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 July 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 September 5, 2014, there were 86,250,905 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 JULY 31, 2014

PART I. FINANCIAL INFORMATION

	ITEM 1.	Financial Statements

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

		Condensed Consolidated Statements of Operations and Comprehensive Income — Three and Six months ended July 31, 2014 and 2013	5

		Condensed Consolidated Statements of Cash Flows — Six months ended July 31, 2014 and 2013	6

		Condensed Consolidated Statement of Stockholders’ Equity — Six months ended July 31, 2014	7

		Notes to Condensed Consolidated Financial Statements	8

	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	46

	ITEM 4.	Controls and Procedures	48

PART II. OTHER INFORMATION

	ITEM 1.	Legal Proceedings	49
	ITEM 1A.	Risk Factors	49
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
	ITEM 3.	Defaults Upon Senior Securities	49
	ITEM 4.	Mine Safety Disclosures	49
	ITEM 5.	Other Information	49
	ITEM 6.	Exhibits	50

	SIGNATURES		51

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Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets

(In thousands, except share data)

(Unaudited)

	July 31, 2014			January 31, 2014
ASSETS
CURRENT ASSETS
Cash and equivalents	$	107,527		$	81,750
Accounts receivable:
Oil, natural gas and natural gas liquids sales	28,505			20,450
Trade	122,382			86,074
Derivative asset	—			955
Deferred tax asset	321			321
Inventory, deposits and prepaid expenses	5,916			5,331
Total current assets	264,651			194,881

LONG-TERM ASSETS
Oil and natural gas properties at cost, using the full cost method of accounting:
Unproved properties and properties under development, not being amortized	144,023			121,393
Proved properties	924,419			629,051
Total oil and natural gas properties at cost	1,068,442			750,444
Less: accumulated amortization	(109,686		)	(67,657		)
Net oil and natural gas properties	958,756			682,787
Oilfield services equipment, net	64,379			46,586
Other property and equipment, net	28,718			24,507
Equity investment	72,337			68,536
Goodwill	1,680			1,680
Intangible assets, net	3,604			3,862
Derivative asset	136			1,192
Other long-term assets	14,193			3,553
Total assets	$	1,408,454		$	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)

	July 31, 2014			January 31, 2014
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	72,849		$	60,016
Accrued liabilities:
Exploration and development	54,532			34,131
Other	59,137			53,037
Debt	411			8,851
Derivative liability	994			—
Asset retirement obligations	3,400			3,333
Total current liabilities	191,323			159,368

LONG-TERM LIABILITIES
6.75% senior notes	450,000			—
5% convertible note	132,543			129,290
Borrowings on credit facilities	39,616			196,065
Other notes payable	9,854			9,002
Asset retirement obligations	2,374			1,296
Deferred tax liability	28,062			8,262
Other	1,195			1,139
Total liabilities	854,967			504,422

COMMITMENTS AND CONTINGENCIES (Note 10)

STOCKHOLDERS’ EQUITY
Common stock, $0.00001 par value, 140,000,000 shares authorized; 86,231,719 and 85,735,827 shares issued and outstanding at July 31, 2014 and January 31, 2014, respectively	—			—
Additional paid-in capital	572,933			571,702
Accumulated deficit	(19,446		)	(48,540		)
Accumulated other comprehensive income	—			—
Total stockholders’ equity	553,487			523,162
Total liabilities and stockholders’ equity	$	1,408,454		$	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 and Comprehensive Income

(In thousands, except per share data)

(Unaudited)

	For the Three Months Ended July 31,						For the Six Months Ended July 31,
	2014			2013			2014			2013
REVENUES:
Oil, natural gas and natural gas liquids sales	$	80,506		$	34,639		$	141,340		$	55,699
Oilfield services	61,483			15,755			100,431			28,989
Total revenues	141,989			50,394			241,771			84,688
EXPENSES:
Production taxes	8,677			3,919			15,025			6,363
Lease operating expenses	6,698			2,830			11,424			5,046
Gathering, transportation and processing	3,733			69			7,535			106
Depreciation and amortization	26,706			10,918			47,884			18,391
Accretion of asset retirement obligations	41			9			175			17
Oilfield services	43,554			12,692			71,264			23,878
General and administrative:
Stock-based compensation	1,807			1,438			3,815			3,033
Salaries and benefits	5,677			4,133			12,794			7,258
Other general and administrative	6,607			1,413			10,883			3,295
Total operating expenses	103,500			37,421			180,799			67,387

INCOME FROM OPERATIONS	38,489			12,973			60,972			17,301

OTHER INCOME (EXPENSE):
Gain (loss) on equity investment derivatives	(7,534		)	—			2,920			—
Loss from commodity derivative activities	(921		)	(4,399		)	(6,377		)	(3,187		)
Interest expense	(5,385		)	(1,969		)	(8,249		)	(3,441		)
Income (loss) from equity investment	190			(596		)	64			—
Interest income	47			43			107			80
Other income	5			747			7			1,257
Total other income (expense)	(13,598		)	(6,174		)	(11,528		)	(5,291		)

NET INCOME BEFORE INCOME TAXES	24,891			6,799			49,444			12,010
Income tax provision	(10,339		)	—			(20,350		)	—
NET INCOME	$	14,552		$	6,799		$	29,094		$	12,010

Net income per common share outstanding:
Basic	$	0.17		$	0.12		$	0.34		$	0.22
Diluted	$	0.15		$	0.12		$	0.30		$	0.22

Weighted average common shares outstanding:
Basic	86,172			56,451			86,064			54,561
Diluted	103,774			57,012			103,511			55,089

COMPREHENSIVE INCOME:
Net income attributable to common stockholders	$	14,552		$	6,799		29,094			$	12,010
Other comprehensive income	—			—			—			—
Total comprehensive income	$	14,552		$	6,799		$	29,094		$	12,010

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

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Triangle Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	For the Six Months Ended
	July 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	29,094		$	12,010
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	47,884			18,391
Stock-based compensation	3,815			3,033
Interest expense not paid in cash	3,532			2,545
Accretion of asset retirement obligations	175			17
Loss on commodity derivative activities	6,377			3,187
Gain on equity investment derivatives	(2,919		)	—
Settlements of commodity derivative instruments	(3,372		)	—
Income from equity investment	(64		)	—
Unrealized income on securities held for investment	—			(990		)
Deferred income taxes	19,800			—
Changes in related current assets and current liabilities:
Accounts receivable:
Oil and natural gas sales	(8,055		)	(10,059		)
Trade	(36,308		)	(10,329		)
Inventory, deposits and prepaid expenses	(581		)	(1,025		)
Accounts payable and accrued liabilities	2,994			15,101
Asset retirement expenditures	(136		)	(484		)
Other	(390		)	36
Cash provided by operating activities	61,846			31,433

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures and acquisitions	(280,847		)	(130,132		)
Purchases of oilfield services equipment	(24,579		)	(15,953		)
Purchases of other property and equipment	(3,080		)	(4,318		)
Equity investment in Caliber Midstream Partners, L.P.	—			(9,000		)
Other	58			—
Cash used in investing activities	(308,448		)	(159,403		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock	—			55,800
Proceeds from credit facilities	245,116			90,320
Repayments of credit facilities	(410,015		)	(5,000		)
Proceeds from notes payable	450,000			5,876
Repayments of notes payable	(199		)	(1,538		)
Debt issuance costs	(10,331		)	—
Cash paid to settle tax on vested restricted stock units	(2,192		)	(1,225		)
Cash provided by financing activities	272,379			144,233

NET INCREASE IN CASH AND EQUIVALENTS	25,777			16,263
CASH AND EQUIVALENTS, BEGINNING OF PERIOD	81,750			33,117
CASH AND EQUIVALENTS, END OF PERIOD	$	107,527		$	49,380

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

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Triangle Petroleum Corporation

Condensed Consolidated Statement of Stockholders’ Equity

For the Six Months Ended July 31, 2014

(in thousands, except share data)

(Unaudited)

	Shares of Common Stock	Common Stock at Par Value		Additional Paid-in Capital			Accumulated Deficit			Total Equity
Balance - January 31, 2014	85,735,827	$	—	$	571,702		$	(48,540	)	$	523,162
Vesting of restricted stock units (net of shares surrendered for taxes)	495,892	—		(2,192		)	—			(2,192		)
Redeemed RockPile B-Units	—			(1,041		)	—			(1,041		)
Stock-based compensation	—	—		4,464			—			4,464
Net income for the period	—	—		—			29,094			29,094
Balance - July 31, 2014	86,231,719	$	—	$	572,933		$	(19,446	)	$	553,487

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

July 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 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.

The Company also holds leasehold interests in acreage in the Maritimes Basin of Nova Scotia.

2. BASIS OF PRESENTATION

These unaudited condensed consolidated financial statements as of July 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. Note 3 — Summary of Significant Accounting Policies describes our significant accounting policies.

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, filed with the SEC on April 17, 2014 (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 six months ended July 31, 2014, are not necessarily indicative of the operating results for the entire fiscal year ending January 31, 2015.

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;

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

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· 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. See Note 6 - Equity Investment for further discussion.

Reclassifications

Certain amounts in the condensed consolidated balance sheet as of January 31, 2014, and in our condensed consolidated statement of operations and comprehensive income for the quarter ended July 31, 2013, have been reclassified to conform to the financial statement presentation for the quarter ended July 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 May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“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.

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 standard discussed above, there are no significant accounting standards applicable to Triangle which have not been adopted.

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 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.

