10-K 1 a2219702z10-k.htm 10-K

Use these links to rapidly review the document
TABLE OF CONTENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended January 31, 2014

001-34945
(Commission File No.)

LOGO

TRIANGLE PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)

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

1200 17th Street, Suite 2600, 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:   Name of each exchange on which registered:
Common stock, $0.00001 par value   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 o    No ý

         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 o    No ý

         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 ý    No o

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

         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. o

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

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

         As of July 31, 2013, 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 $328,585,579 based on a closing price of $7.10 per share as reported on the NYSE MKT on such date.

         As of April 1, 2014, the registrant had 85,941,961 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

         Part III incorporated by reference from the registrant's Definitive Proxy Statement for its 2014 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.

   


Table of Contents


TRIANGLE PETROLEUM CORPORATION
FORM 10-K FOR THE FISCAL YEAR ENDED JANUARY 31, 2014
TABLE OF CONTENTS

 
   
  Page  

Part I

 

 

       

Item 1.

 

Business

   
10
 

Item 1A.

 

Risk Factors

   
31
 

Item 1B.

 

Unresolved Staff Comments

   
52
 

Item 2.

 

Properties

   
52
 

Item 3.

 

Legal Proceedings

   
52
 

Item 4.

 

Mine Safety Disclosures

   
52
 

Part II

 

 

   
 
 

Item 5.

 

Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

   
53
 

Item 6.

 

Selected Financial Data

   
56
 

Item 7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

   
57
 

Item 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

   
81
 

Item 8.

 

Consolidated Financial Statements and Supplementary Data

   
83
 

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosures

   
146
 

Item 9A.

 

Controls and Procedures

   
146
 

Item 9B.

 

Other Information

   
151
 

Part III

 

 

   
 
 

Item 10.

 

Directors, Executive Officers and Corporate Governance

   
151
 

Item 11.

 

Executive Compensation

   
151
 

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   
151
 

Item 13.

 

Certain Relationships and Related Transactions, Director Independence

   
151
 

Item 14.

 

Principal Accounting Fees and Services

   
151
 

Part IV

 

 

   
 
 

Item 15.

 

Exhibits; Financial Statement Schedules

   
152
 

Signatures

   
156
 

2


Table of Contents

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. 20549-0213. 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 by officers and directors 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 or calling Triangle at 1200 17th Street, Suite 2600, Denver, CO 80202 or by calling 1-303-260-7125.

3


Table of Contents

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:

    Triangle's future capital expenditures and performance;

    anticipated drilling and development;

    drilling results;

    results of acquisitions;

    Triangle's relationships with partners;

    Triangle's plans for RockPile Energy Services, LLC; and

    Triangle's plans for Caliber Midstream Partners, LP.

        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:

    Triangle's ability to acquire additional leasehold interests or other oil and natural gas properties;

    Triangle's ability to manage growth in its businesses;

    Triangle's ability to control properties we do not operate;

    Triangle's ability to protect against certain liabilities associated with properties;

    lack of diversification;

    substantial capital requirements and access to additional capital;

    competition in the oil and natural gas industry;

    global financial conditions;

    oil and natural gas prices;

    seasonal weather conditions;

    marketing and distribution of oil and natural gas;

    the influence of significant stockholders;

    government regulation of the oil and natural gas industry;

    potential regulation affecting hydraulic fracturing;

4


Table of Contents

    environmental regulations, including climate change regulations;

    uninsured or underinsured risks;

    defects in title to Triangle's oil and natural gas interests;

    changes in the fair value of our derivative instruments; and

    material weaknesses in internal accounting controls.

        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.

5


Table of Contents


GLOSSARY OF ABBREVIATIONS AND TERMS

        The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.

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

        Bbl.    One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

        Bcf.    Billion cubic feet of gas.

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

        Boepd.    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.

        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.

        Condensate.    A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

        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.

        DSU or drill spacing unit.    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.

        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.

6


Table of Contents

        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.

        Mbbls.    Thousands of stock tank barrels; used in this report in reference to crude oil or other liquid hydrocarbons.

        Mboe.    Thousand barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

        Mcf.    Thousand cubic feet of natural gas.

        MMbtu.    One million British Thermal Units.

        Mcfe.    Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

        MMcf.    Million cubic feet of natural gas.

        MMcfe.    Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

        Mgal.    Thousand gallons of liquid hydrocarbons.

        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.

7


Table of Contents

        Overriding royalty.    An interest in the gross revenues or production over and above the landowner's royalty carved out of the working interest and also unencumbered by any expenses of operation, development or maintenance, except for state and local production taxes on the overriding royalty.

        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.

        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 prices 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.

8


Table of Contents

        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 acres 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.

        Zipper fracturing.    The process of hydraulic fracturing two horizontal wells simultaneously. The wells are drilled in the same direction with their laterals spaced a given distance apart. The fracturing operations are then alternated between each of the wells, (e.g. fracturing stage 1 in well #1 and then alternating to stage 1 in well # 2; stage 2 in well #1, stage 2 in well #2, and so on, until all stages are complete in each well). The result is a zipper-like appearance of the fracturing between the two wells.

9


Table of Contents


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. The terms fiscal year 2015 ("FY2015"), fiscal year 2014 ("FY2014"), fiscal year 2013 ("FY2013"), and fiscal year 2012 ("FY2012") herein refer to the fiscal years ended January 31, 2015, 2014, 2013, and 2012, respectively.

ITEM 1.    BUSINESS

Company Overview

        We are a growth-oriented, independent energy holding company with three principal lines of business: oil and natural gas exploration, development and production; oilfield services; and midstream services. We conduct these activities in the Williston Basin of North Dakota and Montana through the Company's two principal wholly-owned subsidiaries and our joint venture:

    Triangle USA Petroleum Company ("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 well completion and workover services;

    Caliber Midstream Partners, LP ("Caliber") is our 30% owned joint venture with First Reserve Energy Infrastructure Fund ("FREIF"). Caliber currently plans to provide freshwater delivery, produced water transportation and disposal, crude oil gathering and stabilization services, natural gas gathering and processing services.

        Our primary focus at TUSA is to grow our production volumes through the efficient development of our operated Bakken Shale and Three Forks drilling inventory. We completed our first operated well in May 2012. From May 2012 through January 31, 2014, we have completed 47 gross (34.5 net) operated wells. Our average net daily production for FY2014 was 5,286 Boepd, approximately 75% of which was operated production. The growth we have experienced is facilitated by the use of pad drilling, which increases efficiencies while controlling costs and minimizing environmental impact. We also use advanced completion, collection and production techniques designed to optimize reservoir production while reducing costs. Our estimated proved oil and natural gas reserves as of January 31, 2014 totaled 40,314 Mboe (79% oil).

        In an effort to better control key operations, reduce costs, and retain supply chain value in the Williston Basin, which we view as a resource-constrained and cost-heavy basin, we formed RockPile and entered into our 30% owned joint venture arrangement with FREIF to form Caliber. RockPile's services lower our realized well completion costs, and RockPile affords us greater control over completion schedules, quality control and pay cycles. We expect that Caliber will reduce the cost and environmental impacts of trucking oil and water and reduce or eliminate the emissions generated by the flaring of produced natural gas from our operated wells. In addition to providing services to TUSA, RockPile and Caliber are focused on growing their respective businesses through securing independent, third-party contracts.

        Triangle has two reportable operating segments. Our exploration and production operating segment and our oilfield services operating segment are managed separately because of the nature of their products and services. The focus of the exploration and production operating segment is finding and producing oil and natural gas. The focus of the oilfield services operating segment is pressure pumping for both Triangle-operated wells and wells operated by third-parties. See Part II. Item 8.

10


Table of Contents

Consolidated Financial Statements and Supplementary Data, Note 4Segment Reporting, for additional information on our segments.

        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.

Strategies

        Our primary objective is to increase stockholder value by converting leasehold positions into proved reserves, production and cash flow at attractive returns on invested capital through a vertically integrated, low cost structure. To achieve these objectives we strive to:

    accelerate drilling, inventory and production growth in the Williston Basin;

    maximize efficiencies and lower costs within our operated units;

    improve cost structure and returns through vertical integration;

    continue to acquire assets and businesses at attractive costs that complement our current businesses;

    continue to focus leasehold efforts on converting non-operated acreage to operated acreage; and

    operate in a safe and environmentally responsible manner.

Recent Events

RockPile Credit Facility

        On March 25, 2014, RockPile entered into a Credit Agreement (the "FY2015 RockPile Credit Agreement") by and among RockPile, as borrower, Citibank, N.A. ("Citi"), as administrative agent and collateral agent, Wells Fargo Bank, National Association ("Wells Fargo"), as joint lead arranger and joint book runner with Citi, and the other lenders party thereto. The FY2015 RockPile Credit Agreement provides for a $100.0 million senior secured revolving credit facility with an accordion feature that allows for the expansion of the facility up to $150.0 million. The credit facility is expected to support RockPile's growth initiatives and enable RockPile to remain self-funded as it contemplates additional investment in the infrastructure and equipment necessary to support broad-based growth across its service lines. A portion of the credit facility proceeds will be utilized to refinance RockPile's existing indebtedness. Neither Triangle nor its non-RockPile subsidiaries act as a guarantor under the FY2015 RockPile Credit Agreement.

Summary of FY2014 Highlights

        During FY2014, we accomplished the following:

    Drilled and completed 27 gross (20.1 net) operated wells, a net well increase of 112% versus FY2013;

    Increased average daily production by approximately 295% year-over-year to 5,286 Boepd;

    Increased proved reserves from approximately 14,637 Mboe at January 31, 2013 to 40,314 Mboe at January 31, 2014, an increase of approximately 175% year-over-year;

    Generated total revenues of $258.7 million, an increase of 326% from FY2013;

    Revenues from oil and gas sales increased from $39.6 million in FY2013 to $160.5 million in FY2014;

11


Table of Contents

      Consolidated revenues from oilfield services increased from $20.7 million in FY2013 to $98.2 million in FY2014;

    Increased net income attributable to common stockholders to $73.5 million for FY2014, or $0.91 per diluted share, an increase of $87.2 million from FY2013;

    Generated cash flow from operating activities of $85.6 million;

    Increased operated DSUs from 92 in FY2013, including 33 in our core area, to 101 in FY2014, including 42 in our core area;

    RockPile completed 31 TUSA wells and 50 third-party wells, as compared to 12 TUSA wells and 5 third party wells in FY2013;

    RockPile deployed into service a second hydraulic fracturing spread and its first wireline unit;

    RockPile acquired Team Well Service, Inc., an operator of well service rigs in North Dakota;

    Connected 31 new wells to the Caliber midstream system; and

    Caliber closed a currently undrawn $200.0 million credit facility secured only by Caliber's assets (no Triangle or FREIF guaranty).

Exploration, Development and Production

Williston Basin—United States

        As of January 31, 2014, we held leasehold interests in approximately 94,000 net acres in the Williston Basin. Approximately 45,000 net acres are located in our core focus area in McKenzie and Williams Counties, North Dakota, 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 30,000 net acres in our Core Acreage. We also hold approximately 49,000 net acres in the Station Prospect located in Sheridan and Roosevelt Counties, Montana, of which we operate approximately 33,000 net acres. 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.

        As of January 31, 2014, we have completed a total of 47 gross (34.5 net) operated wells in the Williston Basin. As of that date we were running a three-rig drilling program. In the first quarter of FY2015, we added a fourth drilling rig and plan to continue a four-rig program throughout FY2015. During FY2015, we anticipate drilling 48 to 56 gross operated wells and completing 44 to 50 gross operated wells in North Dakota or eastern Montana for completion in the Bakken Shale or Three Forks formations. 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.

        The operations of our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Oasis Petroleum, Hess Corporation, Continental Resources, Statoil, Newfield Exploration, EOG Resources, XTO Energy, Whiting Petroleum, Slawson Exploration Company and Kodiak Oil & Gas Corporation. These companies are experienced operators in the development of the Bakken Shale and Three Forks formations. Since commencement of drilling in May 2012 through the end of FY2014, we have elected to participate in the drilling of 250 gross (11.7 net) non-operated wells, 203 gross (9.7 net) of which are producing and 47 gross (2.1 net) are in various stages of permitting, drilling or completion.

12


Table of Contents

        Discussed below are key aspects of our drilling program in our Core Acreage:

    Long Laterals.  Based upon our analysis of well costs and the performance from our operated wells and other operators' wells, we believe long laterals (~10,000 feet) in our horizontal wells are better than short laterals (~5,000 feet or less) for wells in our Core Acreage. Although utilizing long laterals is more expensive, we estimate that the additional costs of drilling the longer lateral and adding more fracture stimulation stages is more than offset by the associated incremental increase in oil production cash flows. Accordingly, we plan to continue drilling ~10,000 foot laterals throughout our Core Acreage position.

    Multi-Well Pads.  We typically drill two or more wells per rig visit to each pad. As we continue the development stage of our drilling, we expect the average number of wells drilled per pad to increase. We have designed our initial pads to accommodate the increased number of wells expected on each pad. We plan to continue capitalizing on the many benefits of pad drilling to increase our efficiencies and reduce costs. Pad drilling allows for the reduction of rig mobilization and demobilization costs, the aggregation of necessary infrastructure and distribution of costs for the same. Pad drilling also allows for increased efficiencies and cost savings when completing our wells using techniques such as zipper fracturing. Utilization of zipper fracturing techniques allows the simultaneous completion of two or more wells by alternating perforation and pressure pumping operations. We also perform other simultaneous operations on our well pads, allowing for continuous production from an existing well while drilling and completing activities for another well on the same pad. Pad drilling also reduces the surface footprint of our operations.

