASU 2011-11”), Balance Sheet: Disclosures about Offsetting Assets and Liabilities, which required entities to disclose information about offsetting and related arrangements to enable financial statement users to understand the effect of such arrangements on the balance sheet. Entities are required to disclose both gross information and net information about financial instruments and derivative instruments that are either offset in the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. In January 2013 the FASB issued ASU 2013-01, Balance Sheet: Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies the scope of the offsetting disclosures and addresses any unintended consequences. Amendments to ASU 2011-11, as superseded by ASU 2013-01 is effective for reporting periods beginning after January 1, 2013 (including interim periods), and should be applied retrospectively for any period presented. The adoption of ASU 2013-01and ASU 2011-11 concerns presentation and disclosure only.

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.

Investment in Marketable Securities

As of October 31, 2013, we had sold for $6.1 million, net of brokerage fees, all of the 851,315 shares of Emerald Oil Inc. (“Emerald”) common stock (NYSE MKT symbol “EOX”), originally recorded at $4.9 million when acquired in the January 9, 2013 sale of oil and natural gas leases to Emerald. We elected the fair value option for this investment in equity securities and therefore recorded the change in fair value during the period in the condensed consolidated statements of operations and comprehensive income (loss). We recorded a loss of $0.01 million and a gain of $1.0 million for the three and nine months ended October 31, 2013, respectively, which are included in other income (expense) on the condensed consolidated statements of operations and comprehensive income (loss) for the applicable period. Additionally, we recorded a gain of $0.2 million in January 2013.

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3. Segment Reporting

We conduct our operations with two reportable operating segments. We 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 related services operating segment is responsible for pressure pumping and complementary services for both Triangle-operated wells and wells operated by third-parties.

Management evaluates the performance of our segments based upon net income (loss) before income taxes.

The following tables present selected financial information for our operating segments for the three months ended October 31, 2013 and 2012 (in thousands):

	For the Three Months Ended October 31, 2013
	Exploration and Production		Pressure Pumping and Related Services			Corporate and Other(1)			Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	55,477	$	—		$	—		$	—		$	55,477
Pressure pumping and related services for third parties	—		33,499			—			(427		)	33,072
Intersegment revenues	—		32,499			—			(32,499		)	—
Other	—		—			183			(183		)	—
Total revenues	55,477		65,998			183			(33,109		)	88,549
Expenses
Production taxes and other lease operating	10,604		—			—			—			10,604
Gathering, transportation and processing	1,443		—			—			—			1,443
Depreciation and amortization	16,829		2,635			165			(1,020		)	18,609
Accretion and other asset retirement obligation expenses	983		—			—			—			983
Cost of pressure pumping and related services	—		49,839			—			(20,675		)	29,164
General and Administrative:
Stock-based compensation	328		148			1,981			—			2,457
Other general and administrative	2,346		3,150			2,605			—			8,101
Total operating expenses	32,533		55,772			4,751			(21,695		)	71,361
Income (loss) from operations	22,944		10,226			(4,568		)	(11,414		)	17,188
Other income (expense), net	1,527		(242		)	(731		)	(384		)	170
Net income (loss) before income taxes	$	24,471	$	9,984		$	(5,299	)	$	(11,798	)	$	17,358

	For the Three Months Ended October 31, 2012
	Exploration and Production			Pressure Pumping and Related Services		Corporate and Other(1)			Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	10,443		$	—	$	—		$	—		$	10,443
Pressure pumping and related services for third parties	—			12,530		—			(1,787		)	10,743
Intersegment revenues	—			11,335		—			(11,335		)	—
Other	—			—		114			—			114
Total revenues	10,443			23,865		114			(13,122		)	21,300
Expenses
Production taxes and other lease operating	2,644			—		—			—			2,644
Gathering, transportation and processing	29			—		—			—			29
Depreciation and amortization	3,154			1,203		202			(575		)	3,984
Accretion of asset retirement obligations	5			—		—			—			5
Cost of pressure pumping and related services	—			16,276		—			(7,395		)	8,881
General and Administrative:
Stock-based compensation	602			—		905			—			1,507
Other general and administrative	1,588			1,685		1,595			—			4,868
Total operating expenses	8,022			19,164		2,702			(7,970		)	21,918
Income (loss) from operations	2,421			4,701		(2,588		)	(5,152		)	(618		)
Other income (expense), net	(1,408		)	—		1,354			—			(54		)
Net income (loss) before income taxes	$	1,013		$	4,701	$	(1,234	)	$	(5,152	)	$	(672	)

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

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The following tables present selected financial information for our operating segments for the nine months ended October 31, 2013 and 2012 (in thousands):

	For the Nine Months Ended October 31, 2013
	Exploration and Production			Pressure Pumping and Related Services			Corporate and Other(1)			Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	111,176		$	—		$	—		$	—		$	111,176
Pressure pumping and related services for third parties	—			65,780			—			(3,719		)	62,061
Intersegment revenues	—			71,385			—			(71,385		)	—
Other	—			—			731			(731		)	—
Total revenues	111,176			137,165			731			(75,835		)	173,237
Expenses
Production taxes and other lease operating	22,013			—			—			—			22,013
Gathering, transportation and processing	1,549			—			—			—			1,549
Depreciation and amortization	33,558			5,474			423			(2,455		)	37,000
Accretion and other asset retirement obligation expenses	1,000			—			—			—			1,000
Cost of pressure pumping and related services	—			99,330			—			(46,288		)	53,042
General and Administrative:
Stock-based compensation	897			458			4,134			—			5,489
Other general and administrative	5,378			7,575			5,499			—			18,452
Total operating expenses	64,395			112,837			10,056			(48,743		)	138,545
Income (loss) from operations	46,781			24,328			(9,325		)	(27,092		)	34,692
Other income (expense), net	(1,313		)	(611		)	(1,722		)	(1,677		)	(5,323		)
Net income (loss) before income taxes	$	45,468		$	23,717		$	(11,047	)	$	(28,769	)	$	29,369

Total Assets	$	711,512		$	114,121		$	590,610		$	(527,155	)	$	889,088
Net oil and natural gas properties	$	620,736		$	—		$	—		$	(28,769	)	$	591,967
Pressure pumping and related services equipment	$	—		$	38,572		$	—		$	—		$	38,572
Other property and equipment - net	$	1,647		$	16,960		$	1,983		$	—		$	20,590
Total Liabilities	$	250,486		$	58,122		$	131,847		$	(28,240	)	$	412,215

	For the Nine Months Ended October 31, 2012
	Exploration and Production			Pressure Pumping and Related Services		Corporate and Other(1)			Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	23,123		$	—	$	—		$	—		$	23,123
Pressure pumping and related services for third parties	—			15,125		—			(1,787		)	13,338
Intersegment revenues	—			16,859		—			(16,859		)	—
Other	339			—		—			—			339
Total revenues	23,462			31,984		—			(18,646		)	36,800
Expenses
Production taxes and other lease operating	4,529			—		—			—			4,529
Gathering, transportation and processing	72			—		—			—			72
Depreciation and amortization	8,323			1,622		202			(823		)	9,324
Accretion of asset retirement obligations	11			—		162			—			173
Cost of pressure pumping and related services	—			22,213		—			(11,471		)	10,742
General and Administrative:
Stock-based compensation	1,920			—		2,385			—			4,305
Other general and administrative	3,955			5,559		3,356			—			12,870
Total operating expenses	18,810			29,394		6,105			(12,294		)	42,015
Income (loss) from operations	4,652			2,590		(6,105		)	(6,352		)	(5,215		)
Other income (expense), net	(1,369		)	9		1,370			—			10
Net income (loss) before income taxes	$	3,283		$	2,599	$	(4,735	)	$	(6,352	)	$	(5,205	)

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4. Property and Equipment

Acquisitions

Kodiak Oil & Gas Property Acquisition

On August 28, 2013, TUSA acquired interests in approximately 5,600 net acres of Williston Basin leaseholds, and related producing properties along with various other related rights, permits, contracts, equipment and other assets from Kodiak Oil & Gas Corporation (“Kodiak”), which are located in McKenzie County, North Dakota. We paid approximately $83.8 million in cash. The effective date for the acquisition was July 1, 2013 and is subject to customary post-closing adjustments. The acquisition contributed $1.5 million of revenue to the Company for the three and nine months ended October 31, 2013. Transaction costs related to the acquisition incurred through October 31, 2013 were approximately $0.2 million and are recorded in the statement of operations within the general and administrative expenses line item.

The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed. Accordingly, the allocation may change as additional information becomes available and is assessed by the Company, and the impact of such changes may be material.

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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	$	46,681
Unproved properties	34,063
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 2, 2013, the Company closed a trade agreement with Kodiak (the “Trade Agreement”) to exchange certain of Triangle’s oil and natural gas leasehold interests in Kodiak’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 properties acquired and exchanged from Kodiak for the three and nine months ended October 31, 2013 and 2012 as if the acquisition and exchange had occurred on February 1, 2012. As Kodiak’s fiscal year is within 93 days of the Company’s fiscal year, no adjustment for the differing periods has been considered. The following pro forma results include the operating revenues and direct operating expenses for the acquired and exchanged properties for the three and nine months ended October 31, 2013 and 2012 (in thousands, except per share data):

	Three Months Ended				Nine Months Ended
	October 31,				October 31,
	2013		2012		2013		2012
Operating revenues	$	91,524	$	25,519	$	187,038	$	39,266
Net income (loss)	$	19,362	$	1,320	$	35,957	$	(3,821	)

Earnings (loss) per common share
Basic	$	0.24	$	0.02	$	0.50	$	(0.07	)
Diluted	$	0.21	$	0.02	$	0.46	$	(0.07	)

Weighted average common shares outstanding:
Basic	82,389,625		55,676,811		71,464,178		55,526,236
Diluted	99,372,201		55,676,811		87,512,245		55,526,236

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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 (see Note 6 — Stockholders’ Equity) 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 $0.3 million and $4.0 million for the three and nine months ended October 31, 2013, respectively, as compared to $1.2 million and $1.1 million for the three and nine months ended October 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.

August 2, 2013 Oil & Natural Gas Property Acquisition

On August 2, 2013, TUSA completed the acquisition of 1,236 net acres and various other related rights, permits, contracts, equipment and other assets from an unaffiliated company for cash and stock of approximately $15.9 million consisting of (i) cash of approximately $13.5 million and (ii) 325,000 shares of Triangle’s common stock. We have valued the 325,000 shares of common stock issued at $2.4 million based on the closing price of our common stock of $7.50 per share on the issue date. The effective date for the acquisition was October 1, 2011 and is subject to customary post-closing adjustments. The acquisition contributed $0.8 million in revenue to Triangle for the three and nine month periods ended October 31, 2013.

The final purchase price allocation is pending the determination of adjustments from the effective date and the completion of the valuation of the assets acquired and liabilities assumed.

Pro forma information has not been provided for the August 2, 2013 acquisition as the impact is immaterial to our unaudited condensed consolidated financial statements.

Acquisition of Team Well Service, Inc.

On October 16, 2013, RockPile completed its acquisition of Team Well Service, Inc. (“Team Well”), an operator of well service rigs in North Dakota, in exchange for (i) $6.8 million in cash; (ii) unsecured seller notes of $0.8 million; and, (iii) contingent consideration of $1.5 million, as well as customary post-closing adjustments.