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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 July 31, 2014 and 2013:

	For the Three Months Ended July 31, 2014
(in thousands)	Exploration and Production			Oilfield Services			Corporate and Other			Eliminations			Consolidated Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	80,506		$	—		$	—		$	—		$	80,506
Oilfield services for third parties	—			64,093			—			(2,610		)	61,483
Intersegment revenues	—			37,962			—			(37,962		)	—
Other	—			—			272			(272		)	—
Total revenues	80,506			102,055			272			(40,844		)	141,989
Expenses:
Production taxes and other lease operating	15,375			—			—			—			15,375
Gathering, transportation and processing	3,733			—			—			—			3,733
Depreciation and amortization	23,439			4,690			186			(1,609		)	26,706
Accretion of asset retirement obligations	41			—			—			—			41
Cost of oilfield services	—			68,867			—			(25,313		)	43,554
General and administrative:
Stock-based compensation	344			127			1,336			—			1,807
Other general and administrative	4,442			5,251			2,591			—			12,284
Total operating expenses	47,374			78,935			4,113			(26,922		)	103,500
Income (loss) from operations	33,132			23,120			(3,841		)	(13,922		)	38,489
Other income (expense), net	(4,267		)	(667		)	(7,580		)	(1,084		)	(13,598		)
Net income (loss) before income taxes	$	28,865		$	22,453		$	(11,421	)	$	(15,006	)	$	24,891

	For the Three Months Ended July 31, 2013
(in thousands)	Exploration and Production			Oilfield Services			Corporate and Other			Eliminations			Consolidated Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	34,639		$	—		$	—		$	—		$	34,639
Oilfield services for third parties	—			17,137			—			(1,382		)	15,755
Intersegment revenues	—			27,148			—			(27,148		)	—
Other	—			—			272			(272		)	—
Total revenues	34,639			44,285			272			(28,802		)	50,394
Expenses:
Production taxes and other lease operating	6,749			—			—			—			6,749
Gathering, transportation and processing	69			—			—			—			69
Depreciation and amortization	10,111			1,600			135			(928		)	10,918
Accretion of asset retirement obligations	9			—			—			—			9
Cost of oilfield services	—			30,370			—			(17,678		)	12,692
General and administrative:
Stock-based compensation	247			99			1,092			—			1,438
Other general and administrative	1,683			2,446			1,417			—			5,546
Total operating expenses	18,868			34,515			2,644			(18,606		)	37,421
Income (loss) from operations	15,771			9,770			(2,372		)	(10,196		)	12,973
Other income (expense), net	(4,087		)	(216		)	(578		)	(1,293		)	(6,174		)
Net income (loss) before income taxes	$	11,684		$	9,554		$	(2,950	)	$	(11,489	)	$	6,799

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

	For the Six Months Ended July 31, 2014
(in thousands)	Exploration and Production			Oilfield Services			Corporate and Other			Eliminations			Consolidated Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	141,340		$	—		$	—		$	—		$	141,340
Oilfield services for third parties	—			103,650			—			(3,219		)	100,431
Intersegment revenues	—			59,837			—			(59,837		)	—
Other	—			—			449			(449		)	—
Total revenues	141,340			163,487			449			(63,505		)	241,771
Expenses
Production taxes and other lease operating	26,449			—			—			—			26,449
Gathering, transportation and processing	7,535			—			—			—			7,535
Depreciation and amortization	42,051			8,280			362			(2,809		)	47,884
Accretion of asset retirement obligations	175			—			—			—			175
Cost of oilfield services	—			112,578			—			(41,314		)	71,264
General and administrative:
Stock-based compensation	739			217			2,859			—			3,815
Other general and administrative	7,220			10,348			6,109			—			23,677
Total operating expenses	84,169			131,423			9,330			(44,123		)	180,799
Income (loss) from operations	57,171			32,064			(8,881		)	(19,382		)	60,972
Other income (expense), net	(10,834		)	(1,174		)	1,741			(1,261		)	(11,528		)
Net income (loss) before income taxes	$	46,337		$	30,890		$	(7,140	)	$	(20,643	)	$	49,444

	As of July 31, 2014
Net oil and natural gas properties	$	1,027,074	$	—	$	—	$	(68,318	)	$	958,756
Oilfield services equipment - net	$	—	$	64,379	$	—	$	—		$	64,379
Other property and equipment - net	$	1,562	$	20,372	$	6,784	$	—		$	28,718
Total assets (1)	$	1,188,878	$	171,550	$	168,143	$	(120,117	)	$	1,408,454
Total liabilities	$	659,922	$	89,387	$	136,137	$	(30,479	)	$	854,967

(1) Our Corporate and Other total assets consist primarily of cash and cash equivalents of $64.4 million and our investment in Caliber of $72.3 million, in addition to the Company’s investment in its subsidiaries which are subsequently eliminated.

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	For the Six Months Ended July 31, 2013
(in thousands)	Exploration and Production			Oilfield Services			Corporate and Other			Eliminations			Consolidated Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	55,699		$	—		$	—		$	—		$	55,699
Oilfield services for third parties	—			32,281			—			(3,292		)	28,989
Intersegment revenues	—			38,887			—			(38,887		)	—
Other	—			—			548			(548		)	—
Total revenues	55,699			71,168			548			(42,727		)	84,688
Expenses:
Production taxes and other lease operating	11,409			—			—			—			11,409
Gathering, transportation and processing	106			—			—			—			106
Depreciation and amortization	16,729			2,839			258			(1,435		)	18,391
Accretion of asset retirement obligations	17			—			—			—			17
Cost of oilfield services	—			49,491			—			(25,613		)	23,878
General and administrative:
Stock-based compensation	569			310			2,154			—			3,033
Other general and administrative	3,250			4,425			2,878			—			10,553
Total operating expenses	32,080			57,065			5,290			(27,048		)	67,387
Income (loss) from operations	23,619			14,103			(4,742		)	(15,679		)	17,301
Other income (expense), net	(2,636		)	(369		)	(993		)	(1,293		)	(5,291		)
Net income (loss) before income taxes	$	20,983		$	13,734		$	(5,735	)	$	(16,972	)	$	12,010

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 $2.6 million and $1.4 million in oilfield service income for the three month periods ended July 31, 2014 and 2013, respectively, and approximately $3.2 million and $3.3 million in oilfield service income for the six month periods ended July 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 service income against oilfield service revenue and crediting capitalized oil and natural gas properties.

In addition, we deferred approximately $0.6 million and $0.7 million of Caliber gross profit from our share of its income for the three months ended July 31, 2014 and 2013, respectively and approximately $0.8 million and $1.3 million for the six months ended July 31, 2014 and 2013, respectively, associated with services it provided which were capitalized by TUSA, by charging such gross profit against income (loss) from equity investment and crediting capitalized oil and natural gas properties. See Note 6 - Equity Investment for further discussion.

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

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5. PROPERTY AND EQUIPMENT

Acquisitions

Kodiak Oil & Gas Property Acquisition

On August 28, 2013, we acquired from Kodiak Oil & Gas Corporation (“Kodiak”) interests in approximately 5,600 net acres of Williston Basin leaseholds, and related producing properties along with various other related rights, permits, contracts, equipment and other assets located in McKenzie County, North Dakota for approximately $83.0 million in cash. Transaction costs related to the acquisition incurred during fiscal year 2014 were approximately $0.2 million and are recorded in the statement of operations within the general and administrative expenses line item.

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 August 28, 2013. The following table summarizes the final purchase price and the values of assets acquired and liabilities assumed:

(in thousands)
Final purchase price:
Consideration given
Cash			$	83,044
Total consideration given			$	83,044

Final fair value allocation of purchase price:
Accounts receivable			$	5,503
Oil and natural gas properties:
Proved properties	$	50,332
Unproved properties	30,235
Total oil and natural gas properties			80,567
Accounts payable			(2,894		)
Asset retirement obligations assumed			(132		)
Fair value of net assets acquired			$	83,044

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 for the three months ended July 31, 2014 were approximately $1.3 million and are recorded in the statement of operations within the general and administrative expenses line item.

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.

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

(in thousands)
Preliminary purchase price:
Consideration given
Cash			$	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 and Marathon for the three month and six months ended July 31, 2013, and for the properties acquired from Marathon for the three and six months ended July 31, 2014, as if the acquisitions had occurred on February 1, 2012 and February 1, 2013, respectively.

	For the Three Months Ended July 31,				For the Six Months Ended July 31,
(in thousands, except per share data)	2014		2013		2014		2013
Operating revenues	$	146,559	$	66,401	$	253,206	$	119,072
Net income	$	15,217	$	11,453	$	31,122	$	23,709

Earnings per common share
Basic	$	0.18	$	0.20	$	0.36	$	0.43
Diluted	$	0.16	$	0.20	$	0.32	$	0.43

Weighted average common shares outstanding:
Basic	86,172		56,451		86,064		54,561
Diluted	103,774		57,012		103,511		55,089

The pro forma information includes the effects of adjustments for depreciation, amortization and accretion expense of $1.3 million and $5.0 million for the three months ended July 31, 2014 and 2013, respectively, and $3.3 million and $10.9 million for the six months ended July 31, 2014 and 2013, respectively. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisitions had been completed on February 1, 2012 or 2013, respectively, nor are they necessarily indicative of future results. During the three and six months ended July 31, 2014, the Company realized $2.0 million of revenue and $0.5 million of net earnings 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.

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Oil and Natural Gas Property Additions

During the six months ended July 31, 2014, we acquired oil and natural gas properties, and participated in the drilling and/or completion of wells, for total consideration of approximately $318.0 million.

During the three and six months ended July 31, 2014, we capitalized $1.2 million and $2.4 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 six months ended July 31, 2013, we capitalized $0.9 million and $1.7 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 $24.6 million during the six months ended July 31, 2014, consist primarily of the costs for two hydraulic fracturing spreads and other complementary well completion and workover equipment, $21.9 million of which was in service and $2.7 million of which was not yet placed in service at July 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 comprehensive 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 July 31, 2014. We do not guarantee or otherwise support Caliber’s $200.0 million credit facility, and, as such, we would not have additional exposure associated with any borrowings on Caliber’s credit facility. On June 30, 2014, the Company vested in the 4,000,000 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.

As of July 31, 2014, the balance of the Company’s investment in Caliber was $72.3 million, which consisted of the following:

(in thousands, except units)	Units	Change In Value			Investment
Balance - January 31, 2014					$	68,536
Change in fair value of:
Class A Trigger Units	4,000,000	$	1,746		1,746
Class A Trigger Unit Warrant	1,600,000	$	532		532
Series 1 Warrants	4,000,000	$	994		994
Series 2 Warrants	2,400,000	$	(182	)	(182		)
Series 3 Warrants	3,000,000	$	(117	)	(117		)
Series 4 Warrants	2,000,000	$	(53	)	(53		)
Equity investment share of net income for the period before intra-company profit elimination					881
Balance - July 31, 2014					$	72,337

See Note 8 — Derivative Instruments for a discussion of the change in fair value of the Company’s equity derivative instruments noted above.