    Wellbore Spacing.  Consistent with other operators near our Core Acreage position, we are developing our wellbores on tighter spacing patterns. Our initial test drilling included three wellbores drilled within 600 feet, laterally, of one another in the Middle Bakken formation, and these wells continue to perform well. We currently have seven DSUs with wells spaced within 600 feet, laterally, of one another. These and other tests performed by Triangle and other operators suggest that up to eight Middle Bakken wells can be drilled per DSU without significant communication between wellbores.

    Contiguous Acreage.  Our Core Acreage operated leasehold is largely contiguous and, by virtue of our high working interest and operatorship, we can control the development pace and location of surface facilities. We believe this strategy, combined with pad drilling, Caliber's infrastructure and efficiencies provided by RockPile, should maximize the efficiency of our drilling and completion program and minimize the capital costs of developing our acreage position.

    Acreage Held by Production.  Our drilling activity has resulted in the majority of our operated drilling units being held by production. As a result, we are now able to more systematically plan our drilling and completion activities. This provides increased flexibility in our capital program and allows us to more efficiently develop our leaseholds toward the proper ultimate spacing for each drilling unit.

    Infrastructure.  As of January 31, 2014, we have 54 operated wells, 43 (80%) of which are currently connected to Caliber or third-party midstream pipelines and processing facilities for natural gas liquids, allowing for the reduction of flared volumes and the capture of additional revenue from the liquids-rich gas that is produced with our oil. Caliber has 31 of our operated wells connected to fresh water delivery and 17 operated wells connected to its oil and produced water gathering infrastructure. Most of our Core Acreage will soon be served by similar Caliber or third-party oil and natural gas gathering systems. The majority of our wells are also in the process of being connected to regional oil and natural gas pipelines. Moving produced fluids (oil, natural gas and water) through pipelines eliminates trucking costs and associated environmental disturbance, and mitigates weather related production interruptions. Upon completion of

13


Table of Contents

      Caliber's Medium Haul Pipeline to Alexander, North Dakota, a large portion of our production will have access to various means of transportation to market, which should maximize revenue while minimizing impacts to the environment.

Canada—Nova Scotia

        We also hold leasehold interests in acreage in the Maritimes Basin of Nova Scotia, Canada. Nova Scotia currently has in place a moratorium on hydraulic fracturing and currently does not allow the use of salt water disposal wells. We fully impaired our Nova Scotia leasehold assets as of January 31, 2012. Our Canadian assets are not material to our asset base or development plans.

Reserves

Net Reserves of Crude Oil, Natural Gas and Natural Gas Liquids at Fiscal Year-End 2014, 2013 and 2012

        Approximately 99% of the Company's proved reserves at January 31, 2014 are primarily 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, 2013 and 2012, the estimated projected future cash flows (before income taxes) from those proved reserves, and the PV-10 Value of the proved reserves at January 31, 2014, 2013 and 2012:

 
  As of January 31,  
 
  2014   2013   2012  

Proved developed:

                   

Oil (Mbbls)

    13,734     4,985     538  

Natural gas (MMcf)

    10,930     5,906     202  

NGL (Mbbls)

    1,440          

Proved undeveloped:

                   

Oil (Mbbls)

    18,182     7,555     827  

Natural gas (MMcf)

    15,574     6,679     472  

NGL (Mbbls)

    2,541          

Total proved oil reserves (Mbbls)

   
31,916
   
12,540
   
1,365
 

Total proved natural gas reserves (MMcf)

    26,504     12,585     674  

Total proved NGL reserves (Mbbls)

    3,981          

Total proved oil, NGL and natural gas reserves (Mboe)

    40,314     14,637     1,477  

PV-10 Values (in thousands) of proved reserves:

   
 
   
 
   
 
 

PV-10 Value of proved developed reserves

  $ 471,764   $ 165,484   $ 19,393  

PV-10 Value of proved undeveloped reserves

  $ 206,141   $ 59,377   $ 10,035  

PV-10 Value of total proved reserves

  $ 677,905   $ 224,861   $ 29,428  

        The increase in our total proved reserves in FY2014 of 25,677 Mboe resulted primarily from our drilling and completion activity on the Bakken and Three Forks formations properties. As a result of our drilling program, we increased the number of proved undeveloped ("PUD") locations from 59 gross (19.8 net) at fiscal year-end 2013 to 104 gross (52.5 net) at fiscal year-end 2014. These PUD locations offset our existing producing wells or are located in drill spacing units that offset producing wells.

        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 31st estimation date except that future commodity prices used in the projections reflected a simple average of prices for the well or property on the first day of each of the twelve months in the fiscal year ended on the estimation date. Prices of $97.49 per Bbl for oil, $54.25 per barrel for natural

14


Table of Contents

gas liquids, and $3.73 per MMbtu for natural gas were adjusted for regional price differentials and other factors to arrive at prices of $93.09 per Bbl for oil, $44.10 per barrel for natural gas liquids, and $3.99 per Mcf for natural gas, which were used in the calculation of proved reserves at January 31, 2014.

        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. Accordingly, reserve estimates are often different from the quantities that are ultimately recovered.

        The following table reconciles (a) the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves ("Standardized Measure"), a measure calculated in accordance with generally accepted accounting principles ("GAAP") to (b) the PV-10 Value (a non-GAAP financial measure) of our proved reserves. The difference is due to the fact that PV-10 Value excludes the impact of income taxes.

 
  As of January 31,  
(in thousands)
  2014   2013   2012  

Standardized Measure, for total proved reserves

  $ 573,235   $ 211,352   $ 29,428  

Add back: Discounting at 10% per annum

    690,564     297,653     26,246  
               

Future cash flow, after income taxes

    1,263,799     509,005     55,674  

Add: future undiscounted income taxes

    364,340     87,313      
               

Undiscounted future net cash flows before taxes

    1,628,139     596,318     55,674  

Less: Discounting at 10% per annum

    (950,234 )   (371,457 )   (26,246 )
               

PV-10 Value of total proved oil and natural gas reserves

  $ 677,905   $ 224,861   $ 29,428  
               
               

        The Standardized Measure is presented more fully and discussed further in Part II. Item 8. Consolidated Financial Statements and Supplementary Data, Note 24—Unaudited Supplemental Oil and Natural Gas Disclosures.

Proved Undeveloped Reserves

        At January 31, 2014, we estimated proved undeveloped reserves of 23,319 Mboe, which represents 58% of our total proved reserves as compared to 8,668 Mboe or 59% of our total proved reserves at January 31, 2013. In connection with our drilling and completion program, we incurred approximately $74.9 million (averaging $9.4 million per net well) related to the conversion of 3,701 Mboe (32 gross wells, 7.9 net wells) from proved undeveloped reserves to proved developed reserves.

15


Table of Contents

        Changes in our proved undeveloped reserves are summarized in the following table:

 
  Mboe   Gross Wells   Net Wells  

At January 31, 2013

    8,668     59     19.8  

Became developed reserves in fiscal year 2014

    (3,701 )   (32 )   (7.9 )

Traded for net acres in other drill spacing units

    (353 )   (4 )   (0.8 )

Negative revisions

    (31 )        

Positive revisions

    115          

Acquisitions

    5,466     13     11.8  

Extensions and discoveries of proved reserves

    13,155     68     29.6  
               

At January 31, 2014

    23,319     104     52.5  
               
               

        For proved undeveloped locations at January 31, 2014, the following table provides further information on the timing and status of operated and non-operated locations:

 
   
  Development
Wells
 
 
  PUD
Locations
 
 
  Gross   Net  

Proved undeveloped locations:

                   

For which Triangle operated wells are to be drilled and completed by December 31, 2018

    85     85     51.3  

For which non-operated wells were in-progress at January 31, 2014 and are expected to be completed in fiscal year 2015

    2     2      

That are non-operated wells with drilling permits

    2     2     0.2  

That are non-operated wells to be drilled by July 31, 2016

    15     15     1.0  
               

Total

    104     104     52.5  

        At January 31, 2014, we have no proved undeveloped reserves that are scheduled for development five years or more beyond the date the reserves were initially recorded.

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 and 2013, Triangle's Senior Reservoir Engineer 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.

16


Table of Contents

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 FY2014 year-end 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 provide to them. The internal reserve estimates and supporting schedules are prepared by our Reserve Engineer and reviewed by management prior to being provided to Cawley Gillespie.

        Cawley Gillespie's FY2014 year-end reserves audit report (filed as Exhibit 99.1 to this annual report) states that Cawley Gillespie is a Texas Registered Engineering Firm (F-693), made up 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.

Developed and Undeveloped Acreage

        As of January 31, 2014, we had approximately 2,667 lease agreements representing approximately 217,377 gross (93,552 net) acres in the Williston Basin of North Dakota and Montana. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

 
  Developed Acres   Undeveloped Acres   Total Acres  
 
  Gross   Net   Gross   Net   Gross   Net  

North Dakota

    94,721     31,323     40,879     9,188     135,600     40,511  

Montana

    1,176     406     80,601     52,635     81,777     53,041  
                           

Total

    95,897     31,729     121,480     61,823     217,377     93,552  

        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. We expect to establish production from most of our acreage prior to expiration of the applicable lease. However, there can be no guarantee we will do so.

17


Table of Contents

        The table below shows by future fiscal year (i) costs of available lease extensions, (ii) net acres expiring without lease extensions, and (iii) net acres expiring with lease extensions (assuming the leases are not developed and held by production):

 
   
  Net Acres Expiring  
Fiscal Year
  Future
Extension Costs
(in thousands)
  If No
Extensions
  With All
Extensions
 

2015

  $ 1,832     20,458     12,673  

2016

  $ 215     18,710     19,752  

2017

  $     18,894     24,560  

2018

  $     353     1,430  

2019

  $          

Thereafter

  $     197     197  
                 

Total

  $ 2,047     58,612     58,612  
                   
                   

Already extended

               
                 

          58,612     58,612  

Held by production

          3,211     3,211  
                 

Total Undeveloped Net Acres

          61,823     61,823  
                 
                 

        The table above shows that, with all currently allowed extensions, 12,673 net acres would expire in FY2015 if no drilling occurs or other actions are taken to further extend the lease life. We anticipate that approximately 8,610 net acres will expire in FY2015, of which approximately 185 acres are in our Core Acreage. However, we are taking steps to minimize expirations of those leaseholds we believe are accretive to our drilling and development program.

Drilling and Other Exploratory and Development Activities

        The following table presents the gross and net number of exploration wells and development wells drilled in the U.S. during fiscal years 2014, 2013 and 2012, based on the date of first sales or capable of selling. There was no drilling activity in Canada during the same periods. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. Well completion refers to installation of permanent equipment for production of oil or

18


Table of Contents

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.

 
  Fiscal Year
2014
  Fiscal Year
2013
  Fiscal Year
2012
 
 
  Gross   Net   Gross   Net   Gross   Net  

Productive exploratory wells:

                                     

Operated by Triangle

    9     7.2     6     3.2          

Operated by others

    37     2.0     41     0.6     50     2.1  
                           

Total

    46     9.2     47     3.8     50     2.1  
                           

Dry exploratory wells

            1              

Productive development wells:

   
 
   
 
   
 
   
 
   
 
   
 
 

Operated by Triangle

    22     16.3     10     6.9          

Operated by others

    44     2.6     14     0.7     11     0.6  
                           

Total

    66     18.9     24     7.6     11     0.6  
                           

Dry development wells

                         
                           

Total productive wells

    112     28.1     71     11.4     61     2.7  
                           
                           

        As of January 31, 2014, we had 257 gross productive wells and 50 net productive wells, all located in North Dakota except for one well located in Roosevelt County, Montana. None of our gross productive wells had multiple completions. Our count of productive wells does not include wells that were awaiting completion, in the process of completion, or awaiting flowback subsequent to fracture stimulation as of that date. We have not participated in any wells targeting natural gas reserves.

Costs Incurred and Capitalized Costs

        The table below present costs incurred in oil and natural gas acquisition, exploration and development activities in the U.S. during fiscal years 2014, 2013 and 2012. There were no such costs in Canada in those periods.

(in thousands)
  2014   2013   2012  

Property acquisition

  $ 121,578   $ 21,193   $ 87,226  

Exploration

    96,731     55,583     40,728  

Development

    216,046     91,666     4,706  
               

Total

  $ 434,355   $ 168,442   $ 132,660  
               
               

        We anticipate our unproved properties and properties under development costs at January 31, 2014 of $121.4 million will be included in the amortization computation over the next five years. We are unable to predict the future impact on amortization rates.

Oilfield Services

        RockPile, our wholly-owned subsidiary initially capitalized in October 2011, is a provider of hydraulic oilfield and complementary well completion services to oil and natural gas exploration and production companies in the Williston Basin. RockPile purchased its first set of equipment, collectively known as a "spread", in the first half of 2012. RockPile's first spread commenced 12-hour operations in July 2012 and 24-hour operations in September 2012. RockPile commenced 24-hour operations with a second spread in July 2013 and anticipates delivery of its third spread in the second quarter of FY2015. RockPile's management team has extensive experience providing oilfield services in the Williston Basin.

