UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the year ended January 31, 2016

001-34945

(Commission File No.)

TRIANGLE PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

STATE OF DELAWARE	98-0430762
(State or Other Jurisdiction of Incorporation)	(I.R.S. Employer Identification No.)

1200 17th Street, Suite 2500, Denver, Colorado 80202

(Address of principal executive offices)

Registrant’s telephone number, including area code: 303.260.7125

Securities registered pursuant to Section 12(b) of the Act:

Title of each class: Common Stock, $0.00001 par value Name of each exchange on which registered: NYSE MKT

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐   No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐   No ☒

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 ☒   No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒   No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

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

Large accelerated filer ☐	Accelerated filer ☒
Non-accelerated filer ☐	Smaller reporting company ☐

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

As of July 31, 2015, the last business day of the registrant’s most recently completed second quarter, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $198,604,351based on a closing price of $3.71 per share as reported on the NYSE MKT on such date.

As of April 4, 2016, the registrant had 76,232,614shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporated by reference from the registrant’s Definitive Proxy Statement for its 2016 Annual Meeting of Stockholders to be filed, pursuant to Regulation 14A, no later than 120 days after the close of the registrant’s fiscal year.

TRIANGLE PETROLEUM CORPORATION

FORM 10-K FOR THE YEAR ENDED JANUARY 31, 2016

TABLE OF CONTENTS

		Page
Part I
Item 1.	Business	3
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	36
Item 2.	Properties	36
Item 3.	Legal Proceedings	36
Item 4.	Mine Safety Disclosures	36
Part II
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 8.	Consolidated Financial Statements and Supplementary Data	61
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures	103
Item 9A.	Controls and Procedures	103
Item 9B.	Other Information	106
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	106
Item 11.	Executive Compensation	106
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	106
Item 13.	Certain Relationships and Related Transactions, Director Independence	106
Item 14.	Principal Accounting Fees and Services	106
Part IV
Item 15.	Exhibits; Financial Statement Schedules	107
Signatures		110

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Where You Can Find More Information

Triangle Petroleum Corporation (“Triangle,” the “Company,” “we,” “us,” “our,” or “ours”) files annual, quarterly, and current reports with the Securities and Exchange Commission (the “SEC”).These reports and other information can be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549.Please call the SEC at 1-800-732-0330 for further information on the operation of the Public Reference Room. The SEC also maintains an Internet site at http://www.sec.gov that contains reports, proxy, and information statements, and other information regarding issuers that file electronically with the SEC, including Triangle.

Investors can also access financial and other information via Triangle’s website at www.trianglepetroleum.com. Triangle makes available, free of charge through its website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, any amendments to such reports, and all reports filed under Section 16 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), reporting transactions in Triangle securities.Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Information contained on or connected to Triangle’s website which is not directly incorporated by reference into the Company’s Annual Report on Form 10-K should not be considered part of this report or any other filing made with the SEC.

Finally, you may request a copy of filings, other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing Triangle at 1200 17th Street, Suite 2500, Denver, Colorado 80202 or by calling Triangle at 1-303-260-7125.

Forward-Looking Statements

This annual report contains certain “forward-looking statements” within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 with respect to our business, plans, prospects, financial condition, liquidity and results of operations.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 annual 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 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:

· future capital expenditures and performance;

· future operating results;

· future commodity prices;

· future ability to borrow or repay indebtedness;

· results of evaluation and implementation of strategic alternatives;

· anticipated drilling and development;

· drilling results;

· results of acquisitions;

· relationships with partners; and

· plans for our subsidiaries.

These forward-looking statements are not guarantees of future performance and are subject to risks and uncertainties that could cause actual results to differ materially from the results contemplated by the forward-looking statements, including the risks discussed in this annual report in “Risk Factors” and elsewhere, and the risks detailed from time to time in our future SEC reports. Many of the important factors that will determine these results are beyond Triangle’s ability to control or predict. Risks and uncertainties that could affect future results include those relating to:

· oil and natural gas prices;

· substantial capital requirements and access to additional capital;

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· our indebtedness and borrowing capacity;

· strategic alternatives to enhance liquidity and improve our balance sheet;

· reserves assumptions;

· potential future impairments;

· our ability to develop or acquire additional reserves;

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

· reliance on third party experts and service providers;

· potential increase in non-consenting non-operator partners;

· challenging agreements with, and conditions for, our operators and joint venture partners;

· our inability to control properties we do not operate;

· government regulation and taxation of the oil and natural gas industry;

· potential regulation affecting hydraulic fracturing;

· environmental regulations, including climate change regulations;

· unavailability and cost of facilities, services, raw materials, and infrastructure;

· uninsured or underinsured risks;

· Triangle’s ability to manage growth in its businesses;

· lack of diversification;

· competition in the oil and natural gas industry;

· seasonal weather conditions;

· unavailability of, or difficulty in, and/or high costs of retaining and attracting qualified personnel;

· potential restatement of financial statements;

· cybersecurity risks;

· aboriginal claims;

· the influence of significant stockholders and creditors;

· lack of control over Caliber and potential dilution of our economic interest;

· changes in the fair value of our derivative instruments; and

· expiring commodity derivatives.

You are cautioned not to put undue reliance on any forward-looking statements, which speak only as of the date of this annual report. Triangle does not assume any obligation to update or release any revisions to these forward-looking statements to reflect events or circumstances after the date of this annual report or to reflect the occurrence of unanticipated events.

Units of Measurement and Glossary of Industry Terms

Units of measurement and industry terms are defined in the Units of Measurement and Glossary of Industry Terms, included at the end of this annual report.

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PART I

You should read this entire report carefully; including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Triangle,” the “Company,” “we,” “us,” “our,” or “ours” refer to Triangle Petroleum Corporation and its subsidiaries.Our fiscal year-end is January 31. As such, the fiscal years ended January 31, 2014, 2015, and 2016 are referred to in this annual report as fiscal year 2014, fiscal year 2015, and fiscal year 2016, respectively. The fiscal year ending January 31, 2017 is referred to in this annual report as fiscal year 2017.

ITEM 1.  BUSINESS

Company Overview

We are an 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 primarily in the Williston Basin of North Dakota and Montana through the Company’s two principal wholly-owned subsidiaries and our equity joint venture:

· Triangle USA Petroleum Corporation (“TUSA”) conducts our exploration and production operations by acquiring and developing unconventional shale oil and natural gas resources;

· RockPile Energy Services, LLC (“RockPile”) is a provider of hydraulic pressure pumping and complementary services; and

· Caliber Midstream Partners, L.P. (“Caliber”) is our 28.3% owned joint venture with First Reserve Energy Infrastructure Fund (“FREIF”). Caliber provides crude oil, natural gas and fresh and produced water gathering, processing, and transportation 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. Our average net daily production for the year ended January 31, 2016 was approximately 13,416 Boe/d, approximately 85% of which was operated production.At January 31, 2016, we had estimated proved reserves of approximately 48.9 MMboe, based on adjusted prices of $38.41 per Bbl for oil, $2.45 per Bbl for natural gas liquids, and $0.55 per Mcf for natural gas. We use pad drilling, which increases efficiencies while controlling costs and minimizing environmental impact. We also use advanced completion, collection, and production techniques designed to optimize reservoir production while reducing costs.  

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

Triangle has two reportable operating segments. Our exploration and production operating segment and our oilfield services operating segment are managed separately because of the nature of their products and services. The focus of the exploration and production operating segment is finding and producing oil and natural gas. The focus of the oilfield services operating segment is pressure pumping and complementary services for both TUSA-operated wells and third-party-operated wells. See Item 8. Consolidated Financial Statements and Supplementary Data.

We were incorporated in the State of Nevada on December 11, 2003 under the name Peloton Resources Inc. On May 10, 2005, we changed our name to Triangle Petroleum Corporation. On November 30, 2012, we changed our state of incorporation from Nevada to Delaware.

Liquidity and Ability to Continue as a Going Concern

Our consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of

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business. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.

Although the Company is continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations, its liquidity outlook has changed since the third quarter of fiscal year 2016. Continued low commodity prices are expected to result in significantly lower levels of cash flow from operating activities in the future and have limited the Company’s ability to access capital markets. As a result of these and other factors, there is substantial doubt about the Company’s ability to continue as a going concern. See Item 8. Consolidated Financial Statements and Supplementary Data – Note 2 for further discussion.

Exploration, Development and Production

Williston Basin – United States.As of January 31, 2016, we held leasehold interests in approximately 103,540 net acres in the Williston Basin. Approximately 77,553 net acres are located in our core focus area in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana, which we refer to as our “Core Acreage.”Our Core Acreage has high oil saturation, is slightly over-pressured, and has the potential for multiple benches. We operate approximately 48,728 net acres in our Core Acreage. The majority of our Williston Basin leaseholds are held primarily under fee leases. These leases typically carry a primary term of three to five years with landowner royalties of approximately 16% to 20%. In most cases, we obtain “paid-up” fee leases, which do not require annual delay rentals.

We target the Middle Bakken formation between the Upper and Lower Bakken Shales at an approximate vertical depth of 10,300 to 11,300 feet. We also target the Three Forks formation, which is present immediately below the Lower Bakken Shale. As of January 31, 2016, we have completed a total of 116 gross (84.5 net) operated wells in the Williston Basin.

The operations of our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Oasis Petroleum, Newfield Production Company, Statoil, Whiting Petroleum, and EOG Resources. These companies are experienced operators in the Williston Basin. As of the end of fiscal year 2016, we have an interest in 469 gross (25.7 net) non-operated wells, 446 gross (24.8 net) of which are producing and 23 gross (0.9 net) are in various stages of permitting, drilling or completion.

Reserves

Net Reserves of Crude Oil, Natural Gas, and Natural Gas Liquids at Fiscal Year-End 2014, 2015 and 2016. Approximately 99% of the Company’s proved reserves at January 31, 2016 are associated with properties located in our Core Acreage. Our proved reserves are located in the Bakken Shale and Three Forks formations. The table below summarizes our estimates of proved reserves as of January 31, 2014, 2015 and 2016, the estimated projected future cash

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flows (before income taxes) from those proved reserves, and the PV-10 Value of the proved reserves at January 31, 2014, 2015 and 2016:

	For the Years Ended January 31,
	2014		2015		2016
Proved developed producing:
Oil (Mbbls)		12,777		25,629		25,567
Natural gas (MMcf)		10,207		21,233		22,373
NGL (Mbbls)		1,332		1,994		3,226
Proved developed non-producing:
Oil (Mbbls)		957		3,976		4,761
Natural gas (MMcf)		723		2,903		3,628
NGL (Mbbls)		108		356		577
Proved undeveloped:
Oil (Mbbls)		18,182		18,486		8,573
Natural gas (MMcf)		15,574		16,049		5,822
NGL (Mbbls)		2,541		1,731		876
Total proved oil reserves (Mbbls)		31,916		48,091		38,901
Total proved natural gas reserves (MMcf)		26,504		40,185		31,823
Total proved NGL reserves (Mbbls)		3,981		4,081		4,679
Total proved oil, NGL and natural gas reserves (Mboe)		40,314		58,870		48,884
PV-10 Values (in thousands) of proved reserves:
PV-10 Value of proved developed producing reserves	$	448,709	$	730,601	$	284,769
PV-10 Value of proved developed non-producing reserves	$	23,055	$	72,702	$	19,612
PV-10 Value of proved undeveloped reserves	$	206,141	$	179,510	$	24,403
PV-10 Value of total proved reserves	$	677,905	$	982,813	$	328,784

Proved Reserves.Our net proved reserves of 48.9 MMboe as of January 31, 2016 decreased 17% from 58.9 MMboe at January 31, 2015. Our proved reserves were principally affected by the following during fiscal year 2016:

In fiscal year 2016, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 13.8 MMboe. Upward revisions of 9.4 MMboe that mostly related to well performance were more than offset by downward adjustments of 23.2 MMboe that resulted from proved reserves that became uneconomic on a PV-10 basis due to the significantly lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at January 31, 2016 as compared to January 31, 2015.

In fiscal year 2016, extensions of 8.8 MMboe of proved reserves added by extensions and discoveries in North Dakota are primarily due to our successful completions of exploratory wells and proved undeveloped wells, and the extensions of reserves for offsetting locations.

Proved Undeveloped Reserves.Our proved undeveloped (“PUD”) reserves decreased from 22.9 MMboe at January 31, 2015 to 10.4 MMboe at January 31, 2016. The following table provides a reconciliation of the major changes in our PUD reserves in fiscal year 2016:

	(Mboe)	Gross Wells	Net Wells
Proved Undeveloped Reserves at January 31, 2015	22,892	103	54.0
Conversion to developed reserves in fiscal year 2016	(2,668)	(12)	(5.8)
Revisions	(14,693)	(66)	(39.0)
Acquisitions	—	—	—
Extensions and discoveries of proved reserves	4,888	18	8.4
Proved Undeveloped Reserves at January 31, 2016	10,419	43	17.6

The number of PUD locations decreased from 103 gross locations (54.0 net) at January 31, 2015 to 43 gross locations (17.6 net) at January 31, 2016. Upward revisions related to well performance were more than offset by decreases in PUD reserves and PUD locations that resulted from proved undeveloped reserves that became uneconomic on a PV-10 basis due to the significantly lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at

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January 31, 2016 as compared to January 31, 2015. At January 31, 2016, we have no proved undeveloped reserves that are scheduled for development five years or more beyond the date the reserves were initially recorded.

During fiscal year 2016, we invested approximately $48.0 million (averaging $8.3 million per net well) related to the drilling and completion of the 12 gross wells (5.8 net) wells that converted 2.7 MMboeof proved undeveloped reserves to proved developed reserves.

In estimating proved reserves, Triangle used the SEC definition of proved reserves. Projected future cash flows were based on economic and operating conditions as of the respective January 31 estimation dates except that future commodity prices used in the projections reflected a simple average of prices for our operated and non-operated properties on the first day of each of the twelve months in the year ended on the estimation date. Prices of $48.93 per Bbl for oil, $24.97 per barrel for natural gas liquids, and $2.53 per MMbtu for natural gas were adjusted for regional price differentials; gathering, transportation, and processing; and other factors to arrive at prices of $38.41 per Bbl for oil, $2.45 per barrel for natural gas liquids, and $0.55 per Mcf for natural gas, which were used in the calculation of proved reserves at January 31, 2016.

Volumes of reserves that will actually be recovered and cash flows that will actually be received from production may differ significantly from the proved reserve estimates and the related projected cash flows, respectively. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any 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, particularly for undeveloped locations where estimates may be more imprecise than for established producing oil and natural gas properties.Accordingly, reserve estimates are often different from the quantities that are ultimately recovered.

The Standardized Measure is presented more fully and discussed further in Item 8.Consolidated Financial Statements and Supplementary Data.

Reserve Estimation Methods.The process of estimating proved reserves involves exercising professional judgment to select estimation method(s) within three categories: (1) performance-based methods, (2) volumetric-based methods, and (3) analogy. The selection of estimation method(s) considers (i) the geoscience and engineering data available at the time, (ii) the established or anticipated performance characteristics of the reservoir being evaluated, and (iii) the development stage and production history of the well, property or field.

For proved reserves estimated at January 31, 2014, 2015 and 2016, Triangle has used the following general estimation methods:

· Proved producing reserves attributable to producing wells were estimated by performance methods or by analogy. Performance methods included decline curve analysis, which utilized extrapolation of historical production through the estimation date where such historical data was considered to be definitive. Where such historical data was insufficient for extrapolation, the analogy method was used.

· Proved undeveloped reserves were estimated by the analogy method.

Internal Controls over Reserve Estimation.The Company engaged Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), an independent petroleum engineering firm, to perform an audit of Triangle’s internal estimates of proved reserves. Cawley Gillespie’s fiscal year-end 2016 reserves audit report was prepared based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provided to them. The internal reserve estimates and supporting schedules are prepared by our Production & Reservoir Engineer and reviewed by management prior to being provided to Cawley Gillespie.

Cawley Gillespie’s fiscal year-end 2016 reserves audit report (filed as Exhibit 99.1 to this annual report) states that Cawley Gillespie is a Texas Registered Engineering Firm (F-693), comprised of independent Registered Professional Engineers and Geologists. The firm has provided petroleum consulting services to the oil and gas industry for over 50 years.This audit was supervised by Mr. W. Todd Brooker, Senior Vice President at Cawley Gillespie and a State of Texas Licensed Professional Engineer (License #83462). Mr. Brooker received his Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin in 1989, and joined Cawley Gillespie as a Reservoir Engineer in 1992.

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Our Production & Reservoir Engineer, Daniel Lockley, is the technical person primarily responsible for overseeing the preparation of the Company’s reserves estimates. He has over 10 years of experience as a petroleum engineer and is a member of the Society of Petroleum Engineers. He holds an undergraduate degree from the Colorado School of Mines. The Company’s internal estimates of proved reserves are based on available geoscience and engineering data, including North Dakota online files of monthly production for wells in which we have an interest and wells adjacent to drill spacing units in which we have an interest. The internal reserve schedules and certain supporting schedules are reviewed by various members of management before our Production & Reservoir Engineer prepares a final internal summary of proved reserves and a final listing (by well and drilling location) of proved reserves, which is then provided to Cawley Gillespie.

Developed and Undeveloped Acreage

As of January 31, 2016, we had approximately 3,536 lease agreements representing approximately 233,232 gross (103,540 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:

	DevelopedAcres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
North Dakota	164,669	62,754	18,459	5,518	183,128	68,272
Montana	8,272	6,190	41,832	29,078	50,104	35,268
Total Williston Basin	172,941	68,944	60,291	34,596	233,232	103,540

We are subject to lease expirations if we or the operator of our non-operated acreage do not commence the development of operations within the agreed terms of our leases. All of our leases for undeveloped acreage will expire at the end of their respective primary terms except for leases where we (i) make extension payment(s) under the lease terms, (ii) renew the existing lease, (iii) establish commercial production in paying quantities, or (iv) trigger some other “savings clause” in the relevant lease. Out of our 60,291 gross (34,596 net) undeveloped acres as of January 31, 2016, the portion of our net undeveloped acres that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 51.5% in fiscal year 2017, 39.9% in fiscal year 2018, and 0.2% in fiscal year 2019. As of January 31, 2016, 6.9% of our undeveloped acres are held by production. A large portion of our undeveloped acres will likely expire at the end of their respective terms unless commodity prices recover in the near term. For financial reporting purposes in fiscal year 2016, the Company impaired unproved leasehold costs for substantially all acreage not held by production into the amortizable full cost pool.

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Drilling and Other Exploratory and Development Activities

The following table presents the gross and net number of exploration wells and development wells that we drilled in the U.S. during fiscal years 2014, 2015 and 2016 targeting oil reserves, based on the date of first sales or the date the well became capable of selling. The number of wells drilled refers to the number of wells completed at any time during the year, regardless of when drilling was initiated. Well completion refers to installation of permanent equipment for production of oil or natural gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned after little or no production.

	For the Years Ended January 31,
	2014		2015		2016
	Gross	Net	Gross	Net	Gross	Net
Productive exploratory wells:
Operated by Triangle	9	7.2	17	11.7	9	6.1
Operated by others	37	2.0	78	3.3	31	0.9
Total	46	9.2	95	15.0	40	7.0
Dry exploratory wells	—	—	—	—	1	1
Productive development wells:
Operated by Triangle	22	16.3	32	22.8	11	8.2
Operated by others	44	2.6	18	0.8	1	—
Total	66	18.9	50	23.6	12	8.2
Dry development wells	—	—	—	—	1	0.7
Total productive wells	112	28.1	145	38.6	52	15.2

As of January 31, 2016, we had 586 gross productive wells and 129.6 net productive wells, all located in North Dakota except for 13 gross wells located in Roosevelt and Sheridan Counties, Montana. None of our gross productive wells had completions within multiple zones. Our count of productive wells does not include 37 gross (14.0 net) wells that were awaiting completion, in the process of completion, or awaiting flowback subsequent to fracture stimulation as of that date. Although we encounter and produce natural gas as a byproduct of drilling wells targeting crude oil, we have not participated in any wells specifically targeting natural gas reserves.

Costs Incurred and Capitalized Costs

The table below presents costs incurred in oil and natural gas acquisition, exploration, and development activities during fiscal years 2014, 2015 and 2016.

	For the Years Ended January 31,
(in thousands)	2014		2015		2016
Property acquisition	$	121,578	$	138,778	$	810
Exploration		96,731		180,174		58,660
Development		216,046		226,765		93,756
Total	$	434,355	$	545,717	$	153,226

Oilfield Services

RockPile, our wholly-owned subsidiary, is a provider of hydraulic pressure pumping and complementary services to oil and natural gas exploration and production companies primarily in the Williston Basin. RockPile provides a variety of oilfield services including, but not limited to, pressure pumping, wireline, perforating, pump rental, and workover services.

The use of RockPile’s services lowers our realized well completion costs and affords us greater control over completion schedules and quality control. In fiscal year 2016, RockPile increased year-over-year completions by approximately 18%, completing 20 TUSA operated wells and 155 third-party wells, as compared to 49 TUSA operated

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wells and 99 third-party wells in fiscal year 2015. RockPile contributed $176.9 million to our consolidated revenue for the year ended January 31, 2016.

RockPile is currently providing oilfield services in the Williston Basin and the Permian Basin of Texas and is evaluating opportunities in other areas.

Midstream Services

Caliber is an energy infrastructure company that provides a full suite of midstream services to us and other producers in the Williston Basin. Caliber’s midstream services include crude oil and natural gas gathering, transportation, treating and processing, produced water transportation and disposal, and freshwater sourcing and transportation via pipeline.

Caliber was created in October 2012, and capitalized through initial funding commitments of $100.0 million in equity capital contributions ($70.0 million from FREIF, $30.0 million from Triangle). FREIF committed an additional $80.0 million in equity capital contributions in September 2013, followed by an equity capital contribution of $34.0 million in February 2015. Caliber is managed and governed by its general partner, Caliber Midstream GP, LLC, of which FREIF and Triangle each hold a 50% non-economic interest and share governance equally. We currently hold a 28.3% Class A Units economic interest in Caliber.

Caliber’s operations are principally located in McKenzie County, North Dakota. Since its inception, Caliber has constructed over 300 miles of pipelines across its four service lines. Caliber’s crude oil infrastructure includes two stabilization facilities and an interconnection with the Enbridge pipeline at the Alexander Market Center. Caliber also owns and operates the Hay Butte Gas Plant, which consists of a mechanical refrigeration unit with a capacity of 10 MMcf per day. Processed natural gas and natural gas liquids are delivered via pipeline for further distribution downstream. Caliber also operates five produced water disposal wells. The disposal wells are connected to the produced water pipeline system or they can receive water from producers by truck. In 2015, Caliber completed construction of a 23 mile freshwater transportation pipeline to an intake facility on the Yellowstone River. The fresh water pipeline allows access to 13,200 acre feet per year of fresh water supply to Triangle and other producers for well completions and maintenance water.

As of January 31, 2016, we had connected 111 of our operated wells to one or more services provided by Caliber’s midstream system.

Pricing and Production Cost Information

The following table summarizes the volumes and realized prices for oil and natural gas produced and sold from the Bakken Shale and Three Forks formations properties in which we held an interest during the periods indicated. Realized prices presented below exclude the effects of hedges and derivative activities. Also presented is a summary of related production costs per Boe.

	For the Years Ended January 31,
	2014		2015		2016
Net Sales Volume
Crude oil (Mbbls)		1,754		3,511		3,952
Natural gas (MMcf)		626		2,429		3,115
Natural gas liquids (Mbbls)		70		260		426
Total barrels of oil equivalent (Mboe)		1,929		4,176		4,897
Average Sales Price Per Unit
Oil price (per Bbl)	$	88.07	$	75.00	$	43.07
Natural gas price (per Mcf)	$	4.39	$	5.27	$	2.61
Natural gas liquids price (per Bbl)	$	46.72	$	32.26	$	6.74
Weighted average price (per Boe)	$	83.22	$	68.13	$	37.01
Operating Expenses Per Unit
Lease operating expenses (per Boe)	$	7.49	$	6.15	$	8.48
Gathering, transportation and processing (per Boe)	$	2.23	$	4.43	$	5.29
Production taxes (per Boe)	$	9.33	$	7.13	$	3.57

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Sales from our operated wells began in May 2012. Our net sales volumes from operated wells totaled 4,182 Mboe for fiscal year 2016. We sold crude oil, natural gas liquids, and natural gas through delivery points on Caliber and other third-party gathering systems in fiscal year 2016.

Significant Customers

Oil, Natural Gas, and Natural Gas Liquids Customers.For wells that we operate, produced oil is sold at the wellhead, or a location nearby, under short term agreements with several purchasers. While the pricing terms of these agreements vary by purchaser, they all reflect a price determined by the current NYMEX West Texas Intermediate contract, less a discount that is either calculated, fixed, or a combination of calculated and fixed.

In fiscal year 2016, we made sales of operated well production directly to 11 oil purchasers, two NGL purchasers and six natural gas purchasers. In fiscal year 2016, we had revenues from one TUSA customer that exceeded 10% of our $358.1 million in total revenues for the year. For our top TUSA customer, our fiscal year 2016 revenues were approximately $36.2 million or 10% of our total revenues.

Although a substantial portion of our production is purchased by, or through, these parties, we do not believe the loss of any one customer would have a material adverse effect on our business as other customers should be accessible to us. We regularly monitor the credit worthiness of customers and may require parental guarantees, letters of credit or prepayments when deemed necessary.

For our economic interests in wells operated by third-parties, substantially all of our sales of crude oil and natural gas in fiscal years 2014, 2015 and 2016 were sold (i) through arrangements made by the wells’ operators and (ii) at sales points at or close to the producing wells. These third-party operators include a variety of exploration and production companies ranging from large publicly-traded companies to small privately-owned companies. We do not believe the loss of any single operator’s customer would have a material adverse effect on our Company as a whole.

For our economic interests in wells operated by third-parties, we have the right to take and sell our proportionate share of production, rather than have the operator arrange such sale; however, we did not do so in fiscal years 2014, 2015 or 2016. The operators collect the sales proceeds and pass on to us our proportionate share of sales, net of severance taxes and royalties paid either by the purchaser or the operator on our behalf.

Oilfield Services Customers.The ability of RockPile to acquire and retain business depends substantially upon the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, and the number and design of well completions. These factors are affected by changes in commodities prices, the overall economic environment, and industry trends and technological advancements. RockPile’s principal customers consist of independent oil and natural gas producers in need of horizontal well completion and oilfield services primarily in the Williston Basin.During fiscal year 2016, RockPile provided pressure pumping services for 20 wells operated by TUSA and 155 wells operated by third parties. Currently, our pressure pumping and oilfield services are conducted at spot prices pursuant to master services agreements that have no long term commitments. Therefore, while the pricing and demand for our services has declined significantly over recent quarters as a result of decreased drilling and completion activities by operators in the Williston Basin, we do not believe that the loss of any single third party customer would have a material adverse effect on our Company.

In fiscal year 2016, we made sales of pressure pumping and well completion services directly to 24third party oilfield services customers. In fiscal year 2016, we had revenues from two oilfield services customers that exceeded 10% of our $358.1 million in total revenues for the year. For our top two oilfield services customers, our fiscal year 2016 revenues were approximately $97.5 million or 27% of our total revenues.

Delivery Commitments

In October 2012, TUSA entered into two midstream services agreements with Caliber North Dakota LLC (“Caliber North Dakota”), an affiliate of Caliber: one for crude oil gathering, stabilization, treating and redelivery, and one 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 completion and production operations. Under the agreements, TUSA committed to deliver minimum monthly revenues derived from the fees paid by TUSA to Caliber for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the

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in-service date of the Caliber facilities (occurred in April 2014). On September 12, 2013, TUSA and Caliber North Dakota amended and restated the two agreements. Under the amended and restated agreements, TUSA maintained the revenue commitments included in the original agreements and added a commitment to deliver additional minimum monthly revenues derived from the fees paid by TUSA to Caliber North Dakota related to an increased acreage dedication and increased firm volume commitment. The additional minimum monthly revenue commitments commenced on the in-service date of certain incremental Caliber North Dakota facilities (occurred in September 2014).The minimum commitment over the term of the agreements is $405.0 million, of which $303.4 million is outstanding at January 31, 2016.The agreements permit TUSA to build up credits against future monthly commitments for the excess of actual monthly revenues over the minimum monthly revenues. As of January 31, 2016, TUSA has built up a cumulative credit of $41.5 million. Credits may be carried forward for a period of four years from the date of the accrual. TUSA is required to pay Caliber for any deficiency of actual monthly revenues if no credits are available. Also on September 12, 2013, TUSA and Caliber Measurement Services LLC (“Caliber Measurement”), another Caliber affiliate, entered into a gathering services agreement pursuant to which Caliber Measurement provides certain gathering-related measurement services to TUSA.

Competitors

In the Williston Basin, TUSA competes with a number of larger public and private exploration and production companies including, but not limited to, Continental Resources, Statoil, Enerplus Resources Corporation, Oasis Petroleum, Newfield Exploration, and Whiting Petroleum.

RockPile’s competition includes large integrated oilfield services companies, a significant number of regional competitors, and a limited number of smaller service companies. RockPile’s competitors include, but are not limited to, Halliburton, Schlumberger, Baker Hughes, PumpCo, Sanjel, and Liberty Oilfield Services.

Caliber competes with large and small-scale pipeline operators, producer-owned midstream systems, trucking companies, and other oilfield services companies.

Seasonality

There is little seasonality in the demand for crude oil produced in North Dakota. Generally, oil prices in the Williston Basin are impacted by global oil demand and by the availability of crude oil transportation capacity, storage, and related services and infrastructure. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or cool summers sometime lessen these fluctuations. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during lower demand periods, which can lessen seasonal demand fluctuations.

Certain of our operations are subject to seasonal limitations. Our operations are conducted in areas subject to extreme weather conditions during certain parts of the year, primarily in the winter and the spring. During these periods, drilling, completion, and other operations can be delayed because of cold, snow, and other winter weather conditions. Additionally, certain state and local governments in our area of operations have enacted “frost laws” to protect their roadways during the spring as the ground thaws and makes the roads unstable. Passage over certain county roads is restricted by weight. For state roads, additional fees are required to obtain over-the-road permits. Frost laws result in logistical challenges that could potentially result in temporary interruptions in our operations.Complications from adverse weather conditions are one reason why we generally prefer to have crude oil, natural gas and produced water transported away from the wellhead by pipeline, rather than by truck, for our operated wells.

We do not currently believe that seasonal fluctuations will have a material impact on our performance.

Governmental Regulation

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax, and other laws and regulations relating to the oil and natural gas industry. Governmental authorities have the power to enforce compliance with these laws and regulations, and violations are subject to injunctive action, as well as administrative, civil and criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that may be adopted in the future, could have a material adverse impact on our business, financial condition and results of operations. In view of the many uncertainties concerning future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

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We believe that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations are generally no more restrictive on our operations than they are on other similar companies in the oil and natural gas industry.

Environmental Laws and Regulations.Like the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state, and local laws and regulations designed to protect and preserve natural resources and the environment. The recent trend in environmental legislation and regulation affecting the oil and natural gas industry generally is toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, especially in wilderness areas and areas with endangered or threatened plant or animal species; impose restrictions on construction, drilling, and other exploration and production activities; regulate air emissions, wastewater, and other production and waste streams from our operations; impose substantial liabilities for pollution that may result from our operations; and require the reclamation of certain lands.

The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities, and in some cases private parties, have the power to enforce compliance with environmental regulations, and violations are subject to fines, compliance orders, and other enforcement actions. We are not aware of any material noncompliance with applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with applicable environmental requirements. However, given the complex regulatory requirements applicable to our operations, and the rapidly changing nature of environmental laws in our industry, we cannot predict our future exposure concerning such matters, and our future costs to achieve compliance or resolve potential violations could be significant.

Waste Disposal and Pollution Regulation.The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund law,” and comparable state laws may impose joint and several and strict liability, without regard to fault, on certain classes of persons for the release of CERCLA “hazardous substances” into the environment. These persons include the current and former owners and operators of a site where a release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance at a site. Under CERCLA, such persons may be subject to joint and several and strict liability for the costs of cleaning up hazardous substances released into the environment and for damages to natural resources. Strict liability means liability without fault such that in some situations we could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or otherwise without negligence on our part or for the conduct of third parties. These third parties may include prior operators of properties we have acquired, operators of properties in which we have an interest and parties that provide transportation services for us. If exposed to joint and several liability, we could be responsible for more than our share of a particular clean-up, remediation or other obligation, and potentially for the entire obligation, even where other parties were involved in the activity giving rise to the liability. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Such claims may be asserted under CERCLA, as well as state common law theories, or state laws that are modeled after CERCLA. In the course of our operations, we generate waste that may fall within CERCLA’s definition of “hazardous substances.” Therefore, governmental agencies or third parties could seek to hold us responsible for all or part of the costs to clean up a site at which such hazardous substances may have been released, or other damages resulting from a release.

