Triangle Petroleum Corp - FORM 10-Q

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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, 2014

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 smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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 5, 2014, there were 76,611,272 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, 2014

PART I. FINANCIAL INFORMATION

	ITEM 1.	Financial Statements

		Condensed Consolidated Balance Sheets — October 31, 2014 and January 31, 2014	3

		Condensed Consolidated Statements of Operations — Three and Nine months ended October 31, 2014 and 2013	5

		Condensed Consolidated Statements of Cash Flows — Nine months ended October 31, 2014 and 2013	6

		Condensed Consolidated Statement of Stockholders’ Equity — Nine months ended October 31, 2014	7

		Notes to the Condensed Consolidated Financial Statements	8

	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	44

	ITEM 4.	Controls and Procedures	46

PART II. OTHER INFORMATION

	ITEM 1.	Legal Proceedings	47
	ITEM 1A.	Risk Factors	47
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
	ITEM 3.	Defaults Upon Senior Securities	48
	ITEM 4.	Mine Safety Disclosures	48
	ITEM 5.	Other Information	48
	ITEM 6.	Exhibits	48

	SIGNATURES		49

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets

(In thousands, except share data)

(Unaudited)

	October 31, 2014			January 31, 2014
ASSETS
CURRENT ASSETS
Cash and equivalents	$	53,236		$	81,750
Accounts receivable:
Oil, natural gas and natural gas liquids sales	31,482			20,450
Trade	166,668			86,074
Commodity derivative assets	18,918			955
Deferred tax asset	321			321
Inventory, deposits and prepaid expenses	7,839			6,248
Total current assets	278,464			195,798

LONG-TERM ASSETS
Oil and natural gas properties, at cost, full cost method of accounting:
Unproved properties and properties under development, not being amortized	150,652			121,393
Proved properties	1,054,382			629,051
Total oil and natural gas properties	1,205,034			750,444
Less: accumulated amortization	(137,673		)	(67,657		)
Net oil and natural gas properties	1,067,361			682,787
Oilfield services equipment, net	80,114			46,586
Other property and equipment, net	32,579			24,507
Equity investment	74,124			68,536
Goodwill	1,680			1,680
Intangible assets, net	3,475			3,862
Commodity derivative assets	449			1,192
Other long-term assets	12,125			2,636
Total assets	$	1,550,371		$	1,027,584

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

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Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets

(In thousands, except share data)

(Unaudited)

	October 31, 2014		January 31, 2014
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	101,752	$	60,016
Accrued liabilities:
Exploration and development	87,337		34,131
Other	91,911		53,037
Current portion of long-term debt	416		8,851
Asset retirement obligations	3,457		3,333
Total current liabilities	284,873		159,368

LONG-TERM LIABILITIES
5% convertible note	134,200		129,290
Borrowings on credit facilities	84,616		196,065
Other notes and mortgages payable	9,759		9,002
TUSA 6.75% notes	450,000		—
Asset retirement obligations	2,878		1,296
Deferred tax liability	47,085		8,262
Other	1,220		1,139
Total liabilities	1,014,631		504,422

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Common stock, $0.00001 par value, 140,000,000 shares authorized; 81,440,082 and 85,735,827 shares issued and outstanding at October 31, 2014 and January 31, 2014, respectively	1		1
Additional paid-in capital	535,739		571,701
Retained earnings (accumulated deficit)	—		(48,540		)
Total stockholders’ equity	535,740		523,162
Total liabilities and stockholders’ equity	$	1,550,371	$	1,027,584

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

(In thousands, except per share data)

(Unaudited)

	For the Three Months Ended October 31,						For the Nine Months Ended October 31,
	2014			2013			2014			2013
REVENUES:
Oil, natural gas and natural gas liquids sales	$	80,139		$	55,477		$	221,479		$	111,176
Oilfield services	94,057			33,072			194,488			62,061
Total revenues	174,196			88,549			415,967			173,237
EXPENSES:
Production taxes	8,637			6,161			23,662			12,524
Lease operating expenses	7,454			4,443			18,741			9,489
Gathering, transportation and processing	4,380			1,443			11,915			1,549
Depreciation and amortization	32,581			18,609			80,465			37,000
Accretion of asset retirement obligations	149			983			324			1,000
Oilfield services	70,857			29,164			142,121			53,042
General and administrative, net of amounts capitalized:
Stock-based compensation	1,827			2,457			5,642			5,489
Salaries and benefits	7,725			4,740			20,519			11,998
Other general and administrative	7,241			3,389			18,124			6,684
Total operating expenses	140,851			71,389			321,513			138,775

INCOME FROM OPERATIONS	33,345			17,160			94,454			34,462

OTHER INCOME (EXPENSE):
Gain on equity investment derivatives	742			35,832			3,662			35,832
Gain (loss) from commodity derivatives	19,822			2,123			13,445			(1,064		)
Interest expense	(9,463		)	(1,993		)	(17,712		)	(5,434		)
Income from equity investment	393			—			457			—
Interest income	39			53			146			133
Other income (loss)	(180		)	15			(310		)	1,272
Total other income (expense)	11,353			36,030			(312		)	30,739

NET INCOME BEFORE INCOME TAXES	44,698			53,190			94,142			65,201
Income tax provision	(19,300		)	(5,969		)	(39,650		)	(5,969		)
NET INCOME	$	25,398		$	47,221		$	54,492		$	59,232

Net income per common share outstanding:
Basic	$	0.30		$	0.60		$	0.64		$	0.94
Diluted	$	0.26		$	0.50		$	0.55		$	0.78

Weighted average common shares outstanding:
Basic	85,242			79,059			85,769			62,817
Diluted	102,954			96,042			103,421			78,865

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,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	54,492		$	59,232
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	80,465			37,000
Stock-based compensation	5,642			5,489
Interest expense not paid in cash	12,040			3,936
Accretion of asset retirement obligations	324			1,000
(Gain) loss on commodity derivatives	(13,445		)	1,064
Gain on equity investment derivatives	(3,662		)	(35,832		)
Settlements of commodity derivative instruments	(3,775		)	(779		)
Income from equity investment	(457		)	—
Unrealized income on securities held for investment	—			(1,040		)
Deferred income taxes	38,823			5,969
Changes in related current assets and current liabilities:
Accounts receivable:
Oil and natural gas sales	(11,032		)	(16,823		)
Trade	(80,594		)	(42,123		)
Related party	—			(2,031		)
Inventory, deposits and prepaid expenses	(157		)	(1,775		)
Accounts payable and accrued liabilities	21,724			2,936
Asset retirement expenditures	(137		)	(484		)
Other	2,172			—
Cash provided by operating activities	102,423			15,739

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures and acquisitions	(351,156		)	(294,283		)
Purchases of oilfield services equipment	(41,263		)	(26,201		)
Purchases of other property and equipment	(12,079		)	(5,285		)
Equity investment in Caliber Midstream Partners, L.P.	—			(9,000		)
Sale of marketable securities	—			6,105
Sale of oil and natural gas properties	1,500			—
Other	188			—
Cash used in investing activities	(402,810		)	(328,664		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock	—			245,333
Stock offering costs	—			(7,059		)
Proceeds from credit facilities	313,616			170,320
Repayments of credit facilities	(433,515		)	(30,700		)
Proceeds from notes payable	450,000			5,876
Repayments of other notes and mortgages payable	(300		)	—
Debt issuance costs	(12,714		)	(2,406		)
Cash paid to settle tax on vested restricted stock units	(2,666		)	(1,510		)
Issuance of common stock on exercise of options	—			117
Common stock repurchased and retired	(42,548		)	—
Cash provided by financing activities	271,873			379,971

NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS	(28,514		)	67,046
CASH AND EQUIVALENTS, BEGINNING OF PERIOD	81,750			33,117
CASH AND EQUIVALENTS, END OF PERIOD	$	53,236		$	100,163

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, 2014

(in thousands, except share data)

(Unaudited)

	Shares of Common Stock		Common Stock at Par Value		Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Total Equity
Balance - January 31, 2014	85,735,827		$	1	$	571,701		$	(48,540	)	$	523,162
Vesting of restricted stock units (net of shares surrendered for taxes)	635,999		—		(2,666		)	—			(2,666		)
Redeemed RockPile B-Units	—		—		(1,041		)	—			(1,041		)
Shares repurchased and retired	(4,931,744	)	—		(38,790		)	(5,952		)	(44,742		)
Stock-based compensation	—		—		6,535			—			6,535
Net income for the period	—		—		—			54,492			54,492
Balance - October 31, 2014	81,440,082		$	1	$	535,739		$	—		$	535,740

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

October 31, 2014

(Unaudited)

1. DESCRIPTION OF BUSINESS

Triangle Petroleum Corporation (“we,” “us,” “our,” the “Company,” or “Triangle”) is a growth-oriented, independent energy holding company with three principal lines of business: oil and natural gas exploration, development and production; oilfield services; and midstream services.

We hold leasehold interests and conduct our operations in the Williston Basin of North Dakota and Montana. Our core focus area is in McKenzie and Williams counties, North Dakota, and eastern Roosevelt and Sheridan counties, Montana (collectively, our “Core Acreage”). 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 oilfield and complementary well completion services to oil and natural gas exploration and production companies primarily in the Williston Basin. RockPile began operations in July 2012.

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 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.

2. BASIS OF PRESENTATION

These unaudited condensed consolidated financial statements as of October 31, 2014, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and are expressed in U.S. dollars. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the Securities and Exchange Commission (“SEC”), and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts.

Certain information and footnote disclosures normally included in our annual financial statements prepared in accordance with 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, 2014, as filed with the SEC (the “Fiscal 2014 Form 10-K”).

In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the three and nine months ended October 31, 2014, are not necessarily indicative of the operating results for the entire fiscal year ending January 31, 2015.

No condensed consolidated statement of comprehensive income (loss) is presented because the Company had no comprehensive income or loss activity in the periods presented.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Management believes the major estimates and assumptions impacting our condensed consolidated financial statements are the following:

· estimates of proved reserves of oil and natural gas, which affect the calculations of amortization and consideration of any possible impairment of capitalized costs of proved oil and natural gas properties;

· estimates of the fair value of unproved oil and natural gas properties we own and the consideration of any possible impairment;

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· assumptions impacting our estimates as to the future realization of deferred income tax assets and the amount of our deferred tax liabilities;

· consideration of any impairment of our other long-term assets;

· depreciation of property and equipment; and

· valuation of derivative instruments.

Actual results may differ from estimates and assumptions of future events. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.

Principles of Consolidation

The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying condensed consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20.0% and 50.0% and exercises significant influence. Triangle Caliber Holdings, LLC, a wholly-owned subsidiary of Triangle, is a joint venture partner in Caliber. The Company’s investment in Caliber is accounted for utilizing the equity method of accounting.

Reclassifications

Certain amounts in the condensed consolidated balance sheet as of January 31, 2014, and in our condensed consolidated statement of operations for the three and nine months ended October 31, 2013, have been reclassified to conform to the financial statement presentation for the period ended October 31, 2014. Such reclassifications had no impact on consolidated total assets, stockholders’ equity or net income previously reported.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

There have been no material changes to the Company’s significant accounting policies and estimates from those disclosed in Note 3 - Summary of Significant Accounting Policies in our audited financial statements included in our Fiscal 2014 Form 10-K.

New Pronouncements Issued But Not Yet Adopted

In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014. Adoption of this amendment will not have a material effect on our financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective for the Company beginning in fiscal year 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the effect that adopting this new accounting guidance will have on our consolidated results of operations, cash flows and financial position.

In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact. Management will be required to make this evaluation for both annual and interim reporting periods, if applicable. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review new pronouncements to determine their impact, if any, on our condensed consolidated financial statements. Other than the standards discussed above, there are no significant accounting standards applicable to Triangle which have not been adopted.

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4. SEGMENT REPORTING

We conduct our operations within 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 nearly all operations are in the Williston Basin of the United States. The Exploration and Production operating segment, consisting of TUSA and several insignificant oil and gas subsidiaries, is responsible for finding and producing oil and natural gas. The Oilfield Services segment, consisting of RockPile and several insignificant oilfield service subsidiaries, is responsible for a variety of oilfield and complementary services for both Triangle-operated wells and wells operated by third-parties. Corporate and Other includes our corporate office and several subsidiaries that management does not consider to be part of the Exploration and Production or Oilfield Services segments. Also included in Corporate and Other are our results from our investment in Caliber, including any changes in the fair value of our equity investment derivatives.