The unsecured seller notes have an aggregate face value of $1.0 million bearing an interest rate of 1% per annum. Principal and accrued interest is due on October 16, 2016. The contingent consideration, or earn-out payments, is comprised of three annual payments equal to 10% of revenue during each consecutive earn-out period (the one year period beginning on the first day of the first month immediately following the closing date) with payments limited to a maximum of $0.7 million for each earn-out period, based on revenue of up to $7.0 million. The estimated liability assumed that 100% of the earn-out would be achieved.

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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			$	6,792
Unsecured note payable			764
Earn-out payments			1,499
Total consideration given			$	9,055

Preliminary fair value allocation of purchase price:
Net working capital			$	493
Equipment:
Light equipment	$	342
Workover equipment	2,969
Total net assets			3,311
Goodwill			5,251
Fair value of net assets acquired			$	9,055

Transaction and other costs associated with the acquisition of net assets are expensed as incurred.

Pro forma information has not been provided for the Team Well acquisition as the impact is immaterial to our unaudited condensed consolidated financial statements.

Oil and Natural Gas Property Additions

During the nine months ended October 31, 2013, we acquired oil and natural gas properties, and participated in the drilling and/or completion of wells, for total consideration of approximately $326.7 million.

In the three and nine months ended October 31, 2013, we capitalized $1.0 million and $2.6 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 nine months ended October 31, 2012, we capitalized $0.7 million and $1.5 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.

Other Property and Equipment Additions

Pressure pumping and related services equipment of $45.8 million ($38.6 million net of accumulated depreciation) consists primarily of costs for two frac spreads and other complementary well completion and work over equipment, all of which were in service at October 31, 2013.

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Other property and equipment of $22.6 million ($20.6 million net of accumulated depreciation) is located in the U.S. and consists of the following:

· $13.2 million for land, administrative and services facility, residential living facilities and land in North Dakota;

· $4.1 million for a RockPile proppant storage and transloading facility in North Dakota;

· $1.9 million of light vehicles; and

· $3.4 million for hardware, software and furniture and fixtures.

Ceiling-Test Impairments

The Company uses the full-cost accounting method, which requires recognition of an impairment of oil and natural gas properties when, by country, the total net carrying value of oil and natural gas properties exceeds a ceiling as described in Note 3 — Summary of Significant Accounting Policies in our audited financial statements included in our Fiscal 2013 Form 10-K. The Company did not recognize any impairment for the three or the nine-month periods ended October 31, 2013 and 2012.

5. Equity Investment

On October 1, 2012, Triangle Caliber Holdings, LLC (“Triangle Caliber Holdings”), a wholly-owned subsidiary of Triangle, entered into a joint venture with FREIF Caliber Holdings LLC (“FREIF Caliber Holdings”), a wholly-owned subsidiary of First Reserve Energy Infrastructure Fund, L.P. The joint venture entity, Caliber Midstream Partners, L.P. (“Caliber”), was formed to provide crude oil, natural gas and water transportation and processing services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana. For further discussion of the Caliber agreements, see Note 7 — Investment in Unconsolidated Affiliate in our Fiscal 2013 Form 10-K.

On September 12, 2013, Triangle Caliber Holdings entered into a series of agreements modifying its joint venture with FREIF Caliber Holdings. In connection with the modifications to the joint venture, Triangle Caliber Holdings entered into an Amended and Restated Contribution Agreement, dated September 12, 2013 (the “A&R Contribution Agreement”), with FREIF Caliber Holdings, Caliber, and Caliber Midstream GP LLC (“Caliber GP”), the general partner of Caliber owned and controlled equally between Triangle Caliber Holdings and FREIF Caliber Holdings. The A&R Contribution Agreement amends and restates the Contribution Agreement entered into between Triangle Caliber Holdings, FREIF Caliber Holdings, Caliber, and Caliber GP on October 1, 2012 (the “Contribution Agreement”).

Pursuant to the terms of the A&R Contribution Agreement, FREIF Caliber Holdings agreed to contribute an additional $80.0 million to Caliber in exchange for an additional 8,000,000 Class A Units to be issued no later than June 30, 2014. Also pursuant to the terms of the A&R Contribution Agreement, Triangle Caliber Holdings’ 4,000,000 Class A Trigger Units granted in connection with the Contribution Agreement will be converted to 4,000,000 Class A Units no later than June 30, 2014. The conversion will not require any additional contribution of capital from Triangle Caliber Holdings. Following the issuance of the additional 8,000,000 Class A Units to FREIF Caliber Holdings and the conversion of Triangle Caliber Holdings’ 4,000,000 Class A Trigger Units to 4,000,000 Class A Units, FREIF Caliber Holdings will own 15,000,000 Class A Units, representing an approximate sixty-eight percent (68%) limited partner interest in Caliber, and Triangle Caliber Holdings will own 7,000,000 Class A Units, representing an approximate thirty-two percent (32%) limited partner interest in Caliber. Triangle Caliber Holdings currently holds a thirty percent (30%) limited partner interest in Caliber.

We use the equity method of accounting for our investment in Caliber, with earnings or losses, after elimination of intra-company profits and losses, reported in the income (loss) from equity investment line on the condensed consolidated statements of operations and comprehensive income (loss).

As of October 31, 2013, the balance of the Company’s investment in Caliber was $22.4 million. The investment balance was increased in fiscal year 2014 by $9.0 million from additional contributions by Triangle and by $1.7 million which was Triangle’s share of Caliber’s net income before such share’s elimination as Triangle intra-company profit, for the nine months ended October 31, 2013. During the nine months ended October 31, 2013, a significant portion of

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Caliber’s net income was generated from services provided to Triangle in its well completion operations, which Triangle capitalized as part of its oil and natural gas properties. As such, that portion of Triangle’s share of Caliber’s net income was recorded as a reduction to these capitalized costs.

After elimination of intra-company profits related to Caliber’s provision of services to wells operated by TUSA, we recognized no income from our equity investment for the three and nine month period October 31, 2013.

6. Stockholders’ Equity

Common Stock

The following transactions occurred during the nine months ended October 31, 2013 with regard to shares of the Company’s common stock:

· On March 8, 2013, the Company sold to two affiliates of NGP Triangle Holdings, LLC (“NGP”) an aggregate of 9,300,000 million shares of common stock in a private placement at $6.00 per share for aggregate consideration of $55.8 million. The Company paid approximately $0.1 million in expenses related to this offering.

· We issued 540,124 shares of common stock (net of shares surrendered for related employee payroll tax withholding) for restricted stock units that vested during the period.

· We issued 5,000 shares of common stock at $7.24 per share to a consultant for services provided to TUSA.

· On August 2, 2013, the Company issued 325,000 shares of common stock to an unaffiliated oil and gas company at $7.50 per share for total consideration of $2.4 million.

· In August and September, 2013, the Company sold 17,250,000 shares of common stock at $6.25 per share in a public offering for gross proceeds of $107.8 million. The Company paid approximately $6.0 million in expenses related to this offering.

· On August 28, 2013, the Company sold 11,350,000 shares of common stock to an unaffiliated entity at $7.20 per share for total consideration of $81.7 million. The Company paid approximately $0.9 million in expenses related to this offering.

· We issued 93,333 shares of common stock for the exercise of stock options.

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 under the Stock Purchase Agreement to ActOil Bakken, LLC (“ActOil”), which is an affiliate of TOGI.

Also, on August 28, 2013, the Company issued to ActOil 11,350,000 shares of common stock at $7.20 per share for gross proceeds to the Company of $81.7 million ($80.8 million net after transaction costs), which were used to consummate the August 28, 2013 Kodiak property acquisition. Concurrently with the issuance, the Company entered into a Rights Agreement (the “Rights Agreement”) with ActOil. Under the Rights Agreement, ActOil 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 ActOil from selling, pledging or otherwise disposing of the Company’s common stock acquired by ActOil 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 ActOil 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 ActOil and its affiliates cease to hold at least the lesser of (i) 50% of the shares of common stock acquired by ActOil 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.

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Pursuant to the Rights Agreement, on the date on which the aggregate amount paid to the Company by ActOil and certain of its affiliates as consideration for shares of common stock exceeds $150.0 million, ActOil 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 ActOil holds (i) 50% of the common stock purchased by ActOil under the Stock Purchase Agreement, and (ii) 10% of the then issued and outstanding common stock, without the prior written consent of ActOil, 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, the Company 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. 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 a price to the public of $6.25 per share. The over-allotment option closed on September 11, 2013.

The total gross proceeds to the Company from the Offering were approximately $107.8 million ($101.8 million net, after deducting underwriting discounts and commissions and other estimated offering expenses). The Company intends to use the net proceeds from the Offering and the exercise of the Underwriters’ over-allotment option 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.

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Restricted Stock Units

During the nine months ended October 31, 2013, the Company granted 1,235,633 restricted stock units as compensation to officers, directors, employees, and a consultant. The restricted stock units vest over one to five years. As of October 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 2.5 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		$	6.68
Units granted during the nine months ended October 31, 2013	1,235,633		$	6.64
Units forfeited during the nine months ended October 31, 2013	(23,319	)	$	6.54
Units that vested during the nine months ended October 31, 2013	(762,915	)	$	7.21
Restricted stock units outstanding - October 31, 2013	2,873,484		$	6.04

For the three and nine months ended October 31, 2013, the Company recorded stock-based compensation related to restricted stock units of $2.0 million and $4.4 million, respectively, in general and administrative expenses. An additional $0.4 million and $1.0 million of stock based compensation was capitalized to oil and natural gas properties during the three and nine months ended October 31, 2013, respectively.

For the three and nine months ended October 31, 2012, the Company recorded stock-based compensation related to restricted stock units of $1.5 million and $4.3 million, respectively, in general and administrative expenses. An additional $0.4 million and $0.7 million of stock based compensation was capitalized to oil and natural gas properties during the three and nine months ended October 31, 2012.

Stock Options

On July 4, 2013, the Company entered into a CEO Stand-Alone Stock Option Agreement with 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 required stockholder approval before any shares of the Company’s common stock could 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.

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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 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 on July 4, 2023.

Compensation expense related to stock options is calculated using the Black Scholes valuation model. Expected volatility is generally based on the historical volatility of (a) Triangle’s common stock and (b) for expected terms exceeding three years, the historical volatility of similar companies with significant exploration and production activity in the Bakken over a historical period consistent with that of the expected term of the options. Triangle’s historical volatility before January 2011 related to high-risk, unsuccessful exploration in Nova Scotia and is not representative of expected future volatility for Triangle. The expected term of the options is estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rate for the expected term (from service inception to option exercise) of the options is based on the yields of U.S. Treasury instruments with lives comparable to the estimated expected option term or life.