The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the management, storage, treatment, disposal, and cleanup of solid and hazardous waste, and authorize substantial fines and penalties for noncompliance. Drilling fluids, produced waters and many of the other wastes associated with the exploration, development, and production of oil or gas currently are exempt under federal law from regulation as RCRA “hazardous” wastes and instead are regulated as non-hazardous “solid” wastes. It is possible, however, that oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our operating expenses, which could have a material adverse effect on the results of operations and financial position. Also, in the course of our operations, we generate some industrial wastes, such as paint wastes, waste solvents, and waste oils that may be regulated as hazardous wastes under RCRA and comparable state laws and regulations.

Regulation of Discharges to Water and Water Supplies.The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and analogous state laws, impose restrictions and strict controls on the discharge of

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“pollutants” into “waters of the United States,” including wetlands and other waters without appropriate permits. These controls generally have become more stringent over time, and it is possible that additional restrictions will be imposed in the future. Pollutants under the Clean Water Act are defined to include produced water and sand, drilling fluids, drill cuttings, and other substances related to the oil and natural gas industry. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for unauthorized discharges or noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. They also can impose substantial liability for the costs of removal or remediation associated with discharges of pollutants.

The Clean Water Act also regulates stormwater discharges from industrial properties and construction sites, and requires separate permits and implementation of a Stormwater Pollution Prevention Plan (“SWPPP”) establishing best management practices, training, and periodic monitoring of covered activities. Certain operations also are required to develop and implement Spill Prevention, Control, and Countermeasure (“SPCC”) plans or facility response plans to address potential oil spills from certain above-ground and underground storage tanks. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013 which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the final rule issued in June 2015 defining the scope of jurisdictional Waters of the U.S. This final rule has been stayed pending the resolution of ongoing litigation.

Our underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous state laws and regulations. Under Part C of the Safe Drinking Water Act, the Environmental Protection Agency (“EPA”) established the Underground Injection Control (“UIC”) program, which established the minimum program requirements for state programs regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, recordkeeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. Federal and state regulations require permits from applicable regulatory agencies to operate underground injection wells. In addition, concerns regarding the underground disposal of produced water into Class II UIC wells, including potential seismic impacts, may result in stricter regulation and increased costs associated with oil and natural gas wastewater disposal.

Oil Spill and Wastewater Disposal Regulation.The British Petroleum crude oil spill in the Gulf of Mexico in 2010 and generally heightened industry scrutiny has resulted and may result in new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations relating to water protection and specifically to oil spill prevention and enforcement. The Oil Pollution Act of 1990 (“OPA”), augments the Clean Water Act and imposes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. For example, operators of oil and natural gas facilities must develop, implement, and maintain facility response plans, conduct annual spill training for employees, and provide varying degrees of financial assurance to cover costs that could be incurred in responding to oil spills. In addition, owners and operators of oil and natural gas facilities may be subject to liability for cleanup costs and natural resource damages as well as a variety of public and private damages resulting from oil spills.

These and similar state laws also govern the management and disposal of produced waters from our extraction process. Currently, wastewater associated with oil and natural gas production from shale formations is prohibited from being directly discharged to waterways and other waters of the United States. While some of our wastewater is reused or re-injected, a significant amount still requires disposal. As a result, some wastewater is transported to third-party treatment plants. In April 2015, the EPA proposed regulations under the Clean Water Act to impose pretreatment standards on wastewater discharges associated with hydraulic fracturing activities. Aside from the EPA, the Bureau of Land Management, or BLM, has issued new rules, which are currently stayed pending further litigation, for hydraulic fracturing activities involving federal and tribal lands and minerals that, in general, would cover disclosure of fracturing fluid components, wellbore integrity, and handling of flowback and produced water.

Our operations also could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water, used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage, may lead to water constraints and supply concerns (particularly in some parts of the country).

Air Emissions and Climate Change.Federal standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) under the Clean Air Act (“CAA”) applicable to hydraulically fractured natural

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gas wells , also known as “Quad O,” became effective in 2012, with more amendments effective in 2013 and 2014, all of which have added administrative and operational costs. The standards require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions during hydraulically fractured natural gas well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators. Following a legal challenge and several petitions for administrative reconsideration of the Quad O rules, EPA issued final amendments related to storage tanks, green completions, and other provisions of the rule in September 2013 and December 2014 respectively. Most key provisions in Quad O took effect in 2015. The rules associated with such standards are substantial and will likely increase future costs of our operations and will require us to make modifications to our operations or install new equipment. While the “green completion” requirements likely will not impact our operations since we primarily explore for and produce oil rather than natural gas, the storage vessel requirements apply to a wide array of storage vessels, including those holding condensate and crude oil. Applicability of these requirements depends on a tank’s potential to emit (PTE) Volatile Organic Compounds (VOCs), not whether it is a gas or oil well. Thus, while the green completion requirements may not apply to our operations, certain of our tanks may trigger the Quad O storage vessel requirements if they have a PTE that exceeds the applicable threshold. In addition, as part of its comprehensive strategy to further reduce methane emissions from the oil and gas sector, EPA proposed amendments to Quad O in 2015 that would impose additional control and other requirements to reduce such emissions. A final rule is expected in June 2016.

On October 1, 2015, EPA announced its final rule lowering the existing 75 part per billion (“ppb”) national ambient air quality standard (“NAAQS”) for ozone under the CAA to 70 ppb. The lower ozone NAAQS could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

Wells in the Bakken Shale and Three Forks formations in North Dakota produce natural gas as well as crude oil. Constraints in the current gas gathering network in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. The North Dakota Industrial Commission, the State’s chief energy regulator, issued an order to reduce the volume of natural gas flared from oil wells in the Bakken Shale and Three Forks formations. In addition, the Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals.

Climate change has emerged as an important topic in public policy debate. It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases (“GHGs”). Products produced by the oil and natural gas exploration and production industry are a source of certain GHGs, primarily carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting and release of fugitive emissions of natural gas could have a significant impact on our future operations. EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane, and other GHGs present an endangerment to human health and the environment, which has allowed the EPA to begin regulating emissions of GHGs under existing provisions of the Clean Air Act. The EPA has been implementing GHG-related reporting and permitting rules. In June 2014, however, the United States Supreme Court invalidated a portion of EPA’s GHG program in the case Utility Air Regulatory Group (“UARG”) v. EPA. Specifically, under the Supreme Court’s UARG opinion, sources subject to the federal Title V and/or the Prevention of Significant Deterioration (“PSD”) programs because of emissions of non-GHG pollutants may still be subject to GHG permitting, including requirements to install Best Available Control Technology (“BACT”). Sources that would be subject to Title V or PSD because of only GHG emissions, however, are no longer subject to GHG permitting requirements, including GHG BACT requirements. Upon remand, EPA currently is considering how to implement the Court’s decision.

The U.S. Congress has considered, and may in the future consider, “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. Similarly, President Obama, who has made GHG regulation a significant priority for his second term, issued a Climate Action Plan in June 2013 that, among other things, calls for a reduction in methane emissions from the oil and gas sector. In spring 2014, EPA issued five “Methane White Papers” exploring methane emissions from, and possible controls for, various aspects of the oil and natural gas production process. Building on these white papers, in January 2015, EPA announced a comprehensive strategy to further reduce methane emissions from the U.S. oil and gas industry. As part of the Obama Administration’s overall GHG reduction strategy, EPA proposed amendments to Clean Air Act New Source Performance Standards in 2015 that would

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impose additional control and other requirements to reduce methane emissions. A final rule is expected in June 2016. These rules likely will include some additional mandatory requirements, potentially including leak detection and repair obligations, controls for hydraulically fractured oil wells, as well as other control, monitoring, and recordkeeping requirements applicable to a variety of oil and gas facility processes and associated equipment.

In November 2013, the President released an Executive Order charging various federal agencies, including EPA, with devising and pursuing strategies to improve the country’s preparedness and resilience to climate change. In part through these executive actions, the direct regulation of methane emissions from the oil and gas sector continues to be a focus of regulation. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production. For example, as part of state-level efforts to reduce these emissions, operating restrictions on emissions by drilling rigs and completion equipment could be enacted, leading to an increase in drilling and completion costs. Also, the emergence of trends such as a worldwide increase in hybrid power motor vehicle sales, and/or decreased personal motor vehicle use by individuals in response to regulatory changes and/or perceived negative impacts on the climate from GHGs could result in lower world-wide consumption of, and prices for, crude oil.

On January 22, 2016, the BLM issued a proposed rule on venting, flaring, and leaking from oil and gas operations on onshore federal and Indian leases, along with a four-page fact sheet. DOI is proposing to update Notice to Lessees (NTL)-4A by requiring operators to limit venting and flaring through new technologies, processes, and equipment including storage tanks, adopt leak detection and repair programs, and limit gas losses during liquids unloading. The proposed rule also would prohibit venting, except during emergencies and other limited exceptions, which effectively implements a "no venting" standard. The rule also proposes to clarify when operators owe royalties on flared gas and allows BLM to set royalty rates at or above 12.5 percent of the value of production.

These and other laws or regulations that have been or may be adopted to restrict or reduce emissions of GHGs or flaring likely would require us to incur increased operating costs and could have an adverse effect on demand for our production. These or future federal, state, regional or international monitoring or regulatory requirements relating to climate change could require us to obtain permits or allowances for our GHG emissions, install new pollution controls, increase our operational costs, limit our operations, or adversely affect demand for the oil and natural gas we produce.

Regulation of Hydraulic Fracturing.Hydraulic fracturing is the primary well-completion method used in the Bakken Shale and Three Forks formations. Hydraulic fracturing is a process that creates fractures extending from the wellbore into a rock formation that enables oil or natural gas to move more easily through the otherwise impermeable rock to a production well. Fractures typically are created through the injection of water, chemicals, and sand (or some other type of “proppant”) into the rock formation. Although hydraulic fracturing has been an accepted practice in the oil and natural gas industry for many years, its use has dramatically increased in the last decade, and concerns over its potential environmental effects have received increasing attention from regulators and the public.

Several federal agencies, including the EPA, recently have asserted potential regulatory authority over hydraulic fracturing. The EPA continues its study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and issued a draft assessment in June 2015, with a final, peer-reviewed report expected in 2016. Moreover, in April 2015, the EPA proposed regulations under the Clean Water Act to impose pretreatment standards on wastewater discharges associated with hydraulic fracturing activities.

On March 20, 2015, the BLM released a final rule that will regulate hydraulic fracturing on federal and Indian lands. The rule requires operators to: (i) submit detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, the depths of all usable water, estimated volume of fluid to be used, and estimated direction and length of fractures, to the BLM before hydraulically fracturing an existing well; (ii) design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate “usable” water; (iii) monitor cementing operations during well construction; (iv) take remedial action if there are indications of inadequate cementing, and demonstrate to the BLM that the remedial action was successful; (v) perform a successful mechanical integrity test prior to the hydraulic fracturing operation; (vi) monitor annulus pressure during a hydraulic fracturing operation; (vii) manage recovered fluids in rigid enclosed, covered or netted and screened above-ground storage tanks, with very limited exceptions that must be approved on a case-by-case basis; (viii) disclose the chemicals used to the BLM and the public, with limited exceptions for material demonstrated to be trade secrets; and (ix) provide documentation of all of the above actions to the BLM.

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In addition, Congress has considered, and may in the future consider, legislation that would amend the Safe Drinking Water Act to encompass hydraulic fracturing activities. In the past, such proposed legislation would have required hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, including disclosure of chemicals used in the hydraulic fracturing process, and meet plugging and abandonment requirements. Some states already have adopted, and other states are considering adopting, requirements that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, Montana and North Dakota have enacted regulations requiring operators to disclose information about hydraulic fracturing fluids on a well-by-well basis, and require specific construction and testing requirements for wells that will be hydraulically fractured. In addition, in Montana, operators generally must obtain approval from the state before hydraulic fracturing occurs and submit a report after the work is completed. Some states, municipalities, and other local governmental bodies also have purported to regulate, and in some cases prohibit, hydraulic fracturing activities. For example, Vermont and New York have banned the use of the technology.

The EPA also has initiated a stakeholder and potential rulemaking process under the Toxic Substances Control Act (“TSCA”) to obtain data on chemical substances and mixtures used in hydraulic fracturing. The EPA has not indicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to the TSCA rulemaking. The TSCA rulemaking follows the general trend of increased disclosure and transparency associated with the chemicals used in hydraulic fracturing among the various states (e.g., North Dakota), including widespread participation by industry in a publicly searchable registry website developed and maintained by the Ground Water Protection Council (“FracFocus”). In addition, in January 2015, several national environmental advocacy groups filed a lawsuit requesting that EPA add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under EPCRA’s Toxics Release Inventory (TRI) program. All of these initiatives present significant, but uncertain, risk of additional regulation of the oil and natural gas industry.

In addition, concerns have been raised about the potential for earthquakes associated with disposal of produced waters into Class II UIC wells. The EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. We cannot predict the EPA’s future actions in this regard. Certain states, such as California and Ohio, where earthquakes have been alleged to be linked to UIC disposal activities, have proposed regulations that would require mandatory reviews of seismic data and related testing and monitoring as part of the future permitting process for UIC wells.

Regulation of Production of Natural Gas and Oil.The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, and the regulation of well spacing or density. The effect of these regulations is to limit the amount of natural gas and oil we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations, or to have reductions in well spacing or density. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

The states in which we operate also regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, bonding requirements to drill or operate wells, limits on the location of wells, imposing requirements on the methods of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Transportation and Sales of Natural Gas.The transportation and sale of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. Although FERC’s orders do

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not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

The Domenici Barton Energy Policy Act of 2005, or “EP Act of 2005,” amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provided FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA to $1.0 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704.

On December 26, 2007, FERC issued Order No. 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMbtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. In some cases, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although nondiscriminatory-take regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the

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Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

Our sales of natural gas are also subject to requirements under the Commodity Exchange Act, or CEA, and regulations promulgated thereunder by the Commodity Futures Trading Commission, or CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering, or causing to be delivered, false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other producers, gatherers and marketers with which we compete.

Employees

As of January 31, 2016, we had 385 full time employees compared to 562 full time employees at January 31, 2015. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.

Offices

We maintain our principal office at 1200 17th Street, Suite 2500, Denver, Colorado, 80202, and our telephone number is 1-303-260-7125. We also own or lease field offices and facilities in North Dakota and Texas.

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ITEM 1A.  RISK FACTORS  

You should carefully consider the following risk factors and all other information contained in this annual report in evaluating our business and prospects. The risks and uncertainties described below are not the only ones we face.Additional risks and uncertainties, other than those we describe below, that are not presently known to us or that we currently believe are immaterial may also impair our business operations. If any of the following risks occur, our business and financial results could be harmed. You should also refer to the other information contained in this annual report, including the Forward-Looking Statements section in Item 1, our consolidated financial statements and the related notes, and Management’s Discussion and Analysis of Financial Condition and Results of Operations for a further discussion of the risks, uncertainties and assumptions relating to our business. Except where the context otherwise indicates, references in this section to “we,” “our,” “ours,” and “us” includes our subsidiaries and our interest in Caliber.

The risks described below relating to oil and natural gas exploration, exploitation and development activities affect TUSA directly but also affect RockPile and Caliber because the materialization of those risks, whether experienced by TUSA or other customers or potential customers of RockPile or Caliber, may adversely affect demand for the products and services provided by RockPile and Caliber.

Risks Relating to Our Business

Oil and natural gas prices are volatile and change for reasons that are beyond our control. Decreases in the price we receive for our production adversely affect our business, financial condition, results of operations and liquidity.

Declines in the prices we receive for our production adversely affect many aspects of our business, including our financial condition, revenues, results of operations, liquidity, rate of growth, and the carrying value of our properties, all of which depend primarily or in part upon those prices. Declines in the prices we receive for our production also adversely affect our ability to finance capital expenditures, make acquisitions, raise capital, and satisfy our financial obligations. In addition, declines in prices reduce the amount of oil and natural gas that we can produce economically and the expected cash flows from that production and, as a result, adversely affect the quantity and present value of proved reserves. Among other things, a reduction in our reserves can limit the capital available to us, as the maximum amount of available borrowing under TUSA’s credit facility is, and the availability of other sources of capital likely will be, based to a significant degree on the estimated quantity and present value of those reserves, as discussed in greater detail below. Declines in prices may also reduce the demand for services provided by RockPile and Caliber. The price of oil fell dramatically in the second half of fiscal year 2015, from a high of $107.26 per barrel in June 2014 to a low of $26.68 per barrel in January 2016, in each case based on WTI prices. This decline adversely affected TUSA’s revenue and profitability, and also led to a significant reduction in drilling activity in North Dakota, which adversely affected the revenue and profitability of both RockPile and Caliber. Low commodity prices have persisted in the beginning of fiscal year 2017. If commodity prices remain low, we may be unable to maintain adequate liquidity, and our ability to meet our debt service and other obligations could be adversely affected.

Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Prices have historically been volatile and are likely to continue to be volatile in the future. The prices of oil and natural gas are affected by a variety of factors that are beyond our control, including changes in the global supply and demand for oil and natural gas, domestic and foreign governmental regulations and taxes, the level of global oil and natural gas exploration activity and inventories, the price, availability and consumer acceptance of alternative fuel sources, the availability of refining capacity, technological advances affecting energy consumption, weather conditions, speculative activity, civil or political unrest in oil and natural gas producing regions, financial and commercial market uncertainty, and worldwide economic conditions. The significant decline in the price of oil that occurred in calendar year 2014 was due to a number of causes outside of our control, including increased overall U.S. production, concerns regarding worldwide economic conditions and a decision by the Organization of Petroleum Exporting Countries not to curtail supply in order to rebalance global crude oil fundamentals.

In addition to factors affecting the price of oil and natural gas generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. Pricing can be influenced by, among other things, local or regional supply and demand factors (such as refinery or pipeline capacity issues, trade restrictions and governmental regulations) and the terms of our sales contracts. The prices we receive for our production are typically at a discount to the relevant benchmark prices on NYMEX. A negative difference between the benchmark price and the price received is called a differential. The differential may vary significantly due to market conditions, the quality and

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location of production, and other factors. Due to increasing production from the Williston Basin in recent years and limits to the available takeaway capacity and related infrastructure, the differential applicable to oil produced there has been significant. We cannot accurately predict future differentials, and increases in differentials could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, the difficulty involved in predicting the differential also makes it more difficult for us to effectively hedge our production.

Our planned operations may require additional capital that may not be available.

Our business is capital intensive and requires substantial expenditures to maintain currently producing wells, to make the acquisitions and conduct the exploration, exploitation and development activities necessary to replace our reserves, and to pay expenses and to satisfy our other obligations. In recent years, we have chosen to pursue projects that required capital expenditures substantially in excess of cash flows from operations. That fact has made us dependent on external financing. In addition, our existing asset base is small compared to many of our public company competitors, which may make financing more difficult. We anticipate that we will continue to make substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future and for future drilling programs. We cannot assure you that our cash flows from operations and other available sources of financing will be adequate for us to implement our capital plans and to satisfy our debt-related and other obligations. Debt or equity financing may not be available in a timely manner, on terms acceptable to us or at all. Moreover, future activities may require us to alter our capitalization significantly. Recent declines in commodity prices will likely make it more difficult or impossible for us to raise capital on acceptable terms. Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations and prospects.

TUSA’s lenders can limit the amount TUSA may borrow under its credit facility, which may materially impact our operations.

TUSA uses borrowings under its credit facility to fund its exploration, development, and acquisition activities and for other corporate purposes. At January 31, 2016, TUSA had $243.8 million outstanding under its credit facility, with a borrowing base of $350.0 million. On March 31, 2016, TUSA borrowed an additional $103.7 million under its credit facility, representing the entire amount remaining thereunder relative to the current borrowing base.

The borrowing base under TUSA’s credit facility is redetermined semi-annually on or about May 1 and November1 based upon a number of factors, including proved reserves growth and TUSA’s overall financial condition. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year upon ten days’ notice to the other party. Upon a redetermination, TUSA’s borrowing base could be substantially reduced. If the new borrowing base resulting from any regularly scheduled, semi-annual redetermination is less than the amount of outstanding indebtedness under the credit facility (which we refer to as a “borrowing base deficiency”), TUSA will be required to (i) pledge additional collateral, (ii) repay the principal amount of the loans in an amount sufficient to eliminate the excess, (iii) repay the excess in three equal monthly installments, or (iv) any combination of options (i) through (iii). In contrast, if a borrowing base deficiency results from an unscheduled redetermination, TUSA must immediately repay the excess and may not remedy such deficiency by pledging additional collateral or repaying the excess in installments. Recent declines in commodity prices make significant reductions of the borrowing base likely, and in light of the lenders’ right to implement two unscheduled borrowing base redeterminations annually, such reduction could occur with relatively little warning. Because TUSA’s credit agreement is effectively fully drawn, any reduction of the borrowing base would result in a borrowing base deficiency that TUSA would be required to remedy. A reduction in TUSA’s borrowing base could materially and adversely impact our liquidity, which would materially limit our exploration, development, and acquisition activities and adversely affect our operations and financial results.

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

We have significant outstanding indebtedness under TUSA’s 6.75% Senior Notes due 2022 (the “TUSA 6.75% Notes”), TUSA’s and RockPile’s credit facilities, and Triangle’s 5% convertible note issued to an affiliate of Natural Gas Partners in July 2012. A significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend upon our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial,

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business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flows from operations, or that future borrowings will be available to us under our credit facilities or otherwise, in an amount sufficient to fund our liquidity needsor to meet our debt service requirements.

The terms of certain of our debt agreements require us to comply with specified financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable.Should our indebtedness accelerate, we may lack sufficient funds to immediately repay such indebtedness and may be unable to refinance such indebtedness on commercially reasonable terms or at all.

In addition to making it more difficult for us to satisfy our debt service obligations, our substantial indebtedness could limit our ability to incur additional indebtedness if needed for other purposes, including working capital, capital expenditures, acquisitions and general corporate or other purposes, on satisfactory terms or at all. As a result, our indebtedness, and the terms of agreements governing that indebtedness, could increase our vulnerability to continued economic downturns and impair our ability to withstand sustained declines in commodity prices and limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

There is substantial doubt about our ability to continue as a going concern.

Our consolidated financial statements were prepared assuming we will continue as a going concern and further states that continued low commodity prices are expected to result in significantly lower levels of cash flow from operating activities in the future and have limited our ability to access capital markets, both of which raise substantial doubt about our ability to continue as a going concern.  Our inability to continue as a going concern could impair our ability to finance our operations through the sale of equity, incurring debt, or other financing alternatives, and depends upon aligning our sources of funding (debt and equity) with our expenditure requirements and repayment of debt as and when it becomes due. If we are unable to achieve these goals, our business would be jeopardized and the Company may not be able to continue and could potentially be forced to seek relief through a filing under the U.S. Bankruptcy Code.

We are evaluating a variety of strategic alternatives to improve our balance sheet, but there is no guarantee that any such alternatives can be effectuated on acceptable terms or at all.

Because our operating cash flows may be insufficient for us to meet our debt service requirements or pay principal on our indebtedness when due, we are evaluating a number of alternative measures to enhance our liquidity and improve our balance sheet. On March 24, 2016, we announced our retention of financial and legal advisors to assist us in evaluating our strategic alternatives. The strategies we are evaluating include modifying our operations; selling material assets or business segments; seeking additional financing; or refinancing, recapitalizing, or restructuring all or a portion of our existing debt.

These alternative measures may not be available on commercially reasonable terms or at all, may not be successful, and may not permit us to meet our scheduled debt service and other obligations. To the extent inadequate cash flow from operations and other available capital resources requires us to dispose of material assets or operations to meet our debt service and other obligations, we may not be able to consummate these dispositions for fair market value, in a timely manner, or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due. To the extent inadequate liquidity or other considerations require us to seek to restructure or refinance our debt, our ability to do so will depend on numerous factors, including many beyond our control, such as the condition of the capital markets and our financial condition at such time. Any refinancing or restructuring of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations.

Moreover, we cannot guarantee that any particular refinancing or restructuring alternatives, such as refinancing our existing indebtedness, extending the maturity dates of such indebtedness, or otherwise amending the terms thereof, would be sufficient or could be effectuated at all. If we are unable to service our debt and other obligations through cash flow from operations and are unable to effectuate one or more of the alternative measures and transactions we currently are evaluating, we may be required to reorganize the Company in its entirety and therefore cannot assure you that the Company

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will continue in its current state or that your investment in the Company will retain any value. A severe redetermination of the borrowing base under the TUSA credit facility could substantially increase this risk.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves.

The reserve data included in this report represent estimates only. Estimating quantities of proved oil and natural gas reserves is a complex process that requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes, availability of capital, estimates of required capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. The assumptions underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect, among other things, future estimates of our reserves, the economically recoverable quantities of oil and natural gas attributable to our properties, the classifications of reserves based on risk of recovery, and estimates of our future net cash flows.

At January 31, 2016, approximately 21% of our estimated net remaining proved reserves (Mboe) were proved undeveloped, or PUDs. Estimation of PUD reserves is almost always based on analogy to existing wells as contrasted with the performance data used to estimate producing reserves. Recovery of PUD reserves requires significant capital expenditures and successful drilling operations.

Additionally, SEC rules require that, subject to limited exceptions, PUD reserves may be recorded only if they relate to wells scheduled to be drilled within five years after the date of booking. This rule has limited and may continue to limit our potential to record additional PUD reserves as we pursue our drilling program. Moreover, we may be required to write-down our PUDs if we do not drill those wells within the required five-year time frame. Our PUD reserve estimates as of January 31, 2016 reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including currently estimated expenditures of approximately $100.9 million during the five years ending on January 31, 2021. You should be aware that this estimate of our development costs may not be accurate, development may not occur as scheduled, and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves.

You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing and success of development activities and related expenses, each of which is subject to numerous risks and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present value. In addition, our PV-10 and Standardized Measure estimates are based on assumed future prices and costs. Actual future prices and costs may be materially higher or lower than the assumed prices and costs. Further, the effect of derivative instruments is not reflected in these assumed prices. Also, the use of a 10% discount factor to calculate PV-10 and Standardized Measure may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business, and the oil and natural gas industry in general, are subject.

Our investments in oil and natural gas properties may result in impairments.

We follow the full cost method of accounting for oil and natural gas properties. Accordingly, all costs associated with the acquisition, exploration and development of oil and natural gas properties, including costs of undeveloped leasehold, geological and geophysical expenses, dry holes, leasehold equipment and other costs directly related to acquisition, exploration and development activities, are capitalized. Capitalized costs of oil and natural gas properties also include estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. The capitalized costs plus future development and dismantlement costs are depleted and charged to operations using the equivalent unit-of-production method based on proved oil and natural gas reserves as determined annually by an experienced petroleum engineer on our staff and audited by an independent petroleum engineering firm, and determined in interim quarterly periods by an experienced petroleum engineer on our staff. To the extent that such capitalized costs, net of their accumulated depreciation and amortization, exceed the sum of (i) the present value (discounting at 10% per annum) of estimated future net revenues from proved oil and natural gas reserves and (ii) the capitalized costs of unevaluated properties (both adjusted for income tax effects), such excess costs are charged to operations, which may have a material adverse effect on our business, financial condition and results of operations. We recognized such impairment expense in fiscal years 2012 and 2016 and, in the current low-price commodity market, we will likely incur additional impairments in fiscal year 2017. Once incurred, such a write-down of oil and natural gas properties is not reversible at a

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later date, even if oil or natural gas prices substantially increase or if estimated proved reserves substantially increase. There can be no assurance that that we will not recognize impairment expense in future periods.

Much of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could have a material adverse effect on our future oil and natural gas reserves and production and, therefore, our future cash flows and income.

Much of our net leasehold acreage is undeveloped acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive within specified periods of time, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. We intend to develop our leasehold acreage by implementing our exploration and development plan, but the funds needed to do so may not be available and our exploration and development activities may be unsuccessful. Our future oil and natural gas reserves and production, and therefore our future cash flows and income, are highly dependent on our success in developing our undeveloped leasehold acreage.

Oil and natural gas exploration, exploitation and development activities may not be successful and could result in a complete loss of a significant investment.

Exploration, exploitation and development activities are subject to many risks. For example, new wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. In addition, a productive well may become commercially unproductive in the event that water or other deleterious substances are encountered which impair or prevent the commercial production of oil and natural gas from the well. Similarly, decline rates from a productive well may exceed our estimates and may cause the well to become uneconomic. We engage in exploratory drilling, which increases these risks. Drilling for oil and natural gas often involves unprofitable efforts as a result of dry holes or wells that are productive but do not produce sufficient oil or natural gas to return a profit at then-realized prices after deducting drilling, operating and other costs. Moreover, even profitable development activity may be less successful than we, investors or analysts expect, potentially resulting in a decline in the market value of our securities. Cost-related risks are exacerbated in the Williston Basin because the drilling and completion of a well there generally costs significantly more than a typical onshore conventional well. The currently prevailing lower commodity price environment may reduce certain of these costs. However, TUSA may not be able to achieve the cost savings it anticipates. Moreover, RockPile, as a provider of completion services, will have its revenue and profitability reduced by cost reductions demanded by its customers. In addition, our exploration, exploitation and development activities may be curtailed, delayed or canceled as a result of numerous factors, including:

· title problems;

· problems in delivery of our oil and natural gas to market;

· pressure or irregularities in geological formations;

· equipment failures or accidents;

· adverse weather conditions;

· reductions in oil and natural gas prices;

· compliance with environmental and other governmental requirements, including with respect to permitting issues; and

· costs of, or shortages or delays in the availability of, drilling rigs, equipment, qualified personnel and services.

We expect that nearly all of the wells we drill in the Williston Basin will be drilled horizontally and will be hydraulically fractured. When drilling horizontal wells, the risks we face include, but are not limited to, failing to place our wellbore in the desired target producing zone, not staying in the desired drilling zone while drilling horizontally through the formation, failing to run casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks we face while completing such wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, failing to run tools the entire length of the wellbore during completion operations, and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. Because of the cost typically associated with this type of well, unsuccessful exploration or development activity affecting even a small number of these wells could have a significant impact on our results of operations.

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We may not realize the benefits of integrating acquired properties.

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

Acquisitions may prove to be unprofitable because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our recent growth is due in large part to acquisitions of undeveloped leasehold interests and the drilling and completion of productive wells. We expect acquisitions may also contribute to our future growth, subject to the availability of capital to pursue such acquisitions. However, our access to additional capital maybe highly constrained in light of prevailing economic conditions and commodity prices and other factors. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In addition, many of these factors are subject to change and are beyond our control. In particular, the prices of and markets for oil and natural gas products may change from those anticipated at the time such assessments are made. In connection with our assessment of a potential acquisition, we perform a review of the acquired properties that we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems, and generally will not involve a review of seismic data or independent environmental testing. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their capabilities and deficiencies, including any structural, subsurface and environmental problems that may exist or arise. As a result, we may assume unknown liabilities that could have a material adverse effect on our business, financial condition and results of operations.

We may be unable to successfully acquire additional leasehold interests or other oil and natural gas properties, which may inhibit our ability to grow our production.

Acquisitions of leasehold interests or other oil and natural gas properties have been an important element of our business, and we will continue to pursue acquisitions in the future. In recent years, we have pursued and consummated leasehold or other property acquisitions that have provided us opportunities to expand our acreage position and grow our production. Although we regularly engage in discussions and submit proposals regarding leasehold interests or other oil and natural gas properties, suitable acquisitions may not be available in the future on reasonable terms, or we may not possess sufficient capital to consummate attractive acquisitions.

Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned.

Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations.

We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, midstream constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, and other factors. Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential well locations.In addition, the

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number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. If these third parties are unwilling to pool their interests with ours, and we are unable to require such pooling on a timely basis or at all, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified. Further, our inventory of drilling projects includes locations in addition to those that we currently classify as proved. The development of and results from these additional projects are more uncertain than those relating to proved locations.

No assurance can be given that defects in our title to oil and natural gas interests do not exist.

It is often not possible to determine title to an oil and natural gas interest without incurring substantial expense. The title review processes we have conducted with respect to certain interests we have acquired may not have been sufficient to detect all potential defects, and we have not conducted such a process with respect to all our properties. If a title defect does exist, it is possible that we may lose all or a portion of our interest in the properties to which the title defect relates. Our actual interest in certain properties may therefore vary from our records.

The results of our planned drilling in the Bakken Shale and Three Forks formations are subject to more uncertainties than drilling programs in more established formations and may not meet our expectations for production.

Part of our drilling strategy to maximize recoveries from the Bakken Shale and Three Forks formations involves the drilling of horizontal wells using completion techniques that have proven to be successful for other companies in these and other shale formations. Our experience with horizontal drilling in the Bakken Shale and Three Forks formations, like that of the industry in general, is limited. The ultimate success of these drilling and completion strategies and techniques in these formations will be better evaluated over time as more wells are drilled and longer-term production profiles are established. In addition, the decline rates in these formations may be higher than in other areas and in other shale formations, making overall production difficult to estimate until our experience in these formations increases. Accordingly, the results of our future drilling in the Bakken Shale and Three Forks formations are more uncertain than drilling results in some other formations with more established reserves and longer production histories. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in resource constrained plays such as the Williston Basin.