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7. LONG-TERM DEBT

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

(in thousands)	July 31, 2014			January 31, 2014
6.75% Senior Notes	$	450,000		$	—
5% Convertible Note	132,543			129,290
TUSA credit facility	—			183,000
RockPile credit facility	39,616			21,515
RockPile notes and mortgages payable	10,265			9,403
Total debt	632,424			343,208
Less current portion of debt:
RockPile credit facility	—			(8,450		)
RockPile notes and mortgages payable	(411		)	(401		)
Total long-term debt	$	632,013		$	334,357

6.75% Senior 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 $450,000,000 aggregate principal amount of 6.75% Senior Notes due 2022 (the “6.75% Senior Notes”).

The 6.75% Senior 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 6.75% Senior Notes are senior unsecured obligations of TUSA and are guaranteed on a senior unsecured basis by the Guarantor. The 6.75% Senior 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 6.75% Senior Notes bear interest at a rate of 6.75% per year, accruing from July 18, 2014. Interest on the 6.75% Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2015. The 6.75% Senior Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture. The Company incurred $10.0 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 6.75% Senior 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 6.75% Senior 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 6.75% Senior 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 July 31, 2014, TUSA was in compliance with all covenants under the 6.75% Senior Notes.

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 (see Note 13 — Long-Term Debt in our audited financial statements included in our Fiscal 2014 Form 10-K).

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

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paid-in-kind by adding to the principal balance of the 5% Convertible Note, provided that, after July 31, 2017, the Company has the option to make such interest payments in cash. As of July 31, 2014, $12.5 million of accrued interest has been added to the principal balance of the 5% Convertible Note.

TUSA Credit Facility

On January 13, 2014, TUSA entered into Amendment No. 3 to the Amended and Restated Credit Agreement and Master Assignment (“Amendment No. 3”) with Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent and issuing lender, and the other lenders named therein, as lenders. Amendment No. 3 amended that certain Amended and Restated Credit Agreement (the “A&R Credit Agreement”), dated April 11, 2013, as amended by that certain Amendment No. 1 to Amended and Restated Credit Agreement and Master Assignment, dated July 30, 2013, and that certain Amendment No. 2 to Amendment and Restated Master Assignment, dated October 16, 2013, to (i) broaden the definition of “Independent Engineering Report” to include a report prepared by or under the supervision of TUSA’s engineers if certain requirements are satisfied, and (ii) increase the borrowing base under the TUSA Credit Facility from $275.0 million to $320.0 million. The amendments in Amendment No. 1 remaining in force were (i) provisions permitting TUSA to hedge up to 85.0% of the anticipated production of (x) oil, (y) gas, and (z) natural gas liquid volumes, respectively, attributable to TUSA’s total proved reserves, and (ii) revisions enabling TUSA to enter into a second lien credit facility at a future date. The amendments in Amendment No. 2 remaining in force were (i) the addition of three new lenders under the facility, (ii) the extension of the maturity date to October 16, 2018, and (iii) the decrease of the applicable margins for ABR and Eurodollar advances by 0.25% at all utilization levels. Further, the existing lenders assigned a portion of their lending commitments to the three new lenders.

On May 9, 2014, TUSA entered into Amendment No. 4 to the A&R Credit Agreement (“Amendment No. 4”) with Wells Fargo as administrative agent and issuing lender, and the other lenders named therein, as lenders. Amendment No. 4 amended the A&R Credit Agreement to (i) increase the borrowing base under the facility from $320.0 million to $355.0 million, (ii) add three new lenders to the facility, (iii) add a borrowing base redetermination by August 1, 2014, (iv) cause the borrowing base to increase by up to an additional $10.0 million upon closing the June 6, 2014 Acquisition, (v) permit a one-time distribution to the Company of any funds contributed by the Company to TUSA in connection with closing the June 6, 2014 Acquisition (the “Permitted Distribution”), and (vi) permit TUSA to enter into a second lien credit facility of up to $100.0 million.

On May 14, 2014, TUSA entered into Amendment No. 5 to the A&R Credit Agreement (“Amendment No. 5”) with Wells Fargo, as administrative agent and issuing lender, and the other lenders named therein, as lenders. Amendment No. 5 amended the A&R Credit Agreement, as amended by Amendment No. 4, to (i) cause the borrowing base to increase by up to an additional $40.0 million upon closing the Marathon acquisition, and (ii) amend the Permitted Distribution provision to include funds contributed by the Company to TUSA in connection with closing the Marathon acquisition.

On June 6, 2014, TUSA entered into Amendment No. 6 to the A&R Credit Agreement (“Amendment No. 6”) with Wells Fargo, as administrative agent and issuing lender, and the other lenders named therein, as lenders. Amendment No. 6 amended the A&R Credit Agreement, as amended by Amendment No. 4 and Amendment No. 5, to expressly permit the prepayment of the second lien credit facility using proceeds from the issuance of Permitted Notes (as defined in the A&R Credit Agreement), including the 6.75% Senior Notes. As of July 31, 2014, TUSA, as borrower, had no borrowings outstanding under the A&R Credit Agreement, as amended through Amendment No. 6 (the “TUSA Credit Facility”).

The borrowing base under the TUSA Credit Facility is subject to redetermination by the beginning of November 2014 and thereafter on a semi-annual basis by the beginning of each May and November. In addition, TUSA has the option to request two additional redeterminations during any calendar year. Upon issuance of the 6.75% Senior Notes, the borrowing base was automatically reduced to $305.5 million. On August 21, 2014, in accordance with the redetermination provided for in Amendment No. 4, the borrowing base was increased to $415.0 million.

Borrowings under the TUSA Credit Facility 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 rate (as defined in the Credit Agreement) 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. TUSA may prepay borrowings under the TUSA Credit Facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. All borrowings under the TUSA Credit Facility mature on October 16, 2018.

TUSA will pay a per annum fee on all letters of credit issued under the TUSA 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 equal to 0.125% of the letter of credit amount. TUSA will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the TUSA Credit Facility, depending on TUSA’s utilization percentage of the then effective borrowing base.

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

The TUSA Credit Facility contains financial covenants requiring TUSA to comply with the following: (i) TUSA must 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) the ratio of TUSA’s 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) may not be greater than 4.0 to 1.0. As of July 31, 2014, TUSA was in compliance with all covenants under the TUSA Credit Facility.

Second Lien Credit Facility

On June 27, 2014, TUSA entered into a Second Lien Credit Agreement (the “Second Lien Credit Facility”) with Wells Fargo, as administrative agent, and the lenders named therein. This credit agreement 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 (six 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 6.75% Senior Notes on July 18, 2014, TUSA terminated the Second Lien Credit Facility and repaid all amounts owing thereunder.

RockPile Credit Facility

Borrowings under the FY2015 RockPile Credit Agreement 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 FY2015 RockPile Credit Agreement) 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 recent 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 recent fiscal quarter. RockPile may prepay borrowings under the FY2015 RockPile Credit Agreement at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. All borrowings under the FY2015 RockPile Credit Agreement 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 FY2015 RockPile Credit Agreement. RockPile will also pay a per annum fee on all letters of credit issued under the FY2015 RockPile Credit Agreement, which will equal the applicable margin for loans accruing interest based on the Eurodollar rate and a fronting fee to the issuing lender equal to 0.125% of the letter of credit amount. In connection with entering into the FY2015 RockPile Credit Agreement, RockPile paid certain upfront fees to the lenders thereunder, and RockPile paid certain arrangement and other fees to Citi and Wells Fargo. Triangle is not a guarantor under the FY2015 RockPile Credit Agreement. Upon entering into the FY2015 RockPile Credit Agreement, funds were drawn to pay off all outstanding borrowings under RockPile’s then outstanding credit agreement with Wells Fargo, and for working capital. As of July 31, 2014, the weighted-average interest rate on the loan was 3.22% and $39.6 million was outstanding on the loan.

The FY2015 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 FY2015 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 FY2015 RockPile Credit Facility) of at least 1.25 to 1.00 quarterly. As of July 31, 2014, RockPile was in compliance with all financial covenants under the FY2015 RockPile Credit Facility.

RockPile Mortgages Payable to Dacotah Bank

Bakken Real Estate Development, LLC, a wholly-owned subsidiary, has two mortgage loan agreements with Dacotah Bank in the amounts of $2.5 million for its residential units and $4.4 million for its administrative and maintenance facility,

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all located in Dickinson, North Dakota. The mortgage loans have a term of 15 years, bear interest at a variable rate equal to the Federal Home Loan Bank of Des Moines Five-Year Fixed-Rate Advance Rate plus 2.80%, and have a maturity date of December 15, 2028.

RockPile Notes Payable to Sellers of Team Well Service, Inc.

On October 16, 2013, RockPile issued two identical unsecured subordinated promissory notes to the sellers of Team Well Service, Inc. (“Team Well”) in connection with its acquisition of Team Well. The notes each have a face value of $0.5 million and bear interest at a fixed rate of 1.0%. The loans have a maturity date of October 16, 2016, at which time the principal and accrued interest is due and payable. The aggregate carrying value of the loans at July 31, 2014 was $0.9 million. Over the term of the loans, the discount will be accreted on a monthly basis by increasing the carrying value of both notes and recording interest expense.

RockPile Hauck Apartments Mortgage

On November 20, 2013, RockPile closed on the purchase of a 12 unit apartment building in Dickinson, ND for a total purchase price of $1.8 million. The purchase was funded by cash on hand and a mortgage from Dacotah Bank in the amount of $1.5 million. The mortgage has a term of 15 years and bears interest at a variable rate equal to the Federal Home Loan Bank of Des Moines Five-Year Fixed-Rate Advance Rate plus 2.70%. At July 31, 2014, the interest on the mortgage was 4.75% and the outstanding balance on the mortgage was $1.4 million.