The following assumptions were used for the Black-Scholes model to calculate the share-based compensation expense for the CEO Option Grant for the period presented:

Risk free rate	2.18	%
Dividend yield	—
Expected volatility	62	%
Weighted average expected stock option life (years)	6.3

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) and the CEO Option Grant:

	Number of Shares		Weighted Average Exercise Price
Options outstanding - January 31, 2013 (231,666 exercisable)	231,666		$	1.48
Options exercised	(93,333	)	$	1.25
Options granted	6,000,000		$	11.25
Options outstanding - October 31, 2013 (138,333 exercisable)	6,138,333		$	11.03

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The following table presents additional information related to the stock options outstanding under the Rolling Plan and the CEO Option Grant at October 31, 2013:

Exercise Price		Remaining Contractual Life	Number of shares
per Share		(years)	Outstanding		Exercisable
$	3.00	0.24	30,000		30,000
$	1.25	1.08	108,333		108,333
$	7.50	9.68	750,000		—
$	8.50	9.68	750,000		—
$	10.00	9.68	1,500,000		—
$	12.00	9.68	1,500,000		—
$	15.00	9.68	1,500,000		—
			6,138,333		138,333

Weighted average exercise price per share			$	11.03	$	1.63

Weighted average remaining contractual life			9.48		0.90

As of October 31, 2013, all compensation expense related to stock options under the Rolling Plan had been recognized as they became fully vested in fiscal year 2013. Total compensation expense related to the CEO Option Grant of $0.6 million was recognized for the three and nine months ended October 31, 2013. The aggregate intrinsic value of all options as of October 31, 2013 was $5.9 million. As of October 31, 2013, there was approximately $18.7 million of total unrecognized compensation expense related to unvested stock options.

RockPile Share-Based Compensation

At October 31, 2013, RockPile had 30.0 million Series A Units authorized by the LLC Agreement (as defined below) with approximately 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 December 28, 2012, Triangle acquired an aggregate of 4.0 million Series A Units from the other two original owners of Series A Units. On February 15, 2013, Triangle made an additional capital contribution of $5.0 million to acquire an additional approximately 1.5 million Series A Units.

Effective October 22, 2012, RockPile’s Board of Managers approved the Second Amended and Restated Limited Liability Company Agreement, as further amended on February 20, 2013 (“LLC Agreement”), which includes provisions allowing RockPile to make equity grants in the form of restricted units (“Series B Units”) pursuant to Restricted Unit Agreements. The LLC Agreement, which was executed by RockPile and its members on October 31, 2012, authorizes RockPile to issue an aggregate of up to 6.0 million Series B Units in multiple series designated by a sequential number (i.e., Series B-1, Series B-2, etc.) with the right to re-issue forfeited or redeemed Series B Units. As of October 31, 2013, RockPile had granted approximately 4.1 million Series B Units, of which approximately 2.4 million were unvested at that date, to certain employees in key positions at RockPile.

The Series B Units are intended to constitute interests in future profits, i.e., “profit interests” within the meaning of Internal Revenue Service Revenue Procedures 93-27 and 2001-43. Accordingly, the capital account associated with each Series B Unit at the time of its issuance shall be nil. RockPile’s Board of Managers may designate a “Liquidation Value” applicable to each tranche of a Series B Unit so as to constitute a net profits interest in RockPile. The Liquidation Value shall equal the dollar amount per unit that would, in the reasonable determination of RockPile’s Board of Directors, be distributed with respect to the initial Series B tranche if, immediately prior to the issuance of a new Series B tranche, the

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assets of RockPile were sold for their fair market value and the proceeds (net of any liabilities of RockPile) were distributed.

RockPile’s Series A Units are entitled to a return of contributed capital and an 8.0% preferred return on such capital before Series B Units participate in profits. The initial Series B tranche (Series B-1 Units) participates pro-rata with the Series A Units once the preferred return has been achieved. However, no distributions shall be made with respect to any Series B-1 Units until total cumulative distributions to the Series A Units total $40.0 million. After distributions totaling $40.0 million have been made to the Series A Units, future distributions will be allocated to the Series B-1 Units until the per unit profits distributed to the Series B-1 Units is equivalent to the per unit profits distributed to the Series A Units. Thereafter, all further distributions would be distributed on a pro-rata basis. Subsequent issuances of Series B Units will begin participating on a pro rata basis once the per unit profits allocated to the Series B-1 Units reaches the Liquidation Value of the subsequent Series B Unit issuance.

Series B Units currently have from 2 to 44 months remaining until fully vested. Compensation costs are determined using a Black-Scholes option pricing model based upon the grant date calculated fair market value of the award and is recognized ratably over the applicable vesting period.

Series B Units are valued using a waterfall valuation approach beginning with the initial asset valuation contained in the LLC Agreement with each tranche of Series B Units constituting a waterfall valuation event. Additionally, due to the limited operating history of RockPile, its private ownership and the nature of the equity grants, RockPile has made use of estimates as it relates to employee termination and forfeiture rates, used different valuation techniques including income and/or market approaches, and utilized certain peer group derived information. The assumptions used in the Black-Scholes option pricing model consist of the underlying equity value, the estimated time to liquidity which is based upon the projected exit path, volatility based upon the midpoint volatility of a publicly traded peer group, and the risk-free interest rate which is based upon the rate for zero coupon U.S. Government issues with a term equal to the expected life.

A summary of RockPile’s Series B Unit activity and vesting for the nine months ended October 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	—		(15,000		)	—
Units unvested at October 31, 2013	1,441,667		45,000			910,000

Weighted average award date unit fair value	$	0.44	$	0.29		$	0.70
Remaining vesting period (years)	0.68		1.83			3.53

Non-cash compensation cost related to the Series B Units was $0.1 million and $0.5 million for the three and nine months ended October 31, 2013, respectively.

As of October 31, 2013, there was approximately $0.9 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 common 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, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for

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securities outstanding at the end of a period. Also, the treasury stock method for calculating dilution 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 restricted stock units 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 nine months ended October 31, 2013 and 2012 (in thousands, except per share data):

	For the Three Months Ended October 31,					For the Nine Months Ended October 31,
	2013		2012			2013		2012
Net income (loss) attributable to common stockholders	$	17,358	$	(599	)	$	29,369	$	(4,579	)
Effect of debt conversion	1,401		—			4,230		—
Net income (loss) attributable to common shareholders after effect of debt conversion	18,759		(599		)	33,599		(4,579		)

Basic weighted average common shares outstanding	79,058,647		44,326,947			62,816,559		44,217,660
Effect of dilutive securities	16,982,576		—			16,048,067		—
Diluted weighted average common shares outstanding	96,041,223		44,326,947			78,864,626		44,217,660

Basic net income (loss) per share	$	0.22	$	(0.01	)	$	0.47	$	(0.10	)
Diluted net income (loss) per share	$	0.20	$	(0.01	)	$	0.43	$	(0.10	)

For the three and nine month periods ended October 31, 2012, with a basic net loss per share, all of the stock options, restricted stock units and convertible debt outstanding at October 31, 2012 would have been anti-dilutive if converted into additional common stock and were excluded in calculating diluted net loss per share.

Of the stock options, restricted stock units and convertible debt outstanding at October 31, 2013, only the CEO Options having an exercise price of $10.00 to $15.00 per share were anti-dilutive for the three-months ended October 31, 2013; and their potential 4,500,000 common shares were excluded from the calculation of the diluted net income per share for that three-month period. All CEO Options outstanding at October 31, 2013 were anti-dilutive for the nine months ended October 31, 2013, and their potential 6,000,000 common shares were excluded from the calculation of diluted net income per share for the period. These CEO stock options could be potentially dilutive in future periods.

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):

	October 31, 2013			January 31, 2013
TUSA Credit Facility	$	151,000		$	25,000
5% Convertible Note	127,694			123,023
RockPile Credit Facility	13,620			—
RockPile Notes Payable	6,640			—
Total debt	298,954			148,023
Less: Current portion	(12,711		)	—
Total debt, net of current portion	$	286,243		$	148,023

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The weighted average effective interest rates of the loans were 3.7% at October 31, 2013 and 4.6% at January 31, 2013.

TUSA Credit Facility

On October 16, 2013, TUSA entered into Amendment No. 2 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. 2 amends that certain Amended and Restated Credit Agreement (the “A&R Credit Agreement”), dated April 11, 2013, as amended by that certain Amendment No. 1 to Amended and Restated Credit Agreement and Master Assignment, dated July 30, 2013 (the “Amended A&R Credit Agreement”), to (i) increase the borrowing base under the Amended A&R Credit Agreement from $165.0 million to $275.0 million, (ii) add JPMorgan Chase Bank, N.A., KeyBank National Association, and IBERIABANK as new lenders under the facility, (iii) extend the maturity date to October 16, 2018, and (iv) decrease the applicable margins for ABR and eurodollar advances by 0.25% at all utilization levels. Further, the existing lenders assigned a portion of their lending commitments to the three new lenders. The amendments in Amendment No. 1 remaining in force were (i) permits 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 (ii) make revisions enabling TUSA to enter into a second lien credit facility at a future date. As of October 31, 2013, TUSA, as borrower, had borrowings of $151.0 million outstanding under the TUSA Credit Facility.

The borrowing base under the TUSA Credit Facility is subject to redetermination by the beginning of 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 calendar year and two additional redeterminations after May 1, 2014 during any calendar 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 October 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).

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 October 31, 2013, $7.7 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

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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 had a maximum borrowing of $9.8 million at October 31, 2013. The loan bears interest at the daily three month LIBOR plus 4.50%. Payments on this loan are monthly principal payments of $0.4 million plus monthly accrued and unpaid interest. At October 31, 2013, $9.8 million was outstanding, the interest rate was 4.75% and accrued and unpaid interest was $0.04 million.

On November 18, 2013, the RockPile Credit Agreement was amended increasing the maximum borrowing limit to $17.3 million and the monthly principal payment to $0.6 million. All other terms of the original agreement remained in force.

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 principal payments of $0.07 million plus accrued and unpaid interest will be due. At October 31, 2013, the full $2.0 million was outstanding, the interest rate was 4.75% and accrued and unpaid interest was de minimis.

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 October 31, 2013, $1.8 million was outstanding, the interest rate was 4.25% and accrued interest was de minimis.

At October 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, RockPile’s subsidiary guarantors 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 October 31, 2013, RockPile was in compliance with all financial covenants under the Credit Facility.

Upon an event of default under the RockPile Credit Agreement, the Lender may terminate the commitments under the RockPile Credit Agreement and declare all amounts owing under the RockPile Credit Agreement to be due and payable. In addition, upon an event of default under the RockPile Credit Agreement, the Lender is empowered to exercise all rights and remedies of a secured party and foreclose upon the collateral securing the RockPile Credit Agreement, in addition to all other rights and remedies under the security documents described in the RockPile Credit Agreement.

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RockPile Notes Payable to Dacotah Bank

On February 15, 2013, Bakken Real Estate Development, LLC, a wholly-owned subsidiary of RockPile, entered into two loan agreements with Dacotah Bank in the amounts of $2.6 million for construction financing of its residential units in Dickinson, North Dakota and $3.3 million for construction financing of its administrative and maintenance facility in Dickinson, North Dakota. The loans have a fixed interest rate of 4.75% and a maturity date of December 31, 2013. Payments on the loans are interest only until maturity and the full principal balance is due on December 31, 2013. The construction mortgages are guaranteed by Triangle. At October 31, 2013, both loans were fully drawn and accrued and unpaid interest was de minimis.

RockPile Notes Payable to Sellers of Team Well Services

On October 16, 2013, RockPile issued two identical unsecured subordinated promissory notes to the sellers of Team Well Services. The notes each have a face value of $0.5 million and bear interest at a fixed rate of 1%. The loans have a maturity date of October 16, 2016, at which time the principal and accrued interest is due and payable. The aggregate carrying value of the loans at October 31, 2013 was $0.8 million. Over the term of the loans, the discount will be accreted on a monthly basis by increasing the carrying value of both notes and recording interest expense.