If our drilling results are less favorable than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, lack of access to gathering systems and takeaway capacity or otherwise, or oil and natural gas prices decline further, the return on our investment in these areas may not be as attractive as we anticipate, and we could incur material write-downs of properties and the value of our undeveloped acreage could decline.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use independent contractors to provide us with technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of oilfield services, to drill and develop certain of our prospects to production. In addition, we rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these operators and service providers, any inability on our part to maintain satisfactory commercial relationships with them, or their failure to provide quality services could materially and adversely affect our business, financial condition, and results of operations.

Our agreements with operators and other joint venture partners, as well as other operational agreements that we may enter into, present a number of challenges that could have a material adverse effect on our business, financial condition or results of operations.

Our agreements with well operators and other joint venture partners, as well as other operational agreements (including agreements with mineral rights owners and suppliers of services, equipment and product transportation), represent a significant portion of our business. In addition, as part of our business strategy, we plan to enter into other similar transactions, some of which may be material. These transactions typically involve a number of risks and present financial, managerial and operational challenges, including the existence of unknown potential disputes, liabilities or contingencies that arise after entering into these arrangements related to the counterparties to such arrangements. We could

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experience financial or other setbacks if we encounter unanticipated problems in connection with such transactions, including problems related to execution or integration. In addition, low commodity prices and other unfavorable economic conditions may impair our partners’ ability to perform under their agreements with us or to continue operations at all.Any of these risks could reduce our revenues or increase our expenses, which could adversely affect our business, financial condition or results of operations. 

We may experience an increase in non-consenting working interest owners in our operated wells.

Our exploration and development agreements contain customary industry non-consent provisions. Pursuant to these provisions, if we, as operator, propose a well to be drilled and completed and a working interest owner elects not to participate, we assume the non-participating working interest owners’ share of the costs of such well. As a penalty for not participating, the portion of the well’s revenues that would otherwise would go to the non-participant flow to us until we receive from 150% to 300% of the capital that we provided to cover the non-participant's share. We have historically viewed non-consents by other working interest owners in our operated wells favorably as it has the effect of increasing our interest in our operated wells, despite the additional capital outlay. However, in the current depressed commodity pricing environment, we could experience a significant increase in the number of non-consenting working interest owners that either do not have the capital to participate or choose not to participate at current commodity prices. In either case, we would be required to assume their portion of the well’s expenses. The potential for such an increase makes it difficult to accurately predict our fiscal year 2017 capital expenditures and could require us to redirect capital budgeted for other expenditures. Because these requirements cannot be forecasted precisely, we cannot guarantee that we will have sufficient liquidity to satisfy the increased capital demands associated with the exercise of non-consent provisions by other working interest owners.Further, redirecting capital to fund the expenses of non-participating working interest owners in our operated wells could cause us to non-consent in wells that we do not operate, and such wells may prove more successful than our operated wells.

We cannot control the activities on the properties we do not operate and are unable to ensure their proper operation and profitability.

Other companies’ operated properties represent a portion of our production. We have limited ability to exercise influence over, or control the risks associated with, operations of our non-operated properties. The failure of an operator of our non-operated wells to adequately perform operations, an operator’s breach of the applicable agreements, or an operator’s failure to act in our best interests could reduce our production and revenues. The success and timing of drilling and development activities on properties operated by others depends upon a number of factors outside of our control, including the operator’s expertise and financial resources, inclusion of other participants in drilling wells, and use of technology. In addition, we could be adversely affected by our lack of control over the timing and amount of capital expenditures related to non-operated properties.

We are subject to complex laws and regulations, including environmental laws and regulations that can adversely affect the cost, manner and feasibility of doing business and limit our growth.

Our operations and facilities are subject to extensive federal, state, local and foreign laws and regulations relating to exploration for, and the exploitation, development, production and transportation of, oil and natural gas, as well as environmental, safety and other matters. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, may harm our business, results of operations and financial condition. Laws and regulations applicable to us include those relating to:

· land use restrictions;

· drilling bonds and other financial responsibility requirements;

· spacing of wells;

· emissions into the air;

· unitization and pooling of properties;

· habitat and endangered species protection;

· environmental, reclamation, and remediation obligations;

· the management and disposal of hazardous substances, oil field waste and other waste materials;

· the use of underground and above-ground storage tanks;

· transportation and drilling permits;

· the use of underground injection wells;

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· safety precautions;

· hydraulic fracturing (including limitations on the use of this technology);

· the prevention of oil spills;

· the closure of production facilities;

· operational reporting; and

· taxation and royalties.

Under these laws and regulations, we could be liable for:

· personal injuries;

· property and natural resource damages;

· releases or discharges of hazardous materials;

· well reclamation costs;

· oil spill clean-up costs;

· other remediation and clean-up costs;

· plugging and abandonment costs;

· governmental sanctions, such as fines and penalties; and

· other environmental damages.

These regulations have been changed frequently in the past and, in general, these changes have imposed more stringent requirements that have increased operating costs and required capital expenditures to remain in compliance. For example, in 2013, North Dakota, the primary state in which we conduct operations, amended its regulations to impose more stringent regulation of hydraulic fracturing, the disclosure of chemicals used in hydraulic fracturing and more rigorous regulation of pits. Any noncompliance with these laws and regulations could subject us to material administrative, civil, or criminal penalties or other liabilities, including suspension or termination of operations. Some environmental laws and regulations impose strict liability, under which we could be exposed to liability for clean-up costs and other damages for conduct that was not negligent and was lawful at the time it occurred, or for the conduct of prior owners or operators of properties we have acquired or other third parties, including, in some circumstances, operators of properties in which we have an interest and parties that provide transportation services for us. Similarly, some environmental laws and regulations impose joint and several liability, under which we could be held responsible for more than our proportionate share of liability for site remediation or other obligations, and potentially the entire obligation, even where other parties also have liability. In addition, we may be required to make large and unanticipated capital expenditures to comply with applicable laws and regulations, for example by installing and maintaining pollution control devices. Further, our plugging and abandonment obligations will be substantial and may exceed our estimates. Our operations could also be adversely affected by environmental and other laws and regulations that require us to obtain permits before commencing drilling or other activities. Even when permits are granted in a timely manner, they may be subject to conditions that impose delays on a project, increase its costs or reduce its benefits to us.

In addition, any changes in applicable laws, regulations and/or administrative policies or practices may have a negative impact on our ability to operate and on our profitability. The laws, regulations, policies or current administrative practices of any government body, organization or regulatory agency in the United States or any other jurisdiction in which we operate may be changed, applied or interpreted in a manner that could fundamentally alter our ability to carry on our business or otherwise adversely affect our results of operations and financial condition.

Caliber’s operations may be subject to additional regulatory risks. For example, in the future its pipelines may be subject to siting, public necessity, rate and service regulations by FERC or various state regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas, NGLs and crude oil in interstate commerce. FERC’s actions in any of these areas or modifications of its current regulations could adversely impact Caliber’s ability to compete for business, the costs it incurs in its operations, the construction of new facilities or its ability to recover the full cost of operating its pipelines. Other laws and actions by federal and state regulatory authorities could have similar effects on Caliber’s operations. For example, North Dakota adopted new regulations in December 2013 requiring operators to submit data to the state to track construction and reclamation of pipelines, and to track pipeline locations for surface owners.

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Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for, or responding to, those effects.

Climate change has emerged as an important topic in public policy debate. It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in GHGs. Products produced by the oil and natural gas exploration and production industry are a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting and release of fugitive emissions of natural gas could have a significant impact on our future operations. The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to regulate GHG emissions under existing provisions of the federal Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered and may in the future consider “cap and trade” legislation that would establish an economy-wide cap on GHG emissions in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. Any laws or regulations that may be adopted to restrict or reduce GHG emissions would likely require us to incur increased operating costs and could have an adverse effect on demand for our production. These or future federal, state, regional or international monitoring or regulatory requirements relating to climate change could require us to obtain permits or allowances for our GHG emissions, install new pollution controls, increase our operational costs, limit our operations or adversely affect demand for the oil and natural gas we produce. See Item 1. Business – Governmental Regulation - Air Emissions and Climate Change for further discussion.

Many scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting services or infrastructure provided to us by other parties. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change and, as a result, this could have a material adverse effect on our business, financial condition and results of operations.

Hydraulic fracturing has recently come under increased scrutiny and could be the subject of further regulation, which could impact the timing and cost of development, as well as our investment in RockPile.

As discussed above in Item 1. Business – Governmental Regulation - Regulation of Hydraulic Fracturing, the regulatory landscape regarding hydraulic fracturing remains in flux. Depending on the legislation or regulations that ultimately may be adopted, exploration and production activities that employ hydraulic fracturing could be restricted or subject to additional regulation and permitting requirements. Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs for TUSA and RockPile, and could result in additional burdens that could increase the costs and delay or curtail the development of unconventional oil and natural gas resources from shale formations that are not commercially viable without hydraulic fracturing. Further, commercially prohibitive costs or a prohibition or moratorium on hydraulic fracturing in the areas in which RockPile operates could result in a complete loss of our investment in RockPile. As a result, such legislation or regulation could have a material adverse effect on our business, financial condition and results of operations.

The sale of our oil and natural gas production depends in part on gathering, transportation and processing facilities and services. Any limitation in the availability of, or our access to, those facilities or services would interfere with our ability to market the oil and natural gas that we produce and could adversely impact our drilling program, cash flows and results of operations.

We deliver oil and natural gas that may ultimately flow through gathering, processing and pipeline systems that Caliber does not own. The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering, processing and pipeline systems. In particular, natural gas produced from the Bakken Shale has a high Btu content that requires natural gas processing to remove the natural gas liquids before it can be redelivered into transmission pipelines. Industry-wide in the Williston Basin, there is currently a shortage of natural gas gathering and processing capacity. Such shortage has limited our ability to sell our natural gas production. In addition, the use of alternative forms of transportation for oil production, such as trucks or rail, involve risks as well. For example, recent and well-publicized accidents involving trains delivering crude oil could result in increased levels of regulation and transportation costs.

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The lack of available capacity in any of the gathering, processing and pipeline systems we use could result in our inability to realize the full economic potential of our production or in a reduction of the price offered for our production and could force us to reduce production in some circumstances. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities or any changes in regulatory requirements, could harm our business and, in turn, our financial condition, results of operations and cash flows.

Furthermore, weather conditions or natural disasters, actions by companies doing business in the areas in which we operate, or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to conduct our operations.

Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely and cost-effective manner.

Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and gas, which could have an adverse effect on our business, financial condition and results of operations.

Moreover, new environmental initiatives and regulations could include restrictions on disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. Compliance with environmental regulations and permit requirements for the withdrawal, storage and use of surface water or ground water necessary for hydraulic fracturing of our wells may increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

Constraints in the supply of, prices for, and availability of transportation of raw materials can have a material adverse effect on RockPile’s business.

High levels of demand for, or a shortage of, raw materials used in hydraulic fracturing operations, such as proppants, can trigger constraints in RockPile’s supply chain of those raw materials. Many of the raw materials essential to its business require the use of rail, storage, and trucking services to transport the materials to its jobsites. These services, particularly during times of high demand, may cause delays in the arrival of, or otherwise constrain its supply of, raw materials. These constraints could have a material adverse effect on RockPile’s business. In addition, price increases imposed by its vendors for such raw materials and the inability to pass these increases through to its customers could have a material adverse effect on RockPile’s business. Our other operations may be similarly adversely affected by shortages of these raw materials.

Growing Caliber’s business by constructing new pipelines and other infrastructure subjects it to construction risks and will require it to obtain rights of way at a reasonable cost. Such projects may not be profitable if costs are higher, or demand is less, than expected.

Caliber intends to grow its business through the construction of pipelines, treatment/processing facilities and other midstream infrastructure. The construction of this infrastructure requires significant amounts of capital, which may exceed our expectations and may exceed the capital available in the market place, and will involve numerous regulatory, environmental, political and legal uncertainties and stringent, lengthy and occasionally unreasonable or impractical federal, state and local permitting, consent, or authorization requirements. As a result, new infrastructure may not be constructed as scheduled or as originally designed, which may require redesign and additional equipment, relocations of facilities or rerouting of pipelines, which in turn could subject Caliber to additional capital costs, additional expenses or penalties and may adversely affect Caliber’s operations. In addition, the coordination and monitoring of these projects requires skilled and experienced labor.Agreements with Caliber’s producer customers may contain substantial financial penalties and give the producers the right to terminate their contracts if construction deadlines are not achieved. Moreover, Caliber’s revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if Caliber builds a new pipeline, the construction may occur over an extended period of time, and Caliber may not receive any material increases in revenues until after completion of the project, if at all.

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In addition, the construction of pipelines and other infrastructure may require Caliber to obtain rights-of-way or other property rights prior to construction. Caliber may be unable to obtain such rights-of-way or other property rights at a reasonable cost. If the cost of obtaining new or renewing rights-of-way or other property rights increases, it would adversely affect Caliber’s operations.

Furthermore, Caliber may have limited or no commitments from customers relating to infrastructure projects prior to their construction. If Caliber constructs facilities to capture anticipated future growth in production or satisfy anticipated market demand that does not materialize, the facilities may not operate as planned or may not be used at all. Caliber may rely on estimates of proved reserves in deciding to construct new pipelines and facilities, and those estimates may prove to be inaccurate because of the numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new infrastructure projects may be unprofitable.

We do not insure against all potential operating risk. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our operations.

Our operations are subject to the risks normally incident to the operation and development of oil and natural gas properties, the drilling of oil and natural gas wells, hydraulic fracturing and the provision of related services including:

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other substances into the environment, including groundwater;

abnormally pressured formations;

fires and explosions;

personal injuries and death;

regulatory investigations and penalties;

well blowouts;

pipeline failures and ruptures;

casing collapse;

mechanical and operational problems that affect production; and

natural disasters.

We do not maintain insurance against all such risks. We generally elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Also, certain risk events may not be detected or detectable within the period during which notice must be provided under the applicable insurance policy. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations.

Our lack of geographic diversification may increase the risk of an investment in us.

Our current business focus is on the oil and natural gas industry in a limited number of properties in North Dakota and Montana. RockPile and Caliber also focus on the Williston Basin areas of those states; although, both companies recently began exploring opportunities in other basins. Larger companies have the ability to manage their risk by diversification. However, we currently lack diversification in terms of the geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified, and this may increase our risk profile.

We face strong competition from other companies.

We encounter competition from other companies involved in the oil and natural gas industry in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies. Many of our competitors have been engaged in the oil and natural gas business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory projects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry, particularly in the Bakken Shale and Three Forks formations on which we

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focus. Such competitors may also be in a better position to secure oilfield services and equipment on a timelier basis or on more favorable terms. We may not be able to conduct our operations, evaluate and select suitable properties, and consummate transactions successfully in this highly competitive environment, which could adversely affect our business, financial condition, results of operations and prospects. Similarly, the market for RockPile’s services and products is characterized by continual technological developments to provide better and more reliable performance and services. If RockPile is not able to design, develop, and produce commercially competitive products, and to implement commercially competitive services in a timely manner in response to changes in technology, its business could be materially and adversely affected.

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling and completion activities.

Our operations could be adversely affected by weather conditions. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Severe weather conditions limit and may temporarily halt operations during such conditions. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and state transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment during certain periods, thereby reducing activity levels. Similarly, any drought or other condition resulting in a shortage or the unavailability of adequate supplies of water would impair our ability to conduct hydraulic fracturing operations. These constraints, and resulting shortages or cost increases, could delay or temporarily halt our oil and natural gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

If we are unable to retain or recruit qualified managerial, operations and field personnel, we may not be able to continue our operations.

Our success depends to a significant extent upon the continued services of our directors and officers and that of key managerial, operational, land, finance, legal and accounting staff. In order to successfully implement and manage our business plan, we will be dependent upon, among other things, successfully recruiting qualified managerial and field personnel having experience in required aspects of our business. Competition for qualified individuals is intense. We cannot assure you that we will be able to retain existing employees or that we will be able to find, attract and retain qualified personnel on acceptable terms.The uncertainties resulting from low commodity prices, the associated pressure on our balance sheet, and our ongoing evaluation of strategic alternatives to manage these challenges may make it increasingly difficult for us to retain and attract qualified personnel or increase the cost of doing so.

On March 24, 2016, we announced the departure of our former Chief Financial Officer, Justin Bliffen, who resigned effective March 21, 2016.

We have restated our financial statements in the past and may be required to do so in the future.

The preparation of financial statements in accordance with GAAP involves making estimates, judgments, interpretations and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and income.These estimates, judgments, interpretations and assumptions are often inherently imprecise or uncertain, and any necessary revisions to prior estimates, judgments, interpretations or assumptions could lead to a restatement of our financial statements. Any such restatement or correction may be highly time consuming, may require substantial attention from management and significant accounting costs, may result in adverse regulatory actions by the SEC or NYSE MKT, may result in stockholder litigation, may cause us to fail to meet our reporting obligations, and may cause investors to lose confidence in our reported financial information, leading to a decline in our stock price.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

President Obama has proposed changes to U.S. tax laws that would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies, including by (i) repealing the percentage depletion allowance for oil and natural gas wells, (ii) eliminating current deductions for intangible drilling and development costs, (iii) eliminating the deduction for certain domestic production activities, and (iv) extending the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any

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similar changes in U.S. federal income tax laws could increase the cost of exploration and development of natural gas and oil resources. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Our business could be negatively impacted by cybersecurity risks and other disruptions.

As an oil and natural gas producer, we face various security threats, including possible attempts by third parties to gain unauthorized access to sensitive information, or to render data or systems unusable, through unauthorized computer access, threats to the safety of our employees, and threats to the security of our infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines. Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, face similar threats, including with respect to sensitive information of ours. There can be no assurance that the procedures and controls we or our business partners use to monitor these threats and mitigate exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, and cash flows.

Aboriginal claims could have an adverse effect on us and our operations.

Aboriginal peoples have claimed aboriginal title and rights to portions of Montana where we operate. We are not aware that any claims have been made in respect to our property or assets in Montana or North Dakota. However, if a claim arose and was successful, it could have an adverse effect on us and our business operations, financial conditions or prospects.

Certain stockholders have significant influence on our major corporate decisions, including control over some matters that require stockholder approval, and could take actions that could be adverse to stockholders.

In connection with the issuance and sale to NGP Triangle Holdings, LLC (“NGP”) in July 2012 of our 5% convertible note with an initial principal amount of $120.0 million (the “Convertible Note”), we entered into an Investment Agreement with NGP and its parent company. Pursuant to the Investment Agreement, NGP is entitled to designate one director to our board of directors until the occurrence of a “Termination Event” (as defined in the Investment Agreement). The Investment Agreement further provides that, for so long as at least 50% of the original principal amount is outstanding and held by NGP, we will not take certain actions without the prior written consent of NGP. In addition, pursuant to the Convertible Note, for so long as at least 50% of the original principal amount is outstanding and held by NGP, we have agreed to (i) obtain the prior written consent of NGP before submitting certain resolutions or matters to a vote of the stockholders, or (ii) require the approval of stockholders as would be required to approve such resolution or matter if the then-outstanding Convertible Note held by NGP had been converted into shares of common stock immediately prior to the record date for such meeting of stockholders and NGP had voted all of such shares of common stock against such resolution or matter. The Convertible Note is convertible into shares of common stock at an initial conversion price of $8.00 per share, which, based on the initial principal amount, would allow the Convertible Note to be converted into 15,000,000 shares of common stock plus any shares issuable upon the conversion of accrued interest, which is paid-in-kind by adding to the principal balance on a quarterly basis.

In March 2013, we sold to two affiliates of NGP an aggregate of 9,300,000 shares of our common stock in a private placement (the “NGP Private Placement”). In connection with the NGP Private Placement, we entered into an amendment to the Investment Agreement to modify the definition of “Termination Event,” thereby strengthening NGP’s board seat designation right.As of April 1, 2016, NGP’s affiliates collectively held (i) 9,300,000 shares of our outstanding common stock and (ii) the Convertible Note with an outstanding principal balance of approximately $144.0 million. If NGP had fully converted the Convertible Note on March 31, 2016, NGP and its affiliates would have collectively held approximately 29% of our outstanding shares of common stock on that date. As a result of the Investment Agreement, as amended, and NGP’s current and potential holdings of our common stock, NGP has significant influence over us, our management, our policies, and certain matters requiring stockholder approval.

Further, in August 2013, we sold to ActOil Bakken, LLC (“ActOil”) 11,350,000 shares of our common stock in a private placement. As of March 31, 2016, ActOil held approximately 14.9% of our outstanding shares of common stock.

The interests of NGP and its affiliates, including in NGP’s capacity as a creditor, and ActOil may differ from the

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interests of our other stockholders, and the ability of NGP and ActOil to influence certain of our major corporate decisions may harm the market price of our common stock by delaying, deferring or preventing transactions that are in the best interest of all stockholders or discouraging third-party investors.

Our limited partner interest in Caliber may be diluted.

In October 2012, a wholly-owned subsidiary of ours participated in the formation of Caliber, a joint venture with FREIF to provide crude oil, natural gas, and water transportation and related services to us and third-parties primarily in the Williston Basin. In connection with its investment in Caliber, our subsidiary received an initial 30% percent limited partner interest, as well as warrants to purchase additional limited partner interests at specified prices, trigger units, and trigger warrants. Based on initial anticipated funding commitments by the joint venture partners, full exercise and vesting of our warrants, trigger units, and trigger warrants would cause our ownership to increase to a 50% limited partner interest.

In September 2014, FREIF committed to providing an anticipated additional $80.0 million to Caliber in return for 8,000,000 limited partner units. The associated amendment to the joint venture agreement resulted in our 4,000,000 trigger units vesting and converting to limited partner units. FREIF and our subsidiary received the 8,000,000 and 4,000,000 limited partner units, respectively, on June 30, 2014. Following the conversion of our 4,000,000 trigger units and the issuance of 8,000,000 limited partner units to our joint venture partner, our limited partner interest in Caliber increased to 32%.

In February 2015, FREIF contributed an additional $34.0 million to Caliber in exchange for 2,720,000 limited partner units, which diluted our limited partner interest to 28.3%. In conjunction with the contribution, we received warrants to purchase an additional 3,626,667 limited partner units, and FREIF received warrants to purchase an additional 906,667 limited partner units. On a fully-diluted basis, assuming the exercise of all outstanding warrants and no further capital contributions, we and FREIF would each hold a 50% percent limited partner interest in Caliber.

We will be unable to increase our limited partner interest above 28.3% absent a cashless exercise of our warrants or a direct capital outlay to exercise our warrants or commit additional partnership approved capital. Further, if FREIF makes a partnership approved capital contribution and we choose not to invest additional capital in the joint venture, or if FREIF exercises its warrants and we do not exercise our warrants, we would be diluted below our 28.3% limited partner interest.

We do not control Caliber.

Caliber is managed and governed by its general partner, Caliber Midstream GP, LLC, of which FREIF and Triangle each own a 50% non-economic interest and share governance equally. Because we do not hold a controlling interest in Caliber, we do not have the ability to direct the activities of Caliber that most significantly impact Caliber’s growth and economic performance. If we and the other general partner disagree on significant matters relating to Caliber, such an impasse could adversely affects Caliber’s prospects and our investment therein.

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

We use derivatives for a portion of our crude oil production to reduce exposure to adverse fluctuations in prices of crude oil and to achieve more predictable cash flows. These arrangements expose us to the risk of financial loss in some circumstances, including when sales are different than expected, when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive, or if the counterparty to the derivative contract were to default on its contractual obligations.

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

Additionally, the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, among other things, imposes restrictions on the use and trading of certain derivatives, including energy derivatives. The nature

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and scope of those restrictions is in the process of being determined in significant part through implementing regulations adopted by the SEC, the Commodities Futures Trading Commission and other regulators. If, as a result of the Dodd-Frank Act or its implementing regulations, capital or margin requirements or other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy. In particular, a requirement to post cash collateral in connection with our derivative positions would likely make it impracticable to implement our current hedging strategy. In addition, requirements and limitations imposed on our derivative counterparties could increase the costs of pursuing our hedging strategy.

Unrelated to our hedging activities with respect to crude oil prices, we hold warrants in Caliber that are classified as derivatives. For so long as such warrants remain outstanding, we will be required to estimate their fair market value on a quarterly basis. We currently use a modified market approach and Black-Scholes option pricing model to value the warrants. The associated model is based on several assumptions about future events. While we believe that our model and underlying assumptions are reasonable, there can be no assurance that the assumptions will ultimately prove to be accurate or that our model is the best model for valuing the warrants. If the model and underlying assumptions are flawed, then our accounting for the warrants may not reflect their true value.

Our remaining commodity derivatives were entered into during a depressed commodity pricing environment.

The last of our commodity derivative contracts entered into before the dramatic decline in oil prices beginning in the second half of fiscal year 2015 expired by December 31, 2015. As of January 31, 2016, we had commodity derivative swap contracts for 2,175 Bbl/d with a weighted average price of $56.13 for fiscal year 2017 and commodity derivative swap contracts for 2,745 Bbl/d with a weighted average price of $53.36 for fiscal year 2018 (in each case NYMEX). These swap contracts were entered into during a depressed commodity pricing environment and cover only a small portion of our anticipated production during those future periods. Further, crude oil production and sales for fiscal year 2019 and beyond may be largely unhedged, or hedged at depressed prices, which will expose us to continued volatility in crude oil market prices, whether favorable or unfavorable.

Risks Relating to Our Common Stock

The market price for our common stock may be highly volatile.  

The market price for our common stock may be highly volatile and could be subject to wide fluctuations. Some of the factors that could negatively affect such share price include:

· changes in oil and natural gas prices;

· actual or anticipated fluctuations in our quarterly results of operations;

· liquidity;

· adverse redetermination of the borrowing base under the TUSA credit facility, which would reduce our liquidity;

· non-compliance with financial covenants under our debt facilities;

· sales of common stock by our stockholders, directors, and officers;

· changes in our cash flows from operations or earnings estimates;

· publication of research reports about us or the oil and natural gas exploration and production industry generally;

· increases in market interest rates which may increase our cost of capital;

· changes in applicable laws or regulations, court rulings, and enforcement and legal actions;

· changes in market valuations of similar companies;

· adverse market reaction to any indebtedness we incur in the future;

· additions or departures of key management personnel;

· actions by our stockholders;

· commencement of or involvement in litigation;

· news reports relating to trends, concerns, technological or competitive developments, regulatory changes and other related issues in our industry, including adverse public sentiment regarding hydraulic fracturing;

· speculation in the press or investment community regarding our business;

· general market and economic conditions; and

· domestic and international economic, legal and regulatory factors unrelated to our performance.

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Financial markets have recently experienced significant price and volume fluctuations that have affected the market prices of securities that have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of the companies issuing those securities. Accordingly, the market price of our common stock may decline even if our results of operations, underlying asset values or prospects improve or remain consistent.

Future sales or other issuances of our common stock could depress the market for our common stock.

We may seek to raise additional funds through one or more public or private offerings of our common stock, in amounts and at prices and terms to be determined at the time of the offering. We may also use our common stock as consideration to make acquisitions, including acquisitions of additional leasehold interests. Any issuances of large quantities of our common stock could reduce the price of our common stock. In addition, to the extent that we issue equity securities to fund our business plan, our existing stockholders’ ownership will be diluted.

Issuances, or the availability for sale, of substantial amounts of our common stock could adversely affect the value of our common stock.

No prediction can be made as to the effect, if any, that future issuances of our common stock, or the availability of common stock for future sales, will have on the market price of our common stock. Sales of substantial amounts of our common stock in the public market and the availability of shares for future sale, including by one or more of our significant stockholders or shares of our common stock issuable upon exercise of outstanding options to acquire shares of our common stock, could adversely affect the prevailing market price of our common stock. This in turn would adversely affect the fair value of our common stock and could impair our future ability to raise capital through an offering of our equity securities.

The potential future issuance of preferred stock may not enhance stockholder value.

Our Certificate of Incorporation authorizes our Board of Directors to issue preferred stock without stockholder approval. Shares of preferred stock could be issued in a financing in which investors purchase preferred stock with rights, preferences and privileges that may be superior to those of our common stock. We could also use the preferred stock for potential strategic transactions, including, among other things, acquisitions, strategic partnerships, joint ventures, restructurings, business combinations and investments. We cannot provide assurances that any such transactions will be consummated on favorable terms or at all, that they will enhance stockholder value, or that they will not adversely affect our business or the trading price of the common stock. Further, the existence of outstanding preferred stock may make us a less attractive candidate for third party acquirers.

In the past, we have not paid dividends on our common stock and do not anticipate paying dividends on our common stock in the foreseeable future.

In the past, we have not paid dividends on our common stock and do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock, as we intend to use cash flows generated by operations to develop our business. Any future determination to pay cash dividends will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations, capital requirements, limits imposed by our debt agreements, and such other factors as our board of directors deems relevant.

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

We are subject to Section 203 of the Delaware General Corporation Law, which generally prohibits certain business combination transactions between a corporation and an “interested stockholder” within three years of the time such stockholder became an interested stockholder, absent, in most cases, board or stockholder approval. An “interested stockholder” is any person who, together with affiliates and associates, is the owner of 15% or more of the outstanding voting stock of the corporation, and the term “business combination” encompasses a wide variety of transactions with or caused by an interested stockholder, including mergers, asset sales and other transactions in which the interested stockholder receives a benefit on other than a pro rata basis with other stockholders. Although a corporation can opt out of Section 203 in its certificate of incorporation, we have not done so.Section 203 may have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including by discouraging takeover attempts that might result in a premium being paid over the then-current market price of our common stock and that might be supported by a majority of our stockholders.

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ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

The information required by Item 2. Properties is contained in Item 1. Business of this annual report.

ITEM 3.  LEGAL PROCEEDINGS

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of 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 legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on our business, financial condition or operating results.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common stock is traded on the NYSE MKT under the symbol “TPLM”.The table below sets forth the intraday high and low sales prices for our common stock in each quarter of the last two fiscal years:

	Fiscal Year 2016
	High		Low
February 1, 2015 to April 30, 2015	$	6.49	$	4.56
May 1, 2015 to July 31, 2015	$	6.00	$	3.36
August 1, 2015 to October 31, 2015	$	4.09	$	1.08
November 1, 2015 to January 31, 2016	$	1.47	$	0.35

	Fiscal Year 2015
	High		Low
February 1, 2014 to April 30, 2014	$	10.10	$	6.96
May 1, 2014 to July 31, 2014	$	12.48	$	9.05
August 1, 2014 to October 31, 2014	$	12.14	$	6.75
November 1, 2014 to January 31, 2015	$	8.10	$	3.10

Holders

Our 76,232,614shares of common stock outstanding at April 4, 2016 were held by 17 stockholders of record. The number of holders was determined from the records of our transfer agent and does not include the thousands of beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies. The transfer agent of our common stock is Continental Stock Transfer & Trust Company, 17 Battery Place, New York, New York 10004.

Dividends

We have not paid any cash dividends in the past and we do not anticipate paying any cash dividends to stockholders in the foreseeable future. Any future determination to pay cash dividends will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations and capital requirements, limitations imposed by applicable law and the terms of our debt agreements, and such other factors as our board of directors deems relevant.

Sales of Unregistered Equity Securities

We had no sales of unregistered equity securities during fiscal year 2016.

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Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes our purchases of shares of our common stock during the fiscal quarter ended January 31, 2016:

						Maximum number
					Total number of	of shares that may
	Total Number		Average		shares purchased	yet be purchased
	of Shares		Price Paid		as part of publicly	under the plans
	Purchased		Per Share		announced plans (2)	at month end
November 1, 2015 to November 30, 2015	7,329		$	1.23	—	5,591,645	(3)
December 1, 2015 to December 31, 2015	19,963			0.61	—	5,811,091	(4)
January 1, 2016 to January 31, 2016	12,430			0.61	—	5,811,091
	39,722	(1)	$	0.72	—

(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. The number of shares of common stock actually issued to such employees upon the vesting of their restricted stock units was net of the shares surrendered in satisfaction of their tax liability. The withheld shares are not issued or considered common stock repurchased under the repurchase program described below.

(2) As reported in Current Reports on Form 8-K filed with the SEC on September 11, 2014 and October 17, 2014, the Company’s Board of Directors approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 2”), and (iii) up to the number of shares potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (“Tranche 3”). Shares repurchased under the program may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program may be executed using open market purchases pursuant to Rule 10b-18 under the Exchange Act, pursuant to a Rule 10b5-1 plan, in privately negotiated agreements, or other transactions. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. As of January 31, 2016, an aggregate of 11,431,744 shares of the Company’s common stock have been repurchased under the program.