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, 2014 and 2013:

	For the Three Months Ended October 31, 2014
(in thousands)	Exploration and Production		Oilfield Services			Corporate and Other			Eliminations			Consolidated Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	80,139	$	—		$	—		$	—		$	80,139
Oilfield services for third parties	—		96,810			—			(2,753		)	94,057
Intersegment revenues	—		46,941			—			(46,941		)	—
Total revenues	80,139		143,751			—			(49,694		)	174,196
Expenses:
Production taxes and other lease operating	16,091		—			—			—			16,091
Gathering, transportation and processing	4,380		—			—			—			4,380
Depreciation and amortization	27,998		6,249			125			(1,791		)	32,581
Accretion of asset retirement obligations	149		—			—			—			149
Cost of oilfield services	—		102,762			—			(31,905		)	70,857
General and administrative, net of amounts
Stock-based compensation	93		146			1,588			—			1,827
Other general and administrative	4,230		7,310			3,426			—			14,966
Total operating expenses	52,941		116,467			5,139			(33,696		)	140,851
Income (loss) from operations	27,198		27,284			(5,139		)	(15,998		)	33,345
Other income (expense), net	12,263		(695		)	443			(658		)	11,353
Net income (loss) before income taxes	$	39,461	$	26,589		$	(4,696	)	$	(16,656	)	$	44,698

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	For the Three Months Ended October 31, 2013
(in thousands)	Exploration and Production		Oilfield Services			Corporate and Other			Eliminations			Consolidated Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	55,477	$	—		$	—		$	—		$	55,477
Oilfield services for third parties	—		33,498			—			(426		)	33,072
Intersegment revenues	—		32,681			—			(32,681		)	—
Total revenues	55,477		66,179			—			(33,107		)	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		2,700			100			(1,020		)	18,609
Accretion of asset retirement obligations	983		—			—			—			983
Cost of oilfield services	—		49,839			—			(20,675		)	29,164
General and administrative, net of amounts
Stock-based compensation	328		148			1,981			—			2,457
Other general and administrative	2,594		3,150			2,385			—			8,129
Total operating expenses	32,781		55,837			4,466			(21,695		)	71,389
Income (loss) from operations	22,696		10,342			(4,466		)	(11,412		)	17,160
Other income (expense), net	1,553		(242		)	35,103			(384		)	36,030
Net income (loss) before income taxes	$	24,249	$	10,100		$	30,637		$	(11,796	)	$	53,190

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The following tables present selected financial information for our operating segments for the nine months ended October 31, 2014 and 2013:

	For the Nine Months Ended October 31, 2014
(in thousands)	Exploration and Production		Oilfield Services			Corporate and Other			Eliminations			Consolidated Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	221,479	$	—		$	—		$	—		$	221,479
Oilfield services for third parties	—		200,460			—			(5,972		)	194,488
Intersegment revenues	—		107,227			—			(107,227		)	—
Total revenues	221,479		307,687			—			(113,199		)	415,967
Expenses
Production taxes and other lease operating	42,403		—			—			—			42,403
Gathering, transportation and processing	11,915		—			—			—			11,915
Depreciation and amortization	70,049		14,619			397			(4,600		)	80,465
Accretion of asset retirement obligations	324		—			—			—			324
Cost of oilfield services	—		215,340			—			(73,219		)	142,121
General and administrative, net of amounts
Stock-based compensation	832		363			4,447			—			5,642
Other general and administrative	11,450		17,660			9,533			—			38,643
Total operating expenses	136,973		247,982			14,377			(77,819		)	321,513
Income (loss) from operations	84,506		59,705			(14,377		)	(35,380		)	94,454
Other income (expense), net	1,292		(1,869		)	1,734			(1,469		)	(312		)
Net income (loss) before income taxes	$	85,798	$	57,836		$	(12,643	)	$	(36,849	)	$	94,142

	As of October 31, 2014
Net oil and natural gas properties	$	1,152,302	$	—		$	—		$	(84,941	)	$	1,067,361
Oilfield services equipment - net	$	—	$	80,114		$	—		$	—		$	80,114
Other property and equipment - net	$	6,714	$	23,946		$	1,919		$	—		$	32,579
Total assets (1)	$	1,338,162	$	225,924		$	96,240		$	(109,955	)	$	1,550,371
Total liabilities	$	763,964	$	131,445		$	138,196		$	(18,974	)	$	1,014,631

(1) Our Corporate and Other total assets consist primarily of cash and cash equivalents of $14.1 million and our investment in Caliber of $74.1 million, in addition to the Company’s investment in subsidiaries the results of which are subsequently eliminated.

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	For the Nine Months Ended October 31, 2013
(in thousands)	Exploration and Production			Oilfield Services			Corporate and Other			Eliminations			Consolidated Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	111,176		$	—		$	—		$	—		$	111,176
Oilfield services for third parties	—			65,780			—			(3,719		)	62,061
Intersegment revenues	—			72,116			—			(72,116		)	—
Total revenues	111,176			137,896			—			(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			5,667			230			(2,455		)	37,000
Accretion of asset retirement obligations	1,000			—			—			—			1,000
Cost of oilfield services	—			99,330			—			(46,288		)	53,042
General and administrative, net of amounts
Stock-based compensation	897			458			4,134			—			5,489
Other general and administrative	5,844			7,576			5,262			—			18,682
Total operating expenses	64,861			113,031			9,626			(48,743		)	138,775
Income (loss) from operations	46,315			24,865			(9,626		)	(27,092		)	34,462
Other income (expense), net	(1,083		)	(611		)	34,110			(1,677		)	30,739
Net income (loss) before income taxes	$	45,232		$	24,254		$	24,484		$	(28,769	)	$	65,201

Eliminations and Other

For consolidation, intercompany revenues and expenses are eliminated with a corresponding reduction in Triangle’s capitalized well costs.

Under the full cost method, we deferred recognition of approximately an additional $2.8 million and $0.4 million in oilfield services income for the three month periods ended October 31, 2014 and 2013, respectively, and approximately $6.0 million and $3.7 million in oilfield services income for the nine month periods ended October 31, 2014 and 2013, respectively, associated with our non-operating partners’ share of costs charged by RockPile for well completion activities on properties we operate, by charging such oilfield services income against oilfield services revenue and crediting proved oil and natural gas properties.

In addition, we deferred approximately $0.7 million and $0.4 million of Caliber gross profit from our share of its income for the three months ended October 31, 2014 and 2013, respectively, and approximately $1.5 million and $1.7 million for the nine months ended October 31, 2014 and 2013, respectively, associated with services it provided which were capitalized by TUSA, by charging such gross profit against income from equity investment and crediting proved oil and natural gas properties.

The above deferred income is indirectly recognized in future periods through a lower amortization rate as proved reserves are produced.

5. PROPERTY AND EQUIPMENT

Acquisitions

Marathon Oil & Gas Property Acquisition

On June 30, 2014, we acquired from Marathon Oil Company (“Marathon”) certain oil and gas leaseholds and related producing properties located in Williams County, North Dakota, Sheridan County, Montana, and Roosevelt County, Montana comprising approximately 41,100 net acres and various other related rights, permits, contracts, equipment and other assets for approximately $90.4 million in cash, which included a net downward adjustment of $9.6 million for certain pre-closing adjustments. Additional post-closing adjustments may be required. Transaction costs related to the acquisition incurred during the nine months ended October 31, 2014 of approximately $1.3 million are recorded in the statement of operations with general and administrative expenses.

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The acquisition was accounted for using the acquisition method under ASC-805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at fair value as of the acquisition date of June 30, 2014. The final purchase price allocation is pending the completion of management’s assessment of the fair value 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.

The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed:

Preliminary purchase price:

(in thousands)
Cash	$	90,352
Total consideration given	$	90,352

Preliminary fair value allocation of purchase price:
Oil and natural gas properties:
Proved properties	$	71,044
Unproved properties	20,262
Total oil and natural gas properties	91,306

Accounts payable	(469		)
Asset retirement obligations assumed	(485		)
Fair value of net assets acquired	$	90,352

Pro Forma Financial Information

The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired from Kodiak Oil & Gas Corporation, in August of 2013, and Marathon for the three month and nine months ended October 31, 2013, and for the properties acquired from Marathon for the three and nine months ended October 31, 2014, as if the acquisitions had occurred on February 1, 2012 and February 1, 2013, respectively.

	For the Three Months Ended October 31,				For the Nine Months Ended October 31,
(in thousands, except per share data)	2014		2013		2014		2013
Operating revenues	$	174,196	$	102,310	$	427,708	$	219,467
Net income	$	25,398	$	52,305	$	57,110	$	75,913

Earnings per common share
Basic	$	0.30	$	0.66	$	0.67	$	1.21
Diluted	$	0.26	$	0.55	$	0.58	$	0.99

Weighted average common shares outstanding:
Basic	85,242		79,059		85,769		62,817
Diluted	102,954		96,042		103,421		78,865

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The pro forma information includes the effects of adjustments for depreciation, amortization and accretion expense of $3.7 million for the three months ended October 31, 2013, and $3.4 million and $14.1 million for the nine months ended October 31, 2014 and 2013, respectively. The pro forma results do not include any cost savings 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 acquisitions had been completed on February 1, 2012 or 2013, respectively, nor are they necessarily indicative of future results. During the three and nine months ended October 31, 2014, the Company realized $5.2 million and $7.3 million of revenue, respectively, and $1.6 million and $2.7 million of net earnings, respectively, from the properties acquired from Marathon.

June 6, 2014 Oil & Gas Property Acquisition

On June 6, 2014, the Company acquired, from an unrelated third party, certain oil and gas leaseholds located in Williams County, North Dakota comprising approximately 4,600 net acres and various other related rights, permits, contracts, equipment and other assets for approximately $34.5 million in cash, which included a net downward adjustment of $0.5 million for certain pre-closing adjustments (the “June 6, 2014 Acquisition”). Additional post-closing adjustments may be required.

Oil and Natural Gas Property Additions

During the nine months ended October 31, 2014, we acquired oil and natural gas properties, and participated in the drilling and/or completion of wells, for total consideration of approximately $454.6 million.

During the three and nine months ended October 31, 2014, we capitalized $1.2 million and $3.6 million, respectively, of internal land, geology and operations department costs directly associated with property acquisition, exploration (including lease record maintenance) and development. During the three and nine months ended October 31, 2013, we capitalized $1.0 million and $2.6 million, respectively, 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.

Oilfield Services Equipment Additions

Oilfield services equipment additions of $41.3 million dsuring the nine months ended October 31, 2014, consist primarily of the costs for two hydraulic fracturing spreads and other complementary well completion and workover equipment, $32.8 million of which was in service and $8.5 million of which was not yet placed in service at October 31, 2014.

6. EQUITY INVESTMENT

The Company’s investment interest in Caliber is considered to be variable, and Caliber is considered to be a variable interest entity because the power to direct the activities that most significantly impact Caliber’s economic performance does not reside with the holders of equity investment at risk. However, the Company is not considered the primary beneficiary of Caliber since it does not have the power to direct the activities of Caliber that are considered most significant to the economic performance of Caliber. Under the equity method, our investment will be adjusted each period for contributions made, distributions received, the change in the fair value of our holdings of equity investment derivatives of Caliber, and our share of Caliber’s net income and accretion of any basis difference. Our maximum exposure to loss related to Caliber is limited to our equity investment as presented in the accompanying condensed consolidated balance sheet at October 31, 2014. On June 30, 2014, the Company vested in 4,000,000 Class A Trigger Units and its ownership interest in Caliber increased from 30% to approximately 32%.

We evaluate our equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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As of October 31, 2014, the balance of the Company’s investment in Caliber was $74.1 million, which consisted of the following:

(in thousands, except units)	Units	Investment
Balance - January 31, 2014		$	68,536
Change in fair value of:
Class A Trigger Units (1)	4,000,000	1,746
Series 1 Warrants (2)	5,600,000	2,214
Series 2 Warrants	2,400,000	(158		)
Series 3 Warrants	3,000,000	(87		)
Series 4 Warrants	2,000,000	(53		)
Equity investment share of net income for the period before intra-company profit elimination		1,926
Balance - October 31, 2014		$	74,124

(1) The change in value was prior to the vesting of the Class A Trigger Units into Class A Units on June 30, 2014.

(2) On June 30, 2014, the 1.6 million Class A Trigger Unit Warrants then outstanding automatically converted into Series 1 Warrants upon the Company’s vesting of the Class A Trigger Units, resulting in an aggregate of 5,600,000 Series 1 Warrants outstanding.

7. DEBT

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

(in thousands)	October 31, 2014			January 31, 2014
5% convertible note	$	134,200		$	129,290
TUSA credit facility	33,000			183,000
RockPile credit facility	51,616			21,515
Other notes and mortgages payable	10,175			9,403
TUSA 6.75% notes	450,000			—
Total debt	678,991			343,208
Less current portion of debt:
RockPile credit facility	—			(8,450		)
Other notes and mortgages payable	(416		)	(401		)
Total long-term debt	$	678,575		$	334,357

5% Convertible Note

On July 31, 2012, the Company sold to NGP Triangle Holdings, LLC a $120.0 million Convertible Note (the “5% Convertible Note”) that became convertible after November 16, 2012 into the Company’s common stock at a conversion rate of one share per $8.00 of note principal.