19


Table of Contents

        RockPile provides a variety of oilfield services including, but not limited to, pressure pumping, wireline, perforating, pumping and pump rental. The use of these services lowers our realized well completion costs and affords us greater control over completion schedules, quality control and pay cycles. In FY2014, RockPile increased year-over-year completions by approximately 376%, completing 31 TUSA operated wells and 50 third-party wells, as compared to 12 TUSA operated wells and five third-party wells in FY2013. RockPile contributed $98.2 million to our revenue for the year ended January 31, 2014. We believe that the breadth of RockPile's services and the experience and expertise of their personnel give it a competitive advantage relative to many of its competitors in the region.

        RockPile's customers use hydraulic fracturing or pressure pumping services to enhance the production of oil and natural gas from formations with low permeability, which restricts the natural flow of hydrocarbons. Hydraulic fracturing involves pumping fluid down a well casing or tubing at sufficient pressure to cause the underground producing formation to fracture, allowing the oil or natural gas to flow more freely. A propping agent, or proppant, is suspended in the fracturing fluid and pumped into the fractures created by the fracturing process in the underground formation to prop the fractures open. Proppants generally consist of sand, bauxite, resin-coated sand or ceramic particles and other engineered proprietary materials. The extremely high pressure required to stimulate wells in the regions in which we operate presents a challenging environment for achieving a successfully fractured horizontal well. As a result, an important element of the services RockPile provides to producers is assisting with well completion design, which includes determining the proper fluid, proppant and injection specifications to maximize production.

        In addition, RockPile's workover rig division provides intervention and remedial services such as drill out, clean outs, installation and replacement of pumps, packers and frac strings, swabbing, and well repair and maintenance. As the Williston Basin matures, demand for remedial service is also expected to increase.

        RockPile has historically operated exclusively in the Williston Basin. While RockPile expects that the Williston Basin will remain the focus of its operations, it is currently evaluating opportunities in other areas.

Midstream Services

        Caliber is an energy infrastructure joint venture that provides variety of services including fresh water delivery, produced water transportation and disposal, crude oil gathering and stabilization, and natural gas gathering and processing, to us and other operating exploration and production companies in the Williston Basin. 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). In September 2013, FREIF committed an additional $80.0 million in equity capital contributions. 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. We currently hold a 30% economic interest in Caliber.

        Caliber's midstream operations are currently located in McKenzie County, North Dakota, but it plans to expand its operations across the Williston Basin. We have connected 31 of our operated wells to Caliber's midstream system. We expect to have over 80 of our operated wells in McKenzie County connected to Caliber's midstream system by the end of FY2015. Our investment in Caliber is approximately $68.5 million, which includes our initial investment of $30.0 million and our share of Caliber's net income, equity investment derivatives (at fair value), less cash distributions. Caliber's net income totaled approximately $7.3 million for FY2014, and Triangle's share of Caliber's net income totaled approximately $2.2 million. After elimination of intra-company profits related to Caliber's provision of services to our operated wells, we recognized no consolidated income from Caliber in FY2014.

20


Table of Contents

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 fiscal years ended
January 31,
 
 
  2014   2013   2012  

Net Sales Volume

                   

Oil (Bbls)

    1,754,375     451,784     92,694  

Natural gas (Mcf)

    626,447     188,044     11,758  

Natural gas liquids (Bbls)

    70,477     5,054     216  

Total equivalent barrels

    1,929,260     488,179     94,870  

Average Sales Price Per Unit

                   

Oil price (per Bbl)

  $ 88.07   $ 85.29   $ 86.40  

Natural gas price (per Mcf)

  $ 4.39   $ 4.78   $ 9.10  

Natural gas liquids price (per Bbl)

  $ 46.72   $ 36.01   $ 92.59  

Weighted average price (per Boe)

  $ 83.22   $ 81.15   $ 85.76  

Production tax (per Boe)

  $ 9.33   $ 9.20   $ 9.44  

Lease operating expenses (per Boe)

  $ 7.49   $ 7.11   $ 9.50  

Gathering, transportation and processing (per Boe)

  $ 2.23   $ 0.31   $ 0.23  

        Sales from our operated wells began in May 2012. Our net sales volumes from operated wells totaled 1,341 Mbbls of oil for FY2014. We expect to begin selling crude oil, natural gas liquids and natural gas through delivery points on Caliber's gathering system in FY2015.

Significant Customers

Oil, Natural Gas and Natural Gas Liquids Customers

        In the U.S., sales of produced crude oil, natural gas and natural gas liquids are made at negotiated prices. Of our $160.5 million in revenues from oil and gas sales in FY2014, $154.5 million is revenue from sales of crude oil, and of that approximately $117.5 million is our share of revenue from sales of crude oil from the 54 wells we operated.

        For wells that we operate, oil production has been 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.

        We sell our oil, natural gas and NGLs to multiple customers. In FY2014, we made sales of operated well production directly to five oil purchasers, one NGL purchaser and one natural gas purchaser. In FY2014, we had revenues from two customers (both crude oil purchasers) that exceeded 10% of our $258.7 million in total revenues in FY2014. For one customer, our FY2014 revenues were approximately $83.1 million. For the second customer, our FY2014 revenues were approximately $63.9 million. We also have sales through unrelated operators of wells in which we have revenue interests.

        We do not believe the loss of any single customer would have a material adverse effect on our Company since there are numerous potential purchasers of our production. We regularly monitor the credit worthiness of customers and may require parental guarantees, letters of credit or prepayments when deemed necessary.

21


Table of Contents

        For our economic interests in wells operated by third-parties, substantially all of our sales of crude oil, NGL and natural gas in fiscal years 2014, 2013 and 2012 were sold through arrangements made by the operators and 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. 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, 2013 or 2012. 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.

Pressure Pumping 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 of well completions. These factors can be 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 in western North Dakota and eastern Montana. During FY2014, RockPile provided pressure pumping services for 31 wells operated by TUSA and 50 wells operated by third parties. We do not believe that the loss of any single customer would have a material adverse effect on our Company since there are numerous operators in the Williston Basin in need of pressure pumping and related services.

Delivery Commitments

        In October 2012, TUSA entered into two midstream services agreements with Caliber North Dakota LLC ("Caliber North Dakota"); 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 in-service date of the Caliber facilities (the date that the Caliber North Dakota central facility has been substantially completed and has commenced commercial operation, estimated to occur in the first quarter of FY2015). 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 will commence on the in-service date of certain incremental Caliber North Dakota facilities (estimated to occur in the second quarter of FY2015). The minimum commitment over the term of the agreements is $405.0 million. Also on September 12, 2013, TUSA and Caliber Measurement Services LLC ("Caliber Measurement") entered into a gathering services agreement pursuant to which Caliber Measurement will provide 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 such as Continental Resources, Statoil, Kodiak Oil & Gas Corporation, Enerplus Resources Corporation, Oasis Petroleum, Newfield Exploration and Whiting Petroleum. Many of our competitors possess significantly more personnel and experience in the Williston Basin and greater access to capital resources than we do. Such companies may be able to define, evaluate, bid for and purchase a greater number of properties and exploratory prospects than the Company's financial or human resources permit.

22


Table of Contents

        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 and Baker Hughes.

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

Seasonality

        Due to United States refineries having to import most of their crude oil, there is little seasonality in the demand for crude oil produced in North Dakota. Oil prices in North Dakota are impacted more by global oil demand and by the availability of crude oil transportation capacity 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 this fluctuation. 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 drilling, completion, and other 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 are in the process of having future crude oil, natural gas and produced water transported away from the wellhead by Caliber's 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 with respect to future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

        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

23


Table of Contents

the oil and natural gas industry is generally 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 Contamination Issues

        The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund law," and comparable state laws may impose strict, joint, and several liability, without regard to fault, on classes of persons responsible for the release of CERCLA "hazardous substances" into the environment. These persons include the current and former owners and operators of the 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 liability for the costs of cleaning up the hazardous substances released into the environment and for damages to natural resources. 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 filed 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 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 operations, we generate some amounts of 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 "pollutants" into waters of the United States, including wetlands, without appropriate permits. These controls generally have

24


Table of Contents

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 oil, hazardous substances, or other 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 are also required to develop and implement Spill Prevention, Control, and Countermeasure ("SPCC") plans or facility response plans to address potential oil spills.

        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 concerns regarding seismic consequences, may result in stricter regulation and increased costs associated with oil and natural gas wastewater disposal.

Oil Spill Regulation

        The BP crude oil spill in the Gulf of Mexico 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 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 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 October 2011, citing concerns that third-party treatment plants may not be properly equipped to handle wastewater from shale gas operations, the EPA announced that it will consider federal pre-treatment standards for these wastewaters. Proposed standards are expected in 2014. We cannot predict the EPA's future actions in this regard, but increased and more stringent future regulation of produced waters or other waste streams could have a material impact on our operations.

25


Table of Contents

        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

        The federal Clean Air Act and implementing state air quality laws and regulations impose permit requirements, operational restrictions, and emission control requirements on certain sources of emissions used in our operations. In August 2012, the EPA published final New Source Performance Standards ("NSPS") and National Emissions Standards for Hazardous Air Pollutants ("NESHAPs") that amend existing NSPS and NESHAPs applicable to the oil and natural gas industry and create new air quality-related standards for oil and natural gas production, transmission, and distribution facilities. The standards established new requirements for emissions from compressors, dehydrators, storage tanks, and other production equipment, as well as more stringent leak-detection requirements for natural gas processing plants. Importantly, these standards include requirements for hydraulically fractured natural gas wells and apply to newly drilled and fractured natural gas wells, as well as existing natural gas wells that are refractured. The EPA received numerous requests for reconsideration of these standards from both the industry and the environmental community, as well as court challenges to the standards. In September 2013, the EPA issued revised standards largely focused on storage tank requirements. The revised standards were responsive to some, but not all, industry concerns. Although most of the requirements of the new regulations applicable to hydraulically fractured natural gas wells do not become effective until 2015, other requirements of these new and revised standards may require us to modify our current facilities and operations and may increase future costs of our operations. In addition, the EPA currently is reconsidering other portions of the standards that may broaden the scope of the regulations or otherwise require us to modify our current facilities and operations and may increase future costs of our operations.

        After the United States Supreme Court's holding in Massachusetts v. EPA that carbon dioxide, methane, and other greenhouse gases ("GHGs") fall under the Clean Air Act's definition of "air pollutant," the EPA issued a notice of finding and determination that emissions of GHGs present an endangerment to human health and the environment, which allows the EPA to regulate GHG emissions under existing provisions of the Clean Air Act. Although a decision from the United States Supreme Court regarding the scope of the EPA's authority to regulate GHGs from stationary sources is expected in June 2014, 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.

        A number of states also have taken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or regional cap-and-trade programs, but we do not currently conduct business in those states. For example, although we do not currently operate in Colorado, in 2014, the Colorado Air Quality Control Commission adopted the nation's first rules targeting GHG emissions (i.e., methane) from upstream oil and gas operations. These new Colorado rules could serve as a regulatory model for other states, including Montana or North Dakota, or for the federal government. Canada, where we also hold oil and natural gas leases, also is implementing laws concerning GHG emissions. On March 28, 2014, the Obama administration announced that in the spring of 2014, the EPA will assess several sources of methane and other emissions from the oil and gas sector. In the fall of 2014, the EPA is expected to determine how to pursue further methane reductions from these sectors. If the EPA decides to develop additional regulations, it plans to complete those

26


Table of Contents

regulations by the end of 2016. The administration also announced that it will identify "downstream" methane reduction opportunities at some point in the future. Later this year, the Bureau of Land Management ("BLM) will propose updated standards to reduce venting and flaring from oil and gas production on public lands. Finally, there has been significant focus on the flaring of natural gas in the Williston Basin. Increased regulatory pressure or litigation regarding flaring or reduction of methane emissions could affect our operations or increase future costs of our operations.

        Any laws or regulations that 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, commonly known as "fracing," 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, and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with the results of the study anticipated to be available for review in 2014. Moreover, the EPA also is studying the potential impact of wastewater derived from hydraulic fracturing activities and by 2014 plans to propose standards that such wastewater must meet before being transported to a treatment plant. In May 2013, the BLM published a supplemental notice of proposed rulemaking that would regulate hydraulic fracturing on federal and Indian lands, replacing a prior draft of proposed rulemaking issued by the agency in May 2012. Among other things, the revised proposed rule would continue to require public disclosure of certain chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in hydraulic fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. 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, Nova Scotia currently has in place a moratorium on hydraulic fracturing and Vermont has banned the use of the technology.

27


Table of Contents

        Finally, the EPA is moving forward with Toxic Substances Control Act ("TSCA") rulemaking, which will collect expansive information on the chemicals used in hydraulic fracturing fluid, including health-related data, from chemical manufacturers and processors. The EPA expects to issue an Advance Notice of Proposed Rulemaking ("ANPRM") in 2014. 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"). All of these initiatives present significant, but uncertain, risk of additional regulation of the oil and natural gas industry. As discussed in Note 5—Oil and Natural Gas Properties in the accompanying consolidated financial statements, Nova Scotia, where we own oil and natural gas properties, is currently evaluating how hydraulic fracturing should be regulated and does not allow the use of salt water disposal wells.

        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 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 that 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, maintenance of bonding requirements in order to drill or operate wells, and limits on the location of wells, the method 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 for resale 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 affects the marketing of natural gas that 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 not directly regulate natural gas

28


Table of Contents

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: (1) 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; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) 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 the 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.

29


Table of Contents

        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 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, 2014, we had 332 full time employees compared to 132 full time employees at January 31, 2013. 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 2600, Denver, Colorado, 80202, and our telephone number is (303) 260-7125. We also own or lease field offices and facilities in North Dakota.