(3) Includes the number of shares remaining available for repurchase pursuant to Tranche 2, plus the number of shares available for repurchase pursuant to Tranche 3 based on the paid-in-kind interest accrued on the Convertible Note as of September 30, 2015.  All shares authorized for repurchase under Tranche 1, as well as a portion of the shares authorized for repurchase under Tranche 2, were exhausted during the fiscal quarter ended October 31, 2014.

(4) Includes an additional 219,446shares potentially issuable pursuant to the paid-in-kind interest added to the principal balance of the Convertible Note on December 31, 2015.

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Performance Graph

The following graph compares our common stock’s performance for the period beginning January 31, 2011 through January 31, 2016 with the performance of the Standard & Poor’s 500 Stock Index, the Dow Jones U.S. Oil and Gas Index, and a peer group of Bakken focused exploration and production companies comprised of Continental Resources, Inc., Whiting Petroleum Corp, Oasis Petroleum Inc., Halcon Resources Corp, Northern Oil & Gas, Inc., and Emerald Oil, Inc. The graph assumes the value of the investment in our common stock and in each index/group was $100 on January 31, 2011 and that any dividends were reinvested. The common stock performance shown on the graph below is not indicative of future price performance. The information provided in this section is being furnished to, and not filed with, the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Exchange Act.

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ITEM 6.  SELECTED FINANCIAL DATA

The following table sets forth selected consolidated financial data as of and for the years ended January 31, 2012 through January 31, 2016. The data as of and for the years ended January 31 for the respective years was derived from our historical consolidated financial statements and the accompanying notes included elsewhere in this annual report on Form 10-K or in our prior annual reports on Form 10-K, as applicable.The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying notes thereto provided in Item 8 of this Report.

	For the Years Ended January 31,
(in thousands, except per share data)	2012		2013		2014		2015		2016
Consolidated Statement of Operations Information:
REVENUES:
Oil, natural gas, and natural gas liquids sales	$	8,136	$	39,614	$	160,548	$	284,502	$	181,228
Oilfield services		—		20,747		98,199		288,453		176,901
Total revenue		8,136		60,361		258,747		572,955		358,129
EXPENSES:
Lease operating and production taxes		2,438		8,058		32,460		55,477		58,995
Gathering, transportation and processing		22		150		4,302		18,520		25,910
Depreciation, amortization and accretion		3,281		15,265		58,067		124,222		121,750
Impairments		10,416		—		—		—		793,900
Oilfield services		—		16,606		82,327		216,596		163,452
General and administrative		16,954		28,543		34,629		62,757		62,305
Total operating expenses		33,111		68,622		211,785		477,572		1,226,312
OTHER INCOME (EXPENSE):
Interest expense, net		—		(2,672)		(7,132)		(25,100)		(38,706)
Amortization of debt issuance costs		—		(146)		(554)		(3,149)		(3,180)
Gain on extinguishment of debt		—		—		—		6,610		17,927
Commodity derivative gains (losses)		—		(3,570)		1,082		64,050		38,547
Equity investment gain (loss)		—		(283)		39,785		634		(19,994)
Other income (expense), net		552		448		1,278		469		(2,148)
Total other income (expense)		552		(6,223)		34,459		43,514		(7,554)
Income (loss) before income taxes		(24,423)		(14,484)		81,421		138,897		(875,737)
Income tax provision (benefit)		—		—		7,941		45,500		(53,397)
Net income (loss)	$	(24,423)	$	(14,484)	$	73,480	$	93,397	$	(822,340)
Less: net income (loss) attributable to noncontrolling interest in subsidiary		(145)		(724)		—		—		—
Net income (loss) attributable to common stockholders	$	(24,278)	$	(13,760)	$	73,480	$	93,397	$	(822,340)
Earnings per common share - basic	$	(0.60)	$	(0.31)	$	1.07	$	1.12	$	(10.89)
Earnings per common share - diluted	$	(0.60)	$	(0.31)	$	0.91	$	0.97	$	(10.89)
Consolidated Balance Sheet Information:
Cash and cash equivalents	$	68,815	$	33,117	$	81,750	$	67,871	$	115,769
Total assets	$	229,845	$	428,321	$	1,027,522	$	1,645,041	$	753,148
Long-term obligations	$	83	$	148,788	$	345,054	$	847,648	$	800,538
Other Financial Information:
Net cash provided by (used in) operating activities	$	(12,766)	$	2,764	$	82,436	$	200,817	$	165,034
Net cash used in investing activities	$	(111,046)	$	(179,712)	$	(455,566)	$	(577,019)	$	(231,834)
Net cash provided by financing activities	$	134,854	$	141,250	$	421,763	$	362,323	$	114,698
Capital expenditures	$	108,913	$	167,037	$	439,451	$	584,243	$	245,638
Proved reserves:
Oil (Mbbls)		1,365		12,540		31,916		48,091		38,901
Natural gas (MMcf)		674		12,585		26,504		40,185		31,823
NGL (Mbbls)		—		—		3,981		4,081		4,679
Total equivalent (MBoe)		1,477		14,637		40,314		58,870		48,884

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ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this annual report contain additional information that should be referred to when reviewing this material.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties that could cause actual results to differ from those expressed. We encourage you to revisit the Forward-Looking Statements section of this annual report.

Liquidity and Ability to Continue as a Going Concern

Our consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern. See Item 8. Consolidated Financial Statements and Supplementary Data – Note 2 for further discussion.

Overview

We are an 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 primarily in the Williston Basin of North Dakota and Montana through TUSA and RockPile, the Company’s two principal wholly-owned subsidiaries, and Caliber, our equity joint venture.

Summary of results for the year ended January 31,2016

· Average daily production volumes were 13,416 Boe/day for the year ended January 31,2016, compared to 11,441 Boe/day for the year ended January 31,2015, an increase of 17%.  

· TUSA spud 16 gross (12.9 net) operated wells and completed 20 gross (14.3 net) operated wells during the year ended January 31, 2016. As of January 31, 2016, TUSA had 14 gross (13.1 net) operated wells that have been drilled and were pending completion.

· We released our last drilling rig in August 2015 and have temporarily deferred our drilling program. We plan to periodically reassess the appropriate number of rigs for our future drilling program based on a variety of factors including, but not limited to, prevailing oil and natural gas prices and operational efficiencies.

· Lower average realized prices of $37.01 per Boe for the year ended January 31, 2016, versus $68.13 per Boe for the year ended January 31, 2015, resulted in oil, natural gas and natural gas liquids sales for the year ended January 31, 2016 of $181.2 million compared to $284.5 million for the year ended January 31, 2015.

· RockPile completed 20 TUSA operated wells and 155 third-party wells in the year ended January 31,2016, as compared to 49 TUSA operated wells and 99 third-party wells in the year ended January 31,2015.  

· Oilfield services revenue for the year ended January 31,2016 was $176.9 million compared to $288.5 million for the year ended January 31,2015.  

· The competitive oilfield services pricing environment resulted in a negative gross profit of $15.4million for the year ended January 31, 2016 compared to a gross profit of $56.1million for the year ended January 31, 2015 after eliminations of intercompany gross profit.

· The carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation at January 31,2016 resulting in an impairment of $779.0 million for the year ended January 31,2016.

· Cash flows provided by operating activities were $165.0 million for the year ended January 31,2016 compared to $200.8 million for the year ended January 31, 2015.

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Summary of Operating Results

The following table reflects the components of our production volumes, average realized prices, oil, natural gas and natural gas liquids revenues, and operating expenses for the periods indicated. No pro forma adjustments have been made for the acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below. The information set forth below is not necessarily indicative of future results.

	For the Years Ended January 31,
Oil and Natural Gas Operations	2014		2015		2016
Production volumes:
Crude oil (Mbbls)		1,754		3,511		3,952
Natural gas (MMcf)		626		2,429		3,115
Natural gas liquids (Mbbls)		70		260		426
Total barrels of oil equivalent (Mboe)		1,929		4,176		4,897
Average daily production volumes (Boe/d)		5,286		11,441		13,416
Average realized prices:
Crude oil ($ per Bbl)	$	88.07	$	75.00	$	43.07
Natural gas ($ per Mcf)	$	4.39	$	5.27	$	2.61
Natural gas liquids ($ per Bbl)	$	46.72	$	32.26	$	6.74
Total average realized price ($ per Boe)	$	83.22	$	68.13	$	37.01
Oil, natural gas and natural gas liquids revenues (in thousands):
Crude oil	$	154,507	$	263,310	$	170,227
Natural gas		2,748		12,804		8,130
Natural gas liquids		3,293		8,388		2,871
Total oil, natural gas and natural gas liquids revenues	$	160,548	$	284,502	$	181,228
Operating expenses (in thousands):
Lease operating expenses	$	14,454	$	25,703	$	41,504
Gathering, transportation and processing		4,302		18,520		25,910
Production taxes		18,006		29,774		17,491
Oil and natural gas amortization expense		51,954		106,903		90,406
Impairment of oil and natural gas properties		—		—		779,000
Accretion of asset retirement obligations		56		167		376
Total operating expenses	$	88,772	$	181,067	$	954,687
Operating expenses per Boe:
Lease operating expenses	$	7.49	$	6.15	$	8.48
Gathering, transportation and processing	$	2.23	$	4.43	$	5.29
Production taxes	$	9.33	$	7.13	$	3.57
Oil and natural gas amortization expense	$	26.93	$	25.60	$	18.46

Comparison of the Year Ended January 31,2016 to the Year Ended January 31,2015

Oil, Natural Gas and Natural Gas Liquids Revenues. Revenues from oil, natural gas and natural gas liquids for the year ended January 31, 2016 decreased 36% to $181.2 million from $284.5 million for the year ended January 31, 2015. Total production increased 17% due to our drilling and completion program. This increase in production was offset by a 46% decrease in weighted average realized prices from $68.13 per Boe for the year ended January 31, 2015 to $37.01 per Boe for the year ended January 31, 2016.

Lease Operating Expenses.  Lease operating expenses increased to $8.48 per Boe for the year ended January 31,2016 from $6.15 per Boe for the year ended January 31, 2015. The cost increase is primarily the result of increased workover expenses and higher produced water disposal costs. We expect that lease operating expenses on a per Boe basis in fiscal year 2017 will be similar to those incurred in fiscal year 2016.

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Gathering, Transportation and Processing.  Gathering, transportation and processing expenses increased to $5.29 per Boe for the year ended January 31,2016 compared to $4.43 per Boe for the year ended January 31,2015. We began transporting and processing our oil, natural gas, and natural gas liquids through Caliber’s facilities in fiscal year 2015. We often receive higher average realized prices by using Caliber’s facilities, partly offset by higher gathering, transportation, and processing expenses. We expect future expenses on a per Boe basis will be similar to those incurred in fiscal year 2016.

Production Taxes. Production taxes decreased 41% in fiscal year 2016 to $17.5 million from $29.8 million for fiscal year 2015. The 36% decrease in oil, natural gas and natural gas liquids revenues for the year ended January 31,2016 versus the year ended January 31,2015 is the primary reason for the decrease.

Oil and Natural Gas Amortization. Oil and natural gas amortization expense decreased 15% to $90.4 million for the year ended January 31,2016 from $106.9 million for the year ended January 31,2015. On a per Boe basis, our oil and natural gas amortization expense decreased by $7.14 from $25.60 for the year ended January 31,2015 to $18.46 for the year ended January 31,2016 primarily due to the impairments recorded in fiscal year 2016.

Impairment of Oil and Natural Gas Properties.During fiscal year 2016, we recorded a $779.0 million non-cash impairment of the carrying value of our proved oil and natural gas properties as a result of the effects of significant declines in oil, natural gas and natural gas liquids prices on the ceiling test limitation. The trailing twelve month reference prices at January 31, 2016 were $48.93 per Bbl of oil, $2.53 per MMbtu for natural gas and $24.97 per Bbl of natural gas liquids.No provision for impairment was recorded during fiscal year 2015.

Because the ceiling calculation requires rolling 12-month average commodity prices, the effect of lower quarter over- quarter prices in fiscal year 2016 compared to fiscal year 2015 will be a lower ceiling limitation each quarter. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further. The amount of any future impairment is difficult to predict and will depend, in part, upon future oil, natural gas and natural gas liquids prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

If the simple average of oil, natural gas and natural gas liquids prices as of the first day of each month for the trailing 12-month period ended January31, 2016 had been $38.53 per Bbl of oil, $2.22 per MMbtu for natural gas and $20.04 per Bbl of natural gas liquids and all other factors remained constant, our impairment for the year ended January31, 2016 would have increased, on a pro forma basis, by approximately $116.0 million. The aforementioned prices were calculated based on a twelve-month simple average, which includes the oil and natural gas spot prices on February 1, March 1, and April 1, 2016; and first of the month forward strip prices from May 1, 2016 through January 1, 2017 based on forward strip prices as of April 1, 2016.

This calculation of the impact of lower commodity prices is prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil, natural gas and natural gas liquids prices. Therefore, this calculation strictly isolates the impact of commodity prices on our ceiling test limitation and proved reserves. The impact of price is only a single variable in the estimation of our proved reserves and other factors could have a significant impact on future reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, changes in costs, drilling results, revisions due to performance and other factors, changes in development plans and production. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results.

The ceiling calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity. Any recorded impairment of oil and natural gas properties is not reversible at a later date.

Impairment of Long-Lived Assets.During fiscal year 2016, we also recorded an impairment of long-lived assets of $14.9 million including $13.8 million related to the downturn in our oilfield services business. No provision for impairment was recorded during fiscal year 2015.

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Oilfield Services Gross Profit.We formed RockPile with the strategic objective of having both greater control over one of our largest cost centers as well as to provide locally-sourced, high-quality completion services to TUSA and other operators in the Williston Basin. Since formation, RockPile has been focused on procuring new oilfield and complementary well completion equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, and establishing third-party customers.In addition, RockPile is currently providing oilfield services in the Permian Basin of Texas and evaluating opportunities in other areas. RockPile’s results of operations are affected by a number of variables including drilling and stimulation activity, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers. 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 the pricing environment, completion design and equipment utilization.

The table below summarizes the RockPile contribution to our consolidated results for the years ended January 31, 2015 and 2016:

	For the Year Ended January 31, 2015						For the Year Ended January 31, 2016
(inthousands)	OilfieldServices		Eliminations		Consolidated		OilfieldServices		Eliminations		Consolidated
Revenues
Oilfield services	$	418,103	$	(129,650)	$	288,453	$	210,118	$	(33,217)	$	176,901
Total revenues		418,103		(129,650)		288,453		210,118		(33,217)		176,901
Cost of sales
Oilfield services		301,142		(84,854)		216,288		184,094		(20,642)		163,452
Depreciation		22,008		(5,899)		16,109		32,365		(3,537)		28,828
Total cost of sales		323,150		(90,753)		232,397		216,459		(24,179)		192,280
Gross profit	$	94,953	$	(38,897)	$	56,056	$	(6,341)	$	(9,038)	$	(15,379)

For the year ended January 31,2016 RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 24 third-party customers. RockPile has increased its base of third-party customers; however, the competitive oilfield services pricing environment resulted in a 39% decrease in consolidated oilfield services revenues from $288.5 million for the year ended January 31,2015 to $176.9 million for the year ended January 31,2016. Hydraulic fracturing services resulted in175 total well completions (20 for TUSA and 155 for third-parties) for the year ended January 31, 2016 compared to 148 well completions (49 for TUSA and 99 for third parties) for the year ended January 31, 2015.

The current competitive oilfield services pricing environment has resulted in a gross profit of $56.1 million for the year ended January 31,2015 compared to a negative gross profit of $15.4 million for the year ended January 31, 2016, after eliminations of $38.9 million and $9.0 million of intercompany gross profit, respectively. We expect that the oilfield services pricing environment will continue to be very challenging as long as oil and natural gas prices remain near current levels, resulting in continued compressed profit levels.

General and Administrative Expenses. The following table summarizes general and administrative expenses for the years ended January 31,2015 and 2016:

	For the Year Ended January 31, 2015								For the Year Ended January 31, 2016
	Exploration								Exploration
	and		Oilfield				Consolidated		and		Oilfield				Consolidated
(in thousands)	Production		Services		Corporate		Total		Production		Services		Corporate		Total
Salaries and benefits	$	6,028	$	14,620	$	11,559	$	32,207	$	1,161	$	16,648	$	10,432	$	28,241
Share-based compensation		1,155		509		6,255		7,919		1,537		805		15,052		17,394
Other general and administrative		9,042		10,598		2,991		22,631		3,375		8,268		5,027		16,670
Total	$	16,225	$	25,727	$	20,805	$	62,757	$	6,073	$	25,721	$	30,511	$	62,305

Total general and administrative expenses decreased $0.5 million to $62.3 million for the year ended January 31,2016 compared to $62.8 million for the year ended January 31, 2015. The decrease in total general and administrative expenses is a result of lower salaries and benefits from staffing reductions and lower other general and administrative expenses costs partly offset by higher share based compensation costs. In fiscal year 2016, salaries and benefits includes

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$0.7 million for severance costs related to our reductions in work force and other general and administrative expense includes $2.7 million for costs related to vacated facilities. We expect that our fiscal year 2017 general and administrative expenses will be less than fiscal year 2016 due to the reductions in force and other cost reduction measures made in fiscal year 2016.

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 consolidated balance sheets as derivative assets and liabilities. During the years ended January 31, 2015 and 2016, we recognized gains of $64.1 million and $38.5 million, respectively, on our commodity derivative positions due to continued decreases in underlying crude oil prices. The fair values of the open commodity derivative instruments will continue to change in value until the transactions are settled. 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. We recorded a realized commodity derivative gain of $71.9 million in fiscal year 2016, as compared to a realized commodity derivative gain of $11.4 million in fiscal year 2015.

In August 2015, the Company unwound certain commodity derivative swap contracts and realized a gain of $9.3 million. The early settled contracts were for 2,000 barrels of oil per day at an average fixed price of $60.34 per Bbl for the period from January 1, 2016 to December 31, 2016.

Income (Loss) from Equity Investment.  Our equity investment in Caliber consists of Class A Units and equity derivative instruments. The Company recognized a $3.1 million gain on its equity investment derivatives in fiscal year 2016 compared to a $0.6 million gain during fiscal year 2015 related to the change in the fair value of the equity investment derivatives. During the year ended January 31,2016, the Company recognized $3.1 million for its share of Caliber’s net income for the period. This income was offset by $1.2 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $1.9 million. During the year ended January 31,2015, the Company recognized $1.4 million for its share of Caliber’s net income for the period. This income was offset by $1.3 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $0.1 million. The carrying value of our investment in Caliber exceeded its fair value at January 31, 2016.Since we deemed this decline in fair value to be other than temporary, we recorded a net impairment in our investment in Caliber of $25.0 million in fiscal year 2016.

Interest Expense. The $38.7 million in interest expense for the year ended January 31,2016 consists of (i)$4.5 million in interest related to the TUSA credit facility, (ii)$3.0 million in interest expense associated with RockPile’s credit facility and notes payable, (iii)$28.6 million in interest related to the TUSA 6.75% Notes, (iv) $6.9 million in accrued interest related to the Convertible Note, and (v)$0.5 million in interest expense related to our other debt, all net of $4.8 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. We paid $37.1 million of interest expense and capitalized interest in cash.

The $25.1 million in interest expense for the year ended January 31,2015 consists of (i)$4.3 million in interest related to the TUSA credit facility, (ii) $2.7 million in interest expense associated with RockPile’s credit facility and notes payable (iii) $16.2 million in interest related to the TUSA 6.75% Notes, (iv)$6.6 million in accrued interest related to our Convertible Note, and (v) $0.2 million in interest expense related to our other debt, all net of $4.9 million of capitalized interest. We paid $21.4 million of interest expense and capitalized interest in cash.

Income Taxes. We recorded a full valuation allowance against our net deferred tax assets in fiscal year 2016, and we recognized a benefit of $53.4 million compared to an expense of $45.5 million in fiscal year 2015.

As previously noted, the carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in impairments of $779.0 million for the year ended January 31, 2016. These impairments resulted in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Triangle also had net operating loss carryovers (“NOLs”) for federal income tax purposes of $286.0 million at January 31, 2016. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of January 31, 2016 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

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The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense or for state income taxes.

Comparison of the Year Ended January 31, 2015 to the Year Ended January 31, 2014

Oil, Natural Gas and Natural Gas Liquids Revenues. Revenues from oil, natural gas and natural gas liquids for the year ended January 31, 2015 increased 77% to $284.5 million from $160.5 million for the year ended January 31, 2014 primarily due to the significant increase in oil production from new wells and the acquisition of producing wells in the third quarter of fiscal year 2014 and the second quarter of fiscal year 2015, partially offset by normal production declines and pricing declines in oil and natural gas liquids. Total production increased 116% for the year ended January 31, 2015 compared to the year ended January 31, 2014. This increase in production was partly offset by an18% decrease in weighted average realized prices from $83.22 per Boe for the year ended January 31, 2014 to $68.13 per Boe for the year ended January 31, 2015.

Lease Operating Expenses. Lease operating expenses decreased to $6.15 per Boe for the year ended January 31, 2015 from $7.49 per Boe for the year ended January 31, 2014. The cost decrease is primarily the result of efficiencies generated from operating more wells with labor and power costs spread across increased production.

Gathering, Transportation and Processing. Gathering, transportation and processing expenses increased to $4.43 per Boe for the year ended January 31, 2015 compared to $2.23 per Boe for the year ended January 31, 2014, 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. We often receive higher average realized prices by using Caliber’s facilities, partly offset by higher gathering, transportation, and processing expenses.

Production Taxes. Production taxes increased 65% in fiscal year 2015 to $29.8 million from $18.0 million in fiscal year 2014. The 77% increase in oil, natural gas and natural gas liquids revenues for the year ended January 31, 2015 versus the year ended January 31, 2014 is the primary reason for the increase.

Oil and Natural Gas Amortization. Oil and natural gas amortization expense increased 106% to $106.9 million for the year ended January 31, 2015 from $52.0 million for the year ended January 31, 2014. The increase is primarily related to increased production in fiscal year 2015 as compared to fiscal year 2014. On a per Boe basis, our oil and natural gas amortization expense decreased by $1.33 from $26.93 for the year ended January 31, 2014 to $25.60 for the year ended January 31, 2015 primarily due to increases in proved reserves from successful development and field extensions, and the acquisition of additional oil and natural gas properties.

Impairments.  No provision for impairment was recorded during fiscal year 2015 or fiscal year 2014.

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Oilfield Services Gross Profit. The table below summarizes the RockPile contribution to our consolidated results for the years ended January 31, 2014 and 2015:

	For the Year Ended January 31, 2014						For the Year Ended January 31, 2015
(in thousands)	Oilfield Services		Eliminations		Consolidated		Oilfield Services		Eliminations		Consolidated
Revenues
Oilfield services	$	193,625	$	(95,426)	$	98,199	$	418,103	$	(129,650)	$	288,453
Total revenues		193,625		(95,426)		98,199		418,103		(129,650)		288,453
Cost of sales
Oilfield services		142,339		(60,012)		82,327		301,142		(84,854)		216,288
Depreciation		8,905		(3,542)		5,363		22,008		(5,899)		16,109
Total cost of sales		151,244		(63,554)		87,690		323,150		(90,753)		232,397
Gross profit	$	42,381	$	(31,872)	$	10,509	$	94,953	$	(38,897)	$	56,056

For the year ended January 31, 2015, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 11 third-party customers. RockPile increased its base of third-party customers resulting in a 194% increase in consolidated oilfield services revenues from $98.2 million for the year ended January 31, 2014 to $288.5 million for the year ended January 31, 2015. Hydraulic fracturing services resulted in 148 total well completions (49 for TUSA and 99 for third-parties) for the year ended January 31, 2015 compared to 81 total well completions (31 for TUSA and 50 for third-parties) for the year ended January 31, 2014.

We recognized a gross profit from oilfield services of $56.1 million for the year ended January 31, 2015 compared to a gross profit of $10.5 million for the year ended January 31, 2014, after eliminations of $38.9 million and $31.9 million of intercompany gross profit, respectively.

General and Administrative Expenses. The following table summarizes general and administrative expenses for the years ended January 31, 2014 and 2015:

	For the Year Ended January 31, 2014								For the Year Ended January 31, 2015
	Exploration								Exploration
	and		Oilfield				Consolidated		and		Oilfield				Consolidated
(in thousands)	Production		Services		Corporate		Total		Production		Services		Corporate		Total
Salaries and benefits	$	3,541	$	6,894	$	6,864	$	17,299	$	6,028	$	14,620	$	11,559	$	32,207
Share-based compensation		1,127		590		6,113		7,830		1,155		509		6,255		7,919
Other general and administrative		3,939		4,222		1,339		9,500		9,042		10,598		2,991		22,631
Total	$	8,607	$	11,706	$	14,316	$	34,629	$	16,225	$	25,727	$	20,805	$	62,757

Total general and administrative expenses increased $28.2 million to $62.8 million for the year ended January 31, 2015 compared to $34.6 million for the year ended January 31, 2014. The increase in total general and administrative expenses in the year ended January 31, 2015 is primarily a result of increased salaries and benefit costs for personnel due to the growth of the businesses, which also included an accrual for a transaction bonus of $1.9 million due to our President and Chief Executive Officer. During the year ended January 31, 2015, we also incurred a $1.3 million charge associated with the write-off of software implementation costs associated with a land and accounting system conversion that was abandoned.

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 consolidated balance sheets as derivative assets and liabilities. During the years ended January 31, 2014 and 2015, we recognized gains of$1.1 million and $64.1 million, respectively, on our commodity derivative positions due to decreases in underlying crude oil prices. The fair values of the open commodity derivative instruments will continue to change in value until the transactions are settled. 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. We recorded a realized commodity derivative gain of $11.4 million in fiscal year 2015, as compared to a realized commodity derivative loss of $4.6 million in fiscal year 2014.

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Income (Loss) from Equity Investment. Our equity investment in Caliber consists of Class A Units and equity derivative instruments. The Company recognized a $0.6 million gain on its equity investment derivatives in fiscal year 2015 compared to a $39.8 million gain during fiscal year 2014 related to the change in the fair value of the equity investment derivatives. In addition, during the year ended January 31, 2015, the Company recognized $1.4 million for its share of Caliber’s net income for the period. This income was offset by $1.3 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $0.1 million. During the year ended January 31, 2014, the Company recognized $2.2 million for its share of Caliber’s net income for the period. This income was completely offset by $2.2 million of intra-company profit gross recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in no recognized income.

Interest Expense. The $25.1 million in interest expense for the year ended January 31, 2015 consists of (i) $4.3 million in interest related to the TUSA credit facility, (ii)$2.7 million in interest expense associated with RockPile’s credit facility and notes payable, (iii) $16.2 million in interest related to the TUSA 6.75% Notes, (iv)$6.6 million in accrued interest related to the Convertible Note, and (v)$0.2 million in interest expense related to our other debt, all net of $4.9 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. We paid $21.4 million of interest expense and capitalized interest in cash.

The $7.1 million in interest expense for the year ended January 31, 2014 consists of (i)$2.9 million in interest related to the TUSA credit facility, (ii)$1.0 million in interest expense associated with RockPile’s credit facility, and (iii) $6.2 million in accrued interest related to our Convertible Note, all net of $3.0 million of capitalized interest. We paid $3.6 million of interest expense and capitalized interest in cash.

Income Taxes. Our fiscal year 2015 income tax provision was $45.5 million compared to $7.9 million in fiscal year 2014. Our effective tax rate of 32.8% for fiscal year 2015 was less than our U.S. blended statutory rate of 37.6% primarily due to a bad debt deduction taken for amounts owed by our Canadian subsidiary to Triangle that will not be realized because our Canadian operations have ceased except for certain reclamation activities. During fiscal year 2014, the effective income tax rate of 10% was less than the U.S. blended statutory rate because Triangle reversed its valuation allowance. In fiscal year 2014, Triangle determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net U.S. deferred tax assets will be realized.

Liquidity and Capital Resources

Our liquidity is highly dependent on the prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and are historically volatile. Prices received for production heavily influence our revenue, cash flows, 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 affect the demand for services provided by RockPile and Caliber.

In fiscal year 2016, our average realized price for oil was $43.07 per barrel, a decrease of 43% over the average realized price for fiscal year 2015. This reflected the dramatic decrease in the price of oil that occurred over the second half of fiscal year 2015 and continued throughout fiscal year 2016. Future prices for oil will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors. We seek to manage the impact that volatility in commodity prices has on our liquidity by periodically hedging a portion of our oil production to mitigate our potential exposure to price declines and maintaining flexibility in our capital investment program. However, our commodity derivative contracts entered into prior to the aforementioned dramatic decrease in the price of oil expired by December 31, 2015. Although we have entered into additional commodity derivative contracts for production in fiscal years 2017 and 2018, those contracts were entered into during the depressed commodity pricing environment, and we will be exposed to continued volatility in crude oil market prices, whether favorable or unfavorable.

Although the Company is continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations, its liquidity outlook has changed since the third quarter of fiscal year 2016. Continued low commodity prices are expected to result in significantly lower levels of cash flow from operating activities in the future and have limited the Company’s ability to access capital markets. As a result of these and other factors, there is substantial doubt about the Company’s ability to continue as a going concern.

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As of January 31, 2016, we had approximately $911.1 million of debt outstanding, consisting of $243.8 million for the TUSA credit facility, $112.0 million for the RockPile credit facility, $398.4 million for the TUSA 6.75% Notes, $142.8 million for the Convertible Note, and $14.1 million for other notes and mortgages.

As of January 31, 2016, we had cash of $115.8 million consisting primarily of cash held in bank accounts, as compared to $67.9 million at January 31, 2015. At January 31, 2016, we also had available borrowing capacity of $103.7 million under the TUSA credit facility and $38.0 million under the RockPile credit facility. On March 31, 2016, we borrowed an additional $103.7 million under the TUSA credit facility, representing the entire amount remaining thereunder relative to the current borrowing base. After these additional borrowings, we had cash and cash equivalents of $206.2 million as of March 31, 2016.

Cash Flows

The following is a summary of our changes in cash and cash equivalents for the years ended January 31, 2014, 2015 and 2016:

	For the Years Ended January 31,
(inthousands)	2014		2015		2016
Net cash provided by operating activities	$	82,436	$	200,817	$	165,034
Net cash used in investing activities		(455,566)		(577,019)		(231,834)
Net cash provided by financing activities		421,763		362,323		114,698
Net increase (decrease) in cash and equivalents	$	48,633	$	(13,879)	$	47,898

Net Cash Provided by Operating Activities. Cash flows provided by operating activities were $200.8 million for the year ended January 31, 2015, compared to $165.0 million for the year ended January 31, 2016. Cash flows from operating activities were unfavorably impacted in the year ended January 31, 2016 by lower realized oil prices and the competitive oilfield services pricing environment compared to the year ended January 31, 2015, offset by favorable changes in current assets and current liabilities in the year ended January 31, 2016.

Cash flows provided by operating activities were $82.4 million for the year ended January 31, 2014, as compared to $200.8 million for the year ended January 31, 2015.The increase in operating cash flows in fiscal year 2015 was primarily due to higher oil revenues driven by higher sales volumes and increased contributions from RockPile, partially offset by related increases in operating expenses and unfavorable changes in current assets and current liabilities during the period. 

Net Cash Used in Investing Activities. During the year ended January 31, 2015, we used $577.0 million in cash in investing activities compared to $231.8 million during the year ended January 31, 2016. During the years ended January 31, 2015 and 2016, we used $359.1 million and $231.2 million, respectively, on oil and natural gas property expenditures and $138.8 million and $0.8 million, respectively, to acquire oil and natural gas properties. During the years ended January 31, 2015 and 2016, we also spent $59.6 million and $8.5 million, respectively, on purchases of oilfield services equipment and $26.7 million and $5.1 million, respectively, on other property and equipment, primarily consisting of facility construction and improvements. During the year ended January 31, 2016, we received net proceeds of $6.0 million from the sale of a salt water disposal well and $7.8 million from the sale of equipment.

During the year ended January 31, 2014, we used $455.6 million in cash in investing activities compared to $577.0 million during the year ended January 31, 2015.During both years, our primary uses of cash flows in investing activities were related to our oil and natural gas property expenditures.During the years ended January 31, 2014 and 2015, we used $279.5 million and $359.1 million, respectively, on oil and natural gas property expenditures.During the years ended January 31, 2014 and 2015, we also used $121.6 million and $138.8 million, respectively, to acquire oil and natural gas properties. During the years ended January 31, 2014 and 2015, we spent $27.4 million and $59.6 million, respectively, on purchases of oilfield services equipment. During the years ended January 31, 2014 and 2015, we also spent $10.9 million and $26.7 million, respectively, on other property and equipment, namely facility construction and improvements.