The 5% 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 5% Convertible Note. Such interest is paid-in-kind by adding to the principal balance of the 5% Convertible Note, provided that, after October 31, 2017, the Company has the option to make such interest payments in cash. As of October 31, 2014, $14.2 million of accrued interest has been added to the principal balance of the 5% Convertible Note.

TUSA Credit Facility

On April 11, 2013, TUSA entered into an Amended and Restated Credit Agreement, which was subsequently amended on July 30, 2013, October 16, 2013, January 13, 2014, May 9, 2014, May 14, 2014, and June 6, 2014 (as amended, the “TUSA Credit Facility”).

Borrowings under the TUSA Credit Facility mature on October 16, 2018 and bear interest, at TUSA’s option, at either (i) the ABR (the highest of (A) the administrative agent’s prime rate, (B) the federal funds rate plus 0.5%, or (C) the one-month Eurodollar

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rate (as defined in the TUSA Credit Facility) plus 1%), plus an applicable margin that ranges between 0.50% and 1.50%, depending on TUSA’s utilization percentage of the then effective borrowing base, or (ii) the Eurodollar rate plus an applicable margin that ranges between 1.50% and 2.50%, depending on TUSA’s utilization percentage of the then effective borrowing base.

The TUSA Credit Facility contains various covenants and restrictive provisions that may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, make investments or loans and create liens. In addition, the facility contains financial covenants requiring TUSA to: (i) maintain a ratio of consolidated current assets to consolidated current liabilities (as those terms are defined in the TUSA Credit Facility) of at least 1.0 to 1.0 and (ii) maintain a ratio of consolidated debt to consolidated EBITDAX (as those terms are defined in the TUSA Credit Facility and determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) that is not greater than 4.0 to 1.0. As of October 31, 2014, TUSA was in compliance with all covenants under the TUSA Credit Facility.

On November 25, 2014, TUSA entered into a Second Amended and Restated Credit Agreement (“the TUSA Credit Agreement”), which provides for a $1.0 billion senior secured revolving credit facility, with a sublimit for the issuance of letters of credit equal to $15.0 million.

The lenders will redetermine the borrowing base under the TUSA Credit Agreement on a semi-annual basis by the beginning of each May and November. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. If at any time the borrowing base is less than the amount of outstanding credit exposure under the facility, TUSA will be required to (i) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, (ii) pledge additional collateral, (iii) prepay the excess in three equal monthly installments, or (iv) any combination of options (i) through (iii). As of November 25, 2014, the borrowing base was set by the lenders at $435.0 million.

TUSA will pay a per annum fee on all letters of credit issued under the TUSA Credit Agreement, which fee will equal the applicable margin for loans accruing interest based on the eurodollar rate and a fronting fee to the issuing lender equal to the greater of 0.125% of the letter of credit amount and $500 per letter of credit. TUSA will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the TUSA Credit Agreement.

The TUSA Credit Agreement is collateralized by certain of TUSA’s assets, including (1) at least 80% of the adjusted engineered value of TUSA’s oil and gas interests evaluated in determining the borrowing base for the facility, and (2) all of the personal property of TUSA and its subsidiaries. The obligations under the TUSA Credit Agreement are guaranteed by TUSA’s domestic subsidiaries.

Second Lien Credit Facility

On June 27, 2014, TUSA entered into a Second Lien Credit Agreement (the “Second Lien Credit Facility”), which provided for a $60.0 million second priority secured credit facility, which was funded at signing. All borrowings under the Second Lien Credit Facility were scheduled to mature on October 16, 2019 (nine months after the maturity of the TUSA Credit Facility). Borrowings under the Second Lien Credit Facility bore interest, at our option, at either (i) LIBOR (subject to a floor) plus a margin of 7% or (ii) a base rate (subject to a floor) plus a margin of 6%. The Second Lien Credit Facility also provided that no prepayment fees would be payable for prepayments made during the first twelve months.

Upon issuance of the TUSA 6.75% Notes on July 18, 2014, TUSA terminated the Second Lien Credit Facility and repaid all amounts owing thereunder.

RockPile Credit Facility

On March 25, 2014, RockPile entered into a Credit Agreement (the “RockPile Credit Facility”) to provide a $100.0 million senior secured revolving credit facility with an accordion feature that allows for the expansion of the facility up to an aggregate of $150.0 million.

Borrowings under the RockPile Credit Facility bear interest, at RockPile’s option, at either (i) the alternative base rate (the highest of (a) the administrative agent’s prime rate, (b) the federal funds rate plus 0.5%, or (c) the one-month adjusted Eurodollar rate (as defined in the RockPile Credit Facility) plus 1.0%), plus an applicable margin that ranges between 1.5% and 2.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter, or (ii) the Eurodollar rate plus an applicable margin that ranges between 2.50% and 3.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter. All borrowings under the RockPile Credit Facility mature on March 25, 2019.

RockPile will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile Credit Facility. RockPile will also pay a per annum fee on all letters of credit issued under the RockPile Credit Facility, which will equal the applicable margin for loans accruing interest based on the Eurodollar rate and a fronting fee to the issuing lender

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equal to 0.125% of the letter of credit amount. Triangle is not a guarantor under the RockPile Credit Facility. As of October 31, 2014, the weighted-average interest rate on the loan was 3.39% and $51.6 million was outstanding under the facility.

The RockPile Credit Facility contains financial covenants requiring RockPile to comply with the following: (i) the ratio of RockPile’s consolidated debt to EBITDA (as defined in the RockPile Credit Facility) may not be greater than 2.75 to 1.00 (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) and (ii) RockPile must maintain a ratio of Adjusted EBITDA to Fixed Charges (as defined in the RockPile Credit Facility) of at least 1.25 to 1.00 quarterly. As of October 31, 2014, RockPile was in compliance with all financial covenants under the RockPile Credit Facility.

On November 13, 2014, RockPile entered into Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement (“Amendment No. 1”), which amended the RockPile Credit Facility to increase the borrowing capacity under the facility from $100.0 million to $150.0 million. Following Amendment No. 1, the facility maintained the accordion feature that allows for expansion of the facility by up to an additional $50.0 million, resulting in aggregate borrowing capacity of $200.0 million. Amendment No. 1 also modified covenants in the RockPile Credit Facility related to certain restrictions on the payment of dividends and distributions and increased the amount of permitted capital expenditures.

TUSA 6.75% Notes

On July 18, 2014, TUSA entered into an indenture (the “Indenture”) among TUSA, Foxtrot Resources LLC (the “Guarantor”), a TUSA wholly-owned subsidiary, and Wells Fargo Bank, National Association, as trustee, governing the terms of TUSA’s $450.0 million aggregate principal amount of TUSA 6.75% Notes due 2022 (the “TUSA 6.75% Notes”).

The TUSA 6.75% Notes were issued in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), to qualified institutional buyers in accordance with Rule 144A and to persons outside of the United States pursuant to Regulation S under the Securities Act. The TUSA 6.75% Notes are senior unsecured obligations of TUSA and are guaranteed on a senior unsecured basis by the Guarantor and another TUSA wholly-owned subsidiary that became a guarantor of the TUSA 6.75% Notes in early December 2014. The TUSA 6.75% Notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements.

The TUSA 6.75% Notes bear interest at a rate of 6.75% per year, accruing from July 18, 2014. Interest on the TUSA 6.75% Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2015. The TUSA 6.75% Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture. The Company incurred $10.5 million of offering costs which have been deferred and are being recognized on the effective interest method over the life of the notes.

TUSA may redeem some or all of the TUSA 6.75% Notes at any time prior to July 15, 2017 at a price equal to 100.0% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date and a make-whole premium set forth in the Indenture. On or after July 15, 2017, TUSA may redeem some or all of the notes at any time at redemption prices set forth in the Indenture, plus accrued and unpaid interest, if any, to the redemption date. In addition, at any time prior to July 15, 2017, TUSA may redeem up to 35% of the aggregate principal amount of the TUSA 6.75% Notes at a specified redemption price set forth in the Indenture plus accrued and unpaid interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings. If TUSA experiences certain change of control events, TUSA must offer to repurchase the TUSA 6.75% Notes at 101% of their principal amount, plus accrued and unpaid interest, if any, to the redemption date.

The Indenture contains covenants that, among other things, restrict TUSA’s ability and the ability of any guarantor subsidiary to sell certain assets; make certain dividends, distributions, investments and other restricted payments; incur certain additional indebtedness and issue preferred stock; create certain liens; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries, and consolidate, merge or sell substantially all of TUSA’s assets. These covenants are subject to a number of important exceptions and qualifications. As of October 31, 2014, TUSA was in compliance with all covenants under the TUSA 6.75% Notes.

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8. DERIVATIVE INSTRUMENTS

The following summarizes the fair value of the Company’s derivative instruments (in thousands):

		As of October 31, 2014
Underlier	Balance Sheet Classification	Gross Amount of Recognized Assets (Liabilities)		Gross Amount of Offset		Net Amount of Assets (Liabilities)
Crude oil derivative contracts	Current Assets	$	18,918	$	—	$	18,918
Crude oil derivative contracts	Long-term assets	$	449	$	—	$	449
Equity investment derivatives	Equity investment	$	3,612	$	—	$	3,612

		As of January 31, 2014
Underlier	Balance Sheet Classification	Gross Amount of Recognized Assets (Liabilities)		Gross Amount of Offset			Net Amount of Assets (Liabilities)
Crude oil derivative contracts	Current assets	$	1,066	$	(111	)	$	955
Crude oil derivative contracts	Long-term assets	$	1,192	$	—		$	1,192
Equity investment derivatives	Equity investment	$	39,734	$	—		$	39,734

The Company recorded gains on its commodity derivative activities of $19.8 million and $13.4 million, respectively, for the three and nine months ended October 31, 2014. The Company recorded a gain on commodity derivative activities of $2.1 million and a loss of $1.1 million, respectively, for the three and nine months ended October 31, 2013. We recorded gains of $0.7 million and $3.7 million, respectively, on our equity investment derivatives for the three and nine months ended October 31, 2014 and a gain of $35.8 million for the three and nine months ended October 31, 2013.

Commodity Derivative Instruments

Through TUSA, the Company has entered into commodity derivative instruments utilizing costless collars and swaps 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 each counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the same underlier with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying condensed consolidated 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. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in 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

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liability under a marketplace participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

The Company’s commodity derivative contracts as of October 31, 2014 are summarized below:

Term End Date	Contract Type	Basis (1)	Quantity (Bbl/d)	Weighted Average Put Strike		Weighted Average Call Strike
Fiscal Year 2015	Collar	NYMEX	5,899	$	87.40	$	99.90
Fiscal Year 2016	Collar	NYMEX	4,356	$	86.85	$	98.06

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

Equity Investment Derivatives

At October 31, 2014, the Company held Class A (Series 1 through Series 4) Warrants to acquire additional ownership in Caliber. These instruments are valued using the following valuation techniques, which are generally less observable from objective sources. As such, the Company has classified these instruments as Level 3 in fair value hierarchy (see Note 9 — Fair Value Measurements).

The fair value of the Class A (Series 1 through Series 4) Warrants as of October 31, 2014, were estimated using a Monte Carlo Simulation (“MCS”) model. An MCS model provides a numeric approach to stochastic stock movement to forecast the future stock price of the underlying Class A Units, as opposed to an analytic solution provided by Black-Scholes. For each MCS, the value of the Class A Units was forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly. The fair value of the underlying Class A Units was estimated employing primarily a discounted cash flow analysis. The resulting value represented a marketable minority value of Caliber. As the Class A Units represent a non-marketable equity interest in a private enterprise, an adjustment to our preliminary value estimates was made to account for the lack of liquidity. The concluded fair value of a single Class A Unit of Caliber was determined to be $10.43 at October 31, 2014, an increase of $0.23 per unit from July 31, 2014, and an increase of $0.43 per unit from January 31, 2014.

The MCS model assumed that the warrants would be exercised at the earlier of (a) the contractual life of 12 years, and (b) the point at which the exercise price would be reduced to $5.00 per warrant (at which point it would be advantageous for Triangle to exercise early to capture future distributions on the Class A Units). The key inputs to the MCS model are the same as the Black-Scholes model previously used including 10-year historical volatilities for publicly-traded comparable companies, risk-free interest rates over the expected warrant term and dividend yields based on expected distributions. The change in fair value during the three and nine months ended October 31, 2014 resulted in a $0.7 million and $2.0 million increase, respectively, in our equity investment account in the accompanying unaudited condensed consolidated balance sheet and as the gain on equity investment derivatives reflected in the accompanying unaudited condensed consolidated statement of operations.

Also included in the gain on equity investment derivatives during the nine months ended October 31, 2014 was a gain of $1.7 million associated with the change in fair value of the 4.0 million Caliber Class A Trigger Units which vested on June 30, 2014.

9. 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.