9. Commodity Derivative Instruments

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

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

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The Company has not designated any of its derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to its commodity derivative instruments. Net gains and losses on derivative activities are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on derivative activities are recorded in the gain (loss) from derivative activities line on the condensed consolidated statements of operations and comprehensive income (loss). The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s condensed consolidated statements of cash flows.

The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

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

Collars	Basis(1)	Quantity (Bbl/d)		Put Strike		Call Strike
May 1, 2013 - December 31, 2013	NYMEX	3,500	bopd	$85.00 - $97.00		$100.00 - $110.30
November 1, 2013 - December 31, 2013	NYMEX	1,000	bopd	$92.00		$106.85
January 1, 2014 - March 31, 2014	NYMEX	250	bopd	$85.00		$98.75
January 1, 2014 - June 30, 2014	NYMEX	750	bopd	$85.00 - $87.00		$100.80 - $101.00
April 1, 2014 - June 30, 2014	NYMEX	150	bopd	$84.25		$100.00
January 1, 2014 - December 31, 2014	NYMEX	2,750	bopd	$80.00 - $91.25		$98.00 - $101.20
July 1, 2014 - December 31, 2014	NYMEX	500	bopd	$83.50		$100.00
January 1, 2015 - December 31, 2015	NYMEX	1,500	bopd	$80.00		$94.50 - $96.65

Puts	Basis	Quantity (Bbl)		Average Strike Price ($/Bbl)
Expiring on December 16, 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 tables detail the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category (in thousands):

		As of October 31, 2013
Underlying Commodity	Balance Sheet Classification	Gross Amount of Recognized Assets (Liabilities)			Gross Amount of Offset			Net Amount of Assets (Liabilities)
Crude oil derivative contract	Current liabilities	$	(2,019	)	$	1,677		$	(342	)

Crude oil derivative contract	Non-current assets	$	2,824		$	(2,456	)	$	368

		As of January 31, 2013
Underlying Commodity	Balance Sheet Classification	Gross Amount of Recognized Assets (Liabilities)			Gross Amount of Offset			Net Amount of Assets (Liabilities)
Crude oil derivative contract	Current assets	$	1,305		$	(702	)	$	603

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

The Company recorded a gain of $2.1 million for the three months ended October 31, 2013 and a loss on derivative activities of $1.1 million for the nine months ended October 31, 2013. The Company recorded a net income on derivative activities of $1.4 million for the three and nine months ended October 31, 2012.

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10. Fair Value Measurements

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

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

· Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; 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 October 31, 2013 by level within the fair value hierarchy (in thousands):

	Level 1		Level 2			Level 3		Total
Assets:
Derivative assets	$	—	$	368		$	—	$	368

Liabilities:
Derivative liabilities	$	—	$	(342	)	$	—	$	(342	)
Earn-out liability	$	—	$	(1,499	)	$	—	$	(1,499	)
Note payable	$	—	$	(764	)	$	—	$	(764	)

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 October 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 Company determined the estimated fair value of the earn-out liability using a market approach based on information derived from an analysis performed for RockPile by an independent third-party. This analysis used publicly available information from market participants in the same industry, generally accepted methods for estimating an investor’s return requirements, and quoted market prices in active markets. As such, the earn-out liability has been classified as Level 2.

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The Company determined the estimated fair value of the note payable using a market approach based on several factors, including quoted market rates in active markets, and RockPile’s current cost of funds. As such, the note payable has been classified as Level 2.

The Convertible Note (carried at $127.7 million at October 31, 2013) has an estimated fair value at October 31, 2013 of $207.9 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 $10.57 per share at October 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	4,671
Total net unrecognized loss	70,345
Ending balance, October 31, 2013	$	207,916

11. Commitments and Contingencies

As of October 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. Non-compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on the Company’s financial position, results of operations or cash flows.

On September 12, 2013, TUSA and Caliber North Dakota LLC (“Caliber North Dakota”) amended and restated two midstream services agreements, which the parties originally entered into on October 1, 2012. Caliber North Dakota is a wholly-owned subsidiary of Caliber in which Triangle has a 30% ownership. The two original midstream services 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. The two agreements were revised to include an additional acreage dedication from TUSA to Caliber North Dakota and an increased firm volume commitment by Caliber North Dakota for each service line. The revenue commitment language included in the original midstream services agreements was removed and replaced by a stand-alone agreement.

Under the new revenue commitment agreement, TUSA maintained the commitment included in the original midstream services agreement to deliver minimum monthly revenues derived from the fees paid by TUSA to Caliber North Dakota 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 facilities (the date that the Caliber North Dakota central facility has been substantially completed and has commenced commercial operation — estimated to occur in the fourth quarter of fiscal year 2014) and added a commitment to deliver additional minimum monthly revenues derived from the fees paid by TUSA to Caliber North Dakota related to the increased acreage dedication and increased firm volume commitment. The additional minimum monthly revenue commitment will commence on the in-service date of the incremental Caliber North Dakota facilities (estimated to occur in the second quarter of fiscal year 2015). The minimum commitment over the term of the agreements is $405 million.

On September 12, 2013, TUSA and Caliber Measurement Services LLC (“Caliber Measurement”) entered into a gathering services agreement, pursuant to which Caliber North Dakota will provide measurement services necessary for gathering to TUSA.

For the nine months ended October 31, 2013, Caliber North Dakota had $10.8 million of revenue, $10.4 of which was from TUSA, mainly comprised of fresh water and water disposal revenues as well as well connect fees. (See Note 5 — Equity Investment).

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As of October 31, 2013 the Company was subject to commitments on three drilling rig contracts. The contracts expire between April 2014 and February 2015. In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $15.6 million as of October 31, 2013 as required under the terms of the contracts.

12. Supplemental Disclosures of Cash Flow Information

	For the Nine Months Ended October 31,
	2013		2012
	(in thousands)
Cash paid during the period for:
Interest expense	$	2,260	$	13

Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increased (decreased) accrued liabilities and decreased prepaid well costs	$	28,874	$	24,301
Issuance of common stock	$	2,435	$	1,912
Change in asset retirement obligations	$	608	$	310
Capitalized interest	$	1,193	$	—
Acquisition of pressure pumping and related services equipment through notes payable and liabilities	2,262		$	—

13. Income Taxes

The Company has net deferred tax assets as of October 31, 2013 primarily due to accumulated net operating losses. Deferred tax assets are reduced by a valuation allowance when, in the current 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 October 31, 2013 and 2012, a full valuation allowance was placed against net deferred tax assets.

There is no income tax expense or benefit for the three or nine months ended October 31, 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 October 31, 2013, the Company has not recognized any interest or penalties related to uncertain tax benefits.

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14. Asset Retirement Obligations

The following tables reflect the change in asset retirement obligations for the three and nine month periods ended October 31, 2013 (in thousands):

	For the Three Months Ended
	October 31, 2013
	USA			Canada			Total
Balance, July 31, 2013	$	1,951		$	1,096		$	3,047
Liabilities incurred	524			—			524
Revision of estimates	—			962			962
Sale of assets	(7		)	—			(7		)
Liabilities settled	—			—			—
Accretion	20			—			20
Balance, October 31, 2013	2,488			2,058			4,546
Less current portion of obligations	(500		)	(1,965		)	(2,465		)
Long-term asset retirement obligations	$	1,988		$	93		$	2,081

	For the Nine Months Ended
	October 31, 2013
	USA			Canada			Total
Balance, January 31, 2013	$	1,974		$	1,448		$	3,422
Liabilities incurred	814			—			814
Revision of estimates	(188		)	962			774
Sale of assets	(17		)	—			(17		)
Liabilities settled	(132		)	(352		)	(484		)
Accretion	37			—			37
Balance, October 31, 2013	2,488			2,058			4,546
Less current portion of obligations	(500		)	(1,965		)	(2,465		)
Long-term asset retirement obligations	$	1,988		$	93		$	2,081

Internal engineering re-assessment of Canadian asset retirement obligations resulted in a $1.0 million increase in the asset retirement obligations (“ARO”) as of October 31, 2013. Since our Canadian oil and natural gas properties were fully impaired, the ARO revision was expensed and included in Accretion and asset retirement obligation expense as asset retirement obligation expense in the accompanying condensed consolidated statements of operations and comprehensive income (loss) for the three-month period and nine-month period ended October 31, 2013.

The $2.5 million current liability at October 31, 2013 consists of (a) an estimated $2.0 million for reclamation of man-made “ponds” holding produced formation water and the plugging and abandonment of well bores in the Maritimes Basin of Canada, and (b) $0.5 million for the estimated remaining costs to plug and abandon several producing (but marginally economic) vertical wells drilled years ago on North Dakota leases we acquired in the second half of fiscal year 2013. These North Dakota leases are held by production. We intend to drill, complete and produce horizontal wells on the leases in fiscal year 2014 or early fiscal year 2015, allowing us to plug and abandon the marginally economic vertical wells and still hold the leases by production.

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15. Related Party Transactions

On September 12, 2013, TUSA and Caliber North Dakota amended and restated two midstream services agreements, which the parties originally entered into on October 1, 2012. Caliber North Dakota is a wholly-owned subsidiary of Caliber Midstream Partners, L.P., in which Triangle has a 30% ownership. The two original midstream services 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. The two agreements were revised to include an additional acreage dedication from TUSA to Caliber North Dakota and an increased firm volume commitment by Caliber North Dakota for each service line. The revenue commitment language included in the original midstream services agreements was removed and replaced by a stand-alone agreement.

On September 12, 2013, TUSA and Caliber Measurement entered into a gathering services agreement, pursuant to which Caliber Measurement will provide measurement services necessary for gathering to TUSA. Caliber Measurement also purchased Lease Automatic Custody Transfer (“LACT”) units from TUSA for $2.5 million, which is included in the balance of related party receivables in the accompanying condensed consolidated balance sheet.

For the nine months ended October 31, 2013, Caliber North Dakota, LLC had $10.8 million of revenue, $10.4 of which is from TUSA, mainly comprised of fresh water and water disposal revenues as well as well connect fees. See Note 5 — Equity Investment.

For the three and nine month periods ended October 31, 2013, Triangle received $0.3 million and $0.9 million, respectively, from Caliber for administrative services supplemental to those provided by Caliber employees and pursuant to the October 1, 2012 Services Agreement between Triangle and Caliber.

16. Subsequent Events

Amendment to RockPile Credit Facility

On November 18, 2013, the RockPile Credit Agreement was amended to increase the amount available under the equipment term loan by $7.5 million and increasing the monthly principal payments to $0.6 million. Following the amendment, the total amount available under the equipment term loan was $17.3 million. All other terms and conditions of the RockPile Credit Agreement and the related loan documents remain in full force and effect.

Amendment to Certificate of Incorporation

On December 4, 2013, the Company filed with the Delaware Secretary of State a Certificate of Amendment to the Certificate of Incorporation of Triangle Petroleum Corporation (the “Certificate of Amendment”). The Certificate of Amendment amended the Company’s Certificate of Incorporation to authorize 40,000,000 shares of preferred stock, par value $0.00001 per share. The Certificate of Amendment was effective upon filing.

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Hauck Apartments Mortgage

On November 20, 2013, RockPile closed on the purchase of a 12 unit apartment building in Dickinson, ND for a total purchase price of $1.8 million. The purchase was funded by cash on hand and a mortgage from Dacotah Bank in the amount of $1.5 million. The mortgage has a term of 15 years and bears interest at a variable rate equal to the Federal Home Loan Bank of Des Moines Five-Year Fixed-Rate Advance rate plus 2.70%. At the inception of the mortgage, the interest rate was 4.75%.