RockPile Promissory Notes

RockPile redeemed 180,000 B-1 Units from three parties during the six months ended July 31, 2014, in exchange for promissory notes totaling approximately $1.0 million. The notes mature in the second quarter of the Company’s 2018 fiscal year. The notes accrue interest at a rate of LIBOR plus 3.0% per annum, payable at maturity.

8. DERIVATIVE INSTRUMENTS

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

		As of July 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	Long-term assets	$	605		$	(469	)	$	136
Crude oil derivative contracts	Current liabilities	$	(1,972	)	$	978		$	(994	)
Equity investment derivatives	Equity investment	$	2,870		$	—		$	2,870

		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

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In regards to our commodity derivatives, the Company recorded a loss of $0.9 million and $6.4 million, respectively for the three and six months ended July 31, 2014. The Company recorded a loss on commodity derivative activities of $4.4 million and $3.2 million, respectively, for the three and six months ended July 31, 2013. In regards to our equity investment derivatives, we recorded a loss of $7.5 million and a gain of $2.9 million, respectively, for the three and six months ended July 31, 2014. The Company had no equity investment derivative activity during the six months ended July 31, 2013.

Commodity Derivative Instruments

Through TUSA, the Company has entered into commodity derivative instruments, as described below. The Company has utilized 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 four 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 and comprehensive income. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s condensed consolidated statements of cash flows.

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

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

Term End Date	Contract Type	Basis (1)	Quantity (Bbl/d)	Weighted Average Put Strike		Weighted Average Call Strike		Weighted Average Price
Fiscal Year 2015	Collar	NYMEX	5,767	$	87.33	$	100.71
Fiscal Year 2015	Swap	NYMEX	166					$	94.50
Fiscal Year 2016	Collar	NYMEX	4,356	$	86.85	$	98.06

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

Equity Investment Derivatives

At July 31, 2014, the Company held Class A Trigger Unit Warrants and Class A Warrants (Series 1 through Series 4) to acquire additional ownership in Caliber. These instruments are valued using the following valuation techniques that are generally less observable from objective sources. As such, the Company has classified these instruments as Level 3.

The fair value of the Class A Trigger Unit Warrant and the Class A (Series 1 through Series 4) Warrants as of July 31, 2014, were estimated using a Monte Carlo Simulation (“MCS”) model. A 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 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 $10.20 at July 31, 2014, a decrease of $1.08 per unit from April 30, 2014, but an increase of $0.20 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 months ended July 31, 2014, resulted in a $2.3 million decrease, and the change in fair value during the six months ended July 31, 2014 resulted in a $1.2 million increase, in our equity investment account in the accompanying unaudited condensed consolidated balance sheet as of July 31, 2014, and as the gain (loss) on equity investment derivatives reflected in the accompanying unaudited condensed consolidated statement of operations and comprehensive income.

Also included in the gain (loss) on equity investment derivatives during the three and six months ended July 31, 2014, was a loss of $5.2 million and a gain of $1.7 million, respectively, 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 July 31, 2014 and January 31, 2014 by level within the fair value hierarchy:

	As of July 31, 2014
(in thousands)	Level 1		Level 2			Level 3		Total
Assets:
Equity investment derivative assets	$	—	$	—		$	2,870	$	2,870
Commodity derivative assets	$	—	$	136		$	—	$	136

Liabilities:
Commodity derivative liabilities	$	—	$	(994	)	$	—	$	(994	)
RockPile earn-out liability	$	—	$	(1,791	)	$	—	$	(1,791	)

	As of January 31, 2014
(in thousands)	Level 1		Level 2			Level 3		Total
Assets:
Equity investment 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 such counterparties have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At July 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 Trigger Unit Warrant and Class A (Series 1 through Series 4) Warrants

At July 31, 2014, the Caliber Class A Trigger Unit Warrant and 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. See Note 8 - Derivative Instruments for further discussion.

RockPile Earn-out Liability

The Company determined the estimated fair value of the earn-out liability relating to RockPile’s acquisition of Team Well 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.

6.75% Senior Notes

The fair value of the 6.75% Senior Notes approximated their fair value due to their recent issuance.

5% Convertible Note

The 5% Convertible Note had an estimated fair value at July 31, 2014 of $245.3 million, based on discounted cash flow analysis and option pricing (Level 3). The increase in fair value from $169.2 million at January 31, 2014 is largely due to a greater option value for Triangle’s common stock based on an increase in the closing price of the stock to $10.80 per share at July 31, 2014 compared with $7.61 per share at January 31, 2014.

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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)	5% Convertible Note			Class A Trigger Units			Warrants (1)
Beginning balance, January 31, 2014	$	(169,170	)	38,091			$	1,696
Interest paid in-kind	(3,252		)	—			—
Net unrecognized loss	(72,876		)	—			—
Net unrealized gain	—			1,746			1,174
Conversion to Class A units	—			(39,837		)	—
Ending balance, July 31, 2014	$	(245,298	)	$	—		$	2,870

(1) Includes Caliber Class A Trigger Unit Warrant and Class A (Series 1 through Series 4) Warrants

10. COMMITMENTS AND CONTINGENCIES

As of July 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.

As of July 31, 2014, the Company was subject to commitments on four drilling rig contracts. The contracts expire between July 2014 and July 2015. In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $14.0 million as of July 31, 2014 as required under the terms of the contracts.

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 initial 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 July 31, 2014, and, therefore, no amounts have been recorded in the accompanying condensed consolidated balance sheets.

11. CAPITAL STOCK

Common Stock

During the six months ended July 31, 2014, the Company issued 495,892 shares of its common stock (net of shares surrendered for related employee payroll tax withholding) for restricted stock units that vested during the period.

Share-Based Compensation

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

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

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The 2011 Plan authorizes the Company to issue stock options, stock appreciation rights (“SARs”), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards to any employee, consultant, independent contractor, director or officer of the Company or its subsidiaries. The maximum number of shares of common stock reserved for issuance under the 2011 Plan is 5,900,000 shares, subject to adjustment for certain transactions.

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.

On July 4, 2013, the Company entered into a CEO Stand-Alone Stock Option Agreement with the Company’s President and Chief Executive Officer (the “CEO Option Grant”). The CEO Option Grant is a stand-alone stock option agreement unrelated to the 2011 Plan. As such, the CEO Option Grant required separate stockholder approval before any shares of the Company’s common stock could be issued thereunder. At the Company’s Annual Meeting of Stockholders held on August 30, 2013, the CEO Option Grant was approved.

On May 27, 2014, the Company’s Board of Directors approved the 2014 Equity Incentive Plan (the “2014 Plan”). Upon approval of the 2014 Plan by the Company’s stockholders on July 17, 2014, the 2011 Plan was terminated and no additional awards may be granted under the 2011 Plan. All outstanding awards under the 2011 Plan 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 6,000,000 shares, subject to adjustment for certain transactions.

For the three and six months ended July 31, 2014 and 2013, the Company recorded stock based compensation related to restricted stock units, the CEO Option Grant and RockPile Series B Units as follows:

	Three Months Ended July 31,
(in thousands)	2014			2013
Restricted stock units	$	1,503		$	1,695
Stock options	487			—
RockPile stock based compensation related to Series B Units	127			99
	2,117			1,794
Less amounts capitalized to oil and natural gas properties	(310		)	(356		)
Compensation expense	$	1,807		$	1,438

	Six Months Ended July 31,
(in thousands)	2014			2013
Restricted stock units	$	3,274		$	3,360
Stock options	973			—
RockPile stock based compensation related to Series B Units	217			310
	4,464			3,670
Less amounts capitalized to oil and natural gas properties	(649		)	(637		)
Compensation expense	$	3,815		$	3,033

Restricted Stock Units

During the six months ended July 31, 2014, the Company granted 859,600 restricted stock units as compensation to employees, officers and directors. The restricted stock units vest over one to five years. As of July 31, 2014, there was approximately $16.8 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 2.9 years. When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit.

The following table summarizes the status of restricted stock units outstanding:

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	Number of Shares		Weighted- Average Award Date Fair Value
Restricted stock units outstanding - January 31, 2014	2,875,624		$	6.75
Units granted	859,600		$	8.73
Units forfeited	(302,085	)	$	7.13
Units that vested	(739,710	)	$	7.20
Restricted stock units outstanding - July 31, 2014	2,693,429		$	7.09

Stock Options

The Company did not issue stock options during the six months ended July 31, 2014.

As of July 31, 2014, there was approximately $17.3 million of total unrecognized compensation expense related to stock options (including those issued under the CEO Option Grant and the Rolling Plan). This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 3.9 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	—	$	—
Options outstanding - July 31, 2014 (708,333 exercisable)	6,108,333	$	11.07

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

		Remaining
Exercise Price		Contractual Life	Number of shares
per Share		(years)	Outstanding		Exercisable
$	1.25	0.59	108,333		108,333
$	7.50	9.18	750,000		75,000
$	8.50	9.18	750,000		75,000
$	10.00	9.18	1,500,000		150,000
$	12.00	9.18	1,500,000		150,000
$	15.00	9.18	1,500,000		150,000
			6,108,333		708,333

Weighted average exercise price per share			$	11.07	$	9.72

Weighted average remaining contractual life			8.78		7.62

RockPile Share-Based Compensation

RockPile issued 1,412,000 Series B units to 32 parties during the six months ended July 31, 2014.

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RockPile redeemed 180,000 B-1 Units from three parties during the six months ended July 31, 2014 in exchange for promissory notes totaling approximately $1.0 million. The notes mature in the second quarter of fiscal year 2018.