Net Cash Provided by Financing Activities.Cash flows provided by financing activities for the year ended January 31, 2015 totaled $362.3 million, as compared to $114.7 million for the year ended January 31, 2016. Our primary financing activities during the year ended January 31, 2015 included the issuance of $450.0 million of the TUSA 6.75% Notes and net borrowings from our credit facilities of $19.6 million. Our primary source of cash from financing activities during the year ended January 31, 2016 came from $131.6 million in net borrowings from our credit facilities. In fiscal

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years 2015 and 2016, we used cash of $13.9 million and $13.2 million, respectively, to repurchase and retire TUSA 6.75% Notes with a face value of $20.5 million and $31.1 million, respectively.In fiscal year 2015, we also used $76.8 million of cash to repurchase shares of our common stock in the open market. 

Cash flows provided by financing activities totaled $421.8 million for the year ended January 31, 2014. Our primary sources of cash from financing activities included $179.5 million in net borrowings from our credit facilities and net proceeds of $238.3 million from issuances of our common stock.

Capital Requirements Outlook

Our cash flows from operations for fiscal year 2016 were insufficient to cover our capital requirements, and we continued to rely on external financing activities. We believe that the lag time between initial investment and cash flows from such investment is typical of the oil and natural gas industry where upfront costs are significant and cash flows are delayed. This holds true across all of our businesses, including drilling and completion costs for TUSA and equipment costs for RockPile. While we are not obligated to fund any further equity commitment for Caliber, the lag time between investment in operations and cash flows is exacerbated in the midstream space where initial construction costs and project timelines are substantial. In a higher oil and natural gas pricing environment such as we experienced in recent years, we expect that our cash flows from operations would 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 more fully utilized. However, we expect that current depressed oil and natural gas prices, which have temporarily deferred our drilling program and created a very challenging oilfield services market, will continue to limit our cash flows from operations in upcoming quarters.

In response to the current oil and natural gas pricing environment, we have significantly reduced capital expenditures and implemented reductions in force across our businesses, and we may further adjust such expenditures as market dynamics warrant. For fiscal year 2017, TUSA’s capital expenditure plan is focused primarily on completing wells that have been drilled and are awaiting completion, but the number and timing of such completions is dependent upon prevailing oil and natural gas prices. While we work toward cash flow neutrality in fiscal year 2017, low commodity prices may make it difficult for us to achieve this objective. As a result, we will likely remain dependent on cash on hand and, to a lesser extent, potential additional financings to fund any difference between cash flows from operations and our capital expenditures budget and other contractual commitments. However, as noted in Item 1A – Risk Factors, an adverse borrowing base redetermination under the TUSA credit facility and actual or potential financial covenant defaults under both our TUSA and RockPile credit facilities are expected to make additional credit extensions under those facilities unavailable. Any additional liquidity shortfall may be financed through additional debt or equity instruments, if we are able to access the capital markets on acceptable terms, which is highly uncertain. There can be no assurance, however, that we will achieve our anticipated future cash flows 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.

While unlikely in the current commodity environment, we may 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 industry, and tax burdens due to new tax laws.

If our existing and potential sources of liquidity are not sufficient to allow us to satisfy our commitments and to undertake our planned expenditures, particularly if commodity prices remain depressed for an extended period of time, we have the flexibility to further alter our development program or divest assets. Our operatorship of much of our acreage allows us the ability to adjust our drilling and completion schedules in response to changes in commodity prices or the oilfield services environment. We plan to complete certain of our drilled uncompleted wells opportunistically throughout the year. If we are not successful in achieving cash flow neutrality or obtaining sufficient funding on a timely basis on terms acceptable to us, we may be required to curtail our planned expenditures and/or restructure our operations, which may reduce anticipated future cash flows from operations. We may also be required to pursue alternative measures, such as selling material assets or business segments; seeking additional financing; or refinancing, recapitalizing, or restructuring all or a portion of our existing debt. As discussed in Item 1A – Risk Factors, we cannot assure you that any of the measures would be successful or sufficient.

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Sources of Capital

Cash flows from operations. Our produced volumes have increased significantly over the past three years as a result of the successful development of our operated properties. However, due to the current depressed oil and natural gas pricing environment, we have temporarily deferred our drilling program, and we plan to delay the completion of certain wells subject to a number of factors, including the price of oil and natural gas, development costs, and the availability of third party work for RockPile. Consequently, our production volume is expected to decrease in fiscal year 2017 as compared to fiscal year 2016, and the cash flows we receive from our production will likely be less than we received in prior years due to lower realized prices. If oil and natural gas prices recover sufficiently in fiscal year 2017, we may increase capital expenditures, which we expect would increase production volumes and cash flows from operations.

Cash flows from our oilfield services segment decreased significantly in fiscal year 2016 primarily due to efforts to remain competitive in the current oil and natural gas pricing environment by significantly reducing fees that RockPile charges to its customers. As a result of the margin compression on fees charged for services, as well as the likelihood for lower utilization of RockPile services by customers slowing the pace of their development operations, we anticipate that RockPile’s cash flows from operations in fiscal year 2017 may be substantially lower than in fiscal year 2016.

Credit facilities.As of January 31, 2016, our maximum credit available under the TUSA credit facility was $1.0 billion, subject to a borrowing base of $350.0 million. As of January 31, 2016, we had $103.7 million of borrowing capacity available; however, on March 31, 2016, we borrowed an additional  $103.7 million under the TUSA credit facility, representing the entire amount remaining thereunder relative to the current borrowing base. The borrowing base under the TUSA credit facility is subject to redetermination on a semi-annual basis by May 1 and November 1. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. We anticipate that our borrowing base will be substantially reduced in connection with our May 2016 redetermination. Because TUSA’s credit agreement is effectively fully drawn, any reduction of the borrowing base would result in a borrowing base deficiency that TUSA would be required to remedy by repaying principal thereunder in an amount sufficient to eliminate the deficiency and/or pledging additional collateral. The terms on which TUSA would be required to remedy any borrowing deficiency depend on whether such deficiency results from a regularly scheduled redetermination or an unscheduled redetermination called by the lenders, asdiscussed in greater detail in Item 1A – Risk Factors.

On April 13, 2016, RockPile entered into Amendment No. 2 to the Credit Agreement (“Amendment No. 2”), which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 or may occur as of April 30, 2016.  The waivers are conditioned on RockPile agreeing to certain informational and process requirements and deadlines. Following the execution of Amendment No. 2, RockPile is precluded from drawing additional funds absent further amendment of the facility.

Absent a substantial increase in commodity prices or favorable negotiations with our credit facility lenders, we do not anticipate that we will have borrowing capacity available under our existing credit facilities to finance any difference between our cash on hand and cash flows from operations and our anticipated capital expenditures.

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

Asset Sales. In the past, our acquisition activities have significantly outpaced our asset sales, which have been generally limited to small, opportunistic divestitures or exchanges of leasehold interests. In the current depressed commodity pricing environment, we are strategically reviewing our assets to consider monetizing those that may garner attractive prices or are peripheral to our core businesses. Such assets include, but are not limited to, non-operated acreage, equity investments, equipment, and other real property interests. If commodity prices remain depressed and we are unable to fund our operations or service our debt obligations from other sources of capital, we may be forced to sell portions of our operated Core Acreage or other assets at distressed prices.

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Liquidity

TUSA Liquidity and Covenants. As of January 31, 2016, TUSA was in compliance with all financial covenants under the TUSA credit facility. Although it is difficult to forecast future operations in this low commodity price environment, TUSA anticipates that it could breach its ratio of consolidated debt to EBITDA or its interest coverage ratio covenants (as defined in the credit agreement) in fiscal year 2017 if commodity prices do not recoveror it is unable to obtain cure financing or a waiver or amendment from its lenders, with whom it is engaged in ongoing discussions. Also, the current ratio covenant could be adversely impacted if a redetermination significantly lowers the borrowing base. If TUSA were to breach a covenant in a future period, TUSA has a cure right to obtain a cash capital contribution from Triangle or another investor approved by Triangle on or before ten days following the date that its compliance certificates are due (45 days after quarter ends and 90 days after its fiscal year end) to cure such a breach, also known as an equity cure. Although there are many risks and uncertainties in this environment, TUSA believes that it will be able to reach an agreement with its banks, find acceptable alternative financing or obtain equity cure contributions to prevent or cure an event of default under its credit facility. However, there can be no assurances that these plans can be achieved. If TUSA were to breach any financial covenants under its credit facility and such breach became an event of default, there are cross-default provisions in the Indenture or the TUSA 6.75% Notes that could enable holders of the TUSA 6.75% Notes to declare some or all of the amounts outstanding under the TUSA 6.75% Notes to be immediately due and payable.

While we believe our existing capital resources, including our cash flow from TUSA’s operations and cash on hand at TUSA and Triangle, are sufficient to conduct our operations of TUSA through fiscal year 2017 and into fiscal year 2018, there are certain risks arising from depressed oil and natural gas prices and declines in production volumes that could impact our liquidity and ability to meet debt covenants in future periods. Our ability to maintain compliance with our debt covenants may be negatively impacted if oil and natural gas prices remain depressed for an extended period of time. Further, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. Accordingly, our ability to effectively execute our corporate strategies and manage our operating, general and administrative expenses and capital expenditure programs is critical to our financial condition, liquidity and our results of operations.

If we are not able to meet our debt covenants in future periods, or if our borrowing base is significantly reduced, we may be required but unable to refinance or restructure all or part of our existing debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all, and may be required to surrender assets pursuant to the security provisions of the TUSA credit facility. Further, failing to comply with the financial and other restrictive covenants in the TUSA credit facility and the TUSA 6.75% Notes could result in an event of default, which could adversely affect our business, financial condition and results of operations.

RockPile Liquidity and Covenants.  On April 13, 2016, RockPile entered into Amendment No. 2, which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 or may occur as of April 30, 2016.  We are encouraged that the credit facility lenders have continued to work with us and granted an extension of time to further amend or refinance the credit facility. However, ifcommodity prices remain depressed and RockPile does not realize an increased market demand or better pricing terms for its services, RockPile does not expect to comply with all of the financial covenants contained in its credit facility throughout fiscal year 2017 unless those requirements are also waived or amended or unless RockPile can obtain new capital or cure financing. RockPile remains in discussions with its bank syndicate and various providers of external capital to refinance the existing indebtedness, but there are no guarantees these discussions or negotiations will be successful. If RockPile is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, RockPile’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable. If this happens, the Company does not currently have sufficient liquidity to make the RockPile equity cure and RockPile does not have sufficient cash on hand to repay this outstanding debt. Therefore, the consolidated balance sheet reflects all of the amounts outstanding under the RockPile credit facility as current liabilities as of January 31, 2016. RockPile could then be required to pursue in- and out-of-court restructuring transactions and Triangle could lose control of RockPile.

As a result, substantial doubt exists regarding the ability of RockPile, our oilfield services subsidiary, to continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. Triangle has not guaranteed RockPile’s obligations under the credit facility, and there are no

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cross-default provisions in Triangle’s or TUSA’s other debt agreements that could cause the acceleration of such indebtedness as a result of the RockPile credit facility default.

Triangle Liquidity. Triangle recently engaged certain professional advisors to assist it in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including: (i) obtaining waivers or amendments from RockPile’s and TUSA’s lenders; (ii) obtaining additional sources of capital from asset sales, issuances of debt or equity securities, debt for equity swaps, or any combination thereof; and (iii) pursuing in- and out-of-court restructuring transactions. In connection with a debt restructuring or refinancing, we may seek to convert a significant portion of our outstanding debt to equity, including the exchange of debt for shares of our common stock. In addition, we may seek to reduce our cash interest cost and extend debt maturity dates by negotiating the exchange of outstanding debt for new debt with modified terms or other measures. While we anticipate engaging in active dialogue with our creditors, at this time we are unable to predict the outcome of such discussions, the outcome of any strategic transactions that we may pursue or whether any such efforts will be successful.

Commodity Derivative Instruments

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

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 a $25.7 million deficit as of January 31, 2016, as compared to $57.1 million of working capital at January 31, 2015.

Off-Balance Sheet Arrangements

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

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Contractual Obligations as of January 31, 2016

The following table lists information with respect to our known contractual obligations as of January 31, 2016:

	Payments Due by Period
Contractual Obligations			Less than						More than
(in thousands)	Total		1 year		1 - 3 years		3 - 5 years		5 years
Office leases (a)	$	8,577	$	1,896	$	4,002	$	2,679	$	—
TUSA credit facilities (b)		243,772		—		243,772		—		—
TUSA 6.75% notes (c)		398,419		—		—		—		398,419
TUSA 6.75% notes interest (c)		174,850		26,900		53,800		53,800		40,350
Convertible note principal (d)		120,000		—		—		—		120,000
Convertible note interest (d)		22,799		—		—		—		22,799
Oilfield services (e)		43,805		7,580		13,177		9,752		13,296
RockPile credit facilities (f)		112,000		112,000		—		—		—
Other notes payable (g)		14,065		2,088		3,314		1,382		7,281
Midstream services (h)		303,351		36,644		65,421		48,719		152,567
Asset retirement obligations (i)		10,073		560		4,872		—		4,641
	$	1,451,711	$	187,668	$	388,358	$	116,332	$	759,353

(a) The Company leases office facilities in Denver, Colorado under operating lease agreements that expire in April 2020.

(b) Calculated based on our January 31, 2016 outstanding borrowings under the TUSA credit facility of $243.8 million and assumes no principal repayment until the maturity date of October 2018.

(c) Calculated based on our January 31, 2016 outstanding aggregate principal amount of the TUSA 6.75% Notes of $398.4 million and assumes no principal payments until July 2022. The interest on the TUSA 6.75% Notes is payable semi-annually in January and July each year until maturity of the notes.

(d) Calculated based on our January 31, 2016 outstanding aggregate principal amount of the Convertible Note with no stated maturity date. The interest on the Convertible Note is payable in kind and added to the principal balance of the note.

(e) As of January 31, 2016, RockPile had various commitments for future expenditures relating to equipment for transportation, transloading and storage of bulk commodities and light vehicles, (ii) transloading services and track rental and (iii) transportation equipment management, logistics and maintenance.

(f) Calculated based on outstanding principal borrowings of $112.0 million under RockPile’s credit facility which has a maturitydate of March 2019.The outstanding principal amount is classified as a current liability at January 31, 2016, as the financial covenants waiver pursuant to Amendment No. 2 does not provide covenant relief for all of fiscal year 2017. See Item 8. Consolidated Financial Statements and Supplementary Data.  

(g) Includes RockPile obligations relating to (i) seller financed notes payable associated with an acquisition and (ii) three notes payable associated with the redemption of B-1 Units.

(h) Amounts relate to agreements between TUSA and Caliber North Dakota described in Item 1.  “Business - Delivery Commitments.”

(i) Amounts represent our estimate of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.

As is customary in the oil and natural gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost.

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Impact of Inflation and Pricing

Triangle’s transactions are denominated in U.S. dollars. Inflation in the context of oilfield services and goods has historically been significant in the Williston Basin, the primary area in which Triangle operates. As prices for oil and natural gas increased, associated costs rose. However, in the second half of fiscal year 2015 and throughout fiscal year 2016, prices for oil and natural gas decreased dramatically, and associated costs declined as a result. Future higher prices for oil and natural gas may result in increases in the costs of materials, services and personnel. Changes in prices impact Triangle’s revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes also have the potential to affect Triangle’s ability to raise capital, borrow money, and retain personnel.

Critical Accounting Policies

Use of Estimates.The preparation of financial statements in conformity with GAAP requires us to make appropriate accounting estimates and to make estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. We consider our critical accounting policies and related estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and may differ materially from those estimates.

Full Cost Accounting Method.We use the full cost method of accounting for our oil and natural gas operations.All costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, internal costs directly related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized.Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and natural gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.

Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement obligations, are amortized over total estimated proved reserves. The capitalized costs of unproved properties, including those in connection with wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

Companies that follow the full cost method of accounting are required to make quarterly “ceiling test” calculations on country-wide cost pools. This test limits total capitalized costs for oil and natural gas properties (net of accumulated depreciation, depletion and amortization (“DD&A”) and deferred income taxes) to the sum of the present value (discounted at 10% per annum) of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproved properties included in the costs being amortized, and all related tax effects. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and natural gas properties is not reversible at a later date.

Full Cost Accounting’s Non-recognition of Service Income with Third Parties in Certain Circumstances.Both the successful efforts accounting method and the full cost accounting method require the elimination of revenue, cost of sales and gross profit for intercompany transactions in consolidated financial statements. Hence, upon consolidation, Triangle eliminates RockPile’s revenues, costs of sales and gross profit on a well to the extent of Triangle’s working interest in the well.

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Unlike the successful efforts accounting method, the full cost accounting method also restricts or eliminates recognition of service income with third parties in certain circumstances. The full cost accounting method’s Rule 4-10(c)(6)(iv)(C) is to be broadly applied such that Triangle may recognize no pressure pumping services income on behalf of third parties, as well as Triangle, with regard to a well operated by Triangle or a Triangle affiliate. If Triangle or a Triangle affiliate is the well’s operator, then no income earned on RockPile pressure pumping services for the well may be currently recognized in Triangle’s financial statements, regardless of how much economic interest Triangle may have in that well. Such income is credited to Triangle’s capitalized well costs and indirectly recognized later through a lower amortization rate as proved reserves are produced. Such income is pressure pumping revenue in excess of related expenses in providing pressure pumping services, including the portion of RockPile general and administrative expenses (i) identifiable with those pressure pumping services, and (ii) incurred in the period of service.

Where Triangle (or a Triangle affiliate) is not the well operator, the full cost accounting method’s Rule 4-10(c)(6)(iv)(A) restricts recognition of consolidated service income (such as pressure pumping) for a well to such income that exceeds Triangle’s share of costs incurred and estimated to be incurred in connection with the drilling and completion of the well, for Triangle’s related property interests acquired within the twelve-month period preceding engagement for the service. As a simplified example, if RockPile provides pressure pumping services on a well not operated by Triangle, but in which Triangle has a recently acquired 5% working interest for which Triangle’s share of well cost are $0.5 million (after elimination of consolidated intercompany profit), then Triangle cannot recognize the first $0.5 million of other pressure pumping income on the well. To the extent income cannot be currently recognized, Triangle charges such service income against service revenue and credits the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced.

Asset Retirement Obligations.We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and natural gas producing companies incur this liability in connection with costs related to the plugging of wells, the removal of facilities and equipment and site restorations upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period.Capitalized costs are depleted as a component of the full cost pool.

Estimates of Proved Oil and Natural Gas Reserves.Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. Changes in our estimates of proved reserve quantities will cause corresponding changes in amortization expense for the revision period and for periods thereafter as the reserves are produced. In some cases, a reduction in reserve estimates will lead to a full cost ceiling limitation charge in the period of the revision.

The process of estimating quantities of oil and natural gas reserves is complex, requiring significant decisions and judgments in the evaluation of available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and varying economic conditions, particularly as to the economic viability of proved undeveloped reserves in light of upfront development costs. As a result, material revisions to existing reserve estimates may occur from time to time.

At January 31, 2016, 21% of our total proved reserves were categorized as proved undeveloped. All of these proved undeveloped reserves are located in the Bakken Shale formation or Three Forks formation in North Dakota or Montana.We review and update our reserve estimates at least quarterly.

Commodity Derivatives.The Company has entered into commodity derivative instruments, primarily utilizing swaps or costless collars to reduce the effect of price changes on a portion of our future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the gain/loss on derivatives line on the consolidated statement of operations. We value our derivative instruments by obtaining independent market quotes, as well as using industry‑standard models that consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate. We utilize our valuations to assess the

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reasonableness of counterparties’ valuations. 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.

Equity Investment.Triangle accounts for its investment in Caliber using the equity method of accounting. The equity method of accounting requires the investor to recognize its share of the earnings and losses of the investee in the periods in which they are reflected in the accounts of the investee.

The Company holds Class A Warrants in Caliber. Our equity investment derivatives are measured at fair value and are included on the consolidated balance sheets as derivative assets. We estimate the fair value of our Caliber Class A Warrants using a Monte Carlo Simulation (“MCS”) model. For each MCS, the value of the Class A Units was forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly. At each reporting date, the fair value of the underlying Class A Units is estimated employing an income approach using a MCS model and discounted cash flows, and a market approach based on observed valuation multiples for comparable public companies. Net gains and losses on equity investment derivatives are recorded based on the changes in the fair values of the derivative instruments and included in our consolidated statements of operations.

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. The effects of commodity prices and development activities by exploration and production companies have a significant impact on the fair value of our investment in Caliber.Determining whether an impairment is other than temporary requires consideration of factors such as the length of time fair value has been less than carrying value and our intent and ability to recover the carrying amount of the investment.

Income Taxes.Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s consolidated financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense.

We assess quarterly the likelihood of realization of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as historical performance and future operating conditions (particularly as related to prevailing oil and natural gas prices).

Share-Based Compensation. Triangle recognizes compensation related to all equity-based awards in the consolidated financial statements based on their estimated grant-date fair value. We grant various types of equity-based awards including restricted stock units and stock options at Triangle, and restricted units at RockPile (“Series B Units”).The fair value of stock option and Series B Unit awards is determined using the Black-Scholes option pricing model.Service-based restricted stock units are valued using the market price of our common stock on the grant date.Compensation cost is recognized ratably on a straight-line basis over the applicable vesting period.

RevenueRecognition.All revenue is recognized when persuasive evidence of an arrangement exists, the service is complete, or the amount is fixed or determinable and collectability is reasonably assured, as follows:

Oil and Natural Gas Revenue.The Company recognizes revenues from the sale of crude oil and natural gas using the sales method of accounting. Revenues from the sale of crude oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title and risk of ownership have transferred and collectability is reasonably assured.

Oilfield Services Revenue.The Company enters into arrangements with its customers to provide hydraulic fracturing and other services, which can be either on a spot market basis or under term contracts. We only enter into arrangements

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with customers for which we believe that collectability is reasonably assured. Revenue is recognized upon the completion of each job.

Intercompany revenues are eliminated in the consolidated financial statements, and under certain circumstances, service revenue is reduced when service income cannot be recognized under full cost accounting as discussed above.

PV-10.  The pre-tax present value of future net cash flows, or PV-10, is a non-GAAP measure because it excludes income tax effects. Management believes that pre-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company's unique tax position and strategies, can make after-tax amounts less comparable. We derive PV-10 based on the present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs and future plugging and abandonment costs, using the twelve-month unweighted arithmetic average of the first of the month prices without giving effect to hedging activities or future escalation, costs as of the date of estimate without future escalation, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization and impairment and income taxes, and discounted using an annual discount rate of 10%. The following table reconciles the Standardized Measure of future net cash flows to PV-10 as of the dates shown (in thousands):

	For the Years Ended January 31,
(in thousands)	2014 (1)		2015 (2)		2016 (3)
Standardized Measure, for total proved reserves	$	573,235	$	821,492	$	328,784
Add back: Discounting at 10% per annum		690,564		977,088		307,649
Future cash flows, after income taxes		1,263,799		1,798,580		636,433
Add: future undiscounted income taxes		364,340		394,538		—
Undiscounted future net cash flows before taxes		1,628,139		2,193,118		636,433
Less: Discounting at 10% per annum		(950,234)		(1,210,305)		(307,649)
PV-10 Value of total proved oil and natural gas reserves	$	677,905	$	982,813	$	328,784

(1) Unescalated twelve month unweighted arithmetic average of the first day of the month posted prices of $97.49 per Bbl for oil, $54.25 per Bbl for natural gas liquids and $3.73 per MMbtu for natural gas were adjusted for quality, energy content, transportation fees and regional price differentials to arrive at realized prices of $93.09 per Bbl for oil, $44.10 per Bbl for natural gas liquids and $3.99 per MMbtu for natural gas, which were used in the determination of proved reserves at January 31, 2014.

(2) Unescalated twelve month unweighted arithmetic average of the first day of the month posted prices of $91.22 per Bbl for oil, $50.07 per Bbl for natural gas liquids and $4.20 per MMbtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $79.71 per Bbl for oil, $34.61 per Bbl for natural gas liquids and $6.09 per MMbtu for natural gas, which were used in the determination of proved reserves at January 31, 2015.

(3) Unescalated twelve month unweighted arithmetic average of the first day of the month posted prices of $48.93 per Bbl for oil, $24.97 per Bbl for natural gas liquids and $2.53 per MMbtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $38.41 per Bbl for oil, $2.45 per Bbl for natural gas liquids and $0.55 per MMbtu for natural gas, which were used in the determination of proved reserves at January 31, 2016.

Recently Issued Accounting Pronouncements. For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to the “Summary of Significant Accounting Policies” footnote in the notes to consolidated financial statements.

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ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk.  Our primary market risk is related to changes in oil prices. The market price of oil has been highly volatile and is likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. We  primarily utilize swaps and costless collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes.

We may 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 on a monthly basis. When the settlement price (the market price for oil or natural gas during the settlement period) 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 six counterparties. The Company has a netting arrangement with each counterparty that provides for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparty. The derivative contracts may be terminated by a non-defaulting party in the event of a 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 prices and to manage its exposure to commodity price risk. While the use of these derivative instruments reduces 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 forecasted production, restructure or reduce 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 January 31, 2016 are summarized below:

				Weighted		Weighted		Weighted
	Contract		Quantity	Average		Average		Average
	Type	Basis (1)	(Bbl/d)	Put Strike		Call Strike		Price
February 1, 2016 to January 31, 2017	Swap	NYMEX	2,175		n/a		n/a	$	56.13
February 1, 2017 to January 31, 2018	Swap	NYMEX	2,745		n/a		n/a	$	53.36

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

We have elected not to apply cash flow hedge accounting to any of our derivative transactions and we therefore recognize mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.

All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of derivatives are recorded in commodity derivative (gains) losses on the consolidated statements of operations. As of January 31, 2016, the fair value of our commodity derivatives was a net asset of $21.4 million. An assumed increase of 10% in the forward commodity prices used in the January31, 2016 valuation of our derivative instruments would result in a net derivative asset of approximately $13.8 million at January 31, 2016. Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $29.0 million at January31, 2016.  

Interest Rate Risk.  As of January 31, 2016, we had $350.0 million of borrowing availability under the TUSA credit facility, of which $243.8 million was drawn.  On March 31, 2016, TUSA borrowed $103.7 million under its credit facility, representing the entire amount remaining thereunder relative to the current borrowing base. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at January 31, 2016 under the TUSA credit facility of $350.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $3.5 million.

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As of January 31, 2016, RockPile had an aggregate of $150.0 million available for borrowing under its credit facility of which $112.0 million of principal was outstanding as of such date. The credit facility bears interest at variable rates. Assuming RockPile had the maximum amount outstanding at January 31, 2016 under the credit facility of $150.0 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $1.5 million.

The TUSA 6.75% Notes and the Convertible Note bear interest at fixed rates.

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ITEM 8.  CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	62
Consolidated Balance Sheets as of January 31, 2015 and 2016	63
Consolidated Statements of Operations for the years ended January 31, 2014, 2015 and 2016	65
Consolidated Statements of Cash Flows for the years ended January 31, 2014, 2015 and 2016	66
Consolidated Statement of Stockholders’ Equity (Deficit) for the years ended January 31, 2014, 2015 and 2016	67
Notes to Consolidated Financial Statements	68

All supplementary data is either omitted as not applicable or the information required is shown in the consolidated financial statements or related notes thereto.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Triangle Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Triangle Petroleum Corporation and subsidiaries (the Company) as of January 31, 2015 and 2016, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the years in the three-year period ended January 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Triangle Petroleum Corporation and subsidiaries as of January 31, 2015 and 2016, and the results of their operations and their cash flows for each of the years in the three‑year period ended January 31, 2016, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in note 2 to the consolidated financial statements, significant decreases in oil and natural gas commodity prices have resulted in losses from subsidiary operations. Such losses have resulted in current and projected subsidiary debt covenant violations, including current violations at RockPile Energy Services, LLC rendering the outstanding balance of its credit facility to be classified as a current liability. The Company does not have sufficient liquidity to meet this obligation, if called by the lenders. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Triangle Petroleum Corporation’s internal control over financial reporting as of January 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated April 13, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

(signed) KPMG LLP

Denver, Colorado
April13, 2016

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Triangle Petroleum Corporation

Consolidated Balance Sheets

(In thousands, except share data)

	January 31, 2015		January 31, 2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	67,871	$	115,769
Accounts receivable		171,911		53,302
Commodity derivatives		54,775		12,370
Other current assets		14,952		10,046
Total current assets		309,509		191,487
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and natural gas properties, full cost method of accounting
Proved properties		1,159,584		1,372,480
Unproved properties and properties under development, not being amortized		142,896		78,367
Total oil and natural gas properties		1,302,480		1,450,847
Accumulated amortization		(176,390)		(1,044,307)
Net oil and natural gas properties		1,126,090		406,540
Oilfield services equipment, net		87,549		48,445
Other property and equipment, net		47,367		42,874
Net property, plant and equipment		1,261,006		497,859
OTHER ASSETS
Equity investment		64,411		45,600
Commodity derivatives		—		9,012
Debt issuance costs		4,209		3,877
Other		5,906		5,313
Total other assets		74,526		63,802
Total assets	$	1,645,041	$	753,148

See notes to consolidated financial statements.

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Triangle Petroleum Corporation

Consolidated Balance Sheets

(In thousands, except share data)

	January 31, 2015		January 31, 2016
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued capital expenditures	$	176,182	$	67,339
Other accrued liabilities		73,440		34,065
Current portion of long-term debt		503		114,088
Interest payable		2,250		1,700
Total current liabilities		252,375		217,192
LONG-TERM LIABILITIES
Long-term debt		789,809		789,043
Deferred income taxes		53,441		—
Other		4,398		11,495
Total liabilities		1,100,023		1,017,730
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,174,442 and 75,807,111 shares issued and outstanding at January 31, 2015 and January 31, 2016, respectively		1		1
Additional paid-in capital		545,017		557,757
Retained earnings (accumulated deficit)		—		(822,340)
Total stockholders' equity (deficit)		545,018		(264,582)
Total liabilities and stockholders’ equity (deficit)	$	1,645,041	$	753,148

See notes to consolidated financial statements.

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Triangle Petroleum Corporation

Consolidated Statements of Operations

(In thousands, except per share data)

	For the Years Ended January 31,
	2014		2015		2016
REVENUES:
Oil, natural gas and natural gas liquids sales	$	160,548	$	284,502	$	181,228
Oilfield services		98,199		288,453		176,901
Total revenues		258,747		572,955		358,129
EXPENSES:
Lease operating expenses		14,454		25,703		41,504
Gathering, transportation and processing		4,302		18,520		25,910
Production taxes		18,006		29,774		17,491
Depreciation and amortization		58,011		124,055		121,374
Impairment of oil and natural gas properties		—		—		779,000
Impairment of long lived assets		—		—		14,900
Accretion of asset retirement obligations		56		167		376
Oilfield services		82,327		216,596		163,452
General and administrative, net of amounts capitalized		34,629		62,757		62,305
Total operating expenses		211,785		477,572		1,226,312
INCOME (LOSS) FROM OPERATIONS		46,962		95,383		(868,183)
OTHER INCOME (EXPENSE):
Interest expense, net		(7,132)		(25,100)		(38,706)
Amortization of debt issuance costs		(554)		(3,149)		(3,180)
Gain on extinguishment of debt		—		6,610		17,927
Realized commodity derivative gains (losses)		(4,643)		11,422		71,940
Unrealized commodity derivative gains (losses)		5,725		52,628		(33,393)
Equity investment income (loss)		—		81		1,887
Impairment of equity investment		—		—		(24,979)
Gain (loss) on equity investment derivatives		39,785		553		3,098
Other income (expense), net		1,278		469		(2,148)
Total other income (expense)		34,459		43,514		(7,554)
INCOME (LOSS) BEFORE INCOME TAXES		81,421		138,897		(875,737)
INCOME TAX PROVISION (BENEFIT)		7,941		45,500		(53,397)
NET INCOME (LOSS)	$	73,480	$	93,397	$	(822,340)
Earnings (loss) per common share outstanding:
Basic	$	1.07	$	1.12	$	(10.89)
Diluted	$	0.91	$	0.97	$	(10.89)
Weighted average common shares outstanding:
Basic		68,579		83,611		75,502
Diluted		84,558		101,032		75,502

See notes to consolidated financial statements.