30


Table of Contents

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 revolving 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. Declines in prices would also reduce the demand for services provided by RockPile and Caliber, adversely affecting their revenue and profitability.

        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.

        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 often at a discount to the relevant benchmark prices on NYMEX. A negative difference between the benchmark price and the

31


Table of Contents

price received is called a differential. The differential may vary significantly due to market conditions, the quality and 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.

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. Further, 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 FY2015 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,

32


Table of Contents

unsuccessful exploration or development activity affecting even a small number of these wells could have a significant impact on our results of operations.

Our planned operations will 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 flow from operations. That fact has made us dependent on external financing to a greater degree than many of our competitors. 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. 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.

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 and availability of capital, estimates of required capital expenditures and workover and remedial costs, and the assumed effect 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, 2014, approximately 58% 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, 2014 reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including currently estimated expenditures of approximately $505.4 million during the five years ending on January 31, 2019. 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.

33


Table of Contents

        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.

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 and the drilling and completion of productive wells. We expect acquisitions will also contribute to our future growth. 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 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, reclamation and remediation;

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

    the use of underground storage tanks;

34


Table of Contents

    transportation and drilling permits;

    the use of underground injection wells;

    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 2012, 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,

35


Table of Contents

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 operation 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.

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 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 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. As a result, such legislation or regulation could have a material adverse effect on our business, financial condition and results of operations.

We have a limited operating history.

        We have a limited operating history conducting oil and natural gas exploration and production activities. The history of RockPile and Caliber is more limited, as both of those entities began conducting operations in FY2013. Each of these businesses will be subject to all the risks inherent in the establishment of a developing enterprise and the uncertainties arising from the absence of a significant operating history. We may be unable to operate on a profitable basis. We are in the early stage of our development plan, and potential investors should be aware of the difficulties normally encountered by enterprises in this stage. If our business plan is not successful and we are not able to operate profitably, investors may lose some or all of their investment.

The results of our planned drilling in the Bakken Shale and Three Forks formations, each an emerging play with limited drilling and production history, 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

36


Table of Contents

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 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, 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.

The lack of availability or high cost of drilling rigs, fracture stimulation crews, equipment, supplies, insurance, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

        Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, fracture stimulation crews, equipment, supplies, key infrastructure, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified crews rise as the number of active rigs and completion fleets in service increases. If increasing levels of exploration and production result from strong commodity prices, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. Costs associated with hydraulic fracturing, such as costs relating to water and proppants, may be subject to similar pressures in areas such as the Williston Basin where hydraulic fracturing activities are widespread. Moreover, costs in the Williston Basin generally are high relative to many areas of the country due to its rapid growth in recent years and its distance from major metropolitan areas.

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 experience financial or other setbacks if we encounter unanticipated problems in connection with such transactions, including problems related to execution or integration. Any of these risks could reduce

37


Table of Contents

our revenues or increase our expenses, which could adversely affect our business, financial condition or results of operations.

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 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.

Most 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 flow and income.

        Most 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 flow and income, are highly dependent on our success in developing our undeveloped leasehold acreage.

38


Table of Contents

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.

We may have difficulty managing growth in our business, which could adversely affect our business plan, financial condition and results of operations.

        Growth in accordance with our business plan, if achieved, will place a significant strain on our financial, accounting, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on these resources. Our vertical integration strategy effectively increases the variety of these projects, which adds complexity and may require additional resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

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

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

We may not realize the benefits of integrating acquired properties.

        The integration into our operations of oil and natural gas properties acquired in August 2013, 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.

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.

39


Table of Contents

Our method of accounting for 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 the 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 FY2012. Once incurred, such a write-down of oil and natural gas properties is not reversible at a later date, even if oil or natural gas prices substantially increase or if estimated proved reserves substantially increase. Although we had no impairments in FY2013 or FY2014, there can be no assurance that that we will not recognize impairment expense in future periods.

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

        On April 17, 2013, our board of directors approved the audit committee's and management's recommendation that we file Amendment No. 1 on Form 10-Q/A (the "FY2013 Amendment") to amend and restate our Quarterly Report on Form 10-Q for the three months ended October 31, 2012, which was filed with the SEC on December 10, 2012. The FY2013 Amendment included an error correction that eliminates $1.8 million of previously recognized pressure pumping income, pursuant to recognition exception rules set forth in Regulation S-X Rule 4-10(c)(6)(iv), as further discussed in Item 7 of our Annual Report on Form 10-K for the fiscal year ended January 31, 2013. Accordingly, we identified a material weakness in our controls over the accounting for pressure pumping income. Our control for the accounting for service income was not designed to consider all of the relevant accounting literature applicable to service income, including related party considerations as described in the Regulation S-X Rule 4-10(c)(6)(iv). This material weakness resulted in a material error in our accounting for pressure pumping income and a restatement of our previously issued quarterly financial statements for the three months ended October 31, 2012. As a result of this material weakness, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were not effective as of January 31, 2013. Accordingly, we identified a material weakness in our controls over the accounting for pressure pumping income. Our control for the accounting for service income was not designed to consider all of the relevant accounting literature applicable to service income, including related party considerations as described in the Regulation S-X Rule 4-10(c)(6)(iv). This material weakness resulted in a material error in our accounting for pressure pumping income and a restatement of our previously issued quarterly financial statements for the three months ended October 31, 2012. As a result of this material weakness, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were not effective as of January 31, 2013.

        On April 13, 2014, our board of directors approved the audit committee's and management's recommendation that we file Amendment No. 1 on Form 10-Q/A (the "2014 Amendment") to amend

40


Table of Contents

and restate our Quarterly Report on Form 10-Q for the three months ended October 31, 2013, which we intend to file as soon as reasonably practicable following the date of this annual report. The FY2014 Amendment is expected to include an error correction to recognize the fair value of equity investment derivatives for the trigger units and warrants that the Company holds in Caliber in accordance with Accounting Standards Codification ("ASC") 820—Fair Value Measurement and ASC 815—Derivatives and Hedging, as further discussed in Item 8 of this Annual Report filed on Form 10-K. Consequently, we identified a material weakness in our controls over the accounting for equity investment derivatives. Our control for the accounting for equity investment derivatives was not designed to consider all of the relevant accounting literature applicable to our Caliber trigger units and warrants. This material weakness resulted in a material error in our accounting for equity investment derivatives, and we expect to restate our previously issued quarterly financial statements for the three months ended October 31, 2013. As a result of this material weakness, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were not effective as of January 31, 2014.

        We are in the process of implementing system and procedural changes to prevent these issues from recurring in FY2015. If we are not able to remedy the control deficiencies in a timely manner, or if other deficiencies arise in the future, we may be unable to provide holders of our securities with required financial information in a timely and reliable manner and we could be required to restate or correct our financial statements in the future.

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 significant 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.

Our lack of geographic diversification will 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. 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 increases 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

41


Table of Contents

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 focus. Such competitors may also be in a better position to secure oilfield services and equipment on a timely 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. Each of our businesses has a relatively high degree of customer concentration, which could increase our risks with respect to competition.

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 we do 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. As a result, the majority of our natural gas from the Williston Basin wells to date has been flared. In addition, the use of alternative forms of transportation for oil production, such as trucks or rail, involves 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.

        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. Additionally, if we were prohibited from flaring natural gas due to environmental or other regulations, then we would be forced to shut-in producing wells, which would also adversely impact our drilling program. 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 affecting flaring activities, 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 one or more of 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.

A U.S. or global economic downturn could have a material adverse effect on our business and operations.

        Any or all of the following may occur if a crisis arises in the global financial and securities markets and an economic downturn results:

    An economic slowdown could lead to lower demand for oil and natural gas by individuals and industries, which in turn could result in lower oil and natural gas prices.

42


Table of Contents

    The lenders under our revolving credit facilities may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth.

    TUSA's credit facility requires the lenders to re-determine our borrowing base periodically. The re-determinations are based on our proved reserves, which reflect price assumptions that our lenders require us to use to calculate reserves pursuant to the credit facility. The lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base due to lower commodities and futures prices, which could result in the reduction of our borrowing base and funds available to borrow.

    We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.

    The losses incurred by financial institutions as well as the insolvency of some financial institutions could heighten the risk that a counterparty to our hedge arrangements would default on its obligations. A failure of one or more counterparties to our hedging transactions to meet their obligations to us could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially adversely affected.

    Bankruptcies of purchasers of our oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.

    A generally reduced availability of capital would likely lead to a decreased demand for the services provided by RockPile and Caliber.

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

43


Table of Contents

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 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.

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.

        The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gases, or 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 emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production. Canada, where we also hold oil and natural gas leases, is also implementing laws concerning GHG emissions. 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.

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. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If

44


Table of Contents

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.

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 all 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. 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.

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, particularly where it has a relationship with a single supplier for a particular resource. 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 its business. Our other operations may be similarly adversely affected by shortages of these raw materials.

45


Table of Contents

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.

        One of the ways we intend to grow Caliber's business is 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 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 repurchase certain assets and 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.

        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 these 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.

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 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. As a result of the foregoing, NGP has significant influence

46


Table of Contents

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

        In March 2013, we sold to two affiliates of NGP 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, 2014, NGP's affiliates collectively held approximately 11% of our outstanding common stock. If NGP had fully converted the Convertible Note on April 1, 2014, NGP and its affiliates would have collectively held approximately 25% of our outstanding shares of common stock on that date. 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 April 1, 2014, ActOil held approximately 13% 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 interests of our other stockholders, and the ability of ActOil and NGP and its affiliates 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.

The cost of servicing our debt could adversely affect our business. In addition, our debt agreements have substantial restrictions and financial covenants that could adversely affect our business.

        We have outstanding indebtedness under TUSA's and RockPile's credit facilities and our Convertible Note. 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, 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 revolving credit facilities or otherwise, in an amount sufficient to fund our liquidity needs.

        A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, refinancing all or a portion of our existing debt, or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing 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. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required 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.

        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.

47


Table of Contents

        In addition to making it more difficult for us to satisfy our debt and other obligations, our indebtedness could limit our ability to respond to changes in the markets in which we operate and otherwise limit our activities. For example, our indebtedness, and the terms of agreements governing that indebtedness, could increase our vulnerability to 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.

        TUSA's revolving credit facility limits the amount it can borrow to a borrowing base amount determined by the lenders. Outstanding borrowings in excess of the borrowing base may be required to be repaid immediately, and we may not have the financial resources in the future to make those repayments. Our inability to borrow additional funds under TUSA's revolving credit facility, or a requirement to repay borrowings in excess of a reduced borrowing base, could adversely affect our operations and our financial results.

Our limited partner interest in the Caliber joint venture may be diluted.

        In October 2012, a wholly-owned subsidiary of ours entered into a joint venture 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 the joint venture entity, our subsidiary received a 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 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 2013, our joint venture partner committed to providing an anticipated additional $80.0 million to the joint venture in return for 8,000,000 limited partner units. The associated amendment to the joint venture agreement will also result in our 4,000,000 trigger units vesting and converting to limited partner units. Our joint venture partner and our subsidiary will receive the 8,000,000 and 4,000,000 limited partner units, respectively, on the earlier of the in-service date of Caliber's expansion system and 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 the joint venture is expected to increase to 32%.

        We will be unable to increase our limited partner interest above 32% absent a cashless exercise of our warrants or a direct capital outlay to exercise our warrants or commit additional capital. Further, if the joint venture partner makes a partnership approved capital contribution and we choose not to invest additional capital in the joint venture, or if the joint venture partner exercises its warrants and we do not exercise our warrants, we would be diluted below our 32% limited partner interest.

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 a more predictable cash flow. 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

48


Table of Contents

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 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 trigger units and warrants in Caliber that are classified as derivatives. For so long as such trigger units and 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 trigger units and warrants, respectively. The associated models are based on several assumptions about future events. While we believe that our models and underlying assumptions are reasonable, there can be no assurance that the assumptions will ultimately prove to be accurate or that our models are the best models for valuing the derivatives. If the models and underlying assumptions are flawed, then our accounting for such derivative investments may not reflect their true value.

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

        We have restated or corrected certain financial information in the past, including by issuing restated financial information for the fiscal quarters ended April 30, 2007, July 31, 2007 and October 31, 2007, for the year ended January 31, 2012, and for the fiscal quarter ended October 31, 2012. We also expect to issue restated financial information for the fiscal quarter ended October 31, 2013 following the filing of this Annual Report on Form 10-K. 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 further restatements. Our vertical integration strategy and midstream joint venture investment create certain accounting issues relating to the relationship of our various businesses that are complex, increasing the risk that we may have to restate or correct financial disclosures in the future. 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.

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:

    actual or anticipated fluctuations in our quarterly results of operations;

49


Table of Contents

    liquidity;

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

    changes in oil and natural gas prices;

    changes in our cash flow 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.

        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.

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 flow 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.

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.

50


Table of Contents

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.

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.

51


Table of Contents

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 on Form 10-K.

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

ITEM 4.    MINE SAFETY DISCLOSURES

        Not applicable.