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 - July 31, 2014	2,920,000		60,000	910,000	1,412,000	5,302,000
Vested	2,386,667		15,000	188,000	—	2,589,667
Unvested	533,333		45,000	722,000	1,412,000	2,712,333

As of July 31, 2014, there was approximately $2.9 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 three 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 for 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 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 six months ended July 31, 2014 and 2013:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands, except per share data)	2014		2013		2014		2013
Net income attributable to common stockholders	$	14,552	$	6,799	$	29,094	$	12,010
Effect of 5% Convertible Note conversion	996		—		1,983		—
Net income attributable to common stockholders after effect of debt conversion	15,548		6,799		31,077		12,010

Basic weighted average common shares outstanding	86,172		56,451		86,064		54,561
Effect of dilutive securities	17,602		561		17,447		528
Diluted weighted average common shares outstanding	103,774		57,012		103,511		55,089

Basic net income per share	$	0.17	$	0.12	$	0.34	$	0.22
Diluted net income per share	$	0.15	$	0.12	$	0.30	$	0.22

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Of the stock options, restricted stock units and convertible debt outstanding at July 31, 2014, only 4.5 million of outstanding options in the CEO Option Grant were anti-dilutive for the three and six month periods ended July 31, 2014, and the shares of common stock issuable upon exercise of those options were excluded from the calculation of the diluted net income per share for those three and six month periods. These awards could be potentially dilutive in future periods.

13. INCOME TAXES

The effective tax rate for the six months ended July 31, 2014 was 41.2%, which differs from the statutory income tax rate due primarily to permanent book to tax differences and state income taxes. Neither a tax expense nor a tax benefit was recognized for the three or six months ended July 31, 2013, as the Company had provided a 100% valuation allowance against its net deferred tax assets which exceeded its deferred tax liabilities at that time.

As of July 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 half 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 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 $387.6 million remained at July 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”, owned 51% by Caliber Fresh Water LLC (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, 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 all necessary regulatory approvals. As of July 31, 2014, the necessary regulatory approvals had not yet been received, however the Company expects to receive all such approvals and finalize the transaction during its fiscal 2015 third quarter.

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For the three and six months ended July 31, 2014, Caliber North Dakota had $9.6 million and $13.7 million of revenue, respectively, of which, $8.4 million and $12.2 million, respectively, were from TUSA, and mainly comprised of fresh water and salt water disposal revenues. See Note 6 — Equity Investment.

For the three and six month period ended July 31, 2014, Triangle received $0.3 million and $0.6 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.

15. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

	For the Six Months Ended
	July 31,
(in thousands)	2014		2013
Cash paid during the period for:
Interest expense	$	4,717	$	1,042
Income taxes	$	550	$	—

Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increased (decreased) accrued liabilities and prepaid well costs	$	37,151	$	6,700
Capitalized stock based compensation	$	649	$	637
Change in asset retirement obligations	$	1,106	$	92
Capitalized interest	$	1,808	$	1,100

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 July 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 July 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 $88.97 per barrel of oil, $44.82 per barrel of natural gas liquids and $5.72 per Mcf of natural gas for the reserves presented as of July 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

July 31, 2014

January 31,

Reserves

Oil

Gas

NGL

2014

Reserve Category

(Mboe)

(Mbbls)

(MMcf)

(Mbbls)

Mboe

Proved Developed

24,213

20,000

2,484

30,030

16,995

Proved Undeveloped

16,849

14,371

2,386

21,630

23,319

Total Proved

100

41,062

34,371

4,870

51,660

40,314

The primary reason for the increase in proved reserves is the drilling and completion of wells in the first six months of fiscal year 2015 and the Marathon acquisition and the June 6, 2014 Acquisition that both closed during the three months ended July 31, 2014.

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Our net interest in proved developed wells increased 96% from 50.0 net wells at January 31, 2014 to 98.0 net wells at July 31, 2014, and our net interest in proved undeveloped locations decreased 8% from 52.5 net future development wells at January 31, 2014 to 48.4 net future development wells at July 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, filed with the SEC on April 17, 2014 (the “Fiscal 2014 Form 10-K”) 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 July 31, 2014, we have completed 71 gross (50.0 net) operated wells. Our average net daily production for the quarter ended July 31, 2014 was 10,551 barrels of oil equivalent per day (“Boepd”), approximately 87% of which was operated production. The growth we have experienced is facilitated by the use of pad drilling, which increases efficiencies while controlling costs and minimizing environmental impact. We

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also use advanced completion, collection and production techniques designed to optimize reservoir production while reducing costs. Our estimated proved oil and natural gas reserves as of July 31, 2014 totaled 51,660 Mboe (80% oil).

In an effort to better control key operations, reduce costs, and retain supply chain value in the Williston Basin, which we view as a resource-constrained and cost-heavy basin, we formed RockPile 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 of 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 July 31, 2014:

· Production volumes totaled 970,710 Boe for the three months ended July 31, 2014, compared to 394,405 Boe for the three months ended July 31, 2013, an increase of 146%.

· Oil, natural gas and natural gas liquid sales in the three months ended July 31, 2014, were $80.5 million compared to $34.6 million for the three months ended July 31, 2013.

· Oilfield services revenue in the three months ended July 31, 2014, totaled $61.5 million compared to $15.8 million for the three months ended July 31, 2013, and total gross profit contribution from our oilfield service operations was $14.8 million for the three months ended July 31, 2014, as compared to $2.4 million for the comparable period in 2013.

· Net income was $14.6 million for the three months ended July 31, 2014, compared to $6.8 million for the three months ended July 31, 2013.

· We spud 14 gross (9.2 net) operated wells and completed 15 gross (9.9 net) operated wells during the three months ended July 31, 2014.

Summary of operating and financial results for the six months ended July 31, 2014:

· Production volumes totaled 1,694,228 Boe for the six months ended July 31, 2014 compared to 635,929 Boe for the six months ended July 31, 2013, an increase of 166%.

· Oil, natural gas and natural gas liquid sales in the six months ended July 31, 2014, were $141.3 million compared to $55.7 million for the six months ended July 31, 2013.

· Oilfield services revenue in the six months ended July 31, 2014, was $100.4 million compared to $29.0 million for the six months ended July 31, 2013, and total gross profit contribution from our oilfield service operations was $23.7 million for the six months ended July 31, 2014, as compared to $3.7 million for the comparable period in 2013.

· Net income was $29.1 million for the six months ended July 31, 2014 compared to $12.0 million for the six months ended July 31, 2013.

· Cash flow provided by operating activities was $61.8 million for the six month period ended July 31, 2014 compared to $31.4 million for the six months ended July 31, 2013.

· We spud 27 gross (18.5 net) operated wells and completed 24 gross (16.0 net) operated wells during the six months ended July 31, 2014.

Recent Events

Oil & Gas Property Acquisitions

On June 30, 2014, we acquired 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 (the “Marathon Acquisition”).

On June 6, 2014, we acquired 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”).

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TUSA Credit Facility Amendments

On May 9, 2014, TUSA entered into Amendment No. 4 to Amended and Restated Credit Agreement and Joinder Agreement (‘‘Amendment No. 4’’) with Wells Fargo Bank, National Association (‘‘Wells Fargo’’) as administrative agent and issuing lender, and the other lenders named therein, as lenders. Amendment No. 4 amended that certain Amended and Restated Credit Agreement, dated April 11, 2013, as previously amended (the ‘‘A&R Credit Agreement’’), to (i) increase the borrowing base from $320.0 million to $355.0 million, (ii) add three new lenders to the facility, (iii) add a borrowing base redetermination in August 2014, (iv) cause the borrowing base to increase by up to an additional $10.0 million upon closing the June 6, 2014 Acquisition, (v) permit a one-time distribution to the Company of any funds contributed by the Company to TUSA in connection with closing the June 6, 2014 Acquisition (the “Permitted Distribution”), and (vi) permit TUSA to enter into a second lien credit facility of up to $100.0 million.

On May 14, 2014, TUSA entered into Amendment No. 5 to the A&R Credit Agreement (“Amendment No. 5”) with Wells Fargo, as administrative agent and issuing lender, and the other lenders named therein, as lenders. Amendment No. 5 amended the A&R Credit Agreement, as amended by Amendment No. 4, to (i) cause the borrowing base to increase by up to an additional $40.0 million upon closing the Marathon Acquisition, and (ii) amend the Permitted Distribution provision to include funds contributed by the Company to TUSA in connection with closing the Marathon Acquisition.

On June 6, 2014, TUSA entered into Amendment No. 6 to the A&R Credit Agreement (“Amendment No. 6”) with Wells Fargo, as administrative agent and issuing lender, and the other lenders named therein, as lenders. Amendment No. 6 amended the A&R Credit Agreement, as amended by Amendment No. 4 and Amendment No. 5, to expressly permit the prepayment of the Second Lien Credit Facility (as defined below) using proceeds from the issuance of Permitted Notes (as defined in the A&R Credit Agreement), including the 6.75% Senior Notes (as defined below).

Upon issuance of the 6.75% Senior Notes, the borrowing base was automatically reduced to $305.5 million. On August 21, 2014, in accordance with the redetermination provided for in Amendment No. 4, the borrowing base was increased to $415.0 million.

TUSA Second Lien Credit Facility

On June 27, 2014, TUSA entered into a Second Lien Credit Agreement (the “Second Lien Credit Facility”) with Wells Fargo Energy Capital, Inc., as administrative agent and certain other lenders. The agreement provided for a $60.0 million second priority secured credit facility, which was funded at signing. Upon issuance of the 6.75% Senior Notes (defined below), TUSA terminated the Second Lien Credit Facility and repaid all amounts owing thereunder.

6.75% Senior Notes

On July 18, 2014, TUSA entered into an indenture (the “Indenture”) among TUSA, a TUSA wholly-owned subsidiary as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the terms of TUSA’s $450,000,000 aggregate principal amount of 6.75% Senior Notes due 2022 (the “6.75% Senior Notes”). The 6.75% Senior Notes bear interest at a rate of 6.75% per year, accruing from July 18, 2014. Interest on the 6.75% Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2015. The 6.75% Senior Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture.