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Triangle Petroleum Corporation

Consolidated Statements of Cash Flows

(In thousands)

	For the Years Ended January 31,
		2014	2015		2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	73,480	$	93,397	$	(822,340)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion		58,067		124,222		121,750
Impairment of oil and natural gas properties		—		—		779,000
Impairment of long lived assets		—		—		14,900
Share-based compensation		7,830		7,919		17,394
Interest expense paid-in-kind on 5% convertible note		6,267		6,587		6,922
Amortization of debt issuance costs		554		3,149		3,180
Gain on extinguishment of debt		—		(6,610)		(17,927)
Unrealized commodity derivative (gains) losses		(5,725)		(52,628)		33,393
Equity investment (income) loss		—		(81)		(1,887)
Gain on equity investment derivatives		(39,785)		(553)		(3,098)
Impairment of investment in Caliber		—		—		24,979
Deferred income taxes		7,941		45,500		(53,441)
Other		(1,040)		—		1,067
Changes in related current assets and current liabilities:
Accounts receivable		(65,929)		(65,448)		118,609
Other current assets		(3,579)		(9,926)		4,588
Accounts payable and accrued liabilities		44,840		57,233		(61,181)
Asset retirement expenditures		(484)		(2,206)		(1,526)
Other		(1)		262		652
Cash provided by operating activities		82,436		200,817		165,034
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures		(279,531)		(359,102)		(231,238)
Acquisitions of oil and natural gas properties		(121,578)		(138,778)		(810)
Purchases of oilfield services equipment		(27,414)		(59,624)		(8,478)
Purchases of other property and equipment		(10,928)		(26,739)		(5,112)
Sale of oil and natural gas properties		—		1,500		6,000
Acquisition of oilfield services companies		(7,715)		—		—
Proceeds from sale of equipment		—		—		7,804
Equity investment in Caliber Midstream Partners, L.P.		(18,000)		—		—
Equity investment cash distribution		3,150		6,080		—
Sale of marketable securities		6,105		—		—
Other		345		(356)		—
Cash used in investing activities		(455,566)		(577,019)		(231,834)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities		211,820		504,159		320,789
Repayments of credit facilities		(32,306)		(484,515)		(189,176)
Proceeds from notes payable		14,430		451,568		4,032
Repayments of other notes and mortgages payable		(5,876)		(416)		(631)
Early extinguishment of repurchased debt		—		(13,890)		(13,154)
Debt issuance costs		(2,706)		(13,980)		(943)
Proceeds from issuance of common stock		245,369		—		—
Stock offering costs		(7,072)		—		—
Payments to settle tax on vested restricted stock units		(2,058)		(2,854)		(861)
Issuance of common stock on exercise of options		162		135		—
Distributions to RockPile B Unit holders		—		—		(4,329)
Purchase of vested RockPile B Units from unit holders		—		(1,041)		(1,029)
Common stock repurchased and retired		—		(76,843)		—
Cash provided by financing activities		421,763		362,323		114,698
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS		48,633		(13,879)		47,898
CASH AND EQUIVALENTS, BEGINNING OF PERIOD		33,117		81,750		67,871
CASH AND EQUIVALENTS, END OF PERIOD	$	81,750	$	67,871	$	115,769

See notes to consolidated financial statements.

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Triangle Petroleum Corporation

Consolidated Statement of Stockholders’ Equity (Deficit)

(in thousands, except share data)

						Retained		Total
	Shares of	Common		Additional		Earnings		Stockholders'
	Common	Stock at		Paid-in		(Accumulated		Equity
	Stock	Par Value		Capital		Deficit)		(Deficit)
Balance - January 31, 2013	46,733,011	$	1	$	323,641	$	(122,020)	$	201,622
Shares issued	37,905,000		—		245,369		—		245,369
Stock offering costs	—		—		(7,072)		—		(7,072)
Shares issued for the purchase of oil and natural gas properties	325,000		—		2,438		—		2,438
Vesting of restricted stock units (net of shares surrendered for taxes)	664,483		—		(2,058)		—		(2,058)
Exercise of stock options	108,333		—		162		—		162
Share-based compensation	—		—		9,221		—		9,221
Net income for the period	—		—		—		73,480		73,480
Balance - January 31, 2014	85,735,827	$	1	$	571,701	$	(48,540)	$	523,162
Vesting of restricted stock units (net of shares surrendered for taxes)	762,026		—		(2,854)		—		(2,854)
Redeemed RockPile B Units	—		—		(1,041)		—		(1,041)
Shares repurchased and retired	(11,431,744)		—		(31,986)		(44,857)		(76,843)
Exercise of stock options	108,333		—		135		—		135
Share-based compensation	—		—		9,062		—		9,062
Net income for the period	—		—		—		93,397		93,397
Balance - January 31, 2015	75,174,442	$	1	$	545,017	$	—	$	545,018
Vesting of restricted stock units (net of shares surrendered for taxes)	632,669		—		(861)		—		(861)
Share-based compensation	—		—		18,959		—		18,959
Distributions to RockPile B Unit holders	—		—		(4,329)		—		(4,329)
Purchase of vested RockPile B Units from unit holders	—		—		(1,029)		—		(1,029)
Net income (loss) for the period	—		—		—		(822,340)		(822,340)
Balance - January 31, 2016	75,807,111	$	1	$	557,757	$	(822,340)	$	(264,582)

See notes to consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  DESCRIPTION OF BUSINESS

Triangle Petroleum Corporation (“Triangle,” the “Company,” “we,” “us,” “our,” or “ours”) is an 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 predominantly located in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana. 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 predominantly 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. Caliber was formed for the purpose of providing oil, natural gas and water transportation and related services to oil and natural gas exploration and production companies in the Williston Basin.

The Company, through its wholly-owned subsidiary, Elmworth Energy Corporation (“Elmworth”), previously conducted insignificant exploration and production activities in Canada. Elmworth has since sold all leasehold interests except for acreage in the Maritimes Basin of Nova Scotia. Elmworth has ceased all exploration and production activities in Canada except for reclaiming five wells, the drilling site and brine ponds on its Nova Scotia acreage. Elmworth has no proved reserves and its oil and natural gas properties were fully impaired as of January 31, 2012.

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation. These consolidated financial statements and related notes are presented 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 (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the Securities and Exchange Commission (“SEC”), and (ii) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and other disclosed amounts.

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

Liquidity and Ability to Continue as a Going Concern. The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.

Although the Company is continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations, its liquidity outlook has changed since the third quarter of fiscal year 2016. Continued low commodity prices are expected to result in significantly lower levels of cash flow from operating activities in the future and have limited the Company’s ability to access capital markets. These factors and theRockPile debt compliance issues raise substantial doubt about the Company’s ability to continue as a going concern.

RockPile Liquidity and Covenants.  On April 13, 2016, RockPile entered into Amendment No. 2 to the Credit Agreement (“Amendment No. 2”), which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 or may occur as of April 30, 2016. Following the execution of Amendment No. 2, RockPile is precluded from drawing additional funds absent further amendment of the facility. Beginning with the second

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quarter and for the remainder of fiscal year 2017, RockPile does not expect to comply with all of the financial covenants contained in its credit facility unless those requirements are also waived or amended or unless RockPile can obtain new capital or equity cure financing as discussed further in Note 4. RockPile remains in discussions with its bank syndicate and various providers of external capital to refinance the existing indebtedness, but the success of these discussions and negotiations is uncertain. In addition, if RockPile is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, RockPile’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable. If this happens, the Company does not currently have sufficient liquidity to make the equity cure and RockPile does not have sufficient cash on hand to repay this outstanding debt. Therefore, the consolidated balance sheet reflects all of the amounts outstanding under the RockPile credit facility as current liabilities as of January 31, 2016. RockPile could then be required to pursue in- and out-of-court restructuring transactions and Triangle could lose control of RockPile.

As a result, substantial doubt exists regarding the ability of RockPile, our oilfield services subsidiary, to continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. Triangle has not guaranteed RockPile’s obligations under the credit facility, and there are no cross-default provisions in Triangle’s or TUSA’s other debt agreements that could cause the acceleration of such indebtedness as a result of the RockPile credit facility default.

TUSA Liquidity and Covenants. As of January 31, 2016, TUSA had $243.8 million drawn, plus an additional $2.5 million outstanding in letters of credit, resulting in remaining available borrowing capacity of $103.7 million under the TUSA credit facility. On March 31, 2016, TUSA borrowed $103.7 million under its credit facility, representing the entire amount remaining thereunder relative to the current borrowing base of $350.0 million. As a result, no further extensions of credit currently are available under the TUSA credit agreement.

As of January 31, 2016, TUSA was in compliance with all financial covenants under the TUSA credit facility. Although it is difficult to forecast future operations in this low commodity price environment, TUSA anticipates that it could breach its ratio of consolidated debt to EBITDA or its interest coverage ratio covenants (as defined in the credit agreement) in fiscal year 2017 if commodity prices do not recoveror it is unable to obtain cure financing or a waiver or amendment from its lenders, with whom it is engaged in ongoing discussions. Also, the current ratio covenant could be adversely impacted if a redetermination significantly lowers the borrowing base. If TUSA were to breach a covenant in a future period, TUSA has a cure right to obtain a cash capital contribution from Triangle or another investor approved by Triangle on or before ten days following the date that its compliance certificates are due (45 days after quarter ends and 90 days after its fiscal year end) to cure such a breach, also known as an equity cure. Although there are many risks and uncertainties in this environment, TUSA believes that it will be able to reach an agreement with its banks, find acceptable alternative financing or obtain equity cure contributions to prevent or cure an event of default under its credit facility. However, there can be no assurances that these plans can be achieved. If TUSA were to breach any financial covenants under its credit facility and such breach became an event of default, there are cross-default provisions in the Indenture of the TUSA 6.75% Notes (as defined below) that could enable holders of the TUSA 6.75% Notes to declare some or all of the amounts outstanding under the TUSA 6.75% Notes to be immediately due and payable.

While we believe our existing capital resources, including our cash flow from TUSA’s operations and cash on hand at TUSA and Triangle, are sufficient to conduct our operations of TUSA and Triangle through fiscal year 2017 and into fiscal year 2018, there are certain risks arising from depressed oil and natural gas prices and declines in production volumes that could impact our liquidity and ability to meet debt covenants in future periods. Our ability to maintain compliance with our debt covenants may be negatively impacted if oil and natural gas prices remain depressed for an extended period of time. Further, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. Accordingly, our ability to effectively execute our corporate strategies and manage our operating, general and administrative expenses and capital expenditure programs is critical to our financial condition, liquidity and our results of operations.

If we are not able to meet our debt covenants in future periods, or if our borrowing base is significantly reduced, we may be required but unable to refinance or restructure all or part of our existing debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all, and may be required to surrender assets pursuant to the security provisions of the TUSA credit facility. Further, failing to comply with the financial and other restrictive covenants in the TUSA credit

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facility and the TUSA 6.75% Notes could result in an event of default, which could adversely affect our business, financial condition and results of operations.

Triangle Liquidity. Triangle recently engaged certain professional advisors to assist it in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including: (i) obtaining waivers or amendments from RockPile’s and TUSA’s lenders; (ii) obtaining additional sources of capital from asset sales, issuances of debt or equity securities, debt for equity swaps, or any combination thereof; and (iii) pursuing in- and out-of-court restructuring transactions. In connection with a debt restructuring or refinancing, we may seek to convert a significant portion of our outstanding debt to equity, including the exchange of debt for shares of our common stock. In addition, we may seek to reduce our cash interest cost and extend debt maturity dates by negotiating the exchange of outstanding debt for new debt with modified terms or other measures. While we anticipate engaging in active dialogue with our creditors, at this time we are unable to predict the outcome of such discussions, the outcome of any strategic transactions that we may pursue or whether any such efforts will be successful.

Use of Estimates. In the course of preparing its consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of unproved properties, investment in equity method investees and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables; (vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued expenses and related liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these consolidated financial statements.

Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying consolidated financial statements. All significant 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% and 50% and exercises significant influence. The investment in Caliber is accounted for utilizing the equity method of accounting.

Cash and Cash Equivalents. Cash and cash equivalents, including cash in banks in the United States and Canada, consist of highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased.

Accounts Receivable and Credit Policies. The components of accounts receivable include the following (in thousands):

	For the Years Ended January 31,
		2015		2016
Oil and natural gas sales	$	21,445	$	11,432
Joint interest billings		72,354		25,820
Oilfield services revenue		59,408		11,920
Other		18,704		4,130
Total accounts receivable	$	171,911	$	53,302

The Company’s accounts receivable result primarily from (i) oil and natural gas purchasers, (ii) billings to joint working interest partners in properties operated by the Company and (iii) trade receivables for oilfield services revenue. The Company’s trade and accrued revenue receivables are dispersed among various customers and purchasers and most of the Company’s significant purchasers are large companies with strong credit ratings. If customers are considered a credit risk, letters of credit or parental guarantees are the primary security obtained to support the extension of credit. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues.

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The following table provides the percentage of revenue derived from oil and natural gas sales to customers and oilfield services customers who comprise 10% or more of the Company’s consolidated annual revenue (the customers in each year are not necessarily the same from year to year):

	For the Years Ended January 31,
	2014		2015		2016
Oil & Gas Customer A		22%		13%		N/A
Oil & Gas Customer B		15%		12%		10%
Oil & Gas Customer C		N/A		12%		N/A
Oilfield Services Customer A		N/A		15%		N/A
Oilfield Services Customer B		13%		12%		N/A
Oilfield services Customer C		N/A		N/A		16%
Oilfield services Customer D		N/A		N/A		11%

Although a substantial portion of our oil and natural gas sales and our oilfield services revenues may be to a few large customers, we do not believe the loss of any one customer would have a material adverse effect on our exploration and production business as we believe that other purchasers would be available. The loss of any significant oilfield services customer is detrimental to RockPile during this low price competitive pressure pumping and oilfield services environment but would not be expected to have a material adverse effect on the Company.

Inventories. Inventories, included in other current assets, consist of well equipment, sand, chemicals and ceramic proppant for hydraulic pressure pumping and complementary well completion services. Inventories are stated at the lower of cost or market (net realizable value) on an average cost basis with consideration given to deterioration, obsolescence and other factors utilized in evaluating net realizable value.

Oil and Natural Gas Properties. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the amortizable pool of proved properties or in unproved properties, collectively, the full cost pool. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and natural gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.

The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Under the full cost method of accounting, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced.

Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. Depreciation and amortization expense of oil and natural gas properties in the U.S. for fiscal years 2014, 2015 and 2016 was $52.0 million, $106.9 million and $90.4 million, respectively.

At the end of each quarterly period, we must compute a limitation on capitalized costs, which is equal to the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC (unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve

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months), less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. We then conduct a “ceiling test” that compares the net book value of the full cost pool, after taxes, to the full cost ceiling limitation. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties.

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.

	January 31, 2014		January 31, 2015		January 31, 2016
Oil (per Bbl)	$	97.49	$	91.22	$	48.93
Natural gas (per MMbtu)	$	3.73	$	4.20	$	2.53
Natural gas liquids (per Bbl)	$	54.25	$	50.07	$	24.97

We recognized impairments to our proved oil and natural gas properties of $779.0 million for the year ended January 31, 2016, primarily due to the decline in oil, natural gas and natural gas liquids prices. We did not recognize impairments to our proved oil and natural gas properties for the years ended January 31, 2014 and 2015. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further. The amount of any future impairment is difficult to predict, and will depend, in part, upon future oil, natural gas and natural gas liquids (“NGL”) prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. The ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity. Any recorded impairment of oil and natural gas properties is not reversible at a later date.

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

Oil and Natural Gas Reserves.Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. Changes in our estimates of proved reserve quantities will cause corresponding changes in amortization expense for the revision period and for periods thereafter as the reserves are produced. In some cases, a reduction in reserve estimates will lead to a full cost ceiling limitation charge in the period of the revision. The process of estimating quantities of oil and natural gas reserves is complex, requiring significant decisions and judgments in the evaluation of available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and varying economic conditions, particularly as to the economic viability of proved undeveloped reserves in light of upfront development costs. As a result, material revisions to existing reserve estimates may occur from time to time.

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Oilfield Services Equipment and Other Property and Equipment.  Oilfield services equipment and other property and equipment consisted of the following as of:

(in thousands)	January 31, 2015		January 31, 2016
Oilfield services equipment	$	105,938	$	110,992
Accumulated depreciation		(28,805)		(63,367)
Depreciable assets, net		77,133		47,625
Assets not placed in service		10,416		820
Total oilfield services equipment, net	$	87,549	$	48,445
Land	$	7,888	$	6,838
Building and leasehold improvements		33,625		37,149
Vehicles		4,811		5,036
Software, computers and office equipment		5,327		7,451
Capital leases		853		944
Accumulated depreciation		(6,384)		(14,939)
Depreciable assets, net		46,120		42,479
Assets not placed in service		1,247		395
Total other property and equipment, net	$	47,367	$	42,874

Impairment of Long-Lived Assets.Long‑lived assets such as property and equipment and identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long‑lived asset or asset group be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long‑lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined using various valuation techniques including discounted cash flow models, quoted market values, and third‑party independent appraisals, as considered necessary. No impairment losses were recognized in fiscal years 2014 and 2015 and an impairment loss of $14.9 million, primarily related to oilfield services equipment, was recorded in fiscal year 2016.

Debt Issuance Costs. Debt issuance costs related to the TUSA 6.75% Notes and the Convertible Note, each as defined below, are included as a deduction from the carrying amount of long-term debt in the consolidated balance sheets, and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are included in other long-term assets, and are amortized to interest expense on a straight-line basis over the term of the agreement.

Equity Investment. The Company accounts for its investments in unconsolidated entities by the equity method. The Company’s share of earnings (loss) in the unconsolidated entity is included in other income (loss) on the consolidated statements of operations after elimination of intra-company profits and losses. The Company records losses of the unconsolidated entities only to the extent of the Company’s investment.

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

Asset Retirement Obligations. We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and natural gas producing companies incur this liability for their working interest in a well at the time the well is drilled or acquired. The liability reflects a discounted present value of estimated future costs related to the plugging of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool amortization base.

Derivative Instruments. The Company enters into derivative contracts, primarily costless collars and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative

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instruments are recorded on the balance sheet at fair value. The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges.

The Company holds equity investment derivatives (Class A Warrants) in Caliber. Our equity investment derivatives are measured at fair value and are included in equity investment on the consolidated balance sheet. Net gains and losses on equity investment derivatives are recorded based on the changes in the fair values of the derivative instruments and included in our consolidated statements of operations.

Income Taxes. Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company’s policy is to recognize interest and penalties related to uncertain tax positions in interest expense.

Oil, Natural Gas and Natural Gas Liquids Revenue.The Company recognizes revenues from the sale of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price, title has transferred, and/or collectability is reasonably assured and evidenced by a contract. There were no oil or natural gas sales imbalances at January 31, 2015 and 2016.

Oilfield Services Revenue.  The Company enters into arrangements with its customers to provide hydraulic fracturing services and other oilfield services, which can be either on a spot market basis or under term contracts. We only enter into arrangements with customers for which we believe collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on agreed-upon market rates.

Share-Based Compensation. Share-based compensation is measured at the estimated grant date fair value of the awards and is recognized on a straight-line basis over the vesting period. The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered.

Earnings per Share. Basic earnings per common share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted earnings per common share reflects increases in average shares outstanding from the potential dilution, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for 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

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future compensation expense of hypothetical early vesting of the outstanding restricted stock units. The assumed proceeds are adjusted for income tax effects. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive.

The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented:

	For the Years Ended January 31,
(in thousands)	2014		2015		2016
Dilutive		15,979		17,421		—
Anti-dilutive shares		5,250		6,905		10,156

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the periods presented:

	For the Years Ended January 31,
(in thousands, except per share data)	2014		2015		2016
Net income (loss) attributable to common stockholders	$	73,480	$	93,397	$	(822,340)
Effect of 5% convertible note conversion		3,392		4,135		—
Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion	$	76,872	$	97,532	$	(822,340)
Basic weighted average common shares outstanding		68,579		83,611		75,502
Effect of dilutive securities		15,979		17,421		—
Diluted weighted average common shares outstanding		84,558		101,032		75,502
Basic net income (loss) per share	$	1.07	$	1.12	$	(10.89)
Diluted net income (loss) per share	$	0.91	$	0.97	$	(10.89)

Adopted and Recently Issued Accounting Pronouncements.  In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014‑09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, however, in August 2015, the FASB issued Accounting Standards Update No. 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date (“ASU 2015-14”), which deferred the effective date of ASU 2014‑09 for one year. ASU 2015-14 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company is currently evaluating the impact of adopting ASU 2014‑09 and ASU 2015-14, including the transition method to be applied, however the standards are not expected to have a significant effect on its consolidated financial statements.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s consolidated financial statements.

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”). This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a Company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings.

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ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, should be applied retrospectively and represent a change in accounting principle. Early adoption is permitted. The Company adopted ASU 2015-03 and ASU 2015-15 as of January 31, 2016, and as a result, $9.8million of debt issuance costs related to the TUSA 6.75% Notes and the Convertible Note were reclassified from other long-term assets to long-term debt in the Company’s consolidated balance sheet as of January 31, 2015. The Company elected to continue presenting the debt issuance costs associated with its credit facility as other long-term assets in the consolidated balance sheets. 

In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”). This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively. Early adoption is permitted. The adoption of this standard will not have a material impact on the Company’s consolidated financial statements.

In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). This ASU eliminates the requirement to retrospectively apply measurement-period adjustments made to provisional amounts recognized in a business combination. Under ASU 2015-16, the cumulative impact of a measurement-period adjustment (including the impact on prior periods) should instead be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. This standard should be applied prospectively, and early adoption is permitted. The adoption of this standard is not expected to have a significant impact on the Company’s consolidated financial statements.

In November 2015, the FASB issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). The objective of this ASU is to simplify the financial statement presentation of deferred taxes by presenting both current and noncurrent deferred tax assets and liabilities as noncurrent on the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. This standard may be applied either prospectively or retrospectively to all periods presented, and early adoption is permitted. The Company adopted ASU 2015-17 as of January 31, 2016 on a retrospective basis, which represents a change in accounting principle. As a result, $19.5million of deferred income taxes previously included within current liabilities were reclassified to noncurrent in the Company’s consolidated balance sheet as of January 31, 2015.

In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU No. 2016-02”). The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after Dec. 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-02 on its financial position and results of operations.

Reclassifications.  Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.

3.  SEGMENT REPORTING

We conduct our operations within two reportable operating segments. We identified each segment based on management’s responsibility and the nature of their products, services, and costs. There are no major distinctions in geographical areas served as nearly all operations are in the Williston Basin of the United States. The Exploration and Production operating segment, consisting of TUSA and several insignificant oil and natural gas subsidiaries, is responsible for finding and producing oil and natural gas. The Oilfield Services segment, consisting of RockPile and its subsidiaries, is responsible for a variety of oilfield and well completion services for both TUSA-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 years ended January 31, 2016, 2015 and 2014:

	For the Year Ended January 31, 2016
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	181,228	$	—	$	—	$	—	$	181,228
Oilfield services for third parties		—		177,342		—		(441)		176,901
Intersegment revenues		—		32,776		—		(32,776)		—
Total revenues		181,228		210,118		—		(33,217)		358,129
Expenses:
Lease operating and production taxes		58,995		—		—		—		58,995
Gathering, transportation and processing		25,910		—		—		—		25,910
Depreciation and amortization		91,213		32,365		1,565		(3,769)		121,374
Impairments		779,000		13,758		1,142		—		793,900
Accretion of asset retirement obligations		376		—		—		—		376
Oilfield services		—		184,094		—		(20,642)		163,452
General and administrative, net of amounts capitalized:
Salaries and benefits		1,161		16,648		10,432		—		28,241
Share-based compensation		1,537		805		15,052		—		17,394
Other general and administrative		3,375		8,268		5,027		—		16,670
Total operating expenses		961,567		255,938		33,218		(24,411)		1,226,312
Income (loss) from operations		(780,339)		(45,820)		(33,218)		(8,806)		(868,183)
Other income (expense)		25,400		(4,456)		(26,505)		(1,993)		(7,554)
Income (loss) before income taxes	$	(754,939)	$	(50,276)	$	(59,723)	$	(10,799)	$	(875,737)
As of January 31, 2016:
Cash and cash equivalents	$	47,997	$	32,850	$	34,922	$	—	$	115,769
Net oil and natural gas properties	$	492,120	$	—	$	—	$	(85,580)	$	406,540
Oilfield services equipment, net	$	—	$	48,445	$	—	$	—	$	48,445
Other property and equipment, net	$	9,030	$	17,638	$	16,206	$	—	$	42,874
Total assets	$	621,803	$	119,699	$	97,397	$	(85,751)	$	753,148
Total liabilities	$	719,626	$	140,855	$	157,420	$	(171)	$	1,017,730

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	For the Year Ended January 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	284,502	$	—	$	—	$		$	284,502
Oilfield services for third parties		—		294,526		—		(6,073)		288,453
Intersegment revenues		—		123,577		—		(123,577)		—
Total revenues		284,502		418,103		—		(129,650)		572,955
Expenses:
Lease operating and production taxes		55,477		—		—		—		55,477
Gathering, transportation and processing		18,520		—		—		—		18,520
Depreciation and amortization		116,633		22,008		921		(15,507)		124,055
Accretion of asset retirement obligations		167		—		—		—		167
Oilfield services		—		301,142		308		(84,854)		216,596
General and administrative, net of amounts capitalized:
Salaries and benefits		6,028		14,620		11,559		—		32,207
Share-based compensation		1,155		509		6,255		—		7,919
Other general and administrative		9,042		10,598		2,991		—		22,631
Total operating expenses		207,022		348,877		22,034		(100,361)		477,572
Income (loss) from operations		77,480		69,226		(22,034)		(29,289)		95,383
Other income (expense)		51,216		(3,027)		(2,353)		(2,322)		43,514
Income (loss) before income taxes	$	128,696	$	66,199	$	(24,387)	$	(31,611)	$	138,897
As of January 31, 2015:
Cash and cash equivalents	$	14,980	$	3,822	$	49,069	$	—	$	67,871
Net oil and natural gas properties	$	1,200,872	$	—	$	—	$	(74,782)	$	1,126,090
Oilfield services equipment, net	$	—	$	87,549	$	—	$	—	$	87,549
Other property and equipment, net	$	9,679	$	22,245	$	15,443	$	—	$	47,367
Total assets	$	1,399,482	$	202,648	$	131,107	$	(88,196)	$	1,645,041
Total liabilities	$	745,638	$	163,987	$	203,812	$	(13,414)	$	1,100,023

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	For the Year Ended January 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	160,548	$	—	$	—	$		$	160,548
Oilfield services for third parties		—		102,606		—		(4,407)		98,199
Intersegment revenues		—		91,019		—		(91,019)		—
Total revenues		160,548		193,625		—		(95,426)		258,747
Expenses:
Lease operating and production taxes		32,460		—		—		—		32,460
Gathering, transportation and processing		4,302		—		—		—		4,302
Depreciation and amortization		56,788		8,905		620		(8,302)		58,011
Accretion of asset retirement obligations		56		—		—		—		56
Oilfield services		—		142,339		—		(60,012)		82,327
General and administrative, net of amounts capitalized:
Salaries and benefits		3,541		6,894		6,864		—		17,299
Share-based compensation		1,127		590		6,113		—		7,830
Other general and administrative		3,939		4,222		1,339		—		9,500
Total operating expenses		102,213		162,950		14,936		(68,314)		211,785
Income (loss) from operations		58,335		30,675		(14,936)		(27,112)		46,962
Other income (expense)		(172)		(991)		38,998		(3,376)		34,459
Income (loss) before income taxes	$	58,163	$	29,684	$	24,062	$	(30,488)	$	81,421

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 of accounting, we defer recognition of oilfield services income (intersegment revenues less cost of oilfield services and related depreciation) for wells that we operate and this deferred income is credited to proved oil and natural gas properties. In addition, we eliminate our non-operating partners’ share of oilfield services income for well completion activities on properties we operate. We also defer Caliber gross profit from our share of its income associated with services it provided that were capitalized by TUSA, by charging such gross profit against income from equity investment and crediting proved oil and natural gas properties.

The above deferred income is indirectly recognized in future periods through a lower amortization rate as proved reserves are produced. For the years ended January 31, 2014, 2015 and 2016, $4.8 million, $9.6 million and $0.2 million, respectively, of the depreciation and amortization elimination relates to the Exploration and Production segment and the balance relates to the Oilfield Services segment.

These differences, as well as differing amounts for impairments, result in basis differences between the net oil and gas property amounts presented in Triangle’s financial statements compared to those presented in TUSA’s standalone financial statements.

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4.  LONG-TERM DEBT

The Company’s long-term debt consisted of the following as of January 31, 2015 and 2016:

(in thousands)	January 31, 2015		January 31, 2016
TUSA credit facility due October 2018	$	119,272	$	243,772
RockPile credit facility due March 2019		104,887		112,000
TUSA 6.75% notes due July 2022		429,500		398,419
5% convertible note		135,877		142,799
Other notes and mortgages payable		10,605		14,065
Total principal		800,141		911,055
Debt issuance costs		(9,829)		(7,924)
Total debt		790,312		903,131
Less current portion of debt:
RockPile credit facility		—		(112,000)
Other notes and mortgages payable		(503)		(2,088)
Total current portion of long-term debt		(503)		(114,088)
Total long-term debt	$	789,809	$	789,043

TUSA Credit Facility. On April 11, 2013, TUSA entered into an Amended and Restated Credit Agreement, which was subsequently amended on various dates. On November 25, 2014, TUSA entered into a Second Amended and Restated Credit Agreement, which provides for a $1.0 billion senior secured revolving credit facility, with a sublimit for the issuance of letters of credit equal to $15.0 million. The TUSA credit facility has a maturity date of October 16, 2018.

On April 30, 2015, TUSA entered into Amendment No. 1 to its Second Amended and Restated Credit Agreement (“Amendment No. 1”) to, among other things, replace the existing total funded debt leverage ratio with a senior secured leverage ratio, add an interest coverage ratio, and add an equity cure right for non-compliance with financial covenants. The May 2015 semi-annual redetermination of the borrowing base was conducted concurrently with the execution of Amendment No. 1, and the borrowing base was adjusted from $435.0 million to $350.0 million. The November 2015 semi-annual redetermination of the borrowing base was reaffirmed at $350.0 million. As of January 31, 2016, TUSA had $243.8 million drawn, plus an additional $2.5 million outstanding in letters of credit, resulting in remaining available borrowing capacity of $103.7 million under the TUSA credit facility. On March 31, 2016, TUSA borrowed $103.7 million under its credit facility, representing the entire amount remaining thereunder relative to the current borrowing base of $350.0 million. As a result, no further extensions of credit currently are available under the TUSA credit agreement.

Borrowings under the TUSA credit facility bear interest, at TUSA’s option, at either (i) the adjusted base rate (the highest of (A) the administrative agent’s prime rate, (B) the federal funds rate plus 0.50%, or (C) the one month Eurodollar rate (as defined in the agreement) plus 1.0%), plus an applicable margin that ranges between 0.50% and 1.50%, depending on TUSA’s utilization percentage of the then effective borrowing base, or (ii) the Eurodollar rate plus an applicable margin that ranges between 1.50% and 2.50%, depending on TUSA’s utilization percentage of the then effective borrowing base.

The lenders will redetermine the borrowing base under the TUSA credit facility on a semi-annual basis by May 1 and November 1. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. If the new borrowing base resulting from any regularly scheduled, semi-annual redetermination is less than the amount of outstanding credit exposure under the credit facility, TUSA will be required to (i) pledge additional collateral, (ii) repay the principal amount of the loans in an amount sufficient to eliminate the excess, (iii) repay the excess in three equal monthly installments, or (iv) any combination of options (i) through (iii). In contrast, if a borrowing base deficiency results from an unscheduled redetermination, TUSA must immediately repay the excess and may not remedy such deficiency by pledging additional collateral or repaying the excess in installments. 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. The TUSA credit facility is collateralized by certain of TUSA’s assets, including (1) at least 80% of the adjusted engineered value of TUSA’s oil and natural gas interests evaluated in determining the borrowing base for the facility, and (2) all of the personal property of TUSA and its subsidiaries. The obligations under the TUSA credit facility are guaranteed by TUSA’s subsidiaries, but Triangle is not a guarantor.

Continued low commodity prices, reductions in TUSA’s capital budget and the resulting reserve write-downs are expected to impact the upcoming May 2016 redetermination. To the extent a reduction in the borrowing base results in

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existing indebtedness exceeding the reduced borrowing base, mandatory repayment of the borrowing base deficiency would be required as described above. Although the outcome of the May redetermination is uncertain, TUSA believes that it has sufficient cash on hand to be able to make any such mandatory repayment. Any such non-payment could result in an event of default.

The TUSA credit facility contains various covenants and restrictive provisions that may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, pay dividends, make investments or loans and create liens. In addition, the facility contains financial covenants requiring TUSA to maintain specified ratios of consolidated current assets to consolidated current liabilities, consolidated senior secured debt to consolidated EBITDAX, and interest to consolidated EBITDAX.

As of January 31, 2016, TUSA was in compliance with all financial covenants under the TUSA credit facility. Although it is difficult to forecast future operations in this low commodity price environment, TUSA anticipates that it could breach its ratio of secured debt to EBITDA or its interest coverage ratio covenants (as defined in the credit agreement) in fiscal year 2017 if commodity prices do not recover.For any such breach of a financial covenant in fiscal year 2017, the Company intends to provide an equity contribution to TUSA to cure such breach, subject to approval by the Company’s Board of Directors.