52


Table of Contents


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 high and low sales price for our common stock in each quarter of the last two fiscal years:

 
  Fiscal Year 2014  
 
  High   Low  

February 1, 2013 to April 30, 2013

  $ 7.30   $ 5.12  

May 1, 2013 to July 31, 2013

  $ 7.75   $ 5.30  

August 1, 2013 to October 31, 2013

  $ 11.21   $ 6.41  

November 1, 2013 to January 31, 2014

  $ 11.00   $ 7.61  

 

 
  Fiscal Year 2013  
 
  High   Low  

February 1, 2012 to April 30, 2012

  $ 7.99   $ 5.54  

May 1, 2012 to July 31, 2012

  $ 6.38   $ 4.72  

August 1, 2012 to October 31, 2012

  $ 7.76   $ 5.65  

November 1, 2012 to January 31, 2013

  $ 6.62   $ 5.12  

Holders

        Our 85,941,961 shares of common stock outstanding at April 1, 2014 were held by 21 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 Securities

        See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Private Placements." The shares issued in the private placements were issued without registration under the Securities Act in reliance upon the exemption from registration set forth in Section 4(a)(2) of the Securities Act.

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

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

53


Table of Contents

January 31, 2014. The Company has no publicly announced plan or program to purchase Company securities.

 
  Total Number of
Shares
Purchased(1)
  Average Price
Paid Per Share(2)
 

November 1, 2013 - November 30, 2013

    12,397   $ 10.19  

December 1, 2013 - December 31, 2013

    33,386   $ 9.24  

January 1, 2014 - January 31, 2014

    13,574   $ 8.32  
           

    59,357   $ 9.23  
           
           

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

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

54


Table of Contents

Performance Graph

        The following graph compares our common stock's performance with the performance of the Standard & Poor's 500 Stock Index and the Dow Jones U.S. Oil and Gas Index for the period beginning January 31, 2009 through January 31, 2014. The graph assumes the value of the investment in our common stock and in each index was $100 on January 31, 2009 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.


COMPARISON OF CUMULATIVE TOTAL RETURN
AMONG TRIANGLE PETROLEUM CORPORATION,
THE S&P 500 STOCK INDEX,
AND THE DOW JONES U.S. OIL & GAS INDEX

GRAPHIC

55


Table of Contents

ITEM 6.    SELECTED FINANCIAL DATA

        The following table sets forth selected consolidated financial data as of and for the years ended January 31, 2010 through January 31, 2014. The data as of and for the fiscal 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 and 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 Fiscal Years Ended January 31,  
(in thousands, except per share data)
  2014   2013   2012   2011   2010  

Operating results:

                               

Oil and natural gas sales

  $ 160,548   $ 39,614   $ 8,136   $ 564   $ 131  

Oilfield Services

    98,199     20,747              

Other

        340              
                       

Total Revenue

  $ 258,747   $ 60,701   $ 8,136   $ 564   $ 131  

Total operating expenses

 
$

212,081
 
$

68,871
 
$

33,111
 
$

20,900
 
$

2,278
 

Net income (loss) attributable to common stockholders

 
$

73,480
 
$

(13,760

)

$

(24,278

)

$

(20,277

)

$

(2,140

)

Income (loss) per share to common stockholders:

   
 
   
 
   
 
   
 
   
 
 

Basic

  $ 1.07   $ (0.31 ) $ (0.60 ) $ (1.63 ) $ (0.03 )

Diluted

  $ 0.91   $ (0.31 ) $ (0.60 ) $ (1.63 ) $ (0.03 )

Total assets

 
$

1,027,584
 
$

428,321
 
$

229,845
 
$

82,031
 
$

24,358
 

Long-term obligations

  $ 345,054   $ 148,788   $ 83   $ 1,404   $ 1,181  

Cash flow data:

   
 
   
 
   
 
   
 
   
 
 

Net cash provided by (used in) operating activities

  $ 85,586   $ 2,764   $ (12,766 ) $ (3,541 ) $ (2,100 )

Net cash used in investing activities

  $ (458,716 ) $ (179,712 ) $ (111,046 ) $ (16,100 ) $ (2,192 )

Net cash provided by financing activities

  $ 421,763   $ 141,250   $ 134,854   $ 72,534   $  

Proved reserves:

   
 
   
 
   
 
   
 
   
 
 

Oil (Mbbls)

    31,916     12,540     1,365     1,236      

Natural gas (MMcf)

    26,504     12,585     674          

NGL (Mbbls)

    3,981                  

Total equivalent (Boe)

    40,314     14,637     1,477     1,236      

56


Table of Contents

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.

Overview

        We are a growth-oriented, independent energy holding company with three principal lines of business: oil and natural gas exploration, development and production; oilfield services; and midstream services. We conduct these activities in the Williston Basin of North Dakota and Montana through TUSA and RockPile, the Company's two principal wholly-owned subsidiaries, and Caliber, our joint venture with FREIF.

        Our primary focus at TUSA is to grow our production volumes through the efficient development of our operated Bakken Shale and Three Forks drilling inventory. We completed our first operated well in May 2012. From May 2012 through January 31, 2014, we have completed 47 gross (34.5 net) operated wells. Our average net daily production for FY2014 was 5,286 Boepd, approximately 75% of which was operated production. The growth we have experienced is facilitated by the use of pad drilling, which increases efficiencies while controlling costs and minimizing environmental impact. We also use advanced completion, collection and production techniques designed to optimize reservoir production while reducing costs. Our estimated proved oil and natural gas reserves as of January 31, 2014 totaled 40,314 Mboe (79% oil).

        In an effort to better control key operations, reduce costs, and retain supply chain value in the Williston Basin, which we view as a resource-constrained and cost-heavy basin, we formed RockPile and entered into our 30% owned joint venture arrangement with FREIF to form Caliber. RockPile's services lower our realized well completion costs, and RockPile affords us greater control over completion schedules, quality control and pay cycles. We expect that Caliber will reduce the cost and environmental impacts of trucking oil and water and reduce or eliminate the emissions generated by the flaring of produced natural gas from our operated wells. In addition to providing services to TUSA, each of RockPile and Caliber are focused on growing their respective businesses through securing independent, third-party contracts.

Proved Reserves

        FY2014 proved reserves grew 175% to 40,314 Mboe, up from 14,637 Mboe at fiscal year-end 2013. Proved reserves were 42% developed at fiscal year-end 2014 compared to 41% at fiscal year-end 2013. Reserves added from extensions and discoveries totaled 15,502 Boe. In total, reserve additions were comprised of 78% oil, 10% NGL and 12% natural gas. Our proved reserves are located in the Bakken Shale and Three Forks formations primarily in North Dakota.

        The process of estimating quantities of oil and natural gas reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, contractual arrangements and continual reassessment of the viability of production under

57


Table of Contents

varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time.

        Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data make these estimates generally less precise than other estimates included in financial statement disclosures. See Item 8. Consolidated Financial Statements and Supplementary Data, Note 24—Unaudited Supplemental Oil and Natural Gas Disclosures for further discussion regarding our proved reserves.

Results of operations for the year ended January 31, 2014 compared to the year ended January 31, 2013

        For January 31, 2014, we recorded net income attributable to common stockholders of $73.5 million ($1.07 per common share, basic and $0.91 diluted) as compared to a net loss attributable to common stockholders of $13.8 million ($0.31 loss per common share, basic and diluted) for January 31, 2013.

58


Table of Contents

Oil and Natural Gas Operations

        The following table summarizes production volumes, average realized prices, oil and natural gas revenues and operating expenses for the fiscal years ended January 31, 2014 and 2013:

 
   
   
  Change  
 
  For the Fiscal Year  
 
  Increase
(Decrease)
  % Increase
(Decrease)
 
U.S. Oil and Natural Gas Operations
  2014   2013  

Production volumes:

                         

Crude oil (Bbls)

    1,754,375     451,784     1,302,591     288 %

Natural gas (Mcf)

    626,447     188,044     438,403     233 %

Natural gas liquids (Bbls)

    70,477     5,054     65,423     1,294 %

Total barrels of oil equivalent (Boe)

    1,929,260     488,179     1,441,081     295 %

Average realized prices:

   
 
   
 
   
 
   
 
 

Crude oil ($ per Bbl)

  $ 88.07   $ 85.29   $ 2.78     3 %

Natural gas ($ per Mcf)

  $ 4.39   $ 4.78   $ (0.39 )   (8 )%

Natural gas liquids ($ per Bbl)

  $ 46.72   $ 36.01   $ 10.71     30 %

Total average realized price ($ per Boe)

  $ 83.22   $ 81.15   $ 2.07     3 %

Oil and natural gas revenues (in thousands):

   
 
   
 
   
 
   
 
 

Crude oil

  $ 154,507   $ 38,533   $ 115,974     301 %

Natural gas

    2,748     899     1,849     206 %

Natural gas liquids

    3,293     182     3,111     1,709 %
                     

Total oil and natural gas revenues

  $ 160,548   $ 39,614   $ 120,934     305 %
                     
                     

Operating expenses (in thousands):

                         

Production taxes

  $ 18,006   $ 4,493   $ 13,513     301 %

Other lease operating expenses

    14,454     3,469     10,985     317 %

Gathering, transportation and processing

    4,302     151     4,151     2,749 %

Oil and natural gas amortization expense

    50,991     13,548     37,443     276 %

Accretion of other asset retirement obligations

    56     22     34     155 %
                     

Total operating expenses

  $ 87,809   $ 21,683   $ 66,126     305 %
                     
                     

Operating expenses per Boe:

                         

Production taxes

  $ 9.33   $ 9.20   $ 0.13     1 %

Other lease operating expense

  $ 7.49   $ 7.11   $ 0.38     5 %

Gathering, transportation and processing

  $ 2.23   $ 0.31   $ 1.92     619 %

Oil and natural gas amortization expense

  $ 26.43   $ 27.75   $ (1.32 )   (5 )%

 

 
  For the Fiscal
Year Ended
  Change  
 
  Increase
(Decrease)
  % Increase
(Decrease)
 
Canadian Oil and Natural Gas Operations
(in thousands)
  2014   2013  

Lease operating expense

  $   $ 97   $ (97 )   (100 )%

Impairment of oil and natural gas properties

                0 %

Accretion and other asset retirement obligation expenses          

    962     162     800     494 %
                     

Loss from Canadian oil and natural gas operations

    962     259     703     271 %
                     

Loss from operations

  $ 962   $ 259   $ 703     271 %
                     
                     

Oil and Natural Gas Revenues

        Production revenues increased to $160.5 million for the year ended January 31, 2014 from $39.6 million for January 31, 2013 due to a 295% increase in production volumes and a 3% increase in

59


Table of Contents

oil and natural gas prices on a per Boe basis. The increase in production volumes added approximately $116.9 million in revenues and the increase in price per Boe increased revenues by $4.0 million.

        Total production volumes increased to 1,929.3 Mboe (5,286 Boepd) for FY2014 from 488.2 Mboe (1,334 Boepd) for FY2013, primarily due to the addition of approximately 1,185.0 Mboe from our operated drilling program as well as a 256.1 Mboe increase in production from our non-operated portfolio.

Oilfield Services

        RockPile commenced operations in July 2012. We formed RockPile with strategic objectives to have both greater control over one of our largest cost centers as well as to provide locally-sourced, high-quality completion services to 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 the Williston Basin. RockPile's results of operations are affected by a number of variables including drilling and stimulation activity in the Williston Basin, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers.

        For the year ended January 31, 2014, RockPile performed hydraulic fracturing services for TUSA and six distinct third-party customers. This work resulted in 81 total well completions: 31 for TUSA and 50 for third-parties. Thirty TUSA wells were completed using plug-and-perf applications and one well was completed using a combination of plug and perf and sliding sleeve. Thirty-four third-party wells were completed using a sliding sleeve application, 15 third-party wells were completed using plug and perf applications and one well was completed using a combination of plug-and-perf and sliding sleeve. RockPile revenue is comprised of service revenue (what we charge for equipment usage and labor), and materials revenue (what we charge for chemicals and proppant). Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), logistic expenses, insurance, repairs and maintenance charges and safety costs. Cost of goods sold as a percentage of revenue will vary based upon completion design and equipment utilization.

        We recognized $10.5 million of gross profit from oilfield services for the year ended January 31, 2014 after elimination of $31.9 million in intercompany gross profit. See Item 8. Consolidated Financial Statements and Supplemental Data, Note 4—Segment Reporting for additional information regarding our segments.

        The tables below summarize the RockPile contribution to our consolidated results for the fiscal years ended January 31, 2014 and 2013:

 
  For the Fiscal Year Ended
January 31, 2014
 
(in thousands)
  RockPile   Eliminations   Consolidated  

Revenues

                   

Oilfield services

    193,625     (95,426 )   98,199  
               

Total revenues

  $ 193,625   $ (95,426 ) $ 98,199  
               
               

Cost of sales

                   

Depreciation

    8,905     (3,542 )   5,363  

Oilfield services

    142,339     (60,012 )   82,327  
               

Total cost of sales

    151,244     (63,554 )   87,690  
               

Gross profit

  $ 42,381   $ (31,872 ) $ 10,509  
               
               

60


Table of Contents


 
  For the Fiscal Year Ended
January 31, 2013
 
(in thousands)
  RockPile   Eliminations   Consolidated  

Revenues

                   

Oilfield services

    57,207     (36,460 )   20,747  
               

Total revenues

  $ 57,207   $ (36,460 ) $ 20,747  
               
               

Cost of sales

                   

Depreciation

    2,857     (1,732 )   1,125  

Oilfield services

    39,534     (22,928 )   16,606  
               

Total cost of sales

    42,391     (24,660 )   17,731  
               

Gross profit

  $ 14,816   $ (11,800 ) $ 3,016  
               
               

Caliber Midstream Joint Venture Revenues

        For the year ended January 31, 2014, Caliber had $15.6 million of revenue, $15.0 million of which was from TUSA, mainly comprised of fresh water delivery and produced water disposal revenues, and well connect fees, as compared to $37,000 of revenue for the fiscal year ended January 31, 2013. (See Note 11—Equity Investment to the consolidated financial statements referenced in Part II, Item 8 of this report). Caliber was formed in October 2012 and began water transportation and disposal operations in January 2013.