Reserve Update

As of July 31, 2014, we have estimated proved reserves of 41.1 million barrels of oil, 4.9 million barrels of natural gas liquids and 34.4 billion cubic feet of natural gas, or 51.7 million barrels of oil equivalent (MMboe). Our reserve quantities are comprised of 80% crude oil, 11% natural gas and 9% natural gas liquids. The July 31, 2014 proved reserves reflect a 28% increase over the January 31, 2014 proved reserves of 40,314 MMboe. Our proved reserves at July 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 July 31, 2014:

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

Proved Developed	58	%	24,213	20,000	2,484	30,030	16,995	77	%
Proved Undeveloped	42	%	16,849	14,371	2,386	21,630	23,319	(7	)%
Total Proved	100	%	41,062	34,371	4,870	51,660	40,314	28	%

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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 July 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 $88.97 per barrel of oil, $44.82 per barrel of natural gas liquids and $5.72 per Mcf of natural gas for the reserves presented as of July 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.

Drilling and Completions

The following tables summarize the wells spud and completed during the three and six months ended July 31, 2014:

	For the Three Months Ended July 31, 2014
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	14	9.2	15	9.9
Non-operated wells	32	1.0	21	1.0
	46	10.2	36	10.9

	For the Six Months Ended July 31, 2014
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	27	18.5	24	16.0
Non-operated wells	66	2.0	33	1.6
	93	20.5	57	17.6

Properties, Plan of Operations and Capital Expenditures

We own operated and non-operated leasehold positions in the Williston Basin. As of July 31, 2014, we have completed a total of 71 gross (50.0 net) operated wells in the Williston Basin. During fiscal year 2015, we anticipate drilling approximately 48 gross (35.0 net) operated wells and completing approximately 44 gross (32.7 net) operated wells in North Dakota or eastern Montana for completion in the Bakken Shale or Three Forks formations. Of the 44 gross wells expected to be completed in fiscal year 2015, we had completed 24 gross wells and had an additional 10 gross wells in progress as of July 31, 2014. Thirty-nine of the gross wells are planned to be in the Bakken Shale and five of the gross wells are planned for the Three Forks formation. We also have economic interests in approximately 431 gross (23.9 net) non-operated wells.

We are currently running a four-rig drilling program, which we anticipate continuing for the remainder of fiscal year 2015. 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.”

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

(in thousands)
Costs incurred during the period
Acquisition of properties:
Proved	$	91,067
Unproved	40,301
Exploration	52,338
Development	133,186
Oil and natural gas expenditures	316,892
Asset retirement obligations, net	1,106
	$	317,998

U.S. Leaseholds

As of July 31, 2014, we have leased approximately 283,358 gross and 131,388 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	168,795	66,434	31,266	8,631	200,061	75,065
Montana	17,868	13,449	65,429	42,874	83,297	56,323
Total Williston Basin	186,663	79,883	96,695	51,505	283,358	131,388

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.

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

For the fiscal quarter ended July 31, 2014, we recorded net income attributable to common stockholders of $14.6 million ($0.17 per share of common stock - basic and $0.15 per share of common stock - diluted) as compared to net income attributable to common stockholders of $6.8 million ($0.12 per share of common stock, basic and diluted) for the quarter ended July 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 July 31, 2014 and 2013:

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	For the Three Months Ended				Change
	July 31,				Increase			% Increase
	2014		2013		(Decrease)			(Decrease)
U.S. Oil and Natural Gas Operations
Production volumes:
Crude oil (Bbls)	837,028		378,107		458,921			121	%
Natural gas (Mcf)	494,015		82,425		411,590			499	%
Natural gas liquids (Bbls)	51,346		2,560		48,786			1,906	%
Total barrels of oil equivalent (Boe)	970,710		394,405		576,305			146	%

Average realized prices (1):
Crude oil ($ per Bbl)	$	90.78	$	90.37	$	0.41		0	%
Natural gas ($ per Mcf)	$	5.49	$	4.60	$	0.89		19	%
Natural gas liquids ($ per Bbl)	$	35.29	$	34.77	$	0.52		1	%
Total average realized price ($ per Boe)	$	82.94	$	87.83	$	(4.89	)	(6	)%

Oil, natural gas and natural gas liquids revenues (in thousands):
Crude oil	$	75,983	$	34,171	$	41,812		122	%
Natural gas	2,711		379		2,332			615	%
Natural gas liquids	1,812		89		1,723			1,936	%
Total oil and natural gas revenues	$	80,506	$	34,639	$	45,867		132	%

Operating expenses (in thousands):
Production taxes	$	8,677	$	3,919	$	4,758		121	%
Lease operating expenses	6,698		2,830		3,868			137	%
Gathering, transportation and processing	3,733		69		3,664			5,310	%
Oil and natural gas amortization expense	23,429		10,100		13,329			132	%
Accretion of asset retirement obligations	41		9		32			356	%
Total operating expenses	$	42,578	$	16,927	$	25,651		152	%

Operating expenses per Boe:
Production taxes	$	8.94	$	9.94	$	(1.00	)	(10	)%
Lease operating expense	$	6.90	$	7.18	$	(0.28	)	(4	)%
Gathering, transportation and processing	$	3.85	$	0.17	$	3.68		2165	%
Oil and natural gas amortization expense	$	24.14	$	25.61	$	(1.47	)	(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 three months ended July 31, 2014 increased 132% to $80.5 million from $34.6 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. Average realized oil prices in the second quarter of fiscal year 2015 increased slightly to $90.78 per barrel from $90.37 per barrel in the same period in fiscal year 2014. In addition, during the three months ended July 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, and average prices received. We also benefited from very strong regional natural gas and natural gas liquid prices during the three months ended July 31, 2014.

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Production Taxes

Due primarily to the 132% increase in oil, natural gas and natural gas liquids revenues for the three months ended July 31, 2014 as compared with the three months ended July 31, 2013, our production taxes increased approximately 121% to $8.7 million from $3.9 million for the same period of fiscal year 2014.

Lease Operating Expense

Lease operating expense decreased to $6.90 per Boe for the three months ended July 31, 2014 from $7.18 per Boe for the three months ended July 31, 2013. The cost decrease is primarily the result of workover costs decreasing by $0.06 per Boe and lower labor and power costs associated with operated properties.

Gathering, Transportation and Processing

Gathering, transportation and processing (“GTP”) expenses increased to $3.85 per Boe for the three months ended July 31, 2014 from $0.17 per Boe for the three months ended July 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 132% to $23.4 million for the three months ended July 31, 2014 from $10.1 million for the three months ended July 31, 2013. The increase is primarily related to increased production in the second quarter of fiscal year 2015 as compared to the second quarter of fiscal year 2014. Our oil and natural gas amortization expense decreased by $1.47 per Boe from $25.61 for the three months ended July 31, 2013, to $24.14 for the three months ended July 31, 2014. This decrease was primarily due to successful development operations, field extensions and acquisition of additional oil and gas properties.

Oilfield Services Gross Profit

During the three months ended July 31, 2014, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and five third-party customers. Equipment utilized to perform these services consisted of three frac spreads; two wireline trucks; and four workover rigs. Hydraulic fracturing services resulted in 34 total well completions: 15 for TUSA and 19 for three 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 $14.8 million and $2.4 million, respectively, of gross profit from oilfield services for the three months ended July 31, 2014 and 2013 after elimination of $13.7 million and $9.9 million, respectively, of intercompany gross profit. See Note 4 — Segment Reporting under Item 1 of this Quarterly Report.

The table below is a summary of the RockPile contribution to our consolidated results for the three months ended July 31, 2014 and 2013, after eliminations:

	For the Three Months Ended July 31, 2014
(in thousands)	RockPile		Eliminations			Consolidated
Revenues
Oilfield services	$	102,055	$	(40,572	)	$	61,483
Total revenues	102,055		(40,572		)	61,483
Cost of sales
Oilfield services	68,867		(25,313		)	43,554
Depreciation	4,690		(1,609		)	3,081
Total cost of sales	73,557		(26,922		)	46,635
Gross profit	$	28,498	$	(13,650	)	$	14,848

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	For the Three Months Ended July 31, 2013
(in thousands)	RockPile		Eliminations			Consolidated
Revenues
Oilfield services	$	44,285	$	(28,530	)	$	15,755
Total revenues	44,285		(28,530		)	15,755
Cost of sales
Oilfield services	30,370		(17,678		)	12,692
Depreciation	1,600		(928		)	672
Total cost of sales	31,970		(18,606		)	13,364
Gross profit	$	12,315	$	(9,924	)	$	2,391

General and Administrative Expenses

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

(in thousands)	Exploration and Production		Oilfield Services		Corporate		Consolidated Total
For the three months ended July 31, 2014
Salaries, benefits and other general and administrative	$	4,442	$	5,251	$	2,591	$	12,284
Stock-based compensation	344		127		1,336		1,807
Total	$	4,786	$	5,378	$	3,927	$	14,091

For the three months ended July 31, 2013
Salaries, benefits and other general and administrative	$	1,683	$	2,446	$	1,417	$	5,546
Stock-based compensation	247		99		1,092		1,438
Total	$	1,930	$	2,545	$	2,509	$	6,984

Total general and administrative expense increased $7.1 million to $14.1 million for the three months ended July 31, 2014 compared to $7.0 million for the three months ended July 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 three months ended July 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 three months ended July 31, 2013.

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 July 31, 2014, we recognized a $0.9 million loss on our commodity derivative positions due to increases in underlying crude oil prices. Included in the net loss on our derivative activities for the quarter were cash settlements we incurred on our commodity derivative instruments of approximately $2.6 million. 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 decrease in the fair value of the equity investment derivatives in the second quarter of fiscal year 2015, the Company recognized a loss in equity

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investment derivatives of $7.5 million. For additional discussion, please refer to Note 8 — Derivative Instruments under Item 1 of this Quarterly Report.

Income (Loss) from Equity Investment

During the three months ended July 31, 2014, the Company recognized $0.8 million for its share of Caliber’s income for the period. This income, however, was offset by $0.6 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.

Interest Expense

The $5.4 million in interest expense for the three months ended July 31, 2014 consists of (a) approximately $2.0 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 5.0% Convertible Note, (c) approximately $1.3 million in interest and amortized fees related to the 6.75% Senior Notes (d) approximately $0.7 million in interest expense associated with our RockPile Credit Facility and notes payable, and (e) approximately $0.8 million in interest expense associated with the Second Lien Credit Facility, all net of approximately $1.0 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $3.1 million of interest expense and capitalized interest was paid in cash. See Note 7 — Long-Term Debt under Item 1 of this Quarterly Report for additional information regarding our debt outstanding.