RockPile Credit Facility. On March 25, 2014, RockPile entered into a Credit Agreement to provide a $100.0 million senior secured revolving credit facility. On November 13, 2014, RockPile entered into Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement, which amended the credit facility to increase the borrowing capacity under the facility from $100.0 million to $150.0 million. The RockPile credit facility has a maturity date of March 25, 2019.

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

RockPile pays a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile credit facility. RockPile also pays a per annum fee on all letters of credit issued under the RockPile credit facility, which will equal the applicable margin for loans accruing interest based on the Eurodollar rate and a fronting fee to the issuing lender equal to 0.125% of the letter of credit amount. The obligations under the RockPile credit facility are guaranteed by RockPile’s subsidiaries, but Triangle is not a guarantor.

The RockPile credit facility contains financial covenants requiring RockPile to maintain specified ratios of consolidated debt to EBITDA and Adjusted EBITDA to Fixed Charges. Amendment No. 1 also modified covenants in the RockPile credit facility related to certain restrictions on the payment of dividends and distributions and increased the amount of permitted capital expenditures.

RockPile has a cure right to obtain a cash capital contribution from Triangle or another investor approved by Triangle on or before ten days following the date that its compliance certificates are due (45 days after quarter ends and 120 days after its fiscal year end) to cure such a breach (an equity cure). The cure amount is defined as the amount which, if added to EBITDA for the test period in which a default of the financial covenant occurred, would cause the financial covenant for such test period to be satisfied. RockPile may exercise this cure right in no more than two of any four consecutive fiscal quarters and no more than five times during the term of the credit facility. To date, RockPile has not exercised an equity cure right.

On April 13, 2016, RockPile entered into Amendment No. 2, which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 or may occur as of April 30, 2016. The waivers are conditioned on RockPile agreeing to certain informational and process requirements and deadlines. Following the execution of Amendment No. 2, RockPile is precluded from drawing additional funds absent further amendment of the facility.

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Beginning with the second quarter and for the remainder of fiscal year 2017, RockPile does not expect to comply with all of the financial covenants contained in its credit facility unless those requirements are also waived or amended or unless RockPile can obtain new capital or equity cure financing. RockPile remains in discussions with its bank syndicate and various providers of external capital to refinance the existing indebtedness, but there are no guarantees these discussions or negotiations will be successful. If RockPile is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, RockPile’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable. If this happens, the Company does not currently have sufficient liquidity to make the RockPile equity cure and RockPile does not have sufficient cash on hand to repay this outstanding debt. Therefore, the consolidated balance sheet reflects all of the amounts outstanding under the RockPile credit facility as current liabilities as of January 31, 2016. Triangle has not guaranteed RockPile’s obligations under the credit facility, and there are no cross-default provisions in Triangle’s or TUSA’s other debt agreements that could cause the acceleration of such indebtedness as a result of the RockPile credit facility default.

TUSA 6.75% 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 $450.0 million aggregate principal amount of 6.75%Senior Notes due 2022 (the “TUSA 6.75% Notes”).

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

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

TUSA may redeem some or all of the TUSA 6.75% Notes at any time prior to July 15, 2017 at a price equal to 100% 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 TUSA 6.75% Notes at any time at a price equal to 105.063% of the principal amount of the notes redeemed (103.375% after July 15, 2018, 101.688% after July 15, 2019 and 100% on and after July 15, 2020), plus accrued and unpaid interest, if any, to the redemption date. In addition, at any time prior to July 15, 2017, TUSA may redeem up to 35% of the aggregate principal amount of the TUSA 6.75% Notes at 106.75% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings and cash contributions to capital stock. If TUSA experiences certain change of control events, TUSA must offer to repurchase the TUSA 6.75% Notes at 101% of their principal amount, plus accrued and unpaid interest, if any, to the repurchase date.

The Indenture permits TUSA to purchase TUSA 6.75% Notes in the open market. In fiscal year 2015, TUSA repurchased TUSA 6.75% Notes with a face value of $20.5 million for $13.9 million, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $6.6 million. During fiscal year 2016, TUSA repurchased additional TUSA 6.75% Notes with a face value of $31.1 million for $13.2 million, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $17.9 million.

The Indenture contains covenants that, among other things, restrict TUSA’s ability and the ability of any restricted 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 January 31, 2016, TUSA was in compliance with all covenants under the TUSA 6.75% Notes.

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

The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, on each December 31, March 31, June 30 and September 30, and on the date of any redemption, conversion or exchange of the Convertible Note. Such interest is paid-in-kind by adding to the principal balance of the Convertible Note, provided that, after September 30, 2017, the Company has the option to make such interest payments in cash. As of January 31, 2016, $22.8 million of accrued interest has been added to the principal balance of the Convertible Note.

The Convertible Note does not have a stated maturity. Following July 31, 2017, if the trading price of the Company’s common stock exceeds $11.00 per share for 20 consecutive trading days and certain trading volume requirements are met, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, payable, at the Company’s option, in cash or common stock. Following July 31, 2020, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal plus accrued and unpaid interest, payable in cash. Further, following July 31, 2022, a change of control of the Company, or certain other fundamental changes (as defined in the indenture), the holder of the Convertible Note will have the right to require the Company to redeem the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, with an additional make-whole payment for scheduled interest payments remaining if such right is exercised prior to July 31, 2017.

Future Maturities of Outstanding Debt. Scheduled annual maturities (including the impact of the reclassification of the RockPile debt) of long-term debt outstanding as of January 31, 2016 were as follows:

For the Years Ending January 31, (in thousands):
2017	$	114,088
2018		1,656
2019		245,430
2020		676
2021		706
Thereafter		548,499
	$	911,055

5.  HEDGING AND COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

Through TUSA, the Company has entered into commodity derivative instruments utilizing costless collars and swaps to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the settlement price is above the ceiling price, and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure or reduce 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 six 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. 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. The Company’s cash flows are only impacted when the actual settlements under the commodity derivative contracts result in a payment to or from the counterparty. These settlements under the

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commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. 

The components of commodity derivative gains (losses) in the consolidated statements of operations are as follows:

	For the Years Ended January 31,
(in thousands)	2014		2015		2016
Realized commodity derivative gains (losses)	$	(4,643)	$	11,422	$	71,940
Unrealized commodity derivative gains (losses)		5,725		52,628		(33,393)
Commodity derivative gains (losses), net	$	1,082	$	64,050	$	38,547

The Company’s commodity derivative contracts as of January 31,2016 are summarized below:

				Weighted		Weighted		Weighted
	Contract		Quantity	Average		Average		Average
	Type	Basis (1)	(Bbl/d)	Put Strike		Call Strike		Price
February 1, 2016 to January 31, 2017	Swap	NYMEX	2,175		n/a		n/a	$	56.13
February 1, 2017 to January 31, 2018	Swap	NYMEX	2,745		n/a		n/a	$	53.36

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

In August 2015, the Company unwound certain commodity derivative swap contracts and realized a gain of $9.3 million. The early settled contracts were for 2,000 barrels of oil per day at an average fixed price of $60.34 for the period from January 1, 2016 to December 31, 2016.

The estimated fair values of commodity derivatives included in the consolidated balance sheets at January 31,2015 and 2016 are summarized below. The Company does not offset asset and liability positions with the same counterparties within the consolidated financial statements; rather, all contracts are presented at their gross estimated fair value.

(in thousands)	January 31, 2015		January 31, 2016
Current Assets:
Crude oil derivative contracts	$	54,775	$	12,370
Other Long-Term Assets:
Crude oil derivative contracts		—		9,012
Total derivative asset	$	54,775	$	21,382
Long-Term Liabilities:
Crude oil derivative contracts	$	—	$	—
Total derivative liability	$	—	$	—

6.  OIL AND NATURAL GAS PROPERTIES

The following table sets forth the capitalized costs incurred in our oil and natural gas production, exploration, and development activities in the United States for years ended January 31, 2014, 2015 and 2016:

	For the Years Ended January 31,
(in thousands)	2014		2015		2016
Costs incurred during the period
Acquisition of properties:
Proved	$	80,201	$	90,920	$	655
Unproved		41,377		47,858		155
Exploration		96,731		180,174		58,660
Development		216,046		226,765		93,756
Oil and natural gas expenditures		434,355		545,717		153,226
Asset retirement obligations, net		676		1,818		1,156
	$	435,031	$	547,535	$	154,382

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During fiscal years 2014, 2015 and 2016, we acquired oil and natural gas properties, and participated in the drilling and completion of wells, for total consideration of approximately $434.4 million, $545.7 million, and $153.3 million, including $121.6 million, $138.8 million, and $0.8 million, respectively, for the acquisition of oil and natural gas properties. Total consideration paid includes common stock of $2.4 million in fiscal year 2014. During fiscal years 2014, 2015 and 2016, we capitalized $3.7 million, $4.8 million, and $4.3 million, respectively, of internal land, geology, and operations department costs directly associated with property acquisition, exploration (including lease record maintenance), and development.

The following table summarizes oil and natural gas property costs not being amortized at January 31, 2016, by year that the costs were incurred:

	Fiscal Year Costs Incurred
	2013
(in thousands)	and prior		2014		2015		2016
Acquisition	$	15,370	$	20,320	$	33,554	$	68
Exploration		—		1,039		224		691
Capitalized interest		—		254		2,045		4,802
Total	$	15,370	$	21,613	$	35,823	$	5,561

Unproved properties includes $78.4 million of costs not being amortized as of January 31, 2016. On a quarterly basis, costs not being amortized are evaluated for inclusion in costs to be amortized. Upon evaluation of a well or well location having proved reserves, the associated costs are reclassified from unproved properties to proved properties and become subject to amortization over our proved reserves for the country-wide amortization base. Upon evaluation that costs of unproved properties are impaired or evaluation that a well or well location will not have proved reserves, the amount of cost impairment and well costs are reclassified from unproved properties to proved properties and become subject to amortization. The majority of the unproved oil and natural gas property costs, which are not subject to amortization, relate to oil and natural gas property acquisitions and leasehold acquisition costs. The Company transferred $14.5 million, $67.2 million and $35.1 million of unproved costs into the amortization base in fiscal years 2014, 2015 and 2016, respectively, due to impairment, development of acreage or placement of assets into service. In fiscal year 2016, the Company impaired unproved leasehold costs for substantially all acreage not held by production. Due to the long estimated economic lives of its wells and the majority of the unproved costs related to leasehold costs for acreage held by production, the Company expects that only a minor portion of its unproved property costs as of January 31, 2016 will be reclassified to proved properties within the next five years unless there is a dramatic increase in commodity prices.

7.  ACQUISITIONS

Kodiak Oil & Gas Property Acquisition. In August 2013, TUSA acquired interests in approximately 5,600 net acres of leaseholds and related producing properties along with various other related rights, permits, contracts, equipment and other assets, all located in McKenzie County, North Dakota, from Kodiak Oil & Gas Corporation (“Kodiak”). We paid approximately $83.8 million in cash. In addition, the Company and Kodiak also agreed to exchange certain of Triangle’s oil and natural gas leasehold interests in Kodiak’s operated units for approximately 600 net acres of leasehold interests held by Kodiak in units then operated by the Company. The effective date for the acquisition and the exchange was July 1, 2013.

Marathon Oil & Gas Property Acquisition. In June 2014, we acquired from Marathon Oil Company (“Marathon”) certain oil and natural 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, net of certain closing adjustments of $9.6 million. Transaction costs related to the acquisition incurred during the year ended January 31, 2015 of approximately $1.3 million are recorded in general and administrative expenses.

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

Purchase price (in thousands):	As of June 30, 2014
Cash	$	90,352
Total consideration given	$	90,352
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, in August of 2013, and Marathon, in June of 2014, as if the acquisitions had occurred on February 1, 2013. 

	For the Years Ended January 31,
(in thousands, except per share data)	2014		2015
Operating revenues	$	312,081	$	584,696
Net income (loss)	$	91,579	$	96,438
Earnings (loss) per common share
Basic	$	1.22	$	1.15
Diluted	$	1.04	$	1.00
Weighted average common shares outstanding:
Basic		75,047		83,611
Diluted		91,026		101,032

For purposes of the pro forma information it was assumed that the net proceeds generated from the issuance of the Company’s common stock were utilized to fund the August 28, 2013 acquisition and that such issuance occurred on February 1, 2012. The pro forma information includes the effects of adjustments for depreciation, amortization and accretion expense of $3.4 million and $16.5 million for fiscal years 2015 and 2014, respectively. The pro forma results do not include any cost savings that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the transactions had been completed, or the common stock had been issued, as of the beginning of the period, nor are they necessarily indicative of future results.

8.  ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations (“ARO”) represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate producing and shut-in properties at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its ARO when incurred by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.

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The following tables reflect the change in ARO for the years ended January 31, 2015 and 2016:

	For the Years Ended January 31,
(in thousands)	2015		2016
Balance at the beginning of the period	$	4,629	$	8,578
Liabilities incurred		1,821		1,268
Revision of estimates		2,737		1,281
Sale of assets		(29)		(30)
Liabilities settled		(747)		(1,400)
Accretion		167		376
Balance at the end of the period		8,578		10,073
Less current portion of obligations		(5,391)		(560)
Long-term ARO	$	3,187	$	9,513

The current portion of ARO is classified with other accrued liabilities and the long-term ARO is classified in other long-term liabilities in the accompanying consolidated balance sheets.

A significant portion of the current obligations relates to the reclamation of man-made ponds holding produced formation water and the plugging and abandonment of well bores in the Maritimes Basin of Canada of $4.8 million and $4.9 million as of January 31, 2015 and January 31, 2016, respectively. Internal engineering re-assessment of Canadian ARO resulted in revisions of $2.7 million and $1.3 million to the ARO during fiscal years 2015 and 2016. Since our Canadian oil and natural gas properties were fully impaired, the ARO revisions were expensed and included in depreciation and amortization expenses in the accompanying consolidated statements of operations.

9.  EQUITY INVESTMENT AND EQUITY INVESTMENT DERIVATIVES

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

On January 31, 2015, Triangle Caliber Holdings entered into a series of agreements modifying its joint venture with FREIF. In connection with the modifications, Triangle Caliber Holdings entered into a Second Amended and Restated Contribution Agreement, dated January 31, 2015 (the “2nd A&R Contribution Agreement”), with FREIF and the general partner of Caliber, which is owned and controlled equally between Triangle Caliber Holdings and FREIF. Pursuant to the terms of the 2nd A&R Contribution Agreement, FREIF agreed to contribute an additional $34.0 million to Caliber in exchange for 2,720,000 Class A Units. FREIF funded the $34.0 million contribution, and the additional 2,720,000 Class A Units were issued, on February 2, 2015. Triangle Caliber Holdings made no capital contribution to Caliber in connection with the 2nd A&R Contribution Agreement or the issuance of the 2,720,000 Class A Units. Following the issuance, FREIF holds 17,720,000 Class A Units, representing an approximate 71.7% Class A Units ownership interest in Caliber, and Triangle Caliber Holdings holds 7,000,000 Class A Units, representing an approximate 28.3% Class A Units ownership interest in Caliber.

Also pursuant to the terms of the 2nd A&R Contribution Agreement, Triangle Caliber Holdings received warrants for the purchase of an additional 3,626,667 Class A Units, and FREIF received warrants (Series 5) for the purchase of an additional 906,667 Class A Units. The warrants received by Triangle Caliber Holdings on February 2, 2015 included 2,357,334 Class A (Series 1 through 4) Warrants at strike prices and expiration dates noted below and 1,269,333 Class A (Series 6) Warrants with a strike price of $12.50 and an expiration date of February 2, 2018.

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The following summarizes the Company’s equity investment holdings in Caliber as of January 31, 2015 and 2016 and the strike prices for exercising warrants as of January 31, 2016:

	Expiration		Strike Price at		As of	As of
	Date		January 31, 2016		January 31, 2015	January 31, 2016
Class A Units		—	$	—	7,000,000	7,000,000
Series 1 Warrants		October 1, 2024	$	12.78	5,600,000	6,615,467
Series 2 Warrants		October 1, 2024	$	22.09	2,400,000	2,835,200
Series 3 Warrants		September 12, 2025	$	22.09	3,000,000	3,544,000
Series 4 Warrants		September 12, 2025	$	28.09	2,000,000	2,362,667
Series 6 Warrants		February 2, 2018	$	12.50	—	1,269,333

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. 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 its economic performance. 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, our share of Caliber’s net income and accretion of any basis differences. Our maximum exposure to loss related to Caliber is limited to our equity investment.

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 a result of the extended low commodity price environment, TUSA and other exploration and production companies have significantly curtailed their development activities. This has adversely impacted the fair value of our investment in Caliber. The carrying value of our investment in Caliber exceeded its fair value at January 31, 2016. Since we deemed this decline in fair value to be other than temporary, we recorded a net impairment of $25.0 million in fiscal year 2016.

The following summarizes the activities related to the Company’s equity investment in Caliber for the years ended January 31, 2015 and 2016:

	For the Years Ended January 31,
(in thousands)	2015		2016
Balance at beginning of year	$	68,536	$	64,411
Capital contributions		—		—
Distributions		(6,080)		—
Equity investment share of net income before intra-company profit eliminations		1,402		3,070
Change in fair value of warrants		553		3,098
Other than temporary impairment		—		(24,979)
Balance at end of year	$	64,411	$	45,600
Fair value of trigger unit warrants and warrants at end of year	$	504	$	3,600

Equity Investment Derivatives. At January 31, 2015 and 2016, the Company held Class A (Series 1 through Series 4 and Series 6) Warrants to acquire additional ownership in Caliber. These instruments are considered to be equity investment derivatives and are valued at each reporting period using valuation techniques for which the inputs are generally less observable than from objective sources.

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Financial Information of Unconsolidated Equity Method Investee. The following table summarizes the financial information of our equity method investee (in thousands):

	For the Years Ended January 31,
(in thousands)	2014		2015		2016
Revenue	$	11,384	$	42,995	$	64,345
Gross profit	$	8,395	$	16,918	$	29,630
Net income (loss)	$	2,617	$	4,875	$	8,605
			January 31, 2015		January 31, 2016
Current assets			$	56,993	$	26,606
Noncurrent assets				423,013		429,534
Total assets			$	480,006	$	456,140
Current liabilities			$	45,585	$	9,806
Noncurrent liabilities				192,032		194,015
Total liabilities			$	237,617	$	203,821
Minority interests			$	15,373	$	14,432

10.  CAPITAL STOCK

The Company had 106.5 million shares of common stock issued or reserved for issuance at January 31,2016. At January 31, 2016, the Company had 75.8 million shares of common stock issued and outstanding. The Company also had 1.3 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan, 6.0 million shares of common stock reserved for issuance under its CEO Stand-Alone Stock Option Agreement, 2.8 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2014 Equity Incentive Plan (the “2014 Plan”), and 2.9 million shares of reserved common stock that remained available for issuance under the 2014 Plan. Lastly, the Company had 17.6 million shares of common stock reserved for issuance pursuant to the Convertible Note.

The Company’s Board of Directors (the “Board”) approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 2”), and (iii) up to the number of shares of common stock potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (“Tranche 3”). The program stipulates that shares of common stock may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. There were no common stock repurchases for the years ended January 31, 2016 and 2014. As of January 31, 2016, the number of shares of common stock remaining available for repurchase under the Board approved program was 5,811,091 shares.

11.  SHARE-BASED COMPENSATION

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

On May 27, 2014, the Board approved the 2014 Plan, which was approved by the Company’s stockholders on July 17, 2014. No additional awards may be granted under prior plans but all outstanding awards under prior plans shall continue in accordance with their applicable terms and conditions. The 2014 Plan authorizes the Company to issue stock options, SARs, restricted stock, restricted stock units, cash awards, and other awards to any employees, officers, directors, and consultants of the Company and its subsidiaries. The maximum number of shares of common stock issuable under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions.

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For the years ended January 31, 2014, 2015 and 2016, the Company recorded share-based compensation as follows:

	For the Years Ended January 31,
(in thousands)	2014		2015		2016
Restricted stock units	$	7,496	$	6,254	$	10,345
Stock options		1,135		2,299		7,809
RockPile Series B Units		590		509		805
		9,221		9,062		18,959
Less amounts capitalized to oil and natural gas properties		(1,391)		(1,143)		(1,565)
Compensation expense	$	7,830	$	7,919	$	17,394

Restricted Stock Units. During the year ended January 31, 2016, the Company granted 1,983,843 restricted stock units as compensation to employees, officers, and directors which generally vest over one to five years. As of January 31, 2016, there was approximately $14.7 million of total unrecognized compensation expense related to unvested restricted stock units. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 2.1 years on a weighted average basis. When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit.

The following table summarizes the activity for our restricted stock units during the years ended January 31, 2014, 2015 and 2016:

		Weighted Average
	Number of	Award Date
	Shares	Fair Value
Restricted stock units outstanding - January 31, 2013	2,524,085	$	6.68
Units granted	1,440,133	$	6.95
Units forfeited	(141,909)	$	6.58
Units vested	(946,681)	$	6.71
Restricted stock units outstanding - January 31, 2014	2,875,628	$	6.62
Units granted	1,523,700	$	9.42
Units forfeited	(394,921)	$	7.21
Units vested	(1,090,362)	$	7.04
Restricted stock units outstanding - January 31, 2015	2,914,045	$	7.92
Units granted	1,983,843	$	4.74
Units forfeited	(574,605)	$	7.06
Units vested	(867,438)	$	7.81
Restricted stock units outstanding - January 31, 2016	3,455,845	$	6.35

Stock Options. The following table summarizes the stock options outstanding at January 31, 2016:  

		Remaining
Exercise Price		Contractual Life	Number of Shares
per Share		(years)	Outstanding		Exercisable
$	7.50	7.43		750,000		150,000
$	8.50	7.43		750,000		150,000
$	10.00	7.43		1,500,000		300,000
$	12.00	7.43		1,500,000		300,000
$	15.00	7.43		1,500,000		300,000
$	12.00	5.61		233,333		77,770
$	14.00	5.61		233,333		77,770
$	16.00	8.61		233,334		77,770
				6,700,000		1,433,310
Weighted average exercise price per share			$	11.54	$	11.70
Weighted average remaining contractual life				7.34		7.29

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As of January 31, 2016, there was approximately $10.8 million of total unrecognized compensation expense related to stock options. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 2.3 years.

RockPile Share-Based Compensation. RockPile currently has two classes of equity; Series A Units, which are voting units with an 8% preference, and Series B Units, which are non-voting equity awards that generally vest over a requisite service period of 3 to 5 years. RockPile approved a plan that includes provisions allowing RockPile to make equity grants in the form of restricted units (“Series B Units”) pursuant to Restricted Unit Agreements. The plan authorizes RockPile to issue an aggregate of up to 6.0 million Series B Units in multiple series designated by a sequential number with the right to reissue forfeited or redeemed Series B Units.

The Series B Units are intended to constitute “profit interests” within the meaning of Internal Revenue Service Revenue Procedures 93-27 and 2001-43. Accordingly, the capital account associated with each Series B Unit at the time of its issuance shall be zero. RockPile may designate a “Liquidation Value” applicable to each tranche of a Series B Unit grant so as to constitute a net profits interest. The Liquidation Value shall equal the dollar amount per unit that would, in the reasonable determination of RockPile, be distributed with respect to the initial Series B Unit tranche if, immediately prior to the issuance of a new Series B Unit tranche, the assets of RockPile were sold for their fair market value and the proceeds (net of any liabilities) were distributed.

The Series A Units are entitled to a return of contributed capital and an 8% preferred return on such capital before Series B Units participate in profits. The initial Series B tranche (Series B-1 Units) participates pro rata with the Series A Units once the preferred return has been achieved. However, no distributions shall be made with respect to any Series B-1 Unit until total cumulative distributions to the Series A Units total $40.0 million. As of January 31, 2015, the $40.0 million cumulative distribution threshold was met. Therefore, future distributions will be allocated to the Series B-1 Units until the per unit profits distributed to the Series B-1 Units is equivalent to the per unit profits distributed to the Series A Units. Thereafter, all further distributions will be distributed on a pro rata basis. Subsequently issued Series B Units will begin participating on a pro rata basis once the per unit profits allocated to the Series B-1 Units reaches the Liquidation Value of the subsequent Series B Unit issuance. RockPile’s limited liability company agreement was amended on January 31, 2015 to permit distributions to holders of vested Series B Units as prepayment for future amounts payable to them upon a RockPile liquidity event. In the event a holder of vested Series B Units receives such a pre-liquidity event distribution, their capital account will be adjusted to reflect the prepayment.

The following table summarizes the activity for RockPile’s Series B Units for the years ended January 31, 2014, 2015 and 2016:

	Series	Series	Series	Series	Series	Series
	B-1units	B-2 units	B-3 units	B-4 units	B-5 units	B-6 units	Total
Units outstanding - January 31, 2013	3,100,000	60,000	—	—	—	—	3,160,000
Units forfeited	—	—	—	—	—	—	—
Units redeemed	—	—	—	—	—	—	—
Units granted	—	—	910,000	—	—	—	910,000
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 - January 31, 2015	2,920,000	60,000	910,000	1,412,000	—	—	5,302,000
Units redeemed	—	—	—	—	—	—	—
Units granted	—	—	—	—	397,500	257,500	655,000
Units forfeited	—	—	(96,000)	(90,800)	—	(40,000)	(226,800)
Units outstanding - January 31, 2016	2,920,000	60,000	814,000	1,321,200	397,500	217,500	5,730,200
Vested	2,920,000	60,000	352,000	117,600	—	—	3,449,600
Unvested	—	—	462,000	1,203,600	397,500	217,500	2,280,600

Compensation costs are determined using a Black-Scholes option pricing model based upon the grant date calculated fair market value of the award and is recognized ratably over the applicable vesting period. As of January 31, 2016, there was approximately $1.9 million of unrecognized compensation expense related to unvested Series B Units. We expect to recognize such expense on a pro-rata basis on the Series B Units’ over the remaining vesting period of the related awards of 2.9 years.

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12.  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 flows 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.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2015 and 2016, by level within the fair value hierarchy:

	As of January 31, 2015
(in thousands)	Level 1		Level 2		Level3		Total
Assets:
Commodity derivative assets	$	—	$	54,775	$	—	$	54,775
Equity investment derivative assets	$	—	$	—	$	504	$	504
Liabilities:
RockPile earn-out liability	$	—	$	(1,825)	$	—	$	(1,825)

	As of January 31, 2016
(in thousands)	Level1		Level 2		Level 3		Total
Assets:
Commodity derivative assets	$	—	$	21,382	$	—	$	21,382
Equity investment derivative assets	$	—	$	—	$	3,600	$	3,600
Liabilities:
Commodity derivative liabilities	$	—	$	—	$	—	$	—
RockPile earn-out liability	$	—	$	(1,265)	$	—	$	(1,265)

Commodity Derivative Instruments.The Company determines its estimate of the 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. In considering 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 believes that each of its counterparties is creditworthy and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At January 31, 2016, commodity derivative instruments utilized by the Company consisted of swaps. The Company’s commodity derivative instruments are valued using public indices and are traded with third-party counterparties, but are not openly traded on an exchange. As such, the Company has classified these commodity derivative instruments as Level 2.

Caliber Class A Warrants (Series 1 through Series 4 and Series 6). The Company determines its estimate of the fair value of Caliber Class A Warrants using a Monte Carlo Simulation (“MCS”) model. For each MCS, the values of the Class

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A Units and Class A Warrants were forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly. At January 31, 2016, the fair values of the underlying Class A Units and Class A Warrants were estimated employing an income approach using a MCS model and discounted cash flows, and a market approach based on observed valuation multiples for comparable public companies. Key inputs into these valuation approaches are generally less observable than those from objective sources. Therefore, the Company has classified these instruments as Level 3.

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

Nonrecurring Fair Value Measurements.For certain situations, the Company is also required to make fair value measurements for assets and liabilities in the consolidated balance sheet after their initial recognition.  At January 31, 2016, the Company was required to make fair value measurements for comparisons to the carrying values of long-lived assets and its equity investment in Caliber Class A Units to assess whether any impairments were required. 

The Company determined its estimate of the fair value of long-lived assets, primarily oilfield services equipment, using discounted cash flow models, replacement cost estimates from a major third-party vendor, and a market approach based on estimates from an independent, third party appraiser. Key inputs into these valuation approaches are generally less observable than those from objective sources. Therefore, the Company considers the related long-lived assets as Level 3.

As described above, the MCS model that is used by the Company to determine the fair value of the Caliber Class A Warrants is also used by the Company to determine the fair value of the Company’s investment in Caliber Class A Units in its other than temporary impairment evaluation, Therefore, the Company considers its investment in Caliber Class A Units as Level 3.

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

The carrying values and fair values of the Company’s debt instruments are as follows:

	January 31, 2015				January 31, 2016
	Carrying		Estimated		Carrying		Estimated
(in thousands)	Value		FairValue		Value		Fair Value
Revolving credit facilities	$	224,159	$	224,159	$	355,772	$	355,772
TUSA 6.75% notes		429,500		303,871		398,419		71,051
5% convertible note		135,877		137,790		142,799		125,310
Other notes and mortgages payable		10,605		10,605		14,065		14,065

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13.  INCOME TAXES

The Company’s income tax provision (benefit) is composed of the following:

	For the Years Ended January 31,
(in thousands)	2014		2015		2016
Current tax expense (benefit)	$	—	$	—	$	44
Deferred tax expense (benefit)
Federal		7,324		42,400		(302,941)
State		617		3,100		(23,400)
Foreign		—		—		100
Valuation allowance - United States and Canada		—		—		272,800
Total income tax provision (benefit)	$	7,941	$	45,500	$	(53,397)
Income (loss) before income taxes	$	81,421	$	138,897	$	(875,737)
Effective income tax rate		10.0%		33.0%		6.1%

A reconciliation of the income tax provision (benefit) computed by applying the federal statutory rate of 35.0% to the Company’s income tax provision (benefit) is as follows:

	For the Years Ended January 31,
(in thousands)		2014		2015		2016
Federal statutory tax expense (benefit)	$	28,498	$	48,613	$	(306,508)
State income tax expense / (benefit), net of federal income tax benefit		2,324		3,618		(23,899)
Permanent differences		3,221		3,196		3,200
Difference in foreign tax rates		164		539		222
Effect of tax rate change		(258)		(147)		227
Credits		(100)		(338)		(106)
State NOL adjustment		—		1,061		669
Bad debt deduction for receivables from Elmworth		—		(14,517)		(736)
Attribute reduction - cancellation of debt exclusion - Elmworth		—		8,466		380
Changes in valuation allowance		(26,364)		(7,464)		272,781
Other		456		2,473		373
Provision (benefit) for income taxes	$	7,941	$	45,500	$	(53,397)

The components of Triangle’s net deferred income tax assets and liabilities are as follows:

	For the Years Ended January 31,
(in thousands)	2015		2016
Deferred income tax assets:
United States net losses carried forward	$	48,443		104,464
United States oil and natural gas properties		—		199,920
Asset retirement obligations		2,592		3,073
Accruals		1,138		—
Stock-based compensation		3,182		7,155
Other		2,395		251
Total deferred income tax assets		57,750		314,863
Deferred income tax liabilities:
United States oil and natural gas properties		(56,531)		—
Investment in Caliber		(32,661)		(32,613)
Hedging liabilities		(20,806)		(8,276)
Other		—		—
Total deferred income tax liabilities		(109,998)		(40,889)
Valuation allowance		(1,193)		(273,974)
Net deferred income tax asset (liability)	$	(53,441)	$	—

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As noted above, the carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in an impairment of $779.0 million for the year ended January 31, 2016. This impairment results in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Triangle also had net operating loss carryovers (“NOLs”) for federal income tax purposes of $286.0  million at January 31, 2016. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of January 31, 2016 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

In fiscal year 2016 the Company recorded the benefit of reversing its net deferred tax liability. As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense or for state income taxes.

Triangle has also determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net Canadian deferred tax assets will not be realized since all Canadian exploration and production activities have ceased other than reclamation activities. Therefore, all remaining Canadian deferred tax assets will have a full valuation allowance placed against them.

The Company has net operating loss carryovers as of January 31, 2016 of $286.0 million for federal income tax purposes and $280.2  million for financial reporting purposes. The difference of $5.8 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The United States NOL carryforwards begin expiring in 2024. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years.

At January 31, 2015 and 2016, we have no unrecognized tax benefits that would impact our effective tax rate, and we have made no provisions for interest or penalties related to uncertain tax positions. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense. Given the substantial net operating loss carryforwards 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 only adjust net operating loss carryforwards.

The tax years for fiscal years ending 2013 to 2016 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for examination for fiscal years 2013 to 2016, except for Colorado which is open for the fiscal years 2012 to 2016. We also file with various Canadian taxing authorities which remain open for fiscal years 2012 to 2016.