17. Significant Changes in Proved Oil and Natural Gas Reserves

Our proved oil and natural gas reserves at October 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 October 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 $89.81 per barrel of oil and $5.77 per Mcf of natural gas for the reserves presented as of October 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.

	% of		October 31, 2013			January 31,
	Reserves		Oil	Gas		2013	%
Reserve Category	(Mboe)		(MBbls)	(MMcf)	Mboe	Mboe	Change
Proved Developed	46	%	12,762	12,964	14,923	5,969	150	%
Proved Undeveloped	54	%	15,039	15,404	17,606	8,668	103	%
Total Proved	100	%	27,801	28,368	32,529	14,637	122	%

The primary reason for the increases in proved reserves is the drilling and completion of wells in the first nine months of fiscal year 2014 in addition to acquisitions in the third quarter of fiscal 2014. Our net interest in producing wells increased 168% from 16.0 net wells at January 31, 2013 to 42.9 net wells at October 31, 2013, and our net interest in proved undeveloped locations increased 116% from 19.8 net future development wells at January 31, 2013 to 42.7 net future development wells at October 31, 2013.

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

Forward-Looking Statements

Certain statements contained in this report and other materials we file with the U.S. Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “predict,” “strategy,” “expect,” “intend,” “plan,” “aim,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

Important factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include, but are not limited to, the following risks and uncertainties:

· our future capital expenditures and performance;

· the amount of oil and natural gas we produce;

· our business strategy;

· our future operating results;

· anticipated drilling and development;

· drilling results;

· closing and integration of significant acquisitions;

· substantial capital requirements and access to additional capital;

· our plans for, and the success of, RockPile Energy Services, LLC and Caliber Midstream Partners LP;

· oil and natural gas realized prices;

· marketing and distribution of oil and natural gas;

· government regulation of the oil and natural gas industry;

· potential regulation affecting hydraulic fracturing;

· uninsured or underinsured risks;

· defects in title to our oil and natural gas interests; and

· other factors discussed elsewhere in this report.

All of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to, or effect on, us or our business or operations. Also note that we provided additional cautionary discussion of risks and uncertainties under “Risk Factors” in our Fiscal 2013 Form 10-K, in our other public filings and in our press releases. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this report and in our future periodic reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report may not occur.

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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 October 31, 2013, we held leasehold interests in approximately 94,000 net acres in the Williston Basin, approximately 45,000 of which are in our core focus area primarily in McKenzie and Williams Counties, North Dakota, (“Core Acreage”). Our Core Acreage has a high oil saturation, is slightly over-pressured, and has the potential for multiple benches. The remaining approximately 49,000 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 natural gas reserves as of October 31, 2013 totaled 32,529 Mboe.

Our daily production for the fiscal quarter ended October 31, 2013 averaged approximately 6,804 Boepd of which 5,286 Boepd is net to our interests in wells we operate, our operated wells, and 1,518 Boepd is from wells operated by third-parties, our 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. Our fiscal year-end is January 31.

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 to form Caliber Midstream Partners LP, or Caliber. RockPile provides pressure pumping and other complementary well completion 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 started providing 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 reduce or eliminate the emissions generated by the flaring of produced natural gas. In addition to providing services to TUSA, RockPile and Caliber are focused on growing their respective businesses through securing independent, third-party contracts.

Summary of operating and financial results for nine months ended October 31, 2013:

· Production volumes totaled 1,261,865 Boe for the nine months ended October 31, 2013. This is an increase of 328% from 295,143 Boe for the nine months ended October 31, 2012.

· Oil and natural gas sales were $111.2 million compared to $23.1 million for the nine months ended October 31, 2012.

· Our average realized oil price increased to $92.21 per barrel compared to $83.23 per barrel in the first nine months of fiscal year 2013.

· Proved reserves were an estimated 32,529 Mboe at October 31, 2013 compared to 14,637 Mboe at January 31, 2013.

· Net income was $29.4 million for the nine months ended October 31, 2013 compared to a net loss of $5.2 million for the nine months ended October 31, 2012.

· Cash flow provided by operating activities was $15.7 million for the nine months ended October 31, 2013 compared to cash used in operating activities of $8.9 million for the nine months ended October 31, 2012.

· Drilled and completed 22 gross (16.55 net) operated wells during the first nine months of fiscal year 2014.

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Recent Events

Acquisition of Oil and Natural Gas Assets

On August 28, 2013, TUSA acquired from Kodiak Oil and Gas Company (“Kodiak”) certain oil and natural gas leaseholds located in McKenzie County, North Dakota comprising approximately 5,600 net acres, and various other related rights, permits, contracts, equipment and other assets for total consideration of $83.8 million. The effective date for this acquisition was July 1, 2013. Concurrently, we exchanged with Kodiak certain of the Company’s oil and natural gas leasehold interests for approximately 600 net acres of leasehold interests for a total of approximately 6,200 net acres. TUSA also entered into various other agreements with unrelated parties to acquire additional oil and natural gas properties. See Note 4 — Property and Equipment under Item 1 of this Quarterly Report for further discussion of acquisitions of oil and natural gas assets.

Production from the acquisitions completed in the third quarter of fiscal 2014 averaged 1,280 Boe per day, based on produced volumes in October 2013. The acquired leaseholds 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 increased (i) our total Core Acreage to approximately 45,000 net acres, and (ii) October 2013 net Boe sold to approximately 7,700 Boe per day. Additionally, the acquired leasehold, combined with successful down-spacing tests for Triangle and other operators, increases our inventory of future operated wells from six years to potentially eight 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 (“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 base Offering closed on August 14, 2013 and the Underwriters’ over-allotment option closed on September 11, 2013. The total net proceeds to the Company from the Offering and the exercise of the over-allotment option was approximately $101.8 million, after deducting underwriting discounts and commissions and other estimated offering expenses payable by the Company. See Note 6 — Stockholders’ Equity 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 ($80.8 million net of share issue costs) and concurrently entered into a Rights Agreement with ActOil. See Note 6 — Stockholders’ Equity under item 1 of this Quarterly Report for further discussion of this transaction.

Amendment to Senior Credit Facility and Increase in Borrowing Base

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three new lenders. The amendments in Amendment No. 1 remaining in force were (i) permits TUSA to hedge up to 85% of the anticipated production of oil, natural gas, and natural gas liquid volumes, respectively, attributable to TUSA’s total proved reserves, and (ii) make revisions enabling TUSA to enter into a second lien credit facility at a future date. As of October 31, 2013, TUSA, as borrower, had borrowings of $151.0 million outstanding under the TUSA Credit Facility.

Reserve Update

As of October 31, 2013, we have estimated proved reserves of 27.8 million barrels of oil and 28.4 million cubic feet of natural gas, or 32.5 million barrels of oil equivalent (MMboe). Our reserve quantities are comprised of 85% crude oil and 15% natural gas. The October 31, 2013 proved reserves reflect a 122% increase over the January 31, 2013 proved reserves of 14,637 MMboe. Our proved oil and natural gas reserves at October 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 reserves as of October 31, 2013:

	% of		October 31, 2013			January 31,
	Reserves		Oil	Gas		2013	%
Reserve Category	(Mboe)		(MBbls)	(MMcf)	Mboe	Mboe	Change

Proved Developed	46	%	12,762	12,964	14,923	5,969	150	%
Proved Undeveloped	54	%	15,039	15,404	17,606	8,668	103	%
Total Proved	100	%	27,801	28,368	32,529	14,637	122	%

In estimating the proved reserves presented above, we used the SEC’s definition of proved reserves. Projected future cash flows were based on economic and operating conditions as of October 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 October 31, 2013, such average pricing was $89.81 per barrel of oil and $5.77 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.

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.

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Drilling and Completions

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

	For the Three Months Ended October 31, 2013
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	9	5.00	9	6.26
Non-operated wells	21	0.55	29	1.51
	30	5.55	38	7.77

	For the Nine Months Ended October 31, 2013
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	27	18.73	22	16.55
Non-operated wells	56	2.96	71	4.22
	83	21.69	93	20.77

Properties, Plan of Operations and Capital Expenditures

We own operated and non-operated leasehold positions in the Williston Basin. As of October 31, 2013, we have completed a total of 38 (27.48 net) operated wells since entering the Williston Basin. During fiscal year 2014, we anticipate drilling approximately 33 (21.77 net) operated wells and completing approximately 32 (22.83 net) operated wells in North Dakota or eastern Montana. Of the 32 gross wells expected to be completed in fiscal year 2014, we have completed 22 gross wells and had an additional seven gross wells in progress as of October 31, 2013. Thirty of the wells are planned to be in the Bakken Shale and two are planned for the Three Forks formation. We also have economic interests in approximately 196 (19.55 net) non-operated wells.

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):

	Nine Months Ended October 31,
	2013		2012
Leasehold acquisitions	$	117,176	$	17,831
Drilling and Completion	207,321		98,303
Facilities and Infrastructure	1,610		1,799
	$	326,107	$	117,933

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U.S. Leaseholds

As of October 31, 2013, we had approximately 2,700 lease agreements representing approximately 219,000 gross and 94,000 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	92,632	30,169	44,962	10,456	137,594	40,625
Montana	696	406	81,081	52,635	81,777	53,041
Total Williston Basin	93,328	30,575	126,043	63,091	219,371	93,666

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, but 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 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. Since January 31, 2012, we have had no development of, and no production or revenues from, our leases in the Maritimes Basin.

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

For the fiscal quarter ended October 31, 2013, we recorded net income attributable to common stockholders of $17.4 million ($0.22 per share of common stock - basic and $0.20 per share of common stock - diluted) as compared to a net loss attributable to common stockholders of $0.6 million ($0.01 per share of common stock, basic and diluted) for the fiscal quarter ended October 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 natural gas revenues and operating expenses for the three months ended October 31, 2013 and 2012:

					Change
	Three Months Ended October 31,				Increase			% Increase
	2013		2012		(Decrease)			(Decrease)
Production volumes:
Crude oil (Bbls)	567,391		118,287		449,104			380	%
Natural gas (Mcf)	196,831		47,277		149,554			316	%
Natural gas liquids (Gallons)	1,081,043		67,896		1,013,147			1,492	%
Total barrels of oil equivalent (Boe)	625,935		127,783		498,152			390	%

Average realized prices:
Crude oil ($ per Bbl)	$	94.47	$	86.25	$	8.22		10	%
Natural gas ($ per Mcf)	$	4.46	$	4.06	$	0.40		10	%
Natural gas liquids ($ per gallon)	$	0.92	$	0.72	$	0.20		28	%
Total average realized price ($ per Boe)	$	88.63	$	81.72	$	6.91		8	%

Oil and natural gas revenues (in thousands):
Crude Oil	$	53,600	$	10,202	$	43,398		425	%
Natural gas	877		192		685			357	%
Natural gas liquids	1,000		49		951			1,939	%
Total oil and natural gas revenues	$	55,477	$	10,443	$	45,034		431	%

Operating expenses (in thousands):
Production taxes	$	6,161	$	1,202	$	4,959		412	%
Other lease operating expenses	4,443		1,410		3,033			215	%
Gathering, transportation and processing	1,443		28		1,415			5,054	%
Oil and natural gas amortization expense	16,800		3,300		13,500			409	%
Accretion of U.S. asset retirement obligations	20		5		15			301	%
Total operating expenses	$	28,867	$	5,945	$	22,922		386	%

Operating expenses per boe:
Production taxes	$	9.84	$	9.41	$	0.43		5	%
Other lease operating expense	$	7.10	$	11.03	$	(3.94	)	(36	)%
Gathering, transportation and processing	$	2.31	$	0.22	$	2.09		952	%
Oil and natural gas amortization expense	$	26.84	$	25.83	$	1.01		4	%

Oil and Natural Gas Revenues

Revenues from oil and natural gas production for the three months ended October 31, 2013 increased 431% to $55.5 million from $10.4 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) and acquisition of producing wells in the third quarter of fiscal 2014, partially offset by normal production decline. Average realized oil prices increased 10% to $94.47 per barrel from $86.25 per barrel in the same period in 2012. Average realized natural gas prices increased 10% to $4.46 per Mcf in the third quarter of fiscal year 2014 from $4.06 per Mcf in the same period in 2012.