Income Taxes

The effective tax rate for the three months ended July 31, 2014 was 41.5%, which differs from the statutory income tax rate due primarily to permanent book to tax differences and state income taxes. Neither a tax expense nor a tax benefit was recognized for the three months ended July 31, 2013, as the Company had provided a 100% valuation allowance against its net tax assets which exceeded its deferred tax liabilities at that time.

Results of Operations for the Six Months Ended July 31, 2014 Compared to the Six Months Ended July 31, 2013

For the six months ended July 31, 2014, we recorded net income attributable to common stockholders of $29.1 million ($0.34 per share of common stock - basic and $0.30 per share of common stock - diluted) as compared to net income attributable to common stockholders of $12.0 million ($0.22 per share of common stock, basic and diluted) for the six months ended July 31, 2013. The following table summarizes production volumes, average realized prices, oil, natural gas and natural gas liquids revenues and operating expenses for the six months ended July 31, 2014 and 2013:

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	For the Six Months Ended				Change
	July 31,				Increase			% Increase
	2014		2013		(Decrease)			(Decrease)
U.S. Oil and Natural Gas Operations
Production volumes:
Crude oil (Bbls)	1,435,298		610,360		824,938			135	%
Natural gas (Mcf)	934,944		129,876		805,068			620	%
Natural gas liquids (Bbls)	103,106		3,923		99,183			2,528	%
Total barrels of oil equivalent (Boe)	1,694,228		635,929		1,058,299			166	%

Average realized prices (1):
Crude oil ($ per Bbl)	$	90.82	$	90.11	$	0.71		1	%
Natural gas ($ per Mcf)	$	6.77	$	4.31	$	2.46		57	%
Natural gas liquids ($ per Bbl)	$	45.12	$	34.92	$	10.20		29	%
Total average realized price ($ per Boe)	$	83.42	$	87.59	$	(4.17	)	(5	)%

Oil, natural gas and natural gas liquids revenues (in thousands):
Crude oil	$	130,355	$	55,002	$	75,353		137	%
Natural gas	6,333		560		5,773			1031	%
Natural gas liquids	4,652		137		4,515			3296	%
Total oil and natural gas revenues	$	141,340	$	55,699	$	85,641		154	%

Operating expenses (in thousands):
Production taxes	$	15,025	$	6,363	$	8,662		136	%
Other lease operating expenses	11,424		5,046		6,378			126	%
Gathering, transportation and processing	7,535		106		7,429			7,008	%
Oil and natural gas amortization expense	42,029		16,707		25,322			152	%
Accretion of other asset retirement obligations	175		17		158			929	%
Total operating expenses	$	76,188	$	28,239	$	47,949		170	%

Operating expenses per Boe:
Production taxes	$	8.87	$	10.01	$	(1.14	)	(11	)%
Other lease operating expense	$	6.74	$	7.93	$	(1.19	)	(15	)%
Gathering, transportation and processing	$	4.45	$	0.17	$	4.28		2518	%
Oil and natural gas amortization expense	$	24.81	$	26.27	$	(1.46	)	(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 six months ended July 31, 2014 increased 154% to $141.3 million from $55.7 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. Average realized oil prices in the first half of fiscal year 2015 increased to $90.82 per barrel from $90.11 per barrel in the same period in fiscal year 2014. In addition, during the six months ended July 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, and average prices received. We also benefited from very strong regional natural gas and natural gas liquid prices during the six months ended July 31, 2014.

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Production Taxes

Due primarily to the 154% increase in oil, natural gas and natural gas liquids revenues for the six months ended July 31, 2014 as compared with the six months ended July 31, 2013, our production taxes increased approximately 136% to $15.0 million from $6.4 million for the same period of fiscal year 2014.

Lease Operating Expense

Lease operating expense decreased to $6.74 per Boe for the six months ended July 31, 2014 from $7.93 per Boe for the six months ended July 31, 2013. The cost decrease is primarily the result of workover costs decreasing by $0.55 per Boe and lower labor and power costs associated with operated properties.

Gathering, Transportation and Processing

GTP expenses increased to $4.45 per Boe for the six months ended July 31, 2014 from $0.17 per Boe for the six months ended July 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 152% to $42.0 million for the six months ended July 31, 2014 from $16.7 million for the six months ended July 31, 2013. The increase is primarily related to increased production. Our oil and natural gas amortization expense decreased by $1.46 per Boe from $26.27 for the six months ended July 31, 2013, to $24.81 for the six months ended July 31, 2014. This decrease was primarily due to successful development operations, field extensions and acquisition of additional oil and gas properties.

Oilfield Services Gross Profit

During the six months ended July 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 two frac spreads in February and March with a third frac spread deployed in mid-April; two wireline trucks; and four workover rigs. Hydraulic fracturing services resulted in 60 total well completions: 24 for TUSA and 36 for three third-parties.

We recognized $23.7 million and $3.7 million, respectively, of gross profit from oilfield services for the six months ended July 31, 2014 and 2013, after elimination of $18.9 million and $15.1 million, respectively, of intercompany gross profit. See Note 4 — Segment Reporting under Item 1 of this Quarterly Report.

The table below is a summary of the RockPile contribution to our consolidated results for the six months ended July 31, 2014 and 2013, after eliminations:

	For the Six Months Ended July 31, 2014
(in thousands)	RockPile		Eliminations			Consolidated
Revenues
Oilfield services	$	163,487	$	(63,056	)	$	100,431
Total revenues	163,487		(63,056		)	100,431
Cost of sales
Oilfield services	112,578		(41,314		)	71,264
Depreciation	8,280		(2,809		)	5,471
Total cost of sales	120,858		(44,123		)	76,735
Gross profit	$	42,629	$	(18,933	)	$	23,696

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	For the Six Months Ended July 31, 2013
(in thousands)	RockPile		Eliminations			Consolidated
Revenues
Oilfield services	$	71,168	$	(42,179	)	$	28,989
Total revenues	71,168		(42,179		)	28,989
Cost of sales
Oilfield services	49,491		(25,613		)	23,878
Depreciation	2,839		(1,435		)	1,404
Total cost of sales	52,330		(27,048		)	25,282
Gross profit	$	18,838	$	(15,131	)	$	3,707

General and Administrative Expenses

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

(in thousands)	Exploration and Production		Oilfield Services		Corporate		Consolidated Total
For the six months ended July 31, 2014
Salaries, benefits and other general and administrative	$	7,220	$	10,348	$	6,109	$	23,677
Stock-based compensation	739		217		2,859		3,815
Total	$	7,959	$	10,565	$	8,968	$	27,492

For the six months ended July 31, 2013
Salaries, benefits and other general and administrative	$	3,250	$	4,425	$	2,878	$	10,553
Stock-based compensation	569		310		2,154		3,033
Total	$	3,819	$	4,735	$	5,032	$	13,586

Total general and administrative expense increased $13.9 million to $27.5 million for the six months ended July 31, 2014 compared to $13.6 million for the six months ended July 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 six months ended July 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 six months ended July 31, 2013

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 six months ended July 31, 2014, we recognized a $6.4 million loss on our commodity derivative positions due to increases in underlying crude oil prices. Included in the net loss on our derivative activities for the period were cash settlements we incurred on our commodity derivative instruments of approximately $3.4 million. 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 six months of fiscal year 2015, the Company recognized a gain in equity investment derivatives of $2.9 million. For additional discussion, please refer to Note 8 — Derivative Instruments under Item 1 of this Quarterly Report.

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Income (Loss) from Equity Investment

During the six months ended July 31, 2014, the Company recognized $0.9 million for its share of Caliber’s income for the period. This income, however, was offset by $0.8 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.

Interest Expense

The $8.2 million in interest expense for the six months ended July 31, 2014 consists of (a) approximately $3.5 million in interest and amortized fees related to the TUSA Credit Facility, (b) approximately $3.2 million in accrued interest and amortized fees related to our 5.0% Convertible Note, (c) approximately $1.3 million in interest and amortized fees related to the 6.75% Senior Notes, (d) approximately $1.2 million in interest expense associated with our RockPile Credit Facility and notes payable, and (e) approximately $0.8 million in interest expense associated with the Second Lien Credit Facility, all net of approximately $1.8 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $4.7 million of interest expense and capitalized interest was paid in cash. See Note 7 — Long-Term Debt under Item 1 of this Quarterly Report for additional information regarding our debt outstanding.

Income Taxes

The effective tax rate for the six months ended July 31, 2014, was 41.2%, which differs from the statutory income tax rate due primarily to permanent book to tax differences and state income taxes. Neither a tax expense nor a tax benefit was recognized for the six months ended July 31, 2013, as the Company had provided a 100% valuation allowance against its net tax assets which exceeded its tax liabilities at that time.

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 have been volatile; therefore, we cannot predict future commodity prices. Prices received for production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth. In addition, commodity prices received by exploration and production companies in the Williston Basin affect the level of drilling activity there, and therefore the demand for products and services provided by RockPile and Caliber.

In the second quarter of fiscal year 2015, our average realized price for oil was $90.78 per barrel, a slight increase over the realized price for the same period of fiscal year 2014. Future prices for oil will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors. We manage volatility in commodity prices by maintaining flexibility in our capital investment program. In addition, we periodically hedge a portion of our oil production to mitigate our potential exposure to price declines and the corresponding negative impact on cash flow available for investment.

As of July 31, 2014, we had cash on hand of approximately $107.5 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 $305.5 million (subsequently increased to $415.0 million) and available borrowing capacity of $60.4 million under the RockPile credit facility as of July 31, 2014.