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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, 2014 and January 31, 2014, by level within the fair value hierarchy:

	As of October 31, 2014
(in thousands)	Level 1		Level 2			Level 3		Total
Assets:
Equity investment derivative assets	$	—	$	—		$	3,612	$	3,612
Commodity derivative assets	$	—	$	19,367		$	—	$	19,367

Liabilities:
RockPile earn-out liability	$	—	$	(1,818	)	$	—	$	(1,818	)

	As of January 31, 2014
(in thousands)	Level 1		Level 2			Level 3		Total
Assets:
Equity investment derivative assets	$	—	$	—		$	39,734	$	39,734
Commodity derivative assets	$	—	$	2,147		$	—	$	2,147

Liabilities:
RockPile earn-out liability	$	—	$	(1,739	)	$	—	$	(1,739	)

Commodity Derivative Instruments

The Company determines its estimate of the fair value of its commodity 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 counterparties to be of substantial credit quality and believes that such counterparties have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At October 31, 2014, derivative instruments utilized by the Company consisted of costless collars and swaps. 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.

Caliber Class A (Series 1 through Series 4) Warrants

At October 31, 2014, the Caliber Class A (Series 1 through Series 4) Warrants are valued using valuation factors that are generally less observable from objective sources. As such, the Company has classified these instruments as Level 3.

RockPile Earn-out Liability

The Company determined the estimated fair value of the earn-out liability relating to RockPile’s acquisition of Team Well Service Inc. 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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Summary of Level 3 Financial Assets and Liabilities

The following table presents the rollforward of the fair values of the Company’s Level 3 financial assets and liabilities:

(in thousands)	Class A Trigger Units			Warrants (1)
Beginning balance, January 31, 2014	$	38,091		$	1,696
Net unrealized gain	1,746			1,916
Conversion to Class A units	(39,837		)	—
Ending balance, October 31, 2014	$	—		$	3,612

(1) Includes Caliber Class A (Series 1 through Series 4) Warrants.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives and Caliber Class A warrants (discussed above) and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The 5% Convertible notes estimated fair value is based on discounted cash flow analysis and option pricing (Level 3). The carrying amount of the Company’s revolving credit facilities approximated fair value because the interest rate of the facilities is variable. The fair value of other notes and mortgages payable is not significantly different than their carry values. The fair value of the TUSA 6.75% notes is derived from quoted market prices (Level 1). This disclosure does not impact our financial position, results of operations or cash flows.

	October 31, 2014				January 31, 2014
	Carrying		Estimated		Carrying		Estimated
(in thousands)	Value		Fair Value		Value		Fair Value

5% Convertible note	$	134,200	$	183,200	$	129,290	$	169,200
Revolving credit facilities	84,616		84,616		196,065		196,065
Other notes and mortgages payable	9,759		9,759		9,002		9,002
TUSA 6.75% notes	450,000		398,300		—		—

10. COMMITMENTS AND CONTINGENCIES

As of October 31, 2014, 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 condensed consolidated 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.

Pursuant to the Third Amended and Restated Employment Agreement, dated July 4, 2013 (the “Employment Agreement”), between the Company and Jonathan Samuels, our President and Chief Executive Officer, Mr. Samuels is entitled to a cash bonus payable upon a liquidity event involving RockPile or Caliber based on the percentage gain realized by the Company relative to its investment in the relevant entity. The amount of this bonus would be equivalent to 5.0% of that gain in Caliber for a Caliber liquidity event, and 3.5% of that gain in RockPile for a RockPile liquidity event. The right to the bonus vests and becomes non-forfeitable in thirds on the first three anniversaries of the execution date of the Employment Agreement, with acceleration or forfeiture of the unvested portions of such right upon the occurrence of certain events. Because consummation of a liquidity event involving RockPile or Caliber is contingent on many unknown factors, the Company has determined that the contingent liability associated with such a bonus is not probable at October 31, 2014, and, therefore, no amounts have been recorded in the accompanying condensed consolidated balance sheets.

11. CAPITAL STOCK

Common Stock

During the nine months ended October 31, 2014, the Company issued 635,999 shares of its common stock (net of shares surrendered for related employee payroll tax withholding) for restricted stock units that vested during the period and, during the three months ended October 31, 2014, the Company repurchased and retired 4.9 million shares of common stock at an average cost of $9.07 per share.

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Share-Based Compensation

The Company has granted equity awards to officers, directors and certain employees of the Company including restricted stock units and stock options. In addition, RockPile has granted Series B units which represent interests in future RockPile profits. The Company measures its awards based on the award’s grant date fair value which is recognized ratably over the applicable vesting period.

On May 27, 2014, the Company’s Board of Directors approved the 2014 Equity Incentive Plan (the “2014 Plan”), which was approved by the Company’s stockholders on July 17, 2014. No additional awards may be granted under prior plans but all outstanding awards under prior plans shall continue in accordance with their applicable terms and conditions.

The 2014 Plan authorizes the Company to issue stock options, SARs, restricted stock, restricted stock units, cash awards, and other awards to any employees, officers, directors and consultants of the Company and its subsidiaries. The maximum number of shares of common stock reserved for issuance under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions.

For the three and nine months ended October 31, 2014 and 2013, the Company recorded stock-based compensation related to restricted stock units, stock options and RockPile Series B Units as follows:

	Three Months Ended October 31,
(in thousands)	2014			2013

Restricted stock units	$	1,298		$	2,059
Stock options	627			648
RockPile stock based compensation related to Series B Units	146			148
	2,071			2,855
Less amounts capitalized to oil and natural gas properties	(244		)	(398		)
Compensation expense	$	1,827		$	2,457

	Nine Months Ended October 31,
(in thousands)	2014			2013

Restricted stock units	$	4,572		$	5,419
Stock options	1,600			648
RockPile stock based compensation related to Series B Units	363			458
	6,535			6,525
Less amounts capitalized to oil and natural gas properties	(893		)	(1,036		)
Compensation expense	$	5,642		$	5,489

Restricted Stock Units

During the nine months ended October 31, 2014, the Company granted 1,380,200 restricted stock units as compensation to employees, officers and directors. Restricted stock units vest over one to five years. As of October 31, 2014, there was approximately $20.8 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 2.4 years on a weighted average basis. When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit.

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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, 2014	2,875,624		$	6.75
Units granted	1,380,200		$	9.67
Units forfeited	(330,171	)	$	7.15
Units that vested	(922,393	)	$	7.18
Restricted stock units outstanding - October 31, 2014	3,003,260		$	7.84

Stock Options

On September 9, 2014, the Company granted options to acquire 700,000 shares of the Company’s common stock pursuant to the 2014 Plan at the following exercise prices: 233,333 shares at $12.00 per share (which expire on September 9, 2021), 233,333 shares at $14.00 per share (which expire on September 9, 2021) and 233,334 at $16.00 per share (which expire on September 9, 2024). Each tranche vests in three equal installments on the first three anniversaries of the grant date.

Compensation expense related to stock options is calculated using the Black-Scholes valuation model. Expected volatility is generally based on the historical volatility of Triangle’s common stock. 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 options granted:

Risk free rate	1.06	%
Dividend yield	—
Expected volatility	54	%
Weighted average expected stock option life (years)	3.0

As of October 31, 2014, there was approximately $19.3 million of total unrecognized compensation expense related to stock options. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 3.6 years. The following table summarizes the status of stock options outstanding:

	Number of Shares	Weighted Average Exercise Price
Options outstanding - January 31, 2014 (108,333 exercisable)	6,108,333	$	11.07
Options forfeited	—	$	—
Options exercised	—	$	—
Options granted	700,000	$	14.00
Options outstanding - October 31, 2014 (708,333 exercisable)	6,808,333	$	11.37

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The following table presents additional information related to the stock options outstanding at October 31, 2014:

		Remaining
Exercise Price		Contractual Life	Number of shares
per Share		(years)	Outstanding		Exercisable
$	1.25	0.08	108,333		108,333
$	7.50	8.68	750,000		75,000
$	8.50	8.68	750,000		75,000
$	10.00	8.68	1,500,000		150,000
$	12.00	8.68	1,500,000		150,000
$	12.00	6.86	233,333		—
$	14.00	6.86	233,333		—
$	15.00	8.68	1,500,000		150,000
$	16.00	9.87	233,334		—
			6,808,333		708,333

Weighted average exercise price per share			$	11.37	$	9.72

Weighted average remaining contractual life			8.46		7.36

RockPile Share-Based Compensation

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 (“RockPile LLC Agreement”), which includes provisions allowing 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 ability to re-issue forfeited or redeemed Series B Units. RockPile issued 1,412,000 Series B Units and redeemed 180,000 B-1 Units during the nine months ended October 31, 2014.

A summary of the activity for RockPile’s Series B Units is as follows:

	Series B-1 units		Series B-2 units	Series B-3 units	Series B-4 units	Total
Units outstanding - January 31, 2014	3,100,000		60,000	910,000	—	4,070,000
Units forfeited	—		—	—	—	—
Units redeemed	(180,000	)	—	—	—	(180,000	)
Units granted	—		—	—	1,412,000	1,412,000
Units outstanding - October 31, 2014	2,920,000		60,000	910,000	1,412,000	5,302,000
Vested	2,386,667		30,000	188,000	—	2,604,667
Unvested	533,333		30,000	722,000	1,412,000	2,697,333

As of October 31, 2014, there was approximately $2.7 million of unrecognized compensation cost related to unvested Series B Units. We expect to recognize such cost on a pro-rata basis on the Series B Units’ vesting schedule during the next five fiscal years.

12. EARNINGS PER SHARE

Basic net income (loss) per common share is computed by dividing net income (loss) attributable to 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, and (ii) vesting of restricted stock units. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period of 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) the

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foregone future compensation expense of hypothetical early vesting of the outstanding restricted stock units. The assumed proceeds are adjusted for income tax effects.

The potential dilution from the conversion of the 5% Convertible Note is determined using the “if converted” method whereby the shares issuable upon conversion are added to the denominator and the current period interest expense is added to the numerator, on an after-tax basis, to determine the dilutive effect of such conversion if it had occurred at the beginning of the period.

The table below sets forth the computations of net income per common share (basic and diluted) for the three and nine months ended October 31, 2014 and 2013:

	For the Three Months Ended				For the Nine Months Ended
	October 31,				October 31,
(in thousands, except per share data)	2014		2013		2014		2013
Net income attributable to common stockholders	$	25,398	$	47,221	$	54,492	$	59,232
Effect of 5% Convertible Note conversion	919		881		2,852		2,503
Net income attributable to common stockholders after effect of debt conversion	$	26,317	$	48,102	$	57,344	$	61,735

Basic weighted average common shares outstanding	85,242		79,059		85,769		62,817
Effect of dilutive securities	17,712		16,983		17,652		16,048
Diluted weighted average common shares outstanding	102,954		96,042		103,421		78,865

Basic net income per share	$	0.30	$	0.60	$	0.64	$	0.94
Diluted net income per share	$	0.26	$	0.50	$	0.55	$	0.78

Of the stock options, restricted stock units and convertible debt outstanding at October 31, 2014, 6.7 million outstanding options were anti-dilutive for the three and nine month periods ended October 31, 2014, and 0.04 million and 0.08 million of restricted stock units were anti-dilutive for the three and nine months periods ended October 31, 2014, respectively, and therefore were excluded from the calculation of the diluted net income per share for those three and nine month periods. These awards could potentially be dilutive in future periods.

13. INCOME TAXES

The Company computes its quarterly tax provision using the effective tax rate method based on applying the anticipated annual effective rate to its year to date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs.

The effective tax rate for the nine months ended October 31, 2014 was 42.1%, which differs from the statutory income tax rate due primarily to permanent book to tax differences and state income taxes.

As of October 31, 2014, the Company had no unrecognized tax benefits (or associated ASC 740-10-25 liabilities) for ASC 740-10-25 purposes. The Company’s management does not believe that there are any new items or changes in facts or judgments that should impact the Company’s ASC 740-10-25 position during the first three quarters of fiscal year 2015. 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 very likely adjust only net operating loss carry forwards.

14. RELATED PARTY TRANSACTIONS

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

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. The two original

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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.

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 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 minimum commitment over the term of the agreements is $405.0 million, of which $375.3 million remained at October 31, 2014.

On September 12, 2013, TUSA and Caliber Measurement Services LLC (“Caliber Measurement”), a wholly-owned subsidiary of Caliber, entered into a gathering services agreement pursuant to which Caliber Measurement will provide certain gathering-related measurement services to TUSA.

On May 14, 2014, TUSA and Caliber Midstream Fresh Water Partners LLC (“Caliber Fresh Water”), which is owned 51% by a wholly-owned subsidiary of Caliber and 49% by a third party, entered into a fresh water sales agreement pursuant to which Caliber Fresh Water will make available certain volumes of fresh water for purchase by TUSA at a set per barrel fee for a primary term of five years. The agreement obligates TUSA to purchase all of the fresh water it requires for its drilling and operating activities in North Dakota exclusively from Caliber Fresh Water, subject to availability, but it does not require TUSA to purchase a minimum volume of fresh water.