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Production Taxes

Due primarily to the 431% increase in oil and natural gas revenues for the three months ended October 31, 2013, as compared with the three months ended October 31, 2012, our U.S. production taxes increased approximately 412% to $6.2 million from $1.2 million for the same respective period. North Dakota production tax rates for the past two years were generally 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 approximately $.08 per Mcf.

Lease Operating Expense

Lease operating expense (“LOE”) for U.S. operations decreased to $7.10 per Boe for the three months ended October 31, 2013 from $11.03 per Boe for the three months ended October 31, 2012. The cost decrease is primarily the result of (a) improvements in how we lift fluids to the well surface and how field equipment is powered for our operated properties and (b) elimination of the need for certain temporary workover activity and temporary equipment rental in the quarter ended October 31, 2012 with regards to operated wells.

Gathering, Transportation and Processing

Gathering, transportation and processing (“GTP”) expenses increased to $2.31 per Boe for the three months ended October 31, 2013 from $0.22 per Boe for the three months ended October 31, 2012. Going forward, we expect GTP costs to increase (along with sales prices) as Caliber’s crude oil and natural gas gathering, transportation and processing infrastructure becomes available for operated wells, allowing us to sell oil, natural gas and natural gas liquids downstream, rather than selling at the wellhead or flaring wet natural gas at the wellhead.

Oil and Natural Gas Amortization

Oil and natural gas amortization expense increased 409% to $16.8 million for the three months ended October 31, 2013 from $3.3 million for the three months ended October 31, 2012. The increase is primarily related to a 390% increase in production in the third quarter of fiscal year 2014 as compared to the third quarter of fiscal year 2013.

Pressure Pumping and Related Services Gross Profit

RockPile commenced operations in July 2012. We formed RockPile with strategic objectives to have both greater control over one of our largest cost centers as well as to provide locally-sourced, high-quality completion services to Triangle and other operators in the Williston Basin. From formation through October 31, 2013, RockPile has been focused on procuring new pressure pumping and complementary well completion equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, establishing third-party customers in the Williston Basin, and securing credit. 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 October 31, 2013, RockPile performed hydraulic fracturing and complementary services for Triangle and four distinct third-party customers utilizing two spreads of equipment. This work resulted in 28 total well completions: nine for Triangle and 19 for third-parties. Nine Triangle wells were completed using plug-and-perf applications. Six third-party wells were completed using plug-and-perf applications, 12 third-party wells were completed using a sliding sleeve application, and one third-party well was completed using a combination of plug and perf and sliding sleeve. 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 completion design and equipment utilization.

We recognized $2.3 million of gross profit from pressure pumping and related services for the three months ended October 31, 2013 after elimination of $11.2 million in intercompany gross profit. See Note 3 — Segment Reporting under Item 1 of this Quarterly Report.

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The table below is a summary of the RockPile contribution to our consolidated results for the three months ended October 31, 2013, after eliminations (in thousands):

	RockPile		Eliminations			Consolidated
Revenues
Pressure pumping and related services	$	65,998	$	(32,926	)	$	33,072
Total revenues	65,998		(32,926		)	33,072
Cost of Sales
Total depreciation and amortization	2,635		(1,020		)	1,615
Pressure pumping and related services	49,839		(20,675		)	29,164
Total Cost of Sales	52,474		(21,695		)	30,779
Gross profit	$	13,524	$	(11,231	)	$	2,293

General and Administrative Expenses

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

	Exploration and Production		Pressure Pumping and Related Services		Corporate		Consolidated Total
For the three months ended October 31, 2013
Stock-based compensation	$	328	$	148	$	1,981	$	2,457
Salaries, benefits and other general and administrative	2,346		3,150		2,605		8,101
Total	$	2,674	$	3,298	$	4,586	$	10,558
Excluded costs*	$	1,162	$	—	$	921	$	2,082

For the three months ended October 31, 2012
Stock-based compensation	$	602	$	—	$	905	$	1,507
Salaries, benefits and other general and administrative	1,588		1,685		1,595		4,868
Total	$	2,190	$	1,685	$	2,500	$	6,375
Excluded costs*	$	814	$	—	$	125	$	939

*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 natural 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 $4.2 million to $10.6 million at October 31, 2013 compared to $6.4 million at October 31, 2012. The increase in corporate general and administrative expenses 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 and Related 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 to manage its growth from initial operations in July 2012 to managing multiple frac spreads and other complementary well completion services at October 31, 2013.

Gain 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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measured at fair value and are included in the accompanying condensed consolidated balance sheets as derivative assets and liabilities. During the three months ended October 31, 2013, we recognized a $2.1 million gain on our commodity derivative positions due to decreases in underlying crude oil prices. Included in the net gain on our derivative activities were cash settlements we incurred on our commodity derivative instruments of approximately $0.8 million during the three months ended October 31, 2013. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. For additional discussion, please refer to Note 9 — Commodity Derivative Instruments under Item 1 of this Quarterly Report.

Interest Expense

The $2.0 million in interest expense for the three months ended October 31, 2013 consists of (a) approximately $1.1 million in interest and amortized fees related to the TUSA credit facility, (b) approximately $1.6 million in accrued interest and amortized fees related to our 5% convertible note with Natural Gas Partners (“NGP”), (c) approximately $0.2 million in interest expense associated with our RockPile credit facility and notes payable, and (d) a reduction of approximately $0.9 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $1.2 million of interest expense and capitalized interest was paid in cash. 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. Interest expense of $1.4 million for the three months ended October 31, 2012 is primarily related to our convertible note with NGP.

Results of Operations for the Nine Months Ended October 31, 2013 Compared to the Nine Months Ended October 31, 2012

For the nine months ended October 31, 2013, we recorded net income attributable to common stockholders of $29.4 million ($0.47 and $0.43 per share of common stock, basic and diluted, respectively) as compared to a net loss attributable to common stockholders of $4.6 million $0.10 per share of common stock, basic and diluted) for the nine months ended October 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 natural gas revenues and operating expenses for the nine months ended October 31, 2013 and 2012:

					Change
	Nine Months Ended October 31,				Increase			% Increase
	2013		2012		(Decrease)			(Decrease)
Production volumes:
Crude oil (Bbls)	1,177,751		268,139		909,612			339	%
Natural gas (Mcf)	326,707		142,293		184,414			130	%
Natural gas liquids (Gallons)	1,245,820		138,114		1,107,706			802	%
Total barrels of oil equivalent (Boe)	1,261,865		295,143		966,722			328	%

Average realized prices:
Crude oil ($ per Bbl)	$	92.21	$	83.23	$	8.98		11	%
Natural gas ($ per Mcf)	$	4.40	$	4.79	$	(0.39	)	(8	)%
Natural gas liquids ($ per Gallon)	$	0.91	$	0.89	$	0.02		2	%
Total average realized price ($ per Boe)	$	88.10	$	78.34	$	9.76		12	%

Oil and natural gas revenues (in thousands):
Crude Oil	$	108,601	$	22,318	$	86,283		387	%
Natural gas	1,437		682		755			111	%
Natural gas liquids	1,138		123		1,015			821	%
Total oil and natural gas revenues	$	111,176	$	23,123	$	88,053		381	%

Operating expenses (in thousands):
Production taxes	$	12,524	$	2,631	$	9,893		376	%
Other lease operating expenses	9,489		1,850		7,639			413	%
Gathering, transportation and processing	1,549		71		1,478			2,082	%
Oil and natural gas amortization expense	33,507		8,311		25,196			303	%
Accretion of U.S. asset retirement obligations	37		10		27			263	%
Total operating expenses	$	57,106	$	12,873	$	44,233		344	%

Operating expenses per boe:
Production taxes	$	9.92	$	8.91	$	1.01		11	%
Other lease operating expense	$	7.52	$	6.27	$	1.25		20	%
Gathering, transportation and processing	$	1.23	$	0.24	$	0.99		410	%
Oil and natural gas amortization expense	$	26.55	$	28.16	$	(1.61	)	(6	)%

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Oil and Natural Gas Revenues

Revenues from oil and natural gas production for the nine months ended October 31, 2013 increased 381% to $111.2 million from $23.1 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) and acquisition of producing wells in the third quarter of fiscal 2014, partially offset by normal production declines. Average realized oil prices increased 11% to $92.21 per barrel from $83.23 per barrel in the same period in 2012. Average realized natural gas prices decreased 8% to $4.40 per Mcf in the first nine months of fiscal year 2014 from $4.79 per Mcf in the same period in fiscal 2013.

Production Taxes

Due primarily to the 381% increase in oil and natural gas revenues for the nine months ended October 31, 2013, as compared with the nine months ended October 31, 2012, our U.S. production taxes increased approximately 376% to $12.5 million from $2.6 million. North Dakota production tax rates for the past two years were generally 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 approximately $.08 per Mcf.

Lease Operating Expense

LOE for U.S. operations increased to $7.52 per Boe for the nine months ended October 31, 2013 from $6.27 per Boe for the nine months ended October 31, 2012. The increase in LOE/Boe is primarily the result of the period ended October 31, 2012 having (1) a relatively high proportion (34%) of its oil sales related to the first three months of sales (when LOE/Boe is relatively low) for new producing wells and (2) relatively low workover expenses in the first two of the three months in the period.

Gathering, Transportation and Processing

GTP expenses increased to $1.23 per Boe for the nine months ended October 31, 2013 from $0.24 per Boe for the nine months ended October 31, 2012. For the first nine months of fiscal 2013, GTP costs were primarily associated with non-operated wells for the gathering and transportation of oil and natural gas. Going forward, we expect GTP costs to increase (along with sales prices) as Caliber’s crude oil and natural gas gathering, transportation and processing infrastructure becomes available for operated wells, allowing us to sell oil, natural gas and natural gas liquids downstream, rather than selling at the wellhead or flaring wet natural gas at the wellhead.

Oil and Natural Gas Amortization

Oil and natural gas amortization expense increased 303% to $33.5 million for the nine months ended October 31, 2013 from $8.3 million for the nine months ended October 31, 2012. The increase is primarily related to a 328% increase in production in the first nine months of fiscal year 2014 compared to the same period in fiscal year 2013.