14.  RELATED PARTY TRANSACTIONS

TUSA and an affiliate of Caliber have entered into certain midstream services agreements for (i) crude oil gathering, stabilization, treating and redelivery; (ii) natural gas compression, gathering, dehydration, processing and redelivery; (iii) produced water transportation and disposal services; and (iv) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. The agreements also include an acreage dedication from TUSA and a firm volume commitment by the Caliber affiliate for each service line. TUSA has agreed to deliver minimum monthly revenues derived from the fees paid by TUSA to the Caliber affiliate for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning in 2014. The aggregate minimum revenue commitment over the term of the agreements is $405.0 million, of which $303.4 million was outstanding at January 31, 2016. The agreements permit TUSA to build up credits against future monthly commitments for the excess of actual monthly revenues over the minimum monthly

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revenues. As of January 31, 2016, TUSA has built up a cumulative credit of $41.5 million. Credits may be carried forward for a period of four years from the date of the accrual. TUSA is required to pay Caliber for any deficiency of actual monthly revenues if no credits are available.

TUSA and an affiliate of Caliber have also entered into a gathering services agreement, pursuant to which the Caliber affiliate will provide certain gathering-related measurement services to TUSA, and a fresh water sales agreement that 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 from the in-service date in March 2015. The fresh water sales agreement obligates TUSA to purchase all of the fresh water it requires for its drilling and operating activities exclusively from the Caliber affiliate, subject to availability, but it does not require TUSA to purchase a minimum volume of fresh water.

TUSA incurred fees to Caliber under these agreements of $15.0 million, $36.6 million and $53.9 million, during the years ended January 31, 2014, 2015 and 2016. TUSA had payables to Caliber of $5.0 million and $9.6 million at January 31, 2015 and 2016, respectively.

TUSA also sold one salt water disposal well in fiscal year 2015 and one salt water disposal well in fiscal year 2016 to an affiliate of Caliber for net proceeds of $1.5 million and $6.0 million, respectively.

15.  COMMITMENTS AND CONTINGENCIES

Triangle has entered into non-cancelable operating leases for office facilities and RockPile has entered into various non-cancelable operating leases relating to (i) equipment for transportation, transloading and storage bulk commodities and light vehicles, (ii) transloading services and track rental and (iii) transportation equipment management, logistics and maintenance. Rent expense incurred under the non-cancelable operating leases was $0.8 million, $1.8 million, and $5.2 million for the fiscal years ended January 31, 2014, 2015, and 2016, respectively.

As of January 31, 2016, the future minimum lease payments under operating leases that have initial or remaining non-cancelable terms in excess of one year are:

	Annual Rental Amount
Fiscal Year Ending January 31,	(in thousands)
2017	$	9,476
2018	$	8,939
2019	$	8,241
2020	$	8,007
2021 and thereafter	$	17,719

CEO Transaction Bonus Program. 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 (“Transaction Bonus”). The amount of this Transaction Bonus would be equivalent to 5% 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 Transaction 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.

On January 31, 2015, Triangle and Mr. Samuels entered into a First Amendment to Third Amended and Restated Employment Agreement (the “First Amendment”) that modified the Employment Agreement to permit Triangle’s Board to authorize distributions to Mr. Samuels pursuant to his Transaction Bonus program in advance of defined liquidity events. Any Board authorized distribution to Mr. Samuels related to the Transaction Bonus program would reduce any future award payable to Mr. Samuels following a liquidity event. There are no clawback provisions in the First Amendment that would require Mr. Samuels to repay Triangle for any excess distributions or payments received. In connection with the First Amendment, the Board authorized the payment of a Transaction Bonus to Mr. Samuels of $1.9 million which was recorded as a liability as of January 31, 2015 and subsequently paid in the first quarter of fiscal year 2016.

The Company has determined that the contingent liability associated with such a bonus is not probable at January 31, 2016 because consummation of a liquidity event involving RockPile or Caliber is contingent on many unknown factors and therefore, no amounts have been recorded in the accompanying consolidated balance sheets at January 31, 2016.

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Other. In addition, the Company is a party from time to time to other claims and legal actions that arise in the ordinary course of business. The Company believes that the ultimate impact, if any, of these other claims and legal actions will not have a material effect on its consolidated financial position, results of operations or liquidity.

16.  SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION

		For the Years Ended January 31,
(in thousands)		2014	2015		2016
Cash paid during the period for:
Interest expense	$	1,419	$	19,713	$	32,319
Income taxes	$	—	$	600	$	—
Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increase (decrease) in accounts payable and accrued liabilities	$	30,785	$	47,838	$	(87,570)
Issuance of common stock	$	2,438	$	—	$	—
Capitalized stock based compensation	$	1,391	$	1,143	$	1,565
Change in asset retirement obligations	$	673	$	1,818	$	1,156
Acquisition of oilfield services equipment through notes payable and liabilities	$	1,990	$	—	$	—

17.  QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The Company’s quarterly financial information for fiscal years 2015 and 2016 is as follows:

	For the Year Ended January 31, 2016 (1)
	First		Second		Third		Fourth
(in thousands)	Quarter		Quarter		Quarter		Quarter
Total revenue	$	118,288	$	109,733	$	65,144	$	64,964
Income (loss) from operations (2)	$	(213,942)	$	(213,368)	$	(285,185)	$	(155,688)
Net income (loss)	$	(180,199)	$	(193,346)	$	(286,999)	$	(161,796)
Net income (loss) attributable to common stockholders	$	(180,199)	$	(193,346)	$	(286,999)	$	(161,796)
Net income (loss) per common share - basic	$	(2.39)	$	(2.56)	$	(3.80)	$	(2.14)
Net income (loss) per common share - diluted	$	(2.39)	$	(2.56)	$	(3.80)	$	(2.14)
	For the Year Ended January 31, 2015 (1)
	First		Second		Third		Fourth
(in thousands)	Quarter		Quarter		Quarter		Quarter
Total revenue	$	99,782	$	141,989	$	174,196	$	156,988
Income (loss) from operations (2)	$	22,483	$	38,489	$	33,534	$	877
Net (loss) income	$	14,542	$	14,552	$	25,398	$	38,905
Net income (loss) attributable to common stockholders	$	14,542	$	14,552	$	25,398	$	38,905
Net income (loss) per common share - basic	$	0.17	$	0.17	$	0.30	$	0.50
Net income (loss) per common share - diluted	$	0.15	$	0.15	$	0.26	$	0.42

(1) Amounts reported for the quarter period.

(2) There were immaterial reclassifications for the periods presented between operating expenses and other income (expense).

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18.  SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

Oil and Natural Gas Reserve Information. The following information concerning the Company’s oil and natural gas operations is provided pursuant to the FASB guidance regarding Oil and Gas Reserve Estimation and Disclosures.

At January 31, 2016, the Company’s oil and natural gas producing activities were conducted in the Williston Basin in the continental United States. All of our proved reserves are in the Bakken or Three Forks formations in the North Dakota counties of McKenzie, Williams, Stark, or Dunn, or in the Montana counties of Roosevelt, Sheridan, Madison or Richland. The Company has ceased all Canadian exploration and production activities and its oil and natural gas properties were fully impaired as of January 31, 2012.

Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, 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 prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. 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, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Such prices are also adjusted for regional price differentials; gathering, transportation, and processing; and other factors to arrive at prices utilized in the calculation of a standardized measure of discounted future net cash flows related to proved oil and natural gas reserves (“Standardized Measure”)

The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended January 31, 2016. Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) an independent petroleum engineering firm, audited our estimate as of January 31, 2014, January 31, 2015 and January 31, 2016 of proved reserves and undiscounted and discounted future cash flows (before income taxes) from those proved reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

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The reserve estimates presented in the following tables are expressed in thousands of barrels of oil (“Mbbls”), millions of cubic feet of natural gas (“MMcf”), thousands of barrels of natural gas liquids (“Mbbls”) and thousands of barrels of oil equivalent (“Mboe”).

	Crude Oil	Natural Gas	NGL
	(Mbbls)	(MMcf)	(Mbbls)	Mboe
Total proved reserves at January 31, 2013	12,539	12,585	—	14,637
Revisions of previous estimates	2,727	(859)	1,762	4,344
Purchase of reserves	6,836	4,714	690	8,313
Extensions, discoveries and other additions	12,059	11,064	1,599	15,502
Sale of reserves	(491)	(374)	—	(553)
Production	(1,754)	(626)	(70)	(1,929)
Total proved reserves at January 31, 2014	31,916	26,504	3,981	40,314
Revisions of previous estimates	2,087	1,475	(776)	1,558
Purchase of reserves	3,655	2,928	7	4,150
Extensions, discoveries and other additions	13,946	11,710	1,129	17,027
Sale of reserves	(2)	(3)	—	(3)
Production	(3,511)	(2,429)	(260)	(4,176)
Total proved reserves at January 31, 2015	48,091	40,185	4,081	58,870
Revisions of previous estimates	(12,309)	(10,360)	223	(13,813)
Purchase of reserves	—	—	—	—
Extensions, discoveries and other additions	7,100	5,113	801	8,753
Sale of reserves	(29)	—	—	(29)
Production	(3,952)	(3,115)	(426)	(4,897)
Total proved reserves at January 31, 2016	38,901	31,823	4,679	48,884
Proved Developed Reserves included above:
January 31, 2013	4,985	5,906	—	5,969
January 31, 2014	13,734	10,930	1,440	16,995
January 31, 2015	29,605	24,136	2,350	35,978
January 31, 2016	30,328	26,001	3,803	38,465
Proved Undeveloped Reserves included above:
January 31, 2013	7,554	6,679	—	8,668
January 31, 2014	18,182	15,574	2,541	23,319
January 31, 2015	18,486	16,049	1,731	22,892
January 31, 2016	8,573	5,822	876	10,419

The following average prices are reflected in the calculation of the Standardized Measure. These prices represent the unescalated twelve month arithmetic average of the first day of the month posted prices, adjusted for quality, energy content, transportation fees and regional price differentials.

	For the Years Ended January 31,
	2014		2015		2016
Oil price per barrel	$	93.09	$	79.71	$	38.41
Natural gas price per Mcf	$	3.99	$	6.09	$	0.55
Natural gas liquids price per barrel	$	44.10	$	34.61	$	2.45

Notable changes in proved reserves for fiscal year 2016 included:

Revisions of previous estimates.In fiscal year 2016, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 13.8 MMboe. Upward revisions of 9.4 MMboe that mostly related to well performance were more than offset by downward adjustments of 23.2 MMboe that resulted from proved reserves that became uneconomic on a PV-10 basis due to the significantly lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at January 31, 2016 as compared to January 31, 2015.

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Extensions and discoveries.In fiscal year 2016, extensions of 8.8 MMboe of proved reserves added by extensions and discoveries in North Dakota are primarily due to our successful completions of exploratory wells andproved undeveloped wells and the extensions of reserves for offsetting locations.

Notable changes in proved reserves for fiscal year 2015 included:

Purchase of reserves.In fiscal year 2015, total purchases of minerals in place of 4.2 MMboe were primarily attributable to the Marathon acquisition which is further described in the “Acquisitions” footnote, which increased the Company’s proved reserves.

Extensions and discoveries.In fiscal year 2015, extensions of 17.0 MMboe of proved reserves added by extensions and discoveries in North Dakota are primarily due to our successful completions of wells, particularly operated wells, and other parties completing wells offsetting our properties.

Notable changes in proved reserves for fiscal year 2014 included:

Revisions of previous estimates.In fiscal year 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 4.3 MMboe. The upward revision in crude oil proved reserves was primarily due to longer production histories that favorably supported the increase in proved oil reserves. The 859 MMcf reduction in natural gas reserves and the 1,762 Mbbls increase in NGL reserves reflect agreements and arrangements at the end of fiscal year 2014 to have the majority of our proved natural gas reserves processed to extract NGLs and dry residue gas.

Purchase of reserves.In fiscal year 2014, total purchases of minerals in place of 8.3 MMboe were primarily attributable to the Kodiak acquisition which is further described in the “Acquisitions” footnote, which increased the Company’s proved reserves.

Extensions and discoveries.In fiscal year 2014, the 15.5 MMboe of proved reserves added by extensions and discoveries in North Dakota are primarily due to our successful completions of wells, particularly operated wells, and other parties completing wells offsetting our properties.

Proved Undeveloped Reserves. At January 31, 2016, we had proved undeveloped oil and natural gas reserves of 10.4MMboe, down 12.5MMboe from 22.9MMboe at January 31, 2015. Changes in our proved undeveloped reserves are summarized in the following table:

	(Mboe)	Gross Wells	Net Wells
Proved Undeveloped Reserves at January 31, 2013	8,668	59	19.8
Conversion to developed reserves in fiscal year 2014	(3,701)	(32)	(7.9)
Traded for net acres in other drill spacing units	(353)	(4)	(0.8)
Revisions	84	—	—
Acquisitions	5,466	13	11.8
Extensions and discoveries of proved reserves	13,155	68	29.6
Proved Undeveloped Reserves at January 31, 2014	23,319	104	52.5
Conversion to developed reserves in fiscal year 2015	(8,461)	(30)	(18.5)
Revisions	1,676	(14)	4.7
Acquisitions	528	6	1.3
Extensions and discoveries of proved reserves	5,830	37	14.0
Proved Undeveloped Reserves at January 31, 2015	22,892	103	54.0
Conversion to developed reserves in fiscal year 2016	(2,668)	(12)	(5.8)
Revisions	(14,693)	(66)	(39.0)
Acquisitions	—	—	—
Extensions and discoveries of proved reserves	4,888	18	8.4
Proved Undeveloped Reserves at January 31, 2016	10,419	43	17.6

During fiscal year 2016, we invested approximately $48.0 million (averaging $8.3 million per net well) related to the drilling and completion of the 12 gross (5.8 net) wells that converted 2.7MMboe of proved undeveloped reserves to proved developed reserves.

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For proved undeveloped (“PUD”) locations at January 31, 2016, the following table provides further information on the timing and status of operated and non-operated locations:

	PUD	Development Wells
	Locations	Gross	Net
Proved undeveloped locations:
For which Triangle operated wells are to be drilled and completed by January 31, 2021	32	32	15.9
For which non-operated wells were in-progress at January 31, 2016 and are expected to be completed in fiscal year 2017	—	—	—
That are non-operated wells with drilling permits	—	—	—
That are non-operated wells to be drilled by January 31, 2021	11	11	1.7
	43	43	17.6

Standardized Measure of Discounted Future Net Cash Flows

Authoritative accounting guidance by the FASB requires the Company to calculate and disclose for January 31, 2015 and 2016 (i) a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and (ii) changes in the Standardized Measure for fiscal years 2015 and 2016. Under that accounting guidance:

· Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the fiscal year-end estimated future proved reserve quantities.

· Future cash inflows are proved reserves at the prices used in determining proved reserves, i.e., for crude oil, natural gas, or natural gas liquids, the average price during the year, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

· Future development and operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using fiscal year-end cost rates and assuming continuation of existing economic conditions.

· Estimated future income taxes are computed using the current statutory income tax rates and with consideration of other tax matters such as (i) tax basis of our oil and natural gas properties and (ii) net operating loss carryforwards relating to our oil and natural gas producing activities. The resulting future after-tax net cash flows are discounted at 10% per annum to arrive at the Standardized Measure.

These assumptions do not necessarily reflect the Company’s expectations of actual net cash flows to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the Standardized Measure computations.

The following summary sets forth the Company’s Standardized Measure for January 31, 2014, 2015 and 2016:

	For the Years Ended January 31,
(in thousands)	2014		2015		2016
Future cash inflows	$	3,252,079	$	4,219,155	$	1,523,105
Future costs:
Production		(1,118,508)		(1,586,288)		(736,573)
Development		(505,432)		(439,749)		(150,099)
Future income tax expense		(364,340)		(394,538)		—
Future net cash flows		1,263,799		1,798,580		636,433
10% discount factor		(690,564)		(977,088)		(307,649)
Standardized measure of discounted future net cash flows relating to proved reserves	$	573,235	$	821,492	$	328,784

Because the estimated salvage value of equipment exceeds the related abandonment costs for well plugging and site restoration costs, future development costs at January 31, 2016 of $150.1 million does not include any net abandonment costs.

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The principle sources of change in the Standardized Measure are shown in the following table:

	For the Years Ended January 31,
(in thousands)	2014		2015		2016
Standardized measure, beginning of period	$	211,352	$	573,235	$	821,492
Extensions and discoveries, net of future production and development costs		333,140		312,185		28,807
Sales, net of production costs		(123,786)		(210,505)		(96,450)
Previously estimated development costs incurred during the period		66,724		121,282		71,047
Revision of quantity estimates		73,598		24,115		(89,939)
Net change in prices, net of production costs		19,173		(141,200)		(677,165)
Acquisition of reserves		99,683		91,327		—
Divestiture of reserves		(7,341)		(72)		(776)
Accretion of discount		22,486		67,790		98,281
Changes in future development costs		7,699		57,259		12,042
Change in income taxes		(91,161)		(56,652)		161,322
Change in production timing and other		(38,332)		(17,272)		123
Standardized measure, end of period	$	573,235	$	821,492	$	328,784

We calculate the projected income tax effect using the “year-by-year” method for purposes of the supplemental oil and natural gas disclosures and use the “short-cut” method for the ceiling test calculation. Companies that follow the full cost accounting method are required to make quarterly “ceiling test” calculations. This test limits total capitalized costs for oil and natural gas properties (net of accumulated amortization and deferred income taxes) to no more than the sum of (i) the present value discounted at 10% of estimated future net cash flows from proved reserves, (ii) the cost of properties not being amortized, (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized and (iv) all related tax effects. 

19.  SUBSEQUENT EVENTS

On April 13, 2016, RockPile entered into Amendment No. 2 with Citibank, N.A., as administrative agent and collateral agent, and the banks and other financial institutions party thereto. Amendment No. 2 amends that certain Credit Agreement, dated March 25, 2014, as amended on November 13, 2014 (the “Credit Agreement”), as reported in Current Reports on Form 8-K filed with the SEC on March 31, 2014 and November 19, 2014, respectively, to waive any default or event of default that may have arisen or that may arise from the failure of RockPile to (i) comply with the financial performance covenants in the Credit Agreement as of January 31, 2016 and April 30, 2016, and (ii) deliver its audited financial statements for the fiscal year ending January 31, 2016 without any qualification from RockPile’s independent accountants. The waivers are conditioned on RockPile agreeing to certain informational and process requirements and deadlines. Following the execution of Amendment No. 2, RockPile is precluded from drawing additional funds absent further amendment of the facility.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

1.Management’s Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures should be designed to ensure that information required to be disclosed by the Company is collected and communicated to management to allow timely decisions regarding required disclosures. The Chief Executive Officer and the Chief Accounting Officer (principal financial officer) have concluded, based on their evaluation as of January 31, 2016, that disclosure controls and procedures were effective in providing reasonable assurance that material information is made known to them by others within the Company.

2.Management’s Annual Report on Internal Control Over Financial Reporting

In regards to internal control over financial reporting, our management is responsible for the following:

· establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act), and

· assessing the effectiveness of internal control over financial reporting.

The Company’s internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Accounting Officer (principal financial officer) and effected by our Board of Directors, management and other personnel. It was designed to provide reasonable assurance to our management, our Board of Directors and external users regarding the fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that:

· pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets,

· provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and Board of Directors, and

· provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our Chief Executive Officer and our Chief Accounting Officer (principal financial officer), management assessed the effectiveness of our internal control over financial reporting as of January 31, 2016.Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013).

Our Chief Executive Officer and Chief Accounting Officer (principal financial officer) concluded that our internal control over financial reporting was effective as of January 31, 2016.

The effectiveness of our internal control over financial reporting as of January 31, 2016 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in their report.

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3.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 that occurred during the fiscal quarter ended January 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Triangle Petroleum Corporation:

We have audited Triangle Petroleum Corporation and subsidiaries’ (the Company) internal control over financialreporting as of January 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Triangle PetroleumCorporation’s management is responsible for maintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financial reporting, included in Item 9A.2. Management’sAnnual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on theCompany’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (UnitedStates). Those standards require that we plan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in all material respects. Our audit included obtaining anunderstanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testingand evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit alsoincluded performing such other procedures as we considered necessary in the circumstances. We believe that our auditprovides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regardingthe reliability of financial reporting and the preparation of financial statements for external purposes in accordance withgenerally accepted accounting principles. A company’s internal control over financial reporting includes those policiesand procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect thetransactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions arerecorded as necessary to permit preparation of financial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being made only in accordance with authorizations ofmanagement and directors of the company; and (3) provide reasonable assurance regarding prevention or timelydetection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect onthe financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may becomeinadequate because of changes in conditions, or that the degree of compliance with the policies or procedures maydeteriorate.

In our opinion, Triangle Petroleum Corporation maintained, in all material respects, effective internal control overfinancial reporting as of January 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (UnitedStates), the consolidated balance sheets of Triangle Petroleum Corporation and subsidiaries as of January 31, 2015 and2016, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the yearsin the three-year period ended January 31, 2016, and our report dated April 13, 2016 expressed an unqualified opinion on those consolidated financial statements. Our report dated April 13, 2016, contains an explanatory paragraph that states there is substantial doubt about the Company’s ability to continue as a going concern.

(signed) KPMG LLP

Denver, Colorado

April 13, 2016

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ITEM 9B. OTHER INFORMATION

On April 13, 2016, RockPile Energy Services, LLC, the Company’s wholly-owned subsidiary, entered into a Waiver and Amendment No. 2 to Credit Agreement (“Amendment No. 2”) with Citibank, N.A., as administrative agent and collateral agent, and the banks and other financial institutions party thereto. Amendment No. 2 amends that certain Credit Agreement, dated March 25, 2014, as amended on November 13, 2014 (the “Credit Agreement”), as reported in Current Reports on Form 8-K filed with the SEC on March 31, 2014 and November 19, 2014, respectively, to waive any default or event of default that may have arisen or that may arise from the failure of RockPile to (i) comply with the financial performance covenants in the Credit Agreement as of January 31, 2016 and April 30, 2016, and (ii) deliver its audited financial statements for the fiscal year ending January 31, 2016 without any qualification from RockPile’s independent accountants. The waivers are conditioned on RockPile agreeing to certain informational and process requirements and deadlines. Following the execution of Amendment No. 2, RockPile is precluded from drawing additional funds absent further amendment of the facility.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2016 Annual Meeting of Stockholders, which the Company expects to file with the Securities and Exchange Commission no later than May 30, 2016.

ITEM 11.  EXECUTIVE COMPENSATION

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2016 Annual Meeting of Stockholders, which the Company expects to file with the Securities and Exchange Commission no later than May 30, 2016.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2016 Annual Meeting of Stockholders, which the Company expects to file with the Securities and Exchange Commission no later than May 30, 2016.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2016 Annual Meeting of Stockholders, which the Company expects to file with the Securities and Exchange Commission no later than May 30, 2016.

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2016 Annual Meeting of Stockholders, which the Company expects to file with the Securities and Exchange Commission no later than May 30, 2016.

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PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibit No.	Description
3.1	Certificate of Incorporation of Triangle Petroleum Corporation, effective November 30, 2012, 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, effective December 4, 2013, 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	Amended and Restated Bylaws of Triangle Petroleum Corporation, effective December 2, 2015, filed as Exhibit 3.3 to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on December 8, 2015 and incorporated herein by reference.
4.1	Form of Common Stock Certificate of Triangle Petroleum Corporation, filed as Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.
4.2	5% Convertible Promissory Note, dated July 31, 2012, filed as Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.
4.3	Investment Agreement, dated July 31, 2012, among Triangle Petroleum Corporation, NGP Triangle Holdings, LLC and NGP Natural Resources X, L.P., filed as Exhibit 4.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.
4.4	First Amendment to Investment Agreement, dated March 8, 2013, between Triangle Petroleum Corporation, NGP Triangle Holdings, LLC, NGP Natural Resources X, L.P., and NGP Natural Resources X Parallel Fund, L.P., filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 13, 2013 and incorporated herein by reference.
4.5	Amended and Restated Registration Rights Agreement, dated March 8, 2013, between Triangle Petroleum Corporation, NGP Triangle Holdings, LLC, NGP Natural Resources X, L.P., and NGP Natural Resources X Parallel Fund, L.P., filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 13, 2013 and incorporated herein by reference.
4.6	Rights Agreement, dated August 28, 2013, between Triangle Petroleum Corporation and ActOil Bakken, LLC, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 2013 and incorporated herein by reference.
10.1†	Amended and Restated 2011 Omnibus Incentive Plan, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 16, 2012 and incorporated herein by reference.
10.2†	CEO Stand-Alone Stock Option Agreement, dated July 4, 2013, between Triangle Petroleum Corporation and Jonathan Samuels, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 10, 2013 and incorporated herein by reference.
10.3†	Triangle Petroleum Corporation 2014 Equity Incentive Plan, filed as Exhibit 10.1 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on May 30, 2014 and incorporated herein by reference.
10.4†	Third Amended and Restated Employment Agreement, dated July 4, 2013, between Triangle Petroleum Corporation and Jonathan Samuels, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 10, 2013 and incorporated herein by reference.
10.5†	First Amendment to Third Amended and Restated Employment Agreement, dated January 31, 2015, between Triangle Petroleum Corporation and Jonathan Samuels, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on February 5, 2015 and incorporated herein by reference.

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Exhibit No.	Description
10.6†	Amended and Restated Employment Agreement, dated September 9, 2014, between Triangle Petroleum Corporation and Justin Bliffen, filed as Exhibit 10.1 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on September 11, 2014 and incorporated herein by reference.
10.7†	Employment Agreement, dated December 14, 2012, by and between RockPile Management, LLC and Robert Dacar, filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on June 9, 2014 and incorporated herein by reference.
10.8	Note Purchase Agreement, dated July 31, 2012, between Triangle Petroleum Corporation and NGP Triangle Holdings, LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.
10.9	Stock Purchase Agreement, dated March 2, 2013, between Triangle Petroleum Corporation and NGP Triangle Holdings, LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 4, 2013 and incorporated herein by reference.
10.10	Stock Purchase Agreement, dated August 6, 2013, between Triangle Petroleum Corporation and TIAA Oil and Gas Investments, LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 2013 and incorporated herein by reference.
10.11	Second Amended and Restated Contribution Agreement, dated January 31, 2015, by and among Triangle Caliber Holdings, LLC, Caliber Midstream GP LLC, Caliber Midstream Partners, L.P., and FREIF Caliber Holdings LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on February 5, 2015 and incorporated herein by reference.
10.12	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 onForm 8-Kfiled with the Securities and Exchange Commission on May 19, 2014 and incorporated herein by reference.
10.13	Purchase and Sale Agreement, dated August 5, 2013, by and among Kodiak Oil & Gas (USA) Inc. and Kodiak Williston, LLC, collectively, as Seller, and Triangle USA Petroleum Corporation, as Purchaser, filed as Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 2013 and incorporated herein by reference.
10.14	Credit Agreement, dated March 25, 2014, between RockPile Energy Services, LLC, as Borrower, the Lenders Party Hereto, Citibank, N.A., as Administrative Agent and Collateral Agent, and Citibank, N.A. and Wells Fargo Bank, National Association, as Joint Lead Arrangers and Joint Bookrunners, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 31, 2014 and incorporated herein by reference.
10.15	Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement, dated November 13, 2014, between RockPile Energy Services, LLC, as Borrower, Citibank, N.A., as Administrative Agent and Collateral Agent, and the banks and other financial institutions signatories thereto, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 19, 2014 and incorporated herein by reference.
10.16	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 onForm 8-Kfiled with the Securities and Exchange Commission on July 18, 2014 and incorporated herein by reference.
10.17	Form of 6.75% Senior Notes due 2022, filed as Exhibit 10.2 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on July 18, 2014 and incorporated herein by reference.
10.18	Second Amended and Restated Credit Agreement, dated November 25, 2014, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Issuing Lender, and the Lenders Named Therein, filed as Exhibit 10.1 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on December 2, 2014 and incorporated herein by reference.

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Exhibit No.	Description
10.19	Amendment No. 1 to Second Amended and Restated Credit Agreement, dated April 30, 2015, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Issuing Lender, and the Lenders and Subsidiary Guarantors Named Therein, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on May 4, 2015 and incorporated herein by reference.
14.1	Code of Business Conduct and Ethics, filed as Exhibit 14.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 6, 2011 and incorporated herein by reference.
21.1*	List of Subsidiaries.
23.1*	Consent of Cawley, Gillespie & Associates, Inc.
23.2*	Consent of KPMG LLP.
24.1	Power of Attorney (incorporated by reference to the signature page of this annual report on Form 10-K).
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 Accounting Officer (principal 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*	Certification of Chief Executive Officer and Chief Accounting Officer (principal financial officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Reserves Audit Report of Cawley, Gillespie & Associates, Inc.
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.

† Management Contract or Compensatory Plan or Arrangement.

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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:  April 13, 2016	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	President and Chief Executive Officer

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Jonathan Samuels and Douglas Griggs, jointly and severally, his or her attorney-in-fact, with the power of substitution, for him or her in any and all capacities, to sign any amendments to this annual report on Form 10-K and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact, or his or her substitute or substitutes, may do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

6
Name	Position	Date
/s/ JONATHAN SAMUELS	President and Chief Executive Officer, Director	April 13, 2016
Jonathan Samuels	(principal executive officer)
/s/ DOUGLAS J. GRIGGS	Chief Accounting Officer	April 13, 2016
Douglas J. Griggs	(principal financial officer, principle accounting officer)
/s/ PETER HILL	Director (Chairman of the Board)	April 13, 2016
Peter Hill
/s/ ROY ANEED	Director	April 13, 2016
Roy Aneed
/s/ GUS HALAS	Director	April 13, 2016
Gus Halas
/s/ RANDAL MATKALUK	Director	April 13, 2016
Randal Matkaluk

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UNITS OF MEASUREMENT AND GLOSSARY OF INDUSTRY TERMS

Units of Measurement

The following presents a list of units of measurement used throughout this annual report:

Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume.

Bbl/d – Bbl per day.

Boe – One barrel of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d – Boe per day.

Btu – One British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

Mbbls – One thousand barrels of crude oil.

Mboe – One thousand barrels of crude oil equivalent.

Mcf – One thousand cubic feet of natural gas volume.

MMboe – One million barrels of crude oil equivalent.

MMbtu – One million British thermal units.

MMcf – One million cubic feet of natural gas volume.

Glossary of Industry Terms

The following are abbreviations and definitions of some of the oil and natural gas industry terms used in this annual report:

Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Delay rental. A payment made to the lessor under a non-producing oil and natural gas lease at the end of each year to continue the lease in force for another year during its primary term.

Developed reserves. Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Drill spacing unit or DSU. An area allotted to a well by regulations or field rules issued by a governmental authority having jurisdiction for the drilling and production of a well.

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differ from nearby rock.

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Fracturing. Mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks greatly by connecting pores together.See “Hydraulic fracturing.”

Gas or natural gas. The lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but may contain liquids.

GHGs. Gases, such as carbon dioxide and methane, that when released into the atmosphere contribute to, or are believed to contribute to, global warming.These gases are commonly known as “greenhouse gases.”

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal well. A well that is drilled vertically to a certain depth and then drilled at a right angle within a specific interval.

Hydraulic fracturing. A procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand or ceramic material) into the formation under high pressure.This creates artificial fractures in the reservoir rock, which increases permeability and porosity.

Leases. Full or partial interests in oil or natural gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for rental, bonus and/or royalty payments.Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

Natural Gas Liquids or NGLs. Liquid hydrocarbons that are extracted from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and heavier hydrocarbons.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Non-operated acreage. Lease acreage owned by the Company for which another oil and natural gas company serves or is expected to serve as the operator of the wells to be drilled and completed.The oil and natural gas company with the largest working interest in a proposed well usually serves as that well’s operator and oversees the well operations on behalf of all the well’s working interest owners.

NYMEX. New York Mercantile Exchange.

Operated acreage. Lease acreage owned or controlled by the Company and to be developed with the Company serving as operator of the wells to be drilled and completed thereon.

Operator. The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

Plugging and abandonment. This term refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.

Pooling. Pooling is a technique used by oil and natural gas development companies to organize an oil or natural gas field.

Pressure pumping. Pumping a fluid down a well for the purpose of improving production from the well.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

Proppant. Particles that are mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used.Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial quantities of hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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Proved properties. Properties with proved reserves.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where relatively major capital expenditures are required to start producing the proved undeveloped reserves.

PV-10 value. The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using average prices for the preceding 12-month period and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty. The share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the relevant well, except for state and local production taxes.

Seismic. Geophysical data that depicts the subsurface strata.

Spacing.  The distance between wells producing from the same reservoir.Spacing is often expressed in terms of wells per acre and is often established by regulatory agencies.

Undeveloped acreage. Lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves.

Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests.Also, the area covered by a unitization agreement.

Unproved properties. Properties with no proved reserves.

Wellbore. The hole drilled by a bit that is equipped for oil or natural gas production when the well is completed.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate, also known as Texas light sweet, is a grade of crude oil used as a benchmark in oil pricing. This grade is described as light because of its relatively low density, and sweet because of its low sulfur content.

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