On May 14, 2014, TUSA entered into a Purchase and Sale Agreement with Caliber North Dakota whereby TUSA agreed to sell two salt water disposal wells to Caliber North Dakota for $7.5 million, subject to necessary regulatory approvals. During the third quarter of fiscal 2015, the Company received the necessary approvals with respect to one of the salt water disposal wells and consummated that sale for total proceeds of $1.5 million, all of which was recorded as a reduction to the Company’s proved oil and natural gas properties and no gain or loss was recognized. As of October 31, 2014, the sale of the second salt water disposal well had not yet been consummated; however, the Company expects to finalize the transaction during its fiscal 2015 fourth quarter.

For the three and nine months ended October 31, 2014, Caliber North Dakota had $14.4 million and $28.0 million of revenue, respectively, of which $11.6 million and $23.8 million, respectively, were from TUSA.

For the three and nine month period ended October 31, 2014, Triangle received $0.1 million and $0.7 million, respectively, from Caliber for certain administrative services supplemental to those provided by Caliber employees. The administrative services were provided pursuant to the October 1, 2012 Services Agreement between Triangle and Caliber.

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15. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

	For the Nine Months Ended
	October 31,
(in thousands)	2014		2013
Cash paid during the period for:
Interest expense	$	5,672	$	2,260
Income taxes	$	550	$	—

Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increased accounts payable and accrued liabilities	$	103,415	$	28,874
Issuance of common stock	$	—	$	2,435
Capitalized stock based compensation	$	893	$	1,036
Change in asset retirement obligations	$	1,519	$	608
Capitalized interest	$	3,422	$	1,956
Acquisition of oilfield services equipment through notes payable and liabilities	$	—	$	2,262

Non-cash financing activities:
Notes payable issued for redemption of RockPile B units	$	1,041	$	—

16. SIGNIFICANT CHANGES IN PROVED OIL AND NATURAL GAS RESERVES

Our proved oil and natural gas reserves at October 31, 2014 increased from our proved oil and natural gas reserves at January 31, 2014. Our proved reserves are in the Bakken and Three Forks formations in the North Dakota Counties of McKenzie, Williams, Stark, Mountrail and Dunn, and in Roosevelt and Sheridan Counties, Montana.

The reserve estimates at October 31, 2014 were estimated by our in-house reservoir engineer, who has been a Petroleum Engineer since 1995 and has over 19 years of experience. Our reserve estimate at January 31, 2014, 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 estimates of proved reserves presented below, such average prices were $86.29 per barrel of oil, $43.23 per barrel of natural gas liquids and $5.79 per Mcf of natural gas for the reserves presented as of October 31, 2014. For the reserves presented as of January 31, 2014, the average prices were $93.09 per barrel of oil, $44.10 per barrel of natural gas liquids and $3.99 per Mcf of natural gas.

% of

October 31, 2014

January 31,

Reserves

Oil

Gas

NGL

2014

Reserve Category

(Mboe)

(Mbbls)

(MMcf)

(Mbbls)

Mboe

Proved Developed

26,816

22,242

2,072

32,595

16,995

Proved Undeveloped

19,605

16,407

2,185

24,525

23,319

Total Proved

100

46,421

38,649

4,257

57,120

40,314

The primary reasons for the increase in proved reserves is the drilling and completion of wells in the first nine months of fiscal year 2015, as well as the Marathon acquisition and the June 6, 2014 Acquisition, both of which closed during the nine months ended October 31, 2014. Our net interest in proved developed wells increased 121% from 50.0 net wells at January 31, 2014 to 110.3 net wells at October 31, 2014, and our net interest in proved undeveloped locations increased 9% from 52.5 net future development wells at January 31, 2014 to 57.2 net future development wells at October 31, 2014.

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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 “anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,” “estimates,” “could,” “would,” “will,” “may,” “can,” “continue,” “potential,” “likely,” “should,” and the negative of these terms or other comparable terminology, often identify forward-looking statements. Statements in this quarterly report that are not statements of historical facts are hereby identified as forward-looking statements for the purpose of the safe harbor provided by Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”).

These forward-looking statements include, but are not limited to, statements about our:

· future capital expenditures and performance;

· future operating results;

· anticipated drilling and development;

· drilling results;

· results of acquisitions;

· relationships with partners;

· plans for Triangle USA Petroleum Corporation (“TUSA”);

· plans for RockPile Energy Services, LLC (“RockPile”); and

· plans for Caliber Midstream Partners, L.P. (“Caliber”).

Actual results or developments may be different than we anticipate or may have unanticipated consequences to, or effects on, us or our business or operations. All of the forward-looking statements made in this report are qualified by the discussion of risks and uncertainties under “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended January 31, 2014 (the “Fiscal 2014 Form 10-K”), in our Quarterly Report on Form 10-Q for the fiscal quarter ended July 31, 2014, (the “Fiscal 2015 Q2 10-Q”), and in our other public filings with the SEC. Although the expectations reflected in the forward-looking statements are based on our current beliefs and expectations, undue reliance should not be placed on any such forward-looking statements due to the risks and uncertainties noted above and 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 reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report may not occur.

Overview

Triangle Petroleum Corporation (“Triangle,” the “Company,” “we” or “our”) is a growth-oriented, independent energy holding company with three principal lines of business: oil and natural gas exploration, development and production; oilfield services; and midstream services. We conduct these activities in the Williston Basin of North Dakota and Montana through the Company’s two principal wholly-owned subsidiaries and our equity joint venture:

· TUSA conducts our exploration and production operations by acquiring and developing unconventional shale oil and natural gas resources;

· RockPile is a provider of hydraulic pressure pumping and complementary well completion and workover services;

· Caliber is our 32% owned joint venture with First Reserve Energy Infrastructure Fund (“FREIF”). Caliber provides freshwater delivery, produced water transportation and disposal, crude oil gathering and stabilization services, and natural gas gathering and processing services.

Our primary focus at TUSA is to grow our production volumes through the efficient development of our operated Bakken Shale and Three Forks drilling inventory. We completed our first operated well in May 2012. From May 2012 through October 31, 2014, we have completed 88 gross (63.8 net) operated wells. Our average net daily production for the quarter ended October 31, 2014 was 12,230 barrels of oil equivalent per day (“Boepd”), approximately 86% of which was operated production. The growth we have

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experienced is facilitated by the use of pad drilling, which increases efficiencies while controlling costs and minimizing environmental impact. We also use advanced completion, collection and production techniques designed to optimize reservoir production while reducing costs.

In an effort to better control key operations, reduce costs, and retain supply chain value in the Williston Basin, which we view as a historically resource-constrained and cost-heavy basin, we formed RockPile and entered into our 32% owned joint venture arrangement with FREIF to form Caliber. RockPile’s services lower our realized well completion costs, and RockPile affords us greater control over completion schedules, quality control and pay cycles. We expect that Caliber will reduce the cost and environmental impacts associated with trucking oil and water and reduce or eliminate the emissions generated by the flaring of produced natural gas from our operated wells. In addition to providing services to TUSA, RockPile and Caliber are focused on growing their respective businesses through securing independent, third-party contracts.

Triangle has two reportable operating segments. Our exploration and production operating segment and our oilfield services operating segment are managed separately because of the nature of their products and services. The focus of the exploration and production operating segment is finding and producing oil and natural gas. The focus of the oilfield services operating segment is providing pressure pumping and complementary services for both TUSA-operated wells and wells operated by third-parties. See Note 4 - Segment Reporting under Item 1 of this Quarterly Report for additional information on our segments.

Summary of operating and financial results for the three months ended October 31, 2014:

· Production volumes totaled 1,125,160 Boe for the three months ended October 31, 2014, compared to 625,935 Boe for the three months ended October 31, 2013, an increase of 80%.

· Oil, natural gas and natural gas liquid sales in the three months ended October 31, 2014 were $80.1 million compared to $55.5 million for the three months ended October 31, 2013.

· Oilfield services revenue in the three months ended October 31, 2014 totaled $94.1 million compared to $33.1 million for the three months ended October 31, 2013, and total gross profit contribution from our oilfield service operations was $18.7 million for the three months ended October 31, 2014, as compared to $2.2 million for the comparable period in 2013.

· Income from operations was $33.3 million for the three months ended October 31, 2014, compared to $17.2 million for the three months ended October 31, 2013.

· We spud 21 gross (14.2 net) operated wells and completed 17 gross (13.2 net) operated wells during the three months ended October 31, 2014.

Summary of operating and financial results for the nine months ended October 31, 2014:

· Production volumes totaled 2,819,388 Boe for the nine months ended October 31, 2014 compared to 1,261,865 Boe for the nine months ended October 31, 2013, an increase of 123%.

· Oil, natural gas and natural gas liquid sales in the nine months ended October 31, 2014, were $221.5 million compared to $111.2 million for the nine months ended October 31, 2013.

· Oilfield services revenue in the nine months ended October 31, 2014 was $194.5 million compared to $62.1 million for the nine months ended October 31, 2013, and total gross profit contribution from our oilfield service operations was $42.3 million for the nine months ended October 31, 2014, as compared to $5.8 million for the comparable period in 2013.

· Income from operations was $94.5 million for the nine months ended October 31, 2014, compared to $34.5 million for the nine months ended October 31, 2013.

· Cash flow provided by operating activities was $102.4 million for the nine month period ended October 31, 2014 compared to $15.7 million for the nine months ended October 31, 2013.

· We spud 48 gross (33.6 net) operated wells and completed 41 gross (29.6 net) operated wells during the nine months ended October 31, 2014.

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Recent Events

RockPile Credit Facility Amendment

On November 13, 2014, RockPile entered into Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement (“Amendment No. 1”), which amended RockPile’s existing Credit Agreement, dated March 25, 2014 (the “RockPile Credit Facility”), to increase the borrowing capacity under the facility from $100.0 million to $150.0 million. Following Amendment No. 1, the facility maintained the accordion feature that allows for expansion of the facility by up to an additional $50.0 million, resulting in aggregate borrowing capacity of $200.0 million. Amendment No. 1 also modified covenants in the RockPile Credit Facility related to certain restrictions on the payment of dividends and distributions and increased the amount of permitted capital expenditures.

TUSA Credit Facility Amendment

On November 25, 2014, TUSA entered in a Second Amended and Restated Credit Agreement (the “TUSA Credit Agreement”), which amended and restated its existing credit facility (the “TUSA Credit Facility”). The TUSA Credit Agreement provides for a $1.0 billion senior secured revolving credit facility, with a sublimit for the issuance of letters of credit equal to $15.0 million. The initial borrowing base under the TUSA Credit Agreement is $435.0 million.

Reserve Update

As of October 31, 2014, we have estimated proved reserves of 46.4 million barrels of oil, 4.3 million barrels of natural gas liquids and 38.6 billion cubic feet of natural gas, or 57.1 million barrels of oil equivalent (MMboe). Our reserve quantities are comprised of 82% crude oil, 11% natural gas and 7% natural gas liquids. The October 31, 2014 proved reserves reflect a 42% increase over the January 31, 2014 proved reserves of 40,314 MMboe. Our proved reserves at October 31, 2014 were estimated by our in-house reservoir engineer, who has been a Petroleum Engineer since 1995 and has over 19 years of experience.

The following table summarizes our estimates of proved reserves as of October 31, 2014:

	% of		October 31, 2014				January 31,
	Reserves		Oil	Gas	NGL		2014	%
Reserve Category	(Mboe)		(Mbbls)	(MMcf)	(Mbbls)	Mboe	Mboe	Change

Proved Developed	57	%	26,816	22,242	2,072	32,595	16,995	92	%
Proved Undeveloped	43	%	19,605	16,407	2,185	24,525	23,319	5	%
Total Proved	100	%	46,421	38,649	4,257	57,120	40,314	42	%

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, 2014 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. The average prices were $86.29 per barrel of oil, $43.23 per barrel of natural gas liquids and $5.79 per Mcf of natural gas for the reserves presented as of October 31, 2014. For the reserves presented as of January 31, 2014, the average prices were $93.09 per barrel of oil, $44.10 per barrel of natural gas liquids and $3.99 per Mcf of natural gas.

Volumes of reserves that will actually be recovered may differ significantly from the proved reserve estimates. 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 reserve estimate is a function of, among other things, the quality of available data and engineering and geological interpretation and judgment. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities 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, 2014:

	For the Three Months Ended October 31, 2014
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	21	14.2	17	13.2
Non-operated wells	41	2.6	26	0.8
	62	16.8	43	14.0

	For the Nine Months Ended October 31, 2014
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	48	33.6	41	29.6
Non-operated wells	109	4.7	64	2.6
	157	38.3	105	32.2

Properties, Plan of Operations and Capital Expenditures

We own operated and non-operated leasehold positions in the Williston Basin. As of October 31, 2014, we have completed a total of 88 gross (63.8 net) operated wells in the Williston Basin. We also have economic interests in approximately 474 gross (26.0 net) non-operated wells.