Pressure Pumping and Related Services Gross Profit

The gross profit from pressure pumping and related services for the nine months ended October 31, 2013 was $6.0 million compared to $1.8 million for the first nine months of fiscal 2013. For the nine months ended October 31, 2013, RockPile performed hydraulic fracturing and complementary services for Triangle and six distinct third-party customers. This work resulted in 56 total well completions: 22 for Triangle and 34 for third-parties. Twenty-one Triangle wells were completed using plug-and-perf applications and one well was completed using a combination of plug and perf and sliding sleeve. Nine third-party wells were completed using plug-and-perf applications, 24 third-party wells were completed using a sliding sleeve application and one third-party well was completed using a combination of plug and perf and sliding sleeve.

The $6.0 million of gross profit from pressure pumping and related services for the nine months ended October 31, 2013 is after elimination of $26.4 million in intercompany gross profit. See Note 3 — Segment Reporting under Item 1 of this Quarterly Report for further discussion of gross profit elimination.

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

	RockPile		Eliminations			Consolidated
Revenues
Pressure pumping and related services	$	137,165	$	(75,104	)	$	62,061
Total revenues	137,165		(75,104		)	62,061
Cost of Sales
Total depreciation and amortization	5,474		(2,455		)	3,019
Pressure pumping and related services	99,330		(46,288		)	53,042
Total Cost of Sales	104,804		(48,743		)	56,061
Gross profit	$	32,361	$	(26,361	)	$	6,000

General and Administrative Expenses

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

	Exploration and Production		Pressure Pumping and Related Services		Corporate		Consolidated Total
For the nine months ended October 31, 2013
Stock-based compensation	$	897	$	458	$	4,134	$	5,489
Salaries, benefits and other general and administrative	5,378		7,575		5,499		18,452
Total	$	6,275	$	8,033	$	9,633	$	23,941
Excluded costs*	$	3,037	$	—	$	2,774	$	5,811

For the nine months ended October 31, 2012
Stock-based compensation	$	1,920	$	—	$	2,385	$	4,305
Salaries, benefits and other general and administrative	3,955		5,559		3,356		12,870
Total	$	5,875	$	5,559	$	5,741	$	17,175
Excluded costs*	$	1,608	$	—	$	125	$	1,733

Total general and administrative expense increased $6.7 million to $23.9 million for the nine months ended October 31, 2013 compared to $17.2 million for the nine months ended October 31, 2012. The increase in corporate general and administrative expense 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 and Related 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 to manage its growth from initial operations in July 2012 to managing multiple frac spreads and other complementary well completion services at October 31, 2013.

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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 measured at fair value and are included in the accompanying condensed consolidated balance sheets as derivative assets and liabilities. During the nine months ended October 31, 2013, we recognized a $1.1 million loss on our commodity derivative positions due primarily to the write-off of $1.4 million for the single-day put that settled worthless in the second quarter of fiscal 2014. Included in the net loss on our derivative activities were cash settlements we incurred on our commodity derivative instruments of approximately $0.8 million during the first nine months of fiscal 2014. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. For additional discussion, please refer to Note 9 — Commodity Derivative Instruments under Item 1 of this Quarterly Report.

Interest Expense

The $5.4 million in interest expense for the nine months ended October 31, 2013 consists of (a) approximately $2.0 million in interest and amortized fees related to the TUSA credit facility and approximately, (b) approximately $4.6 million in accrued interest and amortized fees related to our 5% convertible note with NGP, (c) approximately $0.6 million in interest expense associated with our RockPile credit facility and notes payable and (d) a reduction of approximately $2.0 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $2.3 million of interest and capitalized interest was paid in cash. 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. Interest expense of $1.5 million for the nine months ended October 31, 2012 is primarily related to our convertible note with NGP.

Other Income

During the nine months ended October 31, 2013 we realized approximately $1.1 million in income from other activities. This increase was primarily attributable to the gain from the sale of stock in Emerald Oil Inc., which we acquired in the January 9, 2013 sale of oil and natural gas leases to Emerald. See Note 2 — Basis of Presentation and Significant Accounting Policies — Investment in Marketable Securities under Item 1 of this 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 third quarter of fiscal year 2014, our average realized price for oil was $94.47 per barrel, an increase of 10% 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 October 31, 2013, we had cash of approximately $100.2 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 $124.0 million as of October 31, 2013.

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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 and RockPile credit facilities when needed, or that we would be able to 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 much 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 October 31, 2013, we had $299.0 million of debt outstanding. See Note 8 — Notes Payable and Credit Facilities under Item 1 of this Quarterly Report 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 $83.4 million as of October 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 public offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus or a prospectus supplement at the time of any such offering.

On August 8, 2013, we agreed to issue and sell to the Underwriters 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 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 and the Underwriters’ over-allotment option closed on September 11, 2013.

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The net proceeds to the Company from the Offering, including the exercise of the Underwriters’ over-allotment option, were 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.

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 to ActOil, which is an affiliate of TOGI.

Pursuant to the Stock Purchase Agreement, on August 28, 2013, the Company issued to ActOil 11,350,000 shares of common stock at $7.20 per share for net proceeds to the Company of $80.8 million after transaction costs and concurrently entered into a Rights Agreement (the “Rights Agreement”) with ActOil. Under the Rights Agreement, ActOil 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 ActOil from selling, pledging or otherwise disposing of the common stock acquired by ActOil 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.

Derivative Instruments

We utilize various derivative instruments in connection with anticipated crude oil sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Currently, we utilize costless collars and single-day puts. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments.

Fiscal Year 2014 Capital Expenditures Budget

Our fiscal year 2014 capital expenditures budget is subject to various factors, including market conditions, commodity prices and drilling results. We increased our fiscal year 2014 capital expenditure budget to a range of $430 to $465 million from the previously announced initial budget of $245 million, primarily to support the cost associated with our recent acquisitions, and increased operated and non-operated development programs.

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We will continue to monitor the timing of our drilling and completion activities and, if necessary, we will adjust our plans accordingly based on crude oil pricing and service costs.

Sources of Capital

Cash flow from operations. We expect our cash flow from operations to continue to increase commensurate with our anticipated increase in sales volumes. We have been able to increase our volumes on a quarter over quarter basis for the past two years. This increase is directly related to our successful operations as we have developed our properties. If we are able to continue to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, subject to the changes in the market price of crude oil, we would expect our production rates and operating cash flows to continue to increase for many years as we continue to develop our properties.

Credit facility. As of October 31, 2013, our maximum credit available under the TUSA credit facility was $500.0 million with a borrowing base of $275.0 million. As of October 31, 2013, we had available borrowing capacity under the TUSA credit facility of $124.0 million. The borrowing base under the TUSA credit facility is subject to redetermination by the beginning of 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 calendar year and two unscheduled redeterminations after May 1, 2014 during any calendar year.

On October 16, 2013, TUSA entered into Amendment No. 2 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. 2 amends that certain Amended and Restated Credit Agreement (the “A&R Credit Agreement”), dated April 11, 2013, as amended by Amendment No. 1 to Amended and Restated Credit Agreement and Master Assignment, dated July 30, 2013 (the “Amended A&R Credit Agreement”), to (i) increase the borrowing base under the Amended A&R Credit Agreement from $165.0 million to $275.0 million, (ii) add JPMorgan Chase Bank, N.A., KeyBank National Association, and IBERIABANK as new lenders under the facility, (iii) extend the maturity date to October 16, 2018, and (iv) decrease the applicable margins for ABR and eurodollar advances by 0.25% at all utilization levels. Further, the existing lenders assigned a portion of their lending commitments to the three new lenders. See Note 8 — Notes Payable and Credit Facilities under Item 1 of this Quarterly Report for further discussion.

Analysis of Changes in Cash Flows

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

	For the Nine Months Ended October 31,
	2013			2012			Change
Net cash provided by (used in) operating activities	$	15,739		$	(8,888	)	$	24,627
Net cash used in investing activities	(328,664		)	(132,078		)	(196,586		)
Net cash provided by financing activities	379,971			117,186			262,785
	$	67,046		$	(23,780	)	$	90,826

Net Cash Provided by (Used in) Operating Activities

Cash flows provided by operating activities was $15.7 million for the nine months ended October 31, 2013. Cash flows used in operating activities was $8.9 million for the nine months ended October 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 and related services business and the addition of a second frac spread, 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.

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Net Cash Used in Investing Activities

During the nine months ended October 31, 2013, we used $328.7 million of cash in investing activities as compared to $132.1 million during the nine months ended October 31, 2012. The increase in cash flows used in investing activities in the nine months ended October 31, 2013 was primarily due to our larger capital budget and drilling program, which used $294.3 million, and to the purchase of a second frac spread, facility construction and the purchase of equipment for complementary services at RockPile, which used $26.2 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 nine months ended October 31, 2013 totaled $380.0 million. The cash in-flow was primarily a result of (i) the issuance of 9.3 million shares of common stock to NGP for net proceeds of $55.8 million, (ii) the issuance of 325,000 shares of common stock of the Company to an unaffiliated oil and gas company at $7.50 per share for net proceeds of $2.4 million, (iii) the issuance of 17,250,000 shares of common stock in a public offering for net proceeds of $101.8 million, (iv) the issuance of 11,350,000 shares of common stock to ActOil at $7.20 per share for net proceeds of $80.8 million, and (iv) advances from notes payable and credit facilities.

Cash flows provided by financing activities in the nine months ended October 31, 2012 of $117.2 million was primarily a result of the proceeds from the $120.0 million Convertible Note. See Note 8 — Notes Payable and Credit Facilities under Item 1 of this Quarterly Report for further discussion.

Commodity Price Risk Management

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

We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil price volatility. While the use of these derivative instruments limits the downside risk of adverse price movements, these instruments may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period.

Set forth in the table below are our weighted average daily volumes covered by derivative agreements as of October 31, 2013, along with the associated weighted average floor and ceiling prices.

Fiscal Year	Weighted Average Daily Volumes (oil barrels)	Weighted Average Floor		Weighted Average Ceiling
2014	4,247	$	88.26	$	103.54
2015	3,282	$	84.78	$	99.88
2016	1,373	$	80.00	$	95.78

See Note 9 — Commodity Derivative Instruments under Item 1 of this Quarterly Report for additional details of our derivative financial instruments. See Item 3 — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk, for a presentation of our oil derivative contracts as of October 31, 2013.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our primary market risk is market changes in oil and natural gas prices. Market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties and may indirectly impact our prospective revenues from the sale of pressure pumping and related services. Currently, we use costless collars and single-day puts to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes. All derivative positions are accounted for using mark-to-market accounting.

We use costless collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled monthly. When the settlement price (the market price for oil or natural gas on the settlement date) for a period is above the ceiling price, we pay our counterparty. When the settlement price for a period is below the floor price, our counterparty is required to pay us.

We have used single day puts as a hedge against our minimum fee commitment to Caliber. We paid a cash premium for these contracts which are settled on specific days in the future. If the oil price is below the strike price on the date of settlement, we receive a cash settlement. If the oil price is above the strike price on the date of settlement, nothing is owed by the Company to the counterparty.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. TUSA is currently a party to derivative contracts with three counterparties. The Company has a netting arrangement with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparties. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, these instruments may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions.