Hedging Activities

        To manage commodity risk, we have entered into commodity derivative instruments, utilizing costless collars, single-day puts, and swaps to economically reduce the effect of adverse price movements 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 either derivative assets or liabilities. 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 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.

        During the year ended January 31, 2014, we recognized a $1.1 million gain on our commodity derivative positions due to decreases in underlying crude oil prices. Included in the net gain on our derivative activities were cash settlements we incurred on our commodity derivative instruments of approximately $0.8 million. The fair value 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 expect to continue entering into derivative instruments in order to manage our exposure to commodity price risk and achieve more predictable cash flows in support of our future growth plans; however we may choose not to hedge a portion of our future production if the pricing environment for certain time periods is not deemed to be favorable. For additional discussion, please refer to Note 14—Derivative Instruments in the consolidated financial statements.

61


Table of Contents

Production Taxes

        Due primarily to the 305% increase in oil and natural gas revenues for January 31, 2014 as compared with January 31, 2013, our U.S. production taxes increased approximately 301% to $18.0 million from $4.5 million. North Dakota production tax rates were 11.5% of oil revenue and approximately $0.08 per Mcf of natural gas.

Lease Operating Expense

        Lease operating expense ("LOE") for U.S. operations increased to $7.49 per Boe for the year ended January 31, 2014 from $7.11 per Boe for the year ended January 31, 2013. The increase in LOE/Boe is primarily the result of a relatively high proportion of oil sales related to sales in FY2013 for new producing wells (when LOE/Boe is relatively low), and relatively low workover expenses in FY2013.

Gathering, Transportation and Processing

        Gathering, transportation and processing ("GTP") expenses increased to $2.23 per Boe for the year ended January 31, 2014 from $0.31 per Boe for the year ended January 31, 2013. For the first nine months of FY2013, GTP expenses were primarily associated with gathering and transportation of oil and natural gas from non-operated wells. During the fourth quarter of FY2014, GTP expenses significantly increased on a per Boe basis as third party gathering providers and Caliber's gathering infrastructure became available for certain of our operated wells, which allowed us to transport much of our oil, natural gas and natural gas liquids further downstream as opposed to selling oil at the wellhead and flaring natural gas, thus increasing both our GTP expense and the associated revenue.

Oil and Natural Gas Amortization

        Oil and natural gas amortization expense increased 276% to $51.0 million for the year ended January 31, 2014 from $13.5 million for the year ended January 31, 2013. The increase is primarily related to a 295% increase in production in FY2014 compared to FY2013.

Accretion and Other Asset Retirement Obligation Expense

        These expenses increased in FY2014 by $1.0 million versus FY2013 primarily due to an increase in the estimated asset retirement obligation relating to our fully impaired assets in Nova Scotia.

General and Administrative Expenses

        The following table summarizes increases in general and administrative expenses for FY2014 compared with FY2013. Costs excluded from the amounts presented below are (i) those personnel costs which are capitalized under the full cost accounting method as direct internal costs of acquisition, exploration and development of oil and gas properties, (ii) costs equal to overhead reimbursements charged by TUSA as well operator to third parties participating in TUSA-operated wells, and (iii) general and administrative expenses recovered by Triangle for charges to Caliber and TUSA for various general and administrative services. The increases are primarily due to increases in the number

62


Table of Contents

of employees as we continued to expand our acquisition, exploration, development, completion and production activities in North Dakota and Montana during FY2014.

(in thousands)
  Exploration
and
Production
  Oilfield
Services
  Corporate   Consolidated
Total
 

For the fiscal year ended January 31, 2014

                         

Salaries, benefits and other general and administrative

  $ 7,777   $ 11,116   $ 8,203   $ 27,096  

Stock-based compensation

    1,127     590     6,113     7,830  
                   

Total

  $ 8,904   $ 11,706   $ 14,316   $ 34,926  
                   
                   

For the fiscal year ended January 31, 2013

                         

Salaries, benefits and other general and administrative

  $ 6,838   $ 11,130   $ 4,358   $ 22,326  

Stock-based compensation

    2,507     617     3,342     6,466  
                   

Total

  $ 9,345   $ 11,747   $ 7,700   $ 28,792  
                   
                   

Interest Expense

        The $7.7 million in interest expense for the year ended January 31, 2014 consists of (a) approximately $3.4 million in interest and amortized fees related to the TUSA credit facility, (b) approximately $6.3 million in accrued interest and amortized fees related to our Convertible Note issued to NGP in July 2012, (c) approximately $1.0 million in interest expense associated with our RockPile credit facility and notes payable, and (d) a reduction of approximately $3.0 million of capitalized interest which is generally incurred on properties not being amortized. Approximately $3.6 million of interest expense was paid in cash. See Item 8, Consolidated Financial Statements and Supplementary Data, Note 13Long-Term Debt for additional information regarding our credit facilities and Convertible Note. Interest expense of $2.8 million for the year ended January 31, 2013 is primarily related to our Convertible Note with NGP.

Income Taxes

        Our FY2014 provision for deferred income taxes is $7.9 million. In prior years a 100% valuation allowance was placed against our net deferred tax assets of $35.0 million and $29.2 million at January 31, 2013 and 2012, respectively. Facts and circumstances indicate that the entire U.S. deferred tax asset is more likely than not to be realized in the future, and as such the valuation allowance is being correspondingly reduced by the amount of $26.7 million and a deferred tax expense recognized. Facts and circumstances indicate that the entire Canadian deferred tax asset will not be realized in the future, and as such, a 100% valuation allowance is being applied against our net Canadian deferred tax assets of $8.6 million.

        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 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.

63


Table of Contents

        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).

Results of operations for the year ended January 31, 2013 compared to the year ended January 31, 2012

        For January 31, 2013, we recorded a net loss attributable to common stockholders of $13.8 million ($0.31 loss per common share, basic and diluted) as compared to a net loss attributable to common stockholders of $24.3 million ($0.60 loss per common share, basic and diluted) for the year ended January 31, 2012.

64


Table of Contents

Oil and Natural Gas Operations

        The following table summarizes production volumes, average realized prices, oil and natural gas revenues and operating expenses for the fiscal years ended January 31, 2013 and 2012:

 
   
   
  Change  
 
  For the Fiscal Year  
 
  Increase
(Decrease)
  % Increase
(Decrease)
 
U.S. Oil and Natural Gas Operations
  2013   2012  

Production volumes:

                         

Crude oil (Bbls)

    451,784     92,694     359,090     387 %

Natural gas (Mcf)

    188,044     11,758     176,286     1,499 %

Natural gas liquids (Bbls)

    5,054     216     4,838     2,240 %

Total barrels of oil equivalent (Boe)

    488,179     94,870     393,309     415 %

Average realized prices:

   
 
   
 
   
 
   
 
 

Crude oil ($ per Bbl)

  $ 85.29   $ 86.40   $ (1.11 )   (1 )%

Natural gas ($ per Mcf)

  $ 4.78   $ 9.10   $ (4.32 )   (47 )%

Natural gas liquids ($ per Bbl)

  $ 36.01   $ 92.59   $ (56.58 )   (61 )%

Total average realized price ($ per Boe)

  $ 81.15   $ 85.76   $ (4.61 )   (5 )%

Oil and natural gas revenues (in thousands):

   
 
   
 
   
 
   
 
 

Crude oil

  $ 38,533   $ 8,009   $ 30,524     381 %

Natural gas

    899     107     792     740 %

Natural gas liquids

    182     20     162     810 %
                     

Total oil and natural gas revenues

  $ 39,614   $ 8,136   $ 31,478     387 %
                     
                     

Operating expenses (in thousands):

                         

Production taxes

  $ 4,493   $ 896   $ 3,597     401 %

Other lease operating expenses

    3,469     901     2,568     285 %

Gathering, transportation and processing

    151     22     129     586 %

Oil and natural gas amortization expense

    13,548     3,022     10,526     348 %

Accretion of other asset retirement obligations

    22     7     15     214 %

Impairment of oil and natural gas properties

        6,000     (6,000 )   (100 )%
                     

Total operating expenses

  $ 21,683   $ 10,848   $ 10,835     100 %
                     
                     

Operating expenses per Boe:

                         

Production taxes

  $ 9.20   $ 9.44   $ (0.24 )   (3 )%

Other lease operating expense

  $ 7.11   $ 9.50   $ (2.39 )   (25 )%

Gathering, transportation and processing

  $ 0.31   $ 0.23   $ 0.08     35 %

Oil and natural gas amortization expense

  $ 27.75   $ 31.85   $ (4.10 )   (13 )%

 

 
  For the Fiscal
Year Ended
  Change  
 
  Increase
(Decrease)
  % Increase
(Decrease)
 
(in thousands)
Canadian Oil and Natural Gas Operations
  2013   2012  

Lease operating expense

  $ 97   $ 641   $ (544 )   (85 )%

Impairment of oil and natural gas properties

        4,416     (4,416 )   (100 )%

Accretion and other asset retirement obligation expenses          

    162     160     2     1 %
                       

Loss from Canadian oil and natural gas operations

    259     5,217     (4,958 )   (95 )%
                       

Loss from operations

  $ 259   $ 5,217   $ (4,958 )   (95 )%
                       
                       

65


Table of Contents

Oil and Natural Gas Revenues

        Production revenues increased to $39.6 million for January 31, 2013 from $8.1 million for the year ended January 31, 2012 due to a 415% increase in production volumes, offset by a 5% reduction in oil and natural gas prices on a per Boe basis. The increase in production volumes added approximately $31.9 million in revenues, and the decrease in price per Boe reduced revenues by approximately $0.4 million.

        Total production volumes increased to 488.2 Mboe (1,334 Boepd) for January 31, 2013 from 94.9 Mboe (260 Boepd) for the year ended January 31, 2012, primarily due to the addition of approximately 240.2 Mboe from our operated drilling program and a 153.1 Mboe (161%) increase in production from our non-operated portfolio.

Oilfield Services

        RockPile commenced operations in July 2012. We formed RockPile with the strategic objectives of having greater control over our largest cost center as well as providing locally-sourced, high-quality completion services to TUSA and other operators in the Williston Basin. RockPile's focus from formation through January 31, 2013 was primarily on procuring new pressure pumping equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, and establishing third-party customers in the Williston Basin. Results of operations are affected by a number of variables including drilling and stimulation activity in the Williston Basin, the pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers.

        For the year ended January 31, 2013, RockPile performed hydraulic fracturing services for TUSA and three third-party customers. This work resulted in 17 total well completions: 12 for Triangle and five for third-parties. All Triangle wells were completed using plug-and-perf applications. Four third-party wells were completed using a sliding sleeve application and one well was completed using a plug-and-perf application. RockPile revenue is comprised of service revenue, which is what we charge for equipment and labor, and materials revenue, which is what we charge for chemicals and proppant. Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), trucking charges, material transloading fees, railroad related costs, insurance, repairs and maintenance charges, and safety costs. Direct costs as a percentage of revenue will vary based upon equipment utilization.

        We recognized $3.0 million of gross profit from oilfield services for the year ended January 31, 2013 after elimination of $11.8 million in intercompany gross profit. See Item 8, Consolidated Financial Statements and Supplementary Data, Note 4—Segment Reporting for additional information regarding our segments.

66


Table of Contents

        The table below summarizes the RockPile contribution to our consolidated results for the year ended January 31, 2013:

 
  For the Fiscal Year Ended
January 31, 2013
 
(in thousands)
  RockPile   Eliminations   Consolidated  

Revenues

                   

Oilfield services

  $ 57,207   $ (36,460 ) $ 20,747  
               

Total revenues

    57,207     (36,460 )   20,747  

Cost of sales

                   

Depreciation

    2,857     (1,732 )   1,125  

Oilfield services

    39,534     (22,928 )   16,606  
               

Total cost of sales

    42,391     (24,660 )   17,731  
               

Gross profit

  $ 14,816   $ (11,800 ) $ 3,016  
               
               

        As RockPile did not commence operations until the second quarter of FY2013, there are no comparative consolidated financial results for FY2012.

Hedging Activities

        We have entered into commodity derivative instruments, primarily utilizing costless collars and single-day puts, to reduce the effect of price changes on a portion of our future oil production. Our commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. 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 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. During the year ended January 31, 2013, we recognized a $3.6 million loss on our commodity derivative positions, less than $10,000 of which was cash settled, due to crude oil prices generally falling between the floor and ceiling of our costless collars. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled, and we will likely add to our hedging program. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. See Item 8, Consolidated Financial Statements and Supplementary Data, Note 14—Derivative Instruments, for additional information regarding our derivative instruments.

Production Taxes

        Total production taxes increased to $4.5 million for FY2013 from $0.9 million for FY2012. Production taxes are primarily based on the wellhead values of production. The increase in production taxes in FY2013 is directly related to a 387% increase in production revenues. Production taxes as a percentage of oil and natural gas sales were 11.3% for FY2013 and 11.0% for FY2012. These rates were consistent with the published production tax rates in North Dakota, the primary source of our production.