The focus of our drilling program is on our core area in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana, which we refer to collectively as our “Core Acreage.” We currently run a four-rig drilling program. We periodically reassess the appropriate number of rigs for our drilling program based on a variety of factors, including but not limited to prevailing oil and gas prices and operational efficiencies.

Our oil and natural gas property expenditures during the nine months ended October 31, 2014 are summarized below:

(in thousands)
Costs incurred during the period
Acquisition of properties:
Proved	$	91,075
Unproved	41,768
Exploration	150,985
Development	170,743
Oil and natural gas expenditures	454,571
Asset retirement obligations, net	1,519
	$	456,090

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We use the full cost method of accounting for our oil and natural gas operations. Accounting rules require us to perform a quarterly ceiling test calculation to test our oil and natural gas properties for possible impairment. The primary components impacting this calculation are commodity prices, reserve quantities added and produced, overall exploration and development costs, amortization expense, and tax effects. If the net capitalized cost of our oil and natural gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess would be charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects.

At October 31, 2014, the calculated value of the ceiling limitation exceeded the carrying value of our oil and natural gas properties subject to the test, and no impairment was necessary. However, the Company could be required to recognize an impairment of oil and natural gas properties in future periods if oil and natural gas prices remain at current levels or continue to decline or if there is a negative impact on one or more of the other components of the calculation.

U.S. Leaseholds

As of October 31, 2014, we have leased approximately 269,241 gross and 128,245 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	159,107	56,551	46,557	18,153	205,664	74,704
Montana	8,114	6,002	55,463	47,539	63,577	53,541
Total Williston Basin	167,221	62,553	102,020	65,692	269,241	128,245

We are subject to lease expirations if we (or, in the case of non-operated acreage, the operator) 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 (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 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 also hold leasehold interests in acreage in the Maritimes Basin of Nova Scotia, Canada. Currently, Nova Scotia has in place a moratorium on hydraulic fracturing and does not allow the use of salt water disposal wells. We fully impaired our Nova Scotia leasehold assets as of January 31, 2012. Our Canadian assets are not material to our asset base or development plans.

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Results of Operations for the Three Months Ended October 31, 2014 Compared to the Three Months Ended October 31, 2013

For the fiscal quarter ended October 31, 2014, we recorded net income of $25.4 million ($0.30 per share of common stock - basic and $0.26 per share of common stock - diluted) as compared to net income $47.2 million ($0.60 per share of common stock - basic and $0.50 per share of common stock - diluted) for the quarter ended October 31, 2013. The following table summarizes production volumes, average realized prices, oil, natural gas and natural gas liquids revenues and operating expenses for the quarters ended October 31, 2014 and 2013:

	For the Three Months Ended				Change
	October 31,				Increase			% Increase
U.S. Oil and Natural Gas Operations	2014		2013		(Decrease)			(Decrease)
Production volumes:
Crude oil (Bbls)	946,727		567,391		379,336			67%
Natural gas (Mcf)	653,950		196,831		457,119			232%
Natural gas liquids (Bbls)	69,441		25,739		43,702			170%
Total barrels of oil equivalent (Boe)	1,125,160		625,935		499,225			80%

Average realized prices (1):
Crude oil ($ per Bbl)	$	79.11	$	94.47	$	(15.36	)	(16)%
Natural gas ($ per Mcf)	$	4.59	$	4.46	$	0.13		3%
Natural gas liquids ($ per Bbl)	$	32.24	$	38.85	$	(6.61	)	(17)%
Total average realized price ($ per Boe)	$	71.22	$	88.63	$	(17.41	)	(20)%

Oil, natural gas and natural gas liquids revenues (in thousands):
Crude oil	$	74,896	$	53,600	$	21,296		40%
Natural gas	3,004		877		2,127			243%
Natural gas liquids	2,239		1,000		1,239			124%
Total oil and natural gas revenues	$	80,139	$	55,477	$	24,662		44%

Operating expenses (in thousands):
Production taxes	$	8,637	$	6,161	$	2,476		40%
Lease operating expenses	7,454		4,443		3,011			68%
Gathering, transportation and processing	4,380		1,443		2,937			204%
Oil and natural gas amortization expense	27,986		16,800		11,186			67%
Accretion of asset retirement obligations	149		20		129			645%
Total operating expenses	$	48,606	$	28,867	$	19,739		68%

Operating expenses per Boe:
Production taxes	$	7.68	$	9.84	$	(2.16	)	(22)%
Lease operating expenses	$	6.62	$	7.10	$	(0.48	)	(7)%
Gathering, transportation and processing	$	3.89	$	2.31	$	1.58		68%
Oil and natural gas amortization expense	$	24.87	$	26.84	$	(1.97	)	(7)%

(1) Excludes the impact of commodity derivative activity.

Oil, Natural Gas and Natural Gas Liquids Revenues

Revenues from oil, natural gas, and natural gas liquids production for the three months ended October 31, 2014 increased 44% to $80.1 million from $55.5 million for the same period in fiscal year 2014 primarily due to the significant increase in oil production from new wells (as noted in “Recent Events - Drilling and Completions”), and the acquisition of producing wells in the third quarter of fiscal year 2014 and the second quarter of fiscal year 2015, partially offset by normal production declines and pricing declines in oil and natural gas liquids. Average realized oil prices in the third quarter of fiscal year 2015 decreased to $79.11 per barrel from $94.47 per barrel in the same period in fiscal year 2014. In addition, during the three months ended October 31, 2014, we experienced increases in both our volumes of natural gas and natural gas liquids sold as a result of expanding gathering, transportation and processing infrastructure.

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Production Taxes

Due primarily to the 44% increase in oil, natural gas and natural gas liquids revenues for the three months ended October 31, 2014 as compared with the three months ended October 31, 2013, our production taxes increased approximately 40% to $8.6 million from $6.2 million for the same period of fiscal year 2014. Production taxes decreased to $7.68 per Boe for the three months ended October 31, 2014 from $9.84 per Boe for the three months ended October 31, 2013 because natural gas and natural gas liquids are becoming a larger proportion of our total Boe sales and natural gas and natural gas liquids have lower tax rates than crude oil.

Lease Operating Expense

Lease operating expense decreased to $6.62 per Boe for the three months ended October 31, 2014 from $7.10 per Boe for the three months ended October 31, 2013. The cost decrease is primarily the result of efficiencies generated from operating more wells with labor and power costs spread across increased production.

Gathering, Transportation and Processing

Gathering, transportation and processing (“GTP”) expenses increased to $3.89 per Boe for the three months ended October 31, 2014 from $2.31 per Boe for the three months ended October 31, 2013, primarily because in the third quarter of fiscal year 2014 we commenced gathering, transporting and processing significant amounts of our natural gas production that had previously been flared. Going forward, we expect our GTP costs to continue to increase (along with our revenues) 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 67% to $28.0 million for the three months ended October 31, 2014 from $16.8 million for the three months ended October 31, 2013. The increase is primarily related to increased production in the third quarter of fiscal year 2015 as compared to the third quarter of fiscal year 2014. On a per Boe basis our oil and natural gas amortization expense decreased by $1.97 from $26.84 for the three months ended October 31, 2013 to $24.87 for the three months ended October 31, 2014. This decrease was primarily due to increases in proved reserves from successful development operations, field extensions and the acquisition of additional oil and gas properties.

Oilfield Services Gross Profit

During the three months ended October 31, 2014, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and nine third-party customers. Equipment utilized to perform these services consisted of four frac spreads, four wireline trucks, and five workover rigs. Hydraulic fracturing services resulted in 43 total well completions: 17 for TUSA and 26 for third-parties. Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), logistics 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 $18.7 million and $2.2 million, respectively, of gross profit from oilfield services for the three months ended October 31, 2014 and 2013, respectively, after elimination of $16.0 million and $11.4 million, respectively, of intercompany gross profit. See Note 4 — Segment Reporting under Item 1 of this Quarterly Report.

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The tables below are a summary of the Oilfield Services contribution to our consolidated results for the three months ended October 31, 2014 and 2013, after eliminations:

	For the Three Months Ended October 31, 2014
(in thousands)	Oilfield Services		Eliminations			Consolidated
Revenues
Oilfield services	$	143,751	$	(49,694	)	$	94,057
Total revenues	143,751		(49,694		)	94,057
Cost of sales
Oilfield services	102,762		(31,905		)	70,857
Depreciation	6,249		(1,791		)	4,458
Total cost of sales	109,011		(33,696		)	75,315
Gross profit	$	34,740	$	(15,998	)	$	18,742

	For the Three Months Ended October 31, 2013
(in thousands)	Oilfield Services		Eliminations			Consolidated
Revenues
Oilfield services	$	66,179	$	(33,107	)	$	33,072
Total revenues	66,179		(33,107		)	33,072
Cost of sales
Oilfield services	49,839		(20,675		)	29,164
Depreciation	2,700		(1,020		)	1,680
Total cost of sales	52,539		(21,695		)	30,844
Gross profit	$	13,640	$	(11,412	)	$	2,228

General and Administrative Expenses

The following table summarizes general and administrative expenses for the three months ended October 31, 2014 and 2013, respectively:

(in thousands)	Exploration and Production		Oilfield Services		Corporate		Consolidated Total
For the three months ended October 31, 2014
Stock-based compensation	$	93	$	146	$	1,588	$	1,827
Salaries, benefits and other general and administrative	4,230		7,310		3,426		14,966
Total	$	4,323	$	7,456	$	5,014	$	16,793

For the three months ended October 31, 2013
Stock-based compensation	$	328	$	148	$	1,981	$	2,457
Salaries, benefits and other general and administrative	2,594		3,150		2,385		8,129
Total	$	2,922	$	3,298	$	4,366	$	10,586

Total general and administrative expense increased $6.2 million to $16.8 million for the three months ended October 31, 2014 compared to $10.6 million for the three months ended October 31, 2013. The increase in corporate general and administrative expenses is primarily a result of increased compensation and benefit costs for personnel due to the growth of the business. During the three months ended October 31, 2014, we incurred a $1.3 million charge associated with the write off of accrued software costs associated with a land and accounting system conversion that is no longer contemplated.

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Derivative Activities

Commodity Derivatives

We have entered into commodity derivative instruments, primarily costless collars and swaps, 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 three months ended October 31, 2014, we recognized a $19.8 million gain on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a gain of $2.1 million for 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.

Equity Investment Derivatives

Our equity investment in Caliber consists of Class A Units and equity derivative instruments. Due to the increase in the fair value of the equity investment derivatives in the third quarter of fiscal year 2015, the Company recognized a gain in equity investment derivatives of $0.7 million compared to a gain of $35.8 million during the quarter ended October 31, 2013. For additional discussion, please refer to Note 8 — Derivative Instruments under Item 1 of this Quarterly Report.

Income from Equity Investment

During the three months ended October 31, 2014, the Company recognized $1.1 million for its share of Caliber’s income for the period. This income, however, was offset by $0.7 million of intra-company profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $0.4 million.

Interest Expense

The $9.5 million in interest expense for the three months ended October 31, 2014 consists of (a) approximately $0.7 million in interest and amortized fees related to the TUSA Credit Facility, (b) approximately $1.7 million in accrued interest and amortized fees related to our $120.0 million Convertible Note issued to NGP Triangle Holdings, LLC on July 31, 2012 (the “5% Convertible Note”), (c) approximately $8.1 million in interest and amortized fees related to the TUSA 6.75% Notes due 2022 (the “TUSA 6.75% Notes”), (d) approximately $0.5 million in interest expense associated with our RockPile Credit Facility and notes payable, and (e) approximately $0.1 million in interest expense related to our other debt, all net of approximately $1.6 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $1.0 million of interest expense and capitalized interest was paid in cash. See Note 7 —Debt under Item 1 of this Quarterly Report for additional information regarding our debt outstanding.

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, (c) approximately $0.2 million in interest expense associated with our RockPile Credit Facility and notes payable, all net of approximately $0.9 million of capitalized interest. Approximately $1.2 million of interest expense and capitalized interest was paid in cash.