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

Collars	Basis(1)	Quantity (Bbl/d)		Put Strike	Call Strike
May 1, 2013 - December 31, 2013	NYMEX	3,500	bopd	$85.00 - $97.00	$100.00 - $110.30
November 1, 2013 - December 31, 2013	NYMEX	1,000	bopd	$92.00	$106.85
January 1, 2014 - March 31, 2014	NYMEX	250	bopd	$85.00	$98.75
January 1, 2014 - June 30, 2014	NYMEX	750	bopd	$85.00 - $87.00	$100.80 - $101.00
April 1, 2014 - June 30, 2014	NYMEX	150	bopd	$84.25	$100.00
January 1, 2014 - December 31, 2014	NYMEX	2,750	bopd	$80.00 - $91.25	$98.00 - $101.20
July 1, 2014 - December 31, 2014	NYMEX	500	bopd	$83.50	$100.00
January 1, 2015 - December 31, 2015	NYMEX	1,500	bopd	$80.00	$94.50 - $96.65

Puts	Basis	Quantity (Bbl)	Average Strike Price ($/Bbl)
Expiring on December 16, 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.

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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.

The fair value of our derivative instruments at October 31, 2013 was a net asset of $.02 million. This mark-to-market net asset relates to derivative instruments with various terms that are scheduled to be realized over the period from November 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 October 31, 2013. An assumed increase of 10% in the forward commodity prices used in the October 31, 2013 valuation of our derivative instruments would result in a net derivative liability of approximately $13.5 million at October 31, 2013. Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $10.9 million at October 31, 2013.

Interest Rate Risk

At October 31, 2013, TUSA had $127.7 million outstanding under the convertible note with NGP, all of which has a fixed interest rate of 5%. Such interest is paid-in-kind by adding to the principal balance of the convertible note; provided that, after July 31, 2017, we have the option to make such interest payments in cash.

As of October 31, 2013, TUSA had $275.0 million available for borrowing under its credit facility, $151.0 million of which was drawn as of such date. The credit facility bears interest at variable rates. Assuming TUSA had the maximum amount outstanding at October 31, 2013 under our credit facility of $275.0 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $2.8 million. For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 12 — Long-Term Debt in our audited financial statements included in our Fiscal 2013 Form 10-K and Note 8 — Notes Payable and Credit Facilities under Item 1 of this Quarterly Report.

RockPile Interest Rate Risk

As of October 31, 2013, RockPile had $19.3 million available for borrowing under its credit facility of which $13.6 million was drawn as of such date. The credit facility bears interest at variable rates. Assuming RockPile had the maximum amount outstanding at October 31, 2013 under the credit facility of $19.3 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $0.2 million. For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 12 — Long-Term Debt in our audited financial statements included in our Fiscal 2013 Form 10-K and Note 8 — Notes Payable and Credit Facilities under Item 1 of this Quarterly Report.

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ITEM 4. CONTROLS AND PROCEDURES

Material Weakness in Internal Control over Financial Reporting

As previously discussed in Item 9A “Controls and Procedures” of our Fiscal 2013 Form 10-K, we reported a material weakness, related to previously recognized pressure pumping income that was not properly eliminated.

Evaluation of Disclosure Controls and Procedures

We have performed an evaluation under the supervision, and with the participation of our management, including our Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on (i) the ineffectiveness of the design of controls solely related to previously recognized pressure pumping income that was not properly eliminated and (ii) the need to evaluate if the additional review procedures over service income have been operating effectively for an adequate period of time, our Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer concluded that the Company’s disclosure controls and procedures were not effective as of October 31, 2013.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting, other than as described below, (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended October 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the nine months ended October 31, 2013, we took steps to remediate the material internal control weakness related to previously recognized pressure pumping income reported in our fiscal year 2013 Form 10-K. In the six months ended July 31, 2013, we had updated our accounting policies, schedules and procedures for pressure pumping income and similar income from services performed by RockPile Energy Services, LLC in connection with properties in which Triangle Petroleum Corporation or an affiliate holds an economic interest. In the three months ended October 31, 2013, we developed or updated accounting policies, schedules and procedures for our equity interest in Caliber Midstream Partners, L.P.’s, with regard to Triangle Petroleum Corporation’s share of income from Caliber Midstream Partners, L.P. services in connection with properties in which Triangle Petroleum Corporation or an affiliate holds an economic interest.

In response to anticipated growth in our businesses and that of Caliber Midstream Partners, L.P., we continue to add accounting, financial reporting and technical accounting resources. Specifically we recently added the following senior accounting and internal control professionals:

· Senior Vice President of Accounting, Triangle Petroleum Corporation;

· Internal Audit Director, Triangle Petroleum Corporation; and,

· Vice President of Accounting, Triangle USA Petroleum Corporation

Additionally during the quarter ended October 31, 2013, we completed our evaluation and selection of new accounting and land information systems, began implementation and have targeted an implementation go-live date for these systems in the third quarter of fiscal year 2015.

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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 risk factors, there have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the fiscal year ended January 31, 2013. Those risk factors, in addition to the risk factors listed below, 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 October 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 to NGP in July 2012 of our convertible note with an initial principal amount of $120.0 million (the “Convertible Note”), we entered into an Investment Agreement with NGP Triangle Holdings, LLC, an affiliate of 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

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conversion price of $8.00 per share, which, based on the initial principal amount, would allow the Convertible Note to be converted into 15,000,000 shares of common stock plus any shares issuable upon the conversion of accrued interest. 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 13% 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 into our operations of recently acquired producing oil and natural gas properties 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.

As previously reported in the Company’s Quarterly Report on Form 10-Q filed with the SEC on September 9, 2013, on August 2, 2013, TUSA entered into and closed definitive purchase and sale agreements with OGR Bakken Resources, LLC and ODP AIVII, 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 natural 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, as well as in the Company’s Quarterly Report on Form 10-Q filed with the SEC on September 9, 2013, on August 6, 2013, the Company entered into the Stock Purchase Agreement with 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

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share, for gross proceeds to the Company of $81.72 million. The Company paid advisory fees of $0.8 million 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.

The table below provides a summary of shares of our common stock surrendered to us in payment of tax liability in connection with the vesting of restricted stock units during the three months ended October 31, 2013:

	Total Number of Shares Purchased (1)	Average Price Paid Per Share (2)
August 1, 2013 to August 31, 2013	7,832	$	6.67
September 1, 2013 to September 30, 2013	11,243	7.81
October 1, 2013 to October 31, 2013	8,346	10.44
	27,421	$	8.29

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

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

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not Applicable.

Item 5. Other Information.

Amendment to Certificate of Incorporation

As previously reported on a Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 2013, at the Company’s 2013 Annual Meeting of Stockholders held on August 30, 2013, the Company’s stockholders approved an amendment to the Company’s Certificate of Incorporation to authorize 40,000,000 shares of preferred stock, par value $0.00001 per share (the “Preferred Stock Authorization”).

On December 4, 2013, the Company filed with the Delaware Secretary of State a Certificate of Amendment to the Certificate of Incorporation of Triangle Petroleum Corporation (the “Certificate of Amendment”). The Certificate of Amendment amended the Company’s Certificate of Incorporation to authorize 40,000,000 of preferred stock, par value $0.00001 per share (the “Preferred Stock”). The Certificate of Amendment was effective upon filing.

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The foregoing description of the Certificate of Amendment is not complete and is qualified in its entirety by reference to the complete text of the Certificate of Amendment, which is attached as Exhibit 3.2 to this Quarterly Report and incorporated in this Item 5. Other Information by reference.

As indicated in the Company’s Proxy Statement for its 2013 Annual Meeting of Stockholders, which was filed with the Securities and Exchange Commission on July 25, 2013, the Preferred Stock Authorization was prompted by business and financial considerations and not by the threat of any known or threatened hostile takeover attempt. Further, the Company’s board of directors represented that it will not, without prior stockholder approval, approve the issuance or use of any of the Preferred Stock for any defensive or anti-takeover purpose or for the purpose of implementing any stockholder rights plan. The Company has no current plans to issue Preferred Stock.

Appointment of Principal Accounting Officer

As previously reported in a Form 8-K filed with the SEC on June 20, 2013, Joseph B. Feiten, the Company’s Principal Accounting Officer, will retire from the Company effective December 10, 2013. On December 4, 2014, the Company appointed Steven Stophel, Senior Vice President of Accounting, to serve as its principal accounting officer effective upon Mr. Feiten’s retirement.

Mr. Stophel, 53, has served as the Senior Vice President of Accounting since joining the Company on October 29, 2013. Prior to joining the Company, he was a senior director with Alvarez & Marsal Business Consulting’s energy practice from July 2011 to October 2013, specializing in interim senior financial management roles in the oil & gas industry, post-merger financial integration, business and financial process improvement, Securities and Exchange Commission financial reporting and compliance, public listing readiness and complex accounting matters. Prior to joining Alvarez & Marsal, Mr. Stophel held senior positions in the international consulting and public accounting firms of Opportune LLP (2010-2011), KPMG LLP (2006-2010) and Arthur Andersen LLP (1989-1999). Mr. Stophel was the Chief Financial Officer for Reuters (CIS) in the former Soviet Union (2001 — 2005) and Director of Finance for MediaOne International’s subsidiary, Russian Telecommunications Development Corporation (1999-2001). Mr. Stophel earned a bachelor degree in professional accounting from Regis University and is a Certified Public Accountant in Colorado and a Certified Internal Auditor. He is a member of the Colorado Society of CPAs, the American Institute of CPAs, the Council of Petroleum Accountants Societies and the Institute of Internal Auditors.

Mr. Stophel did not enter into any material plan, contract or arrangement with the Company in connection with his appointment to serve as principal accounting officer. Mr. Stophel has no family relationship with any director or executive officer of the Company and has not been involved in any related person transactions that would require disclosure pursuant to Item 404(a) of Regulation S-K.

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Item 6. Exhibits.

3.1		Certificate of Incorporation of Triangle Petroleum Corporation.*
3.2		Certificate of Amendment to the Certificate of Incorporation of Triangle Petroleum Corporation.*
3.3		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.
10.1		Purchase and Sale Agreement, dated August 5, 2013, by and among Kodiak Oil & Gas (USA) Inc. and Kodiak Williston, LLC, collectively, as Seller, and Triangle USA Petroleum Corporation, as Purchaser, filed as Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 2013 and incorporated herein by reference.
10.2		Stock Purchase Agreement, dated August 6, 2013, between Triangle Petroleum Corporation and TIAA Oil and Gas Investments, LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 2013 and incorporated herein by reference.
10.3		Rights Agreement, dated August 28, 2013, between Triangle Petroleum Corporation and ActOil Bakken, LLC, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 2013 and incorporated herein by reference.
10.4		Amended and Restated Contribution Agreement, dated September 12, 2013, by and among Triangle Caliber Holdings, LLC, Caliber Midstream GP LLC, Caliber Midstream Partners, L.P., and FREIF Caliber Holdings LLC, filed as Exhibit 1.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 17, 2013 and incorporated herein by reference.
10.5		Amendment No. 2 to Amended and Restated Credit Agreement and Master Assignment, dated October 16, 2013, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Issuing Lender, and the Lenders Named Herein, as Lenders, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 22, 2013 and incorporated herein by reference.
10.6		First Amendment to Credit and Security Agreement, dated November 18, 2013, between RockPile Energy Services, LLC and Wells Fargo Bank, National Association, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 22, 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*

* Filed herewith.

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SIGNATURES

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

TRIANGLE PETROLEUM CORPORATION

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

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

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Triangle Petroleum (TPLMQ) Inactive 10-Q2014 Q3 Quarterly report

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