On March 25, 2014, RockPile entered into a Credit Agreement (the “FY2015 RockPile Credit Agreement”) by and among RockPile, as borrower, Citibank, N.A. (“Citi”), as administrative agent and collateral agent, Wells Fargo, as joint lead arranger and joint book runner with Citi, and the other lenders party thereto. The FY2015 RockPile Credit Agreement provides for 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. The credit facility is expected to support RockPile’s growth initiatives and enable RockPile to remain self-funded as it contemplates additional investment in infrastructure and equipment necessary to support broad-based growth across its service lines. A portion of the FY2015 RockPile Credit Agreement proceeds were utilized to refinance RockPile’s existing indebtedness. Neither Triangle nor any of its non-RockPile subsidiaries act as a guarantor under the FY2015 RockPile Credit Agreement.

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. However, we will likely remain dependent on borrowings under our credit facilities and potential additional financings for the foreseeable future to fund the difference between cash flow from operations and our capital expenditures

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budget and other contractual commitments (see Note 7 - Long-Term Debt and Note 10 - Commitments and Contingencies under Item 1 of this Quarterly Report for further discussion). Although we expect that increases in our operating cash flow, proceeds from the 6.75% Senior 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, 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 would 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 July 31, 2014, we had $632.4 million of debt outstanding, of which $132.5 million was attributable to our 5% convertible note with an affiliate of Natural Gas Partners (“NGP”), which is convertible into the Company’s common stock at a conversion rate of one share per $8.00 of 5% convertible note principal outstanding, $450.0 million was attributable to the 6.75% Senior Notes, $39.6 million was attributable to the FY2015 RockPile Credit Agreement, and $10.3 million was attributable to various RockPile notes and mortgages outstanding. See Note 7 - Long-Term 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. Our working capital was approximately $73.3 million as of July 31, 2014, as compared to approximately $35.5 million as of January 31, 2014.

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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 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 to continue to increase commensurate with our anticipated increase in sales volumes. We have been able to increase our volumes on a quarter over quarter basis for the past two years. This increase is directly related to our successful operations as we have developed our properties. If we are able to continue to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, subject to 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 July 31, 2014, our maximum credit available under the TUSA Credit Facility was $500.0 million, subject to a borrowing base of $305.5 million. As of July 31, 2014, we had all of our borrowing capacity under the TUSA Credit Facility available. The borrowing base under the TUSA Credit Facility is subject to redetermination on a semi-annual basis by each November 1st and May 1st. In addition, TUSA has the option to request two unscheduled redeterminations during any calendar year and Amendment No. 4 added a borrowing base redetermination in August 2014. On August 21, 2014, our borrowing base was increased to $415.0 million.

On March 25, 2014, RockPile entered into the FY2015 RockPile Credit Agreement, 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 FY2015 RockPile Credit Agreement 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 FY2015 RockPile Credit Agreement, and (v) support letters of credit.

Analysis and Changes in Cash Flow

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

	For the Six Months Ended July 31,
(in thousands)	2014			2013			Change
Net cash provided by operating activities	$	61,846		$	31,433		$	30,413
Net cash used in investing activities	(308,448		)	(159,403		)	(149,045		)
Net cash provided by financing activities	272,379			144,233			128,146
Net increase in cash and equivalents	$	25,777		$	16,263		$	9,514

Net Cash Provided by Operating Activities

Cash flows provided by operating activities were $61.8 million for the six months ended July 31, 2014. Cash flows provided by operating activities were $31.4 million for the six months ended July 31, 2013. The increase in operating cash flows was primarily due to higher oil revenues driven by higher sales volumes, 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.

Net Cash Used in Investing Activities

During the six months ended July 31, 2014, we used $308.4 million in cash in investing activities compared to $159.4 million during the six months ended July 31, 2013. During both six month periods, our primary uses of cash flow in investing activities were related to our oil and gas property expenditures. During the six months ended July 31, 2014 and 2013, we used $280.8 million and $130.1 million, respectively, on oil and gas property additions. During the six months ended July 31, 2014 and 2013, we also spent

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$24.6 million and $16.0 million, respectively, on purchases of oilfield services equipment. During the six months ended July 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 six months ended July 31, 2014, totaled $272.4 million, as compared to $144.2 million for the six months ended July 31, 2013. Our primary source of cash from financing activities during the six months ended July 31, 2014 came from the issuance of $450 million of our 6.75% Senior Notes, net of net repayments on our credit facilities. During the six months ended July 31, 2013, in addition to credit facility net borrowings, we also had net proceeds of $55.8 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 current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our primary market risk is market changes in oil and natural gas prices. Market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties and may indirectly impact our prospective revenues from the sale of 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 trading purposes. All derivative positions are accounted for using mark-to-market accounting.

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

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 four counterparties. The Company has a netting arrangement with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparties. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

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

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

Term End Date	Contract Type	Basis (1)	Quantity (Bbl/d)	Weighted Average Put Strike		Weighted Average Call Strike		Weighted Average Price
Fiscal Year 2015	Collar	NYMEX	5,767	$	87.33	$	100.71
Fiscal Year 2015	Swap	NYMEX	166					$	94.50
Fiscal Year 2016	Collar	NYMEX	4,356	$	86.85	$	98.06

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

We determine the estimated fair value of 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 July 31, 2014 was a net liability of $0.9 million. This mark-to-market net liability relates to commodity derivative instruments with various terms that are scheduled to be realized over the period from May 2015 through December 2016. Over this period, actual realized commodity derivative settlements may differ significantly, either positively or negatively, from the unrealized mark-to-market valuation at July 31, 2014. An assumed increase of 10.0% in the forward commodity prices used in the July 31, 2014 valuation of our commodity derivative instruments would result in a net commodity derivative liability of approximately $19.2 million at July 31, 2014. Conversely, an assumed decrease of 10.0% in forward commodity prices would result in a net commodity derivative asset of approximately $13.3 million at July 31, 2014.

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Interest Rate Risk

At July 31, 2014, the Company had $132.5 million outstanding under the convertible note with NGP, 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 convertible note; provided that, after July 31, 2017, we have the option to make such interest payments in cash.

TUSA Interest Rate Risk

As of July 31, 2014, TUSA had $305.5 million available for borrowing under the TUSA Credit Facility, none of which was drawn as of such date. The credit facility bears interest at variable rates. Assuming TUSA had the maximum allowable amount outstanding at July 31, 2014, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $3.1 million. For a detailed discussion of the TUSA Credit Facility, including a discussion of the applicable interest rates, please refer to Note 13 — Long-Term Debt in our audited financial statements included in our Fiscal 2014 Form 10-K and Note 7 — Long-Term Debt under Item 1 of this Quarterly Report.

At July 31, 2014, TUSA had $450.0 million outstanding under the 6.75% Senior Notes, which have a fixed interest rate of 6.75%. Interest on the 6.75% Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2015. The 6.75% Senior 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 July 31, 2014, RockPile had $100.0 million available for borrowing under the FY2015 RockPile Credit Agreement of which $39.6 million was drawn as of such date. The FY2015 RockPile Credit Agreement bears interest at variable rates. Assuming RockPile had the maximum allowable amount outstanding at July 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 FY2015 RockPile Credit Agreement, including a discussion of the applicable interest rates, please refer to Note 13 — Long-Term Debt in our audited financial statements included in our Fiscal 2014 Form 10-K and Note 7 — Long-Term 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 July 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 July 31, 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the three months ended July 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 arise 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.

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

Our substantial level of indebtedness could limit our financial and operating activities, and adversely affect our ability to incur additional debt to fund future needs.

At July 31, 2014, we had approximately $632.4 million of total indebtedness outstanding. This substantial amount of indebtedness could:

· require us to dedicate a substantial portion of our cash flow to the payment of principal and interest, thereby reducing the funds available for operations and future business opportunities;

· limit our ability to borrow additional money if needed for other purposes, including working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes, on satisfactory terms or at all;

· limit our ability to adjust to changing economic, business and competitive conditions;

· make us more vulnerable to an increase in interest rates, a downturn in our operating performance or a decline in general economic conditions; and

· make us more susceptible to changes in credit ratings, which could impact our ability to obtain financing in the future and increase the cost of such financing.

If compliance with our debt obligations materially limits our financial or operating activities, or hinders our ability to adapt to changing industry conditions, we may lose market share, our revenue may decline and our operating results may be negatively affected.

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

The table below provides a summary of shares of our common stock surrendered to us in payment of tax liability in connection with the vesting of restricted stock units during the three months ended July 31, 2014:

	Total Number of Shares Purchased	Average Price Paid Per Share
	(1)	(2)
May 1, 2014 to May 31, 2014	29,635	$	9.73
June 1, 2014 to June 30, 2014	17,508	11.86
July 1, 2014 to July 31, 2014	17,723	11.14
	64,866	$	10.69

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

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

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not Applicable.

Item 5. Other Information.

None.

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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		Amendment No. 4 to Amended and Restated Credit Agreement and Joinder Agreement, dated May 9, 2014, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Issuing Lender, and the Lenders Named Herein, as Lenders, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2014 and incorporated herein by reference.

10.2		Amendment No. 5 to Amended and Restated Credit Agreement and Joinder Agreement, dated May 14, 2014, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Issuing Lender, and the Lenders Named Herein, as Lenders, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2014 and incorporated herein by reference.

10.3		Purchase and Sale Agreement, dated May 14, 2014, by and among Marathon Oil Company, as Seller, and Triangle USA Petroleum Corporation, as Purchaser, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on May 19, 2014 and incorporated herein by reference.

10.4		Triangle Petroleum Corporation 2014 Equity Incentive Plan, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on May 30, 2014 and incorporated herein by reference.

10.5		Second Lien Credit Agreement, dated June 27, 2014, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Energy Capital, Inc., as Administrative Agent, and the Lenders Named Herein, as Lenders, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 2, 2014 and incorporated herein by reference.

10.6		Indenture, dated July 18, 2014, among Triangle USA Petroleum Corporation, the guarantor named therein and Wells Fargo Bank, National Association, as trustee, relating to the 6.75% Senior Notes due 2022, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 18, 2014 and incorporated herein by reference.

10.7		Form of 6.75% Senior Notes due 2022, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 18, 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 herewith

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SIGNATURES

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

TRIANGLE PETROLEUM CORPORATION

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


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

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

Attached files

Triangle Petroleum Corp Reports