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Results of Operations for the Nine Months Ended October 31, 2014 Compared to the Nine Months Ended October 31, 2013

For the nine months ended October 31, 2014, we recorded net income attributable to common stockholders of $54.5 million ($0.64 per share of common stock - basic and $0.55 per share of common stock - diluted) as compared to net income attributable to common stockholders of $59.2 million ($0.94 per share of common stock - basic and $0.78 per share of common stock - diluted) for the nine months ended October 31, 2013. The following table summarizes production volumes, average realized prices, oil, natural gas and natural gas liquids revenues and operating expenses for the nine months ended October 31, 2014 and 2013:

	For the Nine Months Ended				Change
	October 31,				Increase			% Increase
U.S. Oil and Natural Gas Operations	2014		2013		(Decrease)			(Decrease)
Production volumes:
Crude oil (Bbls)	2,382,025		1,177,751		1,204,274			102%
Natural gas (Mcf)	1,588,894		326,707		1,262,187			386%
Natural gas liquids (Bbls)	172,547		29,662		142,885			482%
Total barrels of oil equivalent (Boe)	2,819,388		1,261,865		1,557,523			123%

Average realized prices (1):
Crude oil ($ per Bbl)	$	86.17	$	92.21	$	(6.04	)	(7)%
Natural gas ($ per Mcf)	$	5.88	$	4.40	$	1.48		34%
Natural gas liquids ($ per Bbl)	$	39.94	$	38.37	$	1.57		4%
Total average realized price ($ per Boe)	$	78.56	$	88.10	$	(9.54	)	(11)%

Oil, natural gas and natural gas liquids revenues (in thousands):
Crude oil	$	205,251	$	108,601	$	96,650		89%
Natural gas	9,337		1,437		7,900			550%
Natural gas liquids	6,891		1,138		5,753			506%
Total oil and natural gas revenues	$	221,479	$	111,176	$	110,303		99%

Operating expenses (in thousands):
Production taxes	$	23,662	$	12,524	$	11,138		89%
Lease operating expenses	18,741		9,489		9,252			98%
Gathering, transportation and processing	11,915		1,549		10,366			669%
Oil and natural gas amortization expense	70,015		33,507		36,508			109%
Accretion of other asset retirement obligations	324		37		287			776%
Total operating expenses	$	124,657	$	57,106	$	67,551		118%

Operating expenses per Boe:
Production taxes	$	8.39	$	9.92	$	(1.53	)	(15)%
Lease operating expenses	$	6.65	$	7.52	$	(0.87	)	(12)%
Gathering, transportation and processing	$	4.23	$	1.23	$	3.00		244%
Oil and natural gas amortization expense	$	24.83	$	26.55	$	(1.72	)	(6)%

(1) Excludes the impact of commodity derivative activity.

Oil, Natural Gas and Natural Gas Liquids Revenues

Revenues from oil, natural gas, and natural gas liquids production for the nine months ended October 31, 2014 increased 99% to $221.5 million from $111.2 million for the same period in fiscal year 2014, primarily due to the significant increase in oil production from new wells (as noted in “Recent Events - Drilling and Completions”), and the acquisition of producing wells in the third quarter of fiscal year 2014 and second quarter of fiscal year 2015, partially offset by normal production decline and a pricing decline in oil. Average realized oil prices in the first three quarters of fiscal year 2015 decreased to $86.17 per barrel from $92.21 per barrel in the same period in fiscal year 2014. In addition, during the nine months ended October 31, 2014, we experienced increases in both our

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volumes of natural gas and natural gas liquids sold, as a result of expanding gathering, transportation and processing infrastructure, and average prices received.

Production Taxes

Due primarily to the 99% increase in oil, natural gas and natural gas liquids revenues for the nine months ended October 31, 2014 as compared with the nine months ended October 31, 2013, our production taxes increased approximately 89% to $23.7 million from $12.5 million for the same period of fiscal year 2014. Production taxes decreased to $8.39 per Boe for the nine months ended October 31, 2014 from $9.92 per Boe for the nine months ended October 31, 2013 because natural gas and natural gas liquids are becoming a larger proportion of our total Boe sales and natural gas and natural gas liquids have lower tax rates than crude oil.

Lease Operating Expense

Lease operating expense decreased to $6.65 per Boe for the nine months ended October 31, 2014 from $7.52 per Boe for the nine months ended October 31, 2013. The cost decrease is primarily the result of efficiencies generated from operating more wells with labor and power costs spread across increased production.

Gathering, Transportation and Processing

GTP expenses increased to $4.23 per Boe for the nine months ended October 31, 2014 from $1.23 per Boe for the nine months ended October 31, 2013. This is primarily because in the third quarter of fiscal year 2014 we commenced gathering, transporting and processing significant amounts of our natural gas production that had previously been flared. Going forward, we expect our GTP costs to continue to increase (along with our revenues) 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 109% to $70.0 million for the nine months ended October 31, 2014 from $33.5 million for the nine months ended October 31, 2013. The increase is primarily related to increased production. On a per Boe basis, our oil and natural gas amortization expense decreased by $1.72 from $26.55 for the nine months ended October 31, 2013 to $24.83 for the nine months ended October 31, 2014. This decrease was primarily due to increases in proved reserves from successful development operations, field extensions and the acquisition of additional oil and gas properties.

Oilfield Services Gross Profit

During the nine months ended October 31, 2014, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and ten third-party customers. Equipment utilized to perform these services consisted of three frac spreads from February through April with a fourth frac spread deployed in mid-September, four wireline trucks, and five workover rigs. Hydraulic fracturing services resulted in 103 total well completions: 41 for TUSA and 62 for three third-parties.

We recognized $42.3 million and $5.8 million, respectively, of gross profit from oilfield services for the nine months ended October 31, 2014 and 2013, after elimination of $35.4 million and $27.1 million, respectively, of intercompany gross profit. See Note 4 — Segment Reporting under Item 1 of this Quarterly Report.

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The tables below are a summary of the Oilfield Services contribution to our consolidated results for the nine months ended October 31, 2014 and 2013, after eliminations:

	For the Nine Months Ended October 31, 2014
(in thousands)	Oilfield Services		Eliminations			Consolidated
Revenues
Oilfield services	$	307,687	$	(113,199	)	$	194,488
Total revenues	307,687		(113,199		)	194,488
Cost of sales
Oilfield services	215,340		(73,219		)	142,121
Depreciation	14,619		(4,600		)	10,019
Total cost of sales	229,959		(77,819		)	152,140
Gross profit	$	77,728	$	(35,380	)	$	42,348

	For the Nine Months Ended October 31, 2013
(in thousands)	Oilfield Services		Eliminations			Consolidated
Revenues
Oilfield services	$	137,896	$	(75,835	)	$	62,061
Total revenues	137,896		(75,835		)	62,061
Cost of sales
Oilfield services	99,330		(46,288		)	53,042
Depreciation	5,667		(2,455		)	3,212
Total cost of sales	104,997		(48,743		)	56,254
Gross profit	$	32,899	$	(27,092	)	$	5,807

General and Administrative Expenses

The following table summarizes general and administrative expenses for the nine months ended October 31, 2014 and 2013, respectively:

(in thousands)	Exploration and Production		Oilfield Services		Corporate		Consolidated Total
For the nine months ended October 31, 2014
Stock-based compensation	$	832	$	363	$	4,447	$	5,642
Salaries, benefits and other general and administrative	11,450		17,660		9,533		38,643
Total	$	12,282	$	18,023	$	13,980	$	44,285

For the nine months ended October 31, 2013
Stock-based compensation	$	897	$	458	$	4,134	$	5,489
Salaries, benefits and other general and administrative	5,844		7,576		5,262		18,682
Total	$	6,741	$	8,034	$	9,396	$	24,171

Total general and administrative expense increased $20.1 million to $44.3 million for the nine months ended October 31, 2014 compared to $24.2 million for the nine months ended October 31, 2013. The increase in corporate general and administrative expenses is primarily a result of increased compensation and benefit costs for personnel due to the growth of the business. In addition, during the nine months ended October 31, 2014, we incurred approximately $1.3 million of transaction costs associated with the Marathon Acquisition and the June 6, 2014 Acquisition. We did not incur similar costs during the nine months ended October 31, 2013. In addition, during the nine months ended October 31, 2014, we incurred a $1.3 million charge associated with the write off of accrued software costs associated with a land and accounting system conversion that is no longer contemplated.

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Derivative Activities

Commodity Derivatives

We have entered into commodity derivative instruments, primarily costless collars and swaps, 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, 2014, we recognized a $13.4 million gain on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a loss of $1.1 million during the nine 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.

Equity Investment Derivatives

Our equity investment in Caliber consists of Class A Units and equity derivative instruments. Due to the increase in the fair value of the equity investment derivatives in the first nine months of fiscal year 2015, the Company recognized a gain in equity investment derivatives of $3.7 million, as compared to a gain of $35.8 million for the nine months ended October 31, 2013. For additional discussion, please refer to Note 8 — Derivative Instruments under Item 1 of this Quarterly Report.

Income from Equity Investment

During the nine months ended October 31, 2014, the Company recognized $2.0 million for its share of Caliber’s income for the period. This income, however, was offset by $1.5 million of intra-company profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $0.5 million.

Interest Expense

The $17.7 million in interest expense for the nine months ended October 31, 2014 consists of (a) approximately $4.2 million in interest and amortized fees related to the TUSA Credit Facility, (b) approximately $4.9 million in accrued interest and amortized fees related to our 5.0% Convertible Note, (c) approximately $9.4 million in interest and amortized fees related to the TUSA 6.75% Notes, (d) approximately $1.5 million in interest expense associated with our RockPile Credit Facility and notes payable, (e) approximately $0.8 million in interest expense associated with the Second Lien Credit Facility, and (f) approximately $0.3 million in interest expense related to our other debt, all net of approximately $3.4 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $5.7 million of interest expense and capitalized interest was paid in cash. See Note 7 — Debt under Item 1 of this Quarterly Report for additional information regarding our debt outstanding.

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, (b) approximately $4.8 million in accrued interest and amortized fees related to our 5% Convertible Note and (c) approximately $0.6 million in interest expense associated with our RockPile Credit Facility and notes payable, all net of approximately $2.0 million of capitalized interest. Approximately $2.3 million of interest and capitalized interest was paid in cash.

Income Taxes

The effective tax rate for the nine months ended October 31, 2014, was 42.1%, which differs from the statutory income tax rate due primarily to permanent book to tax differences and state income taxes.

Liquidity and Capital Resources

Overview

Our liquidity is highly dependent on the prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and are historically volatile. Prices received for production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth. In addition, commodity prices received by exploration and production companies in the Williston Basin may affect the level of drilling activity there, and therefore may affect the demand for products and services provided by RockPile and/or Caliber.

In the third quarter of fiscal year 2015, our average realized price for oil was $79.11 per barrel, a significant decrease from the $94.47 per barrel realized price for the same period of fiscal year 2014. Future prices for oil will likely continue to fluctuate due to

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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, 2014, we had cash on hand of approximately $53.2 million, consisting primarily of cash held in bank accounts, as compared to approximately $81.8 million at January 31, 2014. We also had available borrowing capacity under the TUSA Credit Facility of $382.0 million and available borrowing capacity of $48.4 million under the RockPile credit facility as of October 31, 2014.

Capital Requirements Outlook

Our cash flow from operations has historically contributed minimally to funding our capital requirements, specifically with respect to our capital expenditure budget. We believe that the lag time between initial investment and cash flow from such investment is typical of the oil and gas industry. We expect our cash flow from operations to continue to increase significantly as additional TUSA oil and natural gas wells commence production, RockPile’s oilfield services increase, and Caliber’s gathering and processing system becomes fully operational. We also expect to adjust downward discretionary capital expenditures as market dynamics warrant. Nonetheless, we will likely remain dependent on borrowings under our credit facilities and, to a lesser extent, potential additional financings to fund the difference between cash flow from operations and our capital expenditures budget and other contractual commitments (see Note 7 - Debt under Item 1 of this Quarterly Report for further discussion). Although we expect that increases in our operating cash flow, proceeds from the issuance of the TUSA 6.75% Notes, and growing availability under our asset-backed credit facilities will be largely sufficient for our capital requirements, any additional shortfall may be financed through additional debt or equity instruments. There can be no assurance that we will achieve our anticipated future cash flow from operations, that credit will be available when needed, or that we would be able to complete alternative transactions in the capital markets, if needed.

We may also continue to pursue significant acquisition opportunities, which may require additional financing. Our ability to obtain additional 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, particularly if commodity prices remain depressed for an extended period of time, we have the flexibility to alter our development program or divest assets. 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 oilfield service environment. If we are not successful in obtaining sufficient funding on a timely basis on terms acceptable to us, we may be required to curtail our planned expenditures and/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), which may reduce anticipated future cash flow from operations. If we are unable to implement our planned exploration and drilling program, we may be unable to service our debt obligations or satisfy our contractual obligations.

Debt

As of October 31, 2014, we had $679.0 million of debt outstanding, of which $450.0 million was attributable to the TUSA 6.75% Notes, $134.2 million was attributable to our 5% Convertible Note, which is convertible into the Company’s common stock at a conversion rate of one share per $8.00 of principal outstanding, $51.6 million was attributable to the RockPile Credit Facility, $33.0 million was attributable to the TUSA Credit Facility and $10.2 million was attributable to other notes and mortgages outstanding. See Note 7 - Debt under Item 1 of this Quarterly Report for further discussion.