67


Table of Contents

Lease Operating Expense

        LOE decreased to $7.11 per Boe for FY2013 from $9.50 per Boe for FY2012. The decrease is primarily the result of lower LOE on non-operated wells, which decreased from $9.50 per Boe to $5.17 per Boe. For most of our non-operated wells the largest LOE component is water disposal. An increase in availability of trucking and third-party disposal facilities in the Williston Basin reduced this cost on a per unit basis. Offsetting the reduction in non-operated LOE costs were operated LOE costs of $9.15 per Boe. Included in the operated LOE rate are non-recurring costs for equipment rentals and for two workovers.

Gathering, Transportation and Processing

        GTP expenses increased to $0.31 per Boe for FY2013 from $0.23 per Boe for FY2012. In both years, all GTP expenses were associated with non-operated wells and primarily related to the gathering and transportation of oil and natural gas. GTP costs were $0.61 and $0.23 per non-operated Boe for the fiscal years ended January 31, 2013 and 2012, respectively. This increase is primarily the result of an increase in natural gas being gathered, transported and processed by third party companies as opposed to being flared.

Oil and Natural Gas Amortization

        Oil and natural gas amortization expense increased 348% to $13.5 million for FY2013 from $3.0 million for FY2012. The increase is primarily related to a 415% increase in production in FY2013 compared to FY2012.

General and Administrative Expenses

        The following table summarizes increases in general and administrative expenses for FY2013 compared with FY2012. Costs excluded from the amounts presented below are (i) those personnel costs which are capitalized under the full cost accounting method as direct internal costs of acquisition, exploration and development of oil and gas properties, (ii) costs equal to overhead reimbursements charged by TUSA as well operator to third parties participating in TUSA-operated wells, and (iii) general and administrative expenses recovered by Triangle for charges to Caliber and TUSA for various general and administrative services. The increases are primarily due to increases in the number of employees as we continued to expand our acquisition, exploration, development and production activities in North Dakota and Montana during FY2013.

(in thousands)
  Exploration
and
Production
  Oilfield
Services
  Corporate   Consolidated
Total
 

For the fiscal year ended January 31, 2013

                         

Salaries, benefits and other general and administrative

  $ 6,838   $ 11,130   $ 4,358   $ 22,326  

Stock-based compensation

    2,507     617     3,342     6,466  
                   

Total

  $ 9,345   $ 11,747   $ 7,700   $ 28,792  
                   
                   

For the fiscal year ended January 31, 2012

                         

Salaries, benefits and other general and administrative

  $ 385   $ 874   $ 8,106   $ 9,365  

Stock-based compensation

            7,567     7,567  
                   

Total

  $ 385   $ 874   $ 15,673   $ 16,932  
                   
                   

        RockPile's general and administrative costs of $11.8 million increased from $0.9 million in fiscal year 2012. This increase is primarily attributable to increased compensation and benefit costs for

68


Table of Contents

personnel in RockPile's headquarters and field offices as RockPile built its team and commenced operations in July 2012.

Interest Expense

        The $2.8 million in interest expense in FY2013 consists of approximately $0.2 million in interest and amortized fees related to the TUSA credit facility, and approximately $3.0 million in accrued interest and amortized fees related to our Convertible Note with NGP. The total $3.2 million in interest expense is reduced by approximately $0.4 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed.

Income Taxes

        Our FY2013 provision for deferred income taxes is zero due to recognition of 100% valuation allowances against our net deferred tax assets of $35.0 million and $29.2 million at January 31, 2013 and 2012, respectively. See Item 7. Results of operations for the year ended January 31, 2014 compared to the year ended January 31, 2013—Income Taxes."

Liquidity and Capital Resources

Overview

        Our liquidity is highly dependent on the prices we receive for the oil and natural gas we produce. Commodity prices are market driven and have been volatile; therefore, we cannot predict future commodity prices. Prices received for production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth. In addition, commodity prices received by exploration and production companies in the Williston Basin affect the level of drilling activity there, and therefore the demand for products and services provided by RockPile and Caliber.

        In FY2014, our average realized price for oil was $88.07 per barrel, an increase of 3% over the average realized price for FY2013. Future prices for oil will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors. We manage volatility in commodity prices by maintaining flexibility in our capital investment program. In addition, we periodically hedge a portion of our oil production to mitigate our potential exposure to price declines and the corresponding negative impact on cash flow available for investment.

        As of January 31, 2014, we had cash of approximately $81.8 million consisting primarily of cash held in bank accounts, as compared to approximately $33.1 million at January 31, 2013. We also had available borrowing capacity under the TUSA credit facility of $137.0 million as of January 31, 2014.

        On March 25, 2014, RockPile entered into the FY2015 RockPile Credit Agreement with a syndicate of lenders led by Citibank and Wells Fargo, which provides for a $100.0 million senior secured revolving credit facility with an accordion feature that allows for the expansion of the facility up to an aggregate of $150.0 million. The credit facility is expected to support RockPile's growth initiatives and enable RockPile to remain self-funded as it contemplates additional investment in infrastructure and equipment necessary to support broad-based growth across its service lines. The FY2015 RockPile Credit Agreement also permits RockPile to make a distribution to Triangle of up to $10.0 million per fiscal year assuming compliance with certain financial ratios, and RockPile may pay Triangle up to an additional $3.0 million per fiscal year for shared services that Triangle provides to RockPile. All of RockPile's assets are pledged as collateral under the FY2015 RockPile Credit Agreement, with certain exceptions relating to real property interests, but neither Triangle nor its non-RockPile subsidiaries act as a guarantor under the facility. The FY2015 RockPile Credit Agreement contains customary covenants, including those that restrict RockPile's ability to make or limit certain payments, distributions, acquisitions, loans or investments, incur certain indebtedness or

69


Table of Contents

create certain liens on its assets, consolidate or enter into mergers, dispose of certain of its assets, engage in certain types of transactions with its affiliates, enter into certain sale/leaseback transactions, and modify certain material agreements. Funds drawn from the FY2015 RockPile Credit Facility were used to pay down and close RockPile's former credit facility.

Capital Requirements Outlook

        Our cash flow from operations has historically contributed minimally to funding our capital requirements, specifically with respect to our capital expenditure budget. We believe that the lag time between initial investment and cash flow from such investment is typical of the oil and gas industry. We expect our cash flow from operations to increase significantly as additional TUSA oil and natural gas wells come online, RockPile's oilfield services increase, and Caliber's gathering and processing system becomes fully operational. However, we will likely remain dependent on borrowings under our credit facilities and potential additional financings for the foreseeable future to fund the difference between cash flow from operations and our capital expenditures budget and other contractual commitments (see Note 13—Long-Term Debt and Note 15—Commitments and Contingencies in the consolidated financial statements for further details). Although we expect that increases in our operating cash flow and growing availability under our asset-backed credit facilities will be largely sufficient for our capital requirements, any additional shortfall will likely be financed through additional debt instruments in the near term. There can be no assurance that we will achieve our anticipated future cash flow from operations, that credit will be available when needed, or that we would be able to complete alternative transactions in the capital markets, if needed.

        We may also continue to pursue significant acquisition opportunities, which would also require additional financing. Our ability to obtain additional financing on commercially reasonable terms is dependent on a number of factors, many of which we cannot control, including changes in our credit rating, interest rates, market perceptions of us and the oil and natural gas exploration and production industry, and tax burdens due to new tax laws.

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

Debt

        As of January 31, 2014, we had $343.2 million of debt outstanding. See Note 13—Long-Term Debt in the consolidated financial statements for further discussion of debt outstanding.

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

70


Table of Contents

consolidated cash requirements. Since our principal source of operating cash flows (proved reserves to be produced in later periods) is not considered working capital, we often have low or negative working capital. Our working capital was approximately $35.5 million as of January 31, 2014, as compared to approximately $3.3 million at January 31, 2013.

Public Securities Offerings

        Historically, we have financed our operations, property acquisitions and other capital investments in part from the proceeds of offerings of our equity and debt securities. We may offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, 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.

        On August 8, 2013, we agreed to issue and sell 15,000,000 shares of common stock at a price to the public of $6.25 per share pursuant to an underwriting agreement (the "Underwriting Agreement") with Wells Fargo Securities, LLC, as representative of the several underwriters named therein (collectively, the "Underwriters"). Pursuant to the Underwriting Agreement, the Company also granted the Underwriters a 30-day over-allotment option to purchase up to an additional 2,250,000 shares of common stock at the same public offering price. The offering was made pursuant to the Company's effective registration statement on Form S-3 (Registration Statement No. 333-171958) previously filed with the Securities and Exchange Commission on January 31, 2011. The offering closed on August 14, 2013 and the Underwriters' over-allotment option closed on September 11, 2013.

        The net proceeds to the Company from the offering, including the exercise of the underwriters' over-allotment option, were approximately $101.8 million, after deducting underwriting discounts and commissions and other expenses.

Private Placements

        On March 8, 2013, the Company sold to two affiliates of NGP an aggregate of 9,300,000 shares of common stock of the Company in a private placement at $6.00 per share for aggregate consideration of $55.8 million.

        On August 6, 2013, the Company entered into a Stock Purchase Agreement (the "Stock Purchase Agreement") with TIAA Oil and Gas Investments, LLC ("TOGI"). As permitted under the terms of the Stock Purchase Agreement, on August 28, 2013, TOGI assigned its rights and obligations to purchase 11,350,000 shares of the Company's common stock to ActOil, which is an affiliate of TOGI.

        Pursuant to the Stock Purchase Agreement, on August 28, 2013, the Company issued to ActOil 11,350,000 shares of common stock at $7.20 per share for net proceeds to the Company of $80.8 million after transaction costs. Concurrently with the issuance, the Company entered into a Rights Agreement (the "Rights Agreement") with ActOil. Under the Rights Agreement, ActOil is entitled to certain demand registration rights and unlimited piggyback registration rights under the Securities Act.

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

71


Table of Contents

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

        The Rights Agreement further provides that, for so long as ActOil holds (i) 50% of the common stock purchased by ActOil under the Stock Purchase Agreement, and (ii) 10% of the then issued and outstanding common stock, without the prior written consent of ActOil, the Company and its Company's subsidiaries shall not incur any indebtedness, unless the Consolidated Leverage Ratio (as defined in the Rights Agreement) does not exceed 5.0 to 1.0 (provided that debt outstanding under TUSA's credit facility and the Company's Convertible Note issued in July 2012 are excluded from such calculation).

Commodity Derivative Instruments

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

Sources of Capital

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

        Credit facilities.    As of January 31, 2014, our maximum credit available under the TUSA credit facility was $500.0 million with a borrowing base of $320.0 million. As of January 31, 2014, we had available borrowing capacity under the TUSA credit facility of $137.0 million. The borrowing base under the TUSA credit facility is subject to redetermination by May 1, 2014, and thereafter on a semi-annual basis by each November 1st and May 1st. In addition, TUSA has the option to request one unscheduled interim redetermination prior to May 1, 2014, and two unscheduled redeterminations during any calendar year after May 1, 2014.

        On March 25, 2014, RockPile entered into the FY2015 RockPile Credit Agreement, which provides a $100.0 million senior secured revolving credit facility with an accordion feature that allows for the expansion of the facility up to an aggregate of $150.0 million. Borrowings under the FY2015 RockPile Credit Agreement are available to (i) repay existing debt, (ii) provide for the working capital and general corporate requirements of RockPile, (iii) fund capital expenditures, (iv) pay any fees and expenses associated with the FY2015 RockPile Credit Agreement, and (iv) support letters of credit.

72


Table of Contents

Analysis and Changes in Cash Flow

        The following is a summary of our change in cash and cash equivalents for fiscal years ended January 31, 2014 and 2013:

 
  For the Year Ended
January 31,
   
 
(in thousands)
  2014   2013   Change  

Net cash provided by (used in) operating activities

  $ 85,586   $ 2,764   $ 82,822  

Net cash used in investing activities

    (458,716 )   (179,712 )   (279,004 )

Net cash provided by financing activities

    421,763     141,250     280,513  
               

Net Increase (decrease) in cash and equivalents

  $ 48,633   $ (35,698 ) $ 84,331  
               
               

Net Cash Provided by Operating Activities

        Cash flows provided by operating activities were $85.6 million in FY2014. Cash flows provided by operating activities were $2.8 million in FY2013. The increase in operating cash flows was primarily due to higher oil revenues driven by higher sales volumes, partially offset by increases in production expenses, production taxes, general and administrative expenses, and other expenses associated with the growth of our operations during the year.

Net Cash Used by Investing Activities

        In FY2014, investing activities used $458.7 million in cash compared to $179.7 million in FY2013. The increase in cash flows used in investing activities in FY2014 was primarily due to our acquisition of properties during FY2014 and the associated increase in capital investment. Additionally we invested in Caliber our remaining commitment of $18.0 million.

Net Cash Provided by Financing Activities

        Cash flows provided by financing in FY2014 totaled $421.8 million. The increase was primarily a result of (i) the issuance of 9,300,000 shares of common stock to two affiliates of NGP for net proceeds of $55.7 million, (ii) the issuance of 325,000 shares of common stock of the Company to an unaffiliated oil and gas company at $7.50 per share for net proceeds of $2.4 million, (iii) the issuance of 17,250,000 shares of common stock in a public offering for net proceeds of $101.8 million, (iv) the issuance of 11,350,000 shares of common stock to ActOil at $7.20 per share for net proceeds of $80.8 million, and (v) advances from notes payable and credit facilities.