Working Capital

As part of our cash management strategy, we periodically use available funds to reduce amounts borrowed under our credit facilities. However, due to certain restrictive covenants contained in our credit facilities regarding our ability to dividend or otherwise transfer funds from the borrower 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. We had a working capital deficit of $6.4 million as of October 31, 2014, as compared to a positive working capital balance of $36.4 million as of January 31, 2014.

Commodity Derivative Instruments

We utilize various derivative instruments in connection with anticipated crude oil sales to reduce the impact of product price fluctuations. Currently, we utilize costless collars and swaps. 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

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the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than they would be 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.

Sources of Capital

Cash flow from operations

We expect our cash flow from operations (before changes in related current assets and current liabilities) 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 three 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 changes in the market price of crude oil, we would expect our production rates and operating cash flows to continue to increase over time as we continue to develop our properties and our RockPile services.

Credit facilities

As of October 31, 2014, our maximum credit available under the TUSA Credit Facility was $500.0 million, subject to a borrowing base of $415.0 million. As of October 31, 2014, we had $382.0 million of borrowing capacity available. Upon entry into the TUSA Credit Agreement on November 25, 2014, our maximum credit available was increased to $1.0 billion, subject to a borrowing base of $435.0 million. The borrowing base under the TUSA Credit Agreement is subject to redetermination on a semi-annual basis by each May 1st and November 1st. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year.

On March 25, 2014, RockPile entered into the RockPile Credit Facility, which provides a $100.0 million senior secured revolving credit facility with an accordion feature that allows for the expansion of the facility up to an aggregate of $150.0 million. Borrowings under the RockPile Credit Facility are available to (i) repay existing debt, (ii) provide for the working capital and general corporate requirements of RockPile, (iii) fund capital expenditures, (iv) pay any fees and expenses associated with the RockPile Credit Facility, and (v) support letters of credit. Upon entry into Amendment No. 1, the borrowing capacity under the facility increased from $100.0 million to $150.0 million while maintaining the $50.0 million accordion feature, resulting in aggregate borrowing capacity of $200.0 million.

Analysis and Changes in Cash Flow

The following is a summary of our change in cash and cash equivalents for the three months ended October 31, 2014 and 2013:

	For the Nine Months Ended October 31,
(in thousands)	2014			2013			Change
Net cash provided by operating activities	$	102,423		$	15,739		$	86,684
Net cash used in investing activities	(402,810		)	(328,664		)	(74,146		)
Net cash provided by financing activities	271,873			379,971			(108,098		)
Net increase (decrease) in cash and equivalents	$	(28,514	)	$	67,046		$	(95,560	)

Net Cash Provided by Operating Activities

Cash flows provided by operating activities were $102.4 million for the nine months ended October 31, 2014. Cash flows provided by operating activities were $15.7 million for the nine months ended October 31, 2013. The increase in operating cash flows was primarily due to higher oil revenues driven by higher sales volumes and increased contributions from RockPile, partially offset by related increases in production expenses, production taxes, general and administrative expenses, and other expenses associated with the growth of our operations during the period and the net change in the components of our working capital.

Net Cash Used in Investing Activities

During the nine months ended October 31, 2014, we used $402.8 million in cash in investing activities compared to $328.7 million during the nine months ended October 31, 2013. During both nine month periods, our primary uses of cash flow in investing activities were related to our oil and gas property expenditures. During the nine months ended October 31, 2014 and 2013, we used $351.2 million and $294.3 million, respectively, on oil and gas property additions. During the nine months ended October 31, 2014

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and 2013, we spent $41.3 million and $26.2 million, respectively, on purchases of oilfield services equipment. During the nine months ended October 31, 2014 and 2013, we also spent $12.1 million and $5.3 million, respectively, on other property and equipment, namely facility construction and improvements. Finally, during the nine months ended October 31, 2013, we also used $9.0 million to meet our Caliber equity funding commitment.

Net Cash Provided by Financing Activities

Cash flows provided by financing activities for the nine months ended October 31, 2014 totaled $271.9 million, as compared to $380.0 million for the nine months ended October 31, 2013. Our primary source of cash from financing activities during the nine months ended October 31, 2014 came from the issuance of $450 million of our TUSA 6.75% Notes, net of net repayments on our credit facilities. We also used $42.5 million of cash in common stock repurchase activity. During the nine months ended October 31, 2013, in addition to net credit facility borrowings, we also had net proceeds of $245.3 million from issuances of our common stock.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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 may 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 oilfield services. Currently, we use costless collars and swaps to reduce the effect of price changes on a portion of our future oil production. We currently have no derivative positions on natural gas, however we continue to evaluate both our production levels and market activity and may enter into natural gas derivative positions in the future. We do not enter into derivative instruments for speculative 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.

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 provides 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.

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The Company’s commodity derivative contracts as of October 31, 2014 are summarized below:

Term End Date	Contract Type	Basis (1)	Quantity (Bbl/d)	Weighted Average Put Strike		Weighted Average Call Strike
Fiscal Year 2015	Collar	NYMEX	5,899	$	87.40	$	99.90
Fiscal Year 2016	Collar	NYMEX	4,356	$	86.85	$	98.06

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

We determine the estimated fair value of commodity 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 whether the counterparty 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 commodity derivative instruments at October 31, 2014 was a net asset of $19.4 million. This mark-to-market net asset relates to commodity derivative instruments with various terms that are scheduled to be realized over the period from November 2014 through December 2015. Over this period, actual realized commodity derivative settlements may differ significantly, either positively or negatively, from the unrealized mark-to-market valuation at October 31, 2014. An assumed decrease of 10.0% in the forward commodity prices used in the October 31, 2014 valuation of our commodity derivative instruments would result in a net increase to our commodity derivative asset of approximately $14.3 million at October 31, 2014. Conversely, an assumed increase of 10.0% in forward commodity prices would result in a net decrease of $11.8 million at October 31, 2014.

Interest Rate Risk

At October 31, 2014, the Company had approximately $134.2 million of principal outstanding under the 5% Convertible Note, which has a fixed interest rate of 5.0%. Such interest is paid-in-kind each calendar quarter by adding to the principal balance of the note; provided that, after October 31, 2017, we have the option to make such interest payments in cash.

TUSA Interest Rate Risk

As of October 31, 2014, the borrowing base under the TUSA Credit Facility was $415.0 million, and $33.0 million was drawn as of such date. The credit facility bears interest at variable rates. Assuming TUSA had the maximum allowable amount outstanding at October 31, 2014, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $4.2 million. For a detailed discussion of the TUSA Credit Facility, including a discussion of the applicable interest rates, please refer to Note 7 —Debt under Item 1 of this Quarterly Report.

At October 31, 2014, TUSA had $450.0 million outstanding under the TUSA 6.75% Notes, which have a fixed interest rate of 6.75%. Interest on the TUSA 6.75% Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2015. The TUSA 6.75% Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture.

RockPile Interest Rate Risk

As of October 31, 2014, the borrowing base under the RockPile Credit Facility was $100.0 million, and $51.6 million was drawn as of such date. The RockPile Credit Facility bears interest at variable rates. Assuming RockPile had the maximum allowable amount outstanding at October 31, 2014, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $1.0 million. For a detailed discussion of the RockPile Credit Facility, including a discussion of the applicable interest rates, please refer to Note 7 — Debt under Item 1 of this Quarterly Report.

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ITEM 4. CONTROLS AND PROCEDURES

Material Weaknesses in Internal Control over Financial Reporting

As previously discussed in Item 9A “Controls and Procedures” of our Fiscal 2014 Form 10-K, we reported a material weakness in our controls over the identification of and accounting for certain derivative instruments.

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 and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under 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. Due to the material weaknesses described above, our Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were not effective as of October 31, 2014.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act), other than discussed in the following paragraph, that occurred during the three months ended October 31, 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the three months ended October 31, 2014, we continued to remediate the material internal control weakness related to identifying and accounting for certain derivative instruments as reported in our Fiscal 2014 Form 10-K. The Company has implemented a new control to review all transactions and new agreements entered into during the financial reporting period with the purpose of identifying all potential derivative instruments and ensuring that they are accounted for properly.

Plan of Remediation of Material Weaknesses

Triangle has updated its accounting policies relating to equity investments and associated derivatives. The Company implemented a new control to review all transactions and new agreements entered into during the financial reporting period with the purpose of identifying all potential derivative instruments and ensuring that they are accounted for properly.

Triangle’s remediation plan has been implemented; however, the above material weakness will not be considered remediated until the additional review procedures over derivatives have been operating effectively for an adequate period of time. Management will consider the status of this remediation effort when assessing the effectiveness of the Company’s internal controls over financial reporting and other disclosure controls and procedures throughout fiscal year 2015. While management believes that the remediation efforts will resolve the identified material weakness, there is no assurance that management’s remediation efforts conducted to date will be sufficient or that additional remediation actions will not be necessary.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

We are involved in disputes and legal proceedings arising in the ordinary course of our business. Litigation is subject to inherent uncertainties, and an adverse result in these or other matters may occur from time to time that may harm our business. We are currently not aware of any disputes or legal proceedings 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.

There have been no material changes to the risk factors set forth in our Fiscal 2014 Form 10-K and in our Form 10-Q for the quarterly period ended July 31, 2014. Those risk factors, in addition to the other information set forth in this Quarterly Report on Form 10-Q, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

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

The following table summarizes our purchases of shares of our common stock during the fiscal quarter ended October 31, 2014:

	Total Number of		Average Price		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or
	Shares Purchased		Paid Per Share		(2)	programs
August 1, 2014 to August 31, 2014	21,882		$	11.34	—	15,966,081	(3)
September 1, 2014 to September 30, 2014	630,474		11.19		746,100	15,426,220	(4)
October 1, 2014 to October 31, 2014	4,321,968		8.77		4,185,644	11,240,576
	4,974,324	(1)	$	9.09	4,931,744

(1) Includes 42,580 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. 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. The withheld shares are not issued or considered common stock repurchased under the repurchase program described below.

(2) As reported in Current Reports on Form 8-K filed with the SEC on September 11, 2014 and October 17, 2014, the Company’s Board of Directors approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the 5% Convertible Note (“Tranche 2”), and (iii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 3”). Shares repurchased under the program may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program may be executed using open market purchases pursuant to Rule 10b-18 under the Securities Exchange Act of 1934, as amended, pursuant to a Rule 10b5-1 plan, in privately negotiated agreements, or other transactions. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. As of October 31, 2014, an aggregate of 4,931,744 shares of the Company’s common stock have been repurchased under the program.

(3) Includes the number of shares actually repurchased pursuant to Tranche 1 during the fiscal quarter ended October 31, 2014, which exhausted all shares available for repurchase under Tranche 1, plus the number of shares available for repurchase pursuant to Tranche 2 based on the paid-in-kind interest accrued on the 5% Convertible Note as of August 31, 2014, plus the number of shares available for repurchase pursuant to Tranche 3.

(4) Includes an additional 206,239 shares potentially issuable pursuant to the paid-in-kind interest added to the principal balance of the 5% Convertible Note on September 30, 2014.

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Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not Applicable.

Item 5. Other Information.

On December 4, 2014, the Company’s Board of Directors appointed Douglas Griggs, the Company’s Chief Accounting Officer since November 5, 2014, to serve as the Company’s principal accounting officer effective upon the filing of the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended October 31, 2014 (the “FY15 Q3 10-Q”). Also on December 4, 2014, Wade Stubblefield of Opportune LLC, the Company’s then acting principal accounting officer since May 2014, submitted his resignation from the principal accounting officer role to be effective upon the filing of the FY15 Q3 10-Q.

Douglas Griggs, age 55, is a certified public accountant with over thirty-three years of accounting and financial management experience. Mr. Griggs previously served as the Chief Accounting Officer of Venoco, Inc. from January 2006 through October 2014, prior to which he was an independent consultant in the areas of finance, accounting, project management and Sarbanes-Oxley compliance since January 2003. Mr. Griggs was formerly an Audit Senior Manager with Ernst & Young LLP, and he subsequently held various financial management positions prior to beginning consulting work in 2003. Mr. Griggs has an accounting degree from the University of Northern Iowa.

Mr. Griggs did not enter into any material plan, contract or arrangement with the Company in connection with his hiring as Chief Accounting Officer or his appointment as principal accounting officer. He 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.

Item 6. Exhibits.

3.1		Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.1 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.

3.2		Certificate of Amendment to the Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.2 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.

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		Amended and Restated Employment Agreement, dated September 9, 2014, between Triangle Petroleum Corporation and Justin Bliffen, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2014 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 or furnished herewith, as applicable.

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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 8, 2014	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	President and Chief Executive Officer


Date: December 8, 2014	By:	/s/ JUSTIN BLIFFEN
	Justin Bliffen
	Chief Financial Officer

Triangle Petroleum Corp - FORM 10-Q - December 8, 2014

Attached files

Triangle Petroleum Corp Reports