        Cash flows provided by financing activities for the year ended January 31, 2013 of $141.3 million was primarily a result of the proceeds from the $120.0 million Convertible Note. See Item 8. Consolidated Financial Statements and Supplementary Data, Note 13—Long-Term Debt, for further discussion.

Off-Balance Sheet Arrangements

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

73


Table of Contents

Contractual Obligations as of January 31, 2014

        The following table lists information with respect to our known contractual obligations as of January 31, 2014:

 
  Payments due by period  
(in thousands)
Contractual Obligations
  Total   Less than
1 year
  1 - 3 years   3 - 5 years   More than
5 years
 

Office leases(a)

  $ 5,345   $ 1,180   $ 2,440   $ 1,725   $  

Drilling rigs(b)

    13,604     13,484     120          

Credit facility(c)

    183,000                 183,000  

Convertible note principal(d)

    120,000                 120,000  

Convertible note interest(d)

    9,290                 9,290  

Oilfield services(e)

    3,990     1,752     1,023     560     655  

RockPile credit facilities(f)

    21,515     8,450     13,065          

RockPile notes payable(g)

    12,108     802     1,605     1,605     8,096  

Midstream services(h)

    405,000     24,798     134,373     68,162     177,667  

Asset retirement obligations(i)

    4,629     3,333         87     1,209  
                       

  $ 778,481   $ 53,799   $ 152,626   $ 72,139   $ 499,917  
                       
                       

(a)
The Company leases office facilities in Denver, Colorado under operating lease agreements that expire in July 2014 and September 2017.

(b)
As of January 31, 2014, the Company was subject to commitments on three drilling rig contracts. Two of the drilling rig contracts expire in first quarter of FY2015 and the remaining contract expires in the fourth quarter of FY2015. In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $11.5 million as of January 31, 2014 as required under the terms of the contracts.

(c)
Calculated based on our January 31, 2014 outstanding borrowings under the TUSA credit facility of $183.0 million and assumes no principal repayment until the maturity date in April 2017. For further discussion regarding the terms of the credit facility see Item 8, Consolidated Financial Statements and Supplementary Data, Note 13—Long-Term Debt.

(d)
Calculated based on our January 31, 2014 outstanding aggregate principal amount of $120.0 million of 5% 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. For further discussion regarding the terms of the Convertible Note, see Item 8, Consolidated Financial Statements and Supplementary Data, Note 13—Long-Term Debt.

(e)
As of January 31, 2014, RockPile had various commitments for future expenditures relating to (i) office space, (ii) leases of land, rail spur, tractor trailer units, equipment for transportation, transloading and storage of bulk commodities and light vehicles, and (iii) transloading services and track rental.

(f)
Calculated based on outstanding principal borrowings of $21.5 million under RockPile's former credit facility on January 31, 2014, with a maturity date of February 26, 2016. RockPile replaced its former credit facility on March 25, 2014 with a $100.0 million credit facility. For further discussion regarding the terms of RockPile's former and replacement credit facilities, see Item 8. Consolidated Financial Statements and Supplementary Data, Note 13—Long-Term Debt.

(g)
Includes RockPile obligations relating to (i) a loan agreement to Dacotah Bank for the construction financing of residential units; (ii) a mortgage loan related to its administrative and maintenance facility; and (iii) a mortgage loan related to the purchase of a 12 unit apartment

74


Table of Contents

    building. For further discussion regarding the terms of the credit facility see Item 8, Consolidated Financial Statements and Supplementary Data, Note 13—Long-Term Debt.

(h)
Amounts relate to agreements between TUSA and Caliber North Dakota LLC 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. See Item 8, Consolidated Financial Statements and Supplementary Data, Note 7—Asset Retirement Obligations.

        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.

Impact of Inflation and Pricing

        Triangle's transactions are denominated in U.S. dollars. Inflation in the context of oil field services and goods has been significant in the Williston Basin, the primary area in which Triangle operates. Typically, as prices for oil and gas increase, associated costs rise. Changes in prices impact Triangle's revenues, estimates of reserves, assessments of any impairment of oil and gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect Triangle's ability to raise capital, borrow money, and retain personnel. Higher prices for oil and gas or other factors could result in increases in the costs of materials, services and 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.

        Companies that follow the full cost accounting method 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

75


Table of Contents

cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. 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.

        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.

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.

        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.

76


Table of Contents

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

        We use the units-of-production method to amortize over proved reserves the cost of our oil and natural gas properties. 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, 2014, 58% of our total proved reserves were categorized as proved undeveloped. All of these proved undeveloped reserves are in the Bakken Shale formation or Three Forks formation in North Dakota. We review and update our reserve estimates at least quarterly.

Derivative Instruments

    Commodity derivative

        The Company has entered into commodity derivative instruments, primarily utilizing single day puts 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 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.

77


Table of Contents

    Equity investment derivatives

        The Company holds equity investment derivatives (Class A Trigger Units, Class A Trigger Unit Warrants and Warrants (Series 1 through Series 4)) in Caliber. Our equity investment derivatives are measured at fair value and are included on the consolidated balance sheets as derivative assets. 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.

        For additional discussion, see Item 8, Consolidated Financial Statements and Supplementary Data, Note 14—Derivative Instruments.

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 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 over the applicable vesting period. See Note 20—Share-Based Compensation for additional information regarding our stock-based compensation.

Revenue Recognition

        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.

        Pressure Pumping Revenue.    The Company enters into arrangements with its customers to provide hydraulic fracturing services, which can be either on a spot market basis or under term contracts. We

78


Table of Contents

only enter into arrangements with customers for which we believe that collectability is reasonably assured. Revenue is recognized upon the completion of each job, which generally consists of numerous fracturing stages.

        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 in "Full Cost Accounting's Non-recognition of Service Income with Third Parties in Certain Circumstances" above.

Business Combinations

        Triangle accounts for its acquisitions in accordance with ASC 805, Business Combinations. Under the guidance, a business combination is measured as the fair value of the consideration given. The acquirer must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The excess of the cost of an acquired entity, if any, over the net amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is recognized immediately to earnings as a gain from bargain purchase. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to the assets acquired and liabilities assumed.

Goodwill

        We evaluate goodwill for possible impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We use a three step process to assess the realizability of goodwill. The first step, Step 0, is a qualitative assessment that analyzes current economic indicators associated with a particular reporting unit. For example, we analyze changes in economic, market and industry conditions, business strategy, cost factors, and financial performance, among others, to determine if there has been a significant decline in the fair value of a particular reporting unit. A qualitative assessment also includes analyzing the excess fair value of a reporting unit over its carrying value from impairment assessments performed in previous years. If the qualitative assessment indicates a stable or improved fair value, no further testing is required. If a qualitative assessment indicates that a significant decline in the fair value of a reporting unit has more likely than not occurred, or if a reporting unit's fair value has historically been closer to its carrying value, we will proceed to Step 1 testing where we calculate the fair value of the reporting unit based on discounted future probability-weighted cash flows. If Step 1 indicates that the carrying value of a reporting unit exceeds its fair value, we will proceed to Step 2, where the fair value of the reporting unit will be allocated to assets and liabilities as it would in a business combination. Impairment occurs when the carrying amount of goodwill exceeds its estimated fair value as calculated in Step 2.

        We estimate fair value using discounted cash flows of the reporting unit. The most significant assumptions used in these analyses are those made in estimating future cash flows. In estimating future cash flows, we use financial assumptions in our internal forecasting model such as weighted average cost of capital, industry and market trends, legislation, projected changes in the prices we charge for our services, projected labor costs, as well as contract negotiation status. Financial and credit market volatility directly impacts our fair value measurement through the weighted average cost of capital that we use to determine our discount rate. We use a discount rate we consider appropriate for the business unit that is providing services. As of January 31, 2014, the Company's assessment of goodwill impairment indicated that the fair values of the Company's reporting units were substantially in excess of their respective estimated carrying values, and therefore goodwill was not impaired.

79


Table of Contents

Intangible Assets

        Triangle's intangible assets are accounted for and reviewed for impairment in accordance with ASC 360-10-35, Impairment or Disposal of Long-Lived Assets. An impairment loss is recognized to the extent the carrying value exceeds its fair value.

Investments

        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.

Recently Issued Accounting Pronouncements

        Refer to Item 8. Consolidated Financial Statements and Supplementary Data, Note 3—Summary of Significant Accounting Policies.

80


Table of Contents

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. Currently, we 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. For accounting purposes we mark our derivatives to fair value and recognize the changes in fair value under the gain (loss) from derivative activities line on the consolidated statements of operations and comprehensive income (loss).

        We use costless collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled 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 four 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 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 March 31, 2014 are summarized below:

Term End Date
  Contract
Type
  Basis(1)   Quantity
(Bbl/d)
  Put Strike   Call Strike   Weighted
Average Price
 

Fiscal 2015

  Collar   NYMEX     3,282   $80.00 - $91.25   $94.40 - $101.20      

Fiscal 2015

  Swap   NYMEX     1,084       $ 95.66  

Fiscal 2016

  Collar   NYMEX     1,373   $80.00   $94.50 - $96.65      

(1)
NYMEX refers to quoted prices on the New York Mercantile Exchange.

        We determine the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third-parties, the credit rating of each counterparty, and the Company's own credit rating. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company believes that it has substantial credit quality and the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

81


Table of Contents

        Changes in commodity futures price strips during FY2014 had an overall net positive impact on the fair value of our derivative contracts. For FY2014, we reported a gain on our derivative contracts of $1.1 million. The fair value of our derivative instruments at January 31, 2014 was a net asset of $2.1 million. This mark-to-market net asset relates to derivative instruments with various terms that are scheduled to be realized over the period from January 2014 through December 31, 2015. Over this period, actual realized derivative settlements may differ significantly, either positively or negatively, from the unrealized mark-to-market valuation at January 31, 2014. An assumed increase of 10% in the forward commodity prices used in the year-end valuation of our derivative instruments would result in a net derivative liability of approximately $12.6 million at January 31, 2014. Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $14.0 million at January 31, 2014. For further details regarding our derivative contracts please refer to Note 14—Derivative Instruments under Item 8 in this annual report.

Interest Rate Risk

        At January 31, 2014, we had $129.3 million outstanding under the Convertible Note, all of which has a fixed interest rate of 5%.

        In addition, as of January 31, 2014, we had $320.0 million of borrowing availability under the TUSA credit facility, of which $183.0 million was drawn at fiscal year-end. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at January 31, 2014 under the TUSA credit facility of $320.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $3.2 million.

        As of January 31, 2014, RockPile had an aggregate of approximately $25.2 million available for borrowing under its credit facility of which approximately $21.5 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, 2014 under the credit facility of $25.2 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $0.3 million.

        On March 25, 2014, RockPile entered into the FY2015 RockPile Credit Agreement which provides borrowings thereunder that bear interest at either (i) the alternative base rate (the highest of (a) the administrative agent's prime rate, (b) the federal funds rate plus 0.5%, or (c) the one-month adjusted eurodollar rate (as defined in the FY2015 RockPile Credit Agreement) plus 1%,), plus an applicable margin that ranges between 1.5% and 2.25%, depending on RockPile's leverage ratio as of the last day of RockPile's most recent fiscal quarter, or (ii) the eurodollar rate plus an applicable margin that ranges between 2.50% and 3.25%, depending on RockPile's leverage ratio as of the last day of RockPile's most recent fiscal quarter. Assuming RockPile had the maximum amount outstanding at January 31, 2014 under the FY2015 RockPile Credit Agreement of $100.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $1.0 million.

        For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, see Item 8. Consolidated Financial Statements and Supplementary Data.

82


Table of Contents

ITEM 8.    CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

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

83


Table of Contents


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 as of January 31, 2014 and 2013, and the related consolidated statements of operations and comprehensive income (loss), stockholders' equity, and cash flows for each of the years in the three-year period ended January 31, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended January 31, 2014, in conformity with U.S. generally accepted accounting principles.

        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, 2014, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated April 16, 2014 expressed an adverse opinion on the effectiveness of the Company's internal control over financial reporting.

    KPMG LLP
Denver, Colorado
April 16, 2014
   

84


Table of Contents


Triangle Petroleum Corporation

Consolidated Balance Sheets

(In thousands, except share data)

 
  January 31, 2014   January 31, 2013  

ASSETS

             

CURRENT ASSETS

             

Cash and equivalents

  $ 81,750   $ 33,117  

Accounts receivable:

             

Oil and natural gas sales

    20,450     10,625  

Trade

    84,973     28,541  

Other

    1,101     955  

Investment in marketable securities

        5,065  

Derivative asset

    955     603  

Deferred tax benefit

    321      

Inventory, deposits and prepaid expenses

    5,331     2,306  
           

Total current assets

    194,881     81,212  
           

LONG-TERM ASSETS

             

Oil and natural gas properties at cost, using the full cost method of accounting:

             

Unproved properties and properties under development, not being amortized

    121,393     94,529  

Proved properties

    629,051     220,894  
           

Total oil and natural gas properties at cost

    750,444     315,423  

Less: accumulated amortization

    (67,657 )   (16,666 )
           

Net oil and natural gas properties

    682,787     298,757  
           

Oilfield services equipment, net

    46,586     18,878  

Other property and equipment, net

    24,507     15,779  

Equity investment

    68,536     11,768  

Goodwill

    1,680      

Intangible assets, net

    3,862      

Long-term derivative asset

    1,192      

Other long-term assets

    3,553     1,927  
           

Total assets

  $ 1,027,584   $ 428,321